0001423902 wes:WesternMidstreamOperatingLPMember wes:SeniorNotes4Point50PercentDue2030Member us-gaap:SeniorNotesMember us-gaap:SubsequentEventMember 2020-01-13 2020-01-13
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, 20192020


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, LP1201 Lake Robbins DriveThe Woodlands,Texas77380(832)636-6000
Western Midstream Operating, LP1201 Lake Robbins DriveThe Woodlands,Texas77380(832)636-6000

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, LPYes☐Noþ
Western Midstream Operating, LPYes☐Noþ

The aggregate market value of the registrant’s common units representing limited partner interests held by non-affiliates of the registrant on June 28, 2019,30, 2020, based on the closing price as reported on the New York Stock Exchange.
Western Midstream Partners, LP$6.22.0 billion
Western Midstream Operating, LPNone

Common units outstanding as of February 24, 2020:
22, 2021:
Western Midstream Partners, LP443,971,409413,059,211
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
PART I
1 and 2.
10
General Overview
10
Basis of Presentation for Acquired Assets and Results of Operations
11
Assets and Areas of Operation
11
Strategy
13
Competitive Strengths
14
WES and WES Operating’s Relationship with Occidental Petroleum Corporation
15
Industry Overview
16
Properties
19
Competition
35
Regulation of Operations
36
Environmental Matters and Occupational Health and Safety Regulations
40
Title to Properties and Rights-of-Way
44
Human Capital Resources
45
1A.
46
1B.
62
3.
62
4.
63
PART II
5.
Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
64
Market Information
64
Other Securities Matters
64
Selected Information From Our Partnership Agreement
65
7.
66
Executive Summary
66
Items Affecting the Comparability of Our Financial Results
69
Our Operations
70
How We Evaluate Our Operations
71
General Trends and Outlook
75
Results of Operations
78
Operating Results
78
Key Performance Metrics
89
Liquidity and Capital Resources
91
Items Affecting the Comparability of Financial Results with WES Operating
99
Critical Accounting Estimates
101
Recent Accounting Developments
103
7A.
103
8.
104
9.
164
9A.
164
9B.
164
3

Item Page
 
PART I
 
1 and 2.
Business and Properties
10
 
General Overview
10
 
Basis of Presentation for Acquired Assets and Results of Operations
11
 
Assets and Areas of Operation
11
 
Strategy
13
 
Competitive Strengths
14
 
WES and WES Operating’s Relationship with Occidental Petroleum Corporation
15
 
Industry Overview
16
 
Properties
19
 
Competition
35
 
Regulation of Operations
36
 
Environmental Matters and Occupational Health and Safety Regulations
41
 
Title to Properties and Rights-of-Way
43
 
Employees
43
1A.
Risk Factors
44
1B.
Unresolved Staff Comments
75
3.
Legal Proceedings
75
4.
Mine Safety Disclosures
75
 
PART II
 
5.
Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
76
 
Market Information
76
 
Other Securities Matters
76
 
Selected Information From Our Partnership Agreement
76
6.
Selected Financial and Operating Data
77
7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
80
 
Executive Summary
80
 
Items Affecting the Comparability of Our Financial Results
84
 
Our Operations
85
 
How We Evaluate Our Operations
86
 
General Trends and Outlook
92
 
Equity Offerings
93
 
Results of Operations
94
 
Operating Results
94
 
Key Performance Metrics
104
 
Liquidity and Capital Resources
106
 
Items Affecting the Comparability of Financial Results with WES Operating
113
 
Contractual Obligations
115
 
Critical Accounting Estimates
116
 
Off-Balance Sheet Arrangements
117
 
Recent Accounting Developments
117
7A.
Quantitative and Qualitative Disclosures About Market Risk
118
8.
Financial Statements and Supplementary Data
119
9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
179
9A.
Controls and Procedures
179
9B.
Other Information
179


ItemPage
PART III
10.
165
11.
171
12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
193
13.
195
14.
202
PART IV
15.
203
16.
208
4
Item Page
 
PART III
 
10.
Directors, Executive Officers, and Corporate Governance
180
11.
Executive Compensation
188
12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
202
13.
Certain Relationships and Related Transactions, and Director Independence
204
14.
Principal Accounting Fees and Services
210
 
PART IV
 
15.
Exhibits, Financial Statement Schedules
211
16.
Form 10-K Summary
217

Table of Contents

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:
Additional DBJV System Interest: The additional 50% interest in the DBJV system acquired from a third party in March 2017.
AESC: Anadarko Energy Services Company, a subsidiary of Occidental.
Affiliates: Occidental and the Partnership’s equity interests in Fort Union, White Cliffs, Rendezvous, the Mont Belvieu JV, TEP, TEG, FRP, Whitethorn LLC, Cactus II, Saddlehorn, Panola, Mi Vida, Ranch Westex, and Red Bluff Express.
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, including the APC water systems acquired as partTexas.

5
Table of the acquisition of AMA.Contents
December 2019 Agreements: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 Executive Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 78 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 (acquired as part of the acquisition of AMA).plant.
Drip condensate: Heavier hydrocarbon liquids that fall out of the natural-gas stream and are recovered in the gathering system without processing.
Dry gas: A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.
EBITDA: Earnings before interest, taxes, depreciation, and amortization. For a definition of “Adjusted EBITDA,” see How We Evaluate Our Operations under Part II, Item 7 of 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
Table of Contents
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.
Non-Operated Marcellus Interest: The 33.75% interest in the Liberty and Rome gas-gathering systems and related facilities located in northern Pennsylvania that was transferred to a third party in March 2017 pursuant to the Property Exchange.
NYSE: New York Stock Exchange.
NYMEX: New York Mercantile Exchange.
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.

7
Table of Contents
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.

Property ExchangePurchase Program: : The acquisitionIn November 2020, we announced a buyback program of the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0up to $250.0 million of cash consideration, as further describedour common units through December 31, 2021. The common units may be purchased from time to time in our Forms 8-K filed with the SEC on February 9, 2017, and March 23, 2017.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
Table of Contents
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.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, all of which were combined into a single complex effective January 1, 2018.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,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
Table of Contents
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. We provide the above-described midstream services for Occidental and third-party customers.

December 2019 Agreements
. On December 31, 2019, WES and certain of its subsidiaries, including WES Operating and WES Operating GP, entered into agreements with Occidental and/or certain of its subsidiaries, including Anadarko. WES Operating also entered into amendments to its debt agreements. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information.

Merger transactions. On February 28, 2019, WES, WES Operating, Anadarko, and certain of their affiliates completed the Merger. See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information.

Occidental Merger. On August 8, 2019, Anadarko, the indirect general partner and majority unitholder of WES, was acquired by Occidental pursuant to the Occidental Merger.

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 for our Chief Executive Officer and Senior Financial Officers, Code of Business Conduct, and Ethics, and the charters of the Audit Committee and the Special Committee of our Board of Directors are also available on our website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s corporate secretary at our principal executive office. Our principal executive office is located at 1201 Lake Robbins9950 Woodloch Forest Drive, Suite 2800, The Woodlands, TX 77380-1046.77380. Our telephone number is 832-636-6000.832-636-1009.


10
Table of Contents
BASIS OF PRESENTATION FOR ACQUIRED ASSETS AND RESULTS OF OPERATIONS

Acquisitions and divestitures. In January 2019, we acquired a 30% interest in Red Bluff Express, and in February 2019, WES Operating acquired AMA. See Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information.

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%98.0% partnership interest in WES Operating as of December 31, 20192020 (see Note 10—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

wesus2019.jpgwes-20201231_g1.jpg


11
Table of Contents
As of December 31, 2019,2020, our assets and investments consisted of the following:
Wholly
Owned and
Operated		Operated
Interests		Non-Operated
Interests		Equity
Interests
Gathering systems (1)
17 2 3 1 
Treating facilities39 3 — — 
Natural-gas processing plants/trains25 3 — 5 
NGLs pipelines2 — — 5 
Natural-gas pipelines5 — — 1 
Crude-oil pipelines3 1 — 4 

  Wholly
Owned and
Operated		 Operated
Interests		 Non-Operated
Interests		 Equity
Interests
Gathering systems (1)
 17
 2
 3
 2
Treating facilities 37
 3
 —
 3
Natural-gas processing plants/trains 25
 3
 —
 5
NGLs pipelines 2
 —
 —
 4
Natural-gas pipelines 5
 —
 —
 1
Crude-oil pipelines 3
 1
 —
 3
(1)(1)Includes the DBM water systems.
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, Texas, and New Mexico.Pennsylvania. The following table provides information regarding our assets by geographic region, as of and for the year ended December 31, 2019, excluding Latham Train II2020:
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 complex and Loving ROTF Trains III and IV at the DBM oil system, which currently are under construction in Colorado andWest Texas respectively (see Assets Under Development within these Items 1 and 2):complexes.
(2)Excludes compression horsepower for transportation.
Area Asset Type 
Miles of Pipeline (1)
 
Approximate Number of Active Receipt Points (1)
 
Compression (HP) (1) (2)
 
Processing or Treating Capacity (MMcf/d) (1)
 
Processing, Treating, or Disposal Capacity (MBbls/d) (1)
 
Average Gathering, Processing, Treating, and Transportation Throughput (MMcf/d) (3)
 
Average Gathering, Treating, Transportation, and Disposal Throughput (MBbls/d) (3)
Rocky Mountains Gathering, Processing, and Treating 7,198
 3,463
 617,150
 3,720
 194
 2,323
 118
  Transportation 2,199
 31
 —
 —
 —
 87
 60
Texas / New Mexico Gathering, Processing, Treating, and Disposal 3,838
 2,040
 774,334
 1,825
 1,386
 1,765
 792
  Transportation 2,438
 38
 —
 —
 —
 142
 249
North-central Pennsylvania Gathering 146
 59
 9,660
 —
 —
 106
 —
Total   15,819
 5,631
 1,401,144
 5,545
 1,580
 4,423
 1,219
(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.
(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. We provide the above-described midstream services for Occidental and third-party customers in the United States. 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, 2018, and 2017.2018.


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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 evaluate
•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.


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

•
Controlling our operating, capital, and administrative costs. We continue to optimize and maximize the operability of our existing assets to realize cost and capital savings. As a result of the recent transformation of our workforce that historically maintained dual upstream and midstream responsibilities into a solely midstream-focused organization, we believe that we will drive operational, capital, and administrative cost efficiencies throughout the organization.

•
Maintaining investment grade metrics. We intend to operate with leverage metrics and distribution coverage levels that are consistent with other investment-grade credits in our sector. Maintaining leverage ratios that are within the industry-standard investment-grade credit metrics positions us to pursue strategic acquisitions and to fund large growth projects at a lower cost of capital, which enhances our accretion and 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.



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.

 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 positions us as a full-service midstream provider in the basin.

•
Well-positioned and well-maintained assets. We believe that our 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, NGLs, and produced-water throughput (excluding equity investments) were serviced under fee-based contracts for the year ended December 31, 2019. 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, 2019, 65% of our natural-gas throughput and 78% of our crude-oil, NGLs, and produced-water throughput were supported by either minimum-volume commitments with associated deficiency payments or cost-of-service commitments.

•
Affiliation with Occidental. We believe Occidental is motivated to promote and support the successful execution of our business plan. We continue leveraging our long-standing relationship with Occidental 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. Continuing 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.

•
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, 2019, there was $1.6 billion in available borrowing capacity under the RCF.

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.


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WES AND WES OPERATING’S RELATIONSHIP WITH OCCIDENTAL PETROLEUM CORPORATION

OurThe officers of our general partner manage our operations and activities are managed byunder 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.
We believe that one of our principal strengths is our relationship with Occidental, and that Occidental, through its direct economic interest in us, will continue to be motivated to promote and support the successful execution of our business plan.
As of December 31, 2019,2020, Occidental held (i) 242,136,976214,281,578 of our common units, representing a 53.4%50.7% limited partner interest in us, (ii) through its ownership of the general partner, 9,060,641 general partner units, representing a 2.0%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, 2019, production owned or controlled by Occidental represented 38%2020, 66% of Total revenues and other, 41% of our throughput for natural-gas assets (excluding equity-investment throughput) and 83%, 88% of our throughput for crude-oil NGLs, and produced-waterNGLs 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 supports our operations by providingprovides dedications and/or minimum-volume commitments.commitments under certain of our contracts.
PriorHistorically, we sold a significant amount of our natural gas and NGLs to December 31, 2019,AESC, Occidental’s marketing affiliate. In addition, we had an omnibus agreement with Occidental and our general partner that governed (i) our obligation to reimburse Occidental for expenses incurred or payments made on our behalf in connection with Occidental’s provision of general and administrative services provided to us, including certain public company expenses and general and administrative expenses; (ii) our obligation to pay Occidental, in quarterly installments, an administrative services fee of $250,000 per year, which was subject to an annual increasepurchased natural gas from AESC pursuant to the omnibus agreement;purchase agreements. While we still have some marketing arrangements with affiliates of Occidental, we began marketing and (iii)selling substantially all of our obligationnatural gas and NGLs directly to reimburse Occidental for all insurance coverage expenses it incurred or payments it madethird parties beginning on our behalf. In addition, WES Operating had a separate omnibus agreement with Occidental and WES Operating GP that governed its relationship with Occidental regarding certain reimbursement and indemnification matters. The WES and WES Operating omnibus agreements were terminated in connection with the execution of the December 2019 Agreements. January 1, 2021.
Pursuant to the Services Agreement entered into as part of the December 2019 Agreements,, Occidental (i) secondsseconded certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP payspaid 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.


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INDUSTRY OVERVIEW

The midstream industry is the link between the exploration for and production of natural gas, NGLs, and crude oil and the delivery of 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.


•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.

16
•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.

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

 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

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


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.

 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, 2019.2020.

GATHERING, PROCESSING, TREATING, AND TREATINGDISPOSAL

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 3 1,802 
West Texas
DBM oil system (5)
Gathering & Treating16 — 256 66 13,473 1 642 
West TexasDBM water systemsGathering & Disposal— — 1,020 109 46,000 5 782 
West Texas
Mi Vida (6)
Processing1 200 — 4 20,000 — — 
West Texas
Ranch Westex (7)
Processing2 125 — 2 10,090 — 12 
East Texas
Mont Belvieu JV (8)
Processing2 — 170 — — — — 
South TexasBrasada complexGathering, Processing, & Treating3 200 15 14 30,450 1 58 
South Texas
Springfield system (9)
Gathering and Treating3 — 75 80 134,223 2 864 
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.

21
Table of Contents
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.

22
Table of Contents
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.

23
Table of Contents
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 2 3,185 
ColoradoDJ Basin oil systemGathering & Treating6 — 155 21 6,095 1 433 
Utah
Chipeta (4)
Processing3 790 — 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
24
Location Asset Type Processing / Treating Plants 
Processing / Treating Capacity (MMcf/d) (1)
 Processing / Treating Capacity (MBbls/d) Compressors Compression Horsepower Gathering Systems 
Pipeline Miles (2)
Colorado 
DJ Basin complex (3)
 Gathering, Processing, & Treating 15
 1,480
 39
 155
 375,962
 2
 3,270
Colorado DJ Basin oil system Gathering & Treating 6
 —
 155
 29
 6,905
 1
 347
Utah 
Chipeta (4)
 Processing 3
 790
 —
 12
 74,875
 —
 2
Total     24
 2,270
 194
 196
 457,742
 3
 3,619
(1)Table of Contents
Includes 160 MMcf/d of bypass capacity at the DJ Basin complex.
(2)
Includes 12 miles of transportation related to a crude-oil pipeline at the DJ Basin oil system.
(3)
The DJ Basin complex includes the Platte Valley, Fort Lupton, Fort Lupton JT, Hambert JT (currently inactive), Wattenberg, Lancaster Trains I and II, and Latham Train I processing plants, and the Wattenberg gathering system. Excludes 600 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.

co2019.jpg

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.

 For the year ended December 31, 2019, Occidental’s production represented 62% of the DJ Basin complex throughput and the two-largest third-party customers provided 19% of the throughput. Effective December 31, 2019, Kerr-McGee Oil & Gas Onshore, LP, a subsidiary of Occidental, and Kerr-McGee Gathering LLC (“KMGG”), a subsidiary of WES Operating, entered into an amendment to the DJ gas-gathering agreement to provide for the extension of gathering services by KMGG to gas produced by a subsidiary of Occidental in Weld County, Colorado, in the DJ Basin for a primary term ending August 2029. This agreement provides new acreage dedications covering approximately 21,000 acres.

•
Supply. The DJ Basin complex is supplied primarily by the Wattenberg field. There were 1,806 active receipt points connected to the DJ Basin complex as of December 31, 2019. Occidental has dedicated to WES approximately 640,000 gross acres within the DJ Basin.

•
Delivery points. As of December 31, 2019, the DJ Basin complex had various delivery-point interconnections with DCP Midstream LP’s (“DCP”) gathering and processing system for gas not processed within the DJ Basin complex. The DJ Basin complex is connected to the Colorado Interstate Gas Company LLC’s pipeline (“CIG pipeline”) and Xcel Energy’s residue pipelines for natural-gas residue takeaway and to Overland Pass Pipeline Company LLC’s pipeline and FRP’s pipeline for NGLs takeaway. In addition, the NGLs fractionator at the Platte Valley plant and associated truck-loading facility provides access to local NGLs markets.

DJ Basin oil-gathering system, stabilization facility, and storage

•
Customers. For the year ended December 31, 2019, 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, and rail-loading facilities in Tampa, Colorado, and local markets.

ut2019.jpg•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.

25
Table of Contents
Utah
wes-20201231_g7.jpg

Chipeta processing complex

•
Customers. For the year ended December 31, 2019, Occidental’s production represented 66% of the Chipeta complex throughput and the two largest third-party customers provided 27%
•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”).

26

•
Supply. The Chipeta complex is well positioned to access Occidental and third-party production in the Uinta Basin. Occidental has dedicated to WES approximately 170,000 gross acres in the Uinta Basin. Chipeta’s inlet is connected to Occidental’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”).


Overview - Rocky Mountains - Wyoming
LocationAssetTypeProcessing / Treating PlantsProcessing / Treating Capacity (MMcf/d)CompressorsCompression HorsepowerGathering SystemsPipeline Miles
Northeast Wyoming
Bison (1)
Treating3 450 2 3,550 — — 
Northeast WyomingHilightGathering & Processing2 60 32 40,361 1 1,215 
Southwest Wyoming
Granger complex (2)
Gathering & Processing4 520 35 44,940 1 783 
Southwest Wyoming
Red Desert complex (3)
Gathering & Processing1 125 26 49,948 1 1,127 
Southwest Wyoming
Rendezvous (4)
Gathering— — 5 7,485 1 286 
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
27
Location Asset Type Processing / Treating Plants Processing / Treating Capacity (MMcf/d) Compressors Compression Horsepower Gathering Systems Pipeline Miles
Northeast Wyoming Bison Treating 3
 450
 9
 14,645
 —
 —
Northeast Wyoming 
Fort Union (1)
 Gathering & Treating 3
 295
 3
 5,454
 1
 315
Northeast Wyoming Hilight Gathering & Processing 2
 60
 34
 36,554
 1
 1,124
Southwest Wyoming 
Granger complex (2)
 Gathering & Processing 4
 520
 41
 44,967
 1
 741
Southwest Wyoming 
Red Desert complex (3)
 Gathering & Processing 1
 125
 25
 50,303
 1
 1,061
Southwest Wyoming 
Rendezvous (4)
 Gathering —
 —
 5
 7,485
 1
 338
Total     13
 1,450
 117
 159,408
 5
 3,579
(1)Table of Contents
We have a 14.81% interest in Fort Union.
(2)
The Granger complex includes the “Granger straddle plant,” a refrigeration processing plant.
(3)
The Red Desert complex includes the Red Desert cryogenic processing plant, which 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.

wy2019.jpg

Northeast Wyoming

Bison treating facility

•
•Customers. Bison treating facility throughput was from one third-party customer as of December 31, 2019. In connection with Anadarko’s sale of the Powder River Basin coal-bed methane assets in 2015, Occidental still retains a commitment to Bison that extends through December 2020 for which we earn affiliate revenues.

•
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.

Fort Union gathering system and 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.

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

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

•
Delivery points. The Fort Union system delivers coal-bed methane gas to the hub in Glenrock, Wyoming, which accesses the following interstate pipelines:
◦CIG pipeline;
◦Tallgrass Interstate Gas Transmission system’s pipeline (“TIGT pipeline”); and
◦WIC pipeline.

These pipelines serve•Supply and delivery points. The Bison treating facility treats and compresses gas marketsfrom coal-bed methane wells in the Rocky MountainsPowder River Basin of Wyoming. The Bison treating facility is directly connected to Fort Union’s pipeline and Midwest regions of the United States.Bison Pipeline operated by TransCanada Corporation.

Hilight gathering system and processing plant

•
Customers. As of December 31, 2019, gas gathered and processed at the Hilight system was from third-party customers. The four-largest producers provided 70% of the system throughput for the year ended December 31, 2019.

•
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.


•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.

 As of December 31, 2019, Granger complex throughput was from third-party customers, with the three-largest third-party customers providing 77% of the Granger complex throughput for the year ended December 31, 2019.

•
Supply. The Granger complex is supplied by the Moxa Arch and the Jonah and Pinedale Anticline fields. The Granger gas-gathering system had 580 active receipt points as of December 31, 2019.

•
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.

28
Table of Contents
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.

 For the year ended December 31, 2019, 70% of the Red Desert complex throughput was from the four-largest third-party customers and 1% was from Occidental.

•
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, 2019, 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.


•Customers. As of December 31, 2020, Rendezvous system throughput primarily was from two shippers that have dedicated acreage to the system.
Overview - Texas
•Supply and New Mexicodelivery 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.

29
Location Asset Type Processing / Treating Plants 
Processing / Treating Capacity (MMcf/d) (1)
 Processing / Treating / Disposal Capacity (MBbls/d) 
Compressors / Pumps (2)
 
Compression Horsepower (2)
 Gathering Systems 
Pipeline Miles (3)
West Texas / New Mexico 
West Texas complex (4)
 Gathering, Processing, & Treating 14
 1,300
 46
 280
 473,230
 3
 1,577
West Texas 
DBM oil system (5)
 Gathering & Treating 14
 —
 195
 102
 17,598
 1
 576
West Texas DBM water systems Gathering & Disposal —
 —
 885
 125
 50,750
 5
 851
West Texas 
Mi Vida (6)
 Processing 1
 200
 —
 4
 20,000
 —
 —
West Texas 
Ranch Westex (7)
 Processing 2
 125
 —
 2
 10,090
 —
 6
East Texas 
Mont Belvieu JV (8)
 Processing 2
 —
 170
 —
 —
 —
 —
South Texas Brasada complex Gathering, Processing, & Treating 3
 200
 15
 14
 30,450
 1
 57
South Texas 
Springfield system (9)
 Gathering and Treating 3
 —
 75
 107
 172,216
 2
 771
Total     39
 1,825
 1,386
 634
 774,334
 12
 3,838
Table of Contents
(1)
Includes 70 MMcf/d of bypass capacity at the West Texas complex.
(2)
Includes owned, rented, and leased compressors and compression horsepower.
(3)
Includes 18 miles of transportation related to the Ramsey Residue Lines (regulated by FERC) at the West Texas complex and 14 miles of transportation related to a crude-oil pipeline at the DBM oil system.
(4)
The West Texas complex includes the DBM complex and DBJV and Haley systems. Excludes 2,300 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.

wtx2019.jpg

West Texas gathering, treating, and processing complex

•
Customers. For the year ended December 31, 2019, Occidental’s production represented 41% 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. Occidental has dedicated to WES approximately 530,000 gross acres within the Delaware 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.


DBM oil-gathering system, treating facilities, and storage

•
Customers. As of December 31, 2019, DBM oil system throughput was from Occidental and one third-party producer. For the year ended December 31, 2019, Occidental’s production represented 94% of the DBM oil system throughput. All parties ship pursuant to a tariff on file with the Texas Railroad Commission.

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

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

DBM produced-water disposal systems

•
Customers. As of December 31, 2019, DBM water systems throughput was from Occidental and numerous third-party producers. Occidental’s production represented 82% of the throughput for the year ended December 31, 2019.

•
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, 2019, 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, 2019, 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.


etx2019.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.


stx2019.jpg

Brasada gathering, stabilization, treating, and processing complex

•
Customers. Brasada complex throughput was from one third-party customer as of December 31, 2019.

•
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, 2019.

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

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


Overview - North-central Pennsylvania
LocationAssetTypeCompressorsCompression HorsepowerGathering SystemsPipeline Miles
North-central Pennsylvania
Marcellus (1)
Gathering7 9,660 3 146 

(1)We own a 33.75% interest in the Marcellus Interest gathering systems.
Location Asset Type Compressors Compression Horsepower Gathering Systems Pipeline Miles
North-central Pennsylvania 
Marcellus (1)
 Gathering 7
 9,660
 3
 146

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

wes-20201231_g9.jpg
pa2019.jpg

Marcellus gathering systems

•
Customers. As of December 31, 2019, the Marcellus Interest gathering systems had two priority shippers. The largest producer provided 80% of the throughput for the year ended December 31, 2019. 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.


•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.
Overview
transportation2019.jpg•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.


30
LocationAssetTypePipeline Miles
Colorado, Kansas, Oklahoma
White Cliffs (1) (2)
Oil & NGLs1,054
Wyoming, Colorado, Kansas, Oklahoma
Saddlehorn (1) (3)
Oil600
Utah
GNB NGL (1)
NGLs33
Northeast Wyoming
MIGC (1)
Gas243
Southwest WyomingOTTCOGas208
Southwest WyomingWamsutterOil61
Colorado, Oklahoma, Texas
FRP (1) (4)
NGLs447
Texas, Oklahoma
TEG (4)
NGLs191
Texas
TEP (1) (4)
NGLs593
Texas
Whitethorn LLC (5)
Oil416
Texas
Panola (1) (6)
NGLs248
Texas
Cactus II (1)(7)
Oil461
Texas
Red Bluff Express (1)(8)
Gas82
Total4,637
TRANSPORTATION
(1)
wes-20201231_g10.jpg
31
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.

White Cliffs, Saddlehorn, GNB NGL, MIGC, FRP, TEP, Panola, Cactus II, and Red Bluff Express are regulated by FERC.
(2)
We own a 10% interest in the White Cliffs pipeline, which is operated by a third party.
(3)
We own a 20% interest in the Saddlehorn pipeline, which is operated by a third party.
(4)
We own a 20% interest in TEG and TEP and a 33.33% interest in FRP. All three systems are operated by third parties.
(5)
We own a 20% interest in Whitethorn, which is operated by a third party.
(6)
We own a 15% interest in the Panola pipeline, which is operated by a third party.
(7)
We own a 15% interest in the Cactus II pipeline, which is operated by a third party.
(8)
We own a 30% interest in the Red Bluff Express pipeline, which is 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.

 The White Cliffs pipeline had multiple committed shippers, including Occidental, as of December 31, 2019. 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. In 2019, one of the pipelines was converted from crude-oil service to NGL Y-grade service.

•
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, 2019.
•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.

32

•
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.


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.

 Occidental was the only shipper on the GNB NGL pipeline as of December 31, 2019. 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.

 Occidental was the largest firm shipper on the MIGC system, with 56% of the throughput for the year ended December 31, 2019. 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. on the north end of the transportation system.

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

◦CIG pipeline;
◦TIGT pipeline; and
◦WIC pipeline.

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

OTTCO transportation system

•
Customers. For the year ended December 31, 2019, 8% of OTTCO’s throughput was from Occidental. The remaining
•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.

33

•
Supply and delivery points. Supply points to the OTTCO transportation system include approximately 28 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.


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.

 For the year ended December 31, 2019, 93% of the Wamsutter pipeline throughput was from two third-party shippers, 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 two 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.

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 Lancaster and Wattenberg plants, which are within the DJ Basin complex) (see Rocky Mountains—Colorado and Utah within these Items 1 and 2). FRP connects to TEP near Skellytown, Texas. As of December 31, 2019, 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 is ongoing and expected to be completed in 2020. The expansion of FRP will increase its capacity by 100 MBbls/d, to a targeted total capacity of approximately 260 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, 2019.

•
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, 2019, TEP had multiple committed shippers, including Occidental. TEP provides capacity to other shippers at the posted FERC tariff rates. In 2018, we elected to participate in the expansion of TEP. The expansion was completed in November 2019 and increased capacity by 90 MBbls/d, to a total capacity of approximately 350 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, 2019,2020, 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, 2019, 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.


•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, 2019,
•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.
•
Supply and delivery points. The Red Bluff Express pipeline is supplied by production from (i) our Ramsey and Mentone gas-processing plants that are part of the West Texas complex and (ii) 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.

Assets Under Development

In addition to significant gathering expansion projects at the Westposted 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, and DJ Basin complexes andto the DBM water systems, we currently have significant Colorado- and Texas-based projects scheduled for completionWAHA hub in 2020 that are described in greater detail below. See Capital expenditures, under Part II, Item 7 of this Form 10-K.Pecos County, Texas.

•
Latham Train II. As of December 31, 2019, we were constructing a second cryogenic train at the Latham processing plant at the DJ Basin complex. Latham Train II commenced operation in February 2020 with a capacity of 200 MMcf/d. Upon completion of Latham Train II, the DJ Basin complex has a total processing capacity of 1,680 MMcf/d.

•
Loving ROTF Trains III and IV. We currently are commissioning and constructing two additional oil-stabilization trains at the ROTFs (part of the DBM oil system). Loving ROTF Trains III and IV will have capacities of 30 MBbls/d each. Construction of Loving ROTF Train III was complete in the fourth quarter of 2019 and commenced operation in January 2020. Loving ROTF Train IV is expected to be completed in the fourth quarter of 2020. Upon completion, the DBM oil system will have a total processing capacity of 255 MBbls/d.

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 supports our operations by providingand 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 the 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 due to our competitive rates. Major competitors in various aspects of our business include Crestwood Equity Partners LP, DCP Midstream LP, MPLX LP, The Williams Companies, Inc., EagleClaw Midstream Ventures, LLC, EnLink Midstream Partners, LP, Enterprise Products Partners LP, Energy Transfer LP, Kinder Morgan, Inc., Plains All American Pipeline, Tallgrass Energy, LP, and Targa Resources Partners LP.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 HLPSAnew or amended PHMSA regulations could result in increased costs that could have a material adverse effect on our results of operations or financial position.
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. The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”), which became law in January 2012, amended the NGPSA and HLPSA by increasing the penalties for safety violations, establishing additional safety requirements for newly constructed pipelines and requiring studies of safety issues that could result in the adoption of new regulatory requirements for existing pipelines. In June 2016, President Obama signed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “2016 Pipeline Safety Act”), further amending the NGPSA and HLPSA, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of the outstanding mandates under the 2011 Pipeline Safety Act and empowering the agency to address imminent hazards by imposing emergency restrictions, prohibitions, and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA published an interim final rule in 2016 to implement the agency’s expanded authority over imminent pipeline hazards.
The adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline-integrity management or safety standards could have a significant adverse effect on our results of operations. For example, in January 2017, PHMSA issued a final rule that significantly extended and expanded the reach of certain PHMSA hazardous liquid pipeline-integrity management requirements, such as periodic assessments, leak detection, and repairs, regardless of the pipeline’s proximity to a high-consequence area. The final rule also imposed new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, implementation of this final rule by publication in the Federal Register was delayed following the January 2017 change from the Obama to Trump presidential administrations. In a second example, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain gas-transportation and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for gas pipelines in newly defined “moderate-consequence areas” that contain as few as five dwellings within a potential impact area; requiring gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their MOP; and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MOP limits, line markers, and emergency-planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity-management requirements for gas pipelines and also require consideration of seismicity in evaluating threats to pipelines. PHMSA has split this so-called gas “Mega Rule” into three separate rulemaking proceedings.


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 will taketook effect on July 1, 2020. PHMSA then 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 will taketook 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.
We also are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended, and comparable state statutes, the purposes of which are to protect the health and safety of workers, generally and within the pipeline industry. Furthermore, we and the entities in which we own an interest are subject to regulations imposed by the U.S. Occupational Safety and Health Administration (“OSHA”) that (i) require information to be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities, and citizens and (ii) are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable, or explosive chemicals.
See Risk Factor,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 operationoperation”” 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.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. However,On November 19, 2020, FERC issued an order affirming the initial decision findings that White Cliffs cannot yet chargelacks market power and is granted market-based rates, as the Initial Decision is still pending approval by the FERC commissioners.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 whichthat 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;

OSHA,•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, potentialpotentially 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 factorsRisk 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
As of December 31, 2019, the Services Agreement obligated us
In March 2020, seconded employees’ employment was transferred to transfer 19 employees (seeWES. 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) to employment by WES and such transfer was fully effective on January 12, 2020.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, 2019, Occidental2020, WES employed 979 people who were seconded to us to provide direct support to our operations and who are anticipated to become employees1,045 persons, all of WES prior towhom reside in the end of 2020. All of these employees are deemed jointly employed by Occidental and our general partner under the Services Agreement.United States. None of these employees are covered by collective bargaining agreements, and OccidentalWES 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 affiliates,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 and the $260.0 million note receivable from Anadarko;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.

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 of the common units 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, 2019, 59%2020, 66% of Total revenues and other, 38%41% of our throughput for natural-gas assets (excluding equity-investment throughput), and 83%88% of our throughput for crude-oil NGLs, and produced-waterNGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets were attributable to transactions withproduction 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.

Following the closing of the Occidental Merger and the execution of the December 2019 Agreements, Occidental owns our general partner. Occidental’s ownership of our general partner may result in conflicts of interest.

Following the closing of the Occidental Merger, 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, who is the indirect owner of our general partner. 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.
Now that the Occidental Merger has been completed, our future prospects will 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.

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, the following:

but not limited to, the volatility of oil and natural-gas prices, which could have a negative effect on the value of Occidental’s oil and natural-gas properties, its drilling programs, and its ability to finance its operations;

the availability of capital on favorable terms to fund Occidental’s exploration and development activities;

a reduction in or reallocation ofactivities, the political and economic uncertainties associated with Occidental’s capital budget, which could reduce the gathering, transportation, and treating volumes available to us as a midstream operator, and/or limit our opportunities for organic growth;

Occidental’s ability to replace its oil and natural-gas reserves;

Occidental’sforeign operations, in foreign countries, which are subject to political, economic, and other uncertainties;

Occidental’s drilling, flowline, pipeline, and operating risks, including potential environmental liabilities;

transportation-capacity constraints, and interruptions;

adverse effects of governmental and environmental regulation, including state-approved ballot initiatives that would change state constitutions or statutes in a manner that makes future oil and gas development in such states more difficult or expensive;

shareholder activism with respect to Occidental’s stock or activities by non-governmental organizations to restrict the exploration, development, and production of oil and natural gas by Occidental; and

adverse effects from current or future litigation.

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 and note receivable.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 Part I, Item 1A in Occidental’s Form 10-K forExchange Act reports filed with the year ended December 31, 2019Securities and Exchange Commission (which isare 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:

things, implementing operational and administrative technology systems, to manage the operations and administration of our day-to-day business;

maintaining an effective system of internal controls, in compliance with the Sarbanes-Oxley Act of 2002;

replicating a regulatory compliance infrastructure, and governance infrastructure:

hiring, training orand retaining qualified personnel, as neededthe loss of which could reduce our competitiveness and prospects for future success. Attention to replace positions that have previously been provided as a shared service by Occidental;

identifying and filling gaps in management functions and expertise and establishing effective communication and information exchange among management teams and employees;

divertingsuch organizational activities could also divert management’s attention from our existing business; and

potentially losing business or key employees.

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, 2019,2020, WES Operating’s long-term debt was rated “BBB-”“BB” by Standard and Poor’s (“S&P”), “BBB-”“BB” by Fitch Ratings, and “Ba1”“Ba2” by Moody’s Investors Service.Service (“Moody’s”). In October 2019, S&P changed its outlook on2020, WES Operating’s credit rating from “developing”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 “negative.” 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, 2019,2020, there were $4.6$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, uncertainthe COVID-19 pandemic and resulting mitigation measures also are having an adverse impact on global demand for crude oileconomic conditions, and the increased supply resulting from the rapid development of shale plays throughout North America have contributed significantly to a substantial decline in crude-oil prices. Rapid development of the North American shale plays also has increased the supply of natural gasare contributing to a substantial dropsignificant decline in natural-gas prices. Additional factors impactingdemand for oil, NGLs, and natural gas, resulting in lower commodity prices include:

domesticthat will negatively impact our and worldwide economicour customers’ financial outlooks and geopolitical conditions;

weather conditions and seasonal trends;

the ability to develop recently discovered fields or deploy new technologies to existing fields;

the levels of domestic production and consumer demand, as affected by, among other things, concerns over inflation, geopolitical issues, and the availability and cost of credit;

the availability of imported, or a market for exported, liquefied natural gas;

the availability of transportation systems with adequate capacity;

the volatility and uncertainty of regional pricing differentials, such as in the Rocky Mountains;

the price and availability of alternative fuels;

the effect of energy conservation measures;

the nature and extent of governmental regulation and taxation; and

the forecasted supply and demand for, and prices of, oil, natural gas, NGLs, and other commodities.

activity levels.
Because of the natural decline in production from existing wells, our success depends on our ability to obtaincompete 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. Fluctuations in commodity prices also affect producers’ investments in the development of new oil and natural-gas reserves. Declines in oil and natural-gas prices have reduced exploration, development, and production activity materially in some regions and, if sustained, could lead to further decreases in such activities. 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 may deter producers (including Occidental) from developing those reserves.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.
WeThe 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.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 2019fourth-quarter 2020 distribution of $0.62200$0.31100 per unit per quarter, or $2.48800$1.24400 per unit per year, we require per-quarter available cash of $281.8$131.3 million, or $1.1 billion$525.1 million per year, based on the number of common units outstanding at January 31, 2020.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 basedquarter.
During 2020, we significantly reduced the quarterly cash distribution on among other things: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 pricesduration of levelthe COVID-19 macroeconomic disruption and the weakened commodity-price environment; however, the duration and severity of production of,this pandemic and demandconcomitant economic downturn remains uncertain. There can be no assurance that these announced actions will be adequate to preserve our financial health for oilthe required duration and natural gas;

additional actions, including additional per-unit distribution reductions, may be necessary to manage through the volume of oil, NGLs, natural gas, and produced watercurrent environment. Furthermore, any cash we gather, compress, process, treat, dispose, and/preserve from delaying or transport;

the volumes and prices of NGLs and condensate thatabandoning capital projects will necessarily delay or eliminate future returns we retain and sell;

demand charges and volumetric fees associated with our transportation services;

the level of competitionhoped to generate from other midstream companies;

regulatory action affecting the supply of or demand for oil or natural gas, the rates we can charge, how we contract for services, our existing contracts, our operating costs, or our operating flexibility; and

prevailing economic conditions.


In addition, the actual amount of cash available for distribution will depend on other factors, some ofpreviously planned projects, which are beyond our control, including the following:

our level of capital expenditures;

our level of operating and maintenance and general and administrative costs;

our debt-service requirements and other liabilities;

fluctuations in our working capital needs;

may meaningfully impact our ability to borrow fundsgenerate long-term revenue and accesscash-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 markets;

necessary to fund our continued treatment as a flow-through entity for U.S. federal income tax purposes;

restrictions contained in debt agreementsbusiness or to which we are a party; and

the amount of cash reserves established bypreserve our general partner.

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 Energy Corporation, which 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 upstream operator for substantially all ofgas volumes gathered by the natural gas, crude oil,Springfield system to our Brasada processing plant. If the attempted rejection is successful, our South Texas assets could be impaired and NGLs that we gather and process in the Eagleford Basin, and which, for the year ended December 31, 2019, directly represents 9% of our natural-gas gathering, treating, and transportation volumes, 1% of our crude-oil, NGLs, and produced-water volumes (excluding equity-investment volumes), and directly and indirectly 6% of our natural-gas processing volumes, filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code on August 12, 2019. As a result, our earnings, in the Eagleford Basin could be materially and adversely impacted, which also may result in impairments to the carrying value of our Eagleford assets.

Our strategies to reduce our exposure to changes in commodity prices may fail to protect us and could impact our financial condition negatively, thereby reducing our cash flows and our ability to make distributions to unitholders.

For the year ended December 31, 2019, 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil, NGLs, 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.
We pursue various strategies to reduce our exposure to adverse changes in the prices for natural gas, condensate, and NGLs. These strategies vary in scope based on the level and volatility of natural-gas, condensate, and NGLs prices and other changing market conditions. To the extent that we engage in price-risk management activities such as the commodity-price swap agreements, we may be prevented from realizing the full impact of price increases above the levels set in those agreements. In addition, our commodity-price management may expose us to the risk of financial loss in certain circumstances, including if counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements.
Additionally, if we are unable to manage risks associated with our contracts that have commodity-price exposure effectively, it could have a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.


unitholders could be materially and adversely impacted.
Implementation of new 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 now is taskedalso approved measures to address cumulative impacts by developing a new program with undertaking several reviews of existing regulations and new or amended rulemakings, with priority given to implementing the new public health, safety, and environmental priorities; cumulative impacts; and local government assistance and interaction. Moreover, the new law requires the Colorado Department of Public Health and Environment’s Air DivisionEnvironment, and the complete overhaul of the existing permitting procedures to adopt additional air-qualitycreate a unified permitting process. The new rules to minimize emissions from oil and natural-gas activities. While the COGCC already has rejected calls for a complete moratoriumwent into effect on new oil and natural-gas projects, it issued a set of “Objective Criteria” in May 2019, which calls for the COGCC to determine whether a pending permit will be subject to “additional review” to determine compliance with Senate Bill 19-181, pending completion of certain COGCC rulemakings necessary to implement the new law. Timing for issuance of new or amended rules pursuant to Senate Bill 19-181 is currently unknown, with hearings initiated in late 2019 and extending into 2020.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. For example, in late 2016, the EPA released its final report on the potential impacts
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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. Moreover, non-governmental organizations may seek to restrict hydraulic fracturing. Such was the case in Colorado where certain interest groups therein unsuccessfully pursued ballot initiatives in recent general election cycles that would have revised the state constitution or state statutes in a manner that would have made future exploration and production activities in the state more difficult or expensive, including, for example, by increasing mandatory setback distances of oil and natural-gas operations from specific occupied structures and/or certain environmentally sensitive or recreational areas.

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. 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 may be class action lawsuits, alleging that disposal-well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. 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.


Restrictions in the indentures governing our publicly traded notes (collectively, the “Notes”) or the RCF may limit our ability to capitalize on acquisitions and other business opportunities.

The operating and financial restrictions and covenants in the agreements governing the Notes, 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. The RCF contains, and with respect to the second, fourth and fifth bullets below, the indentures governing the Notes contain, covenants that restrict or limit our ability to do the following:

incur additional indebtedness or guarantee other indebtedness;

grant liens to secure obligations other than our obligations under the Notes or RCF or agree to restrictions on our ability to grant additional liens to secure our obligations under the Notes or RCF;

engage in transactions with affiliates;

make any material change to the nature of our business from the midstream business; or

enter into a merger, consolidate, liquidate, wind up, or dissolve.

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, as defined in the RCF, 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. See Part II, Item 7 of this Form 10-K for a further discussion of the terms of the RCF and Notes.

Debt we owe or incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our indebtedness could have important consequences to us, including the following:

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes may be impaired or financing may not be available on favorable terms;

our funds available for operations, future business opportunities, and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

our flexibility in responding to changing business and economic conditions may be limited.

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.


Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

Interest rates may increase in the future due to inflation, increased yields on U.S. Treasury obligations, or otherwise. In such cases, the interest rates on our floating-rate debt, including amounts outstanding under the RCF, would increase. If interest rates rise, our future financing costs could increase accordingly. In addition, as is true with other MLPs (the common units of which are often viewed by investors as yield-oriented securities), our unit price could be impacted by our implied distribution yield relative to market interest rates. The distribution yield often is used by investors to compare and rank yield-oriented securities for investment decision-making purposes. 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, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at intended levels.

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 and opposition by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural-gas development and production or midstream processing or transportationnatural-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 various 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 but are not limited to, 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.


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. As a result, we may be prevented from making distributions, 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.
The amount of available cash required to pay the distribution announced for the quarter ended December 31, 2019, on all of our common units was $281.8 million, or $1.1 billion per year. To the extent we do not have sufficient available cash under our partnership agreement, we may be unable to pay these distributions or similar distributions in the future.

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 industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in our areasTable of operation. Our competitors may expand or construct midstream systems that would create additional competition for the services that we provide to our customers. In addition, our customers, including Occidental, may develop their own midstream systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition, and ability to make cash distributions to our unitholders.Contents

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 an affiliatea 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. For example, seeSee the discussion of material impairments in Note 8—9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Further, at December 31, 2019, we had $445.8 million of goodwill recorded on our balance sheet. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. In addition, similar to the carrying value of the assets we previously acquired from Anadarko, part of our goodwill is an allocated portion of Anadarko’s previously recorded goodwill that was allocated to us at the time we acquired assets from Anadarko, which was recorded as a component of the carrying value of the assets acquired from Anadarko. As a result, we may be at increased risk for impairments relative to entities who acquire assets from third parties or construct their own assets, as the carrying value of our goodwill does not reflect, and in some cases is significantly higher than, the difference between the consideration we paid for our acquisitions and the fair value of the net assets on the acquisition date.

Goodwill is not amortized, but instead must be tested at least annually for impairment, and more frequently when circumstances indicate a likely impairment, by applying a fair-value-based test. Goodwill is deemed impaired to the extent that its carrying amount exceeds its implied fair value. Various factors could lead to goodwill impairments, such as our inability to maintain throughput on our systems or sustained lower oil and natural-gas prices, by reducing the fair value of the associated reporting unit. Prolonged low or further declines in commodity prices and changes to producers’ drilling plans in response to lower prices could result in future impairments. Future non-cash asset impairments could negatively affect our results of operations.

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.

Our interstate natural-gas 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 liquids transportation assets and operations are subject to regulation by FERC, which could have an adverse effect on our revenues and our ability to make distributions.

Our interstate natural-gas pipelines are subjectcash distributions to regulation by FERC. If we fail to comply with all applicable FERC-administered statutes, rules, regulations, and orders, weour unitholders could be subject to substantial penaltiesmaterially and fines. FERC has civil penalty authority to impose penalties for certain violations potentially in excess of $1.0 million per day for each violation. FERC also has the power to order the disgorgement of profits from transactions deemed to violate applicable statutes. For additional information, read Regulation of Operations–Interstate Natural-Gas Pipeline Regulation under Items 1 and 2 of this Form 10-K.
Our interstate liquids pipelines are common carriers and also are subject to regulation by FERC. For additional information, read Regulation of Operations—Interstate Liquids-Pipeline Regulation under Items 1 and 2 of this Form 10-K.
FERC regulation requires that common-carrier liquid-pipeline rates and interstate natural-gas pipeline rates be filed with FERC and that these rates be “just and reasonable” and not unduly discriminatory. Interested persons may challenge proposed new or changed rates, and FERC is authorized to suspend the effectiveness of such rates pending an investigation or hearing. 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. Accordingly, adverse action by FERC could affect our ability to establish reasonable rates that cover operating costs and allow for a reasonable return. An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on our business, financial condition, results of operations, and cash available for distribution. For example, one such matter relates to FERC’s policy regarding allowances for income taxes in determining a regulated entity’s cost of service. FERC’s Revised Policy Statement established that FERC will no longer permit master limited partnerships to recover an income tax allowance in cost-of-service rates and noted that to the extent an entity does not include an income tax allowance in cost-of-service rates, such entity may elect to exclude the accumulated deferred income tax balance from the rate calculation. This policy may result in an adverse impact on our revenues associated with the cost-of-service rates of our FERC-regulated gas and liquids pipelines. For additional information, read Regulation of Operations—Interstate Natural-Gas Pipeline Regulation and Regulation of Operations—Interstate Liquids-Pipeline Regulation under Items 1 and 2 of this Form 10-K.


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 result in increasednegatively 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. Examplesnegatively by increasing our compliance costs and the compliance costs of such proposed and/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 final regulationsall 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 otherdifficulty 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 are discussed below.

•
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 to 70 parts per billion under the primary and secondary standards to provide requisite protection of public health and welfare, respectively. 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 finalrelating 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 that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. 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 February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule and, in September 2018, the agency proposed amendments that included rescission or revision of specified rule requirements, such as fugitive emission monitoring frequency. In August 2019, the EPA proposed two options for rescinding the Subpart OOOOa standards. Under the EPA’s preferred alternative, the agency would rescind the methane limits for new, reconstructed, and modified oil and natural-gas production sources while leaving in place the general emission limits for volatile organic compounds (“VOCs”) and relieve the EPA of its obligation to develop guidelines for methane emissions from existing sources. In addition, the proposal would remove from the oil and natural-gas category the natural-gas transmission and storage segment. The other proposed alternative would rescind the methane requirements of the NSPS applicable to all oil and natural-gas sources, without removing any sources from that category (and still requiring control of VOCs in general). 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; however, in September 2018, the BLM published a final rule rescinding most of the new requirements of the 2016 final rule and codifying the BLM’s prior approach to venting and flaring, which rescission has been challenged in federal court and remains pending. Notwithstanding the uncertainty of the 2016 rule, we have taken measures to enter into a voluntary regime, together with certain other oil and natural-gas exploration and production operators, to 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.

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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. However, in August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement, and in November 2019 the United States formally initiated the withdrawal process. 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 operation.


Derivatives legislation could have an adverse effect on our abilitysubject us to use derivative instruments to reduce the effectincreased capital costs, operational delays, and costs of commodity-price, interest-rate, and other risks associated with our business.

The Dodd-Frank Act, among other things, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The CFTC has finalized certain of its regulations under the Dodd-Frank Act, but others remain to be finalized or implemented. It is not possible at this time to predict when this will be accomplished or what the terms of the final rules will be, so the impact of those rules is uncertain at this time.
The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, and reduce the availability of derivatives to protect against risks we encounter.

We may incur significant costs and liabilities resulting from pipeline-integrity programs and related repairs.

operation.
PursuantLegislation 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: (i)to, among other things, perform ongoing assessments of pipeline integrity; (ii) identifyintegrity and characterize applicable threats to pipeline segments that could impact HCAs; (iii) improve data collection, integration, and analysis; (iv) repair and remediate the pipeline as necessary; and (v) implement preventive and mitigating actions. In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines. At this time, we cannot predict the ultimate cost of compliance with these regulations, as the cost will vary significantly depending on the number and extent of any repairs or replacements of pipeline segments found to be necessary as a result of the pipeline-integrity testing. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or replacements of pipeline segments deemed necessary to ensure the safe and reliable operation of our pipelines. Moreover, the adoption of any new legislation or regulations that impose more-stringent or costly pipeline-integrity management could result in 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.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require 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. In 2016, President Obama signed the 2016 Pipeline Safety Act that extended PHMSA’s statutory mandate regarding pipeline safety through 2019, expanded PHMSA’s authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment, and required the agency to complete certain of its outstanding mandates established under the 2011 Pipeline Safety Act. The imposition of new pipeline safety or integrity management requirements pursuant to these enactedexisting 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. Regulatory initiatives targeting the reduction of certain air pollutants, such as ground level ozone or GHGs such as methane, have been proposed and/or adopted by the EPA and, while subject to further implementation or various legal impediments, could result in increased compliance costs. The adoption of these or any other 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.
In addition, the legal requirements related to the disposal of produced water into non-producing geologic formations by means of underground injection wells are subject to change based on public and governmental-authority concerns regarding such disposal activities. One such concern relates to seismic events near injection wells used for the disposal of produced water resulting from oil and natural-gas activities. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced-water disposal wells or otherwise to assess any 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, from time to time, is developing and implementing plans directing operators of wells injecting at certain depths where seismic incidents have occurred to restrict or suspend disposal-well operations. The Texas Railroad Commission has adopted similar permitting, operating, and reporting rules for disposal wells. Another consequence of seismic events may be class action lawsuits alleging 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, which could have a material adverse effect on our capital expenditures and operating costs, financial condition, and results of operations.


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. Construction projects also may require the expenditure of significant amounts of capital and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. For example, construction activities may be delayed or require greater capital investment if the commodity prices of certain supplies such as steel pipe increase due to foreign tariffs. In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural-gas and oil reserves, we often do not have access to estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could affect our results of operations and financial condition adversely. In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural-gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing existing or obtaining new rights-of-way increases, our cash flows could be affected adversely.

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. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. We cannot guarantee that we always will be able to renew existing rights-of-way or obtain new rights-of-way without experiencing significant costs. 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 the following:

(i) damage to pipelines and plants, related equipmentour assets and surrounding properties caused by hurricanes, tornadoes, floods, fires, and other natural disasters andor acts of terrorism;

(ii) inadvertent damage from construction, farm, and utility equipment;

(iii) leaks or losses of hydrocarbons or produced water as a result of the malfunction of equipment or facilities;

•
fires and explosions (for example, see Items Affecting the Comparability of Our Financial Results, under Part II, Item 7 of this Form 10-K for a discussion of the incident at the DBM complex); and

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.

Any acquisitions we pursue create additional execution and other risks and may or otherwise fail to meet our expectations.

Any future acquisitions involve potential additional risks, which may be of a different nature or magnitude from those currently affecting our business, including the following:

mistaken assumptions about volumes or the timing of the delivery of volumes, revenues or costs, including synergies;

an inability to successfully integrate the acquired assets or businesses;


the assumption of unknown liabilities, including environmental liabilities;

limitations on rights to indemnity from the seller;

mistaken assumptions about the overall costs of equity or debt;

the diversion of management’s and employees’ attention to other business concerns;

unforeseen difficulties operating in new geographic areas; and

customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capital structure and results of operations may change significantly.

We are subject to increasingincreased 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 increasingincreased 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.

The loss of, or difficulty in attracting and retaining, experienced personnel could reduce our competitiveness and prospects for future success.

The successful execution of our growth strategy and other activities integral to our operations depends, in part, on our ability to attract and retain experienced engineering, operating, commercial, and other professionals. Competition for such professionals historically has been intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be adversely impacted.


RISKS INHERENT IN AN INVESTMENT IN US

Occidental owns our general partner, which has sole responsibility for conducting our business and managing our operations. Occidental and our general partner have conflicts of interest with, and may favor Occidental’s interests to the detriment of our unitholders.

Occidental, the owner of our general partner, owns a 53.4% limited partner interest in us. Conflicts of interest may arise between (i) Occidental and our general partner and (ii) us and our unitholders. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Occidental over our interests and the interests of our unitholders. These conflicts include, among others, the following situations:

Neither our partnership agreement nor any other agreement requires Occidental to pursue a business strategy that favors us.

Occidental is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us.

Our general partner is allowed to take into account the interests of parties other than us, such as Occidental, in resolving conflicts of interest.

Our partnership agreement limits the liability of, and reduces the default state law fiduciary duties owed by, our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under state law.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

Our general partner has limited, and intends to continue to limit, its liability regarding our contractual and other obligations.

Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

Read Part III, Item 13 of this Form 10-K for additional information.


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 relationshipaffiliation with Occidental and that Occidental, through its significant economic interest in us, will continue to be motivated to promote and support the successful execution of our business plan and to pursue projects that 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.

Occidental is not limited in its ability to compete with us, which could limit our ability to grow and could affect our results of operations and cash available for distribution to our unitholders adversely.

Occidental is not prohibited from owning assets or engaging in businesses that directly or indirectly compete with us. In addition, in the future, Occidental may acquire, construct, or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to participate in such transactions.

Cost reimbursements due to Occidental and our general partner for services provided to us or on our behalf are substantial and reduce our cash available for distribution to our unitholders.

Prior to making distributions on our common units, we reimburse Occidental, which owns our general partner, and its affiliates for expenses incurred on our behalf as determined by our general partner pursuant to the Services Agreement. These expenses include all costs incurred by Occidental and our general partner in managing and operating us, and the reimbursement of certain general and administrative expenses we incur as a result of being a publicly traded partnership. Our partnership agreement and the Services Agreement provide that Occidental will determine in good faith the expenses that are allocable to us. Our general partner may, in good faith, significantly increase the amount of reimbursable general and administrative expenses in the future and any decision to do so would reduce the amount of cash otherwise available for distribution to our unitholders.

If you are not an Eligible Holder, you may not receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.

We have adopted certain requirements regarding investors that own our common units. Eligible Holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are U.S. individuals or entities subject to U.S. taxation. If you are not an Eligible Holder, our general partner may elect not to make distributions or allocate income or loss on your units and you bear the risk of having your units redeemed by us at the lower of your purchase-price cost and the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

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.

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. Examples of decisions that our general partner may make in its individual capacity include the following:

how to allocate corporate opportunities among us and its affiliates;

how to exercise voting rights with respect to the units it owns;

whether to exercise its registration rights; and

whether to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the above-described provisions.

Our partnership agreement restricts the remedies available to holders ofFurthermore, our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

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 any of the following:

(a)approved by the Special Committee of the Board of Directors, although our general partner is not obligated to seek such approval;
(b)approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
(c)on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
(d)fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In situations involving an affiliate transactionapproved in accordance with, or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the Special Committee and the Board of Directors determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either ofotherwise meets the standards set forth in, subclauses (c) and (d) above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such good-faith presumption.

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 have the following effects:

dilute our existing unitholders’ proportionate ownership interest in us will decrease;

interests and voting strength, and may reduce the amount of per-unitmarket price for our common units and cash available for distribution may decrease;

or increase the ratio of taxable income to distributions may increase;

the relative voting strength of each previously outstanding unit may be diminished; and

the market price of the common units may decline.

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 443,971,409413,839,863 common units outstanding as of December 31, 2019.2020. Occidental currently holds 242,136,976214,281,578 common units, representing 54.5%51.8% of our outstanding common units. Occidental’s shelf registration statement currently allows for the offer and sale of up to 50approximately 41.8 million common units, or 11.3%10.1% of our common units as of December 31, 2019,2020, 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’ 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.

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.

If we are deemed toUnitholders’ liability may not be an “investment company” under the Investment Company Act of 1940, it would affect the pricelimited if a court finds that unitholder action constitutes control of our common units adversely and could havebusiness.
A general partner of a material adverse effect on our business.

Our assets include, among other items, a $260.0 million note receivable from Anadarko. If this note receivable, together with a sufficient amount of our other assets are deemed to be “investment securities,” withinpartnership generally has unlimited liability for the meaningobligations of the Investment Company Act of 1940 (the “Investment Company Act”), we either would have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC, or modify our organizational structure or contract rights so as to fall outsidepartnership, except for those contractual obligations of the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property from or to our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add additional directors whopartnership that are independent of us or our affiliates. The occurrence of some or all of these events would affect the price of our common units adversely and could have a material adverse effect on our business.
Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal and possibly state income taxes on our taxable income at applicable corporate tax rates; distributions received by our unitholders generally would be taxed as corporate distributions; and none of our income, gains, losses, or deductions would flow through to our unitholders. If we were taxed as a corporation, our cash available for distribution to our unitholders would be reduced substantially. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flows and after-tax returnexpressly made without recourse to the unitholders, likely causing a substantial reductiongeneral partner. Our partnership is organized under Delaware law, and we conduct business in the value of our common units.


The market price of our common units could be volatile due to a number of factors, manyother 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 are beyond our control.

The market pricewe do business. A unitholder could be liable for any and all of our common units could be subjectobligations as if that unitholder were a general partner if a court or government agency were to wide fluctuationsdetermine that we were conducting business in responsea state, but had not complied with that particular state’s partnership statute, or such unitholder’s right to a number of factors, most of which we cannot control, including the following:

changes in investoract with other unitholders to remove or analyst estimates of Occidental’s andreplace our financial performancegeneral partner, to approve some amendments to our partnership agreement, or to take other actions under our future distribution growth;

the public’s reaction to Occidental’s or our press releases, announcements, and filings with the SEC;

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

fluctuations in broader securities market prices and volumes, particularly among securities of midstream companies and securities of publicly traded limited partnerships;

changes in market valuations of similar companies;

departures of key personnel;

commencement of or involvement in litigation;

variations in our quarterly results of operations or those of other midstream companies;

variations in the amountagreement constitute “control” of our quarterly cash distributions;business.

future issuances and sales

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changes in general conditions in the U.S. economy, financial markets, or the midstream industry.

In recent years, the capital markets have experienced extreme volatility that has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.


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. For example, the “Clean Energy for America Act,” which is similar to legislation that was commonly proposed during the Obama Administration, was introduced in the Senate on May 2, 2019. If enacted, this proposal would, among other things, repeal Section 7704(d)(1)(E) of the Code, which we rely on for our status as a partnership for U.S. federal income tax purposes.
In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future. We believe the income that we treat as qualifying income satisfies the requirements under current regulations.
We are unable to predict whether any changes or proposals ultimately will be enacted. 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 us to satisfy the requirementscertain publicly traded partnerships to be treated as a partnershippartnerships for U.S. federal income tax purposes and could impactor increase the valueamount of an investmenttaxes payable by unitholders in our common units negatively.
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 (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustmentsadjustment directly from us, in which case our cash available for distribution to our unitholders might be reduced substantially. In addition, our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.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 (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustmentsadjustment directly from us. To the extent possible under the new rules, our general partner may electGenerally, we expect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their respective interests in us during the tax year under audit, but there can be no assurance that such election will be practical, permissible,made, or effectiveapplicable, in all circumstances. As a result,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 tax liabilityeconomic burden resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year for which an adverse audit finding relates.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 reduced substantially and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

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 and, in some cases, state and local income taxes on their share of our taxable income irrespective of whether they receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, unitholders may be allocated taxable income and gain resulting from the sale, and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, including debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. Our unitholdersUnitholders 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.
Irrespective of whether a unitholder’s disposition of common units results in a gain, a substantial portion of the amount realized from a unitholder’s sale of units may be taxed as ordinary income to the unitholder due to potential recapture of items, including depreciation recapture. Thus, a unitholder may recognize ordinary incomeTax-exempt entities and capital loss from the sale of units if the amount realized on the sale is less than the unitholder’s adjusted basis in the units. Net capital loss may offset only capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells units, the unitholder may recognize ordinary income from our allocations of income and gain prior to the sale and from recapture items, which generally cannot be offset by any capital loss recognized on the sale of units.

Tax-exempt entitiesforeign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans, and individual retirement accounts (or “IRAs”) and foreign persons raises issues unique issues.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 taxable as unrelated business taxable income. Further, for taxable years beginning after December 31, 2017, subject to the Treasury Department’s proposed aggregation rules regarding certain similarly situated businesses or activities, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trades or businesses) is required to compute the 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 tax-exempt entity separatelysale, exchange or other disposition if any portion of the gain on such sale, exchange, or other disposition would be treated as effectively connected with respect to each sucha U.S. trade or business (includingbusiness. The U.S. Department of the Treasury and the IRS have recently issued final regulations providing guidance on the application of these rules for purposestransfers of determining anycertain 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 operating loss deduction). As a result, for taxable years beginning after December 31, 2017, it mayincome that has not be possible for tax-exempt entitiespreviously been distributed. The U.S. Department of the Treasury and the IRS have provided that these rules will generally not apply to utilize losses from an investment in us to offset unrelated business taxable income from another unrelated trade or business, and vice versa. Tax-exempt entitiestransfers of our common units occurring before January 1, 2022. Foreign unitholders should consult atheir tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to U.S. taxes and withholding on income and gain from owning our units.

Non-U.S. unitholders generally are taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units generally will be considered “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder are subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit also is subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized on a non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open-market trading and other complications, the IRS temporarily has suspended the application of this withholding obligation to open-market transfers of interests in publicly traded partnerships, pending promulgation of final regulations. It is not clear when such final regulations will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.


We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could affect the value of our common units adversely.

Because we cannot match transferors and transferees of common units, we have adopted certain methods of allocating depreciation and amortization deductions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods 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.

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.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered to have disposed of those common units. If so, the unitholder would no longer be treated as a partner for tax purposes with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated as a partner for tax purposes with respect to those common units during the period of the loan, and the unitholder may recognize gain or loss from such deemed disposition. Moreover, during the period of the loan, any of our income, gain, loss, or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from lending their common units.

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 foreign, state, and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders mayjurisdictions, or be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is the responsibility of each unitholder to file all U.S. federal, foreign, state, and local tax returns.

Item 1B.  Unresolved Staff Comments

None.

Item 3.  Legal Proceedings

Kerr-McGee Gathering LLC, a wholly owned subsidiaryOn July 1, 2020, the U.S. Department of WES, is currently in negotiations withJustice, on behalf of the U.S. Environmental Protection Agency (the “EPA”), and the State of Colorado with respect tocommenced 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 and WGR Operating, LP, another wholly owned subsidiary of WES, iscomplex. KMG previously had been in negotiations with the EPA and the State of Wyoming with respectColorado to resolve the alleged non-compliance with LDAR requirements at its Granger, Wyomingthe Fort Lupton facility. Although managementPer the complaint, plaintiffs pray for injunctive relief, remedial action, and civil penalties. Management cannot predictreasonably estimate the outcome of settlement discussionsthis 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 these matters, management believesthe 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 it is reasonably likelythe Springfield system gathers and that WES processes in the Eagle Ford Shale Play. On April 29, 2020, we received notice that Sanchez filed a resolutionmotion 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 matters will resultSanchez 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 finedeclaratory 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 penalty for each matter in excess of $100,000.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 24, 2020,22, 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.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) and the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (collectively referred to as the “LTIPs”) to our independent directors, executive officers, and Occidental employees performing servicesemployees. The WES LTIP permits the issuance of up to 3,000,000 units, of which 2,823,967 units remained available for us from time to time.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 3,419,0203,431,251 units remained available for future issuance as of December 31, 2019. The Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan permits the issuance of up to 3,000,000 units, of which 2,911,985 units remained available for future issuance as of December 31, 2019. Phantom unit grants under the LTIPs have been made to each of the independent directors of our general partner.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. OurUnder our partnership agreement, requires us towe distribute all of our available cash (as(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 (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such quarter, less the amount of cash reserves established by the 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. OurAs of December 31, 2020, our general partner ownsowned a 2.0%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 6.  Selected7.  Management’s Discussion and Analysis of Financial Condition and Operating DataResults of Operations

The following Summarydiscussion analyzes our financial condition and results of operations and should be read in conjunction with the Consolidated Financial Information tables show the selected financialStatements and operating data of WES andNotes to Consolidated Financial Statements, wherein WES Operating is fully consolidated, and which are derived fromincluded under Part II, Item 8 of this Form 10-K, and the respective consolidated financial statements for the periods and asinformation set forth in Risk Factors under Part I, Item 1A of the dates indicated. Our consolidated financial statements include the consolidated financial results of WES Operating.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%98.0% partnership interest in WES Operating, as of December 31, 20192020 (see Note 10—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.

Occidental Merger. On August 8, 2019, Anadarko, the indirect general partner and majority unitholder of WES, was acquired by Occidental pursuant to the Occidental Merger.

Acquisitions. The following table presents the acquisitions completed by us for the periods presented in the Summary Financial Information table below. Our consolidated financial statements include the combined financial results and operations for: (i) affiliate acquisitions for all periods presented and (ii) third-party acquisitions since the acquisition date.
Acquisition DatePercentage AcquiredAffiliate or Third-party Acquisition
DBJV system03/02/201550%Affiliate
Springfield system03/14/201650.1%Affiliate
DBJV system (1)
03/17/201750%Third party
Whitethorn LLC (2)
06/01/201820%Third party
Cactus II (2)
06/27/201815%Third party
Red Bluff Express (2)
01/18/201930%Third party
(1)
See Property exchange below.
(2)
See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional details.

Acquisition of AMA. In February 2019, WES Operating acquired AMA from Anadarko. See Note 3—Acquisitions and Divestitures under Part II, Item 8 of this Form 10-K for further information.

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

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


The information in the following tables should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements, which are included under Part II, Item 8 of this Form 10-K, and with the information under the captions Items Affecting the Comparability of Our Financial Results, How We Evaluate Our Operations,and Results of Operations under Part II, Item 7 of this Form 10-K.
The following table presents selected financial and operating data for WES:
  Summary Financial Information
thousands except per-unit data, throughput, per-Mcf Adjusted gross margin, and per-Bbl Adjusted gross margin 2019 2018 2017 2016 2015
Statement of Operations Data (for the year ended):          
Total revenues and other $2,746,174
 $2,299,658
 $2,429,614
 $1,941,330
 $1,853,233
Cost of product 444,247
 415,505
 953,792
 517,371
 551,287
Operating income (loss) 1,231,343
 861,282
 801,698
 783,082
 202,105
Net income (loss) 807,700
 630,654
 737,385
 658,286
 48,980
Net income (loss) attributable to noncontrolling interests 110,459
 79,083
 196,595
 251,208
 (154,409)
Net income (loss) attributable to Western Midstream Partners, LP 697,241
 551,571
 540,790
 407,078
 203,389
Net income (loss) per common unit – basic and diluted 1.59
 1.69
 1.72
 1.53
 0.39
Distributions per unit 2.47000
 2.34875
 2.10500
 1.76750
 1.49125
Balance Sheet Data (at year end):          
Total assets $12,346,453
 $11,457,205
 $9,430,090
 $8,709,610
 $8,196,163
Total long-term liabilities 8,515,206
 5,927,045
 3,887,074
 3,503,934
 3,285,264
Total equity and partners’ capital 3,345,293
 4,892,683
 4,995,050
 4,872,656
 4,645,456
Cash Flow Data (for the year ended):          
Net cash flows provided by (used in):          
Operating activities $1,324,100
 $1,348,175
 $1,042,715
 $1,056,149
 $873,330
Investing activities (3,387,853) (2,210,813) (1,133,324) (1,229,874) (740,816)
Financing activities 2,071,573
 875,192
 (188,875) 433,103
 (100,033)
Capital expenditures (1,188,829) (1,948,595) (1,026,932) (547,986) (786,945)
Throughput for natural-gas assets (MMcf/d):
Total throughput 4,423
 4,068
 3,840
 4,219
 4,442
Throughput attributable to noncontrolling interests (1)
 175
 170
 179
 206
 228
Total throughput attributable to WES for natural-gas assets 4,248
 3,898
 3,661
 4,013
 4,214
Throughput for crude-oil, NGLs, and produced-water assets (MBbls/d)
Total throughput 1,219
 775
 406
 371
 295
Throughput attributable to noncontrolling interests (1)
 24
 15
 8
 7
 6
Total throughput attributable to WES for crude-oil, NGLs, and produced-water assets 1,195
 760
 398
 364
 289
Key Performance Metrics (for the year ended): (2)
          
Adjusted gross margin for natural-gas assets $1,656,041
 $1,443,466
 $1,256,160
 $1,225,245
 $1,168,141
Adjusted gross margin for crude-oil, NGLs, and produced-water assets 772,036
 534,739
 263,709
 227,679
 159,116
Per-Mcf Adjusted gross margin for natural-gas assets 1.07
 1.01
 0.94
 0.83
 0.76
Per-Bbl Adjusted gross margin for crude-oil, NGLs, and produced-water assets 1.77
 1.93
 1.82
 1.71
 1.51
Adjusted EBITDA 1,719,090
 1,466,445
 1,169,651
 1,114,114
 961,139
Distributable cash flow 1,325,445
 1,139,587
 1,010,850
 923,163
 830,017
(1)
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 as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2)
Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow are not defined in GAAP. For definitions and reconciliations of these non-GAAP financial measures to their most directly comparable financial measure calculated and presented in accordance with GAAP, see How We Evaluate Our Operations under Part II, Item 7 of this Form 10-K.

The following table presents selected financial data for WES Operating:
  Summary Financial Information
thousands except per-unit data 2019 2018 2017 2016 2015
Statement of Operations Data (for the year ended):          
Total revenues and other $2,746,174
 $2,299,658
 $2,429,614
 $1,941,330
 $1,853,233
Cost of product 444,247
 415,505
 953,792
 517,371
 551,287
Operating income (loss) 1,238,162
 865,311
 804,570
 786,755
 205,253
Net income (loss) 814,685
 636,526
 742,401
 663,600
 52,089
Net income (loss) attributable to noncontrolling interest 7,095
 8,609
 10,735
 10,963
 10,101
Net income (loss) attributable to Western Midstream Operating, LP 807,590
 627,917
 731,666
 652,637
 41,988
Net income (loss) per common unit – basic and diluted N/A
 0.55
 1.30
 1.74
 (1.95)
Distributions per unit —
 3.830
 3.590
 3.350
 3.050
Balance Sheet Data (at year end):          
Total assets $12,342,825
 $11,454,845
 $9,428,129
 $8,706,541
 $8,194,016
Total long-term liabilities 8,515,206
 5,927,045
 3,859,074
 3,475,934
 3,285,264
Total equity and partners’ capital 3,341,819
 4,919,597
 5,021,182
 4,897,669
 4,643,386
Cash Flow Data (for the year ended):          
Net cash flows provided by (used in):          
Operating activities $1,332,189
 $1,352,114
 $1,046,798
 $1,060,658
 $876,166
Investing activities (3,387,853) (2,210,813) (1,133,324) (1,229,874) (740,816)
Financing activities 2,063,338
 870,333
 (192,585) 429,108
 (104,371)
Capital expenditures (1,188,829) (1,948,595) (1,026,932) (547,986) (786,945)


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, 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% partnership interest in WES Operating, as of December 31, 2019 (see Note 10—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.

EXECUTIVE SUMMARY

We currently own or have investments in assets located in the Rocky Mountains (Colorado, Utah, and Wyoming), North-central Pennsylvania, Texas, and New Mexico. We are 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 provideown or have investments in assets located in Texas, New Mexico, the above-described midstream services for OccidentalRocky Mountains (Colorado, Utah, and third-party customers.Wyoming), and North-central Pennsylvania. As of December 31, 2019,2020, our assets and investments consisted of the following:
Wholly
Owned and
Operated		Operated
Interests		Non-Operated
Interests		Equity
Interests
Gathering systems (1)
17 2 3 1 
Treating facilities39 3 — — 
Natural-gas processing plants/trains25 3 — 5 
NGLs pipelines2 — — 5 
Natural-gas pipelines5 — — 1 
Crude-oil pipelines3 1 — 4 

  
Wholly
Owned and
Operated
 
Operated
Interests
 
Non-Operated
Interests
 
Equity
Interests
Gathering systems (1)
 17
 2
 3
 2
Treating facilities 37
 3
 —
 3
Natural-gas processing plants/trains 25
 3
 —
 5
NGLs pipelines 2
 —
 —
 4
Natural-gas pipelines 5
 —
 —
 1
Crude-oil pipelines 3
 1
 —
 3
(1)(1)
Includes the DBM water systems.


December 2019 Agreements. On December 31, 2019, (i) WES and certain of its subsidiaries, including WES Operating and WES Operating GP, entered into the below-described agreements with Occidental and/or certain of its subsidiaries, including Anadarko, and (ii) WES Operating also entered into the below-described amendments to its debt agreements (collectively referred to as the “December 2019 Agreements”).

•
Exchange Agreement. WGRI, the general partner, and WES entered into a partnership interests exchange agreement (the “Exchange Agreement”), pursuant to which WES canceled the non-economic general partner interest in WES and simultaneously issued a 2.0% general partner interest to the general partner in exchange for which WGRI transferred 9,060,641 WES common units to WES, which immediately canceled such units on receipt.

•
Services, Secondment, and Employee Transfer Agreement. Occidental, Anadarko, and WES Operating GP entered into the Services Agreement, pursuant to which Occidental, Anadarko, and their subsidiaries will (i) second certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP will pay a monthly secondment and shared services fee to Occidental equivalent to the direct cost of the seconded employees and (ii) continue to provide certain administrative and operational services to WES for up to a two-year transition period. The Services Agreement also includes provisions governing the transfer of certain employees to WES and WES’s assumption of liabilities relating to those employees at the time of their transfer. In January 2020, pursuant to the Services Agreement, Occidental made a one-time cash contribution of $20.0 million to WES for anticipated transition costs required to establish stand-alone human resources and information technology functions.

•
RCF amendment. WES Operating entered into an amendment to its RCF to, among other things, (i) effective on February 14, 2020, exercise the final one-year extension option to extend the maturity date of the RCF to February 14, 2025, for the extending lenders, and (ii) modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of WES elect to remove the general partner as the general partner of WES in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the RCF.

•
Term loan facility amendment. WES Operating entered into an amendment of its Term loan facility to, among other things, modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of WES elect to remove the general partner as the general partner of WES in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the Term loan facility.

•
Termination of debt-indemnification agreements. WES Operating GP and certain wholly owned subsidiaries of Occidental mutually terminated the debt-indemnification agreements related to indebtedness incurred by WES Operating.

•
Termination of omnibus agreements. WES and WES Operating entered into agreements with Occidental to terminate the WES and WES Operating omnibus agreements. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information on the WES and WES Operating omnibus agreements.

Occidental Merger. On August 8, 2019, Anadarko, the indirect general partner and majority unitholder of WES, was acquired by Occidental pursuant to the Occidental Merger.


Merger transactions. On February 28, 2019, WES, WES Operating, Anadarko, and certain of their affiliates completed the transactions contemplated by the Contribution Agreement and Agreement and Plan of Merger (the “Merger Agreement”) dated November 7, 2018, pursuant to which, among other things, Clarity Merger Sub, LLC, a wholly owned subsidiary of WES, merged with and into WES Operating, with WES Operating continuing as the surviving entity and as a subsidiary of WES (the “Merger”). In connection with the Merger closing, (i) the common units of WES Operating, which previously traded under the symbol “WES,” ceased to trade on the NYSE, (ii) the common units of WES, which previously traded under the symbol “WGP,” began to trade on the NYSE under the symbol “WES,” (iii) WES changed its name from Western Gas Equity Partners, LP to Western Midstream Partners, LP, and (iv) WES Operating changed its name from Western Gas Partners, LP to Western Midstream Operating, LP.
The Merger Agreement also provided that WES, WES Operating, and Anadarko cause their respective affiliates to execute the following transactions, among others, immediately prior to the Merger becoming effective in the following order: (1) Anadarko E&P Onshore LLC and WGRAH (the “Contributing Parties”) contribute to WES Operating, and WES Operating subsequently contributes to WGR Operating, LP, Kerr-McGee Gathering LLC, and DBM (each wholly owned by WES Operating), all
66
Table of their interests in each of Anadarko Wattenberg Oil Complex LLC, Anadarko DJ Oil Pipeline LLC, Anadarko DJ Gas Processing LLC, Wamsutter Pipeline LLC, DBM Oil Services, LLC, Anadarko Pecos Midstream LLC, Anadarko Mi Vida LLC, and APC Water Holdings 1, LLC (“APCWH”) in exchange for aggregate consideration of $1.814 billion of cash, less the outstanding amount payable pursuant to an intercompany note (the “APCWH Note Payable”) assumed by WES Operating in connection with the transfer, and 45,760,201 WES Operating common units; (2) AMH transfers its interests in Saddlehorn Pipeline Company, LLC, and Panola Pipeline Company, LLC to WES Operating in exchange for $193.9 million of cash; (3) WES Operating contributes cash in an amount equal to the outstanding balance of the APCWH Note Payable immediately prior to the effective time of the Merger to APCWH, which in turn uses the contributed cash to satisfy the APCWH Note Payable to Anadarko; (4) the WES Operating Class C units convert into WES Operating common units on a one-for-one basis; and (5) WES Operating and WES Operating GP convert the IDRs and the 2,583,068 general partner units in WES Operating held by WES Operating GP into a non-economic general partner interest in WES Operating and 105,624,704 WES Operating common units. The 45,760,201 WES Operating common units issued to the Contributing Parties, less 6,375,284 WES Operating common units retained by WGRAH, convert into the right to receive an aggregate of 55,360,984 common units of WES at Merger completion. Each WES Operating common unit issued and outstanding immediately prior to the closing of the Merger (other than WES Operating common units owned by WES and WES Operating GP, and certain common units held by subsidiaries of Anadarko) converts into the right to receive 1.525 common units of WES. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information.Contents
Additional significantSignificant financial and operational events during the year ended December 31, 2019,2020, 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 increasedrepurchased 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 to $0.62200of $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 the fourth quarter of 2019, representing a 0.3% increase over the third-quarter 2019 distribution and a 3% increase over the fourth-quarter 2018 distribution.additional information.

•
In July 2019, WES Operating entered into an amendment to the Term loan facility to (i) extend the maturity date from February 2020 to December 2020, and (ii) increase commitments available under the Term loan facility from $2.0 billion to $3.0 billion, the incremental $1.0 billion of which was subsequently drawn by WES Operating on September 13, 2019, and used to repay outstanding borrowings under the RCF. In December 2019, WES Operating amended certain provisions of the Term loan facility. See Liquidity and Capital Resources within this Item 7 for additional information.

•
In March 2019, WES Operating entered into additional interest-rate swap agreements with an aggregate notional principal amount of $375.0 million. 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 those entered into in December 2018 and March 2019. In December 2019, all outstanding interest-rate swap agreements were cash-settled. See Liquidity and Capital Resources within this Item 7 for additional information.

•
In March 2019, the WGP RCF matured and the outstanding borrowings were repaid. See Liquidity and Capital Resources within this Item 7 for additional information.


We commenced operations of MentoneLatham Train II at the West Texas complex (with capacity of 200 MMcf/d) and Latham Train I at the DJ Basin complex (with capacity of 200250 MMcf/d) during the first quarter of 2020 and Loving ROTF Trains III and IV at the endDBM oil system (with capacity of 30 MBbls/d each) during the first and fourththird quarters respectively, of 2019.2020, 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.

•
In February 2019, WES Operating increased the size of the RCF from $1.5 billion to $2.0 billion and extended the maturity date of the RCF to February 2024. In December 2019, WES Operating extended the maturity date of the RCF to February 2025 for the extending lenders and modified the change of control definition in the RCF. See Liquidity and Capital Resources within this Item 7 for additional information.

•
In January 2019, we acquired a 30% interest in Red Bluff Express from a third party. See Acquisitions and Divestitures under Part I, Items 1 and 2 of this Form 10-K for additional information.

Natural-gas throughput attributable to WES totaled 4,2484,274 MMcf/d for the year ended December 31, 2019,2020, representing a 9%1% increasecompared 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% increasecompared 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, 2018.2019.

Crude-oil, NGLs, and produced-water throughput attributable to WES totaled 1,195 MBbls/d•Operating income (loss) was $878.9 million for the year ended December 31, 2019,2020 (included goodwill and long-lived asset impairments of $644.9 million), representing a 57%29% decrease compared to the year ended December 31, 2019.
67
Table of Contents

•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% increasecompared 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% increasecompared 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, 2018.2019.

Operating income (loss) was $1,231.3 million for the year ended December 31, 2019, representing a 43% increase compared to the year ended December 31, 2018.

•
Adjusted gross margin for natural-gas assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.07 per Mcf for the year ended December 31, 2019, representing a 6% increase compared to the year ended December 31, 2018.

•
Adjusted gross margin for crude-oil, NGLs, and produced-water assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.77 per Bbl for the year ended December 31, 2019, representing an 8% decrease compared to the year ended December 31, 2018.

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 6 %189 150 26 %712 556 28 %
DJ Basin1,305 1,236 6 %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 7 %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.


68
  Year Ended December 31,
  2019 2018 Inc/
(Dec)		 2019 2018 Inc/
(Dec)		 2019 2018 Inc/
(Dec)
  
Natural gas
(MMcf/d)
 
Crude oil & NGLs
(MBbls/d)
 
Produced water
(MBbls/d)
Delaware Basin 1,226
 1,041
 18 % 150
 132
 14 % 556
 239
 133%
DJ Basin 1,236
 1,133
 9 % 118
 105
 12 % —
 —
 —%
Equity investments 398
 291
 37 % 343
 241
 42 % —
 —
 —%
Other 1,563
 1,603
 (2)% 52
 58
 (10)% —
 —
 —%
Total throughput 4,423
 4,068
 9 % 663
 536
 24 % 556
 239
 133%

Table of Contents



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, and 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 6—Transactions with Affiliates1—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, andNote 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, and (v) the WES Operating Series A Preferred units issued to private investors as partDBM.


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Table of the funding of the Springfield acquisition, until converted into WES Operating common units in 2017.Contents

Commodity-price swap agreements. During all periods presented, theThe consolidated statements of operations and consolidated statements of equity and partners’ capital included the impacts of commodity-price swap agreements.agreements for the years ended December 31, 2019 and 2018. See Note 6—Related-Party Transactions with Affiliates 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.

Acquisitions and divestitures.For the year ended December 31, 2019, there was a net increase in Adjusted gross margin of $4.1 million related to our third-party asset acquisition during 2019. For the year ended December 31, 2018, there was a net increase in Adjusted gross margin of $40.5 million related to our third-party asset acquisitions and divestitures during 2018. See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information and How We Evaluate Our Operations within this Item 7 for the definition of Adjusted gross margin.

Impairments. During 2018, we recognized impairments of $230.6 million, including impairments of (i) $125.9 million at the Third Creek gathering system and $8.1 million at the Kitty Draw gathering system due to the shutdown of the systems, (ii) $38.7 million at the Hilight system, and (iii) $34.6 million at the MIGC system. During 2017, we recognized impairments of $180.1 million, including an impairment of $158.8 million at the Granger complex due to a reduced throughput fee as a result of a producer’s bankruptcy. See Note 1—Summary of Significant Accounting Policies and Note 8—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.


DBM complex. In December 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. The majority of the damage from the incident was to the liquid handling facilities and the amine-treating units at the inlet of the complex. During the year ended December 31, 2017, a $5.7 million loss was recorded in Gain (loss) on divestiture and other, net in the consolidated statements of operations, related to a change in the estimate of the amount that would be recovered under the property insurance claim based on further discussions with insurers. During the second quarter of 2017, we reached a settlement with insurers and final proceeds were received. During the year ended December 31, 2017, we received $52.9 million in cash proceeds from insurers, including $29.9 million in proceeds from business interruption insurance claims and $23.0 million in proceeds from property insurance claims. See Note 1—Summary of Significant Accounting Policiesin the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Adoption of Topic 606. On January 1, 2018, we adopted Revenue from Contracts with Customers (Topic 606) (“Topic 606”). The 2017 financial information was not adjusted and is reported under Revenue Recognition (Topic 605). See Note 1—Summary of Significant Accounting Policiesin the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for information on our current revenue recognition policy.

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.
Currently we have operationsWe operate in Texas, New Mexico, Colorado, Utah, Wyoming, and North-central Pennsylvania, Texas, and New Mexico, with a substantial portion of our business concentrated in West Texas and the Rocky Mountains and West Texas.Mountains. For example, for the year ended December 31, 2019,2020, our West Texas and DJ Basin and West Texas assets provided (i) 31%46% and 38%, respectively, of Total revenues and other, (ii) 33% each of our throughput for natural-gas assets (excluding equity-investment throughput), (ii) 13%(iii) 57% and 81%31%, respectively, of our throughput for crude-oil NGLs, and produced-waterNGLs assets (excluding equity-investment throughput), and (iii) 36% and 44%, respectively,(iv) all of Total revenues and other.our throughput for produced-water assets.
For the year ended December 31, 2019, 59%2020, 66% of Total revenues and other, 38%41% of our throughput for natural-gas assets (excluding equity-investment throughput), and 83%88% of our throughput for crude-oil NGLs, and produced-waterNGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets were attributable to transactionsproduction owned or controlled by Occidental. While Occidental is our contracting counterparty, these arrangements with Occidental.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 supports our operations by providingprovides dedications and/or minimum-volume commitments.commitments under certain of our contracts.
For the year ended December 31, 2019,2020, 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil NGLs, 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), (v)(vii) Adjusted EBITDA (as defined below), and (vi) Distributable(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 Executive Summary–December 2019 Agreements2019. See further detail in Note 6—Related-Party Transactionswithin in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Item 7)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 approved by our Board of Directors. Pursuant to the WES and WES Operating omnibus agreements, Occidental and our general partner performed centralized corporate functions for us. General and administrative expenses for periods prior to the acquisition of assets from Anadarko included costs allocated by Anadarko through a management services fee. For periods subsequent to the acquisition of assets from Anadarko, allocations and reimbursements of general and administrative expenses were determined by Occidental in its reasonable discretion, in accordance with our partnership and omnibus agreements. Amounts required to be reimbursed to Occidental under the omnibus agreements also included any expenses attributable to our status as a publicly traded partnership, which were paid by Occidental and may include the following:

expenses associated with annual and quarterly reporting;

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

expenses associated with listing on the NYSE; and

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

The WES and WES Operating omnibus agreements were terminated in connection with the execution of the December 2019 Agreements.budget. Pursuant to the Services Agreement entered into as part of the December 2019 Agreements,, Occidental (i) secondsseconded certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP payspaid 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) continuesagreed to continue to provide certain administrative and operational services to us for up to a two-year transition period. See further detail in Executive Summary–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, within this Item 7 Occidental and Note 6—Transactions with Affiliates in our general partner performed centralized corporate functions for us pursuant to the now terminated WES and WES Operating omnibus agreements.
Notes to Consolidated Financial Statements
under Part II, Item 8 of this Form 10-KSafety 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, and 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.

Distributable
Free cash flow. We define “Distributable“Free cash flow” as Adjusted EBITDA,net cash provided by operating activities less total capital expenditures and contributions to equity investments, plus interest income and the net settlement amountsdistributions from the sale and/or purchase of natural gas, condensate, and NGLs under WES Operating’s commodity-price swap agreements to the extent such amounts are not recognized as Adjusted EBITDA, less Service revenues – fee based recognized in Adjusted EBITDAequity investments in excess of (less than) customer billings, net cash paid (or to be paid) for interest expense (including amortization of deferred debt issuance costs originally paid in cash and offset by non-cash capitalized interest), maintenance capital expenditures, WES Operating Series A Preferred unit distributions, income taxes, and Distributablecumulative earnings. Management considers Free cash flow attributable to noncontrolling interests to the extent such amounts are not excluded from Adjusted EBITDA. We compare Distributable cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management determines the Coverage ratio of Distributable cash flow to planned cash distributions. We believe Distributablean appropriate metric for assessing capital discipline, cost efficiency, and balance-sheet strength. Although Free cash flow is useful to investors because this measurement isthe metric used by many companies, analysts, and others in the industry as a performance measurement tool to evaluate our operating and financial performance as compared to the performance of other publicly traded partnerships.
Distributable cash flow is a measure we use to assess ourWES’s ability to make distributions to our unitholders; however,unitholders, this measure should not be viewed as indicative of the actual amount of cash that is available for distributions or planned for distributiondistributions for a given period. Furthermore, to the extent DistributableInstead, Free cash flow includes realized amounts recorded as capital contributions from Anadarko attributable to activity under our commodity-price swap agreements, itshould be considered indicative of the amount of cash that is not a reflectionavailable for distributions, debt repayments, and other general partnership purposes.

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Table of our ability to generate cash from operations.Contents


Reconciliation of non-GAAP financial measures. Adjusted gross margin, Adjusted EBITDA, and DistributableFree 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 DistributableFree cash flow is net income (loss).cash provided by operating activities. Our non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, and DistributableFree 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 DistributableFree 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 DistributableFree 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 DistributableFree 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 DistributableFree cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA, and DistributableFree 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 (a)(i) a reconciliation of the GAAP financial measure of our operating income (loss) to the non-GAAP financial measure of Adjusted gross margin, (b)(ii) a reconciliation of the GAAP financial measures of our net income (loss) and our net cash provided by operating activities to the non-GAAP financial measure of Adjusted EBITDA, and (c)(iii) a reconciliation of the GAAP financial measure of our net income (loss)cash provided by operating activities to the non-GAAP financial measure of DistributableFree 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,
thousands 2019 2018 2017
Reconciliation of Operating income (loss) to Adjusted gross margin      
Operating income (loss) $1,231,343
 $861,282
 $801,698
Add:      
Distributions from equity investments 264,828
 216,977
 148,752
Operation and maintenance 641,219
 480,861
 345,617
General and administrative 114,591
 67,195
 53,949
Property and other taxes 61,352
 51,848
 53,147
Depreciation and amortization 483,255
 389,164
 318,771
Impairments 6,279
 230,584
 180,051
Less:      
Gain (loss) on divestiture and other, net (1,406) 1,312
 132,388
Proceeds from business interruption insurance claims —
 —
 29,882
Equity income, net – affiliates 237,518
 195,469
 115,141
Reimbursed electricity-related charges recorded as revenues 74,629
 66,678
 56,860
Adjusted gross margin attributable to noncontrolling interests (1)
 64,049
 56,247
 47,845
Adjusted gross margin $2,428,077
 $1,978,205
 $1,519,869
Adjusted gross margin for natural-gas assets $1,656,041
 $1,443,466
 $1,256,160
Adjusted gross margin for crude-oil, NGLs, and produced-water assets 772,036
 534,739
 263,709
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.
(1)
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 as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies
(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,
thousands 2019 2018 2017
Reconciliation of Net income (loss) to Adjusted EBITDA      
Net income (loss) $807,700
 $630,654
 $737,385
Add:      
Distributions from equity investments 264,828
 216,977
 148,752
Non-cash equity-based compensation expense 14,392
 7,310
 5,194
Interest expense 303,286
 183,831
 142,520
Income tax expense 13,472
 58,934
 20,483
Depreciation and amortization 483,255
 389,164
 318,771
Impairments 6,279
 230,584
 180,051
Other expense 161,813
 8,264
 145
Less:      
Gain (loss) on divestiture and other, net (1,406) 1,312
 132,388
Equity income, net – affiliates 237,518
 195,469
 115,141
Interest income – affiliates 16,900
 16,900
 16,900
Other income 37,792
 2,749
 1,384
Income tax benefit —
 —
 80,406
Adjusted EBITDA attributable to noncontrolling interests (1)
 45,131
 42,843
 37,431
Adjusted EBITDA $1,719,090
 $1,466,445
 $1,169,651
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA      
Net cash provided by operating activities $1,324,100
 $1,348,175
 $1,042,715
Interest (income) expense, net 286,386
 166,931
 125,620
Uncontributed cash-based compensation awards (1,102) 879
 25
Accretion and amortization of long-term obligations, net (8,441) (5,943) (4,932)
Current income tax (benefit) expense 5,863
 (80,114) (6,785)
Other (income) expense, net (2)
 106,136
 (3,209) (1,384)
Distributions from equity investments in excess of cumulative earnings – affiliates 30,256
 29,585
 31,659
Changes in assets and liabilities:      
Accounts receivable, net 45,033
 60,502
 16,244
Accounts and imbalance payables and accrued liabilities, net 30,866
 (45,605) 937
Other items, net (54,876) 38,087
 2,983
Adjusted EBITDA attributable to noncontrolling interests (1)
 (45,131) (42,843) (37,431)
Adjusted EBITDA $1,719,090
 $1,466,445
 $1,169,651
Cash flow information      
Net cash provided by operating activities $1,324,100
 $1,348,175
 $1,042,715
Net cash used in investing activities (3,387,853) (2,210,813) (1,133,324)
Net cash provided by (used in) financing activities 2,071,573
 875,192
 (188,875)
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 
(1)
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 as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2)
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.

  Year Ended December 31,
thousands except Coverage ratio 2019 2018 2017
Reconciliation of Net income (loss) to Distributable cash flow and calculation of the Coverage ratio      
Net income (loss) $807,700
 $630,654
 $737,385
Add:      
Distributions from equity investments 264,828
 216,977
 148,752
Non-cash equity-based compensation expense 14,392
 7,310
 5,194
Non-cash settled interest expense, net 39
 —
 71
Income tax (benefit) expense 13,472
 58,934
 (59,923)
Depreciation and amortization 483,255
 389,164
 318,771
Impairments 6,279
 230,584
 180,051
Above-market component of swap agreements with Anadarko (1)
 7,407
 51,618
 58,551
Other expense 161,813
 8,264
 145
Less:      
Recognized Service revenues – fee based in excess of (less than) customer billings (28,764) 62,498
 —
Gain (loss) on divestiture and other, net (1,406) 1,312
 132,388
Equity income, net – affiliates 237,518
 195,469
 115,141
Cash paid for maintenance capital expenditures 124,548
 120,865
 77,557
Capitalized interest 26,980
 32,479
 9,074
Cash paid for (reimbursement of) income taxes 96
 2,408
 1,194
WES Operating Series A Preferred unit distributions —
 —
 7,453
Other income 37,792
 2,749
 1,384
Distributable cash flow attributable to noncontrolling interests (2)
 36,976
 36,138
 33,956
Distributable cash flow (3)
 $1,325,445
 $1,139,587
 $1,010,850
Distributions declared      
Distributions from WES Operating $1,128,309
    
Less: Cash reserve for the proper conduct of WES’s business 9,360
    
Distributions to WES unitholders (4)
 $1,118,949
    
Coverage ratio 1.18
x   
(1)
See Note 6—Transactions with Affiliates 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 as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(3)
For the year ended December 31, 2019, excludes cash payments of $107.7 million related to the settlement of interest-rate swap agreements. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(4)
Reflects cash distributions of $2.47000 per unit declared for the year ended December 31, 2019, including the cash distribution of $0.62200 per unit paid on February 13, 2020, for the fourth-quarter 2019 distribution.


GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the followingbelow-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 overall level of our customers’ activityactivities and how our customers allocatecustomers’ allocations of capital within their own asset portfolio. The relatively volatile commodity-price environment overportfolios. During the past decade has impacted drilling activityfirst quarter of 2020, oil and natural-gas prices decreased significantly, driven by the expectation of increased supply and sharp declines in severaldemand 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 basins in which we operate. Manyrecent 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, have shifted capital spending toward opportunities with superior economicsis in financial distress. See Liquidity and reduced activityCapital 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 other areas. 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 possible, and to maintain throughput onproducers continue with development plans in our systems,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 natural 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. Under the terms of our partnership agreement, we are required to distribute all of our available cash to our unitholders, which makes us dependent on our ability to raise capital to fund growth projects and acquisitions. Historically, we have accessed the debt and equity capital markets to raise money for growth projects and acquisitions. From time to time, capital market turbulence and investor sentiment towards MLPs, 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 willmay 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 20192020 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 three separate timestwice during 2019.2020. Long-term interest rates experienced a similar decrease in response to lower future economic growth expectations. Any future increases in the federal funds rateinterest rates likely will result in an increase in short-term 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.

EQUITY OFFERINGS

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 information.

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WES common and general partner units. Under the Exchange Agreement, 9,060,641 common units were canceled and 9,060,641 general partner units were issued to the general partner. In February 2019, we issued 234,053,065 common units in connection with the Merger closing. See Note 1—SummaryTable of Significant Accounting Policies and 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 information.Contents

WES Operating common units. In February 2019, WES Operating (i) converted the IDRs and general partner units into 105,624,704 common units in connection with the Merger closing, and (ii) issued 45,760,201 common units as part of the AMA acquisition.

WES Operating Class C units. All outstanding Class C units converted into WES Operating common units on a one-for-one basis immediately prior to the Merger closing.

WES Operating Series A Preferred units. In 2016, WES Operating issued 21,922,831 Series A Preferred units to private investors. Pursuant to an agreement between WES Operating and the holders of the WES Operating Series A Preferred units, 50% of the WES Operating Series A Preferred units converted into WES Operating common units on a one-for-one basis on March 1, 2017, and all remaining WES Operating Series A Preferred units converted into WES Operating common units on a one-for-one basis on May 2, 2017. See Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information.



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.
  Year Ended December 31,
thousands 2019 2018 2017
Total revenues and other (1)
 $2,746,174
 $2,299,658
 $2,429,614
Equity income, net – affiliates 237,518
 195,469
 115,141
Total operating expenses (1)
 1,750,943
 1,635,157
 1,905,327
Gain (loss) on divestiture and other, net (1,406) 1,312
 132,388
Proceeds from business interruption insurance claims (2)
 —
 —
 29,882
Operating income (loss) 1,231,343
 861,282
 801,698
Interest income – affiliates 16,900
 16,900
 16,900
Interest expense (303,286) (183,831) (142,520)
Other income (expense), net (123,785) (4,763) 1,384
Income (loss) before income taxes 821,172
 689,588
 677,462
Income tax (benefit) expense 13,472
 58,934
 (59,923)
Net income (loss) 807,700
 630,654
 737,385
Net income attributable to noncontrolling interests 110,459
 79,083
 196,595
Net income (loss) attributable to Western Midstream Partners, LP (3)
 $697,241
 $551,571
 $540,790
Key performance metrics (4)
      
Adjusted gross margin $2,428,077
 $1,978,205
 $1,519,869
Adjusted EBITDA 1,719,090
 1,466,445
 1,169,651
Distributable cash flow 1,325,445
 1,139,587
 1,010,850
(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.
(1)

Revenues and other include amounts earned from services provided to our affiliates and from the sale of residue gas and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services and reimbursements of amounts paid by affiliates to third parties on our behalf. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2)
See Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(3)
For reconciliations to comparable consolidated results of WES Operating, see Items Affecting the Comparability of Financial Results with WES Operating within this Item 7.
(4)
Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow are defined under the caption How We Evaluate Our Operations within this Item 7. For reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, see How We Evaluate Our Operations—Reconciliation of non-GAAP 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, 2018,2018.
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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 3 %546 (3)%
Processing3,445 3,497 (1)%3,231 8 %
Equity investments (1)
445 398 12 %291 37 %
Total throughput4,433 4,423 — %4,068 9 %
Throughput attributable to noncontrolling interests (2)
159 175 (9)%170 3 %
Total throughput attributable to WES for natural-gas assets4,274 4,248 1 %3,898 9 %
Throughput for crude-oil and NGLs assets (MBbls/d)
Gathering, treating, and transportation331 320 3 %295 8 %
Equity investments (3)
381 343 11 %241 42 %
Total throughput712 663 7 %536 24 %
Throughput attributable to noncontrolling interests (2)
14 13 8 %11 18%
Total throughput attributable to WES for crude-oil and NGLs assets698 650 7 %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 %4 175 %
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 any increases or decreases “forDivestitures 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, 2018” refer2020, primarily due to increased production in areas around the comparison ofMarcellus Interest systems, partially offset by production declines in areas around the year ended December 31, 2018, to the year ended December 31, 2017.


Throughput
  Year Ended December 31,

 2019 2018 
Inc/
(Dec)
 2017 
Inc/
(Dec)
Throughput for natural-gas assets (MMcf/d)          
Gathering, treating, and transportation (1)
 528
 546
 (3)% 958
 (43)%
Processing (1)
 3,497
 3,231
 8 % 2,592
 25 %
Equity investment (2)
 398
 291
 37 % 290
 — %
Total throughput 4,423
 4,068
 9 % 3,840
 6 %
Throughput attributable to noncontrolling interests (3)
 175
 170
 3 % 179
 (5)%
Total throughput attributable to WES for natural-gas assets 4,248
 3,898
 9 % 3,661
 6 %
Throughput for crude-oil, NGLs, and produced-water assets (MBbls/d)          
Gathering, treating, transportation, and disposal 876
 534
 64 % 258
 107 %
Equity investment (4)
 343
 241
 42 % 148
 63 %
Total throughput 1,219
 775
 57 % 406
 91 %
Throughput attributable to noncontrolling interests (3)
 24
 15
 60 % 8
 88%
Total throughput attributable to WES for crude-oil, NGLs, and produced-water assets 1,195
 760
 57 % 398
 91 %
(1)
The combination of the DBM complex and DBJV and Haley systems, effective January 1, 2018, into a single complex now is referred to as the “West Texas complex,” and resulted in DBJV and Haley systems throughput previously reported as “Gathering, treating, and transportation” now being reported as “Processing.”
(2)
Represents the 14.81% share of average Fort Union throughput, 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.
(3)
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 as of December 31, 2019. For a discussion of the impact to noncontrolling interests as a result of the Merger closing, see Noncontrolling interests within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(4)
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

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 offset 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.
Gathering, treating, and transportationProcessing throughput decreased by 41252 MMcf/d for the year ended December 31, 2018,2020, primarily due to (i) third-party volumes being diverted away from the combinationGranger straddle plant beginning in the fourth quarter of 2019 and the DBMplant 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 DBJVa third-party contract that terminated during the fourth quarter of 2019, and Haley systems into a single(iii) lower throughput at the Red Desert complex now referreddue to asproduction declines in the “Westarea. 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” which resulted in DBJV and Haley systems throughput previously reported as “Gathering, treating, and transportation” now being reported as “Processing” (decreaseMarch 2019.
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Table of 258 MMcf/d) and (ii) the divestiture of the Non-Operated Marcellus Interest as part of the March 2017 Property Exchange (decrease of 158 MMcf/d).Contents

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 offset 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.
ProcessingEquity-investment throughput increased by 63947 MMcf/d for the year ended December 31, 2018,2020, primarily due to (i) the combination of the DBM complex and DBJV and Haley systems into the West Texas complex, (ii)increased volumes on Red Bluff Express resulting from increased production in the areas around the DJ Basin and West Texas complexes, (iii) the start-up of Train VIarea. This increase was offset partially by (i) decreased third-party volumes at the West Texas complex in December 2017, (iv) increased throughputFort Union system, which was sold to a third party during the fourth quarter of 2020, and (ii) decreased volumes at the West Texas complexRendezvous system due to the acquisition of the Additional DBJV System Interest as part of the March 2017 Property Exchange, and (v) increased throughput at the MGR assets due to increased uptime compared to 2017. These increases were partially offset by lower throughput at the Chipeta complex due to downstream fractionation capacity constraintsproduction declines in the third quarter of 2018 and the expiration and non-renewal of a contract in September 2017.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 affiliaterelated-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 NGLs, and produced-waterNGLs assets

Gathering, treating, transportation, and disposaltransportation throughput increased by 34211 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 water systems due to new water-disposal systems that commenced operations during the third and fourth quarters of 2018, (ii) 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 (iii)(ii) increased production in areas around the DJ Basin oil system.
Gathering, treating, transportation, and disposalEquity-investment throughput increased by 27638 MBbls/d for the year ended December 31, 2018,2020, 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 throughputvolumes on FRP resulting from the DBM water systems that commenced operations beginning ina pipeline expansion project completed during the second quarter of 2017 and (ii) increased throughput at2020. These increases were offset partially by decreased volumes on the DBM oil system due to the commencement of ROTF operations beginning in the second quarter of 2018.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.
Equity-investment
Produced-water assets

Gathering and disposal throughput increased by 93156 MBbls/d for the year ended December 31, 2018, primarily2020, 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 acquisitionsystems.
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 our interest in Whitethorn LLC in June 2018 and (ii) increased volumes on TEP and FRP as a result2018.


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Table of increased NGLs production in the DJ Basin area.Contents


Service Revenues
 Year Ended December 31,Year Ended December 31,
thousands except percentages 2019 2018 
Inc/
(Dec)
 2017 
Inc/
(Dec)
thousands except percentages20202019Inc/
(Dec)		2018Inc/
(Dec)
Service revenues – fee based $2,388,191
 $1,905,728
 25 % $1,357,876
 40%Service revenues – fee based$2,584,323 $2,388,191 8 %$1,905,728 25 %
Service revenues – product based 70,127
 88,785
 (21)% —
 NM
Service revenues – product based48,369 70,127 (31)%88,785 (21)%
Total service revenues $2,458,318
 $1,994,513
 23 % $1,357,876
 47% Total service revenues$2,632,692 $2,458,318 7 %$1,994,513 23 %
NM
—Not Meaningful

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 offset 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 – feeproduct based increased

Service revenues – product based decreased by $547.9$21.8 million for the year ended December 31, 2018,2020, primarily due to increases of (i) $154.5 million from the adoption of Topic 606, as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7, (ii) $141.3 million, $71.5 million, and $19.1 million at the West Texas complex and DBM and DJ Basin oil systems, respectively, due to increased throughput, (iii) $112.7 milliondecreased third-party volumes at the DJ Basin complex due to increased throughput ($91.3 million) and a higher processing fee ($21.4 million), and (iv) $78.4 million at the DBM water systems that commenced operations beginning in the second quarter of 2017. These increases were partially offset by decreases of (i) $22.1 million due to the divestiture of the Non-Operated Marcellus Interest as part of the March 2017 Property ExchangeMGR assets and (ii) $10.4 million at the Springfield system due to a lower cost-of-service rate.

Service revenues – product based

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.
Service revenues – product based increased

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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 1 %
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 $88.8$36.0 million for the year ended December 31, 2018,2020, primarily due to decreases of (i) $15.2 million at the adoptionDJ 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 Topic 606. As2019 related to the Kitty Draw gathering-system shutdown (further discussed underbelow), 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 ResultsResults—Commodity purchase and sale agreements within this Item 7, under Topic 606, certain of our customer agreements result in revenues being recognized when the natural gas and/or NGLs are received from the customer as non-cash consideration for services provided. In addition, retained proceeds from sales of customer products, where we are acting as their agent, are included in Service revenues – product based.7).


Product Sales
  Year Ended December 31,
thousands except percentages and
per-unit amounts
 2019 2018 
Inc/
(Dec)
 2017 
Inc/
(Dec)
Natural-gas sales (1)
 $66,557
 $85,015
 (22)% $391,393
 (78)%
NGLs sales (1)
 219,831
 218,005
 1 % 659,817
 (67)%
Total Product sales $286,388
 $303,020
 (5)% $1,051,210
 (71)%
Per-unit gross average sales price (1):
          
Natural gas (per Mcf) $1.65
 $2.16
 (24)% $2.92
 (26)%
NGLs (per Bbl) 20.93
 31.55
 (34)% 23.88
 32 %
(1)
For the years ended December 31, 2018 and 2017, includes the effects of commodity-price swap agreements for the MGR assets and DJ Basin complex, excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Natural-gas sales

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 offset 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 (see system.

NGLs sales
Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
Natural-gasNGLs sales decreased by $306.4$111.8 million for the year ended December 31, 2018,2020, primarily due to decreases of (i) $258.9$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 adoption of Topic 606, as discussed undermarketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial ResultsResults—Commodity purchase and sale agreements within this Item 7, (ii) $24.67), (iii) $17.7 million at the West TexasDJ Basin complex dueattributable to a decrease in average price, partially offset by an increase in volumes sold,prices, and (iii) $5.7(iv) $14.7 million due to a decreaseat the Brasada complex, $6.7 million at the Chipeta complex, and $6.1 million at the MGR assets resulting from decreases in average priceprices and $9.3 million due to the shutdown of the Kitty Draw gathering system, both at the Hilight system.volumes sold.

NGLs sales

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 offset 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.
NGLs sales
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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 $441.8$10.8 million for the year ended December 31, 2018,2020, primarily due to a decrease of $844.0 millionin equity income from the adoption of Topic 606, as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7. This decrease wasWhitethorn LLC related to commercial activities and decreased volumes, and decreased rates at White Cliffs. These decreases were offset partially offset by increases of (i) $256.8 million at the West Texas complex due to an increase in volumes sold, partially offset by a decrease in average price, (ii) $48.2 million at the DJ Basin complex due to an increase in the swap market price and volumes sold, (iii) $39.0 million at the DJ Basin oil system due to an increase in average price and volumes sold, (iv) $23.8 million at the Brasada complex due to volumes sold under a new sales agreement beginning January 1, 2018, and (v) $12.8 million at the DBM water systems due to an increase in volumes sold related to byproducts from the treatmentacquisition of produced water.

Other Revenues
  Year Ended December 31,
thousands except percentages 2019 2018 
Inc/
(Dec)
 2017 
Inc/
(Dec)
Other revenues $1,468
 $2,125
 (31)% $20,528
 (90)%

Forour interest in Cactus II in June 2018, which began delivering crude oil during the year ended December 31, 2018, Other revenues decreased by $18.4 million, primarily due to deficiency feesthird quarter of $8.8 million at the Chipeta complex2019, and $7.2 million at the DBM water systems in 2017. Upon adoption of Topic 606increased volumes on January 1, 2018, deficiency fees are recorded as Service revenues – fee based in the consolidated statements of operations (see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

Equity Income, Net – Affiliates
  Year Ended December 31,
thousands except percentages 2019 2018 
Inc/
(Dec)
 2017 
Inc/
(Dec)
Equity income, net – affiliates $237,518
 $195,469
 22% $115,141
 70%

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

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 7 %
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 %

NM—Not meaningful
  Year Ended December 31,
thousands except percentages 2019 2018 
Inc/
(Dec)
 2017 
Inc/
(Dec)
NGLs purchases (1)
 $331,872
 $292,698
 13 % $573,309
 (49)%
Residue purchases (1)
 100,570
 125,106
 (20)% 367,179
 (66)%
Other 11,805
 (2,299) NM
 13,304
 (117)%
Cost of product 444,247
 415,505
 7 % 953,792
 (56)%
Operation and maintenance 641,219
 480,861
 33 % 345,617
 39 %
Total Cost of product and Operation and maintenance expenses $1,085,466
 $896,366
 21 % $1,299,409
 (31)%
(1)
For the year ended December 31, 2017, includes the effects of the commodity-price swap agreements for the MGR assets and DJ Basin complex, excluding the amounts considered above market with respect to these swap agreements that were recorded as capital contributions in the consolidated statements of equity and partners’ capital. See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.


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 offset 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.
NGLs
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Residue purchases

Residue purchases decreased by $280.6$35.4 million for the year ended December 31, 2018,2020, primarily due to decreases of (i) $21.1 million resulting from a decrease of $690.2 million fromchange in accounting for the adoption of Topic 606, as discussed undermarketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial ResultsResults—Commodity purchase and sale agreements within this Item 7, partially offset by increases of (i) $269.5 million at the West Texas complex due to an increase in volumes purchased,7), (ii) $50.4 million and $40.4$11.3 million at the DJ Basin complex attributable to average-price decreases, and DJ Basin oil system, respectively, due to increases in average prices and volumes purchased, (iii) $22.0$4.3 million at the Brasada complex dueMGR assets attributable to volumes purchased under a new purchase agreement beginning January 1, 2018,average-price and (iv) $11.8purchased-volume decreases. These decreases were offset partially by an increase of $3.2 million at the DBM water systems, which commenced operation beginning in the second quarter of 2017.Chipeta complex primarily due to purchased-volume and average-price increases.

Residue purchases

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.
Residue purchases
Other items

Other items decreased by $242.1$20.9 million for the year ended December 31, 2018,2020, primarily due to decreases of (i) $222.6 million from the adoption of Topic 606, as discussed under Items Affecting the Comparability of Financial Results within this Item 7, (ii) $12.9$10.3 million at the West Texas complex due to a decreasechanges in average price, partially offset by an increase in volumes purchased, (iii) $6.8 million at the MGR assets due to decreases in average priceimbalance positions and volumes purchased, and (iv) $5.0 million at the Hilight system due to a decrease in volumes purchased. These decreases were partially offset by an increase of $5.7(ii) $10.0 million at the DJ Basin complex due to an increase in volumes purchased, partially offset by a decrease in average price.

Other items

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.
Other items
Operation and maintenance expense

Operation and maintenance expense decreased by $15.6$60.3 million for the year ended December 31, 2018,2020, primarily dueas a result of focused cost-savings initiatives related to the stand-up of WES as an independent organization, resulting in decreases of (i) $9.8$34.2 million from the adoption of Topic 606, as discussed under Items Affecting the Comparability of Financial Results within this Item 7 and (ii) $6.6 million from changes in imbalance positions primarily at the West Texas complex.

Operationcomplex 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.
Operation and maintenance expense increased by $135.2 million for the year ended December 31, 2018, primarily due to increases
84
Table of (i) $62.2 million at the West Texas complex due to increases in salaries and wages, surface maintenance and plant repairs, utilities expense, and equipment rentals, (ii) $29.2 million at the DBM water systems, which commenced operation beginning in the second quarter of 2017, (iii) $25.4 million at the DJ Basin complex due to increases in utilities expense, surface maintenance and plant repairs, and salaries and wages, and (iv) $14.8 million at the DBM oil system due to increases in surface maintenance and plant repairs, salaries and wages, and chemicals and treating services.Contents


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 2 %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.
  Year Ended December 31,
thousands except percentages 2019 2018 
Inc/
(Dec)
 2017 
Inc/
(Dec)
General and administrative (1)
 $114,591
 $67,195
 71 % $53,949
 25 %
Property and other taxes 61,352
 51,848
 18 % 53,147
 (2)%
Depreciation and amortization 483,255
 389,164
 24 % 318,771
 22 %
Impairments 6,279
 230,584
 (97)% 180,051
 28 %
Total other operating expenses $665,477
 $738,791
 (10)% $605,918
 22 %
(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 offset by a decrease of $4.4 million in legal and consulting fees.
General
Property and administrative expensesother taxes

Property and other taxes increased by $13.2$7.0 million for the year ended December 31, 2018,2020, primarily due to (i) legalad 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 consulting fees incurred in 2018West Texas due to lower valuations and (ii) personnel costs for which we reimbursed Occidental pursuant to the omnibus agreements. These increases were partially offset by a decrease in bad debt expense.
Property and other taxes

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.
Property

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Depreciation and other taxes decreasedamortization expense

Depreciation and amortization expense increased by $1.3$7.8 million for the year ended December 31, 2018,2020, primarily due to ad valorem tax decreases of $5.8 million at the DJ Basin complex caused by revisions in estimated tax liabilities, offset by increases of $2.5(i) $11.9 million and $2.1$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 oilcomplex primarily as a result of a change in estimate for asset retirement obligations for the Third Creek gathering system respectively.
Depreciationof $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 amortizationan 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.
Depreciation
Long-lived asset and amortizationother impairment expense increased by $70.4 million

Long-lived asset and other impairment expense for the year ended December 31, 2018,2020, was primarily due to increases(i) $150.2 million of (i) $30.4impairments for assets located in Wyoming and Utah, (ii) a $29.4 million $12.9 million, and $10.8 million at the West Texas complex, DBM water systems, and DBM oil system, respectively, due to capital projects being placed into service and (ii) $17.1other-than-temporary impairment of our investment in Ranch Westex, (iii) impairments of $16.7 million at the DJ Basin complex relatedprimarily due to the shutdowncancellation of projects and impairments of rights-of-way, and (iv) impairments of $3.8 million at the Third Creek gatheringDBM oil system (see Note 1—Summaryprimarily due to the cancellation of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).projects.


Impairment expense

ImpairmentLong-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.complex due to impairments of rights-of-way and cancellation of projects.
Impairment    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, (see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K), (ii) $38.7 million at the Hilight system, (iii) $34.6 million at the MIGC system, (iv)(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.
Impairment expense for the year ended December 31, 2017, included (i) a $158.8 million impairment at the Granger complex, (ii) an $8.2 million impairment at the Hilight system, (iii) a $3.7 million impairment at the Granger straddle plant, (iv) a $3.1 million impairment at the Fort Union system, (v) a $2.0 million impairment of an idle facility in northeast Wyoming, and (vi) an impairment related to the cancellation of a pipeline project in West Texas.
For further information on Long-lived asset and other impairment expense for the periods presented, see Note 8—9—Property, Plant, and Equipmentin 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.

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Interest Income – AffiliatesAnadarko Note Receivable and Interest Expense
 Year Ended December 31,Year Ended December 31,
thousands except percentages 2019 2018 
Inc/
(Dec)
 2017 
Inc/
(Dec)
thousands except percentages20202019Inc/
(Dec)		2018Inc/
(Dec)
Note receivable – Anadarko $16,900
 $16,900
 — % $16,900
 — %
Interest income – affiliates $16,900
 $16,900
 — % $16,900
 — %
Interest income – Anadarko note receivableInterest income – Anadarko note receivable$11,736 $16,900 (31)%$16,900 — %
Third parties          Third parties
Long-term debt $(315,872) $(200,454) 58 % $(143,400) 40 %
Long-term and short-term debtLong-term and short-term debt$(369,815)$(315,872)17 %$(200,454)58 %
Finance lease liabilitiesFinance lease liabilities(1,510)— NM— NM
Amortization of debt issuance costs and commitment fees (12,424) (9,110) 36 % (7,970) 14 %Amortization of debt issuance costs and commitment fees(13,501)(12,424)9 %(9,110)36 %
Capitalized interest 26,980
 32,479
 (17)% 9,074
 NM
Capitalized interest4,774 26,980 (82)%32,479 (17)%
Affiliates          
Related partiesRelated parties
APCWH Note Payable (1,833) (6,746) (73)% (153) NM
APCWH Note Payable— (1,833)(100)%(6,746)(73)%
Finance lease liabilities (137) —
 NM
 —
 NM
Finance lease liabilities(6)(137)(96)%— NM
Deferred purchase price obligation – Anadarko —
 —
 NM
 (71) (100)%
Interest expense $(303,286) $(183,831) 65 % $(142,520) 29 %Interest expense$(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.
Interest expense
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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 $41.3$124.8 million for the year ended December 31, 2018,2020, primarily due to (i) $46.3 million of interest incurred on the 4.500% Senior Notes due 2028 and 5.300% Senior Notes due 2048 that were issued in March 2018, (ii) $15.3 million of interest incurred on the 4.750% Senior Notes due 2028 and 5.500% Senior Notes due 2048 that were issued in August 2018, and (iii) $6.6 million of interest incurred on the APCWH Note Payable. These increases were partially offset by an increase in capitalized interest of $23.4 million, primarily due to continued construction and expansion at (i) the DJ Basin complex, including construction of the Latham processing plant beginning in 2018, (ii) the West Texas complex, including construction of the Mentone processing plant beginning in the fourth quarter of 2017, and (iii) the DBM oil system, including construction of the ROTFs that commenced operations in 2018.


Other Income (Expense), Net
  Year Ended December 31,
thousands except percentages 2019 2018 
Inc/
(Dec)
 2017 
Inc/
(Dec)
Other income (expense), net $(123,785) $(4,763) NM $1,384
 NM

Other income (expense), net decreased by $119.0 million for the year ended December 31, 2019, primarily due to a net lossnon-cash losses of $125.3 million on interest-rate swaps thatincurred during the year ended December 31, 2019. All outstanding interest-rate swap agreements were cash-settledsettled in December 2019. See2019 (see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information.10-K).
Other income (expense), net decreased by $6.1$119.0 million for the year ended December 31, 2018,2019, primarily due to a non-cash losslosses of $8.0$125.3 million on interest-rate swaps entered intothat were settled in December 2018. See2019 (see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information.10-K).

Income Tax Expense (Benefit) Expense
 Year Ended December 31,Year Ended December 31,
thousands except percentages 2019 2018 
Inc/
(Dec)
 2017 
Inc/
(Dec)
thousands except percentages20202019Inc/
(Dec)		2018Inc/
(Dec)
Income (loss) before income taxes $821,172
 $689,588
 19 % $677,462
 2 %Income (loss) before income taxes$522,850$821,172(36)%$689,58819 %
Income tax (benefit) expense 13,472
 58,934
 (77)% (59,923) (198)%
Income tax expense (benefit)Income tax expense (benefit)5,99813,472(55)%58,934(77)%
Effective tax rate 2% 9%   NM
  Effective tax rate1 %2 %9 %

We are not a taxable entity for U.S. federal income tax purposes.purposes; therefore, our federal statutory rate is zero percent. However, our income apportionable to Texas is subject to Texas margin tax. For the periods presented, the variance from the federal statutory rate, which is zero percent as a non-taxable entity, is primarily due to federal and state taxes on pre-acquisition income attributable to assets previously acquired from Anadarko, and our share of Texas margin tax.
During the year ended December 31, 2017, AMA recognized a one-time deferred tax benefit of $87.3 million due to the impact of the U.S. Tax Cuts and Jobs Act signed into law on December 22, 2017. This was offset by federal and state taxes on pre-acquisition income attributable to the AMA assets acquired from Anadarko and our share of Texas margin tax.
Income attributable to 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 subject 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.



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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 8 %1.01 6 %
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets (2)
2.54 2.44 4 %2.40 2 %
Per-Bbl Adjusted gross margin for produced-water assets (3)
0.98 0.97 1 %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.
  Year Ended December 31,
thousands except percentages and per-unit amounts 2019 2018 
Inc/
(Dec)
 2017 
Inc/
(Dec)
Adjusted gross margin for natural-gas assets (1)
 $1,656,041
 $1,443,466
 15 % $1,256,160
 15%
Adjusted gross margin for crude-oil, NGLs, and produced-water assets (1)
 772,036
 534,739
 44 % 263,709
 103%
Adjusted gross margin (1) (2)
 2,428,077
 1,978,205
 23 % 1,519,869
 30%
Per-Mcf Adjusted gross margin for natural-gas assets (3)
 1.07
 1.01
 6 % 0.94
 7%
Per-Bbl Adjusted gross margin for crude-oil, NGLs, and produced-water assets (4)
 1.77
 1.93
 (8)% 1.82
 6%
Adjusted EBITDA (2)
 1,719,090
 1,466,445
 17 % 1,169,651
 25%
Distributable cash flow (2)
 1,325,445
 1,139,587
 16 % 1,010,850
 13%
(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.
(1)

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 is calculated as total revenues and other (less reimbursements for electricity-related expenses recorded as revenue), less cost of product, plus distributions from our equity investments, and excluding the noncontrolling interests owners’ proportionate share of revenues and cost of product.
(2)
For a reconciliation of Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the descriptions under How We Evaluate Our Operations—Reconciliation of non-GAAP financial measures within this Item 7.
(3)
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.
(4)
Average for period. Calculated as Adjusted gross margin for crude-oil, NGLs, and produced-water assets, divided by total throughput (MBbls/d) attributable to WES for crude-oil, NGLs, and produced-water assets.

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 offset 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).

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Per-Mcf Adjusted gross margin for natural-gas assets increased by $458.3 million$0.09 for the year ended December 31, 2018,2020, primarily due to (i) increased throughput at the West Texas complex and DBM oil system, (ii) increased throughput and an annual cost-of-service rate adjustment in the fourth quarter of 2018 at the DJ Basin oil system, (iii) increased throughput and a higher processing fee at the DJ Basin complex, (iv) the start-up of the DBM water systems beginning in the second quarter of 2017, (v) the acquisition ofcomplexes, which have higher-than-average per-Mcf margins as compared to our interest in Whitethorn LLC in June 2018, (vi) the March 2017 Property Exchange, and (vii) an annual cost-of-service rate adjustment at the Springfield system in the fourth quarter of 2018 (seeRevenue and cost of product under Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). These increases were partially offset by a decrease due to the shutdown of the Kitty Draw gathering system (part of the Hilight system) in 2018 (seeNote 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).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-McfPer-Bbl Adjusted gross margin for natural-gascrude-oil and NGLs assets increased by $0.07$0.10 for the year ended December 31, 2018,2020, 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 West Texas complex, which hasDBM oil system and (ii) increased volumes on FRP resulting from a higher-than-average per-Mcf margin as compared to our other natural-gas assets, (ii)pipeline expansion project completed during the March 2017 Property Exchange, and (iii) an annual cost-of-service rate adjustment at the Springfield gas-gathering system in the fourthsecond quarter of 2018.


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 and produced-water assets decreasedincreased by $0.16$0.04 for the year ended December 31, 2019, primarily due to increased throughput at the DBM water systems, which has a lower per-Bbl margin than our other crude-oil and NGLs assets. This decrease was partially offset by (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 crude-oil, NGLs, and produced-water assets increaseddecreased by $0.11$0.05 for the year ended December 31, 2018,2019, 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) increased throughputa $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 an annual cost-of-service rate adjustmentmaintenance expenses, (iii) a $26.4 million increase in the fourth quarter of 2018 at the DJ Basin oil system,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) increased throughput at the DBM oil system, (iii) the acquisition of our interesta $7.0 million increase in Whitethorn LLC in June 2018, (iv) higher distributions received from the TEFR Interests and the Mont Belvieu JV, and (v) an annual cost-of-service rate adjustment at the Springfield oil-gathering system in the fourth quarter of 2018. These increases were partially offset by increased throughput at the DBM water systems, which has a lower per-Bbl margin than our other crude-oil and NGLs assets.

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.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) an increase ofa $446.5 million increase in total revenues and other and (ii) an increase ofa $47.9 million increase in distributions from equity investments. These amounts were offset partially offset by (i) an increase ofa $160.4 million increase in operation and maintenance expenses, (ii) an increase ofa $40.3 million increase in general and administrative expenses excluding non-cash equity-based compensation expense, (iii) an increase ofa $29.3 million increase in cost of product (net of lower of cost or market inventory adjustments), and (iv) an increase ofa $9.5 million increase in property taxes.

Adjusted EBITDAFree cash flow. Free cash flow increased by $296.8$1,190.0 million for the year ended December 31, 2018,2020, primarily due to (i) a $538.9decrease of $765.7 million decrease in costcapital expenditures, (ii) an increase of product (net of lower of cost or market inventory adjustments)$313.3 million in net cash provided by operating activities, and (ii) a $68.2 million increase in distributions from equity investments. These amounts were partially offset by (i) a $135.2 million increase in operation and maintenance expenses, (ii) a $130.0 million decrease in total revenues and other, (iii) a $29.9decrease of $109.0 million decrease in business interruption proceeds, and (iv) an $11.1 million increase in general and administrative expenses excluding non-cash equity-based compensation expense.contributions to equity investments.

Distributable cash flow. DistributableFree cash flow increased by $185.9$741.6 million for the year ended December 31, 2019, primarily due to (i) an increasea decrease of $252.6$759.8 million in Adjusted EBITDAcapital expenditures and (ii) $91.3a decrease of $5.2 million of customer billings in excess of the amount recognized as Service revenues – fee based.contributions to equity investments. These amounts were offset partially offset by (i) an increasea decrease of $113.9$24.1 million in net cash paid for interest expense, (ii) a decrease of $44.2 million in the above-market component of the swap agreements with Anadarko,provided by operating activities.
See Capital Expenditures and (iii) an increase of $3.7 million in cash paid for maintenance capital expenditures. For the year ended December 31, 2019, Distributable cash flow excludes cash payments of $107.7 million related to the settlement of interest-rate swap agreements. See the definition of Distributable cash flow under How We Evaluate Our OperationsHistorical Cash Flow within this Item 7 and see for further information.
Note 13—Debt and Interest Expense
90
in the Notes to Consolidated Financial Statements under Part II, Item 8Table of this Form 10-K.Contents
Distributable cash flow increased by $128.7 million for the year ended December 31, 2018, primarily due to (i) a $296.8 million increase in Adjusted EBITDA and (ii) a $7.5 million decrease in WES Operating Series A Preferred unit distributions. These amounts were partially offset by (i) a $64.8 million increase in net cash paid for interest expense, (ii) $62.5 million of customer billings less than the amount recognized as Service revenues – fee based, (iii) a $43.3 million increase in cash paid for maintenance capital expenditures, and (iv) a $6.9 million decrease in the above-market component of the swap agreements with Anadarko.


LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are foruses include capital expenditures, debt service, customary operating expenses, quarterly distributions, and distributions to our noncontrolling interest owners, and strategic acquisitions.owners. Our sources of liquidity as of December 31, 2019,2020, included cash and cash equivalents, cash flows generated from operations, interest income on our $260.0 million note receivable from Anadarko, available borrowing capacity under the RCF, and 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 maintenance and expansion capital expenditurecapital-expenditure requirements. The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements, and other factors, and will be determined by the Board of Directors on a quarterly basis. Due to our cash distribution policy, we expect toWe may rely on external financing sources, including equity and debt issuances, to fund expansion capital expenditures and future acquisitions. However, we also may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under the RCF to pay distributions or to fund other short-term working capital requirements.
OurUnder our partnership agreement, requires that we distribute all of our available cash (as(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 completely dependent on our ability to generate favorable 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 and have increased our quarterly distribution each quarter since the fourth quarter of 2012. The Board of Directors declared a cash distribution to unitholders for the fourth quarter of 20192020 of $0.62200$0.31100 per unit, or $281.8$131.3 million in the aggregate. The cash distribution was paid on February 13, 2020,12, 2021, to our unitholders of record at the close of business on JanuaryFebruary 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, 2020.2021. 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 positionposition and coordinates our capital expenditure program,expenditures and quarterly distributions and acquisition strategy with our expected cash flowsinflows and projected debt-repayment schedule.debt service requirements. We will continue to evaluate funding alternatives, including additionaladditional borrowings and the issuance of debt or equity securities, to secure funds as needed or to refinance outstandingmaturing 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, 2019,2020, we had an $83.5a $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 needneeds 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 expansion activity. The working capital deficit as of December 31, 2019, was primarily due to the costs incurred related to continued construction and expansion at the West Texas and DJ Basin complexes, DBM oil system, and DBM water systems.activities. As of December 31, 2019,2020, there was $1.6$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. We categorize capitalCapital expenditures as one of the following:
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; or

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.

 Year Ended December 31,
thousands 2019 2018 2017
Acquisitions $2,101,229
 $162,112
 $181,708
       
Expansion capital expenditures $1,064,281
 $1,827,730
 $949,375
Maintenance capital expenditures 124,548
 120,865
 77,557
Total capital expenditures (1) (2)
 $1,188,829
 $1,948,595
 $1,026,932
       
Capital incurred (1) (3)
 $1,055,151
 $1,910,508
 $1,252,067
(3)Capital incurred for the year ended December 31, 2018, included $733.1 million of pre-acquisition capital incurred for AMA.
(1)
For the years ended December 31, 2019, 2018, and 2017, included $23.3 million, $31.1 million, and $9.1 million, respectively, of capitalized interest. For the years ended December 31, 2018 and 2017, capitalized interest included $9.0 million and $2.2 million, respectively, of pre-acquisition capitalized interest for AMA.
(2)
Capital expenditures for the years ended December 31, 2018 and 2017, included $762.8 million and $353.3 million, respectively, of pre-acquisition capital expenditures for AMA. Capital expenditures for the year ended December 31, 2017, are presented net of $1.4 million of contributions in aid of construction costs from affiliates.
(3)
Capital incurred for the years ended December 31, 2018 and 2017, included $733.1 million and $453.4 million, respectively, 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 equipment purchases from affiliates. Acquisitions during 2017 included the Additional DBJV System Interest, the additional interest in Ranch Westex, and equipment purchases from affiliates.related-party asset contributions. See Note 3—Acquisitions and Divestitures and Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Capital expenditures excluding acquisitions, decreased by $759.8$765.7 million for the year ended December 31, 2019. Expansion capital2020, 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 $763.4$759.8 million (including a $7.8 million decrease in capitalized interest) for the year ended December 31, 2019, primarily due to decreases of (i) $423.8$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) $246.5$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) $196.8$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 offset by an increase of $88.1$91.3 million at the DJ Basin complex, primarily due to continued construction of the Latham processing plant. Maintenance capital expenditures increased by $3.7 million for the year ended December 31, 2019, primarily due to increases at the DBM oil system and DJ Basin complex, partially offset by decreases at the West Texas complex and Hilight system.


92
Capital expenditures, excluding acquisitions, increased by $921.7 million for the year ended December 31, 2018. Expansion capital expenditures increased by $878.4 million (including a $22.0 million increase in capitalized interest) for the year ended December 31, 2018, primarily due to increases
Table of (i) $271.7 million at the West Texas complex, $222.4 million at the DJ Basin complex, and $182.4 million at the DBM oil system, primarily due to pipe, compression, and processing projects and (ii) $200.2 million at the DBM water systems due to produced-water gathering and disposal projects. Maintenance capital expenditures increased by $43.3 million for the year ended December 31, 2018, primarily due to increases at the DJ Basin and West Texas complexes and the DJ Basin oil system, which were partially offset by a decrease at the DBM oil system.Contents
For the year ending December 31, 2020, we estimate that our total capital expenditures will be between $875.0 million to $950.0 million (excluding acquisitions and including our 75% share of Chipeta’s capital expenditures and equity investments) and our maintenance capital expenditures will be between $125.0 million to $135.0 million.

Historical cash flow. The following table and discussion present a summary of our net cash flows provided by (used in) operating, activities, investing, activities and financing activities:
Year Ended December 31,
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 
  Year Ended December 31,
thousands 2019 2018 2017
Net cash provided by (used in):      
Operating activities $1,324,100
 $1,348,175
 $1,042,715
Investing activities (3,387,853) (2,210,813) (1,133,324)
Financing activities 2,071,573
 875,192
 (188,875)
Net increase (decrease) in cash and cash equivalents $7,820
 $12,554
 $(279,484)

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

Investing Activitiesactivities. 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 investingfinancing activities for the year ended December 31, 2017,2020, included the following:

•$1.03.0 billion of capital expenditures, netrepayments of $1.4outstanding borrowings under the Term loan facility;

•$600.0 million of contributions in aidrepayments of construction costs from affiliates, primarily related to construction and expansion atoutstanding borrowings under the DBJV system, DBM complex, DBM oil system, and DJ Basin complex and the construction of the DBM water systems;RCF;

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

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

$3.9 million of cash paid for equipment purchases from affiliates;

$31.7695.8 million of distributions received from equity investments in excesspaid to WES unitholders;

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

•$23.332.5 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 saleFixed-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 Helperyear; and Clawson systems in Utah; and

•$23.020.0 million of proceedsa one-time cash contribution from property insurance claims attributableOccidental received in January 2020, pursuant to the incident at the DBM complex in 2015.

Services Agreement, for anticipated transition costs required to establish stand-alone human resources and information technology functions.
Financing Activities
.
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 to fundthe 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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Net cash used in financing activities for the year ended December 31, 2017, included the following:

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

$126.9 million of net contributions from Anadarko representing intercompany transactions attributable to the acquisition of AMA;

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

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

$442.0 million of distributions paid to WES unitholders;

$355.6 million of distributions paid to the noncontrolling interest owners of WES Operating;

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

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

Debt and credit facilities. As of December 31, 2019,2020, the carrying value of outstanding debt was $8.0 billion.$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, 2019,2020, 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. In February 2018, we voluntarily reduced the aggregate commitment of lenders under the WGP RCF to $35.0 million. The WGP RCF, which previously was available to purchase WES Operating common units and for general partnership purposes,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. SeeExecutive Summary–December 2019 Agreements withinNote 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Item 7 for more information.Form 10-K.

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As of December 31, 2019,2020, there were $380.0 million ofno outstanding borrowings and $4.6$5.1 million of outstanding letters of credit, resulting in $1.6$2.0 billion of available borrowing capacity under the RCF. At December 31, 2019,2020, the interest rate on any outstanding RCF borrowings was 3.04%1.64% and the facility feefacility-fee rate was 0.20%0.25%. At December 31, 2019,2020, 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 Executive Summary—Merger transactions within this Item 7). The Term loan facility bears interest at LIBOR, plus applicable margins ranging from 1.000% to 1.625%, or an alternate base rate equal to the greatestNote 1—Summary of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case as defined in the Term loan facilitySignificant Accounting Policies and plus applicable margins currently ranging from zero to 0.625%, based on WES Operating’s senior unsecured debt rating. Net cash proceeds received from future asset sales and debt or equity offerings must be used to repay amounts outstanding under the facility. The Term loan facility contains covenants and certain eventsBasis of default that are substantially similar to those contained in the RCF.
In July 2019, WES Operating entered into an amendment to the Term loan facility to (i) extend the maturity date from February 2020 to December 2020, (ii) increase commitments available under the Term loan facility from $2.0 billion to $3.0 billion, the incremental $1.0 billion of which was subsequently drawn by WES Operating on September 13, 2019, and used to repay outstanding borrowings under the RCF, and (iii) modify the provision requiring that all debt issuance proceeds be used to repay the Term loan facility to allow for a $1.0 billion exclusion for debt-offering proceeds.
As of December 31, 2019, there were $3.0 billion of outstanding borrowings under the Term loan facility that were subject to an interest rate of 3.10%. WES Operating was in compliance with all covenants under the Term loan facility as of December 31, 2019. The outstanding borrowings under the Term loan facility were classified as Long-term debt on the consolidated balance sheet at December 31, 2019. In January 2020, WES Operating repaid the outstanding borrowings under the Term loan facility with proceeds from the issuance of the Senior Notes and Floating Rate Notes (see Note 16—Subsequent EventsPresentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information)10-K).

The RCF and Term loan facility contain certain covenants that limit, among other things, In January 2020, 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 inOperating repaid the character of its business, enter into certain affiliate transactions and useoutstanding borrowings with proceeds other than for partnership purposes. The RCF and Term loan facility also contain various customary covenants, certain events of default, and a maximum consolidated leverage ratio asfrom the issuance of the end of each fiscal quarter (which is defined asFixed-Rate Senior Notes and Floating-Rate Senior Notes and terminated the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated Earnings Before Interest, Taxes, Depreciation, and Amortization for the most-recent four-consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions.


Prior to December 31, 2019, WES Operating GP was indemnified by wholly owned subsidiaries of Occidental against any claims made against WES Operating GP for WES Operating’s long-term debt and/or borrowings under the RCF and Term loan facility. These indemnification agreements were terminated as partDuring the first quarter of 2020, a loss of $2.3 million was recognized for the early termination of the December 2019 Agreements.Term loan facility. See Executive Summary–December 2019 AgreementsNote 13—Debt and Interest Expense withinin the Notes to Consolidated Financial Statements under Part II, Item 8 of this Item 7 for more information.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, which was payable at maturity at the applicable mid-term federal rate based on a quarterly compounding basis as determined by the U.S. Secretary of the Treasury.interest. The APCWH Note Payable was repaid at Merger completion (seecompletion. See Executive Summary—Merger transactionsNote 1—Summary of Significant Accounting Policies and Basis of Presentation withinin the Notes to Consolidated Financial Statements under Part II, Item 8 of this Item 7).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. Pursuant to these swap agreements, WES Operating received a fixed interest rate and paid a floating interest rate indexed to the three-month LIBOR,million, effectively offsetting the swap agreements entered into in December 2018 and March 2019.
In December 2019, all outstanding interest-rate swap agreements were cash-settled.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 statementstatements 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. For the year ended December 31, 2019, a net loss of $125.3 million was recognized, which is included in Other income (expense), net in the consolidated statements of operations. See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information.10-K.

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DBJV acquisition - Deferred purchase priceAsset retirement obligations.When assets are acquired or constructed, the initial estimated asset retirement obligation - Anadarko. Prior to WES Operating’s agreement with Anadarko to settle the deferred purchase price obligation early, the consideration that would have been paid for the March 2015 acquisition of DBJV from Anadarko consisted of a cash payment to Anadarko due on March 31, 2020. In May 2017, WES Operating reachedis recognized in an agreement with Anadarko to settle this obligation with a cash payment to Anadarko of $37.3 million, which wasamount equal to the estimated net present value of the settlement obligation, at Marchwith 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, 2017.2020, 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 imbalancegas-imbalance agreements. We examine and monitor the creditworthiness of third-party customers and may establish credit limits for third-party customers. A substantial portion of our throughput however, comesis sourced from producers, including Occidental, that have investment-grade ratings.recently received credit-rating downgrades. We are subject to the risk of non-payment or late payment by Occidentalproducers for gathering, processing, transportation, and disposal fees andfees. Through December 31, 2020, we were also dependent on Occidental to remit payments to us for proceeds from the salevalue 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 Occidental.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 we remain dependent onour commercial relationships with Occidental for over 50%generate a significant portion of our revenues. Additionally, we are exposedWhile 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 credit risk on the note receivable from Anadarko.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 with Affiliates 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; natural-gascommodity purchase and NGLs purchasesale agreements; Anadarko’s note payable to WES Operating; the contribution agreements; or the December 2019 Agreements (see Agreements.

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Note 1—SummaryTable of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).Contents


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) attributable to WES to net income (loss) attributable to WES Operating.. The differences between net income (loss) attributable to WES and net income (loss) attributable to 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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  Year Ended December 31,
thousands 2019 2018 2017
Net income (loss) attributable to WES $697,241
 $551,571
 $540,790
Limited partner interests in WES Operating not held by WES (1)
 103,364
 70,474
 185,860
General and administrative expenses (2)
 6,819
 4,029
 2,872
Other income (expense), net (79) (192) (85)
Interest expense 245
 2,035
 2,229
Net income (loss) attributable to WES Operating $807,590
 $627,917
 $731,666
(1)Table of Contents
Represents the portion of net income (loss) allocated to the limited partner interests in WES Operating not held by WES. As of December 31, 2019, 2018, and 2017, the public held a 0%, 59.2%, and 59.6% limited partner interest in WES Operating, respectively. Certain subsidiaries of Occidental separately held a 2.0%, 9.7%, and 9.1% limited partner interest in WES Operating as of December 31, 2019, 2018, and 2017, respectively. 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 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.


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 $875,192 
Distributions to WES unitholders (2)
695,834 969,073 502,457 
Distributions to WES from WES Operating (3)
(756,112)(1,006,163)(507,323)
Increase (decrease) in outstanding checks(35)— — 
Registration expenses related to the issuance of WES common units— 855 — 
Unit repurchases32,535 — — 
WGP RCF costs— — 7 
WGP RCF repayments— 28,000 — 
WES Operating net cash provided by (used in) financing activities$(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.
  Year Ended December 31,
thousands 2019 2018 2017
WES net cash provided by operating activities $1,324,100
 $1,348,175
 $1,042,715
General and administrative expenses (1)
 6,819
 4,029
 2,872
Non-cash equity-based compensation expense (1,259) (278) (247)
Changes in working capital 2,383
 (854) (8)
Other income (expense), net (79) (192) (85)
Interest expense 245
 2,035
 2,229
Debt related amortization and other items, net (20) (801) (678)
WES Operating net cash provided by operating activities $1,332,189
 $1,352,114
 $1,046,798
       
WES net cash provided by (used in) financing activities $2,071,573
 $875,192
 $(188,875)
Distributions to WES unitholders (2)
 969,073
 502,457
 441,967
Distributions to WES from WES Operating (3)
 (1,006,163) (507,323) (445,677)
Registration expenses related to the issuance of WES common units 855
 —
 —
WGP RCF costs —
 7
 —
WGP RCF repayments 28,000
 —
 —
WES Operating net cash provided by (used in) financing activities $2,063,338
 $870,333
 $(192,585)
(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.
(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 upon 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 for further information)10-K).

WES Operating distributions. WES Operating distributes all of its available cash (as(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 makeshas made quarterly cash distributions to WES and WGRAH, a subsidiary of Occidental, in respect ofproportion to their proportionate share of limited partner interests in WES Operating. For the quarterseach quarter ended March 31, 2019,2020, June 30, 2019,2020, and September 30, 2019,2020, WES Operating distributed $283.3$143.4 million $288.1 million, and $289.7 million, respectively, to its limited partners. For the quarter ended December 31, 2019,2020, WES Operating distributed $290.3$127.5 million to its limited partners. See Note 54—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 with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information.


CONTRACTUAL OBLIGATIONS

The following is a summary of our contractual cash obligations as of December 31, 2019. The table below excludes amounts classified as current liabilities on the consolidated balance sheets, other than the current portions of the categories listed within the table. It is expected that the majority of the excluded current liabilities will be paid in cash in 2020.
  Obligations by Period
thousands 2020 2021 2022 2023 2024 Thereafter Total
Total debt              
Principal $3,007,873
 $500,000
 $670,000
 $—
 $—
 $3,830,000
 $8,007,873
Interest 331,192
 217,990
 207,589
 180,963
 180,963
 2,136,237
 3,254,934
Asset retirement obligations 22,472
 38,537
 —
 —
 4,443
 293,416
 358,868
Capital expenditures 140,954
 —
 —
 —
 —
 —
 140,954
Credit facility fees 4,133
 4,133
 4,133
 4,133
 4,133
 530
 21,195
Environmental obligations 3,528
 907
 468
 320
 203
 12
 5,438
Operating leases 1,969
 612
 618
 625
 449
 1,209
 5,482
Total $3,512,121
 $762,179
 $882,808
 $186,041
 $190,191
 $6,261,404
 $11,794,744

Asset retirement obligations.When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in properties and equipment. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, asset retirement costs, and the estimated timing of settlement. For additional information, see Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

100
Capital expenditures. Included in this amount are capital obligations related to our expansion projects. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual obligations made in advanceTable of the actual expenditures. See Note 15—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.Contents

Credit facility fees. For additional information on credit facility fees required under the RCF, see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Environmental obligations. We are subject to various environmental-remediation obligations arising from federal, state, and local regulations regarding air and water quality, hazardous and solid waste disposal, and other environmental matters. We regularly monitor the remediation and reclamation process and the liabilities recorded and believe that the amounts reflected in our recorded environmental obligations are adequate to fund remedial actions required to comply with present laws and regulations. For additional information on environmental obligations, see Note 15—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Leases.We have entered into operating leases that extend through 2028 for corporate offices, shared field offices, and equipment supporting our operations, with both Occidental and third parties as lessors. Lease obligations to Occidental represent existing contractual operating lease obligations that may be assigned or otherwise charged to us pursuant to the reimbursement provisions of our Services Agreement. We also have subleased equipment from Occidental via finance leases extending through April 2020. The liabilities associated with these finance leases are included within Short-term debt in the consolidated balance sheets. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

For additional information on contracts, obligations, and arrangements we and WES Operating enter into from time to time, see Note 6—Transactions with Affiliates and Note 15—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.


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 affect the amounts of revenues and expenses recognized during the periods reported. On an ongoing basis, management reviews its estimates, including those related to the determination of property, plant, and equipment, other intangible assets, goodwill, equity investments, asset retirement obligations, litigation, environmental liabilities, income taxes, revenues, and fair values. On an annual basis, as determined by the specific agreement, management reviews and updates certain gathering rates that are based on cost-of-service agreements. These cost-of-service gathering rates are calculated using a contractually specified rate of return and estimates including long-term assumptions for capital invested, receipt volumes, and operating and maintenance expenses. SeeContract 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. 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. ManagementManagement 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 productin 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 tangibleproperty, plant, and equipment and other intangible assets. Property, plant, and equipment generally isand other intangible assets are stated at the lower of historical cost less accumulated depreciation or amortization, or fair value if impaired. Because prior long-lived asset acquisitions of assets from Anadarko were transfers of net assets between entities under common control, the assets acquired were initially were recorded at Anadarko’s historic carrying value. Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value. Property,
Management assesses property, plant, and equipment, balances are evaluatedtogether with any associated materials and supplies inventory and intangible assets, for potential impairment when events or changes in circumstances indicate that their carrying amountsvalues may not be recoverable from expected undiscounted cash flows from the use and eventual disposition of an asset. If the sum of the undiscounted future net cash flows is less than the carrying amount of the asset’s estimated fair value, an impairment loss is recognized for the excess, if any, of the carrying amount of the asset over its estimated fair value.
In assessing long-lived assets for impairments, our management evaluates changesrecoverable. Changes in our business and economic conditions andare evaluated for their implications foron recoverability of the assets’ carrying amounts. Management applies judgment in determining whether there is an indication of impairment, the grouping of assets for impairment assessment, and determinations about the future use of such assets.values. Significant downward revisions in production forecasts or changes in future development plans by producers, to the extent they affect our operations, may necessitate assessmentan 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 carrying amountasset. 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 affected assets for recoverability.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. The measureManagement applies judgment in the grouping of impairmentsassets 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 be recognized, if any, depends upon management’sits estimated fair value with an offsetting charge to impairment expense. Management’s estimate of the asset’s fair value which 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 8—9—Property, Plant, and Equipmentand 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, 2018, and 2017.2018.


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. Among other things, managementImpairment 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 (i) of long-lived assets for impairment testing, (ii) of reporting units for goodwill impairment testing when necessary, (iii) of assets and liabilities acquired in a third-party business combination or exchanged in non-monetary transactions, (iv) for the initial measurement of asset retirement obligations, (v) for the initial measurement of environmental obligations assumed in a third-party acquisition, and (vi) of interest-rate swaps. When management is required to measure fair value and there is not a market-observable price for the asset or liability or a market-observable price for a similar asset or liability, management utilizes the cost, income, or multiples approach, depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach uses management’s best assumptions regarding expectations of projected cash flows and discounts the expected cash flows using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment because results are based on expected future events or conditions, such as sales prices, estimates of future throughput, capital and operating costs and the timing thereof, economic and regulatory climates, and other factors. A multiples approach uses management’s best assumptions regarding expectations of projected EBITDA and an assumed multiple of that EBITDA that a willing buyer would pay to acquire an asset. Management’s estimates of future net cash flows and EBITDA are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, the assumptions used reflect a market participant’s view of long-term prices, costs, and other factors, and are consistent with assumptions used in our business plans and investment decisions. 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.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements other than short-term operating leases and standby letters of credit. The information pertaining to operating leases and standby letters of credit required for this item is provided under Note 1—Summary of Significant Accounting Policies, Note 14—Leases, and Note 13—Debt and Interest Expense, respectively, included 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 for which Occidental is typically responsible for the marketing of the natural gas, condensate, and NGLs.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, 2019,2020, 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil NGLs, 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 imbalances described below.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 indexmarket-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 settlement 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 raiseddecreased its target range for the federal funds rate four separatethree times during 20182019 and has decreased its target range three timestwice in 2019.2020. Any future increases in the federal funds rate likely will result in an increase in short-term financing costs. As of December 31, 2019,2020, we had $380.0 million in(i) no outstanding borrowings under the RCF and $3.0 billion in outstanding borrowings under the Term loan facility. The RCF and Term loan facility eachthat bear interest at a rate based on LIBOR or an alternative base rate at WES Operating’s option.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, under the RCF and Term loan facility, it would impact the fair value of the Senior Notessenior notes at December 31, 2019.2020. 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 and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

120105
121105
Western Midstream Partners, LP
122106
Reports of Independent Registered Public Accounting Firm
122106
Financial Statements
126111
Consolidated Statements of Operations for the years ended December 31, 2020, 2019, 2018, and 20172018
126111
Consolidated Balance Sheets as of December 31, 20192020 and 20182019
127112
Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2020, 2019, 2018, and 20172018
128113
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019, 2018, and 20172018
129114
130115
Report of Independent Registered Public Accounting Firm
130115
Financial Statements
131118
Consolidated Statements of Operations for the years ended December 31, 2020, 2019, 2018, and 20172018
131118
Consolidated Balance Sheets as of December 31, 20192020 and 20182019
132119
Consolidated Statements of Equity and Partners’ Capital for the years ended December 31, 2020, 2019, 2018, and 20172018
133120
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019, 2018, and 20172018
134121
Notes to Consolidated Financial Statements
135122
Note 1. Summary of Significant Accounting Policies and Basis of Presentation
135122
Note 2. Revenue from Contracts with Customers
146132
Note 3. Acquisitions and Divestitures
148134
Note 4. Partnership Distributions
150135
Note 5. Equity and Partners’ Capital
152137
Note 6. Related-Party Transactions with Affiliates
157140
Note 7. Income TaxesEquity Investments
164147
Note 8. Income Taxes
149
Note 9. Property, Plant, and Equipment
165151
Note 9.10. Goodwill and Other Intangibles
166152
Note 10. Equity Investments
167
Note 11. Selected Components of Working Capital
169153
Note 12. Asset Retirement Obligations
170154
Note 13. Debt and Interest Expense
171155
Note 14. Leases
175159
Note 15. Equity-Based Compensation
161
Note 16. Commitments and Contingencies
177163
Note 16. Subsequent Events
177
Supplemental Quarterly Information
178












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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, 2019.2020. 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, 2019.2020.
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, 2019.2020.

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

February 27, 202026, 2021



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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 of
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, 2019,2020, 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, 2019,2020, 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, 20192020 and 2018,2019, 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, 2019,2020, and the related notes (collectively, the consolidated financial statements), and our report dated February 27, 202026, 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 27, 202026, 2021


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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 of
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, 20192020 and 2018,2019, 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, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019,2020, 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, 2019,2020, 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 27, 202026, 2021 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

Change in Accounting Principle

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

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 mattermatters communicated below is a matterare matters arising from the current-periodcurrent period audit of the consolidated financial statements that waswere communicated or required to be communicated to the audit committee and that: (1) relatesrelate 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 a critical audit mattermatters 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 mattermatters below, providing a separate opinionopinions on the critical audit mattermatters 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
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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 relates.

Assessmentis tested for recoverability by comparing the sum of the cumulative catch-up revenue adjustmentestimated 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 and oil-stabilization revenue contractscontract with customers.a customer

As discussed in Notes 1 and 2 into the Notes to Consolidated Financial Statements,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. The Partnership is contractually requiredcost-of-service rate provisions. Annual adjustments are made to redetermine the cost of service ratecost-of-service rates charged to certain of its customers, annually, 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 estimated using actual amounts for prior yearsprobable of occurring and forecasted cash flows based on forecasted receipt volumes overif so, the remaining contract term. The volatilityvariable consideration may be constrained up to the amount of oil and natural-gas prices could negatively impact customers’ production activity and near-term drilling programs, which impacts the future producer volumes to be processed by the Partnership.probable significant reversal.

We identified the assessment of the cumulative catch-up revenue adjustmentestimated constraint on variable consideration related to one gas-gathering contract and one oil-gathering and oil-stabilization revenue contracts with customerscontract as a critical audit matter. Specifically,A high degree of challenging auditor judgment was required to evaluate the evaluationprobability of a significant reversal in the assumptionsamount of variable consideration recognized due to the uncertainty related to forecasted receipt volumes used inongoing legal proceedings and commercial negotiations with the forecasted cash flowscounterparties to estimate the cumulative catch-up revenue adjustment required subjective auditor judgment as there is inherent uncertainty in forecasting receipt volumes over a long period of time.contracts.

The following are the primary procedures we performed to address this critical audit matter includedmatter. We evaluated the following. Wedesign and tested the operating effectiveness of certain internal controls over the Partnership’s assessmentannual re-determination of the forecasted cash flows, includingcost-of-service rate. This included certain controls relatedover 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 forecasted receipt volumes.contracts. We analyzedexamined 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 production activitycounterparties and near-term drilling programsthe resulting impact on the determination of the Partnership’s customers using evidence from publicly available information such as press releases and company filings withestimated constraint on variable consideration. We evaluated the U.S. Securities and Exchange Commission and compared that informationaccuracy of the data used by the Partnerships to calculate the forecasted receipt volumes. We analyzed forecasted oil and natural-gas prices using publicly available information and compared it to the trend in the forecasted receipt volumes. In addition, we compared historical receipt volume forecasts to actual results to assess the Partnership’s ability to accurately forecast.variable consideration constraint.


/s/ KPMG LLP

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

Houston, Texas
February 27, 202026, 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 0 0 
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 0 0 
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)0 
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 

  Year Ended December 31,
thousands except per-unit amounts 2019 2018 2017
Revenues and other – affiliates      
Service revenues – fee based $1,441,875
 $1,070,066
 $769,305
Service revenues – product based 7,062
 3,339
 —
Product sales 158,459
 280,306
 753,724
Other —
 —
 16,076
Total revenues and other – affiliates 1,607,396
 1,353,711
 1,539,105
Revenues and other – third parties      
Service revenues – fee based 946,316
 835,662
 588,571
Service revenues – product based 63,065
 85,446
 —
Product sales 127,929
 22,714
 297,486
Other 1,468
 2,125
 4,452
Total revenues and other – third parties 1,138,778
 945,947
 890,509
Total revenues and other 2,746,174
 2,299,658
 2,429,614
Equity income, net – affiliates 237,518
 195,469
 115,141
Operating expenses      
Cost of product (1)
 444,247
 415,505
 953,792
Operation and maintenance (1)
 641,219
 480,861
 345,617
General and administrative (1)
 114,591
 67,195
 53,949
Property and other taxes 61,352
 51,848
 53,147
Depreciation and amortization 483,255
 389,164
 318,771
Impairments 6,279
 230,584
 180,051
Total operating expenses 1,750,943
 1,635,157
 1,905,327
Gain (loss) on divestiture and other, net (2)
 (1,406) 1,312
 132,388
Proceeds from business interruption insurance claims —
 —
 29,882
Operating income (loss) 1,231,343
 861,282
 801,698
Interest income – affiliates 16,900
 16,900
 16,900
Interest expense (3)
 (303,286) (183,831) (142,520)
Other income (expense), net (4)
 (123,785) (4,763) 1,384
Income (loss) before income taxes 821,172
 689,588
 677,462
Income tax expense (benefit) 13,472
 58,934
 (59,923)
Net income (loss) 807,700
 630,654
 737,385
Net income (loss) attributable to noncontrolling interests 110,459
 79,083
 196,595
Net income (loss) attributable to Western Midstream Partners, LP $697,241
 $551,571
 $540,790
Limited partners’ interest in net income (loss):      
Net income (loss) attributable to Western Midstream Partners, LP $697,241
 $551,571
 $540,790
Pre-acquisition net (income) loss allocated to Anadarko (29,279) (182,142) (164,183)
General partner interest in net (income) loss (5,637) —
 —
Limited partners’ interest in net income (loss) (5)
 662,325
 369,429
 376,607
Net income (loss) per common unit – basic and diluted (5)
 $1.59
 $1.69
 $1.72
Weighted-average common units outstanding – basic and diluted 415,794
 218,936
 218,931
(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.
(1)
Cost of product includes product purchases from affiliates (as defined in Note 1) of $254.8 million, $168.5(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 $74.6 million for the years ended December 31, 2019, 2018, and 2017, respectively. Operation and maintenance includes charges from affiliates of $147.0 million, $115.9 million, and $82.2 million for the years ended December 31, 2019, 2018, and 2017, respectively. General and administrative includes charges from affiliates of $101.5 million, $49.7 million, and $43.2 million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 6.
(2)
Includes losses related to an incident at the DBM complex for the year ended December 31, 2017. See Note 1.
(3)
Includes affiliate amounts of $(2.0) million, $(6.7) million, and $(0.2) million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 1 and Note 13.
(4)
Includes losses associated with the interest-rate swap agreements for the years ended December 31, 2019 and 2018. See Note 13.
(5)
See Note 1.


(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.

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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.
  December 31,
thousands except number of units 2019 2018
ASSETS    
Current assets    
Cash and cash equivalents $99,962
 $92,142
Accounts receivable, net (1)
 260,512
 221,164
Other current assets (2)
 41,938
 31,458
Total current assets 402,412
 344,764
Note receivable – Anadarko 260,000
 260,000
Property, plant, and equipment    
Cost 12,355,671
 11,258,773
Less accumulated depreciation 3,290,740
 2,848,420
Net property, plant, and equipment 9,064,931
 8,410,353
Goodwill 445,800
 445,800
Other intangible assets 809,391
 841,408
Equity investments 1,285,717
 1,092,088
Other assets (3)
 78,202
 62,792
Total assets $12,346,453
 $11,457,205
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL    
Current liabilities    
Accounts and imbalance payables $293,128
 $443,343
Short-term debt (4)
 7,873
 28,000
Accrued ad valorem taxes 35,160
 36,986
Accrued liabilities (5)
 149,793
 129,148
Total current liabilities 485,954
 637,477
Long-term liabilities    
Long-term debt 7,951,565
 4,787,381
APCWH Note Payable (6)
 —
 427,493
Deferred income taxes 18,899
 280,017
Asset retirement obligations 336,396
 300,024
Other liabilities (7)
 208,346
 132,130
Total long-term liabilities 8,515,206
 5,927,045
Total liabilities 9,001,160
 6,564,522
Equity and partners’ capital    
Common units (443,971,409 and 218,937,797 units issued and outstanding at December 31, 2019 and 2018, respectively) 3,209,947
 951,888
General partner units (9,060,641 and zero units issued and outstanding at December 31, 2019 and 2018, respectively) (8)
 (14,224) —
Net investment by Anadarko —
 1,388,018
Total partners’ capital 3,195,723
 2,339,906
Noncontrolling interests 149,570
 2,552,777
Total equity and partners’ capital 3,345,293
 4,892,683
Total liabilities, equity and partners’ capital $12,346,453
 $11,457,205
(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.
(1)
Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $113.3 million and $72.6 million as of December 31, 2019 and 2018, respectively.
(2)
Other current assets includes affiliate amounts of $5.0 million and $3.7 million as of December 31, 2019 and 2018, respectively.
(3)
Other assets includes affiliate amounts of $60.2 million and $42.2 million as of December 31, 2019 and 2018, respectively. Other assets also includes $4.5 million and $5.3 million of NGLs line fill as of December 31, 2019 and 2018, respectively.
(4)
As of December 31, 2019, all amounts are considered affiliate. See Note 14.
(5)
Accrued liabilities includes affiliate amounts of $3.1 million and $2.2 million as of December 31, 2019 and 2018, respectively.
(6)
See Note 1 and Note 6.
(7)
Other liabilities includes affiliate amounts of $97.8 million and $47.8 million as of December 31, 2019 and 2018, respectively.
(8)
See Note 1.

See accompanying Notes to Consolidated Financial Statements.

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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 $0 $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 0 
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 $0 $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)0 
Issuance of general partner units (5)
— 19,861 (19,861)— 0 
Above-market component of swap agreements with Anadarko (2)
— 7,407 — — 7,407 
WES Operating equity transactions, net (3)
— (755,197)— 755,197 0 
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$0 $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.
  Partners’ Capital    
thousands 
Net
Investment
by Anadarko
 
Common
Units
 
General Partner
Units
 
Noncontrolling
Interests
 Total
Balance at December 31, 2016 $761,890
 $1,048,143
 $—
 $3,062,623
 $4,872,656
Net income (loss) 164,183
 376,607
 —
 196,595
 737,385
Above-market component of swap agreements with Anadarko (1)
 —
 58,551
 —
 —
 58,551
WES Operating equity transactions, net (2)
 —
 6,615
 —
 (6,798) (183)
Distributions to Chipeta noncontrolling interest owner —
 —
 —
 (13,569) (13,569)
Distributions to noncontrolling interest owners of WES Operating —
 —
 —
 (355,623) (355,623)
Distributions to Partnership unitholders —
 (441,967) —
 —
 (441,967)
Acquisitions from affiliates (1,263) 1,263
 —
 —
 —
Revision to Deferred purchase price obligation – Anadarko (3)
 —
 4,165
 —
 —
 4,165
Contributions of equity-based compensation from Anadarko —
 4,587
 —
 —
 4,587
Net pre-acquisition contributions from (distributions to) Anadarko 126,866
 —
 —
 —
 126,866
Net contributions from (distributions to) Anadarko of other assets —
 3,189
 —
 —
 3,189
Adjustments of net deferred tax liabilities (1,505) —
 —
 —
 (1,505)
Other —
 (28) —
 526
 498
Balance at December 31, 2017 $1,050,171
 $1,061,125
 $—
 $2,883,754
 $4,995,050
Cumulative effect of accounting change (4)
 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 (1)
 —
 51,618
 —
 —
 51,618
WES Operating equity transactions, net (2)
 —
 (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) Anadarko 97,755
 —
 —
 —
 97,755
Net contributions from (distributions to) Anadarko of other assets 58,835
 —
 —
 —
 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 (5)
 —
 3,169,800
 —
 (3,169,800) —
Issuance of general partner units (5)
 —
 19,861
 (19,861) —
 —
Above-market component of swap agreements with Anadarko (1)
 —
 7,407
 —
 —
 7,407
WES Operating equity transactions, net (2)
 —
 (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 affiliates (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) Anadarko 458,819
 —
 —
 —
 458,819
Net contributions from (distributions to) Occidental of other assets —
 (90) —
 —
 (90)
Adjustments of net deferred tax liabilities 273,102
 (4,375) —
 —
 268,727
Other —
 561
 —
 (20) 541
Balance at December 31, 2019 $—
 $3,209,947
 $(14,224) $149,570
 $3,345,293
(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.


(1)
See Note 6.
(2)
For the years ended December 31, 2019, 2018, and 2017, the $(755.2) million, $(19.6) million, and $6.6 million increase (decrease) to partners’ capital, respectively, together with net income (loss) attributable to Western Midstream Partners, LP, totaled $(58.0) million, $532.0 million, and $547.4 million, respectively.
(3)
See Note 3.
(4)
Includes the adoption of Revenue from Contracts with Customers (Topic 606) on January 1, 2018. See Note 1.
(5)
See Note 1.
(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.

See accompanying Notes to Consolidated Financial Statements.

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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 0 0 
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)0 0 
(Gain) loss on interest-rate swaps0 125,334 7,972 
Cash paid to settle interest-rate swaps(25,621)(107,685)0 
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)0 0 
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)0 
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)0 
Unit repurchases(32,535)0 0 
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)$0 $0 
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.
  Year Ended December 31,
thousands 2019 2018 2017
Cash flows from operating activities      
Net income (loss) $807,700
 $630,654
 $737,385
Adjustments to reconcile net income (loss) to net cash provided by operating activities:      
Depreciation and amortization 483,255
 389,164
 318,771
Impairments 6,279
 230,584
 180,051
Non-cash equity-based compensation expense 15,494
 6,431
 5,169
Deferred income taxes 7,609
 139,048
 (53,138)
Accretion and amortization of long-term obligations, net 8,441
 5,943
 4,932
Equity income, net – affiliates (237,518) (195,469) (115,141)
Distributions from equity-investment earnings – affiliates 234,572
 187,392
 117,093
(Gain) loss on divestiture and other, net (1)
 1,406
 (1,312) (132,388)
(Gain) loss on interest-rate swaps 125,334
 7,972
 —
Cash paid to settle interest-rate swaps (107,685) —
 —
Lower of cost or market inventory adjustments 236
 752
 145
Changes in assets and liabilities:      
(Increase) decrease in accounts receivable, net (45,033) (60,502) (16,244)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net (30,866) 45,605
 (937)
Change in other items, net 54,876
 (38,087) (2,983)
Net cash provided by operating activities 1,324,100

1,348,175

1,042,715
Cash flows from investing activities      
Capital expenditures (1,188,829) (1,948,595) (1,028,319)
Contributions in aid of construction costs from affiliates —
 —
 1,387
Acquisitions from affiliates (2,007,926) (254) (3,910)
Acquisitions from third parties (93,303) (161,858) (177,798)
Investments in equity affiliates (128,393) (133,629) (2,884)
Distributions from equity investments in excess of cumulative earnings – affiliates 30,256
 29,585
 31,659
Proceeds from the sale of assets to third parties 342
 3,938
 23,564
Proceeds from property insurance claims —
 —
 22,977
Net cash used in investing activities (3,387,853)
(2,210,813)
(1,133,324)
Cash flows from financing activities      
Borrowings, net of debt issuance costs (2)
 4,169,695
 2,671,337
 468,803
Repayments of debt (3)
 (1,467,595) (1,040,000) —
Settlement of the Deferred purchase price obligation – Anadarko (4)
 —
 —
 (37,346)
Increase (decrease) in outstanding checks 1,571
 (3,206) 5,593
Proceeds from the issuance of WES Operating common units, net of offering expenses —
 —
 (183)
Registration expenses related to the issuance of Partnership common units (855) —
 —
Distributions to Partnership unitholders (5)
 (969,073) (502,457) (441,967)
Distributions to Chipeta noncontrolling interest owner (9,663) (13,529) (13,569)
Distributions to noncontrolling interest owners of WES Operating (118,225) (386,326) (355,623)
Net contributions from (distributions to) Anadarko 458,819
 97,755
 126,866
Above-market component of swap agreements with Anadarko (5)
 7,407
 51,618
 58,551
Finance lease payments – affiliates (508) —
 —
Net cash provided by (used in) financing activities 2,071,573

875,192

(188,875)
Net increase (decrease) in cash and cash equivalents 7,820

12,554

(279,484)
Cash and cash equivalents at beginning of period 92,142
 79,588
 359,072
Cash and cash equivalents at end of period $99,962

$92,142

$79,588
Supplemental disclosures      
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko (4)
 $—
 $—
 $(4,094)
Net distributions to (contributions from) Anadarko of other assets 90
 (58,835) (3,189)
Interest paid, net of capitalized interest 293,795
 140,720
 136,624
Taxes paid (reimbursements received) 96
 2,408
 1,194
Accrued capital expenditures 140,954
 274,632
 312,720
Fair value of properties and equipment from non-cash third-party transactions (4)
 —
 —
 551,453
(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.
(1)
Includes losses related to an incident at the DBM complex for the year ended December 31, 2017. See Note 1.
(2)
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.
(3)
For the year ended December 31, 2019, includes a $439.6 million repayment to settle the APCWH Note Payable. See Note 6.
(4)
See Note 3.
(5)
See Note 6.

See accompanying Notes to Consolidated Financial Statements.

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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 (the Partnership)(WES Operating) as of December 31, 20192020 and 2018,2019, 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, 2019,2020, 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 PartnershipWES Operating as of December 31, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019,2020, in conformity with U.S. generally accepted accounting principles.

Change in Accounting Principle

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

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership’sWES 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 the PartnershipWES 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. The PartnershipWES 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 the Partnership’sWES 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,
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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.
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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 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 the Partnership’sWES Operating’s auditor since 2007.

Houston, Texas
February 27, 202026, 2021


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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 0 0 
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 0 0 
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 
Pre-acquisition net (income) loss allocated to Anadarko0 (29,279)(182,142)
General partner interest in net (income) loss (4)
0 0 (346,538)
Common and Class C limited partners’ interest in net income (loss) (4)
541,377 778,311 99,237 
Net income (loss) per common unit – basic and diluted (4)
N/AN/A$0.55 

  Year Ended December 31,
thousands except per-unit amounts 2019 2018 2017
Revenues and other – affiliates      
Service revenues – fee based $1,441,875
 $1,070,066
 $769,305
Service revenues – product based 7,062
 3,339
 —
Product sales 158,459
 280,306
 753,724
Other —
 —
 16,076
Total revenues and other – affiliates 1,607,396
 1,353,711
 1,539,105
Revenues and other – third parties      
Service revenues – fee based 946,316
 835,662
 588,571
Service revenues – product based 63,065
 85,446
 —
Product sales 127,929
 22,714
 297,486
Other 1,468
 2,125
 4,452
Total revenues and other – third parties 1,138,778
 945,947
 890,509
Total revenues and other 2,746,174
 2,299,658
 2,429,614
Equity income, net – affiliates 237,518
 195,469
 115,141
Operating expenses      
Cost of product (1)
 444,247
 415,505
 953,792
Operation and maintenance (1)
 641,219
 480,861
 345,617
General and administrative (1)
 107,772
 63,166
 51,077
Property and other taxes 61,352
 51,848
 53,147
Depreciation and amortization 483,255
 389,164
 318,771
Impairments 6,279
 230,584
 180,051
Total operating expenses 1,744,124
 1,631,128
 1,902,455
Gain (loss) on divestiture and other, net (2)
 (1,406) 1,312
 132,388
Proceeds from business interruption insurance claims —
 —
 29,882
Operating income (loss) 1,238,162
 865,311
 804,570
Interest income – affiliates 16,900
 16,900
 16,900
Interest expense (3)
 (303,041) (181,796) (140,291)
Other income (expense), net (4)
 (123,864) (4,955) 1,299
Income (loss) before income taxes 828,157
 695,460
 682,478
Income tax expense (benefit) 13,472
 58,934
 (59,923)
Net income (loss) 814,685
 636,526
 742,401
Net income attributable to noncontrolling interest 7,095
 8,609
 10,735
Net income (loss) attributable to Western Midstream Operating, LP $807,590
 $627,917
 $731,666
Limited partners’ interest in net income (loss):      
Net income (loss) attributable to Western Midstream Operating, LP $807,590
 $627,917
 $731,666
Pre-acquisition net (income) loss allocated to Anadarko (29,279) (182,142) (164,183)
Series A Preferred units interest in net (income) loss (5)
 —
 —
 (42,373)
General partner interest in net (income) loss (5)
 —
 (346,538) (303,835)
Common and Class C limited partners’ interest in net income (loss) (5)
 778,311
 99,237
 221,275
Net income (loss) per common unit – basic and diluted (5)
 N/A
 $0.55
 $1.30
(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 $184.0 million, $501.4 million, and $333.3 million for the years ended December 31, 2020, 2019, and 2018, respectively. See Note 6.
(1)
(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.
Cost of product includes product purchases from affiliates (as defined in Note 1) of $254.8 million, $168.5 million, and $74.6 million for the years ended December 31, 2019, 2018, and 2017, respectively. Operation and maintenance includes charges from affiliates of $147.0 million, $115.9 million, and $82.2 million for the years ended December 31, 2019, 2018, and 2017, respectively. General and administrative includes charges from affiliates of $99.6 million, $48.8 million, and $42.4 million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 6.
(2)
Includes losses related to an incident at the DBM complex for the year ended December 31, 2017. See Note 1.
(3)
Includes affiliate amounts of $(2.0) million, $(6.7) million, and $(0.2) million for the years ended December 31, 2019, 2018, and 2017, respectively. See Note 1 and Note 13.
(4)
Includes losses associated with the interest-rate swap agreements for the years ended December 31, 2019 and 2018. See Note 13.
(5)
See Note 5 for the calculation of net income (loss) per common unit.

See accompanying Notes to Consolidated Financial Statements.
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CONSOLIDATED BALANCE SHEETS
December 31,
thousands except number of units20202019
ASSETS
Current assets
Cash and cash equivalents$418,537 $98,122 
Accounts receivable, net407,549 260,748 
Other current assets43,244 39,914 
Total current assets869,330 398,784 
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)
$11,756,293 $12,342,825 
LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables$210,532 $293,128 
Short-term debt438,870 7,873 
Accrued ad valorem taxes41,427 35,160 
Accrued liabilities230,833 149,639 
Total current liabilities921,662 485,800 
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)
8,895,542 9,001,006 
Equity and partners’ capital
Common units (318,675,578 units issued and outstanding at December 31, 2020 and 2019)2,831,199 3,286,620 
Total partners’ capital2,831,199 3,286,620 
Noncontrolling interest29,552 55,199 
Total equity and partners’ capital2,860,751 3,341,819 
Total liabilities, equity, and partners’ capital$11,756,293 $12,342,825 

(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 $1.5 billion and $1.7 billion as of December 31, 2020 and 2019, respectively, which includes related-party Accounts receivable, net of $246.1 million and $113.6 million as of December 31, 2020 and 2019, respectively. See Note 6.
(3)Total liabilities includes related-party amounts of $164.3 million and $108.8 million as of December 31, 2020 and 2019, respectively. See Note 6.
119
  December 31,
thousands except number of units 2019 2018
ASSETS    
Current assets    
Cash and cash equivalents $98,122
 $90,448
Accounts receivable, net (1)
 260,748
 221,373
Other current assets (2)
 39,914
 30,583
Total current assets 398,784
 342,404
Note receivable – Anadarko 260,000
 260,000
Property, plant, and equipment    
Cost 12,355,671
 11,258,773
Less accumulated depreciation 3,290,740
 2,848,420
Net property, plant, and equipment 9,064,931
 8,410,353
Goodwill 445,800
 445,800
Other intangible assets 809,391
 841,408
Equity investments 1,285,717
 1,092,088
Other assets (3)
 78,202
 62,792
Total assets $12,342,825
 $11,454,845
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL    
Current liabilities    
Accounts and imbalance payables $293,128
 $443,343
Short-term debt (4)
 7,873
 —
Accrued ad valorem taxes 35,160
 36,986
Accrued liabilities (5)
 149,639
 127,874
Total current liabilities 485,800
 608,203
Long-term liabilities    
Long-term debt 7,951,565
 4,787,381
APCWH Note Payable (6)
 —
 427,493
Deferred income taxes 18,899
 280,017
Asset retirement obligations 336,396
 300,024
Other liabilities (7)
 208,346
 132,130
Total long-term liabilities 8,515,206
 5,927,045
Total liabilities 9,001,006
 6,535,248
Equity and partners’ capital    
Common units (318,675,578 and 152,609,285 units issued and outstanding at December 31, 2019 and 2018, respectively) 3,286,620
 2,475,540
Class C units (zero and 14,372,665 units issued and outstanding at December 31, 2019 and 2018, respectively) (8)
 —
 791,410
General partner units (zero and 2,583,068 units issued and outstanding at December 31, 2019 and 2018, respectively) (8)
 —
 206,862
Net investment by Anadarko —
 1,388,018
Total partners’ capital 3,286,620
 4,861,830
Noncontrolling interest 55,199
 57,767
Total equity and partners’ capital 3,341,819
 4,919,597
Total liabilities, equity and partners’ capital $12,342,825
 $11,454,845
(1)
Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $113.6 million and $72.8 million as of December 31, 2019 and 2018, respectively.
(2)
Other current assets includes affiliate amounts of $5.0 million and $3.7 million as of December 31, 2019 and 2018, respectively.
(3)
Other assets includes affiliate amounts of $60.2 million and $42.2 million as of December 31, 2019 and 2018, respectively. Other assets also includes $4.5 million and $5.3 million of NGLs line fill as of December 31, 2019 and 2018, respectively.
(4)
As of December 31, 2019, all amounts are considered affiliate. See Note 14.
(5)
Accrued liabilities includes affiliate amounts of $3.1 million and $2.2 million as of December 31, 2019 and 2018, respectively.
(6)
See Note 1 and Note 6.
(7)
Other liabilities includes affiliate amounts of $97.8 million and $47.8 million as of December 31, 2019 and 2018, respectively.
(8)
Immediately prior to the closing of the Merger (as defined in Note 1), all outstanding general partner units converted into a non-economic general partner interest in WES Operating and WES Operating common units and all outstanding Class C units converted into WES Operating common units on a 1-for-one basis.

See accompanying Notes to Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
 Partners’ Capital  
thousandsNet
Investment
by Anadarko		Common
Units		Class C
Units		General
Partner
Units		Noncontrolling
Interest		Total
Balance at December 31, 2017$1,050,171 $2,950,010 $780,040 $179,232 $61,729 $5,021,182 
Cumulative effect of accounting change (1)
629 (41,108)(3,533)(696)958 (43,750)
Net income (loss)182,142 87,581 11,656 346,538 8,609 636,526 
Above-market component of swap agreements with Anadarko (2)
— 51,618 — — — 51,618 
Amortization of beneficial conversion feature of Class C units— (3,247)3,247 — — 0 
Distributions to Chipeta noncontrolling interest owner— — — — (13,529)(13,529)
Distributions to WES Operating unitholders— (575,323)— (318,326)— (893,649)
Contributions of equity-based compensation from Anadarko— 5,613 — 114 — 5,727 
Net pre-acquisition contributions from (distributions to) 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— 396 — — — 396 
Balance at December 31, 2018$1,388,018 $2,475,540 $791,410 $206,862 $57,767 $4,919,597 
Net income (loss)29,279 765,678 10,636 1,997 7,095 814,685 
Cumulative impact of the Merger transactions (3)
— 926,236 (802,588)(123,648)— 0 
Above-market component of swap agreements with Anadarko (2)
— 7,407 — — — 7,407 
Amortization of beneficial conversion feature of Class C units— (542)542 — — 0 
Distributions to Chipeta noncontrolling interest owner— — — — (9,663)(9,663)
Distributions to WES Operating unitholders— (1,039,158)— (85,230)— (1,124,388)
Acquisitions from related parties (4)
(2,149,218)141,717 — — — (2,007,501)
Contributions of equity-based compensation from Occidental— 13,938 — 19 — 13,957 
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— 269 — — — 269 
Balance at December 31, 2019$0 $3,286,620 $0 $0 $55,199 $3,341,819 
Net income (loss)— 541,377 — — (20,990)520,387 
Distributions to Chipeta noncontrolling interest owner— — — — (8,644)(8,644)
Distributions to WES Operating unitholders— (771,546)— — — (771,546)
Acquisitions from related parties— (3,987)— — 3,987 0 
Contributions of equity-based compensation from Occidental— 14,604 — — — 14,604 
Unit exchange with Occidental (2)
— (261,878)— — — (261,878)
Net contributions from (distributions to) related parties (5)
— 24,466 — — — 24,466 
Other— 1,543 — — — 1,543 
Balance at December 31, 2020$0 $2,831,199 $0 $0 $29,552 $2,860,751 

(1)Includes the adoption of Revenue from Contracts with Customers (Topic 606) on January 1, 2018.
(2)See Note 6.
(3)See Note 1.
(4)The amount allocated to common unitholders represents a non-cash investing activity related to the assets and liabilities assumed in the AMA acquisition.
(5)See December 2019 Agreements—Services, Secondment, and Employee Transfer Agreement within Note 1.
120
  Partners’ Capital    
thousands 
Net
Investment
by Anadarko
 
Common
Units
 
Class C
Units
 Series A Preferred Units 
General
Partner 
Units
 
Noncontrolling
Interest
 Total
Balance at December 31, 2016 $761,890
 $2,536,872
 $750,831
 $639,545
 $143,968
 $64,563
 $4,897,669
Net income (loss) 164,183
 231,405
 24,790
 7,453
 303,835
 10,735
 742,401
Above-market component of swap agreements with Anadarko (1)
 —
 58,551
 —
 —
 —
 —
 58,551
Conversion of Series A Preferred units into common units (2)
 —
 686,936
 —
 (686,936) —
 —
 —
Amortization of beneficial conversion feature of Class C units and Series A Preferred units —
 (66,718) 4,419
 62,299
 —
 —
 —
Distributions to Chipeta noncontrolling interest owner —
 —
 —
 —
 —
 (13,569) (13,569)
Distributions to WES Operating unitholders —
 (510,228) —
 (22,361) (268,711) —
 (801,300)
Acquisitions from affiliates (1,263) 1,263
 —
 —
 —
 —
 —
Revision to Deferred purchase price obligation – Anadarko (3)
 —
 4,165
 —
 —
 —
 —
 4,165
Contributions of equity-based compensation from Anadarko —
 4,473
 —
 —
 90
 —
 4,563
Net pre-acquisition contributions from (distributions to) Anadarko 126,866
 —
 —
 —
 —
 —
 126,866
Net contributions from (distributions to) Anadarko of other assets —
 3,139
 —
 —
 50
 —
 3,189
Adjustments of net deferred tax liabilities (1,505) —
 —
 —
 —
 —
 (1,505)
Other —
 152
 —
 —
 —
 —
 152
Balance at December 31, 2017 $1,050,171
 $2,950,010
 $780,040
 $—
 $179,232
 $61,729
 $5,021,182
Cumulative effect of accounting change (4)
 629
 (41,108) (3,533) —
 (696) 958
 (43,750)
Net income (loss) 182,142
 87,581
 11,656
 —
 346,538
 8,609
 636,526
Above-market component of swap agreements with Anadarko (1)
 —
 51,618
 —
 —
 —
 —
 51,618
Amortization of beneficial conversion feature of Class C units —
 (3,247) 3,247
 —
 —
 —
 —
Distributions to Chipeta noncontrolling interest owner —
 —
 —
 —
 —
 (13,529) (13,529)
Distributions to WES Operating unitholders —
 (575,323) —
 —
 (318,326) —
 (893,649)
Contributions of equity-based compensation from Anadarko —
 5,613
 —
 —
 114
 —
 5,727
Net pre-acquisition contributions from (distributions to) Anadarko 97,755
 —
 —
 —
 —
 —
 97,755
Net contributions from (distributions to) Anadarko of other assets 58,835
 —
 —
 —
 —
 —
 58,835
Adjustments of net deferred tax liabilities (1,514) —
 —
 —
 —
 —
 (1,514)
Other —
 396
 —
 —
 —
 —
 396
Balance at December 31, 2018 $1,388,018
 $2,475,540
 $791,410
 $—
 $206,862
 $57,767
 $4,919,597
Net income (loss) 29,279
 765,678
 10,636
 —
 1,997
 7,095
 814,685
Cumulative impact of the Merger transactions (5)
 —
 926,236
 (802,588) —
 (123,648) —
 —
Above-market component of swap agreements with Anadarko (1)
 —
 7,407
 —
 —
 —
 —
 7,407
Amortization of beneficial conversion feature of Class C units —
 (542) 542
 —
 —
 —
 —
Distributions to Chipeta noncontrolling interest owner —
 —
 —
 —
 —
 (9,663) (9,663)
Distributions to WES Operating unitholders —
 (1,039,158) —
 —
 (85,230) —
 (1,124,388)
Acquisitions from affiliates (6)
 (2,149,218) 141,717
 —
 —
 —
 —
 (2,007,501)
Contributions of equity-based compensation from Occidental —
 13,938
 —
 —
 19
 —
 13,957
Net pre-acquisition contributions from (distributions to) Anadarko 458,819
 —
 —
 —
 —
 —
 458,819
Net contributions from (distributions to) Occidental of other assets —
 (90) —
 —
 —
 —
 (90)
Adjustments of net deferred tax liabilities 273,102
 (4,375) —
 —
 —
 —
 268,727
Other —
 269
 —
 —
 —
 —
 269
Balance at December 31, 2019 $—
 $3,286,620
 $—
 $—
 $—
 $55,199
 $3,341,819
(1)
See Note 6.
(2)
See Note 5.
(3)
See Note 3.
(4)
Includes the adoption of Revenue from Contracts with Customers (Topic 606) on January 1, 2018. See Note 1.
(5)
See Note 1.
(6)
The amount allocated to common unitholders represents a non-cash investing activity related to the assets and liabilities assumed in the AMA acquisition.


See accompanying Notes to Consolidated Financial Statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
thousands202020192018
Cash flows from operating activities
Net income (loss)$520,387 $814,685 $636,526 
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 0 0 
Non-cash equity-based compensation expense14,604 14,235 6,153 
Deferred income taxes3,296 7,609 139,048 
Accretion and amortization of long-term obligations, net8,654 8,421 5,142 
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)0 0 
(Gain) loss on interest-rate swaps0 125,334 7,972 
Cash paid to settle interest-rate swaps(25,621)(107,685)0 
Other193 236 752 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net(147,041)(44,939)(60,460)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net105,352 (29,745)44,424 
Change in other items, net24,816 56,044 (37,802)
Net cash provided by operating activities1,640,651 1,332,189 1,352,114 
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)0 0 
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 2,671,344 
Repayments of debt (2)
(3,803,888)(1,439,595)(1,040,000)
Increase (decrease) in outstanding checks20,664 1,571 (3,206)
Distributions to WES Operating unitholders (3)
(771,546)(1,124,388)(893,649)
Distributions to Chipeta noncontrolling interest owner(8,644)(9,663)(13,529)
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)0 
Net cash provided by (used in) financing activities(871,982)2,063,338 870,333 
Net increase (decrease) in cash and cash equivalents320,415 7,674 11,634 
Cash and cash equivalents at beginning of period98,122 90,448 78,814 
Cash and cash equivalents at end of period$418,537 $98,122 $90,448 
Supplemental disclosures
Non-cash unit exchange with Occidental (3)
$(261,878)$0 $0 
Net distributions to (contributions from) Anadarko of other assets0 90 (58,835)
Interest paid, net of capitalized interest349,913 293,561 139,482 
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.
121
  Year Ended December 31,
thousands 2019 2018 2017
Cash flows from operating activities      
Net income (loss) $814,685
 $636,526
 $742,401
Adjustments to reconcile net income (loss) to net cash provided by operating activities:      
Depreciation and amortization 483,255
 389,164
 318,771
Impairments 6,279
 230,584
 180,051
Non-cash equity-based compensation expense 14,235
 6,153
 4,922
Deferred income taxes 7,609
 139,048
 (53,138)
Accretion and amortization of long-term obligations, net 8,421
 5,142
 4,254
Equity income, net – affiliates (237,518) (195,469) (115,141)
Distributions from equity-investment earnings – affiliates 234,572
 187,392
 117,093
(Gain) loss on divestiture and other, net (1)
 1,406
 (1,312) (132,388)
(Gain) loss on interest-rate swaps 125,334
 7,972
 —
Cash paid to settle interest-rate swaps (107,685) —
 —
Lower of cost or market inventory adjustments 236
 752
 145
Changes in assets and liabilities:      
(Increase) decrease in accounts receivable, net (44,939) (60,460) (16,177)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net (29,745) 44,424
 (947)
Change in other items, net 56,044
 (37,802) (3,048)
Net cash provided by operating activities 1,332,189
 1,352,114
 1,046,798
Cash flows from investing activities      
Capital expenditures (1,188,829) (1,948,595) (1,028,319)
Contributions in aid of construction costs from affiliates —
 —
 1,387
Acquisitions from affiliates (2,007,926) (254) (3,910)
Acquisitions from third parties (93,303) (161,858) (177,798)
Investments in equity affiliates (128,393) (133,629) (2,884)
Distributions from equity investments in excess of cumulative earnings – affiliates 30,256
 29,585
 31,659
Proceeds from the sale of assets to third parties 342
 3,938
 23,564
Proceeds from property insurance claims —
 —
 22,977
Net cash used in investing activities (3,387,853) (2,210,813) (1,133,324)
Cash flows from financing activities      
Borrowings, net of debt issuance costs (2)
 4,169,695
 2,671,344
 468,803
Repayments of debt (3)
 (1,439,595) (1,040,000) —
Settlement of the Deferred purchase price obligation – Anadarko (4)
 —
 —
 (37,346)
Increase (decrease) in outstanding checks 1,571
 (3,206) 5,593
Proceeds from the issuance of common units, net of offering expenses —
 —
 (183)
Distributions to WES Operating unitholders (5)
 (1,124,388) (893,649) (801,300)
Distributions to Chipeta noncontrolling interest owner (9,663) (13,529) (13,569)
Net contributions from (distributions to) Anadarko 458,819
 97,755
 126,866
Above-market component of swap agreements with Anadarko (5)
 7,407
 51,618
 58,551
Finance lease payments – affiliates (508) —
 —
Net cash provided by (used in) financing activities 2,063,338
 870,333
 (192,585)
Net increase (decrease) in cash and cash equivalents 7,674
 11,634
 (279,111)
Cash and cash equivalents at beginning of period 90,448
 78,814
 357,925
Cash and cash equivalents at end of period $98,122
 $90,448
 $78,814
Supplemental disclosures      
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko (4)
 $—
 $—
 $(4,094)
Net distributions to (contributions from) Anadarko of other assets 90
 (58,835) (3,189)
Interest paid, net of capitalized interest 293,561
 139,482
 135,079
Taxes paid (reimbursements received) 96
 2,408
 1,194
Accrued capital expenditures 140,954
 274,632
 312,720
Fair value of properties and equipment from non-cash third-party transactions (4)
 —
 —
 551,453
(1)
Includes losses related to an incident at the DBM complex for the year ended December 31, 2017. See Note 1.
(2)
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.
(3)
For the year ended December 31, 2019, includes a $439.6 million repayment to settle the APCWH Note Payable. See Note 6.
(4)
See Note 3.
(5)
See Note 6.

See accompanying Notes to Consolidated Financial Statements.

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1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

General. Western Midstream Partners, LP (formerly Western Gas Equity Partners, LP) is a Delaware master limited partnership formed in September 2012. Western Midstream Operating, LP (formerly Western Gas Partners, LP, and together(together with its subsidiaries, “WES Operating”) is a Delaware limited partnership formed by Anadarko Petroleum Corporation in 2007 to acquire, own, develop, and operate midstream assets. Western Midstream Partners, LP owns, directly and indirectly, a 98.0% limited partner interest in WES Operating, and directly owns all of the outstanding equity interests of Western Midstream Operating GP, LLC, which holds the entire non-economic general partner interest in WES Operating. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding Western Midstream Holdings, LLC. Anadarko became a wholly owned subsidiary of Occidental Petroleum Corporation as a result of Occidental Petroleum Corporation’s acquisition by merger of Anadarko on August 8, 2019.
For purposes of these consolidated financial statements, the “Partnership” refers to Western Midstream Partners, LP in its individual capacity or to Western Midstream Partners, LP and its subsidiaries, including Western Midstream Operating GP, LLC and WES Operating, as the context requires. “WES Operating GP” refers to Western Midstream Operating GP, LLC, individually as the general partner of WES Operating. The Partnership’s general partner, Western Midstream Holdings, LLC (the “general partner”), is a wholly owned subsidiary of Occidental Petroleum Corporation. “Occidental” refers to Occidental Petroleum Corporation, as the context requires, and its subsidiaries, excluding the general partner. “Affiliates”“Related parties” refers to Occidental (see Note 6) and the Partnership’s investments accounted for under the equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”), Front Range Pipeline LLC (“FRP”), Whitethorn Pipeline Company LLC (“Whitethorn LLC”), Cactus II Pipeline LLC (“Cactus II”), Saddlehorn Pipeline Company, LLC (“Saddlehorn”), Panola Pipeline Company, LLC (“Panola”), Mi Vida JV LLC (“Mi Vida”), Ranch Westex JV LLC (“Ranch Westex”), and Red Bluff Express Pipeline, LLC (“Red Bluff Express”). Seemethod of accounting (see Note 37). The interests in TEP, TEG, and FRP are referred to collectively as the “TEFR Interests.” “MGR assets” refers to the Red Desert complex and the Granger straddle plant. The “West Texas complex” refers to the Delaware Basin Midstream, LLC (“DBM”) complex and DBJV and Haley systems.
The Partnership is engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, natural-gas liquids (“NGLs”), and crude oil; and gathering and disposing of produced water. In its capacity as a natural-gas processor, the Partnership also buys and sells natural gas, NGLs, and condensate on behalf of itself and as an agent for its customers under certain contracts. The Partnership provides the above-described midstream services for Occidental and third-party customers. As of December 31, 2019,2020, the Partnership’s assets and investments consisted of the following:
Wholly
Owned and
Operated		Operated
Interests		Non-Operated
Interests		Equity
Interests
Gathering systems (1)
17 2 3 1 
Treating facilities39 3 — 0 
Natural-gas processing plants/trains25 3 — 5 
NGLs pipelines2 — — 5 
Natural-gas pipelines5 — — 1 
Crude-oil pipelines3 1 — 4 

  
Wholly
Owned and
Operated
 
Operated
Interests
 
Non-Operated
Interests
 
Equity
Interests
Gathering systems (1)
 17
 2
 3
 2
Treating facilities 37
 3
 —
 3
Natural-gas processing plants/trains 25
 3
 —
 5
NGLs pipelines 2
 —
 —
 4
Natural-gas pipelines 5
 —
 —
 1
Crude-oil pipelines 3
 1
 —
 3
(1)Includes the DBM water systems.

(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, Texas, and New Mexico.Pennsylvania. Latham Train I,II, a processingcryogenic train that is part ofat the DJ Basin complex, commenced operations induring the fourthfirst quarter of 2019.2020. Loving ROTF Trains III and IV, oil-stabilization trains at the DBM oil system, commenced operations during the first and third quarters of 2020, respectively.


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1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)AND BASIS OF PRESENTATION

December 2019 Agreements.Agreements. On December 31, 2019, (i) the Partnership and certain of its subsidiaries, including WES Operating and WES Operating GP, entered into the below-described agreements with Occidental and/or certain of its subsidiaries, including Anadarko, and (ii) WES Operating also entered into the below-described amendments to its debt agreements (collectively, referredthe “December 2019 Agreements”).

•Exchange Agreement. Western Gas Resources, Inc. (“WGRI”), the general partner, and the Partnership entered into a partnership interests exchange agreement (the “Exchange Agreement”), pursuant to which the Partnership canceled the non-economic general partner interest in the Partnership and simultaneously issued a 2.0% general partner interest to the general partner in exchange for which WGRI transferred 9,060,641 common units to the Partnership, which immediately canceled such units on receipt.

•Services, Secondment, and Employee Transfer Agreement. Occidental, Anadarko, and WES Operating GP entered into an amended and restated Services, Secondment, and Employee Transfer Agreement (the “Services Agreement”), pursuant to which Occidental, Anadarko, and their subsidiaries (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 the Partnership and (ii) agreed to continue to provide certain administrative and operational services to the Partnership for up to a two-year transition period. In January 2020, pursuant to the Services Agreement, Occidental made a one-time cash contribution of $20.0 million to WES Operating for anticipated transition costs required to establish stand-alone human resources and information technology functions. The Services Agreement also included provisions governing the transfer of certain employees to the Partnership and the assumption by the Partnership of liabilities relating to those employees at the time of their transfer. In late March 2020, seconded employees’ employment was transferred to the Partnership.

•RCF amendment. WES Operating entered into an amendment to its $2.0 billion senior unsecured revolving credit facility (“RCF”) to, among other things, (i) effective on February 14, 2020, exercise the final one-year extension option to extend the maturity date of the RCF to February 14, 2025, for the extending lenders, and (ii) modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of the Partnership elect to remove the general partner as the “general partner of the Partnership in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the RCF. See December 2019 AgreementsNote 13”).

•
Exchange Agreement. Western Gas Resources, Inc. (“WGRI”), the general partner, and the Partnership entered into a partnership interests exchange agreement (the “Exchange Agreement”), pursuant to which the Partnership canceled the non-economic general partner interest in the Partnership and simultaneously issued a 2.0% general partner interest to the general partner in exchange for which WGRI transferred 9,060,641 common units to the Partnership, which immediately canceled such units on receipt.

•
Services, Secondment, and Employee Transfer Agreement. Occidental, Anadarko, and WES Operating GP entered into an amended and restated Services, Secondment, and Employee Transfer Agreement (the “Services Agreement”), pursuant to which Occidental, Anadarko, and their subsidiaries will (i) second certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP will pay a monthly secondment and shared services fee to Occidental equivalent to the direct cost of the seconded employees and (ii) continue to provide certain administrative and operational services to the Partnership for up to a two-year transition period. The Services Agreement also includes provisions governing the transfer of certain employees to the Partnership and the assumption by the Partnership of liabilities relating to those employees at the time of their transfer. In January 2020, pursuant to the Services Agreement, Occidental made a one-time cash contribution of $20.0 million to the Partnership for anticipated transition costs required to establish stand-alone human resources and information technology functions.

•
RCF amendment. WES Operating entered into an amendment to its $2.0 billion senior unsecured revolving credit facility (“RCF”) to, among other things, (i) effective on February 14, 2020, exercise the final one-year extension option to extend the maturity date of the RCF to February 14, 2025, for the extending lenders, and (ii) modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of the Partnership elect to remove the general partner as the general partner of the Partnership in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the RCF.

•
Term loan facility amendment. WES Operating entered into an amendment of its $3.0 billion senior unsecured credit facility (“Term loan facility”) to, among other things, modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of the Partnership elect to remove the general partner as the general partner of the Partnership in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the Term loan facility.

•
Termination of debt-indemnification agreements. WES Operating GP and certain wholly owned subsidiaries of Occidental mutually terminated the debt-indemnification agreements related to indebtedness incurred by WES Operating.

•
Termination of omnibus agreements. The Partnership and WES Operating entered into agreements with Occidental to terminate the WES and WES Operating omnibus agreements. See Note 6.


•Term loan facility amendment. WES Operating entered into an amendment to its $3.0 billion senior unsecured credit facility (“Term loan facility”) to, among other things, modify the change of control definition to provide, among other things, that, subject to certain conditions, if the limited partners of the Partnership elect to remove the general partner as the general partner of the Partnership in accordance with the terms of the partnership agreement, then such removal will not constitute a change of control under the Term loan facility. See Note 13.

•Termination of debt-indemnification agreements. WES Operating GP and certain wholly owned subsidiaries of Occidental mutually terminated the debt-indemnification agreements related to certain indebtedness incurred by WES Operating.

•Termination of omnibus agreements. The Partnership and WES Operating entered into agreements with Occidental to terminate the WES and WES Operating omnibus agreements. See Note 6.

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1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)AND BASIS OF PRESENTATION

Merger transactions. On February 28, 2019, the Partnership, WES Operating, Anadarko, and certain of their affiliates completed the transactions contemplated by the Contribution Agreement and Agreement and Plan of Merger (the “Merger Agreement”), dated November 7, 2018, pursuant to which, among other things, (i) Clarity Merger Sub, LLC, a wholly owned subsidiary of the Partnership, merged with and into WES Operating, with WES Operating continuing as the surviving entity and as a subsidiary of the Partnership (the “Merger”). In connection with the Merger closing, (i) the common units of, and (ii) WES Operating which previously traded underacquired the symbol “WES,” ceased to trade on the New York Stock ExchangeAnadarko Midstream Assets (“NYSE”AMA”), (ii) the common units of the Partnership, which previously traded under the symbol “WGP,” began to trade on the NYSE under the symbol “WES,” (iii) the Partnership changed its name from Western Gas Equity Partners, LP to Western Midstream Partners, LP, and (iv) WES Operating changed its name from Western Gas Partners, LP to Western Midstream Operating, LP.
The Merger Agreement also provided that the Partnership, WES Operating, and Anadarko cause their respective affiliates to execute the following transactions, among others, immediately prior to the Merger becoming effective in the following order: (1) Anadarko E&P Onshore LLC and WGR Asset Holding Company LLC (“WGRAH”) (the “Contributing Parties”) contribute to WES Operating, and WES Operating subsequently contributes to WGR Operating, LP, Kerr-McGee Gathering LLC, and DBM (each wholly owned by WES Operating), all of their interests in each of Anadarko Wattenberg Oil Complex LLC, Anadarko DJ Oil Pipeline LLC, Anadarko DJ Gas Processing LLC, Wamsutter Pipeline LLC, DBM Oil Services, LLC, Anadarko Pecos Midstream LLC, Anadarko Mi Vida LLC, and APC Water Holdings 1, LLC (“APCWH”) in exchange for aggregate consideration of $1.814 billion of cash, less the outstanding amount payable pursuant to an intercompany note (the “APCWH Note Payable”) assumed by WES Operating in connection with the transfer, and 45,760,201 WES Operating common units; (2) APC Midstream Holdings, LLC (“AMH”) transfers its interests in Saddlehorn and Panola to WES Operating in exchange for $193.9 million of cash; (3) WES Operating contributes cash in an amount equal to the outstanding balance of the APCWH Note Payable immediately prior to the effective time of the Merger to APCWH, which in turn uses the contributed cash to satisfy the APCWH Note Payable to Anadarko; (4) the WES Operating Class C units convert into WES Operating common units on a 1-for-one basis; and (5) WES Operating and WES Operating GP convert the incentive distribution rights (“IDRs”) and the 2,583,068 general partner units in WES Operating held by WES Operating GP into a non-economic general partner interest in WES Operating and 105,624,704 WES Operating common units. The 45,760,201 WES Operating common units issued to the Contributing Parties, less 6,375,284 WES Operating common units retained by WGRAH, convert into the right to receive an aggregate of 55,360,984 common units of the Partnership at Merger completion. Each WES Operating common unit issued and outstanding immediately prior to the closing of the Merger (other than WES Operating common units owned by the Partnership and WES Operating GP, and certain common units held by subsidiaries of Anadarko) converts into the right to receive 1.525 common units of the Partnership.. See Note 13 3for additional information..


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Basis of presentation. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest, including WES Operating and WES Operating GP. All significant intercompany transactions have been eliminated.
The following table outlines the ownership interests and the accounting method of consolidation used in the consolidated financial statements for entities not wholly owned:
Percentage Interest
Full consolidation
Chipeta (1)
75.00%
Proportionate consolidation (2)
Springfield system50.10%
Marcellus Interest systems33.75%
Equity investments(3)
Mi Vida50.00%
Ranch Westex50.00%
FRP33.33%
Red Bluff Express30.00%
Mont Belvieu JV25.00%
Rendezvous22.00%
TEP20.00%
TEG20.00%
Whitethorn LLC20.00%
Saddlehorn20.00%
Cactus II15.00%
Panola15.00%
Fort Union14.81%
White Cliffs10.00%
(1)
The 25% third-party interest in Chipeta ProcessingMi Vida JV LLC (“Chipeta”Mi Vida”) is reflected within noncontrolling interests in the consolidated financial statements, in addition to the noncontrolling interests noted below.
50.00 %
(2)Ranch Westex JV LLC (“Ranch Westex”)
The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues, and expenses attributable to these assets.
50.00 %
(3)Front Range Pipeline LLC (“FRP”)
Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method of accounting. “Equity-investment throughput” refers to the Partnership’s share of average throughput for these investments.33.33 %
Red Bluff Express Pipeline, LLC (“Red Bluff Express”)30.00 %
Enterprise EF78 LLC (“Mont Belvieu JV”)25.00 %
Rendezvous Gas Services, LLC (“Rendezvous”)22.00 %
Texas Express Pipeline LLC (“TEP”)20.00 %
Texas Express Gathering LLC (“TEG”)20.00 %
Whitethorn Pipeline Company LLC (“Whitethorn LLC”)20.00 %
Saddlehorn Pipeline Company, LLC (“Saddlehorn”)20.00 %
Cactus II Pipeline LLC (“Cactus II”)15.00 %
Panola Pipeline Company, LLC (“Panola”)15.00 %
White Cliffs Pipeline, LLC (“White Cliffs”)10.00 %

(1)The 25% third-party interest in Chipeta Processing LLC (“Chipeta”) is reflected within noncontrolling interests in the consolidated financial statements. See Noncontrolling interests below.
(2)The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues, and expenses attributable to these assets.
(3)Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method of accounting. “Equity-investment throughput” refers to the Partnership’s share of average throughput for these investments.

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1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

The consolidated financial results of WES Operating are included in the Partnership’s consolidated financial statements. Throughout these notes to consolidated financial statements, and to the extent material, any differences between the consolidated financial results of the Partnership and WES Operating are discussed separately. The Partnership’s consolidated financial statements differ from those of WES Operating primarily as a result of (i) the presentation of noncontrolling interest ownership (see Noncontrolling interests below and Note 5), (ii) the elimination of WES Operating GP’s investment in WES Operating with WES Operating GP’s underlying capital account, (iii) the general and administrative expenses incurred by the Partnership, which are separate from, and in addition to, those incurred by WES Operating, (iv) the inclusion of the impact of Partnership equity balances and Partnership distributions, and (v) the senior secured revolving credit facility (“WGP RCF”) until its repayment in March 2019. See Note 13.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Presentation of the Partnership’s assets. The Partnership’s assets include assets owned and ownership interests accounted for by the Partnership under the equity method of accounting, through its 98.0% partnership interest in WES Operating as of December 31, 20192020 (see Note 107). The Partnership also owns and controls the entire non-economic general partner interest in WES Operating GP, and the Partnership’s general partner is owned by Occidental; therefore, the Partnership’s 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 the Partnership. Further, subsequent to asset acquisitions from Anadarko, the Partnership was required to recast its 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 the Partnership had owned the assets during the periods reported. Net income (loss) attributable to the assets acquired from Anadarko for periods prior to the Partnership’s acquisition of such assets was not allocated to the limited partners.

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

Noncontrolling interests. For periods subsequent to Merger completion, the Partnership’s 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, the Partnership’s 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 priorprior-period 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, and (v) the WES Operating Series A Preferred units issued to private investors as part of the funding of the Springfield acquisition, until converted into WES Operating common units in 2017.Delaware Basin Midstream, LLC (“DBM”). For all periods presented, WES Operating’s noncontrolling interest in the consolidated financial statements consistedconsists of the 25% third-party interest in Chipeta. See Note 5.
When WES Operating issues equity, the carrying amount of the noncontrolling interest reported by the Partnership is adjusted to reflect the noncontrolling ownership interest in WES Operating. The resulting impact of such noncontrolling interest adjustment on the Partnership’s interest in WES Operating is reflected as an adjustment to the Partnership’s partners’ capital.

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Shutdown of gathering systems.
 In May 2018, after assessing a number of factors, and with safety and protection of the environment as the primary focus, the Partnership decided to permanently cease operations at the Kitty Draw gathering system in Wyoming (part of the Hilight system) and the Third Creek gathering system in Colorado (part of the DJ Basin complex). Results for the year ended December 31, 2018, reflect (i) an accrual of $10.9 million in anticipated costs associated with the system shutdowns, recorded as a reduction in affiliate Product sales in the consolidated statements of operations, and (ii) impairment expense of $134.0 million associated with reducing the net book value of the gathering systems and recording an additional asset retirement obligation. During the year ended December 31, 2019, $6.1 million of the accrual related to the Kitty Draw gathering system shutdown was reversed due to producer settlements being less than initial estimates.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)AND BASIS OF PRESENTATION

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

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

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

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

In determining fair value, management uses observable market data when available, or models that incorporate observable market data. When a fair value measurement is required and there is not a market-observable price for the asset or liability or a market-observable price for a similar asset or liability, the cost, income, or multiplesmarket approach is used, depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach uses management’s best assumptions regarding expectations of projected cash flows and discounts the expected cash flows using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment because results are based on expected future events or conditions, such as sales prices,contractual rates, estimates of future throughput, capital and operating costs and the timing thereof, economic and regulatory climates, and other factors. A multiplesThe market approach uses management’s best assumptions regarding expectations of projected earnings before interest, taxes, depreciation, and amortization (“EBITDA”) and an assumed multiple of that EBITDA that a willing buyer would pay to acquire an asset. Management’s estimates of future net cash flows and EBITDA are inherently imprecise because they reflect management’s expectation of future conditions that are often outside of management’s control. However, the assumptions used reflect a market participant’s view of long-term prices,revenues, costs, and other factors, and are consistent with assumptions used in the Partnership’s business plans and investment decisions.
Management uses relevant observable inputs available for the valuation technique employed to estimate fair value. If a fair-value measurement reflects inputs at multiple levels within the hierarchy, the fair-value measurement is characterized based on the lowest level of input that is significant to the fair-value measurement. Non-financial assets and liabilities initially measured at fair value include certain assets and liabilities acquired in a third-party business combination, assets and liabilities exchanged in non-monetary transactions, goodwill and other intangibles, initial recognitionmeasurement of asset retirement obligations, and initial recognitionmeasurement of environmental obligations assumed in a third-party acquisition. Impairment analyses for long-lived assets, goodwill, and other intangibles,equity investments, and the initial recognition of asset retirement obligations and environmental obligations use Level-3 inputs.
The fair value of debt reflects any premium or discount for the difference between the stated interest rate and the quarter-end market interest rate and is based on quoted market prices for identical instruments, if available, or based on valuations of similar debt instruments. See Note 13.
The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable reported on the consolidated balance sheets approximate fair value due to the short-term nature of these items.

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



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1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

AND BASIS OF PRESENTATION
Allowance
Credit losses. Accounts receivable represent contractual rights for uncollectible accounts. services performed, with, on average, 30-day payment terms from the invoice date. Contract assets primarily relate to revenue accrued but not yet billed under cost-of-service contracts and accrued deficiency fees. Exposure to bad debtscredit losses is analyzed onwithin collective pools for all of our customers and, if necessary, individual customers may be analyzed separately if their credit quality becomes a customer-by-customer basis for affiliate and third-party accounts receivableconcern. The Partnership monitors credit exposure to all customers to ensure exposures are within established credit limits.
As of December 31, 2020, there have been no negative indications regarding the collectability of significant receivables as it relates to impacts from the global outbreak of the coronavirus (“COVID-19”) and the oil-market disruption resulting from significantly lower global demand and corresponding oversupply of crude oil. The Partnership may establishwill continue to monitor the credit limits for significant affiliatequality of its customer base and third-party customers.assess collectability of these assets as appropriate. The allowance for uncollectible accountsexpected credit losses was immaterial at December 31, 20192020 and 2018.2019.

Imbalances. The consolidated balance sheets include imbalance receivables and payables resulting from differences in volumes received into the Partnership’s systems and volumes delivered by the Partnership to customers. Volumes owed to or by the Partnership that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates and reflect market index prices. Other volumes owed to or by the Partnership are valued at the Partnership’s weighted-average cost as of the balance sheet dates and are settled in-kind. As of December 31, 2020, imbalance receivables and payables were $13.0 million and $3.3 million, respectively. As of December 31, 2019, imbalance receivables and payables were $4.7 million and $2.7 million, respectively. As of December 31, 2018, imbalance receivables and payables were $9.0 million and $9.6 million, respectively. Net changes in imbalance receivables and payables are reported in Cost of product in the consolidated statements of operations.

Inventory. The cost of NGLs inventoriesinventory is determined by the weighted-average cost method on a location-by-location basis. Inventory is stated at the lower of weighted-average cost or net realizable value. NGLs inventory is reported in Other current assets and NGLs line-fill inventory and NGLs inventory areis reported in Other assets on the consolidated balance sheets. Materials and supplies inventory is valued at weighted-average cost, reviewed periodically for obsolescence, and assessed for impairment together with any associated property, plant, and equipment and other intangible assets. Beginning with the second quarter of 2020, materials and supplies inventory, previously reported in Other current assets, respectively,is prospectively reported in Other assets on the consolidated balance sheets. See Note 11.

Property, plant, and equipment.equipment and other intangible assets. Property, plant, and equipment generally isand other intangible assets are stated at the lower of historical cost less accumulated depreciation or amortization, or fair value if impaired. Because prior long-lived asset acquisitions of assets from Anadarko were transfers of net assets between entities under common control, the assets acquired were initially were recorded at Anadarko’s historic carrying value. The difference between the carrying value of net assets acquired from Anadarko and the consideration paid has been recorded as an adjustment to partners’ capital.
Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value.
All construction-related direct labor and material costs are capitalized. The cost of renewals and betterments that extend the useful life of property, plant, and equipment is also capitalized. The cost of repairs, replacements, and major maintenance projects that do not extend the useful life or increase the expected output of property, plant, and equipment is expensed as incurred.
Depreciation is computed using the straight-line method based on estimated useful lives and salvage values of assets. However, subsequentSubsequent events could cause a change in estimates of remaining useful lives or salvage value, thereby impacting future depreciation amounts. Uncertainties that may impact these estimates include, but are not limited to, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions, and supply and demand in the area.
Management evaluates the ability to recover the carrying amount
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Table of its long-lived assets to determine whether its long-lived assets have been impaired. Impairments exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense. Refer to Note 8 for a description of impairments recorded during the years ended December 31, 2019, 2018, and 2017.Contents


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

AND BASIS OF PRESENTATION
Insurance recoveries.
Management assesses property, plant, and equipment together with any associated materials and supplies inventory and intangible assets, as described in Involuntary conversions resultNote 10, for impairment when events or changes in circumstances indicate their carrying values may not be recoverable. Impairments exist when the carrying value of a long-lived asset exceeds the total estimated undiscounted net cash flows from the lossfuture 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. If an asset because of unforeseen events (e.g., destruction due to fire). Some of these events are insurable and result in property damage insurance recovery. Amounts that are received from insurance carriers are net of any deductibles related to the covered event. A receivable is recorded from insurance to the extent aimpairment exists, an impairment loss is recognized from an involuntary conversion event andmeasured as the likelihood of recovering such loss is deemed probable. To the extent that any insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. A gain on involuntary conversion is recognized when the amount received from insurance exceeds the net book valueexcess of the retired asset(s). In addition, gains relatedasset’s carrying value over its estimated fair value, such that the asset’s carrying value is adjusted down to insurance recoveries are not recognized until all contingencies relatedits estimated fair value with an offsetting charge to such proceeds have been resolved; that is,Long-lived asset and other impairments. Refer to Note 9 for a cash payment is received fromdescription of impairments recorded during the insurance carrier or there is a binding settlement agreement with the carrier that clearly states that a payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, on the consolidated balance sheets and presented as Capital expenditures in the consolidated statements of cash flows. With respect to business interruption insurance claims, income is recognized only when cash proceeds are received from insurers, which are presented in the consolidated statements of operations as a component of Operating income (loss).
In December 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. The majority of the damage from the incident was to the liquid-handling facilities and the amine-treating units at the inlet of the complex. During the yearyears ended December 31, 2017, a $5.7 million loss was recorded in Gain (loss) on divestiture2020, 2019, and other, net in the consolidated statements of operations, related to a change in the Partnership’s estimate of the amount that would be recovered under the property insurance claim based on continued discussions with insurers. During the second quarter of 2017, the Partnership reached a settlement with insurers and final proceeds were received. During the year ended December 31, 2017, the Partnership received $52.9 million in cash proceeds from insurers, including $29.9 million in proceeds from business interruption insurance claims and $23.0 million in proceeds from property insurance claims.2018.

Capitalized interest. Interest is capitalized as part of the historical cost of constructing assets that are in progress. Capitalized interest is determined by multiplying the Partnership’s weighted-average borrowing cost on debt by the average amount of assets under construction. Once construction of an asset subject toCumulative capitalized interest capitalization is substantially complete,accrued during the associated capitalized interestyear is expensed through depreciation or impairment.

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

Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. In addition, goodwill represents the allocated historic carrying value of midstream goodwill attributed to the Partnership’s assets previously acquired from Anadarko. The Partnership hashad allocated goodwill on its two reporting units: (i) gathering and processing and (ii) transportation. Goodwill is evaluated 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. If management concludes, based on qualitative factors, that it is more likely than not that the fair value of the reporting unit exceeds its carrying amount,value, then no goodwill impairment is recorded and further testing is not necessary. If an assessment of qualitative factors does not result in management’s determination that the fair value of the reporting unit more likely than not exceeds its carrying amount,value, then a quantitative assessment must be performed. If the quantitative assessment indicates that the carrying amountvalue 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 through a charge to Goodwill impairment. The Partnership recognized a goodwill impairment expense.of $441.0 million during the first quarter of 2020, which reduced the carrying value of goodwill to 0 for the gathering and processing reporting unit. See Note 910.

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


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

Environmental expenditures. The Partnership expensesis subject to various environmental-remediation obligations arising from federal, state, and local laws and regulations. Losses associated with environmental obligations related to conditions caused by past operations that do not generate current or future revenues. Environmental obligations related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recordedaccrued when the necessity for environmental remediation or other potential environmental liabilities becomes probable and the costs can be reasonably estimated.estimated, with the exception of environmental obligations acquired in a business combination, which are recorded at fair value at the time of acquisition. Accruals for estimated losses from environmental-remediation obligations are recognized no later than at the time of the completion of the remediation feasibility study.study or when the evaluation of response options is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Costs of future expenditures for environmental-remediation obligations are not discounted to their present value. See Note 15.16.

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

Revenue and cost of product. On January 1, 2018, the Partnership adopted Revenue from Contracts with Customers (Topic 606) (“Topic 606”)and changed its accounting policy for revenue recognition as described below.The 2017 financial information was not adjusted and is reported under Revenue Recognition (Topic 605).
The Partnership provides gathering, processing, treating, transportation, and disposal services pursuant to a variety of contracts. Under these arrangements, the Partnership receives fees and/or retains a percentage of products or a percentage of the proceeds from the sale of the customer’s products. These revenues are included in Service revenues and Product sales in the consolidated statements of operations. Payment is generally received from the customer in the month following the service or delivery of the product. Contracts with customers generally have initial terms ranging from 5 to 10 years.
Service revenues – fee based is recognized for fee-based contracts in the month of service based on the volumes delivered by the customer. Producers’ wells or production facilities are connected to the Partnership’s gathering systems for gathering, processing, treating, transportation, and disposal of natural gas, NGLs, condensate, crude oil, and produced water, as applicable. Revenues are valued based on the rate in effect for the month of service when the fee is either the same per-unit rate over the contract term or when the fee escalates and the escalation factor approximates inflation. Deficiency fees charged to customers that do not meet their minimum delivery requirements are recognized as services are performed based on an estimate of the fees that will be billed at the completion of the performance period. Because of its significant upfront capital investment, the Partnership may charge additional service fees to customers for only a portion of the contract term (i.e., for the first year of a contract or until reaching a volume threshold), and these fees are recognized as revenue over the expected period of customer benefit, which is generally the life of the related properties. TheTiming differences between amounts recognized in Service revenues – fee based and the amounts billed to customer are recognized as contract assets or contract liabilities, and are amortized over the related contract period. Prior to April 1, 2020, the Partnership also recognizesrecognized revenue and cost of product expense from marketing services performed on behalf of its customers by Occidental. Effective April 1, 2020, changes to marketing-contract terms with Occidental terminated Occidental’s prior status as an agent of the Partnership for third-party sales and established Occidental as a customer of the Partnership. Accordingly, the Partnership no longer recognizes revenue and the equivalent cost of product expense for the marketing services performed by Occidental. See Note 6.
    

WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

The Partnership also receives Service revenues – fee based from contracts that have minimum-volume commitment demand fees and fees that require periodic rate redeterminations based 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.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 the Partnership 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.
Service revenues – product based includes service revenues from percent-of-proceeds gathering and processing contracts that are recognized net of the cost of product for purchases from the Partnership’s customers since it is acting as the agent in the product sale. Keep-whole and percent-of-product agreements result in Service revenues – product based being recognized when the natural gas and/or NGLs are received from the customer as non-cash consideration for the services provided. Non-cash consideration for these services is valued at the time the services are provided. Revenue from productis also recognized in Product sales, also is recognized, along with the cost of product expense related to the sale, when the product received as non-cash consideration is sold to either Occidental or a third party. When the product is sold to Occidental, Occidental is acting as the Partnership’s agent in the product sale, with the Partnership recognizing revenue and related cost
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Table of product expense associated with these marketing activities based on the Occidental sales price to the third party.Contents

WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

The Partnership also purchases natural-gas volumes from producers at the wellhead or from a production facility, typically at an index price, and charges the producer fees associated with the downstream gathering and processing services. When the fees relate to services performed after control of the product has transferred to the Partnership, the fees are treated as a reduction of the purchase cost. If the fees relate to services performed before control of the product has transferred to the Partnership, the fees are treated as Service revenues – fee based. Product sales revenue is recognized, along with cost of product expense related to the sale, when the purchased product is sold to either Occidental or a third party.
The Partnership receives aid-in-construction reimbursements for certain capital costs necessary to provide services to customers (i.e., connection costs, etc.) under certain service contracts. Aid-in-construction reimbursements are reflected as a contract liability aswhen received and are amortized to Service revenues – fee based over the expected period of customer benefit, which is generally the life of the related properties.

Equity-based compensation.Defined-contribution plan. The general partner awards phantom units underBeginning in the first quarter of 2020, employees of the Partnership are eligible to participate in the Western Gas Partners, LP 2017 Long-Term IncentiveMidstream Savings Plan, (assumeda defined-contribution benefit plan maintained by the Partnership. All regular employees may participate in the plan by making elective contributions that are matched by the Partnership, in connection withsubject to certain limitations. The Partnership also makes other contributions based on plan guidelines. The Partnership recognized expense related to the Merger) and the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan to its independent directors, executive officers, and Occidental employees performing servicesplan of $12.5 million for the Partnership from time to time. As ofyear ended December 31, 2019, the Western Gas Partners, LP 2017 Long-Term Incentive Plan and the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan had 3,419,020 and 2,911,985 units, respectively, available for future issuance. At vesting, each phantom unit under the Western Gas Partners, LP 2017 Long-Term Incentive Plan or the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan, the holder will receive common units of the Partnership, or, at the discretion of the general partner’s Board of Directors (the “Board of Directors”), cash in an amount equal to the market value of the common units on the vesting date. Equity-based compensation expense attributable to grants made under the plans impacts cash flows from operating activities only to the extent cash payments are made to a participant in lieu of issuance of the common units to the participant. Equity-based compensation expense attributable to awards granted under the plans is amortized over the vesting periods applicable to the awards.2020.
Additionally, general and administrative expense includes equity-based compensation expense allocated to the Partnership by Occidental for awards granted to the executive officers of the general partner and to other employees under (i) the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as amended and restated, (ii) Occidental’s 2015 Long-Term Incentive Plan, and (iii) Occidental’s Phantom Share Unit Award Plan. Grants made under equity-based compensation plans result in equity-based compensation expense, which is determined by reference to the fair value of equity compensation. For equity-based awards ultimately settled through the issuance of units or stock, the fair value is measured as of the date of the relevant equity grant. Portions of these amounts are reflected as contributions to partners’ capital in the consolidated statements of equity and partners’ capital. Any unrecognized compensation expense attributable to these plans is allocated to the Partnership over a weighted-average period applicable to the awards. See
Note 6.

WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Partnership income taxes. Deferred federal and state income taxes included in the accompanying consolidated financial statements are attributable to temporary differences between the financial statement carrying amount and tax basis of the Partnership’s investment in WES Operating. The Partnership’s accounting policy is to “look through” its investment in WES Operating for purposes of calculating deferred income tax asset and liability balances attributable to the Partnership’s interests in WES Operating. The application of such accounting policy resulted in no deferred income taxes being recognized for the book and tax basis difference in goodwill, which is non-deductible for tax purposes for all periods presented. The Partnership had no material uncertain tax positions at December 31, 20192020 or 2018.2019.

WES Operating income taxes. WES Operating generally is not subject to federal income tax or state income tax other than Texas margin tax on the portion of its income that is apportionable to Texas. Deferred state income taxes are recorded on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. WES Operating routinely assesses the realizability of its deferred tax assets. If WES Operating concludes that it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by recording a valuation allowance.
With respect to assets previously acquired from Anadarko, WES Operating recorded Anadarko’s historic federal and state current and deferred income taxes for the periods prior to the acquisition of such assets. For periods on and subsequent to the acquisition, WES Operating is not subject to tax except for the Texas margin tax and, accordingly, does not record deferred federal income taxes related to the acquired assets.
For periods beginning on and subsequent to the acquisition of assets from Anadarko, WES Operating made payments to Anadarko pursuant to the tax sharing agreement for its estimated share of taxes from all forms of taxation, excluding income taxes imposed by the United States, that are included in any combined or consolidated returns filed by Occidental. The aggregate difference in the basis of WES Operating’s assets for financial and tax reporting purposes cannot be readily determined as WES Operating does not have access to information about each partner’s tax attributes in WES Operating.
The accounting standards for uncertain tax positions defines the criteria an individual tax position must satisfy for any part of the benefit of that position to be recognized in the financial statements. WES Operating had no material uncertain tax positions at December 31, 20192020 or 2018.2019.
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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION

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

WES Operating’s net income (loss) per common unit. For periods subsequent to the closing of the Merger, net income (loss) per common unit for WES Operating is not calculated as itbecause no longer has publicly traded units.units remained outstanding. For periods prior to the closing of the Merger, WES Operating applied the two-class method in determining net income (loss) per unit applicable to master limited partnerships having multiple classes of securities, including common units, Class C units, general partner units, and IDRs. See Note 5.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Recently adopted accounting standards. ASU 2016-02, Leases (Topic 842) requires lessee recognition of a lease liability and a right-of-use (“ROU”) asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation, and disclosure of leasing arrangements by lessees and lessors. The Partnership adopted this standard on January 1, 2019, using the modified retrospective method applied to all leases in existence on January 1, 2019, and prior-period financial statements were not adjusted. The Partnership elected not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for existing or expired land easements, and not to recognize ROU assets or lease liabilities for short-term leases.

Leases. The Partnership determines if an arrangement is a lease based on the rights and obligations conveyed at contract inception. Significant judgment is required when determining whether a customer obtains the right to direct the use of identified property or equipment.
When the Partnership is a lessee at the lease-commencement date, a lease is classified as either operating or finance, and ROUright-of-use (“ROU”) assets and lease liabilities are recognized based on the present value of future lease payments over the lease term. As the rate implicit in the Partnership’s leases is generally not readily determinable, the Partnership discounts lease liabilities using the Partnership’s incremental borrowing rate at the commencement date. Non-lease components associated with leases that begin in 2019 or later are accounted for as part of the lease component, and prepaid lease payments are included as ROU assets. Options to extend or terminate a lease are included in the lease term when it is reasonably certain that the Partnership will exercise that option. Leases of 12 months or less are not recognized on the consolidated balance sheets. Lease cost is generally recognized on a straight-line basis over the lease term. For finance leases, interest expense is recognized over the lease term using the effective interest method. Variable lease payments are recognized when the obligation for those payments is incurred.
When the Partnership is a lessor at the lease-commencement date, a lease is classified as operating, sales-type, or direct financing. The underlying assets associated with these agreements are evaluated for future use beyond the lease term. For operating leases, lease income is generally recognized on a straight-line basis over the lease term. Variable lease payments are recognized when the obligation for those payments is performed. The Partnership does not have sales-type or direct financing leases.

Recently adopted accounting standards. Accounting Standards Update (“ASU”) 2016-13, Financial Instruments - Credit Losses (Topic 326) significantly changes the accounting and disclosure requirements related to credit losses on financial assets. Under the new standard, entities are now required to estimate lifetime expected credit losses for trade receivables, loans, and other financial instruments as of the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts, resulting in earlier recognition of credit losses. There was no impact to the consolidated financial statements with the Partnership’s adoption of the standard on January 1, 2020. The Partnership has implemented the necessary changes to its processes and controls to support accounting and disclosure requirements under this ASU.
2. REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table summarizes revenue from contracts with customers:
  Year Ended December 31,
thousands 2019 2018
Revenue from customers    
Service revenues – fee based $2,388,191
 $1,905,728
Service revenues – product based 70,127
 88,785
Product sales 287,055
 310,895
Total revenue from customers 2,745,373
 2,305,408
Revenue from other than customers    
Net gains (losses) on commodity-price swap agreements (667) (7,875)
Other 1,468
 2,125
Total revenues and other $2,746,174
 $2,299,658
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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


2. REVENUE FROM CONTRACTS WITH CUSTOMERS (CONTINUED)

The following table summarizes revenue from contracts with customers:
Year Ended December 31,
thousands202020192018
Revenue from customers
Service revenues – fee based$2,360,680 $2,388,191 $1,905,728 
Service revenues – product based48,369 70,127 88,785 
Product sales138,559 287,055 310,895 
Total revenue from customers2,547,608 2,745,3732,305,408
Revenue from other than customers
Lease revenue (1)
223,643 0 0 
Net gains (losses) on commodity-price swap agreements0 (667)(7,875)
Other1,341 1,468 2,125 
Total revenues and other$2,772,592 $2,746,174 $2,299,658 

(1)For the year ended December 31, 2020, includes fixed- and variable-lease revenue from an operating and maintenance agreement entered into with Occidental. See Operating lease within Note 6.

Certain of the Partnership’s midstream services contracts have minimum-volume commitment demand fees and fees that require periodic rate redeterminations based on the related facility cost-of-service rate provisions (see Note 1). During the year ended December 31, 2020, the Partnership constrained revenue under one of its 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.

Contract balances. Receivables from customers, which are included in Accounts receivable, net on the consolidated balance sheets were $362.6$428.2 million and $214.3$362.6 million as of December 31, 20192020 and 2018,2019, respectively.
Contract assets primarily relate to revenue accrued but not yet billed under cost-of-service contracts with fixed and variable fees and accrued deficiency fees the Partnership expects to charge customers once the related performance periods are completed and revenue accrued but not yet billed under cost-of-service contracts with fixed and variable fees.completed. The following table summarizes current-period activity related to contract assets from contracts with customers:
Year Ended December 31,
thousands20202019
Contract assets balance at beginning of year$67,357 $47,621 
Amounts transferred to Accounts receivable, net that were included in the contract assets balance at the beginning of the period
(7,129)(4,841)
Additional estimated revenues recognized3,877 14,698 
Cumulative catch-up adjustment for change in estimated consideration due to an annual cost-of-service rate update(7,761)9,879 
Contract assets balance at end of year$56,344 $67,357 
December 31,
thousands20202019
Other current assets$5,338 $7,129 
Other assets51,006 60,228 
Total contract assets from contracts with customers$56,344 $67,357 
thousands  
Balance at December 31, 2018 $47,621
Amounts transferred to Accounts receivable, net that were included in the contract assets balance at the beginning of the period (4,841)
Additional estimated revenues recognized 14,698
Cumulative catch-up adjustment for change in estimated consideration due to an annual cost-of-service rate update 9,879
Balance at December 31, 2019 $67,357
   
Contract assets at December 31, 2019  
Other current assets $7,129
Other assets 60,228
Total contract assets from contracts with customers $67,357

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. REVENUE FROM CONTRACTS WITH CUSTOMERS

Contract liabilities primarily relate to (i) fees that are charged to customers for only a portion of the contract term and must be recognized as revenues over the expected period of customer benefit, (ii) fixed and variable fees under cost-of-service contracts that are received from customers for which revenue recognition is deferred, and (iii) aid-in-construction payments received from customers that must be recognized over the expected period of customer benefit. The following table summarizes current-period activity related to contract liabilities from contracts with customers:
Year Ended December 31,
thousands20202019
Contract liabilities balance at beginning of year$222,274 $145,624 
Cash received or receivable, excluding revenues recognized during the period65,215 75,166 
Revenues recognized that were included in the contract liability balance at the beginning of the period
(13,842)(12,110)
Cumulative catch-up adjustment for change in estimated consideration due to an annual cost-of-service rate update(6,710)13,594 
Contract liabilities balance at end of year$266,937 $222,274 
December 31,
thousands20202019
Accrued liabilities$31,477 $19,659 
Other liabilities235,460 202,615 
Total contract liabilities from contracts with customers$266,937 $222,274 
thousands  
Balance at December 31, 2018 $145,624
Cash received or receivable, excluding revenues recognized during the period 75,166
Revenues recognized that were included in the contract liability balance at the beginning of the period (12,110)
Cumulative catch-up adjustment for change in estimated consideration due to an annual cost-of-service rate update 13,594
Balance at December 31, 2019 $222,274
   
Contract liabilities at December 31, 2019  
Accrued liabilities $19,659
Other liabilities 202,615
Total contract liabilities from contracts with customers $222,274



WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


2. REVENUE FROM CONTRACTS WITH CUSTOMERS (CONTINUED)

Transaction price allocated to remaining performance obligations. Revenues expected to be recognized from certain performance obligations that are unsatisfied (or partially unsatisfied) as of December 31, 2019,2020, are presented in the following table. The Partnership applies the optional exemptions in Topic 606Revenue from Contracts with Customers (Topic 606) and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied (or partially unsatisfied) performance obligations. Therefore, the following table represents only a portion of expected future revenues from existing contracts as most future revenues from customers are dependent on future variable customer volumes and, in some cases, variable commodity prices for those volumes.
thousands
2021$792,553 
20221,048,087 
2023993,059 
2024964,179 
2025882,461 
Thereafter2,698,435 
Total$7,378,774 
thousands  
2020 $736,055
2021 776,068
2022 1,030,527
2023 973,799
2024 943,514
Thereafter 3,534,725
Total $7,994,688


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3. ACQUISITIONS AND DIVESTITURES

AMA acquisition.
In February 2019, WES Operating acquired the following assets from Anadarko (see Note 1), which collectively are referred to as the Anadarko Midstream Assets (“AMA”):

•
Wattenberg processing plant. The Wattenberg processing plant consists of a cryogenic train (with capacity of 190 million cubic feet per day (“MMcf/d”)) and a refrigeration train (with capacity of 80 MMcf/d) located in Adams County, Colorado, now part of the DJ Basin complex.

•
Wamsutter pipeline. The Wamsutter pipeline is a crude-oil gathering pipeline located in Sweetwater County, Wyoming and delivers crude oil into MPLX LP’s SLC Core Pipeline System (formerly referred to as the Wamsutter Pipeline System).

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

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

•
APC water systems. The APC water systems consist of five produced-water disposal systems with total capacity of 565 MBbls/d, located in Reeves, Loving, and Ward Counties, Texas, which are now part of the DBM water systems. One produced-water disposal system commenced operations in 2017 and the other four commenced operations in 2018.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


3. ACQUISITIONS AND DIVESTITURES (CONTINUED)

•
A 20% interest in Saddlehorn.
AMA acquisition. In February 2019, WES Operating acquired AMA from Anadarko, which is comprised of (i) the DJ Basin oil system and Wattenberg processing plant located in the DJ Basin; (ii) the DBM oil system, APC water systems, a 50% interest in Mi Vida, and a 50% interest in Ranch Westex, located in West Texas; (iii) the Wamsutter pipeline located in Wyoming; (iv) a 20% interest in Saddlehorn, a crude-oil and condensate pipeline that originates in Laramie County, Wyoming and terminates in Cushing, Oklahoma; and (v) a 15% interest in Panola, an NGLs pipeline that originates in Panola County, Texas, and terminates in Mont Belvieu, Texas. AMA was acquired in exchange for aggregate consideration of $2.0 billion of cash, less the outstanding amount payable pursuant to an intercompany note (the “APCWH Note Payable”) assumed by WES Operating in connection with the transfer, and 45,760,201 WES Operating common units. These WES Operating common units, less 6,375,284 WES Operating common units retained by WGR Asset Holding Company LLC (“WGRAH”), converted into the right to receive common units of the Partnership at Merger completion.

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

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

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

•
A 50% interest in Ranch Westex. Ranch Westex owns a processing plant consisting of a cryogenic train (with capacity of 100 MMcf/d) and a refrigeration train (with capacity of 25 MMcf/d), located in Ward County, Texas. The interest in Ranch Westex is accounted for under the equity method of accounting and the processing plant is operated by a third party.

Red Bluff Express acquisition. In January 2019, the Partnership acquired a 30% interest in Red Bluff Express, which owns a third-party-operated natural-gas pipeline operated by a third party that connectsconnecting processing plants in Reeves and Loving Counties, Texas, to the WAHA hub in Pecos County, Texas. The Partnership acquired its 30% interest from a third party via an initial net investment of $92.5 million, which represented itsa 30% share of costs incurred up to the date of acquisition. The initial investment was funded with cash on hand and the interest in Red Bluff Express is accounted for under the equity method of accounting. See Note 107.

Whitethorn LLC acquisition. In June 2018, the Partnership acquired a 20% interest in Whitethorn LLC, which owns a crude-oil and condensate pipeline that originates in Midland, Texas, and terminates in Sealy, Texas (the “Midland-to-Sealy pipeline”) and related storage facilities (collectively referred to as “Whitethorn”). A third party operates Whitethorn and oversees the related commercial activities. In connection with its investment in Whitethorn LLC, the Partnership shares proportionally in the commercial activities. The Partnership acquired its 20% interest via a $150.6 million net investment, which was funded with cash on hand and is accounted for under the equity method.method of accounting. See Note 107.

Cactus II acquisition. In June 2018, the Partnership acquired a 15% interest in Cactus II, which owns a crude-oil pipeline operated by a third party (the “Cactus II pipeline”) connecting West Texas to the Corpus Christi area. The Cactus II pipeline began delivering crude oil during the third quarter of 2019 and is expected to becomebecame fully operational in the first quarter of 2020. The Partnership acquired its 15% interest from a third party via an initial net investment of $12.1 million, which represented its share of costs incurred up to the date of acquisition. The initial investment was funded with cash on hand, and the interest in Cactus II is accounted for under the equity method of accounting. See Note 107.

Property exchange.Fort Union and Bison facilities. In March 2017,October 2020, the Partnership acquired an additional 50%(i) sold its 14.81% interest in the Delaware Basin JVFort Union Gas Gathering, LLC (“DBJV”Fort Union”) system (the “Additional DBJV System Interest”) from, 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, in exchange for (a)exercisable during the Partnership’s 33.75% non-operated interest in two natural-gas gathering systems located in northern Pennsylvania (the “Non-Operated Marcellus Interest”), commonly referred to as the Liberty and Rome systems, and (b) $155.0 millionfirst quarter of cash consideration (collectively, the “Property Exchange”).2021. The Partnership previously held a 50% interest in, and operated, the DBJV system.
The Property Exchange was accounted for as a non-monetary transaction whereby the acquired Additional DBJV System Interest was recorded at the fair valuereceived combined proceeds of the divested Non-Operated Marcellus Interest plus the $155.0$27.0 million, of cash consideration. The Property Exchange resultedresulting in a net gain on sale of $125.7$21.0 million related to the Fort Union interest that was recorded in the fourth quarter of 2020 as Gain (loss) on divestiture and other, net in the consolidated statements of operations. Results of operations attributableA gain related to the Property Exchange were included inoption agreement and potential sale of the consolidated statements of operations beginning on the acquisition dateBison treating facility will be recognized in the first quarter of 2017.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


3. ACQUISITIONS AND DIVESTITURES (CONTINUED)

2021 if the option is exercised or expires.
DBJV acquisition - Deferred purchase price obligation - Anadarko.
 Prior to WES Operating’s agreement with Anadarko to settle the deferred purchase price obligation early, the consideration that would have been paid for the March 2015 acquisition of DBJV from Anadarko consisted of a cash payment to Anadarko due on March 31, 2020. In May 2017, WES Operating reached an agreement with Anadarko to settle this obligation with a cash payment to Anadarko of $37.3 million, which was equal to the estimated net present value of the obligation at March 31, 2017.

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

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

WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. PARTNERSHIP DISTRIBUTIONS

Partnership distributions. TheUnder its partnership agreement, requires the Partnership to distributedistributes all of its available cash (as(beyond proper reserves as defined in its partnership agreement) to unitholders of record on the applicable record date within 55 days following each quarter’s end. The Board of Directors of the general partner (the “Board of Directors”) declared the following cash distributions to the Partnership’s unitholders for the periods presented:
thousands except per-unit amounts
Quarters Ended
Total Quarterly
Per-unit
Distribution		Total Quarterly
Cash Distribution		Distribution
Date
2018 (1)
March 31$0.56875 $124,518 May 2018
June 300.58250 127,531 August 2018
September 300.59500 130,268 November 2018
December 310.60250 131,910 February 2019
2019
March 31$0.61000 $276,324 May 2019
June 300.61800 279,959 August 2019
September 300.62000 280,880 November 2019
December 310.62200 281,786 February 2020
2020
March 31$0.31100 $140,893 May 2020
June 300.31100 140,900 August 2020
September 300.31100 132,255 November 2020
December 31 (2)
0.31100 131,265 February 2021

(1)The 2018 distributions were declared and paid prior to the closing of the Merger.
thousands except per-unit amounts
Quarters Ended
 Total Quarterly
Per-unit
Distribution		 Total Quarterly
Cash Distribution		 Distribution
Date
2017 (1)
      
March 31 $0.49125
 $107,549
 May 2017
June 30 0.52750
 115,487
 August 2017
September 30 0.53750
 117,677
 November 2017
December 31 0.54875
 120,140
 February 2018
2018 (1)
      
March 31 $0.56875
 $124,518
 May 2018
June 30 0.58250
 127,531
 August 2018
September 30 0.59500
 130,268
 November 2018
December 31 0.60250
 131,910
 February 2019
2019      
March 31 $0.61000
 $276,324
 May 2019
June 30 0.61800
 279,959
 August 2019
September 30 0.62000
 280,880
 November 2019
December 31 (2)
 0.62200
 281,786
 February 2020
(2)The Board of Directors declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2020 of $0.31100 per unit, or $131.3 million in aggregate. The cash distribution was paid on February 12, 2021 to unitholders of record at the close of business on February 1, 2021, including the general partner units that were issued on December 31, 2019 (see Note 1).
(1)
The 2017 and 2018 distributions were declared and paid prior to the closing of the Merger.
(2)
The Board of Directors declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2019 of $0.62200 per unit, or $281.8 million in aggregate. The cash distribution was paid on February 13, 2020, to unitholders of record at the close of business on January 31, 2020, including the general partner units that were issued on December 31, 2019 (see Note 1).

Following the transactions contemplated by the Exchange Agreement, the general partner isunits are entitled to 2.0% of all quarterly distributions beginning with the cash distribution declared for the fourth quarter of 2019.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


4. PARTNERSHIP DISTRIBUTIONS (CONTINUED)

Available cash. The amount of available cash (as(beyond proper reserves as defined in theour partnership agreement) generally is all cash on hand at the end of the quarter, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such quarter, less the amount of cash reserves established by the general partner to provide for the proper conduct of the Partnership’s business, including reserves to fund future capital expenditures; to comply with applicable laws, debt instruments, or other agreements; or to provide funds for 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. Working capital borrowings generallyarrangement 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.

WES Operating partnership distributions. For the below-presented periods, WES Operating paid the cash distributions to WES Operating’s common and general partner unitholders as follows:
thousands except per-unit amounts
Quarters Ended
 Total Quarterly
Per-unit
Distribution		 Total Quarterly
Cash Distribution		 Distribution
Date
2017      
March 31 $0.875
 $188,753
 May 2017
June 30 0.890
 207,491
 August 2017
September 30 0.905
 212,038
 November 2017
December 31 0.920
 216,586
 February 2018
2018      
March 31 $0.935
 $221,133
 May 2018
June 30 0.950
 225,691
 August 2018
September 30 0.965
 230,239
 November 2018
December 31 0.980
 234,787
 February 2019


Immediately prior to the closing of the Merger, the WES Operating IDRsincentive distribution rights (“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 the Partnership, WES Operating GP, and 6.4 million common units held by a subsidiary of Anadarko) were converted into common units of the Partnership. Beginning with the first quarter of 2019, WES Operating makes quarterly cash distributions to the Partnership and WGRAH, a subsidiary of Occidental, in respect ofproportion to their proportionate share of limited partner interests in WES Operating. For the quarters ended March 31, 2019, June 30, 2019, and September 30, 2019 WES Operating distributed $283.3 million, $288.1 million, and $289.7 million, respectively, to its limited partners. For the quarter ended December 31, 2019, WES Operating distributed $290.3 million to its limited partners. See Note 5.
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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. PARTNERSHIP DISTRIBUTIONS

WES Operating paid the following cash distributions to its limited partners for the periods presented:
thousands
Quarters Ended
Total Quarterly
Cash Distribution
2019
March 31$283,271 
June 30288,083 
September 30289,676 
December 31290,314 
2020
March 31$143,404
June 30143,404
September 30143,404
December 31127,470

Prior to the closing of the Merger, WES Operating paid the following cash distributions to WES Operating’s common and general partner unitholders for the periods presented:
thousands except per-unit amounts
Quarters Ended
Total Quarterly
Per-unit
Distribution		Total Quarterly
Cash Distribution		Distribution
Date
2018
March 31$0.935 $221,133 May 2018
June 300.950 225,691 August 2018
September 300.965 230,239 November 2018
December 310.980 234,787 February 2019

WES Operating Class C unit distributions. Prior to the closing of the Merger, WES Operating’s Class C units received quarterly distributions at an equivalent rate to WES Operating’s publicly traded common units. The Class C unit distributions were paid-in-kind with additional Class C Units (“PIK Class C units”) and were disregarded with respect to WES Operating’s distributions of available cash. The number of PIK Class C units issued in connection with a distribution payable on the Class C units was determined by dividing the corresponding distribution attributable to the Class C units by the volume-weighted average price of WES Operating’s common units for the ten days immediately preceding the payment date of the common unit distribution, less a 6% discount. WES Operating recorded the PIK Class C unit distributions at fair value at the time of issuance. This Level-2 fair value measurement used WES Operating’s unit price as a significant input in the determination of the fair value. See Note 5 for further discussion of the Class C units.
In February 2019, immediately prior to the closing of the Merger, all outstanding Class C units converted into WES Operating common units on a 1-for-one basis (see Note 1).


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


4. PARTNERSHIP DISTRIBUTIONS (CONTINUED)

basis.
WES Operating Series A Preferred unit distributions.
 As further described in Note 5, WES Operating issued Series A Preferred units representing limited partner interests in WES Operating to private investors in 2016. The Series A Preferred unitholders received quarterly distributions of cash equal to $0.68 per Series A Preferred unit, subject to certain adjustments. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into WES Operating common units on a 1-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into WES Operating common units on a 1-for-one basis. Such converted WES Operating common units were entitled to distributions made to WES Operating common unitholders with respect to the quarter during which the applicable conversion occurred and did not include a prorated Series A Preferred unit distribution. For the quarter ended March 31, 2017, the WES Operating Series A Preferred unitholders received an aggregate cash distribution of $7.5 million (paid in May 2017).

WES Operating’s general partner interest and incentive distribution rights. Prior to the closing of the Merger, WES Operating GP was entitled to 1.5% of all quarterly distributions that WES Operating made prior to its liquidation, and as the former holder of the IDRs, was entitled to incentive distributions at the maximum distribution-sharing percentage of 48.0% for all prior periods presented.. Immediately prior to the closing of the Merger, the IDRs and the general partner units converted into WES Operating common units and a non-economic general partner interest in WES Operating (see Note 1).Operating.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. EQUITY AND PARTNERS’ CAPITAL

Holdings of Partnership equity. The Partnership’s common units are listed on the NYSENew York Stock Exchange under the ticker symbol “WES.” On September 11, 2020, the Partnership assigned its 98% interest in the 30-year $260.0 million note established in May 2008 between WES Operating and Anadarko (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 representing limited partner interests in the Partnership to the Partnership. The units were canceled by the Partnership immediately upon receipt. See Note 6.
As of December 31, 2019,2020, Occidental held 242,136,976214,281,578 common units, representing a 53.4%50.7% limited partner interest in the Partnership, and through its ownership of the general partner, Occidental indirectly held 9,060,641 general partner units, representing a 2.0%2.1% general partner interest in the Partnership (see Note 1). The public held 201,834,433199,558,285 common units, representing a 44.6%47.2% limited partner interest in the Partnership.

Partnership equity repurchases. In February 2019,November 2020, the Board of Directors authorized the Partnership issuedto buy back up to $250.0 million of the Partnership’s common units through December 31, 2021 (the “Purchase Program”). The common units may be purchased from time to time in connection with the closingopen market at prevailing market prices or in privately negotiated transactions. As of December 31, 2020, the Merger (see Note 1) as follows:Partnership 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.
Partnership common units outstanding prior to the Merger218,937,797
WES Operating common units outstanding prior to the Merger152,609,285
WES Operating Class C units outstanding prior to the Merger14,681,388
Less: WES Operating common units owned by the Partnership(50,132,046)
WES Operating common units subject to conversion into Partnership common units117,158,627

Exchange ratio per unit1.525

Partnership common units issued for WES Operating common units (1)
178,692,081
WES Operating common units issued as part of the AMA acquisition45,760,201
Less: WES Operating common units retained by a subsidiary of Anadarko(6,375,284)
WES Operating acquisition common units subject to conversion into Partnership common units39,384,917
Conversion ratio per unit1.4056
Partnership common units issued for WES Operating acquisition common units55,360,984
Partnership common units outstanding at February 28, 2019452,990,862

(1)
Total Partnership units issued at Merger completion exceeds the calculation of such units using the exchange ratio due to the rounding convention described in the Merger Agreement.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Holdings of WES Operating equity. As of December 31, 2019,2020, (i) the Partnership, directly and indirectly through its ownership of WES Operating GP, owned a 98.0% limited partner interest and the entire non-economic general partner interest in WES Operating and (ii) Occidental, through its ownership of WGRAH, owned a 2.0% limited partner interest in WES Operating, which is reflected as a noncontrolling interest within the consolidated financial statements of the Partnership (see Note 1).

WES Operating interests. The following table summarizes WES Operating’s units issued during the years ended December 31, 2019 and 2018:
  
Common
Units
 
Class C
Units
 
General
Partner
Units
 Total
Balance at December 31, 2017 152,602,105
 13,243,883
 2,583,068
 168,429,056
PIK Class C units —
 1,128,782
 —
 1,128,782
Vesting of Long-Term Incentive Plan Awards 7,180
 —
 —
 7,180
Balance at December 31, 2018 152,609,285
 14,372,665
 2,583,068
 169,565,018
PIK Class C units —
 308,723
 —
 308,723
Conversion of Class C units 14,681,388
 (14,681,388) —
 —
IDR and General partner unit conversion 105,624,704
 —
 (2,583,068) 103,041,636
Units issued as part of the AMA acquisition 45,760,201
 —
 —
 45,760,201
Balance at December 31, 2019 (1)
 318,675,578
 —
 —
 318,675,578
(1)
All WES Operating common units that converted into the Partnership’s common units at closing of the Merger were canceled and an equivalent amount of the canceled WES Operating common units were issued to the Partnership. See Note 1 for further details on the units issued and converted in connection with the closing of the Merger.

WES Operating Class C units. In November 2014, WES Operating issued 10,913,853 Class C units to AMH,APC Midstream Holdings, LLC (“AMH”), pursuant to a Unit Purchase Agreement with Anadarko and AMH. The Class C units were issued to partially fund the acquisition of DBM.
The Class C units were issued at a discount to the then-current market price of the common units into which they were convertible. This discount totaling $34.8 million, represented a beneficial conversion feature, and at issuance, was reflected as an increase to WES Operating common unitholders’ capital and a decrease to Class C unitholder capital to reflect the fair value of the Class C units at issuance. The beneficial conversion feature was considered a non-cash distribution that was recognized from the date of issuance through the date of conversion, resulting in an increase to Class C unitholder capital and a decrease to WES Operating common unitholders’ capital as amortized. The beneficial conversion feature was amortized assuming an extended conversion date of March 1, 2020, using the effective yield method. The impact of the beneficial conversion feature amortization was included in the calculation of earnings per unit (see WES Operating’s net income (loss) per common unit below).
All outstanding Class C units converted into WES Operating common units on a 1-for-one basis immediately prior to the closing of the Merger (see Note 1).


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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

WES Operating Series A Preferred units.
 In 2016, WES Operating issued 21,922,831 Series A Preferred units to private investors, generating proceeds of $686.9 million (net of fees and expenses, but including a 2.0% transaction fee paid to the private investors). The Series A Preferred units were issued at a discount to the then-current market price of the common units into which they were convertible. This discount, totaling $93.4 million, represented a beneficial conversion feature, and at issuance, was reflected as an increase to WES Operating common unitholders’ capital and a decrease to Series A Preferred unitholders’ capital to reflect the fair value of the Series A Preferred units on the date of issuance. The beneficial conversion feature was considered a non-cash distribution that was recognized from the date of issuance through the date of conversion, resulting in an increase to Series A Preferred unitholders’ capital and a decrease to WES Operating common unitholders’ capital as amortized. The beneficial conversion feature was amortized using the effective yield method. The impact of the beneficial conversion feature amortization was also included in the calculation of earnings per unit (see WES Operating’s net income (loss) per common unit below). For the year ended December 31, 2017, the amortization for the beneficial conversion feature of the Series A Preferred units was $62.3 million.
Pursuant to an agreement between WES Operating and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into WES Operating common units on a 1-for-one basis on March 1, 2017, and all remaining Series A Preferred units converted into WES Operating common units on a 1-for-one basis on May 2, 2017.

Partnership’s net income (loss) per common unit. As of December 31, 2019, followingFollowing the transactions contemplated toby the Exchange Agreement, the common and general partner unitholders’ allocation of net income (loss) attributable to the Partnership was equal to their cash distributions plus their respective allocations of undistributed earnings or losses.losses using the two-class method. Specifically, net income equal to the amount of available cash (as(beyond proper reserves as defined by the partnership agreement) was allocated to the common and general partner unitholders consistent with actual cash distributions and capital account allocations. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income)income (loss)) were then allocated to the common and general partner unitholders in accordance with their weighted-average ownership percentage during each period.
The Partnership’s basic net income (loss) per common unit is calculated by dividing the limited partners’ interest in net income (loss) by the weighted-average number of common units outstanding during the period. Net income (loss) attributable to assets acquired from Anadarko for periods prior to the acquisition of such assets was not allocated to the limited partners when calculating net income (loss) per common unit.
For periods prior to the Merger, dilutive net income (loss) per common unit was calculated by dividing the limited partners’ interest in net income (loss) adjusted for distributions on the WES Operating Series A Preferred units and a reallocation of the limited partners’ interest in net income (loss) assuming, prior to the actual conversion, conversion of the WES Operating Series A Preferred units into WES Operating common units, by the weighted-average number of the Partnership’s common units outstanding during the period. As of May 2, 2017, all WES Operating Series A Preferred units were converted into WES Operating common units on a 1-for-one basis. The impact of the WES Operating Series A Preferred units assuming, prior to the actual conversion, conversion to WES Operating common units would be anti-dilutive for the year ended December 31, 2017.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

WES Operating’s net income (loss) per common unit. For periods subsequent to the closing of the Merger, net income (loss) per common unit for WES Operating is not calculated as itbecause no longer has publicly traded units. units remained outstanding.
For periods prior to the closing of the Merger, Net income (loss) attributable to Western Midstream Operating, LP earned on and subsequent to the date of acquisition of the Partnership’s assets was allocated in the below-described manner. Net income (loss) attributable to assets acquired from Anadarko for periods prior to the acquisition of such assets was not allocated to the unitholders for purposes of calculating net income (loss) per common unit.

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. EQUITY AND PARTNERS’ CAPITAL

Calculation of net income (loss) per unit. Basic net income (loss) per common unit was calculated by dividing the net income (loss) attributable to common unitholders by the weighted-average number of common units outstanding during the period. The common units issued in connection with acquisitions and equity offerings were included on a weighted-average basis for the periods these units were outstanding. Diluted net income (loss) per common unit was calculated by dividing the sum of (i) the net income (loss) attributable to common units adjusted for distributions on the Series A Preferred units and a reallocation of the common and Class C limited partners’ interest in net income (loss) assuming, prior to the actual conversion, conversion of the Series A Preferred units into common units, and (ii) the net income (loss) attributable to the Class C units as a participating security, by the sum of the weighted-average number of common units outstanding plus the dilutive effect of the (i) weighted-average number of outstanding Class C units and (ii)units.
The following table illustrates the weighted-average numbercalculation of WES Operating’s net income (loss) per common units outstanding assuming, priorunit for the year ended December 31, 2018:
thousands except per-unit amounts
Net income (loss) attributable to Western Midstream Operating, LP$627,917 
Pre-acquisition net (income) loss allocated to Anadarko(182,142)
General partner interest in net (income) loss(346,538)
Common and Class C limited partners’ interest in net income (loss)$99,237 
Net income (loss) allocable to common units (1)
$84,334 
Net income (loss) allocable to Class C units (1)
14,903 
Common and Class C limited partners’ interest in net income (loss)$99,237 
Net income (loss) per unit
Common units – basic and diluted (2)
$0.55 
Weighted-average units outstanding
Common units – basic and diluted152,606 
Excluded due to anti-dilutive effect:
Class C units (2)
13,795 

(1)Adjusted to the actual conversion, conversionreflect amortization of the Series A Preferred units.beneficial conversion feature.

(2)The impact of Class C units would be anti-dilutive for the period presented.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


6. RELATED-PARTY TRANSACTIONS
5. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)

Summary of related-party transactions. The following table illustratestables summarize material related-party transactions included in the calculationPartnership’s consolidated financial statements:
Consolidated statements of operations
Year Ended December 31,
thousands202020192018
Revenues and other
Service revenues – fee based$1,740,999 $1,441,875 $1,070,066 
Service revenues – product based8,509 7,062 3,339 
Product sales71,104 158,459 280,306 
Total revenues and other1,820,612 1,607,396 1,353,711 
Equity income, net – related parties (1)
226,750 237,518 195,469 
Operating expenses
Cost of product92,884 254,771 168,535 
Operation and maintenance49,533 146,990 115,948 
General and administrative (2)
40,295 101,485 49,672 
Total operating expenses182,712 503,246 334,155 
Gain (loss) on divestiture and other, net(2,870)0 0 
Interest income – Anadarko note receivable11,736 16,900 16,900 
Interest expense(6)(1,970)(6,746)

(1)See Note 7.
(2)Includes (i) amounts charged by Occidental pursuant to the shared services agreements (see Shared services agreementswithin this Note 6) and (ii) equity-based compensation expense allocated to the Partnership by Occidental, portions of WES Operating’s net income (loss) per common unit:which are not reimbursed to Occidental and are reflected as contributions to partners’ capital in the consolidated statements of equity and partners’ capital (see Incentive Plans within this Note 6).

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  Year Ended December 31,
thousands except per-unit amounts 2018 2017
Net income (loss) attributable to Western Midstream Operating, LP $627,917
 $731,666
Pre-acquisition net (income) loss allocated to Anadarko (182,142) (164,183)
Series A Preferred units interest in net (income) loss (1)
 —
 (42,373)
General partner interest in net (income) loss (346,538) (303,835)
Common and Class C limited partners’ interest in net income (loss) $99,237
 $221,275
Net income (loss) allocable to common units (1)
 $84,334
 $192,066
Net income (loss) allocable to Class C units (1)
 14,903
 29,209
Common and Class C limited partners’ interest in net income (loss) $99,237
 $221,275
Net income (loss) per unit    
Common units – basic and diluted (2)
 $0.55
 $1.30
Weighted-average units outstanding    
Common units – basic and diluted 152,606
 147,194
Excluded due to anti-dilutive effect:    
Class C units (2)
 13,795
 12,776
Series A Preferred units assuming conversion to common units (2)
 —
 5,406
Table of Contents
(1)
Adjusted to reflect amortization of the beneficial conversion features.
(2)
The impact of Class C units would be anti-dilutive for the periods presented and the conversion of Series A Preferred units would be anti-dilutive for the year ended December 31, 2017. On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a 1-for-one basis, and on May 2, 2017, all remaining Series A Preferred units converted into common units on a 1-for-one basis.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


6. RELATED-PARTY TRANSACTIONS WITH AFFILIATES

Affiliate transactions.
Consolidated balance sheets
December 31,
thousands20202019
Assets
Accounts receivable, net (1)
$291,253 $113,345 
Other current assets5,493 4,982 
Anadarko note receivable0 260,000 
Equity investments (2)
1,224,813 1,285,717 
Other assets50,967 60,221 
Total assets1,572,526 1,724,265 
Liabilities
Accounts and imbalance payables6,664 0 
Short-term debt (3)
0 7,873 
Accrued liabilities19,195 3,087 
Other liabilities138,796 97,800 
Total liabilities164,655 108,760 

(1)Increase attributable to the timing of certain related-party cash receipts. The Partnership received $77.8 million of the December 31, 2020, Accounts receivable, net balance by January 11, 2021.
(2)See Note 7.
(3)Includes amounts related to finance leases Affiliate(see Note 14).

Consolidated statements of cash flows
Year Ended December 31,
thousands202020192018
Distributions from equity-investment earnings – related parties$246,637 $234,572 $187,392 
Acquisitions from related parties0 (2,007,926)(254)
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 
APCWH Note Payable borrowings0 11,000 321,780 
Repayment of APCWH Note Payable0 (439,595)0 
Distributions to Partnership unitholders (1)
(367,861)(566,868)(400,194)
Distributions to WES Operating unitholders (2)
(15,434)(19,768)(7,583)
Net contributions from (distributions to) related parties24,466 458,819 97,755 
Above-market component of swap agreements with Anadarko0 7,407 51,618 
Finance lease payments(6,382)(508)0 

(1)Represents distributions paid to Occidental pursuant to the partnership agreement of the Partnership (see Note 4 and Note 5).
(2)Represents distributions paid to certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4 and Note 5).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. RELATED-PARTY TRANSACTIONS

The following tables summarize material related-party transactions for WES Operating (which are included in the Partnership’s consolidated financial statements) to the extent the amounts differ from the Partnership’s consolidated financial statements:
Consolidated statements of operations
Year Ended December 31,
thousands202020192018
General and administrative (1)
$41,609 $99,613 $48,819 

(1)Includes (i) amounts charged by Occidental pursuant to the shared services agreements (see Shared services agreementswithin this Note 6) and (ii) equity-based compensation expense allocated to WES Operating by Occidental, portions of which are not reimbursed to Occidental and are reflected as contributions to partners’ capital in the consolidated statements of equity and partners’ capital (see Incentive Plans within this Note 6).

Consolidated balance sheets
December 31,
thousands20202019
Accounts receivable, net$246,083 $113,581 

Consolidated statements of cash flows
Year Ended December 31,
thousands202020192018
Distributions to WES Operating unitholders (1)
$(771,546)$(1,025,931)$(514,906)

(1)Represents distributions paid to the Partnership and certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4 and Note 5). For the year ended December 31, 2019, includes distributions to the Partnership and a subsidiary of Occidental related to the repayment of the WGP RCF (see Note 13).

Related-party revenues. Related-party revenues include (i) income from the Partnership’s investments accounted for under the equity method of accounting (see Note 107) and (ii) amounts earned by the Partnership from services provided to Occidental and from the sale of natural gas, condensate, and NGLs to Occidental. Occidental sells natural gas and NGLs as an agent on behalf of either the Partnership or the Partnership’s customers. When product sales are on the Partnership’s customers’ behalf, the Partnership recognizes associated service revenues and cost of product expense. When product sales are on the Partnership’s behalf, the Partnership recognizes product sales revenues based on Occidental’s sales price to the third party and records the associated cost of product expense. In addition, the Partnership purchases natural gas from an affiliate of Occidental pursuant to gas purchase agreements.
Operation and maintenance expense includes amounts accrued for or paid to affiliates for the operation of the Partnership’s assets and for services provided to affiliates, including field labor, measurement and analysis, and other disbursements. A portion of general and administrative expense is paid by Occidental, which results in affiliate transactions pursuant to the reimbursement provisions of the Partnership’s and WES Operating’s agreements with Occidental. Affiliate expenses do not bear a direct relationship to affiliate revenues, and third-party expenses do not bear a direct relationship to third-party revenues.

December 2019 Agreements. As discussed in more detail in Note 1, on December 31, 2019, the Partnership and certain of its subsidiaries, including WES Operating and WES Operating GP, entered into agreements with Occidental and/or certain of its subsidiaries, including Anadarko.

Merger transactions. As discussed in more detail in Note 1, on February 28, 2019, the Partnership, WES Operating, Anadarko, and certain of their affiliates completed the Merger and the other transactions contemplated in the Merger Agreement, which included the acquisition of AMA from Anadarko. See Note 3.

Cash management. Occidental operates a cash management system for its subsidiaries’ separate bank accounts, including accounts for the Partnership and WES Operating. Prior to the acquisition of assets from Anadarko, third-party sales and purchases related to such assets were received or paid in cash by Anadarko within its centralized cash management system. Outstanding affiliate balances as of the dates of acquisition were settled entirely through an adjustment to net investment by Anadarko in connection with the acquisitions. Subsequent to asset acquisitions from Anadarko, transactions related to the acquired assets were cash-settled directly by the Partnership with third parties and Anadarko affiliates. Chipeta cash-settles its transactions directly with third parties, Occidental, and other subsidiaries of the Partnership.

Note receivable - Anadarko. In May 2008, WES Operating loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly and classified as Interest income – affiliates in the consolidated statements of operations. The fair value of the Anadarko note receivable was $337.7 million and $279.6 million at December 31, 2019 and 2018, respectively. Following Occidental’s acquisition by merger of Anadarko, the fair value of the Anadarko note receivable reflects consideration of Occidental’s credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest rate, based on quoted market prices of similar debt instruments. Accordingly, the fair value of the note receivable is measured using Level-2 fair value inputs.

APCWH Note Payable. In June 2017, APCWH entered into an eight-year note payable agreement with Anadarko, which was repaid at the Merger completion date. See Note 1 and Note 13.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Commodity-price swap agreements. WES Operating entered into commodity-price swap agreements with Anadarko to mitigate exposure to the commodity-price risk inherent in WES Operating’s percent-of-proceeds, percent-of-product, and keep-whole natural-gas processing contracts. Notional volumes for each product-based commodity-price swap agreement were not specifically defined. Instead, the commodity-price swap agreements applied to the actual volumes of natural gas, condensate, and NGLs purchased and sold. The commodity-price swap agreements did not satisfy the definition of a derivative financial instrument and, therefore did not require fair-value measurement. Net gains (losses) on commodity-price swap agreements were $(0.7) million (due to settlement of 2018 activity in 2019), $(7.9) million, and $0.6 million for the years ended December 31, 2019, 2018, and 2017, respectively, and are reported in the consolidated statements of operations as affiliate Product sales in 2019 and 2018 and as affiliate Product sales and Cost of product in 2017. These commodity-price swap agreements expired without renewal on December 31, 2018.
Revenues or costs attributable to volumes sold and purchased under the commodity-price swap agreements for the DJ Basin complex and the MGR assets were recognized in the consolidated statements of operations at the applicable market price in the tables below. A capital contribution from Anadarko was recorded in the consolidated statements of equity and partners’ capital for an amount equal to (i) the amount by which the swap price for product sales exceeds the applicable market price in the tables below, minus (ii) the amount by which the swap price for product purchases exceeds the applicable market price in the tables below. For the years ended December 31, 2019, 2018, and 2017, the capital contributions from Anadarko were $7.4 million, $51.6 million, and $58.6 million, respectively. The tables below summarize the swap prices compared to the forward market prices:
  DJ Basin Complex
per barrel except natural gas 2017 - 2018 Swap Prices 
2017 Market Prices (1)
 
2018 Market Prices (1)
Ethane $18.41
 $5.09
 $5.41
Propane 47.08
 18.85
 28.72
Isobutane 62.09
 26.83
 32.92
Normal butane 54.62
 26.20
 32.71
Natural gasoline 72.88
 41.84
 48.04
Condensate 76.47
 45.40
 49.36
Natural gas (per MMBtu) 5.96
 3.05
 2.21

  MGR Assets
per barrel except natural gas 2017 - 2018 Swap Prices 
2017 Market Prices (1)
 
2018 Market Prices (1)
Ethane $23.11
 $4.08
 $2.52
Propane 52.90
 19.24
 25.83
Isobutane 73.89
 25.79
 30.03
Normal butane 64.93
 25.16
 29.82
Natural gasoline 81.68
 45.01
 47.25
Condensate 81.68
 53.55
 56.76
Natural gas (per MMBtu) 4.87
 3.05
 2.21
(1)
Represents the New York Mercantile Exchange forward strip price as of December 1, 2016 and December 20, 2017, for the 2017 Market Prices and 2018 Market Prices, respectively, adjusted for product specification, location, basis, and, in the case of NGLs, transportation and fractionation costs.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Gathering and processing agreements. The Partnership has significant gathering and processing arrangements with affiliates of Occidental on most of its systems. While Occidental is the contracting counterparty of the Partnership, 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 the Partnership’s facilities and infrastructure to bring their volumes to market. Natural-gas throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 38%41%, 36%38%, and 39%36% for the years ended December 31, 2020, 2019, 2018, and 2017,2018, respectively. Crude-oil NGLs, and produced-waterNGLs throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 83%88%, 85%84%, and 81%80% for the years ended December 31, 2020, 2019, and 2018, respectively. Produced-water throughput attributable to production owned or controlled by Occidental was 87%, 82%, and 2017,91% for the years ended December 31, 2020, 2019, and 2018, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. RELATED-PARTY TRANSACTIONS

In connection with the sale of its Eagle Ford assets in 2017, Anadarko remained the primary counterparty to the Partnership’s Brasada gas processing agreement and entered into an agency relationship with Sanchez Energy Corporation (“Sanchez”), now Mesquite Energy, Inc. (“Mesquite”) that allows Mesquite to process gas under such agreement. For this reason, Anadarko continues to be liable under the Brasada gas processing agreement through 2034 to the extent Mesquite does not perform. For all periods presented, Mesquite has performed Anadarko’s obligations under the Brasada gas processing agreement pursuant to its agency arrangement with Anadarko.
Further, in connection with the sale of its Uinta Basin assets in 2020, Kerr McGee Oil & Gas Onshore LP, a subsidiary of Occidental, retained the deficiency payment obligations under a gas processing agreement at the Chipeta plant. This contingent payment obligation extends through the earlier of October 1, 2022, or the termination of the processing agreement.

Commodity purchase and sale agreements. TheThrough December 31, 2020, the Partnership sellssold a significant amount of its natural gas and NGLs to Anadarko Energy Services Company (“AESC”), Occidental’s marketing affiliate that actsaffiliate. Prior to April 1, 2020, AESC acted as an agent on behalf of either the Partnership or the Partnership’s agentcustomers for third-party sales. Where AESC sold natural gas and NGLs on the Partnership’s customers’ behalf, the Partnership recognized associated service revenues and cost of product expense for the marketing services performed by AESC. When product sales were on the Partnership’s behalf, the Partnership recognized product sales revenues based on Occidental’s sales price to the third party and recorded the associated cost of product expense associated with the marketing activities provided by AESC. 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, the Partnership no longer recognizes service revenues and/or product sales revenues and the equivalent cost of product expense for the marketing services performed by AESC. This change has no impact to Operating income (loss), Net income (loss), the balance sheets, cash flows, or any non-GAAP metric used to evaluate the Partnership’s operations (see Key Performance Metrics under Part II, Item 7 of this Form 10-K). In addition, the Partnership purchases natural gas from AESC pursuant to purchase agreements.

Marketing Transition Services Agreement. Effective December 31, 2019, certain subsidiaries of Anadarko entered into a transition services agreement (the “Marketing Transition Services Agreement”) to provide certain marketing-related services to certain of the Partnership’s subsidiaries through December 31, 2020, subject to the Partnership’s subsidiaries’ option to extend such services for an additional six-month period. The Marketing Transition Services Agreement was terminated on December 31, 2020. While the Partnership still has some marketing agreements with affiliates of Occidental, the Partnership began marketing and selling substantially all of its natural gas and NGLs directly to third parties beginning on January 1, 2021.

Operating lease. Effective December 31, 2019, an affiliate of Occidental and a wholly owned subsidiary of the Partnership, the lessor, entered into an operating and maintenance agreement pursuant to which Occidental provides operational and maintenance services with respect to a crude-oil gathering system and associated treating facilities owned by the Partnership through December 31, 2021. See Note 14.

Related-party expenses. Operation and maintenance expense includes amounts accrued for or paid to related parties for the operation of the Partnership’s assets and for services provided to related parties, including field labor, measurement and analysis, and other disbursements. A portion of general and administrative expense is paid by Occidental, which results in related-party transactions pursuant to the reimbursement provisions of the Partnership’s and WES Operating’s agreements with Occidental. Related-party expenses do not bear a direct relationship to related-party revenues, and third-party expenses do not bear a direct relationship to third-party revenues.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. RELATED-PARTY TRANSACTIONS

Shared services agreements.PursuantGeneral and administrative expense includes costs incurred pursuant to the agreements discussed below,below. Under these agreements, Occidental performshas performed certain centralized corporate functions for the Partnership and WES Operating such as legal; accounting; treasury; cash management; investor relations; insurance administration and claims processing; risk management; health, safety, and environmental; information technology; human resources; credit; payroll; internal audit; tax; and marketing and midstream administration.Operating.

•Services Agreement. Pursuant to the Services Agreement, which was amended and restated on December 31, 2019, specified employees of Occidental were seconded to WES Operating GP to provide, under the direction, supervision, and control of the general partner, (i) operating and routine maintenance service and (ii) corporate, administrative, and other services, with respect to the assets owned and operated by the Partnership. Occidental was reimbursed for the services provided by the seconded employees. In January 2020, pursuant to the Services Agreement, Occidental made a one-time cash contribution of $20.0 million to WES Operating for anticipated transition costs required to establish stand-alone human resources and information technology functions. In late March 2020, seconded employees’ employment was transferred to the Partnership. Occidental continues to provide certain limited administrative and operational services to the Partnership, with most services expected to be fully transitioned to the Partnership by December 31, 2021. For additional information on the Services Agreement, see Note 1.

•WES omnibus agreement. Prior to December 31, 2019, the Partnership had an omnibus agreement with Occidental and the general partner (the “WES omnibus agreement”) that governed (i) the Partnership’s obligation to reimburse Occidental for expenses incurred or payments made on its behalf in connection with Occidental’s provision of general and administrative services provided to the Partnership, including certain public company expenses and general and administrative expenses;expenses, (ii) the Partnership’s obligation to pay Occidental, in quarterly installments, an administrative services fee of $250,000 per year, which was subject to an annual increase pursuant to the omnibus agreement;agreement, and (iii) the Partnership’s obligation to reimburse Occidental for all insurance coverage expenses it incurred or payments it made on the Partnership’s behalf. The WES omnibus agreement was terminated as part of the December 2019 Agreements (see Note 1).
The following table summarizes the amounts the Partnership reimbursed to Occidental, separate from, and in addition to, those reimbursed by WES Operating:
  Year Ended December 31,
thousands 2019 2018 2017
General and administrative expenses $604
 $269
 $263
Public company expenses 4,089
 2,895
 1,821
Total reimbursement $4,693
 $3,164
 $2,084



WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

•WES Operating omnibus agreement.Prior to December 31, 2019, WES Operating had a separate omnibus agreement with Occidental and WES Operating GP (the “WES Operating omnibus agreement”) that governed (i) Occidental’s obligation to indemnify WES Operating for certain liabilities and WES Operating’s obligation to indemnify Occidental for certain liabilities, (ii) WES Operating’s obligation to reimburse Occidental for expenses incurred or payments made on its behalf in conjunction with Occidental’s provision of general and administrative services provided to WES Operating, including salary and benefits of Occidental personnel, public company expenses, general and administrative expenses, and salaries and benefits of WES Operating’s executive management who were employees of Occidental, and (iii) WES Operating’s obligation to reimburse AnadarkoOccidental for all insurance coverage expenses it incurred or payments it made with respect to WES Operating’s assets. Occidental, in accordance with the partnership agreement and the WES Operating omnibus agreement, determined, in its reasonable discretion, amounts to be reimbursed by WES Operating in exchange for services provided under the WES Operating omnibus agreement. The WES Operating omnibus agreement was terminated as part of the December 2019 Agreements (see Note 1).
The following table summarizes the amounts WES Operating reimbursed to Occidental pursuant to the WES Operating omnibus agreement:
  Year Ended December 31,
thousands 2019 2018 2017
General and administrative expenses $84,039
 $35,077
 $31,733
Public company expenses 4,065
 15,409
 9,379
Total reimbursement $88,104
 $50,486
 $41,112


Services and secondment agreement. Pursuant to the services and secondment agreement, which was amended and restated on December 31, 2019, and is now referred to as the Services Agreement, specified employees of Occidental are seconded to WES Operating GP to provide, under the direction, supervision, and control of the general partner, operating, routine maintenance, and other services with respect to the assets owned and operated by the Partnership. Occidental is reimbursed for the services provided by the seconded employees. The consolidated financial statements include costs allocated by Occidental for expenses incurred under the services and secondment agreement for periods including and subsequent to the Partnership’s prior asset acquisitions from Anadarko.
Pursuant to the Services Agreement, Occidental (i) seconds certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP pays 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 the Partnership. The initial term of the Services Agreement is two years and will automatically extend for additional six-month periods unless either party provides a 30-day written notice of termination prior to the initial two-year or additional six-month period expires. However, the Services Agreement provides for the transfer of certain employees to the Partnership, which is anticipated to occur prior to the end of 2020. For additional information on the Services Agreement, see Note 1.

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


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


6. RELATED-PARTY TRANSACTIONS WITH AFFILIATES (CONTINUED)

Excluding the Partnership’s management team, who became employees of the Partnership on December 31, 2019, pursuant to the Services Agreement, the employees supporting the Partnership’s operations are employees of Occidental. Occidental allocates costs to the Partnership for its share of personnel costs, including costs associated with equity-based compensation plans, non-contributory defined benefit pension and postretirement plans, and defined contribution savings plans. In general, reimbursement to Occidental is either (i) on an actual basis for direct expenses Occidental and the general partner incur on the Partnership’s behalf, or (ii) based on an allocation of salaries and related employee benefits between WES Operating, WES Operating GP, and Occidental, based on estimates of time spent on each entity’s business and affairs. Most general and administrative expenses charged by Occidental are on an actual basis, and no general and administrative expenses, direct or allocable, include a mark-up or subsidy component. With respect to allocated costs, management believes the allocation method employed by Occidental is reasonable. Although it is not practicable to determine what the amount of these direct and allocated costs would be if the Partnership were to directly obtain these services, management believes that aggregate costs charged by Occidental are reasonable.

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

Indemnification agreements. Prior to December 31, 2019, WES Operating GP was indemnified by wholly owned subsidiaries of Occidental against any claims made against WES Operating GP for WES Operating’s long-term debt and/or borrowings under the RCF and Term loan facility. These indemnification agreements were terminated as part of the December 2019 Agreements (see Note 1).

LTIPs. The general partner has the authority to grant equity compensation awards under the Western Gas Partners, LP 2017 Long-Term Incentive Plan (assumed by the Partnership in connection with the Merger) and the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (collectively referred to as the “LTIPs”) to its independent directors, executive officers, and Occidental employees performing services for the Partnership from time to time. Phantom units awarded to the independent directors vest one year from the grant date, while all other phantom unit awards are subject to ratable vesting over a three-year service period.
The following table summarizes award activity under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan for the years ended December 31, 2019, 2018, and 2017:
  2019 2018 2017
  Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units
Phantom units outstanding at beginning of year $35.08
 7,128
 $43.39
 5,763
 $39.78
 5,658
Granted 29.75
 25,212
 35.08
 7,128
 43.39
 5,763
Vested 31.62
 (44,572) 43.39
 (5,763) 39.78
 (5,658)
Converted (1)
 33.46
 12,232
 —
 —
 —
 —
Phantom units outstanding at end of year —
 —
 35.08
 7,128
 43.39
 5,763
(1)
At closing of the Merger, WES Operating phantom units awarded under the Western Gas Partners, LP 2017 Long-Term Incentive Plan converted into phantom units of the Partnership under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan.

WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

The following table summarizes award activity under the Western Gas Partners, LP 2017 Long-Term Incentive Plan, which was assumed by the Partnership in connection with the Merger, for the years ended December 31, 2019, 2018, and 2017:
  2019 2018 2017
  Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units Weighted-Average Grant-Date Fair Value Units
Phantom units outstanding at beginning of year $49.88
 8,020
 $55.73
 7,180
 $49.30
 7,304
Granted —
 —
 49.88
 8,020
 55.73
 7,180
Vested —
 —
 55.73
 (7,180) 49.30
 (7,304)
Converted (1)
 49.88
 (8,020) —
 —
 —
 —
Phantom units outstanding at end of year —
 —
 49.88
 8,020
 55.73
 7,180
(1)
At closing of the Merger, WES Operating phantom units awarded under the Western Gas Partners, LP 2017 Long-Term Incentive Plan converted into phantom units of the Partnership under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan.

Compensation expense for the LTIPs is recognized over the vesting period and was $1.0 million, $0.7 million, and $0.6 million for the years ended December 31, 2019, 2018, and 2017, respectively.

Incentive Plans. General and administrative expense includes equity-based compensation expense allocated to the Partnership by Occidental for awards granted to the executive officers of the general partner and to other employees prior to their employment with the Partnership under (i) the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as amended and restated, (ii) Occidental’s 2015 Long-Term Incentive Plan, and (iii) Occidental’s Phantom Share Unit Award Plan (collectively referred to as the “Incentive Plans”). Grants made under equity-based compensation plans result in equity-based compensation expense, which is determined by reference to the fair value of equity compensation. For equity-based awards ultimately settled through the issuance of units or stock, the fair value is measured as of the grant date. General and administrative expense includes costs related to the Incentive Plans of $14.6 million, $12.9 million, $6.6 million, and $4.6$6.6 million for the years ended December 31, 2020, 2019, 2018, and 2017,2018, respectively. Portions of these amounts are reflected as contributions to partners’ capital in the consolidated statements of equity and partners’ capital. As of December 31, 2019, $7.92020, $12.5 million of estimated unrecognized compensation expense attributable to the Incentive Plans will be allocated to the Partnership over a weighted-average period of 1.80.7 years.

Affiliate purchases.December 2019 Agreements. As discussed in more detail in Note 1, on December 31, 2019, the Partnership and certain of its subsidiaries, including WES Operating and WES Operating GP, entered into agreements with Occidental and/or certain of its subsidiaries, including Anadarko.

Merger transactions. As discussed in more detail in Note 1, on February 28, 2019, the Partnership, WES Operating, Anadarko, and certain of their affiliates completed the Merger and the other transactions contemplated in the Merger Agreement, which included the acquisition of AMA from Anadarko. See Note 3.

Anadarko note receivable. In May 2008, WES Operating loaned $260.0 million to Anadarko in exchange for a 30-year note that bore interest at a fixed annual rate of 6.50%, payable quarterly and classified as interest income in the consolidated statements of operations. 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 (and accrued interest owed under) the Anadarko note receivable to the Partnership and the remaining 2% of its interest 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.

Purchases from related parties. During the thirdfourth quarter of 2020, a subsidiary of the Partnership entered into an agreement to purchase three electrical substations located in the DJ Basin from a subsidiary of Occidental for $2.0 million. This purchase was recorded as an Accrued capital expenditure as of December 31, 2020, and cash was paid in January of 2021. During 2019, the Partnership purchased $18.4 million of materials and supplies inventory from Occidental, which is included in Other current assets on the consolidated balance sheets.Occidental.

AffiliateRelated-party asset contributions. The following table summarizes affiliaterelated-party contributions of other assets to the Partnership:
 Year Ended December 31,
thousands20192018
Cash consideration paid$(425)$(254)
Net carrying value335 59,089 
Partners’ capital adjustment$(90)$58,835 


145
  Year Ended December 31,
thousands 2019 2018 2017
Cash consideration paid $(425) $(254) $(3,910)
Net carrying value 335
 59,089
 5,283
Partners’ capital adjustment $(90) $58,835
 $1,373
Table of Contents


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


6. RELATED-PARTY TRANSACTIONS WITH AFFILIATES (CONTINUED)

Summary of affiliate transactions.
APCWH Note Payable.The following table summarizes material affiliate transactions included In June 2017, APC Water Holdings 1, LLC (“APCWH”) entered into an eight-year note payable agreement with Anadarko, which was repaid in the Partnership’s consolidated financial statements:first quarter of 2019 at the Merger completion date. See Note 13.

  Year ended December 31,
thousands 2019 2018 2017
Revenues and other (1)
 $1,607,396
 $1,353,711
 $1,539,105
Equity income, net – affiliates (1)
 237,518
 195,469
 115,141
Operating expenses      
Cost of product (1)
 254,771
 168,535
 74,560
Operation and maintenance (1)
 146,990
 115,948
 82,249
General and administrative (2)
 101,485
 49,672
 43,221
Total operating expenses 503,246
 334,155
 200,030
Interest income (3)
 16,900
 16,900
 16,900
Interest expense (4)
 1,970
 6,746
 224
APCWH Note Payable borrowings 11,000
 321,780
 98,813
Repayment of APCWH Note Payable 439,595
 —
 —
Settlement of the Deferred purchase price obligation – Anadarko (5)
 —
 —
 (37,346)
Distributions to Partnership unitholders (6)
 566,868
 400,194
 360,523
Distributions to WES Operating unitholders (7)
 19,768
 7,583
 7,100
Above-market component of swap agreements with Anadarko 7,407
 51,618
 58,551
(1)
Represents amounts earned or incurred on and subsequent to the date of the acquisition of assets from Anadarko, and amounts earned or incurred by Anadarko on a historical basis for periods prior to the acquisition of such assets.
(2)
Represents general and administrative expense 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. These amounts include equity-based compensation expense allocated to the Partnership by Occidental (seeCommodity-price swap agreements. LTIPs and Incentive Plans within this Note 6) and amounts charged by Occidental under the WES and WES Operating omnibus agreements.
(3)
Represents interest income recognized on the Anadarko note receivable.
(4)
Includes amounts related to finance leases and the APCWH Note Payable (see Note 1 and Note 13).
(5)
Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation – Anadarko (see Note 3).
(6)
Represents distributions paid to Occidental pursuant to the partnership agreement of the Partnership (see Note 4 and Note 5).
(7)
Represents distributions paid to certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4 and Note 5).

The following table summarizes material affiliate transactions for WES Operating (which are includedpreviously entered into commodity-price swap agreements with Anadarko to mitigate exposure to the commodity-price risk inherent in WES Operating’s percent-of-proceeds, percent-of-product, and keep-whole natural-gas processing contracts. These commodity-price swap agreements expired without renewal on December 31, 2018.
Notional volumes for each product-based commodity-price swap agreement were not specifically defined. Instead, the commodity-price swap agreements applied to the actual volumes of natural gas, condensate, and NGLs purchased and sold. The commodity-price swap agreements did not satisfy the definition of a derivative financial instrument and, therefore did not require fair-value measurement. Net losses on commodity-price swap agreements were $0.7 million (due to settlement of 2018 activity in 2019) and $7.9 million for the years ended December 31, 2019 and 2018, respectively, reported in the Partnership’s consolidated financial statements)statements of operations as related-party Product sales. A capital contribution from Anadarko related to the extentcommodity-price swap agreements of $7.4 million and $51.6 million was recorded in the amounts differ fromconsolidated statements of equity and partners’ capital for the Partnership’s consolidated financial statements:years ended December 31, 2019 and 2018, respectively.
  Year ended December 31,
thousands 2019 2018 2017
General and administrative (1)
 $99,613
 $48,819
 $42,411
Distributions to WES Operating unitholders (2)
 1,025,931
 514,906
 452,777
(1)
Represents general and administrative expense 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. These amounts include equity-based compensation expense allocated to WES Operating by Occidental (see LTIPs and Incentive Plans within this Note 6) and amounts charged by Occidental pursuant to the WES Operating omnibus agreement.
(2)
Represents distributions paid to the Partnership and certain subsidiaries of Occidental pursuant to WES Operating’s partnership agreement (see Note 4 and Note 5). For the year ended December 31, 2019, includes distributions to the Partnership and a subsidiary of Occidental related to the repayment of the WGP RCF (see Note 13).

WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


6. TRANSACTIONS WITH AFFILIATES (CONTINUED)

Concentration of credit risk. Occidental was the only customer from which revenues exceeded 10% of consolidated revenues for all periods presented in the consolidated statements of operations.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. EQUITY INVESTMENTS

The following tables present the financial statement impact of the Partnership’s equity investments for the years ended December 31, 2020 and 2019:
thousandsBalance at December 31, 2018AcquisitionsEquity
income, net
Contributions (1)
Distributions
Distributions
in excess of
cumulative
earnings (2)
Balance at December 31, 2019
Fort Union$2,259 $0 $(2,232)$0 $0 $(637)$(610)
White Cliffs43,020 0 9,500 5,414 (8,918)(3,139)45,877 
Rendezvous37,841 0 769 0 (2,710)(2,936)32,964 
Mont Belvieu JV104,949 0 28,412 0 (28,451)(1,874)103,036 
TEG19,358 0 4,088 0 (4,110)(1,137)18,199 
TEP193,198 0 30,871 12,220 (32,733)0 203,556 
FRP176,436 0 32,617 30,175 (31,446)0 207,782 
Whitethorn LLC161,858 0 74,548 10,332 (74,856)(10,217)161,665 
Cactus II106,360 0 10,755 56,252 (1,202)0 172,165 
Saddlehorn108,507 0 25,524 3,550 (24,726)0 112,855 
Panola22,769 0 2,136 0 (2,137)(985)21,783 
Mi Vida64,631 0 10,655 0 (12,077)(5,402)57,807 
Ranch Westex50,902 0 6,812 0 (8,143)(2,893)46,678 
Red Bluff Express0 92,546 3,063 10,450 (3,063)(1,036)101,960 
Total$1,092,088 $92,546 $237,518 $128,393 $(234,572)$(30,256)$1,285,717 

thousandsBalance at December 31, 2019
Other-than-temporary
impairment
expense (3)
Equity
income, net		ContributionsDistributions
Distributions
in excess of
cumulative
earnings (2)
DivestituresBalance at December 31, 2020
Fort Union$(610)$0 $(544)$0 $0 $0 $1,154 $0 
White Cliffs45,877 0 5,474 993 (4,892)(1,829)0 45,623 
Rendezvous32,964 0 52 0 (1,994)(2,824)0 28,198 
Mont Belvieu JV103,036 0 25,913 0 (25,951)(4,124)0 98,874 
TEG18,199 0 4,483 0 (4,504)(1,517)0 16,661 
TEP203,556 0 36,351 0 (39,655)(5,063)0 195,189 
FRP207,782 0 37,736 3,670 (39,254)(10,053)0 199,881 
Whitethorn LLC161,665 0 35,725 428 (41,070)(19)0 156,729 
Cactus II172,165 0 22,193 13,645 (31,982)(2,100)0 173,921 
Saddlehorn112,855 0 26,255 0 (27,393)0 0 111,717 
Panola21,783 0 2,047 0 (2,047)(916)0 20,867 
Mi Vida57,807 0 10,764 0 (11,563)(1,977)0 55,031 
Ranch Westex46,678 (29,399)12,127 0 (9,802)(706)0 18,898 
Red Bluff Express101,960 0 8,174 652 (6,530)(1,032)0 103,224 
Total$1,285,717 $(29,399)$226,750 $19,388 $(246,637)$(32,160)$1,154 $1,224,813 

(1)Includes capitalized interest of $3.6 million for the year ended December 31, 2019 related to the construction of the Cactus II pipeline.
(2)Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, are calculated on an individual-investment basis.
(3)Recorded in Long-lived asset and other impairments in the consolidated statements of operations.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. EQUITY INVESTMENTS

The investment balance in White Cliffs at December 31, 2020, is $5.2 million less than the Partnership’s underlying equity in White Cliffs’ net assets, primarily due to the Partnership recording the acquisition of its initial 0.4% interest in White Cliffs at Anadarko’s historic carrying value. This difference will be amortized to Equity income, net – related parties in the consolidated statements of operations over the remaining estimated useful life of the White Cliffs pipeline.
The investment balance in Rendezvous at December 31, 2020, includes $30.4 million for the purchase price allocated to the investment in Rendezvous in excess of the historic cost basis of WGRI, the entity that previously owned the interest in Rendezvous, which Anadarko acquired in August 2006. This excess balance is attributable to the difference between the fair value and book value of such gathering and treating facilities (at the time WGRI was acquired by Anadarko) and will be amortized to Equity income, net – related parties in the consolidated statements of operations over the remaining estimated useful life of those facilities.
The investment balance in Whitethorn LLC at December 31, 2020, is $36.2 million less than the Partnership’s underlying equity in Whitethorn LLC’s net assets, primarily due to terms of the acquisition agreement which provided the Partnership a share of pre-acquisition operating cash flow. This difference will be amortized to Equity income, net – related parties in the consolidated statements of operations over the remaining estimated useful life of Whitethorn.
The investment balance in Saddlehorn at December 31, 2020, was $17.0 million less than the Partnership’s underlying equity in Saddlehorn’s net assets, primarily due to income from an expansion project that was funded by Saddlehorn’s other owners being disproportionately allocated to the Partnership beginning in the second quarter of 2020. This difference will be amortized to Equity income, net – related parties in the consolidated statements of operations over the remaining estimated useful life of the Saddlehorn pipeline.
The investment balance in Ranch Westex at December 31, 2020, was $25.4 million less than the Partnership’s underlying equity in Ranch Westex’s net assets, primarily due to an impairment loss recognized by the Partnership in the third quarter of 2020. The impairment loss of $29.4 million resulted from a decline in value below the carrying value, which was determined to be other than temporary in nature. This investment was impaired to its estimated fair value of $16.7 million at September 30, 2020, using the income approach and Level-3 fair value inputs, due to a reduction in estimated future cash flows resulting from lower forecasted producer throughput.
Management evaluates its equity investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss in the consolidated statements of operations.

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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. EQUITY INVESTMENTS

The following tables present the summarized combined financial information for equity investments (amounts represent 100% of investee financial information):
Year Ended December 31,
thousands202020192018
Revenues$1,635,132 $1,687,116 $1,300,921 
Operating income1,045,889 1,107,664 876,910 
Net income1,045,076 1,108,173 874,587 
December 31,
thousands20202019
Current assets$398,933 $433,390 
Property, plant, and equipment, net5,653,853 5,754,160 
Other assets171,353 175,231 
Total assets$6,224,139 $6,362,781 
Current liabilities$144,629 $223,171 
Non-current liabilities31,383 27,024 
Equity6,048,127 6,112,586 
Total liabilities and equity$6,224,139 $6,362,781 

8. INCOME TAXES

The Partnership is not a taxable entity for U.S. federal income tax purposes.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. FollowingIncome earned on the adoption ofAMA assets for periods subsequent to February 2019 was subject only to Texas margin tax on income apportionable to Texas.
For the U.S. Tax Cuts and Jobs Act signed into law onyear ended December 22, 2017, AMA recognized a one-time deferred tax benefit of $87.3 million31, 2020, the variance from the federal statutory rate was primarily due to our Texas margin tax liability. For the remeasurement of its U.S. deferred tax assetsyears ended December 31, 2019 and liabilities based on the reduction of the corporate tax rate from 35% to 21%.
During 2018, the accounting forvariance from the federal statutory rate primarily was due to federal and state taxes on pre-acquisition income tax effects relatedattributable to the adoptionassets previously acquired from Anadarko, and our share of the Tax Reform Legislation was completed before the end of the measurement period. No additional adjustments to the provisional amount recorded in 2017 were recognized. The federal tax benefit is included in the Deferred income taxes balance as presented on the consolidated balance sheets.applicable Texas margin tax.
The components of income tax expense (benefit) are as follows:
 Year Ended December 31,
thousands202020192018
Current income tax expense (benefit)
Federal income tax expense (benefit)$0 $5,550 $(79,264)
State income tax expense (benefit)2,702 313 (850)
Total current income tax expense (benefit)2,702 5,863 (80,114)
Deferred income tax expense (benefit)
Federal income tax expense (benefit)0 2,782 133,044 
State income tax expense (benefit)3,296 4,827 6,004 
Total deferred income tax expense (benefit)3,296 7,609 139,048 
Total income tax expense (benefit)$5,998 $13,472 $58,934 
  Year Ended December 31,
thousands 2019 2018 2017
Current income tax expense (benefit)      
Federal income tax expense (benefit) $5,550
 $(79,264) $(9,207)
State income tax expense (benefit) 313
 (850) 2,422
Total current income tax expense (benefit) 5,863
 (80,114) (6,785)
Deferred income tax expense (benefit)      
Federal income tax expense (benefit) 2,782
 133,044
 (55,835)
State income tax expense (benefit) 4,827
 6,004
 2,697
Total deferred income tax expense (benefit) 7,609
 139,048
 (53,138)
Total income tax expense (benefit) $13,472
 $58,934
 $(59,923)


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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. INCOME TAXES

Total income taxes differed from the amounts computed by applying the statutory income tax rate to income (loss) before income taxes. The sources of these differences are as follows:
 Year Ended December 31,
thousands except percentages202020192018
Income (loss) before income taxes$522,850$821,172$689,588
Statutory tax rate0 %0 %0 %
Tax computed at statutory rate$0 $0 $0 
Adjustments resulting from:
Federal taxes on pre-acquisition income attributable to assets acquired from Anadarko08,33254,243
State taxes on pre-acquisition income attributable to assets acquired from Anadarko (net of federal benefit)001,745
Texas margin tax expense (benefit)5,9985,1402,946
Income tax expense (benefit)$5,998$13,472$58,934
Effective tax rate1 %2 %9 %
  Year Ended December 31,
thousands except percentages 2019 2018 2017
Income (loss) before income taxes $821,172
 $689,588
 $677,462
Statutory tax rate —% —% — %
Tax computed at statutory rate $—
 $—
 $—
Adjustments resulting from:      
U.S. federal tax reform —
 —
 (87,306)
Federal taxes on pre-acquisition income attributable to assets acquired from Anadarko 8,332
 54,243
 22,353
State taxes on pre-acquisition income attributable to assets acquired from Anadarko (net of federal benefit) —
 1,745
 164
Texas margin tax expense (benefit) 5,140
 2,946
 4,866
Income tax expense (benefit) $13,472
 $58,934
 $(59,923)
Effective tax rate 2% 9% (9)%



WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


7. INCOME TAXES (CONTINUED)

The tax effects of temporary differences that give rise to significant portions of deferred tax assets (liabilities) are as follows:
 December 31,
thousands20202019
Depreciable property$(22,061)$(18,642)
Other intangible assets(812)(678)
Other678 421 
Net long-term deferred income tax liabilities$(22,195)$(18,899)
  December 31,
thousands 2019 2018
Depreciable property $(18,642) $(280,377)
Credit carryforwards —
 497
Other intangible assets (678) (299)
Other 421
 162
Net long-term deferred income tax liabilities $(18,899) $(280,017)


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8.
WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. PROPERTY, PLANT, AND EQUIPMENT

A summary of the historical cost of property, plant, and equipment is as follows:
December 31,
thousandsEstimated Useful Life20202019
LandN/A$9,696 $9,495 
Gathering systems – pipelines30 years5,231,212 5,092,004 
Gathering systems – compressors15 years2,096,905 1,929,377 
Processing complexes and treating facilities25 years3,424,368 3,237,801 
Transportation pipeline and equipment6 to 45 years168,205 173,572 
Produced-water disposal systems20 years831,719 754,774 
Assets under constructionN/A176,834 486,584 
Other3 to 40 years702,806 672,064 
Total property, plant, and equipment12,641,745 12,355,671 
Less accumulated depreciation3,931,800 3,290,740 
Net property, plant, and equipment$8,709,945 $9,064,931 
    December 31,
thousands Estimated Useful Life 2019 2018
Land n/a $9,495
 $5,298
Gathering systems – pipelines 30 years 5,092,004
 4,764,099
Gathering systems – compressors 15 years 1,929,377
 1,712,939
Processing complexes and treating facilities 25 years 3,237,801
 2,844,337
Transportation pipeline and equipment 6 to 45 years 173,572
 172,558
Produced-water disposal systems 20 years 754,774
 629,946
Assets under construction n/a 486,584
 604,265
Other 3 to 40 years 672,064
 525,331
Total property, plant, and equipment   12,355,671
 11,258,773
Less accumulated depreciation   3,290,740
 2,848,420
Net property, plant, and equipment 
 $9,064,931
 $8,410,353


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

Impairments.Long-lived asset and other impairments. During the year ended December 31, 2020, the Partnership recognized impairments of $203.9 million, primarily due to $150.2 million of impairments for assets located in Wyoming and Utah. These assets were impaired to estimated fair values of $105.5 million. The Partnership assesses whether events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. The fair value of assets with impairment triggers were measured using the income approach and Level-3 fair value inputs. The income approach was based on the Partnership’s projected future EBITDA and free cash flows, which requires significant assumptions including, among others, future throughput volumes based on current expectations of producer activity and operating costs. These impairments were primarily triggered by reductions in estimated future cash flows resulting from lower forecasted producer throughput and lower commodity prices. Long-lived asset and other impairments on the consolidated statements of operations for the year ended December 31, 2020, also includes a $29.4 million other-than-temporary impairment of the Partnership’s investment in Ranch Westex (see Note 7). The remaining impairments of $24.3 million were primarily at the DJ Basin complex and DBM oil system due to the cancellation of projects and impairments of rights-of-way.
During the year ended December 31, 2019, the Partnership recognized impairments of $6.3 million, primarily at the DJ Basin complex due to impairments of rights-of-way and cancellation of projects.
During the year ended December 31, 2018, the Partnership recognized impairments of $230.6 million,, including impairments of $125.9 million at the Third Creek gathering system and $8.1 million at the Kitty Draw gathering system. These assets were impaired to estimated salvage values of $1.8 million and 0, respectively, using the market approach and Level-3 fair value inputs, due to the shutdown of these systems in May 2018. During 2018, the Partnership also recognized impairments of $38.7 million and $34.6 million at the Hilight and MIGC systems, respectively. These assets were impaired to estimated fair values of $4.9 million and $15.2 million, respectively, using the income approach and Level-3 fair value inputs, due to a reduction in estimated future cash flows. The remaining $23.3 million of impairments primarily was related to (i) a $10.9 million impairment at the GNB NGL pipeline, which was impaired to estimated fair value of $10.0 million using the income approach and Level-3 fair value inputs, and (ii) a $5.6 million impairment related to an idle facility at the Chipeta complex, which was impaired to estimated salvage value of $1.5 million using the market approach and Level-3 fair value inputs.


151
Table of Contents


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


8.9. PROPERTY, PLANT, AND EQUIPMENT (CONTINUED)

During the year endedPotential future long-lived asset impairments. As of December 31, 2017,2020, it is reasonably possible that prolonged low 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. For example, on April 29, 2020, the Partnership recognized impairmentsreceived notice that Sanchez is attempting to reject a number of $180.1 million,midstream and downstream agreements with commercial counterparties, including an impairment of $158.8 million atSanchez’s Springfield gathering agreements and agreements obligating Sanchez to deliver the Granger complex, which was impairedgas volumes gathered by the Springfield system to estimated fair value of $48.5 million usingour Brasada processing plant. If the income approach and Level-3 fair value inputs, due to a reduced throughput fee as a result of a producer’s bankruptcy. The remaining $21.3 million of impairments primarily was related to (i) an $8.2 million impairment due toattempted rejection is successful, the cancellation of a plant project at the Hilight system, (ii) a $3.7 million impairment at the Granger straddle plant, which was impaired to estimated salvage value of $0.6 million using the income approach and Level-3 fair value inputs, (iii) a $3.1 million impairment of the Fort Union equity investment, (iv) a $2.0 million impairment of an idle facility in northeast Wyoming, which was impaired to estimated salvage value of $0.4 million using the market approach and Level-3 fair value inputs, and (v) the cancellation of a pipeline project in West Texas.Partnership’s South Texas assets could be impaired.

9.10. GOODWILL AND OTHER INTANGIBLES

Goodwill. Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets. In addition, goodwill representsGoodwill also includes the allocated historic carrying value of midstream goodwill attributed to the Partnership’s assets previously acquired from Anadarko. The Partnership’s goodwill has been allocated to 2 reporting units: (i) gathering and processing and (ii) transportation.
The Partnership evaluates goodwill for impairment at the reporting-unit level on an annual basis, 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 Anadarko’s midstreamthe reporting unit, including goodwill, atexceeds its fair value, a goodwill impairment is recorded for the timeamount by which the assets were acquired from Anadarko, representedreporting unit’s carrying value exceeds its fair value.
During the excessthree months ended March 31, 2020, the Partnership performed an interim goodwill impairment test due to a significant decline in the trading price of the purchase price paid to a third party overPartnership’s common units, triggered by the estimated fair value of the identifiable assets acquired and liabilities assumed by Anadarko. Accordingly, the Partnership’s allocated goodwill balance does not represent, and in some cases is significantly differentcombined impacts from the difference betweenglobal outbreak of COVID-19 and the considerationoil-market disruption resulting from significantly lower global demand and corresponding oversupply of crude oil. The Partnership primarily used the Partnership paid for its acquisitions from Anadarkomarket approach and Level-3 inputs to estimate the fair value of such net assetsits two reporting units. The market approach was based on their respectivemultiples of EBITDA and the Partnership’s projected future EBITDA. The EBITDA multiples were based on current and historic multiples for comparable midstream companies of similar size and business profit to the Partnership. The EBITDA projections require significant assumptions including, among others, future throughput volumes based on current expectations of producer activity and operating costs. The reasonableness of the market approach was tested against an income approach that was based on 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. The Partnership 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 dates.premium. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the valuations. As a result of the interim impairment test, the Partnership 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 0. Goodwill allocated to the transportation reporting unit of $4.8 million as of March 31, 2020, was not impaired.
Goodwill is evaluated for impairment annually (see Note 1). The Partnership’s annual qualitative goodwill impairment assessment as of October 1, 2019,2020, indicated 0no further impairment. Qualitative factors also were assessed in the fourth quarter of 20192020 to review any changes in circumstances subsequent to the annual test. This assessment also indicated no impairment.

Other intangible assets. The other intangible assetassets balance on the consolidated balance sheets includes the fair value, net of amortization, ofprimarily related to (i) contracts assumed in connection with the Platte Valley and Wattenberg processing plant acquisitions in 2011, which are being amortized on a straight-line basis over 38 years (ii) interconnect agreements at Chipeta entered into in November 2012, which are being amortized on a straight-line basis over 10 years, and (iii)(ii) contracts assumed in connection with the DBM acquisition in November 2014, which are being amortized on a straight-line basis over 30 years.
The Partnership assesses other intangible assets for impairment together with related underlying long-lived assets whenever events or changes in circumstances indicate that the carrying amountvalue of an asset may not be recoverable. See Property, plant, and equipment and other intangible assets in Note 1 for further discussion of management’s process to evaluate potential impairment of long-lived assets. NaN intangible asset impairment has been recognized in these consolidated financial statements.
The following table presents the gross carrying amount and accumulated amortization
152
Table of other intangible assets:Contents
  December 31,
thousands 2019 2018
Gross carrying amount $979,863
 $979,863
Accumulated amortization (170,472) (138,455)
Other intangible assets $809,391
 $841,408


Amortization expense for intangible assets was $32.0 million, $30.8 million, and $30.7 million for the years ended December 31, 2019, 2018, and 2017, respectively. Intangible asset amortization recorded in each of the next five years is estimated to be $32.0 million for the years ended December 31, 2020 to December 31, 2022, and $31.7 million for the years ended December 31, 2023 and 2024.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


10. EQUITY INVESTMENTSGOODWILL AND OTHER INTANGIBLES

The following tables presenttable presents the equity-investments activitygross carrying value and accumulated amortization of other intangible assets:
December 31,
thousands20202019
Gross carrying value$979,863 $979,863 
Accumulated amortization(203,454)(170,472)
Other intangible assets$776,409 $809,391 

Amortization expense for intangible assets was $33.0 million, $32.0 million, and $30.8 million for the years ended December 31, 2020, 2019, and 2018:2018, respectively. Intangible asset amortization to be recorded in each of the next five years is estimated to be $31.7 million for the years ended December 31, 2021 to December 31, 2025.

11. SELECTED COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:
The PartnershipWES Operating
December 31,December 31,
thousands2020201920202019
Trade receivables, net$452,718 $260,458 $407,547 $260,694 
Other receivables, net162 54 2 54 
Total accounts receivable, net$452,880 $260,512 $407,549 $260,748 

A summary of other current assets is as follows:
The PartnershipWES Operating
December 31,December 31,
thousands2020201920202019
NGLs inventory$882 $906 $882 $906 
Materials and supplies inventory (1)
0 23,444 0 23,444 
Imbalance receivables12,976 4,690 12,976 4,690 
Prepaid insurance8,131 5,676 6,113 3,652 
Contract assets5,338 7,129 5,338 7,129 
Other17,935 93 17,935 93 
Total other current assets$45,262 $41,938 $43,244 $39,914 

(1)See Note 1.

153
thousands Balance at December 31, 2017 Acquisitions 
Equity
income, net
 
Contributions (1)
 Distributions 
Distributions in
excess of
cumulative
earnings (2)
 Balance at December 31, 2018
Fort Union $7,030
 $—
 $(1,433) $—
 $(194) $(3,144) $2,259
White Cliffs 44,945
 —
 11,841
 1,278
 (11,259) (3,785) 43,020
Rendezvous 42,528
 —
 767
 —
 (2,709) (2,745) 37,841
Mont Belvieu JV 110,299
 —
 29,200
 —
 (29,239) (5,311) 104,949
TEG 15,879
 —
 4,290
 3,720
 (4,368) (163) 19,358
TEP 178,975
 —
 37,963
 11,980
 (33,552) (2,168) 193,198
FRP 166,555
 —
 23,308
 14,980
 (23,481) (4,926) 176,436
Whitethorn LLC —
 150,563
 47,088
 7,069
 (39,497) (3,365) 161,858
Cactus II —
 12,052
 —
 94,308
 —
 —
 106,360
Saddlehorn 109,227
 —
 15,833
 294
 (16,017) (830) 108,507
Panola 23,625
 —
 2,200
 —
 (2,200) (856) 22,769
Mi Vida 64,988
 —
 13,734
 —
 (14,000) (91) 64,631
Ranch Westex 53,301
 —
 10,678
 —
 (10,876) (2,201) 50,902
Total $817,352
 $162,615
 $195,469
 $133,629
 $(187,392) $(29,585) $1,092,088
Table of Contents
thousands Balance at December 31, 2018 Acquisitions 
Equity
income, net
 
Contributions (1)
 Distributions 
Distributions in
excess of
cumulative
earnings (2)
 Balance at December 31, 2019
Fort Union $2,259
 $—
 $(2,232) $—
 $—
 $(637) $(610)
White Cliffs 43,020
 —
 9,500
 5,414
 (8,918) (3,139) 45,877
Rendezvous 37,841
 —
 769
 —
 (2,710) (2,936) 32,964
Mont Belvieu JV 104,949
 —
 28,412
 —
 (28,451) (1,874) 103,036
TEG 19,358
 —
 4,088
 —
 (4,110) (1,137) 18,199
TEP 193,198
 —
 30,871
 12,220
 (32,733) —
 203,556
FRP 176,436
 —
 32,617
 30,175
 (31,446) —
 207,782
Whitethorn LLC 161,858
 —
 74,548
 10,332
 (74,856) (10,217) 161,665
Cactus II 106,360
 —
 10,755
 56,252
 (1,202) —
 172,165
Saddlehorn 108,507
 —
 25,524
 3,550
 (24,726) —
 112,855
Panola 22,769
 —
 2,136
 —
 (2,137) (985) 21,783
Mi Vida 64,631
 —
 10,655
 —
 (12,077) (5,402) 57,807
Ranch Westex 50,902
 —
 6,812
 —
 (8,143) (2,893) 46,678
Red Bluff Express —
 92,546
 3,063
 10,450
 (3,063) (1,036) 101,960
Total $1,092,088
 $92,546
 $237,518
 $128,393
 $(234,572) $(30,256) $1,285,717
(1)
Includes capitalized interest of $1.4 million and $3.6 million for the years ended December 31, 2018 and 2019, respectively, related to the construction of the Cactus II pipeline.
(2)
Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, are calculated on an individual-investment basis.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


10. EQUITY INVESTMENTS (CONTINUED)

The investment balance in Fort Union at December 31, 2019, is $3.1 million less than the Partnership’s underlying equity in Fort Union’s net assets due to an impairment loss recognized by the Partnership in 2017 for its investment in Fort Union.
The investment balance in Rendezvous at December 31, 2019, includes $32.4 million for the purchase price allocated to the investment in Rendezvous in excess of the historic cost basis of WGRI, the entity that previously owned the interest in Rendezvous, which Anadarko acquired in August 2006. This excess balance is attributable to the difference between the fair value and book value of such gathering and treating facilities (at the time WGRI was acquired by Anadarko) and is being amortized to Equity income, net – affiliates over the remaining estimated useful life of those facilities.
The investment balance in White Cliffs at December 31, 2019, is $5.8 million less than the Partnership’s underlying equity in White Cliffs’ net assets, primarily due to the Partnership recording the acquisition of its initial 0.4% interest in White Cliffs at Anadarko’s historic carrying value. This difference is being amortized to Equity income, net – affiliates over the remaining estimated useful life of the White Cliffs pipeline.
The investment balance in Whitethorn LLC at December 31, 2019, is $37.3 million less than the Partnership’s underlying equity in Whitethorn LLC’s net assets, primarily due to terms of the acquisition agreement which provided the Partnership a share of pre-acquisition operating cash flow. This difference is being amortized to Equity income, net – affiliates over the remaining estimated useful life of Whitethorn.
Management evaluates its equity investments for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value that is other than temporary. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether the investment has been impaired. Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss.
The following tables present the summarized combined financial information for equity investments (amounts represent 100% of investee financial information):
  Year Ended December 31,
thousands 2019 2018 2017
Revenues $1,687,116
 $1,300,921
 $877,020
Operating income 1,107,664
 876,910
 542,390
Net income 1,108,173
 874,587
 540,538
  December 31,
thousands 2019 2018
Current assets $433,390
 $297,143
Property, plant, and equipment, net 5,754,160
 4,251,020
Other assets 175,231
 81,769
Total assets $6,362,781
 $4,629,932
Current liabilities 223,171
 $101,729
Non-current liabilities 27,024
 42,431
Equity 6,112,586
 4,485,772
Total liabilities and equity $6,362,781
 $4,629,932



WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


11. SELECTED COMPONENTS OF WORKING CAPITAL

A summary of accounts receivable, net is as follows:
  The Partnership WES Operating
  December 31, December 31,
thousands 2019 2018 2019 2018
Trade receivables, net $260,458
 $221,119
 $260,694
 $221,328
Other receivables, net 54
 45
 54
 45
Total accounts receivable, net $260,512
 $221,164
 $260,748
 $221,373


A summary of other current assets is as follows:
  The Partnership WES Operating
  December 31, December 31,
thousands 2019 2018 2019 2018
NGLs inventory $906
 $1,203
 $906
 $1,203
Materials and supplies inventory 23,444
 9,665
 23,444
 9,665
Imbalance receivables 4,690
 9,035
 4,690
 9,035
Prepaid insurance 5,676
 1,972
 3,652
 1,972
Contract assets 7,129
 5,399
 7,129
 5,399
Other 93
 4,184
 93
 3,309
Total other current assets $41,938
 $31,458
 $39,914
 $30,583


A summary of accrued liabilities is as follows:
The PartnershipWES Operating
December 31,December 31,
thousands2020201920202019
Accrued interest expense$137,307 $72,064 $137,307 $72,064 
Short-term asset retirement obligations20,215 22,472 20,215 22,472 
Short-term remediation and reclamation obligations2,950 3,528 2,950 3,528 
Income taxes payable3,399 697 3,399 697 
Contract liabilities31,477 19,659 31,477 19,659 
Other (1)
74,599 31,373 35,485 31,219 
Total accrued liabilities$269,947 $149,793 $230,833 $149,639 

(1)As of December 31, 2019, includes amounts related to WES Operating’s interest-rate swap agreements and lease liabilities related to the implementation of ASU 2016-02, Leases (Topic 842) (see Note 13 and Note 14).
  The Partnership WES Operating
  December 31, December 31,
thousands 2019 2018 2019 2018
Accrued interest expense $72,064
 $70,968
 $72,064
 $70,959
Short-term asset retirement obligations 22,472
 25,938
 22,472
 25,938
Short-term remediation and reclamation obligations 3,528
 863
 3,528
 863
Income taxes payable 697
 384
 697
 384
Contract liabilities 19,659
 16,235
 19,659
 16,235
Other (1)
 31,373
 14,760
 31,219
 13,495
Total accrued liabilities $149,793
 $129,148
 $149,639
 $127,874

(1)
Includes amounts related to WES Operating’s interest-rate swap agreements as of December 31, 2019 and 2018 (see Note 13). Includes lease liabilities related to the implementation of ASU 2016-02, Leases (Topic 842) as of December 31, 2019 (see Note 1).


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


12. ASSET RETIREMENT OBLIGATIONS

The following table provides a summary of changes in asset retirement obligations:
 Year Ended December 31,
thousands20202019
Carrying amount of asset retirement obligations at beginning of year$358,868 $325,962 
Liabilities incurred9,565 27,360 
Liabilities settled(20,418)(17,104)
Accretion expense15,070 13,599 
Revisions in estimated liabilities(82,587)9,051 
Carrying amount of asset retirement obligations at end of year$280,498 $358,868 
  Year Ended December 31,
thousands 2019 2018
Carrying amount of asset retirement obligations at beginning of year $325,962
 $154,571
Liabilities incurred 27,360
 34,558
Liabilities settled (17,104) (12,432)
Accretion expense 13,599
 7,909
Revisions in estimated liabilities 9,051
 141,356
Carrying amount of asset retirement obligations at end of year $358,868
 $325,962


Revisions in estimated liabilities for the year ended December 31, 2020, primarily related to a reduction in expected settlement costs across several of the Partnership’s assets, with the largest decreases at the Third Creek gathering system, DJ Basin complex, Hilight system, and West Texas complex.
The liabilitiesLiabilities incurred for the year ended December 31, 2019, represented additions in asset retirement obligations primarily due to capital expansions at the West Texas and DJ Basin complexes. Revisions in estimated liabilities for the year ended December 31, 2019, primarily related to (i) changes in expected settlement costs at the West Texas and DJ Basin complexes and (ii) changes to the expected abandonment timing of transportation assets in Wyoming.
154
The liabilities incurred for the year ended December 31, 2018, represented additions in asset retirement obligations primarily due to capital expansions at the West Texas and DJ Basin complexes, the DBM water systems, and the DBM oil system. Revisions in estimated liabilities for the year ended December 31, 2018, primarily included (i) $71.8 million related to changes in expected settlement costs and timing, primarily at the DJ Basin and West Texas complexes and the MGR assets, and (ii) $43.4 million related to the shutdownTable of the Third Creek gathering system during the second quarter of 2018. See Note 1 for further information.Contents


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


13. DEBT AND INTEREST EXPENSE

WES Operating is the borrower for all outstanding debt excluding the WGP RCF, and is expected to be the borrower for all future debt issuances. The following table presents the outstanding debt:
 December 31, 2020December 31, 2019
thousandsPrincipalCarrying
Value
Fair
Value (1)
PrincipalCarrying
Value
Fair
Value (1)
Short-term debt
5.375% Senior Notes due 2021$431,081 $430,606 $436,241 $— $— $— 
Finance lease liabilities (2)
8,264 8,264 8,264 7,873 7,873 7,873 
Total short-term debt$439,345 $438,870 $444,505 $7,873 $7,873 $7,873 
Long-term debt
5.375% Senior Notes due 2021$— $— $— $500,000 $498,168 $515,042 
4.000% Senior Notes due 2022580,917 580,555 597,568 670,000 669,322 689,784 
Floating-Rate Senior Notes due 2023239,978 238,879 235,066 0 0 0 
3.100% Senior Notes due 20251,000,000 992,900 1,028,614 0 0 0 
3.950% Senior Notes due 2025500,000 494,866 512,807 500,000 493,830 504,968 
4.650% Senior Notes due 2026500,000 496,708 524,880 500,000 496,197 513,393 
4.500% Senior Notes due 2028400,000 395,617 415,454 400,000 395,113 390,920 
4.750% Senior Notes due 2028400,000 396,555 418,786 400,000 396,190 400,962 
4.050% Senior Notes due 20301,200,000 1,189,407 1,342,996 0 0 0 
5.450% Senior Notes due 2044600,000 593,598 607,234 600,000 593,470 533,710 
5.300% Senior Notes due 2048700,000 687,048 694,172 700,000 686,843 610,841 
5.500% Senior Notes due 2048350,000 342,543 343,928 350,000 342,432 310,198 
5.250% Senior Notes due 20501,000,000 983,512 1,100,375 0 0 0 
RCF0 0 0 380,000 380,000 380,000 
Term loan facility0 0 0 3,000,000 3,000,000 3,000,000 
Finance lease liabilities23,644 23,644 23,644 0 0 0 
Total long-term debt$7,494,539 $7,415,832 $7,845,524 $8,000,000 $7,951,565 $7,849,818 

(1)Fair value is measured using the market approach and Level-2 fair value inputs.
(2)Includes related-party amounts as of December 31, 2019.
155
  December 31, 2019 December 31, 2018
thousands Principal 
Carrying
Value
 
Fair
Value (1)
 Principal 
Carrying
Value
 
Fair
Value (1)
Short-term debt            
WGP RCF $—
 $—
 $—
 $28,000
 $28,000
 $28,000
Finance lease liabilities (2)
 7,873
 7,873
 7,873
 —
 —
 —
Total short-term debt $7,873
 $7,873
 $7,873
 $28,000
 $28,000
 $28,000
             
Long-term debt            
5.375% Senior Notes due 2021 $500,000
 $498,168
 $515,042
 $500,000
 $496,959
 $515,990
4.000% Senior Notes due 2022 670,000
 669,322
 689,784
 670,000
 669,078
 662,109
3.950% Senior Notes due 2025 500,000
 493,830
 504,968
 500,000
 492,837
 466,135
4.650% Senior Notes due 2026 500,000
 496,197
 513,393
 500,000
 495,710
 483,994
4.500% Senior Notes due 2028 400,000
 395,113
 390,920
 400,000
 394,631
 377,475
4.750% Senior Notes due 2028 400,000
 396,190
 400,962
 400,000
 395,841
 384,370
5.450% Senior Notes due 2044 600,000
 593,470
 533,710
 600,000
 593,349
 522,386
5.300% Senior Notes due 2048 700,000
 686,843
 610,841
 700,000
 686,648
 605,327
5.500% Senior Notes due 2048 350,000
 342,432
 310,198
 350,000
 342,328
 311,536
RCF 380,000
 380,000
 380,000
 220,000
 220,000
 220,000
Term loan facility 3,000,000
 3,000,000
 3,000,000
 —
 —
 —
APCWH Note Payable —
 —
 —
 427,493
 427,493
 427,493
Total long-term debt $8,000,000
 $7,951,565
 $7,849,818
 $5,267,493
 $5,214,874
 $4,976,815
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(1)
Fair value is measured using the market approach and Level-2 fair value inputs.
(2)
Amounts are considered affiliate. See Note 14.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


13. DEBT AND INTEREST EXPENSE (CONTINUED)

Debt activity. The following table presents the debt activity for the years ended December 31, 20192020 and 2018:2019:
thousandsCarrying Value
Balance at December 31, 2018$5,242,874 
RCF borrowings1,160,000 
Term loan facility borrowings3,000,000 
APCWH Note Payable borrowings11,000 
Finance lease liabilities7,873 
Repayments of RCF borrowings(1,000,000)
Repayment of WGP RCF borrowings(28,000)
Repayment of APCWH Note Payable(439,595)
Other5,286 
Balance at December 31, 2019$7,959,438 
RCF borrowings220,000
Issuance of Floating-Rate Senior Notes due 2023300,000
Issuance of 3.100% Senior Notes due 20251,000,000
Issuance of 4.050% Senior Notes due 20301,200,000
Issuance of 5.250% Senior Notes due 20501,000,000
Finance lease liabilities24,035
Repayments of RCF borrowings(600,000)
Repayment of Term loan facility borrowings(3,000,000)
Repayment of 5.375% Senior Notes due 2021(68,919)
Repayment of 4.000% Senior Notes due 2022(89,083)
Repayment of Floating-Rate Senior Notes due 2023(60,022)
Other(30,747)
Balance at December 31, 2020$7,854,702
thousands Carrying Value
Balance at December 31, 2017 $3,591,678
RCF borrowings 540,000
APCWH Note Payable borrowings 321,780
Issuance of 4.500% Senior Notes due 2028 400,000
Issuance of 5.300% Senior Notes due 2048 700,000
Issuance of 4.750% Senior Notes due 2028 400,000
Issuance of 5.500% Senior Notes due 2048 350,000
Repayment of 2.600% Senior Notes due 2018 (350,000)
Repayments of RCF borrowings (690,000)
Other (20,584)
Balance at December 31, 2018 $5,242,874
RCF borrowings 1,160,000
Term loan facility borrowings 3,000,000
APCWH Note Payable borrowings 11,000
Finance lease liabilities 7,873
Repayments of RCF borrowings (1,000,000)
Repayment of WGP RCF borrowings (28,000)
Repayment of APCWH Note Payable (439,595)
Other 5,286
Balance at December 31, 2019 $7,959,438


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 (collectively referred to as the “Fixed-Rate Senior Notes”). 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 (the “Floating-Rate Senior Notes”). 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 London Interbank Offered Rate) on the interest determination date plus an initial spread of 0.85%.

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13. DEBT AND INTEREST EXPENSE

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. In 2020, Fitch Ratings and Standard and Poor’s downgraded WES Operating’s long-term debt from “BBB-” to “BB” and Moody’s Investors Service downgraded WES Operating’s long-term debt from “Ba1” to “Ba2.” As a result of these downgrades, annualized borrowing costs will increase by $43.0 million.
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, 2019,2020, WES Operating was in compliance with all covenants under the relevant governing indentures.

WGP RCF. In February 2018, the Partnership voluntarily reduced the aggregate commitment of lenders under the WGP RCF to $35.0 million. The WGP RCF,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 the London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from 0zero 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.
As of December 31, 2019,2020, there were $380.0 million of0 outstanding borrowings and $4.6$5.1 million of outstanding letters of credit, resulting in $1.6$2.0 billion of available borrowing capacity under the RCF. As of December 31, 20192020 and 2018,2019, the interest rate on any outstanding RCF borrowings was 3.04%1.64% and 3.74%3.04%, respectively. The facility feefacility-fee rate was 0.25% and 0.20% at December 31, 2020 and 2019, and 2018.respectively. At December 31, 2019,2020, WES Operating was in compliance with all covenants under the RCF.

As a result of credit-rating downgrades (see WES Operating Senior Notes above), 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%.

WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


13. DEBT AND INTEREST EXPENSE (CONTINUED)

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). The Term loan facility bears interest at LIBOR, plus applicable margins ranging from 1.000% to 1.625%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case as defined in the Term loan facility and plus applicable margins currently ranging from 0 to 0.625%, based on WES Operating’s senior unsecured debt rating. Net cash proceeds received from future asset sales and debt or equity offerings must be used to repay amounts outstanding under the facility.
In July 2019, WES Operating entered into an amendment to the Term loan facility to (i) extend the maturity date from February 2020 to December 2020, (ii) increase commitments available under the Term loan facility from $2.0 billion to $3.0 billion, the incremental $1.0 billion of which was subsequently drawn by WES Operating on September 13, 2019, and used to repay outstanding borrowings under the RCF, and (iii) modify the provision requiring that all debt issuance proceeds be used to repay the Term loan facility to allow for a $1.0 billion exclusion for debt-offering proceeds.
As of December 31, 2019, there were $3.0 billion ofthe interest rate on the outstanding borrowings under the Term loan facility that were subject to an interest rate ofwas 3.10%. WES Operating was in compliance with all covenants under the Term loan facility as of December 31, 2019. The outstanding borrowings under the Term loan facility were classified as Long-term debt on the consolidated balance sheet at December 31, 2019. In January 2020, WES Operating repaid the outstanding borrowings under the Term loan facility with proceeds from the issuance of the Fixed-Rate Senior Notes and Floating RateFloating-Rate Senior Notes and terminated the Term loan facility (see Note 16).

Prior to December 31, 2019, WES Operating GPSenior Notes above). During the first quarter of 2020, a loss of $2.3 million was indemnified by wholly owned subsidiariesrecognized for the early termination of Occidental against any claims made against WES Operating GP for WES Operating’s long-term debt and/or borrowings under the RCF and Term loan facility. These indemnification agreements were terminated as part




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. DEBT AND INTEREST EXPENSE

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, which was payable at maturity at the applicable mid-term federal rate based on a quarterly compounding basis as determined by the U.S. Secretary of the Treasury. As of December 31, 2018, the interest rate on the outstanding borrowings was 3.04%.interest. The APCWH Note Payable was repaid at Merger completion. See Note 1.

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. Pursuant to these swap agreements, WES Operating received a fixed interest rate and paid a floating interest rate indexed to the three-month LIBOR,million, effectively offsetting the swap agreements entered into in December 2018 and March 2019.
In December 2019, all outstanding interest-rate swap agreements were cash-settled.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 statementstatements of cash flows.


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


13. DEBT AND INTEREST EXPENSE (CONTINUED)

The Partnership did not apply hedge accounting and, therefore, gains and losses associated with the interest-rate swap agreements were recognized in earnings. For the yearsyear ended December 31, 2019, and 2018, netnon-cash losses of $125.3 million and $8.0 million, respectively, were recognized, which are included in Other income (expense), net in the consolidated statements of operations.
Valuation of the interest-rate swaps was based on similar transactions observable in active markets and industry standard models that primarily rely on market-observable inputs. Inputs used to estimate fair value in industry standard models are categorized as Level-2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. Inputs used to estimate the fair value include market price curves, contract terms and prices, and credit risk adjustments. The fair value of the interest-rate swaps was a liability of $8.0 million at December 31, 2018, which is reported within Accrued liabilities on the consolidated balance sheets.

Interest expense. The following table summarizes the amounts included in interest expense:
Year Ended December 31,
thousands202020192018
Third parties
Long-term and short-term debt$(369,815)$(315,872)$(200,454)
Finance lease liabilities(1,510)0 0 
Amortization of debt issuance costs and commitment fees(13,501)(12,424)(9,110)
Capitalized interest4,774 26,980 32,479 
Total interest expense – third parties(380,052)(301,316)(177,085)
Related parties
APCWH Note Payable0 (1,833)(6,746)
Finance lease liabilities(6)(137)0 
Total interest expense – related parties(6)(1,970)(6,746)
Interest expense$(380,058)$(303,286)$(183,831)
  Year Ended December 31,
thousands 2019 2018 2017
Third parties      
Long-term and short-term debt $(315,872) $(200,454) $(143,400)
Amortization of debt issuance costs and commitment fees (12,424) (9,110) (7,970)
Capitalized interest 26,980
 32,479
 9,074
Total interest expense – third parties (301,316) (177,085) (142,296)
Affiliates      
APCWH Note Payable (1,833) (6,746) (153)
Finance lease liabilities (137) —
 —
Deferred purchase price obligation – Anadarko —
 —
 (71)
Total interest expense – affiliates (1,970) (6,746) (224)
Interest expense $(303,286) $(183,831) $(142,520)



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


14. LEASES

The Partnership adopted ASU 2016-02, Leases (Topic 842) on January 1, 2019, using the modified retrospective method applied to all leases in existence on January 1, 2019, and prior-period financial statements were not adjusted. The Partnership elected not to reassess contracts that commenced prior to adoption, to continue applying its current accounting policy for existing or expired land easements, and not to recognize ROU assets or lease liabilities for short-term leases.

Lessee. The Partnership has entered into operating leases that extend through 20282039 for corporate offices, shared field offices, easements, and equipment supporting the Partnership’s operations, with both Occidental and third parties as lessors. The Partnership also hashad subleased equipment from Occidental via finance leases extendingthat extended through April 2020. During the first quarter of 2020, the Partnership entered into finance leases with third parties for equipment and vehicles extending through 2029.
The following table summarizes information related to the Partnership’s leases:
December 31,
20202019
thousands except lease term and discount rateOperating LeasesFinance LeasesOperating LeasesFinance Leases
Assets
Other assets$38,985 $— $3,985 $— 
Net property, plant, and equipment— 31,487 — 7,892 
Total lease assets (1)
$38,985 $31,487 $3,985 $7,892 
Liabilities
Accrued liabilities$3,958 $— $1,805 $— 
Short-term debt— 8,264 — 7,873 
Other liabilities34,843 — 3,035 — 
Long-term debt— 23,644 — 0 
Total lease liabilities (1)
$38,801 $31,908 $4,840 $7,873 
Weighted-average remaining lease term (years)975— 
Weighted-average discount rate (%)5.1 4.3 4.7 2.9 

(1)Includes additions to ROU assets and lease liabilities of $39.7 million and $8.5 million related to finance leases atfor the year ended December 31, 2019:2020 and 2019, respectively. Includes additions to ROU assets and lease liabilities of $40.5 million related to operating leases for the year ended December 31, 2020.
thousands except lease term and discount rate Operating Leases Finance Leases
Assets    
Other assets $3,985
 $—
Net property, plant, and equipment —
 7,892
Total lease assets (1)
 $3,985
 $7,892
     
Liabilities 
  
Accrued liabilities $1,805
 $—
Short-term debt —
 7,873
Other liabilities 3,035
 —
Total lease liabilities (1)
 $4,840
 $7,873
     
Weighted-average remaining lease term (years) 5
 —
Weighted-average discount rate 4.7% 2.9%

    
(1)
Includes additions to ROU assets and lease liabilities of $8.5 million related to finance leases for the year ended December 31, 2019.

Lease expense charged to the Partnership was $56.5 million and $45.5 million for the yearsyear ended December 31, 2018 and 2017, respectively.2018. The following table summarizes the Partnership’s lease cost for the year ended December 31, 2019:cost:
Year Ended December 31,
thousands20202019
Operating lease cost$7,702 $6,932 
Short-term lease cost43,102 1,295 
Variable lease cost(46)256 
Sublease income(414)(414)
Finance lease cost
Amortization of ROU assets8,346 562 
Interest on lease liabilities1,516 137 
Total lease cost$60,206 $8,768 
thousands Year Ended 
 December 31, 2019
Operating lease cost $6,932
Short-term lease cost 1,295
Variable lease cost 256
Sublease income (414)
Finance lease cost  
Amortization of ROU assets 562
Interest on lease liabilities 137
Total lease cost $8,768
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The following table summarizes cash paid for amounts included in the measurement of lease liabilities for the year ended December 31, 2019:
thousands Operating Leases Finance Leases
Operating cash flows $7,042
 $118
Financing cash flows —
 508


WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


14. LEASES (CONTINUED)

The following table summarizes cash paid for amounts included in the measurement of lease liabilities:
Year Ended December 31,
20202019
thousandsOperating LeasesFinance LeasesOperating LeasesFinance Leases
Operating cash flows$5,750 $1,516 $7,042 $118 
Financing cash flows— 14,207 — 508 

The following table reconciles the undiscounted cash flows to the operating and finance lease liabilities at December 31, 2019:2020:
thousandsOperating LeasesFinance Leases
2021$4,042 $8,557 
20227,763 6,757 
20234,902 4,383 
20244,253 3,205 
20254,101 3,095 
Thereafter25,415 10,752 
Total lease payments50,476 36,749 
Less portion representing imputed interest11,675 4,841 
Total lease liabilities$38,801 $31,908 
thousands Operating Leases Finance Leases
2020 $1,969
 $7,934
2021 612
 —
2022 618
 —
2023 625
 —
2024 449
 —
Thereafter 1,209
 —
Total lease payments 5,482
 7,934
Less portion representing imputed interest 642
 61
Total lease liabilities $4,840
 $7,873


The amounts in the table below represent contractual operating lease commitments at December 31, 2018, that were assigned or otherwise charged to the Partnership pursuant to the reimbursement provisions of the omnibus agreement (seeLessor. Note 1):
thousands  
2019 $8,711
2020 2,236
2021 460
2022 467
2023 473
Thereafter 1,547
Total lease payments $13,894


Lessor.Effective December 31, 2019, an affiliate of Occidental and a wholly owned subsidiary of the Partnership entered into an operating and maintenance agreement pursuant to which Occidental provides operational and maintenance services with respect to a crude-oil gathering system and associated treating facilities owned by the Partnership through December 31, 2021. ThisThe agreement includesand underlying contracts include (i) fixed consideration, which is measured as the minimum-volume commitment for both gathering and treating, and (ii) variable consideration, which consists of all volumes above the minimum-volume commitment. Subsequent to the initial two-year term, the agreement provides for automatic one-year extensions, unless either party exercises its option to terminate the lease with advance notice. For the year ended December 31, 2020, the Partnership recognized fixed-lease revenue of $175.8 million and variable-lease revenue of $47.9 million related to these agreements, with such amounts included in Service revenues – fee based in the consolidated statements of operations.
The following table presents the undiscounted cash flows expected to be received for all operating leases in effect as of December 31, 2019.2020. This presentation includes minimum fixed lease payments and does not include an estimate of variable lease consideration.
thousands
2021$193,925 
20220 
20230 
20240 
20250 
Thereafter0 
Total lease payments$193,925 
thousands  
2020 $157,582
2021 193,925
2022 —
2023 —
2024 —
Thereafter —
Total lease payments $351,507


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WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15. EQUITY-BASED COMPENSATION

The 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 the Partnership in connection with the Merger) to its independent directors, executive officers, and employees. As of December 31, 2020, the WES LTIP and the Western Gas Partners, LP 2017 Long-Term Incentive Plan had 2,823,967 and 3,431,251 units, respectively, available for future issuance.
On February 10, 2020, the Board of Directors approved awards of phantom units (the “Awards”) to the Partnership’s executive officers under the WES LTIP. The Awards include (i) an award of time-vested phantom units that vest ratably over a three-year period (“Time-Based Awards”), (ii) a market award that vests after a three-year performance period based on the Partnership’s relative total unitholder return as compared to a group of peer companies (“TUR Awards”), and (iii) a performance award that vests based on the Partnership’s average return on assets over a three-year performance period (“ROA Awards”). At vesting, the number of vested units for the TUR Awards and the ROA Awards will be determined in accordance with the terms of the respective Award Agreements that provide for payout percentages ranging from 0% to 200% based on results achieved over the applicable performance period. At vesting, the Awards generally will be settled in Partnership common units. Prior to vesting, the Awards pay in-kind distributions in the form of Partnership common units. During the year ended December 31, 2020, the Partnership issued 48,070 common units as in-kind distributions under such Awards.
In addition, time-vested phantom units are awarded under the WES LTIP to non-executive employees and independent directors of the Partnership from time to time, which vest ratably over a three-year period and one year from the grant date, respectively. Prior to vesting, the awards to non-executive employees and independent directors pay distribution equivalents in cash.
The equity-based compensation expense attributable to these awards is amortized over the vesting periods applicable to the awards using the straight-line method. Expense is recognized based on the grant-date fair value and recorded, net of actual forfeitures, as General and administrative expense in the consolidated statements of operations. The fair value of the Time-Based Awards and non-executive awards is based on the observable market price of the Partnership’s units on the grant date of the award. The fair value of the TUR Awards is determined using a Monte Carlo simulation at the grant date of the award. The fair value of the ROA awards is adjusted quarterly based on the current period unit price and the estimated performance rating at vesting. For ROA Awards, all performance-related fair-value changes are recognized in compensation expense during the performance period. The total fair value of phantom units vested was $0.5 million, $1.2 million, and $0.6 million for the years ended December 31, 2020, 2019, and 2018, respectively, based on the market price at the vesting date. Compensation expense for the long-term incentive plans was $7.9 million, $1.0 million, and $0.7 million for the years ended December 31, 2020, 2019, and 2018, respectively. As of December 31, 2020, the Partnership had $16.9 million of estimated unrecognized compensation expense attributable to the WES LTIP that will be recognized over a weighted-average period of 1.6 years.
The following table summarizes time-vested award activity under the WES LTIP for the years ended December 31, 2020, 2019, and 2018:
202020192018
Time-Vested AwardsWeighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at beginning of year$0 0 $35.08 7,128 $43.39 5,763 
Granted15.49 1,442,821 29.75 25,212 35.08 7,128 
Vested9.54 (53,551)31.62 (44,572)43.39 (5,763)
Forfeited16.27 (81,664)0 0 0 0 
Converted (1)
0 0 33.46 12,232 0 0 
Non-vested units at end of year15.69 1,307,606 0 0 35.08 7,128 

(1)At closing of the Merger, WES Operating phantom units awarded under the Western Gas Partners, LP 2017 Long-Term Incentive Plan converted into phantom units of the Partnership under the WES LTIP.
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15. EQUITY-BASED COMPENSATION
15.
The following table summarizes TUR Awards and ROA Awards activity under the WES LTIP for the year ended December 31, 2020:
TUR AwardsROA Awards
Weighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at January 1, 2020$0 0 $0 0 
Granted17.79 124,067 16.27 124,067 
Forfeited17.79 (15,586)16.27 (15,586)
Non-vested units at December 31, 202017.79 108,481 17.97 108,481 

The following table summarizes award activity under the Western Gas Partners, LP 2017 Long-Term Incentive Plan for the years ended December 31, 2019 and 2018. There were no awards issued under this plan in 2020.
20192018
Weighted-Average Grant-Date Fair ValueUnitsWeighted-Average Grant-Date Fair ValueUnits
Non-vested units at beginning of year$49.88 8,020 $55.73 7,180 
Granted0 0 49.88 8,020 
Vested0 0 55.73 (7,180)
Converted (1)
49.88 (8,020)0 0 
Non-vested units at end of year0 0 49.88 8,020 

(1)At closing of the Merger, WES Operating phantom units awarded under the Western Gas Partners, LP 2017 Long-Term Incentive Plan converted into phantom units of the Partnership under the WES LTIP.

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16. COMMITMENTS AND CONTINGENCIES

Environmental obligations. The Partnership is subject to various environmental-remediation obligations arising from federal, state, and local regulations regarding air and water quality, hazardous and solid waste disposal, and other environmental matters. As of December 31, 20192020 and 2018,2019, the consolidated balance sheets included $5.4$8.2 million and $1.7$5.4 million, respectively, of liabilities for remediation and reclamation obligations. The current portion of these amounts is included in Accrued liabilities, and the long-term portion of these amounts is included in Other liabilities. The recorded obligations do not include any anticipated insurance recoveries. The majority of payments related to these obligations are expected to be made over the next five years. Management regularly monitors the remediation and reclamation process and the liabilities recorded and believes its environmental obligations are adequate to fund remedial actions required to comply with present laws and regulations, and that the ultimate liability for these matters, if any, will not differ materially from recorded amounts nor materially affect the overall results of operations, cash flows, or financial condition. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental issues will not be discovered. See Note 11 and Note 12.

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

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

16. SUBSEQUENT EVENTS

In January 2020, WES Operating issued the following notes:

$1.0 billion in aggregate principal amount of 3.100% Senior Notes due 2025, $1.2 billion in aggregate principal amount of 4.050% Senior Notes due 2030, and $1.0 billion in aggregate principal amount of 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 (collectively referred to as the “Senior Notes”). Interest is paid on each such series semi-annually on February 1 and August 1 of each year, beginning August 1, 2020; and

$300.0 million in aggregate principal amount of floating rate Senior Notes due 2023 (the “Floating Rate Notes”). Interest is paid quarterly in arrears on January 13, April 13, July 13, and October 13 of each year, beginning April 13, 2020. Interest will accrue from January 13, 2020 at a benchmark rate (which will initially be a three-month LIBOR rate) on the interest determination date plus 0.85%.

The interest payable on the Senior Notes and Floating Rate Notes will be subject to adjustment from time to time if the credit rating assigned to the notes declines below certain specified levels or if it declines and subsequently increases.
The net proceeds from the Senior Notes and Floating Rate Notes were used to repay the $3.0 billion outstanding borrowings under the Term loan facility, outstanding amounts under the RCF, and for general partnership purposes.


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WESTERN MIDSTREAM PARTNERS, LP
SUPPLEMENTAL QUARTERLY INFORMATION
(UNAUDITED)

The following table presents a summary of operating results by quarter for the years ended December 31, 2019 and 2018. Operating results reflect the operations of our assets (as defined in Note 1—Summary of Significant Accounting Policies) from the dates of common control, unless otherwise noted. See Note 1—Summary of Significant Accounting Policies and Note 3—Acquisitions and Divestitures.
thousands except per-unit amounts 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2019        
Total revenues and other $671,883
 $685,054
 $666,027
 $723,210
Equity income, net – affiliates 57,992
 63,598
 53,893
 62,035
Cost of product 114,063
 122,877
 97,800
 109,507
Operating income (loss) 318,928
 310,060
 268,725
 333,630
Net income (loss) 211,979
 175,058
 125,223
 295,440
Net income (loss) attributable to Western Midstream Partners, LP 118,660
 169,594
 121,217
 287,770
Net income (loss) per common unit – basic and diluted (1)
 0.30
 0.37
 0.27
 0.62
2018        
Total revenues and other $501,054
 $518,078
 $587,900
 $692,626
Equity income, net – affiliates 30,229
 49,430
 54,215
 61,595
Cost of product 94,318
 95,656
 101,035
 124,496
Operating income (loss) 224,867
 114,214
 257,554
 264,647
Net income (loss) 181,010
 67,167
 198,560
 183,917
Net income (loss) attributable to Western Midstream Partners, LP 131,527
 100,184
 151,357
 168,503
Net income (loss) per common unit – basic and diluted (1)
 0.46
 0.31
 0.49
 0.43
(1)
Represents net income (loss) earned on and subsequent to the date of the acquisition of assets from Anadarko.

Item 9.  Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and Chief Financial Officer of WES’s general partner and WES Operating GP (for purposes of this Item 9A, “Management”) performed an evaluation of WES’s and WES Operating’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. WES’s and WES Operating’s disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed in the reports that are filed or submitted under the Exchange Act is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, Management concluded that WES’s and WES Operating’s disclosure controls and procedures were effective as of December 31, 2019.2020.

Management’s Annual Report on Internal Control Over Financial Reporting. See Management’s Assessment of Internal Control Over Financial Reporting under Part II, Item 8 of this Form 10-K.

Attestation Report of the Registered Public Accounting Firm. See Report of Independent Registered Public Accounting Firm under Part II, Item 8 of this Form 10-K.

Changes in Internal Control Over Financial Reporting. On August 8, 2019, Anadarko, the indirect general partner and majority unitholder of WES, was acquired by Occidental pursuant to the Occidental Merger. Occidental is in the process of integrating Anadarko and its internal control processes, resulting in certain of Anadarko’s internal controls shared by WES and WES Operating being superseded by Occidental’s internal controls. With the exception of Occidental shared controls,Except as described below, there were no changes in WES’s or WES Operating’s internal control over financial reporting during the quarter ended December 31, 2019,2020, that have materially affected, or are reasonably likely to materially affect, WES’s or WES Operating’s internal control over financial reporting.

In October 2020, WES and WES Operating transitioned from Occidental’s Enterprise Resource Planning (“ERP”) system to a stand-alone ERP system. As a result of this implementation, certain processes and internal controls over financial reporting that were provided by Occidental under the Services Agreement have transitioned to WES. Information technology general controls and associated business process controls have been implemented by WES to address the new environment associated with the implementation of this system. There are inherent risks in implementing any new system, and Management will continue to evaluate these control changes as part of its assessment of internal control over financial reporting.

Item 9B.  Other Information

None.


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PART III

Item 10.  Directors, Executive Officers, and Corporate Governance

Management of Western Midstream Partners, LP

As an MLP, we have no directors or officers. Instead, our general partner manages our operations and activities. Our general partner is not elected by our unitholders and is not subject to re-election in the future. The directors of our general partner oversee our operations. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. However, our general partner owes duties to our unitholders as defined and described in our partnership agreement. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Our general partner, therefore, may cause us to incur indebtedness or other obligations that are nonrecourse to it. The officers of our general partner are also officers of WES Operating GP.
Our Board of Directors has 11eight members, fivethree of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a listed limited partnership, such as us, to have a majority of independent directors on the Board of Directors or to establish a compensation committee or a nominating committee. Our Board of Directors has affirmatively determined that Messrs. Steven D. Arnold, James R. Crane, Thomas R. Hix, Craig W. Stewart,Kenneth F. Owen and David J. TudorSchulte and Ms. Lisa A. Stewart are independent as described in the rules of the NYSE and the Exchange Act. With respect to Mr. Crane (the principal owner and Chairman of the Houston Astros Baseball Club), the Board specifically considered payments made by Occidental to Houston Astros-affiliated companies for viewing suites, concessions, sponsorship, and advertising opportunities, and contributions made by Occidental to charitable institutions affiliated with Mr. Crane. The Board determined that such transactions do not impact Mr. Crane’s independence.
The officers of our general partner are also officers of WES Operating GP. During 2019, the executive officers of our general partner allocated their time between managing our business and affairs and the business and affairs of Occidental. Following the execution of the Services Agreement on December 31, 2019, the executive officers and certain other management personnel of our general partner are employed directly by the Partnership and devote 100% of their time to our business and affairs. The remaining employees that operate our business are currently Occidental employees, but will be transferred to direct employment by the Partnership prior to the end of 2020, as required by the Services Agreement. The Services Agreement, the omnibus agreements, which were terminated on December 31, 2019, and the services and secondment agreement, which was amended and restated on December 31, 2019 by the Services Agreement, are described under Part III, Item 13 of this Form 10-K.

Board Leadership Structure

Occidental owns our general partner and, within the limitations of our partnership agreement and applicable SEC and NYSE rules and regulations, also exercises broad discretion in establishing the governance provisions of our general partner’s limited liability company agreement. Accordingly, our general partner’s board structure is established by Occidental.
Although our general partner’s board structure has historically separated the roles of Chairman and Chief Executive Officer (“CEO”), our general partner’s limited liability company agreement and Corporate Governance Guidelines permit the roles of Chairman and CEO to be combined. Those roles may be combined in the future.


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Directors and Executive Officers

The biography of each director below contains information regarding that person’s service as a director, business experience, director positions held currently or at any time during the last five years, and involvement in certain legal or administrative proceedings, if applicable, and the experiences, qualifications, attributes, or skills that caused our general partner and its Board of Directors to determine that the person should serve as a director of our general partner. In light of our strategic relationship with our sponsor, Occidental, our general partner considers service as an Occidental executive to be a meaningful qualification for service as a non-independent director of our general partner.
The following table sets forth certain information with respect to the directors and executive officers of our general partner as of February 24, 2020.
22, 2021.
NameAgePosition with Western Midstream Holdings, LLC
Glenn Vangolen6061
Chairman of the Board (effective August 8, 2019)
Michael P. Ure4344
President, Chief Executive Officer, and Director
(effective August 8, 2019)
Michael C. Pearl48
Senior Vice President and Chief Financial Officer,
(effective October 17, 2019)
and Director
Robert W. Bourne6465
Senior Vice President and Chief Commercial Officer
(effective October 17, 2019)
Craig W. Collins4748
Senior Vice President and Chief Operating Officer
(effective August 8, 2019)
Christopher B. Dial4344
Senior Vice President, General Counsel and Corporate Secretary
(effective December 16, 2019)
Catherine A. Green4647
Vice President and Chief Accounting Officer
(effective October 17, 2019)
Charles G. Griffie4647
Senior Vice President, Operations and Engineering
(effective October 17, 2019)
Robin H. Fielder39
President, Chief Executive Officer and Director
(through August 7, 2019)
Jaime R. Casas49
Senior Vice President, Chief Financial Officer and Treasurer
(through October 16, 2019)
Steven D. Arnold59
Director (effective February 28, 2019)
Marcia E. Backus65
Director (effective August 8, 2019)
Peter J. Bennett5153
Director (effective August 8, 2019)
Oscar K. Brown4950
Director
Nicole E. Clark51Director (effective August 8, 2019)December 15, 2020)
James R. CraneKenneth F. Owen6647
Director (effective February 28, 2019)September 11, 2020)
Thomas R. HixDavid J. Schulte7259
Director (effective September 11, 2020)
Jennifer M. KirkLisa A. Stewart4563
Director (effective August 8, 2019)
Craig W. Stewart65
Director
David J. Tudor60
DirectorSeptember 11, 2020)


Our directors hold office until their successors are duly elected and qualified or until the earlier of their death, resignation, removal, or disqualification. Officers serve at the discretion of the Board of Directors. There are no family relationships among any of our directors or executive officers.
Glenn Vangolen
Houston, Texas
Director since:
August 2019
Not Independent
Biography/Qualifications 

Mr. Vangolen has served as a director of our general partner’s Board of Directors since August 2019. Mr. Vangolen has been Senior Vice President, Business Support of Occidental since February 2015. In this role, Mr. Vangolen oversees the Human Resources and Administration; Information Technology; Flight Operations; Health, Environment, Safety, and Security; Government Relations and Corporate Secretary functions of Occidental. Mr. Vangolen has held positions of increasing responsibility in the oil and gas and corporate segments within Occidental, including senior leadership positions in the Middle East.
Michael P. Ure
Houston, Texas
Director since:
August 2019
Not Independent
Officer since:
August 2019
Biography/Qualifications

Mr. Ure has served as President and Chief Executive Officer of our general partner and as a director of our general partner’s Board of Directors since August 2019. Prior to joining WES, Mr. Ure served as Senior Vice President, Business Development of Occidental Oil and Gas beginning in July 2017 and as Vice President, Mergers and Acquisitions of Occidental from October 2014 to July 2017. Mr. Ure held a leadership role in evaluating acquisition and divestiture opportunities including, during his tenure, accountability for Occidental’s business development activities in North and Latin America. Prior to joining Occidental, Mr. Ure served in a leadership role with Shell Exploration and Production’s Upstream Americas Business Development organization and as an investment banker in New York, London, and Houston; most recently with Goldman, Sachs & Co. During his career, Mr. Ure has worked on total closed transactions representing more than $150 billion in value.
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Michael C. Pearl
Houston, Texas
Officer since:
October 2019
Biography/Qualifications

Mr. Pearl has served as Senior Vice President and Chief Financial Officer of our general partner since October 2019. Mr. Pearl joined Anadarko in 2004 and served in various leadership positions within Anadarko’s accounting and finance organization, including Director Corporate Tax, Corporate Controller, Vice President Finance and Treasurer, and most recently as Senior Vice President, Investor Relations. Mr. Pearl also served as Senior Vice President and Chief Financial Officer of the general partner of Western Midstream Operating, LP (formerly Western Gas Partners, LP) at the time of its 2008 IPO. Prior to joining Anadarko, Mr. Pearl began his career at EY, where he held positions of increasing responsibility in corporate tax and finance.
Robert W. Bourne
Houston, Texas
Officer since:
October 2019
Biography/Qualifications
 
Mr. Bourne has served as Senior Vice President and Chief Commercial Officer of our general partner since October 2019. Prior to joining WES, Mr. Bourne served as a member of the board of directors of Altus Midstream Company from November 2018 to August 2019. Mr. Bourne also served as a member of the board of directors and Vice President of Business Development — Marketing of Apache Corporation from April 2017 to August 2019. Prior to joining Apache Corporation, Mr. Bourne served as a consultant advising Smith Production Inc. Mr. Bourne served as Senior Vice President of Business Development at American Midstream GP LLC, the general partner of American Midstream Partners, LP from November 2014 until December 31, 2015. Mr. Bourne has more than 30 years of experience in midstream corporate business development focused on producer and end-user relations, and was one of the founding members of the executive management team for Coral Energy.
Craig W. Collins
Houston, Texas
Officer since:
August 2019
Biography/Qualifications

Mr. Collins has served as Senior Vice President and Chief Operating Officer of our general partner since August 2019. Mr. Collins served as Vice President, Midstream of Occidental from June 2019 through December 2019. In that role, Mr. Collins was responsible for leading Occidental’s midstream operations business unit. From April 2019 to May 2019, Mr. Collins served as Chief Operating Officer of Altus Midstream. From April 2018 to April 2019, Mr. Collins served as Vice President and Chief Operating Officer — Midstream, of Alta Mesa Resources, Inc., which filed a petition under the federal bankruptcy laws in September 2019. Concurrent with the role at Alta Mesa Resources, Inc., Mr. Collins also served as Chief Operating Officer of Kingfisher Midstream, a wholly owned subsidiary of Alta Mesa Resources, Inc. From February 2017 to April 2018, Mr. Collins served as Senior Vice President and Chief Operating Officer of the general partner and the general partner of Western Gas Partners, LP (now WES Operating) (“Western Gas”). Mr. Collins previously served as Director of Midstream Engineering for Anadarko from July 2016 to February 2017, during which time he was responsible for the engineering and construction of midstream infrastructure for Anadarko and Western Gas. Mr. Collins joined Anadarko in 2003 and served in several roles of increasing responsibility in Anadarko’s Treasury, Corporate Development, and Midstream groups.

Christopher B. Dial
Houston, Texas
Officer since:
December 2019
Biography/Qualifications
 
Mr. Dial has served as Senior Vice President, General Counsel and Secretary of our general partner since December 2019. Prior to joining WES, Mr. Dial served as Senior Vice President, General Counsel, and Chief Compliance Officer of the general partner of American Midstream Partners, LP from January 2018 to September 2019. Prior to joining American Midstream Partners, LP, Mr. Dial served as General Counsel of Susser Holdings II, L.P. after spending over eight years in a number of roles, most recently as Associate General Counsel and Corporate Secretary, with both Susser Holdings Corporation and Sunoco LP. Mr. Dial began his career as an attorney for Andrews Kurth, LLP, representing clients on a variety of corporate, capital markets, and other transactional matters.
Catherine A. Green
Houston, Texas
Officer since:
October 2019
Biography/Qualifications
 
Ms. Green has served as Vice President and Chief Accounting Officer of our general partner since October 2019. Ms. Green joined Anadarko in 2001 and has more than 20 years of accounting and audit experience. During her 18 years at Anadarko, Ms. Green has served in a variety of diverse roles throughout the Anadarko accounting and finance organization, including internal audit, technical U.S. GAAP accounting, internal controls, and most recently as Director, Expenditure Accounting. Prior to joining Anadarko, Ms. Green was an auditor with Grant Thornton LLP in the United Kingdom and Houston.
Charles G. Griffie
Houston, Texas
Officer since:
October 2019

Biography/Qualifications
 
Mr. Griffie has served as Senior Vice President, Operations and Engineering since October 2019. Mr. Griffie was named Senior Vice President, U.S. Onshore Field Operations of Anadarko in November 2018. Prior to this role, Mr. Griffie served as Senior Vice President, Midstream and Marketing at Huntley & Huntley Energy Exploration from June 2016 to November 2018. From 2006 through June 2016, Mr. Griffie held various operational leadership positions at Anadarko, including as General Manager U.S. Onshore Business Advisor, Eagleford Operations Manager, Appalachian Basin Midstream Manager, and Director of Midstream Engineering. Mr. Griffie joined Anadarko through its acquisition of Western Gas Resources, Inc.
Robin H. Fielder
Houston, Texas
Director from:
November 2018 to August 2019
Not Independent
Officer from:
November 2018 to August 2019
Biography/Qualifications

Ms. Fielder served as President and Director of our general partner from November 2018 to August 2019, and as Chief Executive Officer of our general partner from January 2019 to August 2019. Ms. Fielder also served as Senior Vice President, Midstream of Anadarko from November 2018 to August 2019. Prior to these positions, Ms. Fielder served in positions of increasing responsibility at Anadarko, including Vice President, Investor Relations from September 2016 to November 2018, Midstream Corporate Planning Manager from December 2015 to September 2016, Director, Investor Relations from June 2014 to December 2015, and General Manager, Carthage/North Louisiana from June 2013 to June 2014. Prior to serving in these roles, Ms. Fielder held various exploration and operations engineering positions at Anadarko in both the U.S. onshore and the deepwater Gulf of Mexico.
Jaime R. Casas
Houston, Texas
Officer from:
May 2017 to October 2019
Biography/Qualifications

Mr. Casas served as Senior Vice President, Chief Financial Officer and Treasurer of our general partner from May 2017 to October 2019. Mr. Casas also served as Vice President, Finance of Anadarko from May 2017 to October 2019. Mr. Casas has served as Vice President and Treasurer of Occidental since October 2019. Prior to joining WES, Mr. Casas served as Senior Vice President and Chief Financial Officer of Clayton Williams Energy, Inc. from October 2016 until the company’s sale in April 2017. Previously, Mr. Casas served as Vice President and Chief Financial Officer of the general partner of LRR Energy, L.P., a publicly traded exploration and production master limited partnership, from 2011 to October 2015, and as Vice President and Chief Financial Officer of Laredo Energy, a privately held oil and gas company, from 2009 to 2011. Prior to joining Laredo Energy, Mr. Casas worked for over a decade in various positions and industry groups in the investment banking divisions at Donaldson, Lufkin & Jenrette, and Credit Suisse.

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Steven D. Arnold
Houston, Texas
Director since:
February 2019
Independent
Biography/Qualifications
Mr. Arnold has served as a director of our general partner and as a member of the Audit Committee of the Board of Directors since February 2019. Mr. Arnold served as a director of the general partner of Western Gas Partners, LP (now WES Operating) and as a member of that board’s Special Committee and Audit Committee from February 2014 through February 2019. Mr. Arnold served on the board of directors of the general partner of Spectra Energy Partners, LP from 2007 to December 2013, during which time Mr. Arnold served on that board’s Audit Committee and Conflicts Committee. Mr. Arnold served as Chairman of each of those committees at separate times during his board membership. Mr. Arnold is engaged in private investment management and consulting services in Houston, Texas, through 3 Lights Management Co., serving as its President since inception in 2000. Mr. Arnold has over ten years of institutional investment management experience with Prudential Financial, Inc. Mr. Arnold brings strong risk assessment and strategic expertise to the Board.
Marcia E. Backus
Houston, Texas
Director since:
August 2019
Not Independent
Biography/Qualifications

Ms. Backus has served as a director of our general partner’s Board of Directors since August 2019. She has served as General Counsel of Occidental since 2013, Senior Vice President since 2014, and Chief Compliance Officer since 2015. Ms. Backus is responsible for overseeing Occidental’s legal and compliance departments worldwide. Prior to joining Occidental, Ms. Backus was a partner at the law firm Vinson & Elkins L.L.P., heading the firm’s Energy Transactions/Projects Practice Group and serving in key leadership positions.
Peter J. Bennett
Houston, Texas
Director since:
August 2019
Not Independent
Biography/Qualifications 

Mr. Bennett has served as a director of our general partner’s Board of Directors since August 2019. Mr. Bennett has served as Senior Vice President, Permian Resources of Occidental Oil and Gas, a subsidiary of Occidental, since April 2018 and Vice President of Occidental since December 2016. In this role, Mr. Bennett is responsible for the operations, growth, and optimization strategy for all of Occidental’s Permian Resources business. Mr. Bennett previously served as President and General Manager — Permian Resources, New Mexico Delaware Basin, from January 2017 to April 2018, Chief Transformation Officer from June 2016 to January 2017, Vice President, Portfolio and Optimization of Occidental Oil and Gas from February 2016 to June 2016 and, prior to that, pioneered innovative logistical and operational solutions as Vice President, Operations Portfolio and Integrated Planning of Occidental Oil and Gas from October 2015 to February 2016.
Oscar K. Brown
Houston, Texas
Director since:
August 2019
Not Independent
Biography/Qualifications

Mr. Brown has served as a director of our general partner’s Board of Directors since August 2019. Mr. Brown has served as Senior Vice President, Strategy, Business Development and Supply Chain of Occidental sincefrom November 2018.2018 to March 2020. In this role, Mr. Brown iswas responsible for, among other things, Occidental’s global business development functions and global supply chain management. Mr. Brown previously served as Senior Vice President, Corporate Strategy and Business Development from July 2017 to November 2018. Prior to joining Occidental in 2016, Mr. Brown worked at Bank of America Merrill Lynch, where he most recently served as managing director and co-head of Americas Energy Investment Banking. Mr. Brown served as Occidental’s designated representative on the board of directors of Plains All American Pipeline’s governing entity, PAA GP Holdings LLC (NYSE: PAA and PAGP) from August 2017 to September 2019. Mr. Brown also serves on the board of Houston’s Alley Theatre, and as a member of that board’s Executive Committee.
James R. CraneNicole E. Clark
Houston, Texas
Director since:
February 2019
Independent
Biography/Qualifications
Mr. Crane has served as a director of our general partner and as a member of the Special Committee of the Board of Directors since February 2019. Mr. Crane served as a director of the general partner of Western Gas Partners, LP (now WES Operating) and as a member of that board’s Special Committee and Audit Committee from 2008 through February 2019. In 2011, Mr. Crane became the principal owner and Chairman of the Houston Astros Baseball Club. Mr. Crane also is the Chairman and Chief Executive Officer of Crane Capital Group Inc., an investment management company he founded. Crane Capital Group currently invests in transportation, real estate, and asset management. Its holdings include Crane Worldwide Logistics, a premier global provider of customized transportation and logistics services with 100 offices in 29 countries. Prior to founding Crane Capital Group Inc., Mr. Crane was founder, Chairman and Chief Executive Officer of EGL, Inc., a global transportation, supply chain management, and information services company, from 1984 until its sale in 2007. Mr. Crane currently serves as a director of Nabors Industries Ltd., an international drilling contractor and well-services provider and Cargojet Inc., a Canadian cargo services company. From 2010 to February 2012, Mr. Crane served as a director of Fort Dearborn Life Insurance Company, a subsidiary of Health Care Service Corporation, and from 1999 to 2007 he served as a director of HCC Insurance Holdings, Inc.

Thomas R. Hix
Houston, Texas
Director since:
January 2013
Independent
Biography/Qualifications
Mr. Hix has served as a director of our general partner and as a member of the Audit Committee of the Board of Directors since January 2013. Mr. Hix has served as Chairman of the Audit Committee since August 2019 and served as Chairman of the Special Committee of the Board of Directors from January 2013 to August 2019. Mr. Hix has been a business consultant since 2003, and previously served as Senior Vice President of Finance and Chief Financial Officer of Cooper Cameron Corporation from 1995 to 2003. Prior to joining Cooper Cameron Corporation, Mr. Hix held several executive finance and accounting positions in the energy industry. Mr. Hix has significant expertise in finance and accounting and experience in mergers and acquisitions. Mr. Hix currently serves as a director of Ascent Resources, LLC, a privately owned exploration and production company focused on natural gas, oil, and NGLs in the Appalachian basin. Mr. Hix previously served as a director of Health Care Services Corporation from 2004 to November 2017, as a director of EP Energy Corporation from April 2014 to December 2017, as a director of El Paso Corporation from 2004 to May 2012, and as a director of Rowan Companies plc from 2009 to April 2019.
Jennifer M. Kirk
Houston, Texas
Director since:
August 20192020
Not Independent
Biography/Qualifications 

Ms. KirkClark has served as a director of our general partner’s Board of Directors since August 2019. She was appointed SeniorDecember 2020. Ms. Clark presently holds the position of Vice President, Integration, ofDeputy General Counsel and Corporate Secretary at Occidental, in August 2019. In her current role, Ms. Kirk is responsible for overseeing the integration of Anadarko and facilitating Occidental’s achievement of its synergy targets. Prior to her current position with Occidental, Ms. Kirk served as Vice President, Controller and Principal Accounting Officer of Occidental from 2014 to August 2019, and was responsible for the direct oversight of Occidental’s financial reporting, accounting, and internal controls functions. Ms. Kirkhaving joined Occidental in 1999 and has served in financial roles of increasing responsibility and leadership.2014. Prior to joining Occidental, Ms. KirkClark was Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer at a private-equity backed industrial distributor to the energy and petrochemicals markets. Before that, Ms. Clark was a Corporate Partner at Vinson & Elkins LLP, where she specialized in mergers and acquisitions, securities regulation and corporate governance. She began her legal career with Wachtell, Lipton, Rosen & Katz where she was a Corporate Associate. Prior to entering the law, Ms. Clark was an auditor at Arthur Andersen LLP. Ms. Kirk also serves on the board of directors of Republic Services, Inc., where she serves as chair of the Audit Committee and as a member of the Sustainability & Corporate Responsibility Committee. Ms. Kirk also serves on the boards of the Boys and Girls Club of the Greater Houston Area and the Houston Women’s Chamber.
Craig W. StewartKenneth F. Owen
Calgary, Alberta, CanadaHouston, Texas
Director since:
January 2013September 2020
Independent
Biography/Qualifications
 
Mr. StewartOwen has served as a director of our general partner, Chairman of the Audit Committee, and as a member of the Special Committee of the Board of Directors since January 2013.September 2020. Mr. Stewart also served on the Audit Committee of our general partner’s Board of Directors from January 2013 through August 2019. Mr. StewartOwen has been a consultant and entrepreneur since March 2018 and previously served as a director of RMP Energy Inc. from 2011 to May 2017, having served as its Executive Chairman from 2011 to January 2017, and as Chairman,Co-founder, President and Chief Executive Officer of a predecessor entity, RMP Energy Ltd.,Moda Midstream from 2008 until 2011.2015 to 2018. Prior to Moda, Mr. StewartOwen was at Oiltanking Partners, where he served as President and Chief Executive Officer of Rider Resources Ltd. from 2003 to 2008,the general partner of Oiltanking Partners, L.P. (NYSE: OILT) and prior to joining Rider Resources, held various executiveOiltanking North America (OTNA). Mr. Owen originally joined OTNA in 2011 as Vice President and director positions with companiesChief Financial Officer and led the IPO of Oiltanking Partners, later moving into an operations role running the company's largest global terminal assets before becoming Chief Executive Officer. Before he joined Oiltanking, Mr. Owen worked in the energy industry.investment banking groups at Citigroup Global Markets Inc. and UBS Investment Bank, where he advised on mergers and acquisitions, joint ventures, IPOs, and equity and debt transactions primarily for the midstream energy sector.
David J. TudorSchulte
Houston, TexasKansas City, Missouri
Director since:
December 2012September 2020
Independent
Biography/Qualifications
 
Mr. TudorSchulte has served as a director of our general partner, Chairman of the Special Committee, and as a member of the Audit Committee of the Board of Directors since December 2012.September 2020. Mr. Tudor has servedSchulte serves as Chairman, Chief Executive Officer and President of CorEnergy Infrastructure, Inc., the Special Committeefirst publicly traded energy infrastructure real estate investment trust. Prior to founding CorEnergy, Mr. Schulte was a co-founder and a Managing Director of our general partner’s BoardTortoise Capital Advisors where, from 2002 to 2015, he served on the investment committee and as a leader of Directors since August 2019new product development, and served as ChairmanPresident of several NYSE listed closed-end funds. Tortoise is a pioneer in developing funds focused on listed energy infrastructure debt and equity securities, including the Audit Committee from December 2012 through August 2019.first closed end master limited partnership fund in 2004. Prior to Tortoise, Mr. Tudor alsoSchulte had professional experience in private equity and investment banking.
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Lisa A. Stewart
Houston, Texas
Director since:
September 2020
Independent
Biography/Qualifications
Ms. Stewart has served as a director of theour general partner, of Western Gas Partners, LP (now WES Operating) and as Chairmana member of the Audit Committee, of WES Operating’s board of directors from 2008 to February 2019, and as a member of the Special Committee of WES Operating’s boardthe Board of directors from 2008 to December 2012. Since May 2016, Mr. TudorDirectors since September 2020. Ms. Stewart serves as Sheridan Production Partners Executive Chairman, a position she has held since April 2020. From the founding of Sheridan in 2006, she served as Chairman, Chief Executive Officer and General ManagerChief Investment Officer overseeing all aspects of Associated Electric Cooperative Inc., a member-owned, member-governed wholesale power provider serving Missouri, Iowa,Sheridan acquisitions and Oklahoma. From May 2013 to May 2016, Mr. Tudorthe implementation of Sheridan’s strategy. In September 2019, eight Sheridan entities for which Ms. Stewart served as Presidentan executive officer filed a Chapter 11 bankruptcy case in the Southern District of Texas. Ms. Stewart has more than 35 years of experience in the oil and Chief Executive Officer of Champion Energy Services, a retail electric provider. From 1999 through 2013, Mr. Tudor was the Presidentgas industry in engineering and Chief Executive Officer of ACES, an Indianapolis-based commodity risk management company owned by 21 generation and transmission cooperatives throughout the United States.positions. Prior to joining ACES, Mr. Tudor was thefounding Sheridan, Ms. Stewart served as Executive Vice President & Chief Operating Officer of PG&E Energy Trading, where he managed commercial operationsEl Paso Corporation and President of El Paso E&P and other non-regulated businesses. Prior to her time at El Paso, Ms. Stewart spent 20 years at Apache, leaving in the United StatesJanuary 2004 as Executive Vice President with responsibility for reservoir engineering, business development, land, environmental, health and Canada.safety, and corporate purchasing.


Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our general partner’s directors and executive officers, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC, and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common units, and other equity securities. Officers, directors, and greater-than-10-percent unitholders are required by the SEC’s regulations to furnish to us, and any exchange or other system on which such securities are traded or quoted, with copies of all Section 16(a) forms they file with the SEC.
To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of our general partner’s officers, directors, and greater-than-10-percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2019, except that on November 22, 2019, a late Form 4 was filed with respect to the purchase of 80,000 WES common units by Mr. Crane.

Reimbursement of Expenses of Our General Partner and Its AffiliatesRelated Parties

Our general partner does not receive any management fee or other compensation for its management of WES. During 2019 under the WES omnibus agreement, we paid an annual general and administrative expense reimbursement of $250,000 and reimbursed Occidental for all insurance coverage expenses it incurred or payments it made on our behalf. Also during 2019, under WES Operating’s partnership agreement and WES Operating’s omnibus agreement, WES Operating reimbursed Occidental for general and administrative expenses allocated to it, as determined by Occidental in its reasonable discretion. On December 31, 2019, the WES and WES Operating omnibus agreements were terminated and replaced with the Services Agreement. Read Part III, Item 13 of this Form 10-K for additional information regarding these agreements.

Board Committees

The Board of Directors has two standing committees: the Audit Committee and the Special Committee.

Audit Committee. The Audit Committee is comprised of three independent directors, Messrs. HixOwen (Chairman), Arnold, and Tudor,Schulte and Ms. Stewart, each of whom is able to understand fundamental financial statements and at least one of whom has past experience in accounting or related financial management experience. The Board has determined that each member of the Audit Committee is independent under the NYSE listing standards and the Exchange Act. In making the independence determination, the Board considered the requirements of the NYSE and our Code of Ethics and Business Conduct and Ethics.Conduct. The Audit Committee held fivefour meetings in 2019.2020.
Mr. HixOwen has been designated by the Board of Directors as the “Audit Committee financial expert” meeting the requirements promulgated by the SEC based upon his education and employment experience as more fully detailed in Mr. Hix’sOwen’s biography set forth above.
The Audit Committee assists the Board of Directors in its oversight of the integrity of the consolidated financial statements, internal control over financial reporting, and compliance with legal and regulatory requirements, and the policies and controls of WES and WES Operating. The Audit Committee has the sole authority to, among other things, (i) retain and terminate our independent registered public accounting firm, (ii) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (iii) establish policies and procedures for the pre-approval of all audit, audit-related, non-audit, and tax services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the Audit Committee and to our management, as necessary.


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Special Committee. The Special Committee is comprised of three independent directors, Messrs. TudorSchulte (Chairman), Crane, and Owen and Ms. Stewart. The Special Committee reviews specific matters that the Board believes may involve conflicts of interest (including certain transactions with Occidental). The Special Committee will determine, as set forth in our partnership agreement, if the resolution of a conflict of interest submitted to it is fair and reasonable to us. The members of the Special Committee are not officers or employees of our general partner or directors, officers, or employees of its affiliates,related parties, including Occidental. Our partnership agreement provides that any matters approved in good faith by the Special Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The Special Committee held threetwo meetings during 2019.2020.

Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of our Board of Directors, all of our independent directors meet in an executive session without management participation or participation by non-independent directors. Mr. Tudor,Under our Corporate Governance Guidelines, these meetings are chaired on a rotating basis by the Chairmanchairpersons of the Board’s Audit Committee and Special Committee, presides over these executive sessions.Committee.
The Board of Directors welcomes questions or comments about WES and its operations. Unitholders or interested parties may contact the Board of Directors, including any individual director, at BoardofDirectors@westernmidstream.com or at the following address and fax number:address: Name of the Director(s), c/o Secretary, Western Midstream Holdings, LLC, 1201 Lake Robbins9950 Woodloch Forest Drive, Suite 2800, The Woodlands, Texas 77380, (832) 636-6001.77380.

Code of Ethics, Corporate Governance Guidelines, and Board Committee Charters

Our general partner has adopted a Code of Ethics for CEO and Senior Financial OfficersBusiness Conduct (the “Code of Ethics”), which applies to our general partner’s Chief Executive Officer, Chief Financial Officer, principal accounting officer, Controller, and all other senior financial and accounting officers of our general partner. Our Code of Ethics is also applicable to all WES employees. If the general partner amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, we will disclose the information on our website. Our general partner has also adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance and a Code of Business Conduct and Ethics applicable to all employees of Occidental or affiliates of Occidental who perform services for us and our general partner.governance.
We make available free of charge, within the “Governance” section of our website at www.westernmidstream.com, and in print to any unitholder who so requests, our Code of Ethics, Corporate Governance Guidelines, Code of Business Conduct and Ethics, Audit Committee charter, and Special Committee charter. Requests for print copies may be directed to investors@westernmidstream.com or to: Investor Relations, Western Midstream Partners, LP, 1201 Lake Robbins9950 Woodloch Forest Drive, Suite 2800, The Woodlands, Texas 77380, or telephone (832) 636-6000.636-1009. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.


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Item 11.  Executive Compensation

COMPENSATION DISCUSSION AND ANALYSIS

Overview

This Compensation Discussion and Analysis (“CD&A”) describes the material elements, objectives, and principles of WES’s 2020 executive compensation program for its named executive officers (“NEOs”), recent compensation decisions, and the factors the Board considered in making those decisions. The NEOs for 2020 were:
For the year ended
NamePosition
Michael P. UrePresident, Chief Executive Officer and Chief Financial Officer
Michael C. Pearl (1)
Former Senior Vice President and Chief Financial Officer
Craig W. CollinsSenior Vice President and Chief Operating Officer
Charles G. GriffieSenior Vice President, Operations and Engineering
Robert W. BourneSenior Vice President and Chief Commercial Officer

(1)Mr. Pearl left WES on September 11, 2020.

Executive Summary

Prior to December 31, 2019, we did not directly employ any of the persons responsible for managing our business. Rather, until December 31, 2019, all of theOur employees, including executive officers, who managed our business, were employed by Occidental (or, prior to the Occidental Merger, by Anadarko) and their respective subsidiaries other than us. In addition,During this period, compensation decisions for our general partner’s Board of Directors does not have a compensation committee. For the year ended December 31, 2019, the compensation of Anadarko’s and Occidental’s employees that perform services on our behalf, including our general partner’s executive officers was approvedwere made by Anadarko’s and Occidental’s management. For the year ended December 31, 2019, our reimbursement toOccidental or Anadarko, and Occidental for the compensation of executive officers was governed by our omnibus agreement. Under our partnership agreement and our omnibus agreement, for the year ended December 31, 2019, we reimbursed general and administrative expenses as determined by Anadarko and Occidental in their reasonable discretion. Read the caption Shared services agreements under Part III, Item 13 of this Form 10-K.
Our general partner’s “named executive officers”them for 2019 were Robin H. Fielder (the principal executive officer through August 7, 2019), Michael P. Ure (the principal executive officer effective August 8, 2019), Jaime R. Casas (the principal financial officer and principal accounting officer through October 16, 2019), Michael C. Pearl (the principal financial officer effective October 17, 2019), Craig W. Collins (the principal operating officer effective August 8, 2019), Robert W. Bourne (Senior Vice President and Chief Commercial Officer effective October 17, 2019), Charles G. Griffie (Senior Vice President, Operations and Engineering effective October 17, 2019), and John D. Montanti (Vice President, General Counsel and Corporate Secretary through December 13, 2019). With respect to the executive officers who, during their periods of service as executive officers of our general partner, were not fully dedicated to our business, compensation paid or awarded by us in 2019 reflects only thea portion of compensation expense that was allocated to us pursuant to Anadarko’s and Occidental’s allocation methodology, as described below, and subject to the terms of our omnibus agreement. For the year ended December 31, 2019, Anadarko and Occidental had the ultimate decision-making authority with respect
Subsequent to the total compensation of the named executive officers and, subject to the terms of our omnibus agreement, the portion of such compensation we reimbursed pursuant to Anadarko’s and Occidental’s allocation methodology. Generally, once Anadarko and Occidental had established the total aggregate amount the named executive officers were eligible to be paid or awarded with respect to each element of compensation, such aggregate amount was then multiplied byMerger, WES undertook a time allocation percentage for each named executive officer. Each allocation percentage was establishedstrategic shift toward becoming a functionally-independent company based on the recognition that operating our business under a periodic, good-faith estimate made by each namedmidstream-focused organizational infrastructure, with an independent management team solely dedicated to WES, would position WES to achieve long-term cost efficiencies, increase the quality, safety, and reliability of WES’s service offerings and operate more competitively, thereby promoting the creation of long-term value for WES unitholders. Our executive officer and was subject to review by the Chairmanmanagement team, none of our general partner’s Board of Directors. The resulting amount (other than with respect to certain long-term incentive plan awards) was the amount that we reimbursed Anadarko and Occidental for pursuant to the terms of our omnibus agreement, and such amount appears in the Summary Compensation Table below. Notwithstanding the foregoing, perquisites were not allocated to us, and reimbursement of annual bonus amounts under the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table were capped consistent with the methodology used for all employees whose compensation was allocated to us for 2019 and as set forth in the Services Agreement entered into between Occidental, Anadarko, and WES Operating GP. For additional information about the Services Agreement, read the caption Services and secondment agreement under Part III, Item 13 of this Form 10-K.


The following table presents the estimated percentages of time (“time allocation”) that the general partner’s named executive officers devoted to us during the fiscal year ended December 31, 2019, which percentages represent the time devoted to the business of the Partnership relative to the aggregate time devoted to the businesses of the Partnership on one hand andwhom have any remaining role or responsibilities at Anadarko or Occidental, on the other hand:
Named Executive Officers of Our General Partner
Time
Allocation
Occidental Corporate Officer
Michael P. Ure (1)
90%Yes
Michael C. Pearl (1)
100%No
Craig W. Collins (1)
100%No
Robert W. Bourne (1)
100%No
Charles G. Griffie (1)
100%No
Robin H. Fielder75%No
Jaime R. Casas70%Yes
John D. Montanti70%No
(1)
Based upon their respective appointment dates, the full-yearwas brought into WES between August of 2019 and year-end 2019 prorated allocation percentages for Messrs. Ure, Pearl, Collins, Bourne, and Griffie are as follows: 35% for Mr. Ure, 40% for Mr. Pearl, 40% for Mr. Collins, 40% for Mr. Bourne, and 20% for Mr. Griffie. Compensation amounts shown herein for these named executive officers do not include compensation that was paid or awards that were granted by Anadarko or Occidental prior to the named executive officer’s commencement of service with us.

The following discussion relating to compensation paid by Anadarkoexecute this transition. This change in organizational structure was and Occidental is based on information provided to us by Occidental and does not purport to be a complete discussion and analysis of Anadarko’s and Occidental’s executive compensation philosophy and practices. For a more complete analysis of the compensation programs and philosophies used at Occidental, read Compensation Discussion and Analysis contained within Occidental’s proxy statement, which is expected to be filed with the SEC within 120 days of December 31, 2019. The elements of compensation discussed below for 2019 (and the decisions of Anadarko and Occidental with respect to the levels of such compensation) were not subject to approvals by our Board of Directors, including the Audit or Special Committee thereof.
Effective for the beginning of the fiscal year 2020, the employment ofsignificant undertaking that informed all of our current named executive officers has beencompensation decisions, including pay levels, the design of short-and long-term incentive programs, the determination of WES specific metrics used in these programs, and the benefit programs we provide.
In December 2019, we executed several agreements with Occidental designed to provide the legal and organizational framework for this transition. Among these agreements was the Amended and Restated Services, Secondment, and Employee Transfer Agreement (“Services Agreement”), which transferred employment of WES’s management team from Occidental to a subsidiaryWES at year-end 2019 and provided for the secondment of all remaining WES-dedicated employees through the date of their formal transfer to WES—which occurred in the first quarter of 2020. Following the execution of the Partnership on substantially the same terms and conditions of employment as applied immediately prior to the transfer. As a result, going forward, any changes to compensation terms for our named executive officers, such as changes in base salary, target bonus amounts, or perquisites will be determined byServices Agreement, the Board of Directors of our general partner (the “Board”) was vested with responsibility for all decisions relating to WES’s compensation programs, including the compensation of our NEOs.
The compensation actions taken by the Board in 2020 were designed to promote and align with this strategic and operational transition, but were also—in certain respects—limited or a committeeinfluenced by structural considerations relating to this transition and/or the Occidental Merger. For example:

•Under the Anadarko Change of Control Plan, any material diminution in compensation or benefits in connection with the transfer to WES of legacy Anadarko employees—who compromise the majority of our workforce—could have given rise to constructive termination claims and severance obligations.

•Although WES was deconsolidated from Occidental at year-end 2019, there were significant transition considerations in establishing standalone compensation program structures and administrative functions applicable to the newly-formed WES workforce. The WES organization therefore relied upon and
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remained influenced to some degree by the established infrastructure and programs that existed at Occidental during 2020.

•Because WES did not have any employees prior to 2020, and all members of our executive management team were new to the organization, WES management did not have years of accumulated equity grants tending to establish unitholder alignment and retention incentives.

During this transition period, our Board took several key actions—both in furtherance of Directors may establish for such purposes,WES’s strategic objectives and in reaction to external factors—which directly or indirectly impacted executive compensation:

•Approved the Services Agreement with Occidental that outlined the terms of transferring employees, including our Board of Directors (or a committee thereof) will be responsible for determiningNEOs, to WES; this agreement specified that the terms and amountsconditions of any newemployment, including employee aggregate benefit values, be substantially the same as those provided to employees immediately prior to the transfer;

•Hired an independent compensation awards, includingconsultant;

•Established an annual cash incentivesincentive program with performance measures aligned solely with WES’s performance;

•Established an annual equity-based long-term incentive program that rewards executives based on WES’s absolute unit price performance, relative unit price performance compared to industry peers, and return on assets over a three-year performance period;

•Reviewed and made compensation changes to our executive officer base salaries, target bonus opportunities, and long-term incentive awards;

•Approved a 50% cut to our quarterly distributions to secure the Partnership’s long-term financial health; executives participated in the distribution reductions on their own unit holdings, and through tandem distribution rights on their outstanding unvested unit awards.

ElementsAs our transition to a standalone midstream company evolves, we will continue to review our compensation and benefit programs in order to ensure they align with WES’s overall strategy, provide for the attraction and retention of Compensationexecutive talent, and align executive officers’ interests with those of our long-term unitholders.

For2020 Business and Performance Highlights

2020 was a transformative year for WES as it embarked on a business transition predicated on the idea that WES could drive and sustain greater unitholder value by functioning as an independent enterprise and simultaneously shifting its financial strategy toward optimizing its balance sheet and ability to self-fund future growth. While executing this transition, and despite the challenges occasioned by a world-wide pandemic, during the 2020 fiscal year WES:

•Maintained 99.1% system availability.

•Achieved year-over-year increases in throughput for natural gas, crude oil and NGLs, and produced water despite a significantly challenged commodity price environment.

•Generated $1.23 billion in Free Cash Flow, more than thirty times that generated during 2019 and representing a roughly $1.93 billion improvement to the principalnegative $704.5 million generated by the business in 2018.

•Achieved its 2021 target of below 4.0X consolidated total leverage a full year ahead of schedule.

•Worked to reduce future cash obligations and leverage by retiring 30.2 million units, via repurchases and redemptions, and $218.0 million of senior notes.
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•Refinanced $3.0 billion in debt coming due in 2020 at highly attractive rates.

•Generated record, above-forecast, 2020 EBITDA primarily through cost-saving initiatives.

•Published our first ESG report.

How We Make Compensation Decisions

Our Board has responsibility for evaluating and approving the officer and director compensation plans, policies, and programs of the Partnership. The Board uses several resources in reviewing elements of executive compensation forand making compensation decisions. These decisions are not purely formulaic, and the namedBoard exercises judgement and discretion as appropriate.

Compensation Philosophy. Our compensation programs are designed to attract, retain, and motivate our executive officers were as follows:team to successfully manage the operations of a standalone midstream company. Specifically, our compensation programs are designed to:

base salary;•Align with unitholder interests;

annual cash incentives;•Emphasize performance-based compensation, balancing short-term and long-term results;

equity-based•Reward absolute and relative performance; and

•Provide total compensation which, prior to the Occidental Merger, included equity-based compensation under Anadarko’s 2012 Omnibus Incentive Compensation Plan, as amended and restated (the “Omnibus Plan”), for former Anadarko employees and Occidental’s 2015 Long-Term Incentive Plan (the “Occidental LTIP Plan”) for former Occidental employees;

retention awards for certain of our named executive officers; however, we will not bear any costs associatedopportunities competitive with such awards; and

certain other benefits that were provided on the same basisthose offered to other eligible Anadarko and Occidental employees, including welfare and retirement benefits, severance and change of control benefits, and other benefits.

executives across our industry.
Base salary.
Compensation Consultant.  Base salariesIn 2020, the Board engaged Meridian Compensation Partners, LLC (Meridian) as its independent compensation consultant to provide a fixed level of incomeadvice on various executive compensation matters. Because 2020 was the first year our Board became fully responsible for our named executive officers based on their level of responsibility (which for 2019 may or may not have been fullymaking pay decisions related to our business)NEOs, this was our first year to use an independent compensation consultant. In 2020, Meridian provided guidance on our benchmarking peer group, pay levels, pay mix, severance benefits, and overall executive compensation program design.

Benchmarking Peers. With assistance from Meridian, the Board looked at several factors when determining an appropriate peer group of companies to use for benchmarking compensation opportunities. These factors included: similar midstream businesses of comparable size and scope, comparable executive roles and responsibilities, similar structure (largely independent strategy and governance (whether MLP or C-Corp)), their relative expertise and experience, andcompanies that are in some cases their potentialcompetition for advancement. As discussed above, for 2019, a portion of the base salaries of our namedsame senior executive officers was allocated to us based on Anadarko’s and Occidental’s methodologytalent.
The Partnership’s peer group used for allocating general and administrative expenses. As of January 1, 2020, we will be fully responsible for paying base salaries for our named executive officers. The current base salary for each of our current named executive officers is set forth in the following table:
Named Executive Officers 
Base Salary
(Unallocated)
Michael P. Ure $650,000
Michael C. Pearl 455,000
Craig W. Collins 455,000
Robert W. Bourne 405,000
Charles G. Griffie 405,000

Annual cash incentives (bonuses). Our named executive officers are eligible to receive annual cash awards to be paid in 2020 for their performance during the year ended December 31, 2019. Annual cash incentive awards were used by Anadarko and Occidental to motivate their executives and employees, reward them for the achievement of objectives aligned with value creation, and/or recognize individual contributions to performance. These awards put a portion of an executive’s compensation at risk by linking potential annual compensation to Anadarko’s and Occidental’s achievement of specific operational, financial, and safety performance metrics during the year. For 2019, the annual bonuses paid to our named executive officers are determined pursuant to the annual incentive plans of Anadarko and Occidental or, for Messrs. Pearl and Griffie, were fixed according to the Occidental Merger Agreement.
The portion of annual cash awards allocable to us is based on the periods of service during which the named executive officers provided services to us in 2019, but subject to a limitation of 120% of the target bonus amount for each named executive officer. Annual bonuses are generally paid during the first quarter of each calendar year for the prior year’s performance. Beginning withconducting the 2020 annual performance year, we will be fully responsible for paying any annual bonus awards for our named executive officers. For 2020, the target level annual bonus award opportunity for each of our current named executive officers, measured as a percentage of base salary,benchmarking assessment is set forth in the following table, and the actual amount of any annual bonus awards will be determined pursuant to annual incentive programs that we expect to establish:listed below:

Named Executive Officers
•Crestwood Equity Partners LP
Bonus Opportunity
(Unallocated)•Magellan Midstream Partners LP
Michael P. Ure
•DCP Midstream LP
100%
•ONEOK, Inc.
Michael C. Pearl
•Enable Midstream Partners LP
86%
•Plains All American Pipeline LP
Craig W. Collins
•EnLink Midstream, LLC
86%
•Targa Resources Corp.
Robert W. Bourne
•Equitrans Midstream Corporation
81%
Charles G. Griffie85%
•Williams Companies, Inc.

Long-termBenchmarking Data. To assist in reviewing the design and structure of our executive compensation program, Meridian provided the Board with an independent assessment of the compensation programs and practices in our industry peer group. This assessment included compensation data and program design information that was obtained from the most recent public filings for each company. When reviewing benchmarking data, the Board reviewed 25th, 50th, and 75th percentile data, however, the Board does not target a specific percentile of the benchmark data, and in making officer compensation decisions, they take into account other considerations as noted below.


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Role of Executive Officers in Executive Compensation. The Board,after reviewing the information provided by Meridian and considering other factors and with input from Meridian, determines each element of compensation for our CEO. When making determinations about each element of compensation for our other executive officers, the Board also considers recommendations from our CEO. Additionally, at the Board’s request, our executive officers may assess the design of, and make recommendations related to, our compensation and benefit programs, including recommendations related to the performance measures used in our incentive programs. The Board is under no obligation to implement these recommendations. Executive officers and others may also attend Board meetings when invited to do so, but the executive officers do not attend when their individual compensation is being discussed.

Other Considerations. In addition to the above resources, the Board considers other factors when making compensation decisions, such as individual experience, individual performance, internal pay equity, development and succession status, and other individual or organizational circumstances, including the current market and business environment. With respect to equity-based awards, the Board also considers the expense of such awards, the impact on dilution, and the relative value of each element comprising the executive officers’ target total compensation opportunity.

2020 Annual Compensation Program

Our executive compensation program includes direct and indirect compensation elements. We believe that a majority of an executive officer’s total compensation opportunity should be performance-based; however, we do not have a specified formula that dictates the overall weighting of each element. Beginning in 2020, as part of our transition to a standalone company, the Board established an annual target total compensation program that supports WES’s long-term strategic objectives and is competitive with industry practices.
As illustrated in the charts below, a majority of our NEO targeted annual direct compensation is at-risk; 85% for our CEO and 76%, on average, for our other NEOs. Specifically, 70% of our CEO’s compensation and 56%, on average, for our other NEOs’ compensation is tied directly to WES’s unit performance through their annual long-term incentive awards.

wes-20201231_g11.jpg
The charts above are based on the following compensation elements, as discussed under Analysis of 2020 Compensation Actions: base salaries approved in 2020; target bonus opportunities approved by the Board in 2020; and the target value of the 2020 annual long-term incentive awards.

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Direct Compensation Elements. The direct compensation elements for our 2020 annual compensation program are outlined in the table below. The indirect compensation elements are outlined in the Indirect Compensation Elements section below.

ElementAwardPerformance MetricsPurpose
Base SalaryCashN/AProvides a fixed level of competitive compensation to attract and retain executive talent.
Equity-Based AwardsTime-Based Units
(50% of award)		Absolute Unit PriceTime-based Units align with absolute unit price and provide retentive value, especially in a volatile industry.
ROA Units
(25% of award)		3-Year Return on Assets (“ROA”)
Absolute Unit Price		ROA Units provide an incentive for NEOs to focus on efficiently managing the Partnership’s assets to generate earnings.
TUR Units
(25% of award)		3-Year Relative Total Unitholder Return (“TUR”)
Absolute Unit Price		TUR Units provide an effective comparison of our unit price performance against an industry peer group.
Annual Cash IncentivesCashControllable Cash Costs
System Availability
Discretionary Capital Spend
Leverage
TRIR
Overall Performance		Provides incentives for NEOs to focus and excel in areas aligned with WES’s business objectives by providing rewards for short-term financial and operational results.

Analysis of 2020 Compensation Actions

The following is a discussion of the specific actions taken by the Board in 2020 related to each of our direct compensation elements. Each element is reviewed annually, unless circumstances, such as a promotion, other change in responsibilities, significant corporate event or a material change in market conditions require a more frequent review.

Base Salary. In setting base salary levels for each of the NEOs, the Board considered a number of factors, including each executive’s experience, individual performance, internal pay equity, development, and other individual or organizational circumstances, including the current market and business environment.
Prior to 2020, the compensation of WES’s executive officers, who became WES employees at year-end 2019, was based on decisions made by Anadarko and/or Occidental based on their roles in 2019. The table below reflects the base salaries for the NEOs established in 2020 at the commencement of the WES Board’s role in determining executive compensation at levels the Board believed were consistent with the transition and changes in their WES-dedicated roles and responsibilities.
NameSalary as of
February 23, 2020 ($)
Mr. Ure650,000 
Mr. Pearl455,000 
Mr. Collins455,000 
Mr. Griffie405,000 
Mr. Bourne405,000 


Mr. Ure’s salary reflects his responsibilities leading WES as a standalone company, based—in part— on our peer benchmark data. The establishment of salaries for the other NEOs was also informed by peer benchmark data with a view toward promoting internal compensation alignment.

Equity-Based Long-term Incentive Awards. Prior to the Occidental Merger, Anadarko periodically madegranted equity-based awards under thetheir Omnibus Incentive Plan to align the interests of its executive officers and employees with those of its stockholders and, likewise, Occidental madegranted equity-based awards under the
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Occidental LTIP Plan. For 2019, theAs part of our transition to a standalone company, in February 2020, our Board established an annual equity awards generally consistedlong-term incentive program that consists of a combination of performancetime-based units and performance-based units.
This use of both time-based restricted stockand performance-based awards and units. This award structure was intended to provide a combination of equity-based vehicles that are performance-based in absolute and relative terms while also encouraging retention. Our equity-based long-term incentive program is designed to reward our executive officers for sustained long-term unit performance. This program represents 70% of targeted annual direct compensation for our CEO and an average of 56% for our other NEOs.

Time-Based Units. These units, reflecting 50% of the overall 2020 annual long-term incentive awards, vest annually over a three-year period. Upon vesting, the awards are settled in WES common units. Distribution equivalent rights for time-based awards made during 2020 are paid during the vesting period in the form of WES common units.

Return on Asset Performance Units (“ROA Units”).The costs allocated to usBoard established ROA as a performance criterion for 25% of the 2020 annual long-term incentive awards. ROA is calculated each year during a three-year performance period as follows:

Adjusted
EBITDA		divided byAverage
Consolidated Total
Assets

The actual number of units earned for the namedthree-year performance period will be based on WES’s average annual ROA during this period. The following table reflects the payout scale used to determine the number of units earned. In the event performance falls between a whole percentage, the payout will be interpolated linearly.

WES 3 Year Average ROA19%18%17%16%15%14%13%12%11%
Payout as a % of Target200%175%150%125%100%75%50%25%0%

The number of units earned will be paid in the form of WES common units after the end of the performance period and after the Board has certified the attainment of ROA. Distribution equivalent rights for ROA Unit awards made during 2020 are paid during the performance period in the form of WES common units, assuming target performance.

Total Unit Return Performance Units (“TUR Units”). The Board established relative TUR as a performance criterion for 25% of the 2020 annual long-term incentive awards. The units are subject to relative TUR over a three-year performance period, with TUR calculated as follows:

Average Closing Common Unit Price for the last 30 trading days of the performance periodminusAverage Closing Common Unit Price for the 30 trading days preceding the beginning of the performance periodplusDistributions paid per Common Unit over the performance period (based on ex-dividend date)
divided by
Average Closing Common Unit Price for the 30 trading days preceding the beginning of the performance period

The industry peer group for our 2020 TUR awards is listed below. The TUR peer group differs from our compensation benchmarking peer group due primarily to the exclusion of C-Corp peers, whose securities have a different trading profile than that of master limited partnerships.
•Crestwood Equity Partners LP
•EQM Midstream Partners LP
•DCP Midstream LP
•Magellan Midstream Partners LP
•Enable Midstream Partners LP
•Noble Midstream Partners LP
•EnLink Midstream, LLC
•Plains All American Pipeline LP

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If during the performance period, a peer company is acquired, ceases to exist, ceases to be a publicly-traded partnership, files for bankruptcy, spins off 25% or more of its assets, or sells all or substantially all of its assets, then such partnership shall be deemed to fall to the bottom of the relative TUR ranking for the performance period.
The actual number of units earned for the three-year performance period will be based on WES’s relative TUR during this period. The following table reflects the payout scale used to determine the number of units earned.

Final Relative Ranking123456789
Payout as a % of Target200%175%150%125%100%75%50%25%0%

The number of units earned will be paid in the form of WES common units after the end of the performance period and after the Board has certified the attainment of relative TUR. Distribution equivalent rights for TUR Unit awards made during 2020 are paid during the performance period in the form of WES common units, assuming target performance.

2020 Equity Awards. Effective February 12, 2020, the Board approved the following annual long-term incentive awards under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan. These awards are included in the Grants of Plan-Based Awards Table. In determining the annual equity awards, the Board took into consideration our peer benchmarking data, internal pay equity, retention concerns, and current NEO unit ownership levels. Because each of our executive officers’ compensation includes an allocationofficers was newly-appointed to WES, each of expenses associated with a portionthem generally had minimal or no equity interest in WES prior to the 2020 LTI award cycle.
Total Target LTI Value ($) (1)
Time-Based UnitsTUR UnitsROA Units
NameNumber of Units (#)Target Value ($)Number of Units (#)Target Value ($)Number of Units (#)Target Value ($)
Mr. Ure3,000,000 93,6331,500,000 46,817750,000 46,817750,000 
Mr. Pearl1,300,000 40,575650,000 20,288325,000 20,288325,000 
Mr. Collins1,300,000 40,575650,000 20,288325,000 20,288325,000 
Mr. Griffie800,000 24,969400,000 12,485200,000 12,485200,000 
Mr. Bourne700,000 21,848350,000 10,924175,000 10,924175,000 

(1)Target LTI values vary slightly from those reported in the Summary Compensation Table and Grants of these awardsPlan-Based Awards Table, which are calculated in accordance with the allocation mechanisms in our omnibus agreement.FASB ASC Topic 718.
Going forward, our general partner may grant equity and other long-term incentive awards in us, including awards that may be granted pursuant to the LTIPs, under such plans and programs and with terms and conditions and in amounts as the Board of Directors of our general partner (or a committee thereof) may establish and determine from time to time.


Retention awardsSpecial Equity Awards. In 2019, to encourage retention and dedication of certain of our named executive officers to our business, Occidental granted certain cash retention award opportunities. Messrs. Pearl and Griffie were granted a retention award of $783,000 and $684,000, respectively. These retention awards will be paid ratably, subject to the continued employment of Messrs. Pearl and Griffie, on the following anniversary dates: February 8, 2020, August 8, 2020, and February 8, 2021. To the extent earned, the retention awards will be payable by Occidental or one of its subsidiaries other than us. Pursuant to the Services Agreement, we will not be responsible for the cost of these retention awards.

Other benefits.In addition to the compensation elements discussed above, Anadarkoannual awards, in February 2020, the Board approved special equity awards in the form of time-based units to each of the NEOs. Because our NEOs were new to the Partnership in 2019 and Occidental also maintained other benefitshad minimal WES equity, these grants were made to increase their equity holdings to a level adequate to instill an ownership culture more closely aligning their interests with those of our unitholders and to provide additional retentive value. These units vest annually over a three-year period, and upon vesting, the awards are settled in WES common units. Distribution equivalent rights are paid during the vesting period in the form of WES common units. The table below shows the special equity awards granted to each NEO.
NameNumber of
Time-Based Units (#)
Target Value ($) (1)
Mr. Ure62,4221,000,000
Mr. Pearl24,969400,000
Mr. Collins24,969400,000
Mr. Griffie15,606250,000
Mr. Bourne15,606250,000

(1)Target LTI values vary slightly from those reported in the Summary Compensation Table and Grants of Plan-Based Awards Table, which are calculated in accordance with FASB ASC Topic 718.

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Performance-Based Annual Cash Incentives—WES Cash Bonus Program. During 2020, as part of our transition to a standalone business, the Board approved the WES Cash Bonus Program (“WCB Program”) under the US Incentive Compensation Program. Under this program, annual cash bonus awards are earned by eligible employees, including our NEOs, based on the board’s discretion, taking into account the achievement of specified business objectives and individual performance objectives.
In February 2020, individual target bonus opportunities were approved by the Board for each of our NEOs as noted in the table below.
2020 Target Bonus
Name$% of Salary
Mr. Ure650,000100%
Mr. Pearl390,00086%
Mr. Collins390,00086%
Mr. Griffie345,00085%
Mr. Bourne330,00081%


The NEO target bonuses were determined based on a review of our peer benchmarking data and internal pay equity considerations.

Performance Metrics.In February 2020, the Board approved performance measures and targets to be used as an aid in determining annual cash awards under the WCB Program for the one-year performance period that ended December 31, 2020. Our annual incentive program was designed to include measures that support our primary business strategy of creating long-term value for our named executive officers,unitholders by safely delivering above-average customer service and system availability, and obtaining new business over time, while achieving costs efficiencies and optimizing our financial profile.
The table below reflects the Partnership’s original 2020 performance metrics, performance targets and actual performance under these metrics.
Performance MetricRelative Weighting FactorWCB Program
Performance
Targets		WCB Program Performance
Results
Controllable Cash Costs (1)
20%< $860MM$687MM
System Availability (2)
20%> 97%99.1%
Discretionary Capital Spend (3)
20%< $780MM$269MM
Leverage (4)
15%< 4.3x (Debt/Adjusted EBITDA)3.91x
TRIR (Total Recordable Incident Rate) (5)
10%< 0.350.38
Overall Performance (6)
15%Description BelowDiscussed Below

(1)Controllable Cash includes operating expenses and general and administrative expenses, excluding non-cash restricted stock unit, bonus and benefits expense.
(2)System Availability is a measure of the “real” average availability experienced by WES’s 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. The total availability score is a weighted average with more weight given to higher gross-margin-producing assets.
(3)Discretionary Capital Spend (Discretionary Capital Expenditures plus Equity Investments) includes expansion capital expenditures and expenditures related to equity investments. This metric does not include maintenance capital expenditures, as defined in WES’s financial statements.
(4)Leverage is calculated as the December 31, 2020 total debt balance divided by the trailing 12-months adjusted EBITDA.
(5)TRIR 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.
(6)Overall Performance is assessed based upon WES’s year-over-year performance, including the following:ability to generate accretive third-party business and distributable cash flow.

retirement
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COVID 19 and Our Board’s Approach to 2020 Bonuses.Shortly after the approval of the 2020 executive compensation programs described above, including the WCB Program, the energy industry found itself confronted with unprecedented challenges spurred by the COVID 19 global pandemic. Commodity prices fell and many producers forecasted significant production curtailments. In response to these challenges, WES cut its distribution to unitholders by 50%, eliminated geographical bonuses to certain employees, suspended promotions and pay raises for all of its personnel and required many of its personnel to work remotely. In March 2020, Mr. Ure informed the Board that he intended to forego cash bonus eligibility in order to reduce his cash compensation for the 2020 fiscal year.
This rapid change in the global economy prompted WES’s management team and Board to quickly recognize that the WCB Program performance targets described above, while valid leading indicators of WES’s performance in delivering long-term, sustainable value for unitholders, were not necessarily the most appropriate near-term measures of WES’s ability to withstand the immediate challenges brought by COVID 19. Accordingly, the Board utilized greater discretion in approaching 2020 bonuses than might ordinarily be expected and considered many factors, including not just WES’s attainment of previously enunciated goals, but also the recognition that the industry as a whole experienced significant challenges in 2020, which were shared by WES unitholders and employees alike, and that ongoing economic uncertainty is likely to persist into 2021. As a result, despite the fact that management’s overall performance exceeded the quantitative metrics established by the Board, it was determined that a 95% payout under the 2020 WCB Program was appropriate. This bonus level recognized WES’s meaningful financial and operational performance while also attempting to strike an appropriate balance with the hardships occasioned by—and remaining challenges coming out of—the COVID 19 pandemic and associated disruptions to the energy sector as a whole. The payout level was derived with particular importance placed on and potential improvement opportunities related to operating safely. Further, while recognizing that Mr. Ure previously informed the WES Board of his intent to forego a cash bonus as part of WES’s initial response to COVID 19, the Board determined that he should nevertheless be rewarded in light of WES’s performance during the particular challenges brought by 2020.

Actual Bonuses Earned for 2020.The cash bonus awards for 2020 for our NEOs are shown in the table below and are reflected in the “Bonus” column of the Summary Compensation Table.
Name (1)
Target
Bonus ($)		Board Discretionary Assessment of 2020 WCB ProgramCash Bonus
Awards ($)
Mr. Ure650,000x95%=617,500
Mr. Collins390,000x95%=370,500
Mr. Griffie345,000x95%=327,750
Mr. Bourne330,000x95%=313,500

(1)Mr. Pearl is excluded from this table as he had left WES prior to the determination of awards and did not receive a 2020 bonus award.

Indirect Compensation Elements

As identified in the table below, the Partnership provides certain benefits and perquisites (considered indirect compensation elements) that are considered typical within our industry and necessary to matchattract and retain executive talent. The value of each element of indirect compensation is generally structured to be competitive industry practices,within our industry.
Indirect Compensation ElementPrimary Purpose
Retirement Benefits
•Attracts talented executive officers and rewards them for extended service
•Offers secure and tax-advantaged vehicles for executive officers to save effectively for retirement
Other Benefits (for example, health care, paid time off, disability, and life insurance) and Perquisites
•Enhances executive welfare and financial security
•Provides a competitive package to attract and retain executive talent, but does not constitute a significant part of an executive officer’s compensation
Severance Benefits
•Attracts and helps retain executives in a volatile and consolidating industry
•Provides transitional income following an executive’s involuntary termination of employment

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Retirement Benefits. Beginning in 2020, all our regular employees, including participationour NEOs, are eligible to participate in the Western Midstream Savings Plan, a savingsdefined-contribution benefit plan maintained by WES. We do not have a non-qualified savings restoration plan that provides for the accrual and deferral of employer contributions that the participant would have otherwise been eligible for absent the Internal Revenue Code (“IRC”) limitations that restrict the amount of benefits payable under the tax-qualified savings plan. However, in 2020, the Board approved a cash restoration payment program that provides a direct cash payment to participants in the amount of employer contributions that would have been allocated to the participant’s savings plan account each year, without regard to the IRC limitations. Prior to 2020, our NEOs participated in retirement plan, and retirement restoration plan;

•
severance benefits, as described below under the heading Potential Payments Upon Termination or Change of Control;

director indemnification agreements;

a limited number of perquisites, including financial counseling, tax preparation and estate planning, an executive physical program, management life insurance, voluntaryplans provided by their legacy employer (Occidental or Anadarko). Their participation in deferred compensationthese plans ceased when their employment was transferred to the Partnership on December 31, 2019 and personal excess liability insurance; andwe are not responsible for any expense related to these prior benefits.

certainOther Benefits.We provideother benefits that are also provided to all other eligible U.S.-based employees, includingsuch as medical, dental, vision, flexible spending and health savings accounts, paid time off, life insurance, and disability coverage.

coverage to our executive officers. These benefits are also provided to all other eligible U.S. based employees. As legacy Anadarko management employees, Messrs. Pearl and Griffie were eligible for participation in a Management Life Insurance Plan, which provides an additional life insurance benefit of up to two times base salary. This plan was eliminated for 2021.

Perquisites. We provide a limited number of perquisites, including reimbursement of financial counseling, tax preparation, and estate planning services expense up to $4,000 annually, and reimbursement for the cost of personal excess liability insurance. The expenses related to the perquisites are imputed and considered taxable income to the executive officers, as applicable. We do not provide tax gross-ups on these perquisites. The incremental costs of the perquisites provided are included in the “All Other Compensation” column and supporting footnotes of the Summary Compensation Table.

Severance Benefits. In connection with the transfer of employment of our employees to WES on December 31, 2019, and per the terms of our Services Agreement, we assumed certain severance and termination pay obligations under existing Anadarko and Occidental plans and agreements for all employees, including officers, who were employed with Anadarko prior to the Occidental Merger. While employees maintain their eligibility and participation under these arrangements, our obligations are limited to no greater than:

•Six months of employee’s base salary or

•An amount the officer would be entitled to receive under the formulas set forth in Anadarko’s non-change in control Officer Severance Plan

•The Anadarko Entities, not our General Partner, are responsible for any payments that exceed these amounts.

Because Messrs. Pearl and Griffie were employees with Anadarko prior to the Occidental Merger, per the terms of our Services Agreement they were eligible for the benefits noted above. However, in connection with their acceptance of special retention awards granted to them in 2019, Messrs. Pearl and Griffie waved their right to receive severance pay or benefits upon resignation of employment for good reason or involuntary termination without cause.
In order to provide for uniformity in severance entitlements, on December 31, 2019, our Board extended the benefits under the Anadarko Change of Control Plan to all WES employees who were not employed with Anadarko prior to the Occidental Merger (this includes Messrs. Ure, Collins, and Bourne). These benefits will apply for so long as the Anadarko Change of Control Plan continues to apply for the former Anadarko employees who are now employed with us. For these NEOs, we will be responsible for 100% of these broad-based severance payments and benefits available under the plan.
A detailed discussion of the benefits under these programs is included in the Potential Payments Upon Termination or Change of Control section below.


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Additional Compensation Policies and Provisions

The following provides a more detailed summarydiscussion of Occidental’sadditional policies and provisions we have in place related to our overall executive compensation programprogram.

Equity Grant Practices. WES maintains the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan and the benefits provided thereunder, please seeWestern Gas Partners, LP 2017 Long-Term Incentive Plan, which govern the issuance of equity and equity-based awards. Under the provisions of these Plans, the Board has the authority to grant equity awards to our Section 16 officers. The grant date fair value of each award is based on the closing unit price of WES’s common units on the NYSE on the grant date as designated by the Board. The grant date fair value of the TUR and ROA awards also incorporates the estimated payout percentage of the award on the grant date. As authorized by the terms of the Plans, the Board has delegated to Mr. Ure the authority to grant equity awards in certain circumstances to new employees and to grant equity awards to WES’s employees who are not Section 16 officers.

Clawback Provisions. Per the terms of our 2020 long-term incentive awards which were granted under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan, if WES is required to prepare an accounting restatement due to the material noncompliance of the Partnership, as a result of misconduct, with any financial reporting requirement under the securities laws, and if the recipient knowingly engaged in the misconduct (whether or not they are an individual subject to automatic forfeiture under Section 304 of the Sarbanes-Oxley Act of 2002), the Board (or delegated Plan Administrator) may determine that the recipient must reimburse WES the amount of any payment in settlement of an award earned or accrued during the twelve-month period following the first public issuance or filing with the United States Securities and Exchange Commission (whichever first occurred) of the financial document embodying such financial reporting requirement.

Prohibition Against Derivative Transactions and Hedging. Our Insider Trading Policy expressly prohibits directors, officers and designated employees from directly or indirectly entering into equity derivative or other financial instruments (including, but not limited to, options, puts, calls, swaps, collars, forward contracts, hedges, exchange funds or short sales) tied to WES securities (including equity securities received as part of a compensation program as well as WES equity securities acquired personally).

Tax Law Considerations. We are a limited partnership for United States federal income tax purposes. Therefore, the compensation paid to our NEOs is not subject to the deduction limitations under Section 162(m) of the IRC. We have structured our compensation programs in a manner intended to be exempt from, or to comply with Section 409A of the IRC.

Compensation Committee Report

Neither we nor our general partner has a compensation committee. The Board of Directors has reviewed and discussed the Compensation Discussion and Analysis section of Occidental’s proxy statementset forth above and based on this review and discussion has approved it for its annual meeting of 2019 stockholders, which is expected to be filed with the SEC within 120 days of December 31, 2019.inclusion in this Form 10-K.

Role of Executive Officers in Executive Compensation

For 2019, Occidental’s management determined, and, prior to the Occidental Merger, Anadarko’s management determined the compensation for each of our named executive officers. The Board of Directors determines compensation for the independent, non-management directors of our BoardWestern Midstream Holdings, LLC:

Glenn Vangolen
Michael P. Ure
Peter J. Bennett
Oscar K. Brown
Nicole E. Clark
Kenneth F. Owen
David J. Schulte
Lisa A. Stewart
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Compensation Mix

We believe that the mix of base salary, cash, equity-based awards, and other Anadarko and Occidental compensation fit overall compensation objectives for the named executive officers. We believe this mix of compensation provides competitive compensation opportunities to align and drive employee performance in support of our business strategies and Occidental’s, and to attract, motivate, and retain high-quality talent with the skills and competencies required by us and Occidental.


EXECUTIVE COMPENSATION

As noted above, for 2019,prior to 2020, we did not directly employ any of the persons responsible for managing or operating our business and we have no compensation committee.business. Instead, we arewere managed by our general partner, theand our executive officers of which, during 2019, were employees of Anadarko and Occidental. For 2019,During this period, our reimbursement for the compensation of our executive officers iswas governed by the omnibus agreement andagreement. In December 2019, we executed several agreements with Occidental that enabled us to operate as a standalone business. Among these agreements was the Services Agreement.Agreement, which transferred employment of WES’s management team from Occidental to WES.

Summary Compensation Table

The following table summarizes the compensation amounts expensed by us for our named executive officersNEOs for the years ended December 31, 2020, 2019, 2018, and 2017, as applicable. Except as specifically noted,2018. For 2020, the amounts included ininclude the table belowfull expense of our officers. For 2019, the amounts reflect the portion of the expense allocated to us by Anadarko and Occidental. None of these officers were considered NEOs in 2018, so there was no allocated expense to disclose for this year.
Name and Principal PositionYear
Salary
($) (1)
Bonus
($) (2)
Stock
Awards
($) (3)
Non-Equity
Incentive Plan
Compensation
($) (4)
All Other
Compensation
($) (5)
Total
($)
Michael P. Ure2020641,346 617,500 4,133,602 — 42,439 5,434,887 
President, Chief Executive Officer2019147,981 — 1,080,029 162,000 43,252 1,433,262 
and Chief Financial Officer2018— — — — — — 
Michael C. Pearl2020320,673 — 1,757,410 — 237,803 2,315,886 
Former Senior Vice President and2019167,308 — — 160,615 41,909 369,832 
Chief Financial Officer2018— — — — — — 
Craig W. Collins2020461,923 370,500 1,757,410 — 41,500 2,631,333 
Senior Vice President and2019138,462 — 500,049 168,000 25,826 832,337 
Chief Operating Officer2018— — — — — — 
Charles G. Griffie2020401,154 327,750 1,085,394 — 38,231 1,852,529 
Senior Vice President, Operations201973,077 — 208,008 70,154 18,360 369,599 
and Engineering2018— — — — — — 
Robert W. Bourne2020417,692 313,500 981,448 — 41,725 1,754,365 
Senior Vice President and2019136,500 — 1,250,029 154,932 10,680 1,552,141 
Chief Commercial Officer2018— — — — — — 

(1)For a discussion2020, the amounts reflect each officer’s full base salary expense. For Messers. Ure, Collins and Bourne their 2020 amounts reflect one additional pay period that occurred during the year because of the allocation percentagesadministrative timing of transferring from the Occidental payroll to WES’s payroll. The 2019 amounts reflect the base salary expense allocated to us by Anadarko and Occidental.
(2)This column reflects annual cash bonus awards under the WCB Program for the year ended December 31, 2020.
(3)This column reflects the aggregate grant date fair value of stock awards, computed in effect foraccordance with FASB ASC Topic 718 (without respect to the risk of forfeitures). The value ultimately realized upon the actual vesting of the award(s) may or may not be equal to this determined value. The 2020 amounts reflect the full grant date fair value of awards granted during the year. The 2019 amounts reflect the allocated grant date fair value of awards granted in 2019. For information regarding the awards granted in 2020, see the OverviewGrants of Plan-Based Awards in 2020 section, above.table. Upon Mr. Pearl’s termination from the Partnership on September 11, 2020, he received a prorated portion of the disclosed 2020 awards based on the number of days he was employed during the vesting period and applicable performance period.
(4)This column reflects annual cash bonus compensation amounts allocated to us for the year ended December 31, 2019 under the Anadarko and Occidental plans.

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Name and Principal Position Year 
Salary
($) (1)
 
Stock
Awards
($) (2)
 
Option
Awards
($) (3)
 
Non-Equity
Incentive Plan
Compensation
($) (4)
 
All Other
Compensation
($) (5)
 
Total
($)
Michael P. Ure 2019 147,981
 1,080,029
 —
 162,000
 43,252
 1,433,262
President and 2018 —
 —
 —
 —
 —
 —
Chief Executive Officer 2017 —
 —
 —
 —
 —
 —
Robin H. Fielder 2019 223,846
 —
 —
 —
 54,494
 278,340
Former President and 2018 23,019
 384,963
 201,309
 21,313
 5,905
 636,509
Chief Executive Officer 2017 —
 —
 —
 —
 —
 —
Michael C. Pearl 2019 167,308
 —
 —
 160,615
 41,909
 369,832
Senior Vice President and 2018 —
 —
 —
 —
 —
 —
Chief Financial Officer 2017 —
 —
 —
 —
 —
 —
Jaime R. Casas 2019 281,942
 —
 —
 —
 69,281
 351,223
Former Senior Vice President, Chief 2018 348,577
 1,650,799
 392,547
 271,890
 89,029
 2,752,842
Financial Officer and Treasurer 2017 208,731
 1,257,309
 904,934
 135,675
 71,607
 2,578,256
Charles G. Griffie 2019 73,077
 208,008
 —
 70,154
 18,360
 369,599
Senior Vice President, Operations 2018 —
 —
 —
 —
 —
 —
and Engineering 2017 —
 —
 —
 —
 —
 —
Craig W. Collins 2019 138,462
 500,049
 —
 168,000
 25,826
 832,337
Senior Vice President and 2018 —
 —
 —
 —
 —
 —
Chief Operating Officer 2017 146,827
 1,029,025
 279,272
 91,209
 49,090
 1,595,423
Robert W. Bourne 2019 136,500
 1,250,029
 —
 154,932
 10,680
 1,552,141
Senior Vice President and 2018 —
 —
 —
 —
 —
 —
Chief Commercial Officer 2017 —
 —
 —
 —
 —
 —
John D. Montanti 2019 209,794
 156,139
 —
 —
 52,149
 418,082
Former Vice President, General 2018 —
 —
 —
 —
 —
 —
Counsel and Corporate Secretary 2017 —
 —
 —
 —
 —
 —
(5)For 2019, the amounts in this column reflect the compensation expenses related to Anadarko’s and Occidental’s retirement and savings plans that were allocated to us for the year. For 2020, the amounts reflect the expenses detailed in the table below:
NamePayments by the Partnership to Employee 401(k) Plan ($)Financial/Tax/Estate Planning ($)
Other ($) (1)
Total ($)
Michael P. Ure39,327 3,112 — 42,439 
Michael C. Pearl2,844 — 234,959 237,803 
Craig W. Collins37,500 4,000 — 41,500 
Charles G. Griffie38,231 — — 38,231 
Robert W. Bourne41,725 — — 41,725 
(1)

(1)In conjunction with Mr. Pearl’s termination from the Partnership on September 11, 2020, he received a payout of his accrued but unused paid time off balance of $67,813 and also received a cash payment of $167,146 to restore the employer contributions under the employee 401(k) plan he would have otherwise been entitled to absent the IRS compensation limits.
The amounts in this column reflect the base salary compensation allocated to us by Anadarko and Occidental for the years ended December 31, 2019, 2018, and 2017. Amounts for Messrs. Ure, Pearl, Collins, Bourne, and Griffie for the year ended December 31, 2019, reflect base salary compensation earned and allocated since their appointments as officers of our general partner.
(2)
The amounts in this column reflect an allocation to us of the aggregate grant date fair value of the awards, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for non-option stock awards granted pursuant to the Omnibus Plan. The value ultimately realized upon the actual vesting of the award(s) may or may not be equal to this determined value. For Messrs. Griffie and Montanti, their awards represent a grant prior to the acquisition of Anadarko by Occidental on August 8, 2019. For a discussion of valuation assumptions for the awards under the Omnibus Plan, see Note 14—Stock-Based Incentive Plans in the Notes to Consolidated Financial Statements included under Part II, Item 8 of Occidental’s Form 10-K for the year ended December 31, 2019 (which is not, and shall not be deemed to be, incorporated by reference herein). For information regarding the non-option stock awards granted to the named executives in 2019, see the Grants of Plan-Based Awards in 2019 table. The amounts in this column also reflect the allocation of performance unit awards, where such gross amounts were subject to market conditions and have been valued based on the probable outcome of the market conditions as of the grant date.


(3)
The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for option awards granted pursuant to the Omnibus Plan. See note (2) above for valuation assumptions. The value ultimately realized upon the exercise of the stock option(s) may or may not be equal to this determined value.
(4)
The amounts in this column reflect annual cash bonus compensation expected to be allocated to us for the year ended December 31, 2019, and the amounts allocated to us for the years ended December 31, 2018 and 2017.
(5)
The amounts in this column reflect the compensation expenses related to Anadarko’s and Occidental’s retirement and savings plans that were allocated to us for the years ended December 31, 2019, 2018, and 2017. Amounts for Messrs. Ure, Pearl, Collins, Bourne, and Griffie for the year ended December 31, 2019, reflect expenses allocated since their appointments as officers of our general partner. The 2019 allocated expenses are detailed in the table below:
Name 
Retirement Plans
Expense
 
Savings Plans
Expense
Michael P. Ure $—
 $43,252
Robin H. Fielder 27,381
 27,113
Michael C. Pearl 23,310
 18,599
Jaime R. Casas 35,222
 34,059
Charles G. Griffie 10,485
 7,875
Craig W. Collins —
 25,826
Robert W. Bourne —
 10,680
John D. Montanti 27,736
 24,413


Grants of Plan-Based Awards in 20192020

The following table sets forth information concerning annual cash incentive awards, stock options, phantom units, shares of restricted stock, restricted stock unitsequity incentive plan awards, and performance unitsunit awards. The equity incentive plan and unit awards were granted pursuant to the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan during 20192020 to each of the named executive officers. Except for amountsNEOs as described below.

Non-Equity Incentive Plan Awards (WCB Program).Values disclosed reflect the estimated cash payouts under the WES WCB Program, as discussed in the column entitled Exercise or Base PriceCompensation Discussion and Analysis. If threshold levels of Option Awards,performance are not met, the dollarpayout can be zero. If maximum levels of performance are achieved, the plan funding is capped at 200% of target payout. Because of the significant amount of discretion exercised by the Board in determining this year’s bonus amounts and number of securities includedunder the WCB Program, the amounts actually paid to the NEOs for 2020 are disclosed in the table belowSummary Compensation Table in the “Bonus” column.

Equity Incentive Plan Awards (ROA Units and TUR Units).Values disclosed reflect an allocationgrant date fair values for ROA Units and relative TUR Units, as discussed in the Compensation Discussion and Analysis. Officers may earn between 0% and 200% of the target awards based upon each named executive officer’s allocationon WES’s performance over a three-year performance period. Performance units earned are settled in the form of time to our business.common units. The awards include tandem distribution equivalent rights in the form of common units paid on the applicable distribution payment date.

Time-Based Unit Awards.Values disclosed reflect grant date fair values for time-based unit awards that vest ratably over three years, beginning with the first anniversary of the grant date. The awards include tandem distribution equivalent rights in the form of common units paid on the applicable distribution payment date.

183
Table of Contents
          
All
Other 
Stock
Awards:
Number of
Shares of
Stock or
Units
(#) (3)
 
All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#)
 
Exercise
or
Base Price
of Option
Awards
($/Sh)
 
Grant
Date
Fair Value
of Stock
and
Option
Awards 
($) (4)
  
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards (1)
 
Estimated Future Payouts Under
Equity Incentive Plan Awards (2)
    
Name and Grant Date 
Threshold 
($)
 
Target 
($)
 
Maximum 
($)
 
Threshold 
(#)
 
Target 
(#)
 
Maximum 
(#)
    
Michael P. Ure                    
— —
 135,000
 162,000
              
02/15/2019       2,299
 9,197
 18,394
       540,023
02/15/2019             8,037
     540,006
Michael C. Pearl                    
— —
 133,846
 160,615
              
Charles G. Griffie                    
— —
 58,462
 70,154
              
02/12/2019             4,860
     208,008
Craig W. Collins                    
— —
 140,000
 168,000
              
05/30/2019             9,633
     500,049
Robert W. Bourne                    
— —
 129,110
 154,932
              
08/09/2019 ��           26,523
     1,250,029
John D. Montanti                    
— —
 —
 —
              
03/12/2019             3,564
     156,139
All
Other 
Unit
Awards:
Number of
Units
(#)
Grant
Date
Fair Value
of Unit
Awards
($) (2)
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards
Estimated Future Payouts Under
Equity Incentive Plan Awards
Name and 
Award Type		Grant DateBoard Approval DateThreshold
($)		Target
($)
Maximum
($) (1)
Threshold
(#)		Target
(#)		Maximum
(#)
Michael P. Ure— — — 650,000 — — — — — — 
Time-Based Units02/12/202002/10/2020— — — — — — 156,055 2,539,015 
ROA Units02/12/202002/10/2020— — — 11,704 46,817 93,634 — 761,713 
TUR Units02/12/202002/10/2020— — — 11,704 46,817 93,634 — 832,874 
Michael C. Pearl (3)
— — — 390,000 — — — — — — 
Time-Based Units02/12/202002/10/2020— — — — — — 65,544 1,066,401 
ROA Units02/12/202002/10/2020— — — 5,072 20,288 40,576 — 330,086 
TUR Units02/12/202002/10/2020— — — 5,072 20,288 40,576 — 360,924 
Craig W. Collins— — — 390,000 — — — — — — 
Time-Based Units02/12/202002/10/2020— — — — — — 65,544 1,066,401 
ROA Units02/12/202002/10/2020— — — 5,072 20,288 40,576 — 330,086 
TUR Units02/12/202002/10/2020— — — 5,072 20,288 40,576 — 360,924 
Charles G. Griffie— — — 345,000 — — — — — — 
Time-Based Units02/12/202002/10/2020— — — — — — 40,575 660,155 
ROA Units02/12/202002/10/2020— — — 3,121 12,485 24,970 — 203,131 
TUR Units02/12/202002/10/2020— — — 3,121 12,485 24,970 — 222,108 
Robert W. Bourne— — — 330,000 — — — — — — 
Time-Based Units02/12/202002/10/2020— — — — — — 37,454 609,377 
ROA Units02/12/202002/10/2020— — — 2,731 10,924 21,848 — 177,733 
TUR Units02/12/202002/10/2020— — — 2,731 10,924 21,848 — 194,338 

(1)The non-equity incentive plan has a maximum overall funding of 200%, but there are no individual maximums established.
(2)The amounts reflect the fair value on the grant date of the awards made to the NEOs in 2020 computed in accordance with FASB ASC Topic 718. The value ultimately realized by the executive upon the actual vesting of the award(s) may or may not be equal to the determined value. For a discussion of valuation assumptions for the awards, see Note 15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(1)
(3)Mr. Pearl’s employment with the Partnership ended on September 11, 2020 and he did not receive a payout under the non-equity incentive plan and also forfeited a prorated portion of his equity incentive awards and stock awards upon his resignation. The values disclosed reflect the full awards granted to him in 2020.


184
Reflects the estimated 2019 annual cash incentive payouts allocable to us. If threshold levels of performance are not met, then the payout can be zero. The maximum value reflects the maximum amount allocable to us consistent with the methodologies set forth in the Services Agreement. The expense expected to be allocated to us for the actual bonus payouts under the annual incentive program for 2019 is reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.
(2)
Reflects, as of the time of grant, the estimated future payout allocable to us under performance units awarded in 2019. Mr. Ure is eligible to earn from 0% to 200% of the targeted award based on Occidental’s relative total shareholder return performance over a three-year performance period. The threshold value represents the minimum payment (other than zero) that was eligible to be earned.
(3)
Reflects the allocable number of shares of restricted stock and restricted stock units awarded in 2019 under the Omnibus Plan for Messrs. Griffie and Montanti and the Occidental LTIP Plan for Messrs. Ure, Collins, and Bourne, respectively. For Messrs. Griffie and Montanti, their awards represent a grant prior to the acquisition of Anadarko by Occidental on August 8, 2019. Mr. Ure’s award vests ratably on each February 28, 2020, 2021, and 2022. For Messrs. Collins, Bourne, and Montanti, these awards were eligible to vest ratably on each of the first three anniversaries of the grant date. Mr. Griffie’s awards will fully vest four years from the grant date.
(4)
The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the expected allocation to us of the grant date fair value of the awards at the time of grant made to named executives in 2019 computed in accordance with FASB ASC Topic 718. The value ultimately realized by the executive upon the actual vesting of the award(s) or the exercise of the stock option(s) may or may not be equal to the determined value. For a discussion of valuation assumptions for the awards under the Omnibus Plan and the Occidental LTIP Plan, see Note 14-Stock-Based Incentive Plans in the Notes to Consolidated Financial Statements under Part II, Item 8 of Occidental’s Form 10-K for the year ended December 31, 2019 (which is not, and shall not be deemed to be, incorporated by reference herein). There were no grants of stock options in 2019.



Outstanding Equity Awards at Year-End 20192020

The following table reflects outstanding equity awards for each of the named executive officersNEO as of December 31, 2019, including awards under the Omnibus Plan and Occidental LTIP Plan. As of December 31, 2019, none of our named executive officers have any outstanding awards under the LTIPs.2020. The market values shown are based on Occidental’sWES’s closing stockunit price of $41.21$13.82 on December 31, 2019, unless otherwise noted. Except for amounts in2020. The table excludes any prior outstanding awards granted under the column entitled Option Exercise Price, the dollar amounts and number of securities included in the table below reflect an allocation based upon each officer’s estimated allocation of time to our business during the fiscal year ended December 31, 2019. The awards listed below represent those for which expense is being allocated to the Partnership, butOccidental LTIP Plan, as described elsewhere, the Partnership is not reimbursing Occidental in cash for such awards. On August 8, 2019, all outstanding Anadarko restricted stock units and stock options were converted pursuant toper the terms of the December 2019 Services Agreement, the Partnership no longer reimburses Occidental Merger Agreement for Messrs. Pearlthe expense of these awards that were granted prior to 2020.
 Unit Awards
Equity Incentive Plan Awards
Restricted Units (1)
Performance Units (2)
 Number of
Units That Have
Not Vested
(#)		Market Value of Units That Have
Not Vested
($)		Number of Unearned Units
That Have Not Vested
(#)		Market or Payout
Value of Unearned Units That Have Not Vested
($)
Name
Michael P. Ure
Time-Based Units156,055 2,156,680 — — 
ROA Units— — 67,885 938,171 
TUR Units— — 81,930 1,132,273 
Michael C. Pearl
ROA Units— — 6,818 94,225 
TUR Units— — 8,229 113,725 
Craig W. Collins
Time-Based Units65,544 905,818 — — 
ROA Units— — 29,418 406,557 
TUR Units— — 35,504 490,665 
Charles G. Griffie
Time-Based Units40,575 560,747 — — 
ROA Units— — 18,104 250,197 
TUR Units— — 21,849 301,953 
Robert W. Bourne
Time-Based Units37,454 517,614 — — 
ROA Units— — 15,840 218,909 
TUR Units— — 19,117 264,197 

(1)The time-based units vest ratably over three years in installments on the first, second, and Griffie. Their respective amounts shown here representthird anniversaries of the grant date. One-third of the outstanding units vested on February 12, 2021, and the remaining unvested portion will vest one-third on February 12, 2022 and one-third on February 12, 2023. At the end of each vesting period, the number of units that conversion.vest are settled in unrestricted WES common units, less any units withheld for taxes.
(2)The number of outstanding performance units (including ROA units and TUR units) and the estimated payout values disclosed for each award, are calculated based on WES’s return on assets performance and relative total unit return performance ranking as of December 31, 2020, and are not necessarily indicative of what the payout earned will be at the end of each three-year performance period. Mr. Pearl’s outstanding units are based on his awards that were prorated upon his termination and continue to be subject to the original performance criteria. The three-year performance period for these awards is January 1, 2020 to December 31, 2022. WES’s performance to date as of December 31, 2020 under the ROA awards was 145% and 175% under the TUR awards.



185
          Stock Awards
              
Equity Incentive Plan
Awards
Performance Units (3)
          
Restricted Stock
Shares/Units (2)
 
Number of
Unearned
Shares,
Units or
Other
Rights
That Have
Not Vested
(#)
 
Market
Payout
Value of Unearned
Shares,
Units or
Other
Rights
That Have
Not Vested
($)
  
Option Awards (1)
 
Number of
Shares or
Units of
Stock That
Have Not
Vested
(#)
 
Market
Value of
Shares or
Units of
Stock That
Have Not
Vested
($)
 
  
Number of Securities
Underlying Unexercised Options
 
Option
Exercise
Price
($)
 
Option
Expiration
Date
    
  
Exercisable
(#)
 
Unexercisable
(#)
      
Name        
Michael P. Ure                
02/11/2015 2,700
 —
 79.98
 02/11/2022
 —
 —
 —
 —
02/15/2017 —
 —
 —
 —
 1,786
 73,601
 —
 —
02/07/2018 —
 —
 —
 —
 —
 —
 1,686
 69,480
02/07/2018 —
 —
 —
 —
 4,294
 176,956
 —
 —
02/15/2019 —
 —
 —
 —
 —
 —
 2,299
 94,742
02/15/2019 —
 —
 —
 —
 8,037
 331,205
 —
 —
Michael C. Pearl                
11/10/2016 —
 —
 —
 —
 1,875
 77,269
 —
 —
11/14/2017 —
 —
 —
 —
 220
 9,066
 —
 —
11/15/2018 —
 —
 —
 —
 411
 16,937
 —
 —
Charles G. Griffie                
11/28/2018 —
 —
 —
 —
 2,160
 89,014
 —
 —
11/28/2018 —
 —
 —
 —
 150
 6,182
 —
 —
02/12/2019 —
 —
 —
 —
 1,470
 60,579
 —
 —
Craig W. Collins                
05/30/2019 —
 —
 —
 —
 9,633
 396,976
 —
 —
Robert W. Bourne                
08/09/2019 —
 —
 —
 —
 26,523
 1,093,013
 —
 —

(1)Table of Contents
Stock options have a seven-year term and will vest ratably over three years in equal installments on the first, second, and third anniversaries of the date of grant. Stock option awards do not accrue dividends or dividend equivalents.
(2)
Generally, the restricted stock units will vest ratably over three years in installments on the first, second, and third anniversaries of the grant date. Mr. Ure’s 2017 restricted stock units will fully vest on February 28, 2020, his 2018 restricted stock units vested on February 28, 2019, and the remaining unvested portion will vest ratably on February 28, 2020 and 2021. One-third of Mr. Ure’s February 2019 restricted stock units will vest on February 28, 2020, 2021, and 2022. Messrs. Pearl’s and Griffie’s restricted stock units granted on November 10, 2016, and February 12, 2019, respectively, vest four years from the grant date. At the end of each vesting period, unless deferred, the number of restricted stock units that vest are settled in shares of unrestricted Occidental common stock, less applicable withholding taxes. For restricted stock units, dividend equivalents are accrued and reinvested in additional shares of common stock, less applicable withholding taxes. Pursuant to the Occidental Merger Agreement, each outstanding award of restricted stock units converted into a restricted stock and cash unit award of Occidental. Respectively, Messrs. Pearl and Griffie have the following cash portions outstanding as of December 31, 2019, that will vest ratably three years in installments on the first, second, and third anniversary of the grant date; Messrs. Pearl’s and Griffie’s award granted on November 10, 2016, and February 12, 2019, respectively, vests four years from grant date:
Named Executive Officers Cash Portions Outstanding
Michael C. Pearl  
11/10/2016 $369,842
11/14/2017 81,154
11/15/2018 43,498
Charles G. Griffie  
11/28/2018 29,723
11/28/2018 426,104
02/12/2019 289,901
(3)
The number of outstanding performance units and the estimated payout percentages disclosed for each award, for Mr. Ure, are calculated based on Occidental’s relative performance ranking as of December 31, 2019, and are not necessarily indicative of what the payout percent earned will be at the end of each three-year performance period. The three-year performance period generally starts in January in the year of grant and ends on December 31, 2020 and 2021 for 2018 and 2019 grants, respectively. Occidental’s relative performance rankings as of December 31, 2019 were 0% for the February 2018 and the February 2019 grants. For Mr. Ure’s award granted in February 2017 with a performance period beginning in 2019, the performance unit award is not outstanding as the award paid out at 0%. For Messrs. Pearl and Griffie, all outstanding performance units immediately vested on August 8, 2019, as provided under the terms of the Occidental Merger Agreement, and are not allocable to the Partnership.


Option Exercises and StockUnits Vested in 20192020

The following table reflects Anadarko and Occidental option awards exercised in 2019 and Anadarko and Occidental stockinformation about the aggregate dollar value realized during 2020 by our NEOs for WES awards that vested in 2020. The table below excludes the vesting of any prior awards granted under the Occidental LTIP, as per the terms of the December 2019 Services Agreement, the Partnership no longer reimburses Occidental for the expense of awards that were granted prior to the extent allocable to us. 2020.
 Unit Awards
Name
Number of Units 
Acquired on Vesting
(#) (1)
Value Realized
on Vesting
($) (2)
Michael P. Ure25,779 232,975 
Michael C. Pearl20,950 163,723 
Craig W. Collins10,957 99,018 
Charles G. Griffie6,767 61,159 
Robert W. Bourne6,123 55,339 

(1)The dollar amounts and number of securities includedunits acquired on vesting include the vesting of distribution equivalent rights that, per the terms of the underlying award agreements, were settled in common units on the date of the distribution payment. Mr. Pearl’s value also includes the prorated number of WES time-based units that vested upon his termination of employment on September 11, 2020.
(2)The value realized on vesting represents the aggregate number of units that vested multiplied by the common unit price on the vesting date. The actual value ultimately realized by the officer, may be more or less than the valued disclosed in the above table, below reflect an allocation baseddepending upon each officer’s allocation of time to our business.the timing in which he held or sold the units associated with the vesting occurrence.

  Option Awards Stock Awards
Name 
Number of Shares Acquired on Exercise (#) (1)
 
Value Realized on Exercise ($) (1)
 
Number of Shares Acquired on Vesting (#) (2)
 
Value Realized on Vesting ($) (2)
Michael P. Ure —
 —
 —
 —
Robin H. Fielder —
 —
 —
 —
Michael C. Pearl —
 —
 583
 22,607
Jaime R. Casas —
 —
 920
 35,249
Charles G. Griffie —
 —
 327
 12,653
Craig W. Collins —
 —
 —
 —
Robert W. Bourne —
 —
 —
 —
John D. Montanti —
 —
 669
 41,331
(1)
Shares acquired and values realized on exercise include options exercised in 2019. The amounts shown in the Value Realized on Exercise column represent the difference between the market price of common stock at exercise and the applicable exercise price of such option(s). The actual value ultimately realized by the named executive officer may be more or less than the realized value calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise. Pursuant to the Occidental Merger Agreement, for Messrs. Pearl, Griffie, and Casas and Ms. Fielder, each outstanding stock option was canceled and converted into the right to receive an amount in cash and was not allocable to the Partnership.
(2)
Shares acquired and values realized on vesting reflect the taxable value to the named executive officer as of the date of the vesting in 2019 of shares of restricted stock or restricted stock units, performance units, or phantom units. For each named executive officer, the amount shown in the Value Realized on Vesting column represents the aggregate number of restricted stock units or shares of restricted stock held by such named executive officer that vested during 2019 multiplied by the common stock price on the applicable vesting date(s). For shares of restricted stock or restricted stock units, the actual value ultimately realized by the named executive officer may be more or less than the value realized calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise or vesting occurrence. Mr. Ure’s shares acquired and values realized were incurred in early 2019 before becoming an executive officer of the Partnership and were never allocable to the Partnership.

Pension Benefits for 2019

2020
Occidental
WES does not have a defined benefit pension plan that provides named executive officersNEOs a fixed monthly retirement payment. Instead, all salaried employees on the U.S. dollar payroll, including the named executive officers,NEOs, are eligible to participate in one or morea tax-qualified defined contribution plans. Under the omnibus agreement, a portion of the annual expense related to these plans is reimbursed by us to Occidental. The allocated expense for each named executive officer is included in the All Other Compensation column of the Summary Compensation Table. We have not included a pension benefits table as Occidental does not allocate expense to us upon an employee’s retirement and the subsequent payment of benefits under such pension plans. For additional discussion of Occidental’s pension benefits, read Compensation Discussion and Analysis — Indirect Compensation Elements — Retirement Benefits contained within Occidental’s proxy statement for its 2019 annual meeting of stockholders, which is expected to be filed with the SEC within 120 days of December 31, 2019.plan.

Nonqualified Deferred Compensation for 20192020

Occidental maintains two    WES does not have a nonqualified deferred compensation plans: (i) the Supplemental Retirement Plan II (the “SRP II”), and (ii) the Modified Deferred Compensation Plan (the “MDCP”). The purpose of the SRP II is to provide eligible employees, including the named executive officers, with benefits to compensate them for maximum limits imposed by law on the amount of contributionsplan that may be made to Occidental’s tax-qualified defined contribution plans. The purpose of the MDCP is to provide key management and highly compensatedallows employees the ability to accumulate additional retirement income through deferrals of compensation.


Pursuant to the terms
186
Table of the omnibus agreement, a portion of the expense related to these plans is reimbursed by us to Occidental. The allocated expense for each named executive officer is included in the All Other Compensation column of the Summary Compensation Table. We have not included a nonqualified deferred compensation table as Occidental does not allocate expense to us upon distribution of such balances. For additional discussion on Occidental’s nonqualified deferred compensation benefits, read the Compensation Discussion and Analysis — Other Compensation and Benefits section contained within Occidental’s proxy statement for its 2019 annual meeting of stockholders, which is expected to be filed with the SEC within 120 days of December 31, 2019.Contents

Potential Payments Upon Termination or Change of Control

Prior    In connection with the transfer of employment of our NEOs to entry into the Services Agreementa subsidiary of WES on December 31, 2019, inand per the event of a change of control of the general partner or Occidental, we would not be responsible for paying any change of control benefits to our named executive officers. As of December 31, 2019, noneterms of our named executive officers have any outstanding awards under the LTIPs.
Prior to December 31, 2019,Services Agreement, we did not have any employment agreements with our named executive officers. However, during 2019, our named executive officers were eligible for certainassumed severance and termination pay benefitsobligations under plans and programs maintained by Anadarko and Occidental. In connection with the Occidental Merger, Ms. Fielder and Mr. Montanti terminated employment with Anadarko and Occidental and received certain benefits under these arrangements. Such arrangements were not intended as compensation for services to us and we did not incur any costs associated with those payments.
The severance and termination pay arrangements of Anadarko included, for Messrs. Pearl and Griffie, a key employee change of control contract, pursuant to which the executive would be entitled to enhanced severance benefits in the event of an involuntary termination of employment without cause or resignation for good reason following a change of control of Anadarko (the “Anadarko COC Agreements”).Anadarko. The Occidental Merger constituted a change of control of Anadarko for purposes of these agreements. Upon an involuntary termination of employment without cause during the two-year period following the closing of the Occidental Merger,In 2019, to encourage retention and dedication, Messrs. Pearl and Griffie would be entitled to receive the following severance benefits under these agreements: (i) the aggregate amount set forthwere granted retention awards by Occidental in the following sections (A) through (E) paid in cash lump sum within twenty days following the applicable executive’s date of termination, (A) an annual bonus, based on the higher of (x) the highest annual bonus earned by the applicable executiveexchange for the last three years prior to the change of control and (y) the annual bonus paid or payable for the most recently completed fiscal year, (B) two times the sum of the applicable executive’s annual base salary plus the highest annual bonus (as determined in clause (A)), (C) an amount equal to the total value due to the applicable executive under the savings restoration plan, (D) an amount equal to the matching contributions which would have been made on the executive’s behalf in the employee savings plan plus the amount the executive would have accrued under the savings restoration plan for the twenty-four month period following the applicable executive’s termination of employment, (E) an amount equal to the sum of (y) the applicable executive’s accrued retirement benefit payable under the retirement restoration plan and (z) any additional retirement benefits that the applicable executive would have accrued under the tax-qualified benefit plan in which the executive participates and the retirement restoration plan as if the executive continued employment for two years following the applicable executive’s date of termination, (ii) up to $30,000 in outplacement services, and (iii) continued life, accident, disability, medical and health care benefit coverage for two years following the applicable executive’s date of termination. In connection with their acceptance of the retention award opportunities described above under the heading “Retention bonuses,” Messrs. Pearl and Griffie waivedwaiving their right to receive severance pay or benefits upon a resignation of employment for good reason or involuntary termination without cause.cause under these agreements. Pursuant to the Services Agreement, we are not responsible for the cost of these retention awards.
The severance and termination pay arrangements of Anadarko also included the Anadarko Petroleum Corporation Amended and Restated Change of Control Severance Plan, which was a broad-based plan covering substantially all of Anadarko’s employees who provided services to us and provided for enhanced severance benefits following a change of control of Anadarko (the “ Anadarko“Anadarko COC Plan”). The Anadarko COC Plan provided that eligible participants are entitled to certain severance benefits if (i)(A) the participant’s employment is terminated without cause by the participant’s employer or (B) if the participant terminates his or her employment within ninety days following the sale or disposition of the participant’s employer in which the participant was not offered substantially similar employment and compensation terms with the purchaser, in each case, within three years of a change of control or (ii) the participant resigns for good reason within one year following a change of control (all such terminations, a “Qualifying Termination”). Assuming there is a Qualifying Termination, the severance benefits upon termination under the Anadarko COC Plan include the following:

•A cash lump sum equal to (A) 50% of the sum of (i) the participant’s monthly base salary plus (ii) the highest annual bonus received by the participant over the previous three years, divided by twelve, multiplied by the number of years of service by the participant (clauses (i) and (ii), “Monthly Compensation”) and (B) one month of Monthly Compensation for each $10,000 of annual compensation (base salary plus highest annual bonus), rounding up to the next highest whole multiple of $10,000 if the participant’s annual compensation is not a multiple of $10,000 (the “Severance Benefit”);

Pro-rata•A cash lump sum equal to the pro-rata annual bonus based on the participant’s target bonus percentage; and


•Continuation of medical and dental insurance coverage for up to six months following termination of employment.

Notwithstanding the foregoing benefits, the minimum Severance Benefit under the Anadarko COC Plan is three times the Monthly Compensation and the maximum Severance Benefit is twenty-four times the Monthly Compensation.
In connection with the transfer of employment ofWhile employees maintain their eligibility and participation under these arrangements, our named executive officersobligations are limited to a subsidiary of WES on December 31, 2019, we assumed severance and termination pay obligations under the Anadarko COC Agreements and the Anadarko COC Plan. However, with respect to the employees of Anadarko who provided services to us, any compensation amounts arising as a result of the Occidental Merger are not intended as compensation for services to us. As a result, pursuant to the Services Agreement, Anadarko and Occidental will be responsible for all benefits under the Anadarko COC Agreements and the Anadarko COC Plan with respect to any employee (including named executive officers) to the extent such benefits exceed theno greater of sixthan 6 months of the employee’s base salary or for our NEOs, an amount the amount of severance payments the employeeofficer would be entitled to receive under the formulas that were set forth in Anadarko’s applicable non-change in control Officer Severance Plan. The Anadarko Entities, not our General Partner, are responsible for any payments that exceed these amounts.
In order to provide for uniformity in severance entitlements, on December 31, 2019, our Board extended the benefits under the Anadarko COC Plan to the NEOs who were not employed with Anadarko prior to the Occidental Merger (this includes Messrs. Ure, Collins, and Bourne). These benefits will apply for so long as the Anadarko COC Plan continues to apply for the former Anadarko employees who are now employed with us. For these NEOs, we will be responsible for 100% of controlthese broad-based severance plans. Further,payments and benefits available under the plan.
Per the terms of our Services Agreement provides that we will not reimburse Occidental in cash for amounts related to the vesting of any outstanding equity or long-term incentive awards (whether vested, unvested, deferred, or otherwise) previously granted by Anadarko or Occidental to our named executive officers.NEOs, accordingly these awards are excluded from the amounts shown below.
In addition, on


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Involuntary For Cause. For “cause” is generally defined as: (i) conviction of a felony or of a misdemeanor involving moral turpitude, (ii) willful failure to perform duties or responsibilities, (iii) engaging in conduct which is injurious (monetarily or otherwise) to the Partnership (or any affiliates), (iv) engaging in business activities which are in conflict with the business interests of the Partnership (or any affiliates), (v) insubordination, (vi) engaging in conduct which is in violation of any applicable policy or work rule, (vii) engaging in conduct in violation of applicable safety rules or standards, or (viii) engaging in conduct that is in violation of the applicable Code of Ethics and Business Conduct.

Mr. UreMr. CollinsMr. GriffieMr. Bourne
Cash Severance$— $— $— $— 
Total$— $— $— $— 

Involuntary Not For Cause Termination. As of December 31, 2019,2020, unless otherwise noted, our NEOs were eligible for severance benefits under the broad-based Anadarko COC Plan in the event they are terminated without cause before the end of the change of control period defined under the Plan, which is August 8, 2022. The original severance benefits were subject to providea double-trigger; however, the Occidental Merger constituted a change of control of Anadarko for uniformity in severance entitlements, our Boardpurposes of Directors determinedthese arrangements and met the requirements for the first trigger. Accordingly, benefits are now subject only to extend the benefitssecond trigger of an involuntary not for cause termination.

Mr. UreMr. PearlMr. CollinsMr. GriffieMr. Bourne
Cash Severance (1)
$2,800,000 $— $1,651,000 $— $1,437,000 
Pro-Rata Annual Cash Bonus (2)
650,000 — 390,000 — 330,000 
Pro-Rata Vesting of WES Equity Awards (3)
1,323,928 302,735 565,238 348,844 313,161 
Other Payments (4)
— 167,146 — — — 
Total$4,773,928 $469,881 $2,606,238 $348,844 $2,080,161 

(1)The amounts above for Messrs. Ure, Collins and Bourne reflect the double-trigger broad-based rights extended to them under the Anadarko COC PlanPlan. Due to the named executive officers who werewaiver of certain change of control rights discussed above, Messrs. Pearl and Griffie do not employedhave arrangements covering involuntary not for cause termination. Mr. Pearl left the Partnership on September 11, 2020, and did not receive any cash severance in connection with Anadarko prior to the Occidental Merger (which includeshis departure.
(2)The amounts for Messrs. Ure, Collins and Bourne)Bourne reflect a prorated annual bonus based on their target bonus for so longthe year, assuming that each such NEO’s employment terminates as of December 31 of the applicable year, pursuant to the rights extended to them under the Anadarko COC Plan continuesPlan. Mr. Pearl did not receive a bonus upon his termination and Mr. Griffie, as discussed above, has waived his rights to applya prorated bonus.
(3)The amounts reflect the estimated current value of a prorated portion of unvested time-based units and unvested performance units, based on performance to date, all as of December 31, 2020. In the event of an involuntary termination not for cause, the former Anadarko employees who are now employed with us. For these named executive officers, we will be responsible for 100% of these broad-based severance payments and benefits available under the plan.
Unless otherwise noted, the amounts shown below are limited to amounts that would be payable by us under the Services Agreement and do not include amounts thatperformance units would be paid provided, or reimbursedafter the end of the performance period, based on actual performance.
(4)In conjunction with Mr. Pearl’s termination from the Partnership on September 11, 2020, he received a cash payment to us by Anadarko or Occidental.restore the employer contributions under the employee 401(k) plan he would have otherwise been entitled to absent the IRS compensation limits.

Involuntary Not For Cause Termination
  Mr. Ure Mr. Collins Mr. Bourne
Cash Severance (1)
 $2,825,000
 $400,000
 $390,000
Total $2,825,000
 $400,000
 $390,000
(1)
Pursuant to the terms of the Services Agreement, our liability for severance owed to Messrs. Collins and Bourne is capped at one year of base salary, which is the amount that would have been payable if such officers were subject to the Anadarko Officer Severance Plan. The amount above for Mr. Ure reflects the single-trigger broad-based rights extended to him under the Anadarko COC Plan, as such amount is not capped under the Services Agreement. Due to the waiver of certain change of control rights discussed above, Messrs. Pearl and Griffie do not have arrangements covering involuntary not-for-cause termination other than agreements with Occidental providing for the vesting of equity or acceleration of retention payments for which, in either case, we are not obligated under the Services Agreement.

Change of Control: Involuntary Termination or Voluntary For Good ReasonReason. As noted above, on December 31, 2020 certain of our NEOs were eligible for severance benefits under the broad-based Anadarko COC Plan in the event they are terminated without cause before the end of the change of control period defined under the Plan, which is August 8, 2022. Per the terms of the Services Agreement, we assumed Mr. Griffie’s Anadarko key employee change of control contract and while he waived any additional benefits related to the Occidental Merger, he is eligible for severance benefits under this contract in the event of a change of control of WES and a qualifying termination event. In the event there is a change of control of WES and a qualifying termination event, the NEOs would also receive the accelerated vesting of their WES equity awards.

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  Mr. Ure Mr. Pearl Mr. Collins Mr. Bourne Mr. Griffie
Cash Severance (1)
 $2,825,000
 $435,000
 $1,733,123
 $1,297,110
 $380,000
Total $2,825,000
 $435,000
 $1,733,123
 $1,297,110
 $380,000
Per the terms of the award agreements, a change of control is deemed to have occurred in the event: (i) any person or group other than the Partnership or Occidental (or affiliate) becomes the beneficial owner of more than 50% of the combined voting power of the equity interests in the General Partner, (ii) our equity holders approve, in one or a series of transactions, a plan of complete liquidation of the Partnership, (iii) the sale or disposition by the Partnership of all or substantially all of its assets to any person other than an affiliate of the General Partner or Partnership, or (iv) the General Partner or an affiliate of the General Partner ceases to be the general partners of the Partnership and a single person or group other than the Partnership or Occidental (or affiliate) beneficially owns more than 50% of the combined voting power of the equity interests in the entity that is or becomes the general partner of the Partnership.
(1)
Pursuant to the terms of the Services Agreement, our liability for severance owed to Messrs. Pearl and Griffie is capped at one year of base salary, which is the amount that would have been payable if such officers were subject to the Anadarko Officer Severance Plan. Although the amounts payable to Messrs. Ure, Collins, and Bourne under the Anadarko COC Plan are generally available to all WES employees, 100% of such amounts are included above because such amounts are not capped under the Services Agreement.

Because the one-year good reason protection period under the Anadarko COC Plan has lapsed, a voluntary termination for good reason is no longer a qualifying termination event under that Plan. Mr. Griffie’s change of control contract and the WES equity award agreements include good reason as a qualifying termination event, with good reason generally defined as any one of the following occurrences within two years of a change of control: (i) a diminution of duties and responsibilities, (ii) a material reduction in compensation, (iii) a material change in work location, as defined in the applicable agreement, or (iv) a requirement to travel for business to a substantially greater extent, with all occurrences compared to agreements in place immediately prior to the change of control.

Mr. UreMr. CollinsMr. GriffieMr. Bourne
Cash Severance (1)
$2,800,000 $1,651,000 $1,925,750 $1,437,000 
Pro-Rata Annual Cash Bonus (2)
650,000 390,000 345,000 330,000 
Accelerated Vesting of WES Equity Awards (3)
4,227,123 1,803,040 1,112,892 1,000,720 
Total$7,677,123 $3,844,040 $3,383,642 $2,767,720 

(1)The amounts for Messrs. Ure, Collins, and Bourne reflect the double-trigger broad-based rights extended to them under the Anadarko COC Plan. Mr. Griffie’s benefits reflect the cash severance benefits payable under his legacy Anadarko key employee change of control contract that we assumed as part of the Services Agreement.
(2)Messrs. Ure, Collins, and Bourne values reflect a prorated annual bonus based on their target bonus for the year, pursuant to the rights extended to them under the Anadarko COC Plan. Pursuant to the terms of his key employee contract, Mr. Griffie’s value reflects a prorated target bonus for the year.
(3)The amounts reflect the estimated current value of unvested performance units based on performance to date and the value of unvested time-based units, all as of December 31, 2020. In the event of a change of control, the performance would be calculated based on the change of control date.

Disability
Mr. UreMr. CollinsMr. GriffieMr. Bourne
Accelerated Vesting of WES Equity Awards (1)
$4,227,123 $1,803,040 $1,112,892 $1,000,720 
Total$4,227,123 $1,803,040 $1,112,892 $1,000,720 
_______________________________________________________________________________________=
(1)Values reflect the estimated current value of unvested performance units based on performance to date and the value of unvested time-based units, all as of December 31, 2020. In the event of a disability termination, the performance units would be paid after the end of the performance period, based on actual performance.

Death
Mr. UreMr. CollinsMr. GriffieMr. Bourne
Accelerated Vesting of WES Equity Awards (1)
$4,227,123 $1,803,040 $1,112,892 $1,000,720 
Total$4,227,123 $1,803,040 $1,112,892 $1,000,720 

(1)Values reflect the estimated current value of unvested performance units based on performance to date and the value of unvested time-based units, all as of December 31, 2020. In the event of death, the performance units would be paid after the end of the performance period, based on actual performance.


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CEO Pay Ratio

Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, require disclosure regarding the relationship of the annual compensation of our employees and the annual compensation of Mr. Michael P. Ure, our Chief Executive Officer (CEO). For the year ended December 31, 2019, our general partnerPrior to 2020, because we did not directly employhave any employees, our pay ratio was based on those employees of Anadarko and Occidental that provided services to us pursuant to (i) the persons responsible for managing our business. Rather, until December 31, 2019, all ofServices and Secondment Agreement and (ii) the employees, including executive officers, who managed our business were employed by Occidental (or, prior to the Occidental Merger, by Anadarko) and their respective subsidiaries other than us.omnibus agreement. As discussed in the Employees section in Business and Properties under Part I, Items 1 and 2 of this Form 10-K, as of December 31, 2019,2020, we had 191,045 employees.
We identified the median employee by using base salary earnings for all employees, excluding our CEO, who were employed by us on December 31, 2020. We included all employees, whether employed on a full-time or part-time basis, and did not make any estimates, assumptions, or adjustments to the data. After identifying the median employee, we calculated annual total compensation for such employee using the same methodology used for our NEOs as set forth in the process of transferring to WES employment, which was effective as of January 12,above 2020 and seconded employees deemed jointly employed by Occidental and our general partner. Nonetheless, in an effort to comply with this requirement, theSummary Compensation Table. The pay ratio provided below has been calculated as the total 20192020 annual compensation for Mr. Ure of $5,434,887, divided by the total 2020 annual compensation of the median employee providing services to us pursuant to (i) the Services and Secondment Agreement and (ii) the omnibus agreement, in each case on an unallocated (100%) basis.of $139,573. For 2019,2020, the ratio resulting from this calculation was 939 to 1.


Director Compensation

On September 11, 2020, WES announced a re-composition of the board of directors of its general partner. Kenneth F. Owen, David J. Schulte, and Lisa A. Stewart (each a "New Director") were appointed as independent directors. In connection with a reduction in the size of the Board from eleven to eight directors, Steven D. Arnold, Marcia E. Backus, James R. Crane, Thomas R. Hix, Craig W. Stewart, and David J. Tudor left the Board. Officers or employees of Occidental who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Non-employee directors of our general partner receivereceived compensation during 2020 for their boardBoard service and for attending Board and committee meetings pursuant to a director compensation plan approved by the Board of Directors.Board. There were no changes to the director compensation plan during 2019, except that the value of the annual equity grant was increased from $100,000 to $125,000. 2020.

Compensation for independentnon-employee directors consistsduring 2020 consisted of the following:

•an annual retainer of $110,000 for each non-employee Board member;

•an annual retainer of $2,000 for each member of the Audit Committee, or $17,000$22,000 for the Audit Committee chair;

•an annual retainer of $2,000 for each member of the Special Committee, or $17,000$22,000 for the Special Committee chair;

•a fee of $2,000 for each Board and committee meeting attended to the extent a non-employee Board member attends in excess of 10 total Board and committee meetings in one calendar year; and

•annual grants of phantom units with a value of approximately $125,000 on the date of grant, all of which vest 100% on the first anniversary of the date of grant (with vesting to be accelerated upon a change of control of our general partner or Occidental).$125,000.

In addition, each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the Board of Directors or committees and for costs associated with participation in continuing director education programs. Each director is fully indemnified by us, pursuant to individual indemnification agreements and our partnership agreement, for actions associated with being a director to the fullest extent permitted under Delaware law.


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The following table sets forth information concerning total director compensation earned during 20192020 by each non-employee director:
Name
Fees Earned or Paid in Cash
($) (1)
Stock
Awards 
($) (2)
Total
($)
Kenneth F Owen40,783 52,931 93,714 
David J. Schulte40,783 52,931 93,714 
Lisa A. Stewart34,696 52,931 87,627 
Oscar K. Brown69,203 54,855 124,058 
Thomas R. Hix165,000 113,299 278,299 
Craig W. Stewart140,000 113,299 253,299 
David J. Tudor167,500 113,299 280,799 
Steven D. Arnold140,000 113,299 253,299 
James R. Crane140,000 113,299 253,299 

(1)The amounts include fees earned during the year and an additional payment made to Messrs. Hix, Stewart, Tudor, Arnold, and Crane upon their resignation from the Board.
Name Fees Earned or Paid in Cash 
Stock Awards (1)
 Option Awards Non-Equity Incentive Plan Compensation All Other Compensation Total
Thomas R. Hix $121,681
 $125,010
 $—
 $—
 $—
 $246,691
Craig W. Stewart 112,333
 125,010
 —
 —
 —
 237,343
David J. Tudor 146,518
 125,010
 —
 —
 —
 271,528
Steven D. Arnold 112,333
 125,010
 —
 —
 —
 237,343
James R. Crane 112,333
 125,010
 —
 —
 —
 237,343
Milton Carroll 79,989
 125,010
 —
 —
 —
 204,999
(1)
The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in 2019,(2)The amounts included in the Stock Awards column represent the grant date fair value of phantom units made to directors in 2020, computed in accordance with FASB ASC Topic 718. Upon the September 11, 2020 departure of Messrs. Hix, Stewart, Tudor, Arnold, and Crane, the Board approved the vesting of their outstanding phantom units. For these directors, the amounts include the incremental fair value of the awards on the modification date, of $58,444, valued in accordance with FASB ASC Topic 718. See the table below for phantom units awarded to each non-employee director during 2020. As of December 31, 2020, Messrs. Owen and Schulte and Ms. Stewart each had 7,182 outstanding phantom units; Mr. Brown had 7,803 outstanding phantom units; and Messrs. Hix, Stewart, Tudor, Arnold, and Crane had no outstanding phantom units.

The table below for phantom units awarded to each non-employee director during 2019.

The following table contains the grant date fair value of phantom unit awards made to each non-employee director during 2019:2020:
NameGrant Date
Phantom 
Units 
(#) (1)
Grant Date Fair 
Value of Stock Awards
($) (2)
Kenneth F OwenSept 237,182 52,931 
David J. SchulteSept 237,182 52,931 
Lisa A. StewartSept 237,182 52,931 
Oscar K. BrownMay 147,803 54,855 
Thomas R. HixMay 147,803 54,855 
Craig W. StewartMay 147,803 54,855 
David J. TudorMay 147,803 54,855 
Steven D. ArnoldMay 147,803 54,855 
James R. CraneMay 147,803 54,855 

(1)The awards granted on September 23, 2020 reflect a prorated annual award granted to the new directors upon their appointment to the Board and will vest on February 12, 2021, a vesting date that aligns with the annual vesting of our NEO awards. Mr. Brown’s award granted on May 14, 2020 vests on May 14, 2021. On September 11, 2020, upon the departure of Messrs. Hix, Stewart, Tudor, Arnold, and Crane, the Board approved the vesting of their outstanding units granted on May 14, 2020.
(2)The amounts included in the Grant Date Fair Value of Stock Awards column represent the grant date fair value of the awards made to non-employee directors in 2020 computed in accordance with FASB ASC Topic 718. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not have been equal to the value included above.


191
Name Grant Date Phantom Units (#) 
Grant Date Fair Value of Stock and Option Awards ($) (1)
Thomas R. Hix May 8 4,202
 125,010
Craig W. Stewart May 8 4,202
 125,010
David J. Tudor May 8 4,202
 125,010
Steven D. Arnold May 8 4,202
 125,010
James R. Crane May 8 4,202
 125,010
Milton Carroll May 8 4,202
 125,010
Table of Contents
(1)
The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the grant date fair value of the awards made to non-employee directors in 2019 computed in accordance with FASB ASC Topic 718. These awards vested on August 8, 2019, as a result of Anadarko being acquired by Occidental pursuant to the Occidental Merger. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not have been equal to the value included above.

Compensation Committee Interlocks and Insider Participation

As previously discussed, our general partner’s Board of Directors is not required to maintain, and does not maintain, a compensation committee. Messrs. Vangolen and Bennett, and Brown and Mses. Backus and Kirk,Ms. Clark, who are directors of our general partner, are also executive or corporate officers of Occidental. However, all compensation decisions with respect to each of these persons are made by Occidental, and none of these individuals receive any compensation directly from us or our general partner for their service as directors. Read Part III, Item 13 below in this Form 10-K for information about relationships among us, our general partner, and Occidental.

Compensation Committee Report

Neither we nor our general partner has a compensation committee. The Board
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Table of Directors has reviewed and discussed the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.Contents

The Board of Directors of Western Midstream Holdings, LLC:

Glenn Vangolen
Michael P. Ure
Marcia E. Backus
Peter J. Bennett
Oscar K. Brown
Jennifer M. Kirk
Steven D. Arnold
James R. Crane
Thomas R. Hix
Craig W. Stewart
David J. Tudor



Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth the beneficial ownership of our common units held by the following as of February 24, 2020:22, 2021:

•each member of the Board of Directors;

•each named executive officer of our general partner;

•all directors and officers of our general partner as a group; and

•Occidental and its affiliates.
Name and Address of Beneficial Owner (1)
Common
Units
Beneficially Owned		Percentage of
Common Units
Beneficially
Owned
Occidental Petroleum Corporation (2)
214,281,578 51.9%
Glenn Vangolen— *
Michael P. Ure (3)
69,498 *
Robert W. Bourne14,628 *
Craig W. Collins32,760 *
Christopher B. Dial12,879 *
Catherine A. Green5,389 *
Charles G. Griffie16,953 *
Peter J. Bennett— *
Oscar K. Brown1,440 *
Nicole E. Clark— *
Kenneth F. Owen7,182 *
David J. Schulte11,682 *
Lisa A. Stewart7,182 *
All directors and executive officers
as a group (13 persons)		179,593 *

*Less than 1%.
(1)The address for Occidental and its representatives on the Board of Directors of our general partner is 5 Greenway Plaza, Suite 110, Houston, Texas 77046. The address for all other beneficial owners in this table is 9950 Woodloch Forest Drive, Suite 2800, The Woodlands, Texas 77380.
(2)WGRI owns 161,319,520 common units, AMH owns 457,849 common units, WGRAH owns 38,139,260 common units, and Anadarko USH1 Corporation owns 14,364,949 common units of WES. Occidental is the ultimate parent company of each of the foregoing entities and may, therefore, be deemed to beneficially own the units held by such entities.
(3)Includes 10,000 common units held in a margin account. However, there are currently no margin borrowings associated with this account.

193
Name and Address of Beneficial Owner (1)
 
Common
Units
Beneficially Owned (3)
 
Percentage of
Common Units
Beneficially
Owned
Occidental Petroleum Corporation (2)
 242,136,976
 54.5%
Glenn Vangolen —
 *
Michael P. Ure —
 *
Michael C. Pearl 1,250
 *
Craig W. Collins 1,132
 *
Robert W. Bourne —
 *
Charles G. Griffie 706
 *
Marcia E. Backus —
 *
Peter J. Bennett —
 *
Oscar K. Brown 1,440
 *
Jennifer M. Kirk —
 *
Steven D. Arnold 72,616
 *
James R. Crane 254,201
 *
Thomas R. Hix 18,530
 *
Craig W. Stewart 30,073
 *
David J. Tudor 31,241
 *
Christopher B. Dial —
 *
Catherine A. Green 100
 *
All directors and executive officers
as a group (17 persons)
 411,289
 *
*Less than 1%
(1)Table of Contents
The address for Occidental and its representatives on the Board of Directors of our general partner is 5 Greenway Plaza, Suite 110, Houston, Texas 77046. The address for all other beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.
(2)
WGRI owns 161,319,520 common units, AMH owns 24,771,550 common units, WGRAH owns 38,139,260 common units, Kerr-McGee Worldwide Corporation owns 684,922 common units, and Anadarko E&P Onshore LLC owns 17,221,724 common units of WES. Occidental is the ultimate parent company of each of the foregoing entities and may, therefore, be deemed to beneficially own the units held by such entities.
(3)
Does not include unvested WES phantom unit awards as follows:
Name Number of Units
 Time-Based Awards TUR Awards ROA Awards
Michael P. Ure 156,055 46,817 46,817
Michael C. Pearl 65,544 20,288 20,288
Craig W. Collins 65,544 20,288 20,288
Charles G. Griffie 40,575 12,485 12,485
Robert W. Bourne 37,454 10,924 10,924
Christopher B. Dial 34,333 9,364 9,364
Catherine A. Green 14,046 3,902 3,902

The following table sets forth owners of 5% or greater of our common units, other than Occidental and its affiliates, the holdings of which are listed in the first table of this Item 12.
Title of ClassName and Address of Beneficial Owner
Amount and

Nature

of Beneficial

Ownership
Percent of Class
Common UnitsALPS Advisors, Inc.
1290 Broadway, Suite 1100
Denver, CO 80203
24,153,629 (1)
5.33%5.84%
Common UnitsInvesco Ltd.
1555 Peachtree Street NE, Suite 1800
Atlanta, GA 30309
21,340,971 (2)
5.16%

(1)Based upon its Schedule 13G/A filed February 9, 2021, with the SEC with respect to Partnership securities held as of December 31, 2020, ALPS Advisors, Inc. (“ALPS”) has shared voting and dispositive power as to 24,153,629 common units and Alerian MLP ETF, a fund controlled by ALPS, also has shared voting and dispositive power as to 24,098,923 of the common units held by ALPS.
(1)
(2)Based upon its Schedule 13G filed February 16, 2021, with the SEC with respect to Partnership securities held as of December 31, 2020, Invesco Ltd. has sole voting and dispositive power as to 21,340,971 common units.

Based upon its Schedule 13G filed February 7, 2020, with the SEC with respect to Partnership securities held as of December 31, 2019, ALPS Advisors, Inc. (“ALPS”) has shared voting and dispositive power as to 24,153,629 common units and Alerian MLP ETF, a fund controlled by ALPS, also has shared voting and dispositive power as to 24,098,923 of the common units held by ALPS.

Securities Authorized for Issuance Under Equity Compensation Plan

The following table sets forth information with respect to the securities that may be issued under the LTIPsWestern Gas Equity Partners, LP 2012 Long-Term Incentive Plan and the Western Gas Partners, LP 2017 Long-Term Incentive Plan as of December 31, 2019.2020. For more information regarding the LTIPs,plans, read Note 6—Transactions with Affiliates15—Equity-Based Compensation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Plan Category(a)
Number of 
Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants, and Rights		(b)
Weighted-Average
Exercise Price of
Outstanding
Options, Warrants,
and Rights		(c)
Number of Securities
Remaining Available for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in Column(a))
Equity compensation plans approved by security holders— — 3,431,251 
Equity compensation plans not approved by security holders
1,741,530 (1)
— (2)
1,082,437 
Total1,741,530 — 4,513,688 

(1)Includes performance units at their maximum payout of 200%.
(2)Phantom and performance units constitute the only rights outstanding under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan. Each phantom or performance unit that may be settled in common units entitles the holder to receive, upon vesting and determination of any performance criteria, if applicable, one common unit with respect to each phantom or performance unit, without payment of any cash. Accordingly, there is no reportable weighted-average exercise price.
194
Plan Category
(a)
Number of 
Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants, and Rights
(b)
Weighted-Average
Exercise Price of
Outstanding
Options, Warrants,
and Rights
(c)
Number of Securities
Remaining Available for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in Column(a))
Equity compensation plans approved by security holders—
—
3,419,020
Equity compensation plans not approved by security holders—
—
2,911,985
Total—
—
6,331,005


Item 13.  Certain Relationships and Related Transactions, and Director Independence

As of February 24, 2020,22, 2021, Occidental held (i) 242,136,976214,281,578 of our common units, representing a 53.4%50.8% limited partner interest in us, (ii) through its ownership of the general partner, 9,060,641 general partner units, representing a 2.0%2.1% general partner interest in us, and (iii) a 2.0% limited partner interest in WES Operating through its ownership of WGRAH.
We control, manage, and operate WES Operating through our ownership of WES Operating GP. We, directly and indirectly through our ownership of WES Operating GP, owned a 98.0% limited partner interest and the entire non-economic general partner interest in WES Operating.
The officers of our general partner are also officers of WES Operating GP and our general partner’s officers operate WES Operating’s business. SixFive of our directors are currently or formerly affiliated with Occidental and our remaining directors are independent as defined by the NYSE.

Agreements with Occidental

We, WES Operating, and other parties have entered into various agreements with Occidental as discussed below. These agreements were not the result of arm’s-length negotiations and, as such, they or the related underlying transactions may not be based on terms as favorable as those that could have been obtained from unaffiliated third parties.

Merger transactions. On February 28, 2019, WES, WES Operating, Anadarko, and certain of their affiliates completed the Merger. See Note 1—Summary of Significant Accounting Policies 6—Related-Party Transactionsin the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information.more information regarding the transactions and agreements discussed below.

Summary of Material Related-Party Transactions

The following tables summarize material related-party transactions included in our consolidated financial statements (see Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K):
Consolidated statements of operations
Year Ended December 31,
thousands202020192018
Revenues and other
Service revenues – fee based$1,740,999 $1,441,875 $1,070,066 
Service revenues – product based8,509 7,062 3,339 
Product sales71,104 158,459 280,306 
Total revenues and other1,820,612 1,607,396 1,353,711 
Equity income, net – related parties (1)
226,750 237,518 195,469 
Operating expenses
Cost of product92,884 254,771 168,535 
Operation and maintenance49,533 146,990 115,948 
General and administrative (2)
40,295 101,485 49,672 
Total operating expenses182,712 503,246 334,155 
Gain (loss) on divestiture and other, net(2,870)— — 
Interest income – Anadarko note receivable11,736 16,900 16,900 
Interest expense(6)(1,970)(6,746)

(1)See Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2)Includes (i) amounts charged by Occidental pursuant to the shared services agreements (see Shared services agreements within this Item 13) and (ii) equity-based compensation expense allocated to us by Occidental, portions of which are not reimbursed to Occidental and are reflected as contributions to partners’ capital in the consolidated statements of equity and partners’ capital (see Incentive Plans within this Item 13).

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Consolidated balance sheets
December 31,
thousands20202019
Assets
Accounts receivable, net$291,253 $113,345 
Other current assets5,493 4,982 
Anadarko note receivable— 260,000 
Equity investments (1)
1,224,813 1,285,717 
Other assets50,967 60,221 
Total assets1,572,526 1,724,265 
Liabilities
Accounts and imbalance payables6,664 — 
Short-term debt (2)
— 7,873 
Accrued liabilities19,195 3,087 
Other liabilities138,796 97,800 
Total liabilities164,655 108,760 

(1)See Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
(2)Includes amounts related to finance leases(see Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

Consolidated statements of cash flows
Year Ended December 31,
thousands202020192018
Distributions from equity-investment earnings – related parties$246,637 $234,572 $187,392 
Acquisitions from related parties— (2,007,926)(254)
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 
APCWH Note Payable borrowings— 11,000 321,780 
Repayment of APCWH Note Payable— (439,595)— 
Distributions to Partnership unitholders (1)
(367,861)(566,868)(400,194)
Distributions to WES Operating unitholders (2)
(15,434)(19,768)(7,583)
Net contributions from (distributions to) related parties24,466 458,819 97,755 
Above-market component of swap agreements with Anadarko— 7,407 51,618 
Finance lease payments(6,382)(508)— 

(1)Represents distributions paid to Occidental pursuant to our 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).
(2)Represents distributions paid to certain subsidiaries of Occidental pursuant to WES Operating’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).


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The following tables summarize material related-party transactions for WES Operating (which are included in our consolidated financial statements) to the extent the amounts differ from our consolidated financial statements:
Consolidated statements of operations
Year Ended December 31,
thousands202020192018
General and administrative (1)
$41,609 $99,613 $48,819 

(1)Includes (i) amounts charged by Occidental pursuant to the shared services agreements and (ii) equity-based compensation expense allocated to WES Operating by Occidental, portions of which are not reimbursed to Occidental and are reflected as contributions to partners’ capital in the consolidated statements of equity and partners’ capital (see Incentive Plans within this Item 13).

Consolidated balance sheets
December 31,
thousands20202019
Accounts receivable, net$246,083 $113,581 

Consolidated statements of cash flows
Year Ended December 31,
thousands202020192018
Distributions to WES Operating unitholders (1)
$(771,546)$(1,025,931)$(514,906)

(1)Represents distributions paid to us and certain subsidiaries of Occidental pursuant to WES Operating’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).

Related-party revenues. Related-party revenues include (i) income from our investments accounted for under the equity method of accounting (see Note 7 in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K) and (ii) amounts earned by us from services provided to Occidental and from the sale of natural gas, condensate, and NGLs to Occidental.

Gathering and processing agreements.We have significant gathering and processing arrangements with affiliates of Occidental on most of our systems. 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 infrastructure to bring their volumes to market. For the year ended December 31, 2020, production owned or controlled by Occidental represented 41% of our throughput for natural-gas assets (excluding equity-investment throughput) and 88% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets.
In connection with the sale of its Eagle Ford assets in 2017, Anadarko remained the primary counterparty to our Brasada gas processing agreement and entered into an agency relationship with Sanchez Energy Corporation, now Mesquite Energy, Inc. (“Mesquite”) that allows Mesquite to process gas under such agreement. For this reason, Anadarko continues to be liable under the Brasada gas processing agreement through 2034 to the extent Mesquite does not perform. For all periods presented, Mesquite has performed Anadarko’s obligations under the Brasada gas processing agreement pursuant to its agency arrangement with Anadarko.
Further, in connection with the sale of its Uinta Basin assets in 2020, Kerr McGee Oil & Gas Onshore LP, a subsidiary of Occidental, retained the deficiency payment obligations under a gas processing agreement at the Chipeta plant. This contingent payment obligation extends through the earlier of October 1, 2022, or the termination of the processing agreement.

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Commodity purchase and sale agreements. Through December 31, 2020, we sold a significant amount of our natural gas and NGLs to AESC, Occidental’s marketing affiliate. Prior to April 1, 2020, AESC acted as an agent on behalf of either us or our customers for third-party sales. Where AESC sold natural gas and NGLs on our customers’ behalf, we recognized associated service revenues and cost of product expense for the marketing services performed by AESC. When product sales were on our behalf, we recognized product sales revenues based on Occidental’s sales price to the third party and recorded the associated cost of product expense associated with the marketing activities provided by AESC. Effective April 1, 2020, changes to marketing-contract terms with AESC terminated AESC’s prior status as our agent for third-party sales and established AESC as our customer. 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. This change has no impact to Operating income (loss), Net income (loss), the balance sheets, cash flows, or any non-GAAP metric used to evaluate the Partnership’s operations (see Key Performance Metrics under Part II, Item 7 of this Form 10-K). In addition, we purchase natural gas from AESC pursuant to purchase agreements.

Marketing Transition Services Agreement. Effective December 31, 2019, certain subsidiaries of Anadarko entered into a transition services agreement (the “Marketing Transition Services Agreement”) to provide marketing-related services to certain of our subsidiaries through December 31, 2020, subject to the option to extend such services for an additional six-month period. The Marketing Transition Services Agreement terminated on December 31, 2020. While we still have some marketing agreements 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.

Operating lease. Effective December 31, 2019, an affiliate of Occidental and a wholly owned subsidiary of WES, the lessor, entered into an operating and maintenance agreement pursuant to which Occidental provides operational and maintenance services with respect to a crude-oil gathering system and associated treating facilities owned by us through December 31, 2021. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Related-party expenses. Operation and maintenance expense includes amounts accrued for or paid to related parties for the operation of our assets and for services provided to related parties, including field labor, measurement and analysis, and other disbursements. A portion of general and administrative expense is paid by Occidental, which results in related-party transactions pursuant to the reimbursement provisions of our and WES Operating’s agreements with Occidental. Related-party expenses do not bear a direct relationship to related-party revenues, and third-party expenses do not bear a direct relationship to third-party revenues.

Shared services agreements. PriorGeneral and administrative expense includes costs incurred pursuant to December 31, 2019,the agreements discussed below. Under these agreements Occidental has performed certain centralized corporate functions for us and WES Operating underOperating.

•Services Agreement. Pursuant to the omnibus agreements discussed below. OnServices Agreement, which was amended and restated on December 31, 2019, specified employees of Occidental were seconded to WES Operating GP to provide, under the omnibus agreements were terminateddirection, supervision, and replacedcontrol of the general partner, (i) operating and routine maintenance service and (ii) corporate, administrative, and other services, with respect to the assets owned and operated by us. Occidental was reimbursed for the services provided by the seconded employees. In January 2020, pursuant to the Services Agreement, discussed in more detail below.Occidental made a one-time cash contribution of $20.0 million to WES Operating for anticipated transition costs required to establish stand-alone human resources and information technology functions. In late March 2020, seconded employees’ employment was transferred to us. Occidental continues to provide certain limited administrative and operational services to us, with most services expected to be fully transitioned to us by December 31, 2021.

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•WES omnibus agreement.Prior to December 31, 2019, we had an omnibus agreement with Occidental and the general partner (the “WES omnibus agreement”) that governed (i) our obligation to reimburse Occidental for expenses incurred or payments made on our behalf in connection with Occidental’s provision of general and administrative services provided to us, including certain public company expenses and general and administrative expenses;expenses, (ii) our obligation to pay Occidental, in quarterly installments, an administrative services fee of $250,000 per year, which was subject to an annual increase pursuant to the omnibus agreement;agreement, and (iii) our obligation to reimburse Occidental for all insurance coverage expenses it incurred or payments it made on our behalf. The WES omnibus agreement was terminated as part of the December 2019 Agreements (see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).Agreements.
The following table summarizes the amounts we reimbursed to Occidental pursuant to the WES omnibus agreement, separate from, and in addition to, those reimbursed by WES Operating:
  Year Ended December 31,
thousands 2019 2018 2017
General and administrative expenses $604
 $269
 $263
Public company expenses 4,089
 2,895
 1,821
Total reimbursement $4,693
 $3,164
 $2,084


•WES Operating omnibus agreement.Prior to December 31, 2019, WES Operating had a separate omnibus agreement with Occidental and WES Operating GP (the “WES Operating omnibus agreement”) that governed (i) Occidental’s obligation to indemnify WES Operating for certain liabilities and WES Operating’s obligation to indemnify Occidental for certain liabilities;liabilities, (ii) WES Operating’s obligation to reimburse Occidental for expenses incurred or payments made on its behalf in conjunction with Occidental’s provision of general and administrative services provided to WES Operating, including salary and benefits of Occidental personnel, public company expenses, general and administrative expenses, and salaries and benefits of WES Operating’s executive management who were employees of Occidental;Occidental, and (iii) WES Operating’s obligation to reimburse AnadarkoOccidental for all insurance coverage expenses it incurred or payments it made with respect to WES Operating’s assets. Occidental, in accordance with the partnership agreement and the WES Operating omnibus agreement, determined, in its reasonable discretion, amounts to be reimbursed by WES Operating in exchange for services provided under the WES Operating omnibus agreement. The WES Operating omnibus agreement was terminated as part of the December 2019 Agreements (see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
The following table summarizes the amounts WES Operating reimbursed
Incentive Plans.General and administrative expense includes equity-based compensation expense allocated to us by Occidental pursuantfor awards granted to the WES Operating omnibus agreement:
  Year Ended December 31,
thousands 2019 2018 2017
General and administrative expenses $84,039
 $35,077
 $31,733
Public company expenses 4,065
 15,409
 9,379
Total reimbursement $88,104
 $50,486
 $41,112

Servicesexecutive officers of the general partner and secondment agreement. Pursuant to other employees prior to their employment with us under (i) the services and secondment agreement, which wasAnadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as amended and restated, on December 31, 2019,(ii) Occidental’s 2015 Long-Term Incentive Plan, and is now(iii) Occidental’s Phantom Share Unit Award Plan (collectively referred to as the Services Agreement, specified employees of Occidental are seconded to WES Operating GP to provide, under the direction, supervision,“Incentive Plans”). General and control of our general partner, operating, routine maintenance, and other services with respectadministrative expense includes costs related to the assets we ownIncentive Plans of $14.6 million, $12.9 million, and operate. Occidental is reimbursed for services provided by the seconded employees.
Pursuant to the Services Agreement, Occidental (i) seconds certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP pays 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. The initial term of the Services Agreement is two years and will automatically extend for additional six-month periods unless either party provides a 30-day written notice of termination prior to the initial two-year or additional six-month period expires. However, the Services Agreement provides$6.6 million for the transfer of certain employees to us, which is anticipated to occur prior to the end of 2020. For additional information on the Services Agreement, seeyears ended December 31, 2020, 2019, and 2018, respectively. See Note 1—Summary of Significant Accounting Policies 6—Related-Party Transactionsin the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Anadarko note receivable. On September 11, 2020, we 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 us and the remaining 2% to WGRAH, a subsidiary of Occidental, (ii) we 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 of our common units to us, and (iii) we canceled such common units immediately upon receipt. 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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Indemnification agreements with directors and officers. Our general partner has entered into indemnification agreements with each of its officers and directors (each, an “Indemnitee”). The indemnification agreements provide that each Indemnitee will be indemnified and held harmless against all expense, liability, and loss (including attorney’s fees, judgments, fines or penalties, and amounts to be paid in settlement) actually and reasonably incurred or suffered by the Indemnitee in connection with serving in their capacity as officers and directors of our general partner (or of any subsidiary of our general partner) or in any capacity at the request of our general partner or its Board of Directors to the fullest extent permitted by applicable law, including Section 18-108 of the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended to provide more advantageous rights to the Indemnitee. The indemnification agreements also provide that advance payment of certain expenses must be made to the Indemnitee, including fees of counsel, in advance of final disposition of any proceeding subject to receipt of an undertaking from the Indemnitee to return such advance if it is ultimately determined that the Indemnitee is not entitled to indemnification.
Through December 31, 2019,2020, there have been no payments or claims to Occidental related to indemnificationsthese indemnification agreements and no payments or claims have been received from Occidental related to indemnifications.


these indemnification agreements.
Tax sharing agreements.
We and WES Operating have tax sharing agreements with Occidental, pursuant to which Occidental is reimbursed for our and WES Operating’s estimated share of taxes from all forms of taxation, excluding taxes imposed by the United States. Taxes for which Occidental is reimbursed include state taxes attributable to our and WES Operating’s income that are directly borne by Occidental through its filing of a combined or consolidated tax return. Taxes related to assets previously acquired from Anadarko were reimbursed in periods beginning on and subsequent to the acquisition of such assets. Occidental may use its own tax attributes to reduce or eliminate the tax liability of its combined or consolidated group, which may include us and WES Operating as members. However, under this circumstance, we and WES Operating nevertheless are required to reimburse Occidental for the allocable share of taxes that would have been owed had the tax attributes not been available to Occidental.

Indemnification agreements. Prior to December 31, 2019, WES Operating GP was indemnified by wholly owned subsidiaries of Occidental against any claims made against WES Operating GP for WES Operating’s long-term debt and/or borrowings under the RCF and Term loan facility. These indemnification agreements were terminated as part of the December 2019 Agreements.

Chipeta LLC agreement. We are party to the Chipeta LLC agreement, together with a third-party member. Among other things, the Chipeta LLC agreement provides the following:

•Chipeta’s members will be required from time to time to make capital contributions to Chipeta to the extent approved by the members in connection with Chipeta’s annual budget;

•Chipeta will distribute available cash, as defined in the Chipeta LLC agreement, if any, to its members quarterly in accordance with those members’ membership interests; and

•Chipeta’s membership interests are subject to significant restrictions on transfer.

We are the managing member of Chipeta. As managing member, we manage the day-to-day operations of Chipeta and receive a management fee from the other member, which is intended to compensate the managing member for the performance of its duties. We may be removed as the managing member only if we are grossly negligent or fraudulent, breach our primary duties, or fail to respond in a commercially reasonable manner to written business proposals from the other members,member, and such behavior, breach, or failure has a material adverse effect to Chipeta.

Commodity-price swap agreements. Purchases from related parties.PriorDuring the fourth quarter of 2020, a subsidiary of WES entered into an agreement to their expiration on December 31, 2018, we had commodity-price swap agreements with Anadarko to mitigate exposure to commodity-price risk inherent in our percent-of-proceeds, percent-of-product, and keep-whole gas-processing contracts. See Note 6—Transactions with Affiliatespurchase three electrical substations located in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.


Gathering and processing agreements. We have significant gathering and processing arrangements with affiliates of Occidental on most of our systems. For the year ended December 31, 2019, production owned or controlled by Occidental represented 38% of our throughput for natural-gas assets (excluding equity-investment throughput) and 83% of our throughput for crude-oil, NGLs, and produced-water assets (excluding equity-investment throughput).
Effective December 31, 2019, Kerr-McGee Oil & Gas Onshore, LP,DJ Basin from a subsidiary of Occidental and Kerr-McGee Gathering LLC (“KMGG”), a subsidiaryfor $2.0 million. This purchase was recorded as an Accrued capital expenditure as of WES Operating, entered into an amendment to the DJ gas-gathering agreement to provide for the extension of gathering services by KMGG to gas produced by a subsidiary of Occidental in Weld County, Colorado, in the DJ Basin for a primary term ending August 2029.

Commodity purchase and sale agreements. We sell a significant amount of our natural gas and NGLs to AESC, Occidental’s marketing affiliate that acts as our agent for third-party sales. In addition, we purchase natural gas from AESC pursuant to purchase agreements.

Marketing Transition Services Agreement. Effective December 31, 2019, certain subsidiaries of Anadarko entered into a transition services agreement (the “Marketing Transition Services Agreement”) to provide certain marketing-related services to certain of our subsidiaries through December 31, 2020, subject to our subsidiaries’ option to extend such services for an additional six-month period.and cash was paid in January of 2021.

Exchange Agreement. On December 31, 2019, WGRI, the general partner, and WES entered into the Exchange Agreement, pursuant to which WES canceled the non-economic general partner interest in WES and simultaneously issued a 2.0% general partner interest to the general partner in exchange for which WGRI transferred 9,060,641 WES common units to WES, which immediately canceled such units on receipt.

Affiliate asset contributions. The following table summarizes affiliate contributions of other assets to us:
200
  Year Ended December 31,
thousands 2019 2018 2017
Cash consideration paid $(425) $(254) $(3,910)
Net carrying value 335
 59,089
 5,283
Partners’ capital adjustment $(90) $58,835
 $1,373

SummaryTable of affiliate transactions. Affiliate revenues include (i) income from our investments accounted for under the equity method of accounting and (ii) amounts earned from services provided to Occidental and from the sale of natural gas, condensate, and NGLs to Occidental. In addition, we purchase natural gas from an affiliate of Occidental pursuant to gas purchase agreements. Operation and maintenance expense includes amounts accrued for or paid to affiliates for the operation of our assets and for services provided to affiliates, including field labor, measurement and analysis, and other disbursements. A portion of general and administrative expense is paid by Occidental, which results in affiliate transactions pursuant to the reimbursement provisions of the WES and WES Operating agreements with Occidental. Affiliate expenses do not bear a direct relationship to affiliate revenues, and third-party expenses do not bear a direct relationship to third-party revenues.Contents

The following table summarizes material affiliate transactions included in our consolidated financial statements (see Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K):
  Year ended December 31,
thousands 2019 2018 2017
Revenues and other (1)
 $1,607,396
 $1,353,711
 $1,539,105
Equity income, net – affiliates (1)
 237,518
 195,469
 115,141
Operating expenses      
Cost of product (1)
 254,771
 168,535
 74,560
Operation and maintenance (1)
 146,990
 115,948
 82,249
General and administrative (2)
 101,485
 49,672
 43,221
Total operating expenses 503,246
 334,155
 200,030
Interest income (3)
 16,900
 16,900
 16,900
Interest expense (4)
 1,970
 6,746
 224
APCWH Note Payable borrowings 11,000
 321,780
 98,813
Repayment of APCWH Note Payable 439,595
 —
 —
Settlement of the Deferred purchase price obligation – Anadarko (5)
 —
 —
 (37,346)
Distributions to WES unitholders (6)
 566,868
 400,194
 360,523
Distributions to WES Operating unitholders (7)
 19,768
 7,583
 7,100
Above-market component of swap agreements with Anadarko 7,407
 51,618
 58,551
(1)
Represents amounts earned or incurred on and subsequent to the date of the acquisition of assets from Anadarko, and amounts earned or incurred by Anadarko on a historical basis for periods prior to the acquisition of such assets.
(2)
Represents general and administrative expense 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. These amounts include equity-based compensation expense allocated to us by Occidental (see LTIPs and Incentive Plans in Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K) and amounts charged by Occidental under the WES and WES Operating omnibus agreements.
(3)
Represents interest income recognized on the Anadarko note receivable.
(4)
Includes amounts related to finance leases and the APCWH Note Payable (see Note 1—Summary of Significant Accounting Policies and Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
(5)
Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation – Anadarko (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
(6)
Represents distributions paid to Occidental pursuant to our 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).
(7)
Represents distributions paid to certain subsidiaries of Occidental pursuant to WES Operating’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).


The following table summarizes material affiliate transactions for WES Operating (which are included in our consolidated financial statements) to the extent the amounts differ from our consolidated financial statements:
  Year ended December 31,
thousands 2019 2018 2017
General and administrative (1)
 $99,613
 $48,819
 $42,411
Distributions to WES Operating unitholders (2)
 1,025,931
 514,906
 452,777
(1)
Represents general and administrative expense 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. These amounts include equity-based compensation expense allocated to WES Operating by Occidental (see LTIPs and Incentive Plans in Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K) and amounts charged by Occidental pursuant to the WES Operating omnibus agreement.
(2)
Represents distributions paid to us and certain subsidiaries of Occidental pursuant to WES Operating’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). For the year ended December 31, 2019, includes distributions to us and a subsidiary of Occidental related to the repayment of the WGP RCF (see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates,related parties, including Occidental, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owner (Occidental). At the same time, our general partner also has duties to manage our partnership in a manner beneficial to us and our unitholders.
Whenever a conflict arises between our general partner or its affiliates,related parties, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve the conflict. Our partnership agreement contains provisions that modify and limit our general partner’s default state law fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of fiduciary duties otherwise applicable under state law. See Special Committee under Part III, Item 10 of this Form 10-K.
Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is any of the following:

•approved by the Special Committee of our general partner, although our general partner is not obligated to seek such approval;

•approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

•on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.


Our general partner may, but in most circumstances is not required to, seek the approval of such resolution from the Special Committee of its Board of Directors. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the Special Committee and its Board of Directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in the partnership agreement, our general partner or the Special Committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. Our partnership agreement provides that for someone to act in good faith, that person must reasonably believe he is acting in the best interests of the Partnership.
Additionally, the Board of Directors has adopted a written Code of Ethics and Business Conduct and Ethics (the “Code”), under which all directors and officers of the general partner, and employees working on our behalf, are expected to avoid conflicts or the appearance of conflicts in relation to their duties and responsibilities to us, and report any violation of the Code by any person. Under our Corporate Governance Guidelines, any waivers of the Code for any officer or director may only be made by the Board of Directors or by a committee of the Board of Directors composed of independent directors.

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Item 14.  Principal Accounting Fees and Services

We have engaged KPMG LLP as our and WES Operating’s independent registered public accounting firm. The following table presents fees for the audit of the annual consolidated financial statements for the last two fiscal years and for other services provided by KPMG LLP:
WESWES Operating
thousands2020201920202019
Audit fees$250 $325 $2,240 $1,862 
Audit-related fees— 25 — 375 
Total$250 $350 $2,240 $2,237 
  WES WES Operating
thousands 2019 2018 2019 2018
Audit fees $325
 $235
 $1,862
 $1,860
Audit-related fees 25
 —
 375
 210
Total $350
 $235
 $2,237
 $2,070

Audit fees are primarily for the audit of our and WES Operating’s consolidated financial statements, including the audit of the effectiveness of internal control over financial reporting, consents, comfort letters, other audits, and the reviews of financial statements included in the Forms 10-Q. Audit-related fees are primarily for certain financial accounting consultations.

Audit Committee Approval of Audit and Non-Audit Services

The Audit Committee of our general partner has adopted a Pre-Approval Policy with respect to services that may be performed by KPMG LLP. This policy lists specific audit-related services and any other services that KPMG LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that Pre-Approval Policy. The Audit Committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its Chairman, to whom such authority has been conditionally delegated, prior to engagement. During 2019,2020, no fees for services outside the scope of audit, review, or attestation that exceed the waiver provisions of 17 CFR 210.2-01(c)(7)(i)(C) were approved by the Audit Committee. During 2020, the Audit Committee reviewed and approved the use of KPMG LLP’s Accounting research and disclosure checklist applications for no additional fee.
The Audit Committee has approved the appointment of KPMG LLP as independent registered public accounting firm to conduct the audit of our and WES Operating’s consolidated financial statements for the year ended December 31, 2020.2021.


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PART IV

Item 15.  Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

Our consolidated financial statements are included under Part II, Item 8 of this Form 10-K. For a listing of these statements and accompanying footnotes, see the Index to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(a)(2) Financial Statement Schedules

Financial statement schedules have been omitted because they are not required, not applicable, or the information is included under Part II, Item 8 of this Form 10-K.

(a)(3) Exhibits

Exhibit Index
Exhibit
Number		Description
#2.1
Contribution Agreement and Agreement and Plan of Merger, dated as of November 7, 2018, by and among Anadarko Petroleum Corporation, Anadarko E&P Onshore LLC, APC Midstream Holdings, LLC, Western Gas Equity Partners, LP, Western Gas Equity Holdings, LLC, Western Gas Partners, LP, Western Gas Holdings, LLC, Clarity Merger Sub, LLC, WGR Asset Holding Company LLC, WGR Operating, LP, Kerr-McGee Gathering LLC, Kerr-McGee Worldwide Corporation and Delaware Basin Midstream, LLC (incorporated by reference to Exhibit 2.1 to Western Gas Equity Partners, LP’s Current Report on Form 8-K filed on November 8, 2018, File No. 001-35753).
3.1
Certificate of Limited Partnership of Western Gas Equity Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 of Western Gas Equity Partners, LP filed on November 5, 2012, File No. 333-184763).
3.2
Certificate of Amendment to Certificate of Limited Partnership of Western Gas Equity Partners, LP, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
3.3
Second Amended and Restated Agreement of Limited Partnership of Western Midstream Partners, LP, dated as of December 31, 2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
3.4
Certificate of Formation of Western Gas Equity Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Equity Partners, LP’s Registration Statement on Form S-1 filed on November 5, 2012, File No. 333-184763).
3.5
Certificate of Amendment to Certificate of Formation of Western Gas Equity Holdings, LLC, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.2 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
3.6
Second Amended and Restated Limited Liability Company Agreement of Western Midstream Holdings, LLC, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.7 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
3.7
Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of Western Midstream Holdings, LLC, dated February 28, 2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on March 26, 2019, File No. 001-35753).
3.8
Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
3.9
Third Amended and Restated Agreement of Limited Partnership of Western Midstream Operating, LP, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.5 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
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Exhibit
Number		Exhibit
Number		Description
3.10
Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
3.11
Certificate of Amendment to Certificate of Formation of Western Gas Holdings, LLC, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.4 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
Exhibit
Number		 Description
#2.1 
Contribution Agreement and Agreement and Plan of Merger, dated as of November 7, 2018, by and among Anadarko Petroleum Corporation, Anadarko E&P Onshore LLC, APC Midstream Holdings, LLC, Western Gas Equity Partners, LP, Western Gas Equity Holdings, LLC, Western Gas Partners, LP, Western Gas Holdings, LLC, Clarity Merger Sub, LLC, WGR Asset Holding Company LLC, WGR Operating, LP, Kerr-McGee Gathering LLC, Kerr-McGee Worldwide Corporation and Delaware Basin Midstream, LLC, (incorporated by reference to Exhibit 2.1 to Western Gas Equity Partners, LP’s Current Report on Form 8-K filed on November 8, 2018, File No. 001-35753).
3.12
Third Amended and Restated Limited Liability Company Agreement of Western Midstream Operating GP, LLC, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.8 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
3.13
Certificate of Merger of Clarity Merger Sub, LLC with and into Western Gas Partners, LP, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.3 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
**4.1
Description of the registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934.
3.1 
Certificate of Limited Partnership of Western Gas Equity Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 of Western Gas Equity Partners, LP filed on November 5, 2012, File No. 333-184763).
4.2
Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
3.2 
Certificate of Amendment to Certificate of Limited Partnership of Western Gas Equity Partners, LP, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
4.3
Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
3.3 
First Amended and Restated Agreement of Limited Partnership of Western Gas Equity Partners, LP, dated as of December 12, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Equity Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-35753).
4.4
First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
3.4 
Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Western Gas Equity Partners, LP, dated November 9, 2017 (incorporated by reference to Exhibit 3.1 to Western Gas Equity Partners, LP’s Current Report on Form 8-K filed on November 9, 2017, File No. 001-35753).
4.5
Form of 5.375% Senior Notes due 2021 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A to Exhibit 4.2, to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
3.5 
Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Western Midstream Partners, LP, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.6 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
4.6
Fourth Supplemental Indenture, dated as of June 28, 2012, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
3.6 
Second Amended and Restated Agreement of Limited Partnership of Western Midstream Partners, LP, dated as of December 31,2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
4.7
Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
3.7 
Certificate of Formation of Western Gas Equity Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Equity Partners, LP’s Registration Statement on Form S-1 filed on November 5, 2012, File No. 333-184763).
4.8
Sixth Supplemental Indenture, dated as of March 20, 2014, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
3.8 
Certificate of Amendment to Certificate of Formation of Western Gas Equity Holdings, LLC, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.2 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
4.9
Form of 5.450% Senior Notes due 2044 (incorporated by reference to Exhibit 4.4, which is included as Exhibit A to Exhibit 4.2, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
3.9 
Second Amended and Restated Limited Liability Company Agreement of Western Midstream Holdings, LLC, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.7 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
4.10
Seventh Supplemental Indenture, dated as of June 4, 2015, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
4.11
Form of 3.950% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
4.12
Eighth Supplemental Indenture, dated as of July 12, 2016, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).
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Exhibit
Number		Exhibit
Number		 DescriptionExhibit
Number		Description
3.10 
Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of Western Midstream Holdings, LLC, dated February 28, 2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on March 26, 2019, File No. 001-35753).
3.11 
Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
3.12 
Third Amended and Restated Agreement of Limited Partnership of Western Midstream Operating, LP, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.5 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
3.13 
Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
3.14 
Certificate of Amendment to Certificate of Formation of Western Gas Holdings, LLC, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.4 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
3.15 
Third Amended and Restated Limited Liability Company Agreement of Western Midstream Operating GP, LLC, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.8 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
3.16 
Certificate of Merger of Clarity Merger Sub, LLC with and into Western Gas Partners, LP, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.3 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
*4.1 
Description of the registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934
4.2 
Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
4.13
Form of 4.650% Senior Notes due 2026 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).
4.3 
Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.14
Ninth Supplemental Indenture, dated as of March 2, 2018, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
4.4 
First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.15
Form of 4.500% Senior Notes due 2028 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
4.5 
Form of 5.375% Senior Notes due 2021 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A to Exhibit 4.2, to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
4.16
Form of 5.300% Senior Notes due 2048 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
4.6 
Fourth Supplemental Indenture, dated as of June 28, 2012, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
4.17
Tenth Supplemental Indenture, dated as of August 9, 2018, by and between Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 9, 2018, File No. 001-34046).
4.7 
Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
4.18
Form of 4.750% Senior Notes due 2028 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 9, 2018, File No. 001-34046).
4.8 
Sixth Supplemental Indenture, dated as of March 20, 2014, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
4.19
Form of 5.500% Senior Notes due 2048 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 9, 2018, File No. 001-34046).
4.9 
Form of 5.450% Senior Notes due 2044 (incorporated by reference to Exhibit 4.4, which is included as Exhibit A to Exhibit 4.2, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
4.20
Eleventh Supplemental Indenture, dated as of January 13, 2020, by and between Western Midstream Operating, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
4.10 
Seventh Supplemental Indenture, dated as of June 4, 2015, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
4.21
Form of Floating Rate Senior Notes due 2023 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
4.11 
Form of 3.950% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
4.22
Form of 3.100% Senior Notes due 2025 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
4.23
Form of 4.050% Senior Notes due 2030 (incorporated by reference to Exhibit 4.4, which is included as Exhibit A-3 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
4.24
Form of 5.250% Senior Notes due 2050 (incorporated by reference to Exhibit 4.5, which is included as Exhibit A-4 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
10.1
Partnership Interests Exchange Agreement, by and among Western Gas Resources, Inc., Western Midstream Holdings, LLC and Western Midstream Partners, LP, dated as of December 31, 2019 (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
10.2
Amended and Restated Services, Secondment and Employee Transfer Agreement, by and between Occidental Petroleum Corporation, Anadarko Petroleum Corporation and Western Midstream Operating GP, LLC, dated as of December 31, 2019 (incorporated by reference to Exhibit 10.2 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
‡‡10.3
Anadarko Petroleum Corporation Key Employee Change of Control Contract for Vice Presidents (Michael C. Pearl), dated May 28, 2013, as amended on April 11, 2019 (incorporated by reference to Exhibit 10.11 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 27, 2020, File No. 001-34046).
‡‡10.4
Anadarko Petroleum Corporation Key Employee Change of Control Contract for Vice Presidents (Charles G. Griffie), dated November 28, 2018, as amended on April 11, 2019 (incorporated by reference to Exhibit 10.12 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 27, 2020, File No. 001-34046).
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Exhibit
Number		 Description
 4.12 
Eighth Supplemental Indenture, dated as of July 12, 2016, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).
 4.13 
Form of 4.650% Senior Notes due 2026 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).
 4.14 
Ninth Supplemental Indenture, dated as of March 2, 2018, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
 4.15 
Form of 4.500% Senior Notes due 2028 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
 4.16 
Form of 5.300% Senior Notes due 2048 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
 4.17 
Tenth Supplemental Indenture, dated as of August 9, 2018, by and between Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 9, 2018, File No. 001-34046).
 4.18 
Form of 4.750% Senior Notes due 2028 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K file on August 9, 2018, File No. 001-34046).
 4.19 
Form of 5.500% Senior Notes due 2048 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K file on August 9, 2018, File No. 001-34046).
 4.20 
Eleventh Supplemental Indenture, dated as of January 13, 2020, by and between Western Midstream Operating, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
 4.21 
Form of Floating Rate Senior Notes due 2023 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
 4.22 
Form of 3.100% Senior Notes due 2025 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
 4.23 
Form of 4.050% Senior Notes due 2030 (incorporated by reference to Exhibit 4.4, which is included as Exhibit A-3 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
 4.24 
Form of 5.250% Senior Notes due 2050 (incorporated by reference to Exhibit 4.5, which is included as Exhibit A-4 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
 10.1 
Partnership Interests Exchange Agreement, by and among Western Gas Resources, Inc., Wester Midstream Holdings, LLC and Western Midstream Partners, LP, dated as of December 31, 2019 (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
 10.2 
Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC and Anadarko Petroleum Corporation, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
 10.3 
Amendment No. 1 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 19, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).

Exhibit
Number		Description
10.5
Tax Sharing Agreement by and among Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.5 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.6
Anadarko Petroleum Corporation Fixed Rate Note due 2038 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
10.7
Form of Commodity Price Swap Agreement (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on May 6, 2010, File No. 001-34046).
‡10.8
Form of Indemnification Agreement by and between Western Midstream Holdings, LLC, its Officers and Directors (incorporated by reference to Exhibit 10.16 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 27, 2020, File No. 001-34046).
‡10.9
Western Gas Partners, LP 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on October 17, 2017, File No. 001-34046).
‡10.10
Form of Award Agreement under the Western Gas Partners, LP 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.8 to Western Gas Partners, LP’s Post-Effective Amendment No. 1 to Registration Statement on Form S-8 filed on December 13, 2017, File No. 333-151317).
‡10.11
Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Western Gas Equity Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-35753).
‡10.12
Form of Award Agreement for independent directors under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to Western Gas Equity Partners, LP’s Registration Statement on Form S-8 filed on January 30, 2013, File No. 333-186306).
‡10.13
Western Midstream Partners, LP US Incentive Compensation Program (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 14, 2020, File No. 001-35753).
‡10.14
Form of Phantom Unit Award Agreement (Time-Based Awards) (incorporated by reference to Exhibit 10.2 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 14, 2020, File No. 001-35753).
‡10.15
Form of Phantom Unit Award Agreement (TUR Awards) (incorporated by reference to Exhibit 10.3 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 14, 2020, File No. 001-35753).
‡10.16
Form of Phantom Unit Award Agreement (ROA Awards) (incorporated by reference to Exhibit 10.4 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 14, 2020, File No. 001-35753).
†10.17
Amended and Restated Limited Liability Company Agreement of Chipeta Processing LLC effective July 23, 2009 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on November 12, 2009, File No. 001-34046).
10.18
Third Amended and Restated Revolving Credit Agreement, dated as of February 15, 2018, among Western Gas Partners, LP, as the Borrower, Wells Fargo Bank National Association, as the administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.21 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 16, 2018, File No. 001-34046).
10.19
First Amendment to Third Amended and Restated Revolving Credit Agreement, dated as of December 19, 2018, among Western Gas Partners, LP, as the Borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 20, 2018, File No. 001-34046).
10.20
Second Amendment to Third Amended and Restated Revolving Credit Agreement, dated as of December 31, 2019, among Western Midstream Operating, LP, as the Borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.3 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
206
Table of Contents
Exhibit
Number		 Description
 10.4 
Amendment No. 2 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of July 22, 2009 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
 10.5 
Amendment No. 3 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 31, 2009 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 7, 2010, File No. 001-34046).
 10.6 
Amendment No. 4 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of January 29, 2010 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
 10.7 
Amendment No. 5 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of August 2, 2010 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
 10.8 
Services And Secondment Agreement between Western Gas Holdings, LLC and Anadarko Petroleum Corporation dated May 14, 2008 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
 10.9 
Amendment No. 1 to Services And Secondment Agreement between Western Gas Holdings, LLC and Anadarko Petroleum Corporation dated December 10, 2015 (incorporated by reference to Exhibit 10.8 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 25, 2016, File No. 001-34046).
 10.10 
Amended and Restated Services, Secondment and Employee Transfer Agreement, by and between Occidental Petroleum Corporation, Anadarko Petroleum Corporation and Western Midstream Operating GP, LLC, dated as of December 31, 2019 (incorporated by reference to Exhibit 10.2 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
‡10.11 
Anadarko Petroleum Corporation Key Employee Change of Control Contract for Vice Presidents (Michael C. Pearl), dated May 28, 2013, as amended on April 11, 2019.
‡10.12 
Anadarko Petroleum Corporation Key Employee Change of Control Contract for Vice Presidents (Charles G. Griffie), dated November 28, 2018, as amended on April 11, 2019.
 10.13 
Tax Sharing Agreement by and among Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.5 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
 10.14 
Anadarko Petroleum Corporation Fixed Rate Note due 2038 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
 10.15 
Form of Commodity Price Swap Agreement (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on May 6, 2010, File No. 001-34046).
‡10.16 
Form of Indemnification Agreement by and between Western Midstream Holdings, LLC, its Officers and Directors.
‡10.17 
Western Gas Partners, LP 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on October 17, 2017, File No. 001-34046).
‡10.18 
Form of Award Agreement under the Western Gas Partners, LP 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.8 to Western Gas Partners, LP’s Post-Effective Amendment No. 1 to Registration Statement on Form S-8 filed on December 13, 2017, File No. 333-151317).
‡10.19 
Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Western Gas Equity Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-35753).
‡10.20 
Form of Award Agreement for independent directors under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to Western Gas Equity Partners, LP’s Registration Statement on Form S-8 filed on January 30, 2013, File No. 333-186306).
‡10.21 
Western Midstream Partners, LP US Incentive Compensation Program (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 14, 2020, File No. 001-35753).

Exhibit
Number		Description
10.21
364-Day Credit Agreement, dated as of December 19, 2018, among Western Gas Partners, LP, Barclays Bank PLC, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 20, 2018, File No. 001-34046).
10.22
First Amendment to 364-Day Credit Agreement, dated as of July 1, 2019, among Western Midstream Operating, LP, as the Borrower, Barclays Bank PLC, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on July 3, 2019, File No. 001-35753).
10.23
Second Amendment to Term Loan Credit Agreement, dated as of December 31, 2019, among Western Midstream Operating, LP, as the Borrower, Barclays Bank PLC, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.4 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
10.24
Tax Sharing Agreement by and between Western Gas Equity Partners, LP and Anadarko Petroleum Corporation, dated as of December 12, 2012 (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K filed by Western Gas Equity Partners, LP on December 12, 2012, File No. 001-35753).
†10.25
Gas Gathering Agreement effective July 1, 2010 between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP, as amended by Amendment No. 1 dated August 4, 2011, Amendment No. 2 dated December 3, 2012, Amendment No. 3 dated November 19, 2013 and Amendment No. 4 dated June 2, 2014 (incorporated by reference to Exhibit 10.23 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 26, 2015, File No. 001-34046).
†10.26
Amendment to Gas Gathering Agreement effective August 1, 2017, between Kerr-McGee Gathering LLC and Kerr-McGee Oil and Gas Onshore LP (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on July 26, 2017, File No. 001-34046).
†10.27
Amendment to Gas Gathering Agreement effective January 1, 2018, between Kerr-McGee Gathering LLC and Kerr-McGee Oil and Gas Onshore LP (incorporated by reference to Exhibit 10.29 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 16, 2018, File No. 001-34046).
†10.28
Amendment to Gas Gathering Agreement, dated May 10, 2018, between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on August 1, 2018, File No. 001-34046).
†10.29
Amendment to Gas Gathering Agreement effective January 1, 2020, between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP (incorporated by reference to Exhibit 10.42 to Western Midstream Partners, LP’s Annual Report on Form 10-K filed on February 27, 2020, File No. 001-34046).
†10.30
Gas Gathering Agreement between Anadarko E&P Onshore LLC and Delaware Basin Midstream, LLC, dated October 8, 2018 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on October 31, 2018, File No. 001-34046).
10.31
First Amendment to 364-Day Credit Agreement, dated as of July 1, 2019, among Western Midstream Operating, LP, as the Borrower, Barclays Bank PLC, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on July 3, 2019, File No. 001-35753).
10.32
Unit Redemption Agreement by and between Western Midstream Partners, LP and Anadarko Petroleum Corporation, dated as of September 11, 2020 (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on September 16, 2020, File No. 001-35753).
*21.1
List of Subsidiaries of Western Midstream Partners, LP.
*23.1
Consent of KPMG LLP - Western Midstream Partners, LP.
207
Table of Contents
Exhibit
Number		 Description
‡10.22 
Form of Phantom Unit Award Agreement (Time-Based Awards) (incorporated by reference to Exhibit 10.2 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 14, 2020, File No. 001-35753).
‡10.23 
Form of Phantom Unit Award Agreement (TUR Awards) (incorporated by reference to Exhibit 10.3 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 14, 2020, File No. 001-35753).
‡10.24 
Form of Phantom Unit Award Agreement (ROA Awards) (incorporated by reference to Exhibit 10.4 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 14, 2020, File No. 001-35753).
†10.25 
Amended and Restated Limited Liability Company Agreement of Chipeta Processing LLC effective July 23, 2009 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on November 12, 2009, File No. 001-34046).
 10.26 
Third Amended and Restated Revolving Credit Agreement, dated as of February 15, 2018, among Western Gas Partners, LP, as the Borrower, Wells Fargo Bank National Association, as the administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.21 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 16, 2018, File No. 001-34046).
 10.27 
First Amendment to Third Amended and Restated Revolving Credit Agreement, dated as of December 19, 2018, among Western Gas Partners, LP, as the Borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 20, 2018, File No. 001-34046).
 10.28 
Second Amendment to Third Amended and Restated Revolving Credit Agreement, dated as of December 31, 2019, among Western Midstream Operating, LP, as the Borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.3 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
 10.29 
364-Day Credit Agreement, dated as of December 19, 2018, among Western Gas Partners, LP, Barclays Bank PLC, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 20, 2018, File No. 001-34046).
 10.30 
First Amendment to 364-Day Credit Agreement, dated as of July 1, 2019, among Western Midstream Operating, LP, as the Borrower, Barclays Bank PLC, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on July 3, 2019, File No. 001-35753).
 10.31 
Second Amendment to Term Loan Credit Agreement, dated as of December 31, 2019, among Western Midstream Operating, LP, as the Borrower, Barclays Bank PLC, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.4 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
 10.32 
Fourth Amended and Restated Indemnification Agreement, dated March 14, 2016, between Western Gas Holdings, LLC and Western Gas Resources, Inc (incorporated by reference to Exhibit 10.19 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 23, 2017, File No. 001-34046).
 10.33 
First Amendment to Fourth Amended and Restated Indemnification Agreement, dated February 15, 2018, between Western Gas Holdings, LLC and Western Gas Resources, Inc. (incorporated by reference to Exhibit 10.23 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 16, 2018, File No. 001-34046).
 10.34 
Omnibus Agreement, by and among, Western Gas Equity Partners, LP, Western Gas Equity Holdings, LLC and Anadarko Petroleum Corporation, dated as of December 12, 2012 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed by Western Gas Equity Partners, LP on December 12, 2012, File No. 001-35753).
 10.35 
Tax Sharing Agreement by and between Western Gas Equity Partners, LP and Anadarko Petroleum Corporation, dated as of December 12, 2012 (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K filed by Western Gas Equity Partners, LP on December 12, 2012, File No. 001-35753).
 10.36 
AMH Indemnification Agreement, dated March 3, 2014, between Western Gas Holdings, LLC and APC Midstream Holdings, LLC (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2014, File No. 001-34046).
 10.37 
KWC Indemnification Agreement, dated March 14, 2016, between Western Gas Holdings, LLC and Kerr-McGee Worldwide Corporation (incorporated by reference to Exhibit 10.21 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 23, 2017, File No. 001-34046).
Exhibit
Number		Description
*23.2
Consent of KPMG LLP - Western Midstream Operating, LP.
*31.1
Certification of Chief Executive Officer and Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Partners, LP.
*31.2
Certification of Chief Executive Officer and Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Operating, LP.
**32.1
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Western Midstream Partners, LP.
**32.2
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Western Midstream Operating, LP.
*101.INSXBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)
*101.SCHInline XBRL Schema Document
*101.CALInline XBRL Calculation Linkbase Document
*101.DEFInline XBRL Definition Linkbase Document
*101.LABInline XBRL Label Linkbase Document
*101.PREInline XBRL Presentation Linkbase Document
*104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

Exhibit
Number		 Description
†10.38 
Gas Gathering Agreement effective July 1, 2010 between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP, as amended by Amendment No. 1 dated August 4, 2011, Amendment No. 2 dated December 3, 2012, Amendment No. 3 dated November 19, 2013 and Amendment No. 4 dated June 2, 2014 (incorporated by reference to Exhibit 10.23 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 26, 2015, File No. 001-34046).
†10.39 
Amendment to Gas Gathering Agreement effective August 1, 2017, between Kerr-McGee Gathering LLC and Kerr-McGee Oil and Gas Onshore LP (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on July 26, 2017, File No. 001-34046).
†10.40 
Amendment to Gas Gathering Agreement effective January 1, 2018, between Kerr-McGee Gathering LLC and Kerr-McGee Oil and Gas Onshore LP (incorporated by reference to Exhibit 10.29 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 16, 2018, File No. 001-34046).
†10.41 
Amendment to Gas Gathering Agreement, dated May 10, 2018, between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on August 1, 2018, File No. 001-34046).
* †10.42 
Amendment to Gas Gathering Agreement effective January 1, 2020, between Kerr-McGee Gathering LLC and Kerr-McGee Oil & Gas Onshore LP.
†10.43 
Gas Gathering Agreement between Anadarko E&P Onshore LLC and Delaware Basin Midstream, LLC, dated October 8, 2018 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on October 31, 2018, File No. 001-34046).
 10.44 
WGRAH Indemnification Agreement, dated as of February 28, 2019, by and between WGR Asset Holding Company LLC and Western Gas Holdings, LLC (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
 10.45 
First Amendment to 364-Day Credit Agreement, dated as of July 1, 2019, among Western Midstream Operating, LP, as the Borrower, Barclays Bank PLC, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on July 3, 2019, File No. 001-35753).
*21.1 
List of Subsidiaries of Western Midstream Partners, LP.
*23.1 
Consent of KPMG LLP - Western Midstream Partners, LP.
*23.2 
Consent of KPMG LLP - Western Midstream Operating, LP.
*31.1 
Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Partners, LP.
*31.2 
Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Partners, LP.
*31.3 
Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Operating, LP.
*31.4 
Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Operating, LP.
**32.1 
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Western Midstream Partners, LP.
**32.2 
Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Western Midstream Operating, LP.
*101.INS XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)
*101.SCH Inline XBRL Schema Document
*101.CAL Inline XBRL Calculation Linkbase Document
*101.DEF Inline XBRL Definition Linkbase Document
*101.LAB Inline XBRL Label Linkbase Document
*101.PRE Inline XBRL Presentation Linkbase Document
*104   Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*Filed herewith
**Furnished herewith
#Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.
†Portions of this exhibit have been omitted as confidential pursuant to Item 601(b)(10) of Regulation S-K or a request for confidential treatment.
‡Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.


Item 16.  Form 10-K Summary

Not applicable.


208
Table of Contents
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.
 
WESTERN MIDSTREAM PARTNERS, LP
February 26, 2021WESTERN MIDSTREAM PARTNERS, LP
February 27, 2020
/s/ Michael C. PearlP. Ure
Michael C. PearlP. Ure
Senior Vice President, Chief Executive Officer and Chief Financial Officer
Western Midstream Holdings, LLC
(as general partner of Western Midstream Partners, LP)
WESTERN MIDSTREAM OPERATING, LP
February 27, 202026, 2021
/s/ Michael C. PearlP. Ure
Michael C. PearlP. Ure
Senior Vice President, Chief Executive Officer and Chief Financial Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)

Each person whose signature appears below constitutes and appoints Michael P. Ure and Michael C. Pearl, and each of them, either one of whom may act without joinder of the other, his true and lawful attorneys-in-factattorney-in-fact and agents,agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all amendments to this Form 10-K, and to file the same, with all, exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-factattorney-in-fact and agents, and each of them,agent full power and authority to do and perform each, and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-factattorney-in-fact and agents, and each of them,agent or the substitute or substitutes of any or all of them, may lawfully do or cause to be done by virtue hereof.


209
Table of Contents
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 27, 2020.

26, 2021.
SignatureTitle (Position with Western Midstream Holdings, LLC)
/s/ Glenn VangolenChairman
Glenn Vangolen
/s/ Michael P. UrePresident, Chief Executive Officer, Chief Financial Officer and Director
Michael P. Ure(Principal Executive and Financial Officer)
/s/ Michael C. PearlSenior Vice President and Chief Financial Officer
Michael C. Pearl(Principal Financial Officer)
/s/ Catherine A. GreenVice President and Chief Accounting Officer
Catherine A. Green(Principal Accounting Officer)
/s/ Marcia E. BackusDirector
Marcia E. Backus
/s/ Peter J. BennettDirector
Peter J. Bennett
/s/ Oscar K. BrownDirector
Oscar K. Brown
/s/ Jennifer M. KirkNicole E. ClarkDirector
Jennifer M. KirkNicole E. Clark
/s/ Steven D. ArnoldKenneth F. OwenDirector
Steven D. ArnoldKenneth F. Owen
/s/ James R. CraneDirector
James R. Crane
/s/ Thomas R. HixDirector
Thomas R. Hix
/s/ Craig W. StewartDirector
Craig W. Stewart
/s/ David J. TudorSchulteDirector
David J. TudorSchulte
/s/ Lisa A. StewartDirector
Lisa A. Stewart


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