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Item 7. Management’s Discussion and Analysis

2021-02-26 compared with 2020-02-27 · 619 added, 498 removed, 378 unchanged (75% of the section changed)

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 following discussion analyzes our financial condition and results of operations and should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements, wherein WES Operating is fully consolidated, and which are included under Part II, Item 8 of this Form 10-K, and the information set forth in Risk Factors under Part I, Item 1A of this Form 10-K.

The Partnership’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as of December 31, 2020 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental;

therefore, prior asset acquisitions from Anadarko were classified as tran sfers 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.

therefore, prior asset acquisitions from Anadarko were classified as transfers of net assets between entities under common control.

As such, subsequent to asset acquisitions from Anadarko, we were required to recast our financial statements to include the activities of acquired assets from the date of common control.

For reporting periods that required recast, the consolidated financial statements for periods prior to the acquisition of assets from Anadarko were prepared from Anadarko’s historical cost-basis accounts and may not be necessarily indicative of the actual results of operations that would have occurred if we had owned the assets during the periods reported.

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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 engaged in the business of gathering, compressing, treating, processing, and transporting natural gas;

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;

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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.

We own or have investments in assets located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), and North-central Pennsylvania.

As of December 31, 2020, our assets and investments consisted of the following:

Operated Operated

Interests Non-Operated

Interests Equity

Gathering systems (1)

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Crude-oil pipelines 3 1 — 4

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(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 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.

Additional significant financial and operational events during the year ended December 31, 2019 , included the following:

We increased our per-unit distribution to $0.62200 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.

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.

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

• In January 2020, WES Operating completed an offering of $3.2 billion in aggregate principal amount of Fixed-Rate Senior Notes and $300.0 million in aggregate principal amount of Floating-Rate Senior Notes.

Net proceeds from these offerings were used to repay and terminate the Term loan facility, repay outstanding amounts under the RCF, and for general partnership purposes.

See Liquidity and Capital Resources within this Item 7 for additional information.

We commenced operations of Mentone 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 200 MMcf/d) at the end of the first and fourth quarters, respectively, of 2019.

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.

• In November 2020, we announced a buyback program of up to $250.0 million of our common units through December 31, 2021.

We repurchased 2,368,711 units for aggregate consideration of $32.5 million through December 31, 2020.

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

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

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

• During the year ended December 31, 2020, WES Operating purchased and retired $218.0 million of certain of its senior notes and Floating-Rate Senior Notes.

See Liquidity and Capital Resources within this Item 7 for additional information.

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.

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

• Effective with the execution of the December 2019 agreements, WES began the transition to a stand-alone midstream business resulting in efficiencies between our commercial, engineering, and operations teams, enabling our organization to realize operating and capital savings.

This effort has involved, among other things, a transition from Occidental’s Enterprise Resource Planning (“ERP”) system to a stand-alone ERP system, and the transition to a WES-dedicated workforce with its own compensation and benefits structure.

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

Crude-oil, NGLs, and produced-water throughput attributable to WES totaled 1,195 MBbls/d for the year ended December 31, 2019 , representing a 57% increase compared to the year ended December 31, 2018 .

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 .

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

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

• Operating income (loss) was $878.9 million for the year ended December 31, 2020 (included goodwill and long-lived asset impairments of $644.9 million), representing a 29% decrease compared to the year ended December 31, 2019.

• Adjusted gross margin for natural-gas assets (as defined under the caption How We Evaluate Our Operations within this Item 7) averaged $1.16 per Mcf for the year ended December 31, 2020, representing an 8% increase compared to the year ended December 31, 2019.

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

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

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

Year Ended December 31,

2020 2019 Inc/

(Dec) 2020 2019 Inc/

Crude oil & NGLs

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Delaware Basin

1,297 1,226 6 % 189 150 26 % 712 556 28 %

DJ Basin 1,305 1,236 6 % 101 118 (14) % — — — %

Equity investments 445 398 12 % 381 343 11 % — — — %

1,386 1,563 (11) % 41 52 (21) % — — — %

Total throughput

4,433 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.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

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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 allow for rate resets that target an agreed-upon rate of return over the life of the agreement.

See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Certain of the gathering agreements for the West Texas complex, Springfield system, DJ Basin oil system, Marcellus Interest systems, and DBM oil and water systems allow for rate resets that target an agreed-upon rate of return over the life of the agreement.

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

Acquisitions and divestitures.

In February 2019, WES Operating acquired AMA from Anadarko.

In January 2019, we acquired a 30% interest in Red Bluff Express.

In June 2018, we acquired a 20% interest in Whitethorn LLC and a 15% interest in Cactus II.

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

In December 2018, the Newcastle system in Northeast Wyoming was sold to a third party.

See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

We recognized long-lived asset and other impairments of $203.9 million, $6.3 million, and $230.6 million for the years ended December 31, 2020, 2019, and 2018, respectively.

During the year ended December 31, 2020, we also recognized a goodwill impairment of $441.0 million, which reduced the carrying value of goodwill for the gathering and processing reporting unit to zero.

For a description of impairments recorded, see Note 9—Property, Plant, and Equipment , Note 7—Equity Investments, and Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

General and administrative expenses.

On December 31, 2019, we entered into the December 2019 Agreements, which helped facilitate our ability to operate more independently from Occidental.

As a result, during 2020, we began incurring costs to (i) implement technology systems to manage the operations and administration of our day-to-day business, (ii) secure our dedicated workforce, and (iii) operate as a stand-alone entity.

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

Noncontrolling interests.

For periods subsequent to Merger completion, our noncontrolling interests in the consolidated financial statements consist of (i) the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating.

For periods prior to Merger completion, our noncontrolling interests in the consolidated financial statements consisted of (i) the 25% third-party interest in Chipeta, (ii) the publicly held limited partner interests in WES Operating, (iii) the common units issued by WES Operating to subsidiaries of Anadarko as part of the consideration paid for prior acquisitions from Anadarko, (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.

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.

Commodity-price swap agreements .

During all periods presented, the consolidated statements of operations and consolidated statements of equity and partners’ capital included the impacts of commodity-price swap 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 regarding the commodity-price swap agreements with Anadarko that expired without renewal on December 31, 2018.

The consolidated statements of operations and consolidated statements of equity and partners’ capital included the impacts of commodity-price swap agreements for the years ended December 31, 2019 and 2018.

See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information regarding the commodity-price swap agreements with Anadarko that expired without renewal on December 31, 2018.

Income taxes.

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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 ne t 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.

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.

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 Policies in 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 Policies in 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

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We also gather and dispose of produced water.

Currently we have operations in Colorado, Utah, Wyoming, North-central Pennsylvania, Texas, and New Mexico, with a substantial portion of our business concentrated in the Rocky Mountains and West Texas.

For example, for the year ended December 31, 2019 , our DJ Basin and West Texas assets provided (i) 31% of each of our throughput for natural-gas assets (excluding equity-investment throughput), (ii) 13% and 81% , respectively, of our throughput for crude-oil, NGLs, and produced-water assets (excluding equity-investment throughput), and (iii) 36% and 44% , respectively, of Total revenues and other.

For the year ended December 31, 2019 , 59% of Total revenues and other, 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) were attributable to transactions with Occidental.

In addition, Occidental supports our operations by providing dedications and/or minimum-volume commitments.

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 operate in Texas, New Mexico, Colorado, Utah, Wyoming, and North-central Pennsylvania, with a substantial portion of our business concentrated in West Texas and the Rocky Mountains.

For example, for the year ended December 31, 2020, our West Texas and DJ Basin assets provided (i) 46% and 38%, respectively, of Total revenues and other, (ii) 33% each of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 57% and 31%, respectively, of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and (iv) all of our throughput for produced-water assets.

For the year ended December 31, 2020, 66% of Total revenues and other, 41% of our throughput for natural-gas assets (excluding equity-investment throughput), 88% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental.

While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market.

In addition, Occidental provides dedications and/or minimum-volume commitments under certain of our contracts.

For the year ended December 31, 2020, 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil and produced-water throughput (excluding equity investments) were serviced under fee-based contracts under which fixed and variable fees are received based on the volume or thermal content of the natural gas and on the volume of NGLs, crude oil, and produced water we gather, process, treat, transport, or dispose.

This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or production facilities or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements.

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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) Adjusted gross margin (as defined below), (v) Adjusted EBITDA (as defined below), and (vi) Distributable cash flow (as defined below).

These metrics are significant factors in assessing our operating results and profitability and include (i) throughput, (ii) operating and maintenance expenses, (iii) general and administrative expenses, (iv) safety performance, (v) system availability, (vi) Adjusted gross margin (as defined below), (vii) Adjusted EBITDA (as defined below), and (viii) Free cash flow (as defined below).

Throughput is a significant operating variable that we use to assess our ability to generate revenues.

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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, 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 Agreements within this Item 7).

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.

See further detail in Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K .

General and administrative expenses .

To assess the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses by way of comparison to prior periods and to the annual budget 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;

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 .

Pursuant to the Services Agreement entered into as part of the December 2019 Agreements , 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 for up to a two-year transition period.

See further detail in Executive Summary– December 2019 Agreements within this Item 7 and Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K .

Pursuant to the Services Agreement entered into as part of the December 2019 Agreements, Occidental (i) seconded certain personnel employed by Occidental to WES Operating GP, in exchange for which WES Operating GP paid a monthly secondment and shared services fee to Occidental equivalent to the direct cost of the seconded employees until their transfer to us and (ii) agreed to continue to provide certain administrative and operational services to us for up to a two-year transition period, for which Occidental is reimbursed accordingly.

The Services Agreement also included provisions governing the transfer of certain employees to us and our assumption of liabilities relating to those employees at the time of their transfer.

In late March 2020, seconded employees’ employment was transferred to us.

Prior to the December 2019 Agreements, Occidental and our general partner performed centralized corporate functions for us pursuant to the now terminated WES and WES Operating omnibus agreements.

Safety performance .

Maintaining a safe and incident free workplace is a critical component of our operational success.

Our management team uses both lagging and leading indicators to measure and manage safety performance.

Total Recordable Incident Rate is a key lagging indicator reviewed by management.

Total Recordable Incident Rate includes injuries or illnesses that result in any of the following:

days away from work, restricted work or transfer to another job, medical treatment beyond first aid, loss of consciousness, or death.

We also review leading indicators such as unplanned releases, safety observations, occupational and process safety audits and inspections, training completion, and corrective action item completion to enhance our view of safety performance.

Safety performance data is reported, tracked, and trended in a centralized database, which allows us to efficiently focus our incident prevention efforts.

System availability .

By consistently monitoring the availability of our gathering, processing, and water disposal systems to provide critical midstream services to our customers, we can ensure we are maximizing the ability of our assets to generate revenues, while providing a reliable service to our producer customers.

We define system availability as the measure of the “real” average availability experienced by our customers related to its gas systems, oil systems, and water-disposal wells.

It considers the ratio of average actual daily volumes to expected daily volumes and includes all experienced sources of downtime, such as scheduled and unscheduled downtime, logistic downtime, etc.

Non-GAAP financial measures

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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, NGLs, and produced-water assets .

To facilitate investor and industry analyst comparisons between us and our peers, we also disclose per-Mcf Adjusted gross margin for natural-gas assets, per-Bbl Adjusted gross margin for crude-oil and NGLs assets, and per-Bbl Adjusted gross margin for produced-water assets .

See Key Performance Metrics within this Item 7.

Adjusted EBITDA.

We define Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) as net income (loss), plus distributions from equity investments, non-cash equity-based compensation expense, interest expense, income tax expense, depreciation and amortization, impairments, and other expense (including lower of cost or market inventory adjustments recorded in cost of product), less gain (loss) on divestiture and other, net, income from equity investments, interest income, income tax benefit, other income, and the noncontrolling interests owners’ proportionate share of revenues and expenses.

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.

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

Distributable cash flow.

We define “Distributable cash flow” as Adjusted EBITDA, plus interest income and the net settlement amounts from the sale and/or purchase of natural gas, condensate, and NGLs under 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 EBITDA 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 Distributable 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 Distributable cash flow is useful to investors because this measurement is used by many companies, analysts, and others in the industry as a performance measurement tool to evaluate our operating and financial performance as compared to the performance of other publicly traded partnerships.

Distributable cash flow is a measure we use to assess our ability to make distributions to our unitholders;

however, this measure should not be viewed as indicative of the actual amount of cash available for distributions or planned for distribution for a given period.

Furthermore, to the extent Distributable cash flow includes realized amounts recorded as capital contributions from Anadarko attributable to activity under our commodity-price swap agreements, it is not a reflection of our ability to generate cash from operations.

Free cash flow.

We define “Free cash flow” as net cash provided by operating activities less total capital expenditures and contributions to equity investments, plus distributions from equity investments in excess of cumulative earnings.

Management considers Free cash flow an appropriate metric for assessing capital discipline, cost efficiency, and balance-sheet strength.

Although Free cash flow is the metric used to assess WES’s ability to make distributions to unitholders, this measure should not be viewed as indicative of the actual amount of cash that is available for distributions or planned for distributions for a given period.

Instead, Free cash flow should be considered indicative of the amount of cash that is available for distributions, debt repayments, and other general partnership purposes.

Reconciliation of non-GAAP financial measures.

Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow are not defined in GAAP.

Adjusted gross margin, Adjusted EBITDA, and Free cash flow are not defined in GAAP.

The GAAP measure used by us that is most directly comparable to Adjusted gross margin is operating income (loss).

Net income (loss) and net cash provided by operating activities are the GAAP measures used by us that are most directly comparable to Adjusted EBITDA.

The GAAP measure used by us that is most directly comparable to Distributable cash flow is net income (loss).

Our non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow should not be considered as alternatives to the GAAP measures of operating income (loss), net income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP.

Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect operating income (loss), net income (loss), and net cash provided by operating activities.

Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP.

Our definitions of Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility as comparative measures.

Management compensates for the limitations of Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow compared to (as applicable) operating income (loss), net income (loss), and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes.

The GAAP measure used by us that is most directly comparable to Free cash flow is net cash provided by operating activities.

Our non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered as alternatives to the GAAP measures of operating income (loss), net income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP.

Adjusted gross margin, Adjusted EBITDA, and Free cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect operating income (loss), net income (loss), and net cash provided by operating activities.

Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP.

Our definitions of Adjusted gross margin, Adjusted EBITDA, and Free cash flow may not be comparable to similarly titled measures of other companies in our industry, thereby diminishing their utility as comparative measures.

Management compensates for the limitations of Adjusted gross margin, Adjusted EBITDA, and Free cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA, and Free cash flow compared to (as applicable) operating income (loss), net income (loss), and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes.

We believe that investors benefit from having access to the same financial measures that our management considers in evaluating our operating results.

The following tables present (a) a reconciliation of the GAAP financial measure of our operating income (loss) to the non-GAAP financial measure of Adjusted gross margin, (b) 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) a reconciliation of the GAAP financial measure of our net income (loss) to the non-GAAP financial measure of Distributable cash flow:

The following tables present (i) a reconciliation of the GAAP financial measure of operating income (loss) to the non-GAAP financial measure of Adjusted gross margin, (ii) a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non-GAAP financial measure of Adjusted EBITDA, and (iii) a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non-GAAP financial measure of Free cash flow:

Year Ended December 31,

thousands 2020 2019 2018

Reconciliation of Operating income (loss) to Adjusted gross margin

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Distributions from equity investments

278,797 264,828 216,977

Operation and maintenance

580,874 641,219 480,861

General and administrative

155,769 114,591 67,195

Property and other taxes

68,340 61,352 51,848

Depreciation and amortization

491,086 483,255 389,164

Impairments (1)

644,906 6,279 230,584

Gain (loss) on divestiture and other, net 8,634 (1,406) 1,312

Proceeds from business interruption insurance claims

Equity income, net – affiliates

Equity income, net – related parties 226,750 237,518 195,469

Reimbursed electricity-related charges recorded as revenues 79,261 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

Adjusted gross margin for crude-oil, NGLs, and produced-water assets

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 .

$ 1,820,926 $ 1,656,041 $ 1,443,466

Adjusted gross margin for crude-oil and NGLs assets

647,390 578,100 447,131

Adjusted gross margin for produced-water assets

249,889 193,936 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.

Year Ended December 31,

thousands 2020 2019 2018

Reconciliation of Net income (loss) to Adjusted EBITDA

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Depreciation and amortization 491,086 483,255 389,164

Impairments (1)

644,906 6,279 230,584

Other expense 1,953 161,813 8,264

Gain (loss) on divestiture and other, net 8,634 (1,406) 1,312

Equity income, net – affiliates

Interest income – affiliates

Gain (loss) on early extinguishment of debt 11,234 — —

Equity income, net – related parties 226,750 237,518 195,469

Interest income – Anadarko note receivable 11,736 16,900 16,900

Other income 2,785 37,792 2,749

Income tax benefit 4,280 — —

Adjusted EBITDA attributable to noncontrolling interests (2)

50,607 45,131 42,843

Adjusted EBITDA $ 2,030,366 $ 1,719,090 $ 1,466,445

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Accretion and amortization of long-term obligations, net (8,654) (8,441) (5,943)

Current income tax (benefit) expense

Current income tax expense (benefit) 2,702 5,863 (80,114)

Other (income) expense, net (3)

Distributions from equity investments in excess of cumulative earnings – affiliates

(1,025) (1,549) (3,209)

Cash paid to settle interest-rate swaps 25,621 107,685 —

Distributions from equity investments in excess of cumulative earnings – related parties

32,160 30,256 29,585

Changes in assets and liabilities:

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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

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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.

(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.

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Year Ended December 31,

thousands except Coverage ratio

Reconciliation of Net income (loss) to Distributable cash flow and calculation of the Coverage ratio

Net income (loss)

Distributions from equity investments

Non-cash equity-based compensation expense

Non-cash settled interest expense, net

Income tax (benefit) expense

Depreciation and amortization

Above-market component of swap agreements with Anadarko (1)

Other expense

Recognized Service revenues – fee based in excess of (less than) customer billings

Gain (loss) on divestiture and other, net

Equity income, net – affiliates

Cash paid for maintenance capital expenditures

Capitalized interest

Cash paid for (reimbursement of) income taxes

WES Operating Series A Preferred unit distributions

Distributable cash flow attributable to noncontrolling interests (2)

Distributable cash flow (3)

Distributions declared

Distributions from WES Operating

Cash reserve for the proper conduct of WES’s business

Distributions to WES unitholders (4)

Coverage ratio

See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II , Item 8 of this Form 10-K .

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 .

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.

thousands 2020 2019 2018

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

Capital expenditures 423,091 1,188,829 1,948,595

Contributions to equity investments – related parties 19,388 128,393 133,629

Distributions from equity investments in excess of cumulative earnings – related parties 32,160 30,256 29,585

Free cash flow $ 1,227,099 $ 37,134 $ (704,464)

Cash flow information

Net cash provided by operating activities $ 1,637,418 $ 1,324,100 $ 1,348,175

Net cash used in investing activities (448,254) (3,387,853) (2,210,813)

Net cash provided by (used in) financing activities (844,204) 2,071,573 875,192

GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the following key trends and uncertainties.

We expect our business to continue to be affected by the below-described key trends and uncertainties.

Our expectations are based on assumptions made by us and information currently available to us.

To the extent our underlying assumptions about, or interpretations of, available information prove incorrect, our actual results may vary materially from expected results.

See Risk Factors under Part I, Item 1A of this Form 10-K for additional information.

Impact of crude-oil, natural-gas, and NGLs prices.

Crude-oil, natural-gas, and NGLs prices can fluctuate significantly, and have done so over time.

Commodity-price fluctuations affect the overall level of our customers’ activity and how our customers allocate capital within their own asset portfolio.

The relatively volatile commodity-price environment over the past decade has impacted drilling activity in several of the basins in which we operate.

Many of our customers, including Occidental, have shifted capital spending toward opportunities with superior economics and reduced activity in other areas.

To the extent possible, and to maintain throughput on our systems, we will continue to connect new wells or production facilities to our systems to mitigate the impact of natural production declines.

Commodity-price fluctuations affect the level of our customers’ activities and our customers’ allocations of capital within their own asset portfolios.

During the first quarter of 2020, oil and natural-gas prices decreased significantly, driven by the expectation of increased supply and sharp declines in demand resulting from the worldwide macroeconomic downturn that followed the global outbreak of COVID-19.

For example, NYMEX West Texas Intermediate crude-oil daily settlement prices ranged from a high of $63.27 per barrel in January 2020 to a low below $20.00 per barrel in April 2020, with prices rebounding to $48.52 per barrel at December 31, 2020.

While the extent and duration of the recent commodity-price declines cannot be predicted, potential impacts to our business include the following:

• We have exposure to increased credit risk to the extent any of our customers, including Occidental, is in financial distress.

See Liquidity and Capital Resources—Credit risk within this Item 7 for additional information.

• An extended period of diminished earnings may restrict our ability to fully access our RCF, which contains various customary covenants, certain events of default, and a maximum consolidated leverage ratio based on Adjusted EBITDA (as defined in the covenant) related to the trailing twelve-month period.

Further, any future waivers or amendments to the RCF also may trigger pricing increases for available credit.

See Liquidity and Capital Resources—Debt and credit facilities within this Item 7 for additional information.

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

To the extent producers continue with development plans in our areas of operation, we will continue to connect new wells or production facilities to our systems to maintain throughput on our systems and mitigate the impact of production declines.

However, our success in connecting additional wells or production facilities is dependent on the activity levels of our customers.

Additionally, we will continue to evaluate the crude-oil, NGLs, and natural-gas price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility.

See risk factor, “The global outbreak of COVID-19 may have an adverse impact on our operations and financial results.” under Part I, Item 1A of this Form 10-K for additional information.

Liquidity and access to capital markets.

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 have raised our cost of capital and, in some cases, temporarily made certain sources of capital unavailable.

If we are either unable to access the capital markets or find alternative sources of capital at reasonable costs, our growth strategy will become more challenging to execute.

From time to time, capital market turbulence and investor sentiment towards MLPs, and the broader energy industry, have raised our cost of capital and, in some cases, temporarily made certain sources of capital unavailable.

If we require funding beyond our sources of liquidity and are either unable to access the capital markets or find alternative sources of capital at reasonable costs, our growth strategy may become more challenging to execute.

Changes in regulations.

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Overall, short- and long-term interest rates decreased during 2020 and remained low relative to historical averages.

Short-term interest rates experienced a sharp decrease in response to the Federal Open Market Committee (“FOMC”) lowering its target range for the federal funds rate three separate times during 2019 .

Any future increases in the federal funds rate likely will result in an increase in short-term financing costs.

Short-term interest rates experienced a sharp decrease in response to the Federal Open Market Committee (“FOMC”) lowering its target range for the federal funds rate twice during 2020.

Long-term interest rates experienced a similar decrease in response to lower future economic growth expectations.

Any future increases in interest rates likely will result in an increase in financing costs.

Additionally, as with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates.

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However, we expect our cost of capital to remain competitive, as our competitors face similar interest-rate dynamics.

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.

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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.

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—Summary 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.

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

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Year Ended December 31,

thousands 2020 2019 2018

Total revenues and other (1)

Equity income, net – affiliates

$ 2,772,592 $ 2,746,174 $ 2,299,658

Equity income, net – related parties 226,750 237,518 195,469

Total operating expenses (1)

2,129,063 1,750,943 1,635,157

Gain (loss) on divestiture and other, net 8,634 (1,406) 1,312

Proceeds from business interruption insurance claims (2)

Operating income (loss) 878,913 1,231,343 861,282

Interest income – affiliates

Interest income – Anadarko note receivable 11,736 16,900 16,900

Interest expense (380,058) (303,286) (183,831)

Gain (loss) on early extinguishment of debt 11,234 — —

Other income (expense), net 1,025 (123,785) (4,763)

Income (loss) before income taxes 522,850 821,172 689,588

Income tax (benefit) expense

Income tax expense (benefit) 5,998 13,472 58,934

Net income (loss) 516,852 807,700 630,654

Net income attributable to noncontrolling interests

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)

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Adjusted EBITDA 2,030,366 1,719,090 1,466,445

Distributable cash flow

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 .

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 .

Free cash flow 1,227,099 37,134 (704,464)

_________________________________________________________________________________________

(1) Total revenues and other includes amounts earned from services provided to related parties and from the sale of residue gas and NGLs to related parties.

Total operating expenses includes amounts charged by related parties for services and reimbursements of amounts paid by related parties to third parties on our behalf.

See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(2) For reconciliations to comparable consolidated results of WES Operating, see Items Affecting the Comparability of Financial Results with WES Operating within this Item 7.

Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow are defined under the caption How We Evaluate Our Operations 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 unchanged sentence

Year Ended December 31,

2020 2019 Inc/

(Dec) 2018 Inc/

Throughput for natural-gas assets (MMcf/d)

1 unchanged sentence

Processing 3,445 3,497 (1) % 3,231 8 %

Equity investment (2)

Equity investments (1)

445 398 12 % 291 37 %

Total throughput 4,433 4,423 — % 4,068 9 %

Throughput attributable to noncontrolling interests (2)

159 175 (9) % 170 3 %

Total throughput attributable to WES for natural-gas assets

Throughput for crude-oil, NGLs, and produced-water assets (MBbls/d)

Gathering, treating, transportation, and disposal

Equity investment (4)

4,274 4,248 1 % 3,898 9 %

Throughput for crude-oil and NGLs assets (MBbls/d)

Gathering, treating, and transportation

331 320 3 % 295 8 %

Equity investments (3)

381 343 11 % 241 42 %

Total throughput

712 663 7 % 536 24 %

Throughput attributable to noncontrolling interests (2)

Total throughput attributable to WES for crude-oil, NGLs, and produced-water assets

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.”

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.

14 13 8 % 11 18%

Total throughput attributable to WES for crude-oil and NGLs assets

698 650 7 % 525 24 %

Throughput for produced-water assets (MBbls/d)

Gathering and disposal

712 556 28 % 239 133 %

Throughput attributable to noncontrolling interests (2)

14 11 27 % 4 175 %

Total throughput attributable to WES for produced-water assets

698 545 28 % 235 132 %

_________________________________________________________________________________________

(1) Represents the 14.81% share of average Fort Union throughput (until divested in October 2020, see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K), 22% share of average Rendezvous throughput, 50% share of average Mi Vida and Ranch Westex throughput, and 30% share of average Red Bluff Express throughput.

(2) For all periods presented includes (i) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating and (ii) for natural-gas assets, the 25% third-party interest in Chipeta, which collectively represent WES’s noncontrolling interests.

(3) Represents the 10% share of average White Cliffs throughput;

4 unchanged sentences

Natural-gas assets

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

Processing throughput increase d 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 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.

Processing throughput increase d by 639 MMcf/d for the year ended December 31, 2018 , primarily due to (i) the combination of the DBM complex and DBJV and Haley systems into the West Texas complex, (ii) increased production in the areas around the DJ Basin and West Texas complexes, (iii) the start-up of Train VI at the West Texas complex in December 2017, (iv) increased throughput at the West Texas complex due to the acquisition of the Additional DBJV System Interest as part of the 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 constraints in the third quarter of 2018 and the expiration and non-renewal of a contract in September 2017.

Equity-investment throughput increase d 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 affiliate 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-water assets

Gathering, treating, transportation, and disposal throughput increase d by 342 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) increased production in areas around the DJ Basin oil system.

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

Equity-investment throughput increase d 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 throughput increase d by 93 MBbls/d 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 on TEP and FRP as a result of increased NGLs production in the DJ Basin area.

Gathering, treating, and transportation throughput increased by 15 MMcf/d for the year ended December 31, 2020, primarily due to increased production in areas around the Marcellus Interest systems, partially offset by production declines in areas around the Bison facility and Springfield gas-gathering system.

Gathering, treating, and transportation throughput decreased by 18 MMcf/d for the year ended December 31, 2019, primarily due to production declines in areas around the Springfield gas-gathering system.

This decrease was offset partially by (i) increased throughput on the MIGC system due to new third-party customer volumes beginning in the second quarter of 2019 and (ii) increased production in areas around the Marcellus Interest systems.

Processing throughput decreased by 52 MMcf/d for the year ended December 31, 2020, primarily due to (i) third-party volumes being diverted away from the Granger straddle plant beginning in the fourth quarter of 2019 and the plant being held idle during the third and fourth quarters of 2020, (ii) lower throughput at the Chipeta complex due to production declines in the area and a third-party contract that terminated during the fourth quarter of 2019, and (iii) lower throughput at the Red Desert complex due to production declines in the area.

These decreases were offset partially by (i) increased production in areas around the West Texas and DJ Basin complexes, (ii) the start-up of Latham Train II at the DJ Basin complex during the first quarter of 2020, and (iii) the start-up of Mentone Train II at the West Texas complex in March 2019.

Processing throughput increased by 266 MMcf/d for the year ended December 31, 2019, primarily due to (i) the start-up of Mentone Trains I and II at the West Texas complex in November 2018 and March 2019, respectively, and (ii) increased production in areas around the West Texas and DJ Basin complexes.

These increases were offset partially by (i) volumes being diverted away from the Granger straddle plant beginning in the fourth quarter of 2019 resulting from changes to the product mix of a third-party customer and (ii) downstream constraints during the third quarter of 2019 that impacted our DJ Basin complex.

Equity-investment throughput increased by 47 MMcf/d for the year ended December 31, 2020, primarily due to increased volumes on Red Bluff Express resulting from increased production in the area.

This increase was offset partially by (i) decreased third-party volumes at the Fort Union system, which was sold to a third party during the fourth quarter of 2020, and (ii) decreased volumes at the Rendezvous system due to production declines in the area.

Equity-investment throughput increased by 107 MMcf/d for the year ended December 31, 2019, primarily due to the acquisition of the interest in Red Bluff Express in January 2019, partially offset by decreased throughput at the Mi Vida and Ranch Westex plants due to related-party volumes being diverted to the West Texas complex for processing following the start-up of Mentone Trains I and II in November 2018 and March 2019, respectively.

Crude-oil and NGLs assets

Gathering, treating, and transportation throughput increased by 11 MBbls/d for the year ended December 31, 2020, primarily due to increased throughput at the DBM oil system with the commencement of Loving ROTF Trains III and IV operations during the first and third quarters of 2020, respectively, and increased production, partially offset by lower throughput at the DJ Basin oil system due to production declines in the area.

Gathering, treating, and transportation throughput increased by 25 MBbls/d for the year ended December 31, 2019, primarily due to (i) increased throughput at the DBM oil system due to the commencement of ROTF operations in the second quarter of 2018 and increased production in the area and (ii) increased production in areas around the DJ Basin oil system.

Equity-investment throughput increased by 38 MBbls/d for the year ended December 31, 2020, primarily due to (i) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and (ii) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020.

These increases were offset partially by decreased volumes on the Whitethorn pipeline.

Equity-investment throughput increased by 102 MBbls/d for the year ended December 31, 2019, primarily due to (i) the acquisition of our interest in Whitethorn LLC in June 2018 and increased volumes on the Whitethorn pipeline due to additional committed volumes in 2019, (ii) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and (iii) increased volumes on the Saddlehorn pipeline due to incentive tariffs and additional committed volumes effective beginning in the third quarter of 2019.

Produced-water assets

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

Gathering and disposal throughput increased by 317 MBbls/d for the year ended December 31, 2019, due to increased throughput at the DBM water systems resulting from new water-disposal systems that commenced operations during the third and fourth quarters of 2018.

Service Revenues

Year Ended December 31,

thousands except percentages

thousands except percentages 2020 2019 Inc/

(Dec) 2018 Inc/

Service revenues – fee based

$ 2,584,323 $ 2,388,191 8 % $ 1,905,728 25 %

Service revenues – product based

48,369 70,127 (31) % 88,785 (21) %

Total service revenues

NM — Not Meaningful

$ 2,632,692 $ 2,458,318 7 % $ 1,994,513 23 %

Service revenues – fee based

Service revenues – fee based increase d 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 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 – fee based increase d by $547.9 million for the year ended December 31, 2018 , primarily due to increases of (i) $154.5 million from the adoption of Topic 606, as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7, (ii) $141.3 million, $71.5 million, and $19.1 million at the West Texas complex and DBM and DJ Basin oil systems, respectively, due to increased throughput, (iii) $112.7 million at the DJ Basin complex due to increased throughput ($91.3 million) and a higher processing fee ($21.4 million), and (iv) $78.4 million at the DBM water systems 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 Exchange and (ii) $10.4 million at the Springfield system due to a lower cost-of-service rate.

Service revenues – fee based increased by $196.1 million for the year ended December 31, 2020, primarily due to increases of (i) $98.1 million at the West Texas complex and $97.9 million at the DJ Basin complex from increased throughput, (ii) $63.6 million at the DBM oil system from increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, (iii) $59.3 million at the DBM water systems from increased throughput, and (iv) $21.4 million at the Springfield system due to annual cost-of-service rate adjustments that increased revenue in the fourth quarter of 2020 and decreased revenue in the fourth quarter of 2019, partially offset by decreased volumes.

These increases were offset partially by a decrease of $130.9 million, resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).

Service revenues – fee based increased by $482.5 million for the year ended December 31, 2019, primarily due to increases of (i) $266.8 million at the West Texas complex due to a higher average gathering fee effective January 2019 ($186.3 million) and increased throughput ($80.5 million), (ii) $106.1 million at the DBM water systems due to increased throughput and new gathering and disposal agreements effective July 1, 2018, (iii) $67.9 million at the DJ Basin complex due to increased throughput and a higher average processing fee, (iv) $48.6 million at the DBM oil system due to increased throughput and a higher average gathering fee due to a new agreement effective May 2018, and (v) $37.2 million at the DJ Basin oil system due to increased throughput, a higher average gathering fee, and an annual cost-of-service rate adjustment made during the fourth quarter of 2019.

These increases were offset partially by a decrease of $32.6 million at the Springfield system due to decreased volumes and an annual cost-of-service rate adjustment in the fourth quarter of 2019.

Service revenues – product based

Service revenues – product based decrease d 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 increase d by $88.8 million for the year ended December 31, 2018 , due to the adoption of Topic 606.

As discussed under Items Affecting the Comparability of Our Financial Results within this Item 7, under Topic 606, certain of our customer agreements result in revenues being recognized when the natural gas and/or NGLs are received from the customer as 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.

Service revenues – product based decreased by $21.8 million for the year ended December 31, 2020, primarily due to (i) decreased third-party volumes at the DJ Basin complex and MGR assets and (ii) decreased pricing across several systems.

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

Product Sales

2 unchanged sentences

per-unit amounts

2020 2019 Inc/

(Dec) 2018 Inc/

Natural-gas sales $ 30,527 $ 66,557 (54) % $ 85,015 (22) %

4 unchanged sentences

NGLs (per Bbl) 13.14 20.93 (37) % 31.55 (34) %

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 decrease d 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 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 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-gas sales decrease d by $306.4 million for the year ended December 31, 2018 , primarily due to decreases of (i) $258.9 million from the adoption of Topic 606, as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7, (ii) $24.6 million at the West Texas complex due to a decrease in average price, partially offset by an increase in volumes sold, and (iii) $5.7 million due to a decrease in average price and $9.3 million due to the shutdown of the Kitty Draw gathering system, both at the Hilight system.

NGLs sales increase d 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 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 decrease d by $441.8 million for the year ended December 31, 2018 , primarily due to a decrease of $844.0 million from the adoption of Topic 606, as discussed under Items Affecting the Comparability of Our Financial Results within this Item 7.

This decrease was partially offset by increases of (i) $256.8 million at the West Texas complex due to an increase in volumes sold, partially offset by a decrease in average price, (ii) $48.2 million at the DJ Basin complex due to an increase in the swap market price and volumes sold, (iii) $39.0 million at the DJ Basin oil system due to an increase in average price and volumes sold, (iv) $23.8 million at the Brasada complex due to volumes sold under a new sales agreement beginning January 1, 2018, and (v) $12.8 million at the DBM water systems due to an increase in volumes sold related to byproducts from the treatment of produced water.

Other Revenues

Year Ended December 31,

thousands except percentages

Other revenues

For the year ended December 31, 2018 , Other revenues decrease d by $18.4 million , primarily due to deficiency fees of $8.8 million at the Chipeta complex and $7.2 million at the DBM water systems in 2017.

Upon adoption of Topic 606 on January 1, 2018, deficiency fees are recorded as Service revenues – fee based in the consolidated statements of operations (see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II , Item 8 of this Form 10-K ).

Equity Income, Net – Affiliates

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

Natural-gas sales decreased by $18.5 million for the year ended December 31, 2019, primarily due to decreases of $24.0 million and $7.2 million at the West Texas and DJ Basin complexes, respectively, due to decreases in average prices, partially offset by increases in volumes sold.

These decreases were offset partially by an increase of $13.7 million at the Hilight system primarily due to the reversal of a portion of an accrual for anticipated product-purchase costs recorded in 2018 associated with the shutdown of the Kitty Draw gathering system.

NGLs sales decreased by $111.8 million for the year ended December 31, 2020, primarily due to decreases of (i) $34.0 million at the West Texas complex attributable to a decrease in average prices, partially offset by increased volumes sold, (ii) $27.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (iii) $17.7 million at the DJ Basin complex attributable to a decrease in average prices, and (iv) $14.7 million at the Brasada complex, $6.7 million at the Chipeta complex, and $6.1 million at the MGR assets resulting from decreases in average prices and volumes sold.

NGLs sales increased by $1.8 million for the year ended December 31, 2019, primarily due to increases of (i) $17.7 million at the DJ Basin complex due to an increase in volumes sold, (ii) $7.1 million related to commodity-price swap agreements that expired in December 2018, and (iii) $3.2 million at the DBM water systems due to an increase in volumes sold related to byproducts from the treatment of produced water.

These increases were offset partially by decreases of (i) $14.3 million and $7.6 million at the MGR assets and Granger complex, respectively, due to decreases in average prices and volumes sold, and (ii) $6.1 million at the Chipeta complex due to a decrease in average price.

Equity Income, Net – Related Parties

Year Ended December 31,

thousands except percentages

Equity income, net – affiliates

Equity income, net – affiliates increase d 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 partially offset by a decrease in volumes at TEP.

Equity income, net – affiliates increase d 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.

thousands except percentages 2020 2019 Inc/

(Dec) 2018 Inc/

Equity income, net – related parties $ 226,750 $ 237,518 (5) % $ 195,469 22 %

Equity income, net – related parties decreased by $10.8 million for the year ended December 31, 2020, primarily due to a decrease in equity income from Whitethorn LLC related to commercial activities and decreased volumes, and decreased rates at White Cliffs.

These decreases were offset partially by increases related to the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, and increased volumes on TEP, FRP, Ranch Westex, and Red Bluff Express.

Equity income, net – related parties increased by $42.0 million for the year ended December 31, 2019, primarily due to (i) the acquisition of our interest in Whitethorn LLC in June 2018 and increased volumes on the Whitethorn pipeline due to additional committed volumes in 2019, (ii) increased volumes at FRP and the Saddlehorn pipeline, and (iii) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019.

These increases were offset partially by a decrease in volumes at TEP.

Cost of Product and Operation and Maintenance Expenses

Year Ended December 31,

thousands except percentages

thousands except percentages 2020 2019 Inc/

(Dec) 2018 Inc/

NGLs purchases $ 131,964 $ 331,872 (60) % $ 292,698 13 %

Residue purchases 65,193 100,570 (35) % 125,106 (20) %

Other (9,069) 11,805 (177) % (2,299) NM

Cost of product 188,088 444,247 (58) % 415,505 7 %

1 unchanged sentence

Total Cost of product and Operation and maintenance expenses

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 .

$ 768,962 $ 1,085,466 (29) % $ 896,366 21 %

_________________________________________________________________________________________

NM — Not meaningful

NGLs purchases

NGLs purchases increase d 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 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 purchases decreased by $280.6 million for the year ended December 31, 2018 , primarily due to a decrease of $690.2 million from the adoption of Topic 606, as discussed under Items Affecting the Comparability of Financial Results within this Item 7, partially offset by increases of (i) $269.5 million at the West Texas complex due to an increase in volumes purchased, (ii) $50.4 million and $40.4 million at the DJ Basin complex and DJ Basin oil system, respectively, due to increases in average prices and volumes purchased, (iii) $22.0 million at the Brasada complex due to volumes purchased under a new purchase agreement beginning January 1, 2018, and (iv) $11.8 million at the DBM water systems, which commenced operation beginning in the second quarter of 2017.

NGLs purchases decreased by $199.9 million for the year ended December 31, 2020, primarily due to decreases of (i) $139.5 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (ii) $32.6 million at the West Texas complex attributable to average-price decreases, partially offset by purchased-volume increases, (iii) $13.8 million at the Brasada complex attributable to purchased-volume decreases, partially offset by average-price increases, and (iv) $6.9 million at the Chipeta complex attributable to average-price and purchased-volume decreases.

NGLs purchases increased by $39.2 million for the year ended December 31, 2019, primarily due to increases of (i) $48.1 million and $10.6 million at the West Texas and DJ Basin complexes, respectively, primarily due to increases in volumes purchased and (ii) $3.3 million at the DBM water systems due to an increase in volumes purchased related to byproducts from the treatment of produced water.

These increases were offset partially by decreases of (i) $9.8 million and $6.3 million at the MGR assets and Granger complex, respectively, due to decreases in average prices and volumes purchased and (ii) $7.4 million at the Chipeta complex due to a decrease in average price.

Residue purchases

Residue purchases decrease d 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 decreased by $242.1 million for the year ended December 31, 2018 , 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 million at the West Texas complex due to a decrease in average price, partially offset by an increase in volumes purchased, (iii) $6.8 million at the MGR assets due to decreases in average price and volumes purchased, and (iv) $5.0 million at the Hilight system due to a decrease in volumes purchased.

These decreases were partially offset by an increase of $5.7 million at the DJ Basin complex due to an increase in volumes purchased, partially offset by a decrease in average price.

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

Residue purchases decreased by $35.4 million for the year ended December 31, 2020, primarily due to decreases of (i) $21.1 million resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020 (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7), (ii) $11.3 million at the DJ Basin complex attributable to average-price decreases, and (iii) $4.3 million at the MGR assets attributable to average-price and purchased-volume decreases.

These decreases were offset partially by an increase of $3.2 million at the Chipeta complex primarily due to purchased-volume and average-price increases.

Residue purchases decreased by $24.5 million for the year ended December 31, 2019, primarily due to decreases of (i) $16.8 million at the West Texas complex due to a decrease in average price, partially offset by an increase in volumes purchased, (ii) $3.8 million at the MGR assets due to a decrease in volumes purchased, and (iii) $2.7 million at the Hilight system due to decreases in volumes purchased and average price.

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

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

Operation and maintenance expense

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

Operation and maintenance expense decreased by $60.3 million for the year ended December 31, 2020, primarily as a result of focused cost-savings initiatives related to the stand-up of WES as an independent organization, resulting in decreases of (i) $34.2 million at the West Texas complex primarily resulting from decreased salaries and wages, contract labor and consulting services, and surface maintenance and plant repairs expense, (ii) $6.1 million and $3.3 million at the Springfield and DBM oil systems, respectively, primarily due to decreased salaries and wages and surface maintenance and plant repairs expense, partially offset by increases in other field expenses, (iii) $4.6 million at the Chipeta complex primarily attributable to decreased surface maintenance and plant repairs and utilities expense, and (iv) $3.2 million and $2.4 million at the Hilight system and Granger complex, respectively, primarily due to decreased salaries and wages, surface maintenance and plant repairs, and safety expense.

Operation and maintenance expense increased by $160.4 million for the year ended December 31, 2019, primarily due to increases of (i) $51.1 million at the DBM water systems due to new water-disposal systems that commenced operations during the third and fourth quarters of 2018 and higher surface-use fees, (ii) $39.0 million, $32.3 million, and $17.9 million at the West Texas complex, DJ Basin complex, and DBM oil system, respectively, primarily due to increases in surface maintenance and plant repairs, salaries and wages, utilities expense, and contract labor and consulting services, (iii) $6.9 million at the DJ Basin oil system due to increases in surface maintenance and plant repairs, salaries and wages, and utilities expense, and (iv) $5.9 million at the Springfield system due to increases in surface maintenance and plant repairs and safety expense.

Other Operating Expenses

Year Ended December 31,

thousands except percentages

thousands except percentages 2020 2019 Inc/

(Dec) 2018 Inc/

General and administrative (1)

$ 155,769 $ 114,591 36 % $ 67,195 71 %

Property and other taxes 68,340 61,352 11 % 51,848 18 %

Depreciation and amortization 491,086 483,255 2 % 389,164 24 %

Long-lived asset and other impairments 203,889 6,279 NM 230,584 (97) %

Goodwill impairment

441,017 — NM — NM

Total other operating expenses

$ 1,360,101 $ 665,477 104 % $ 738,791 (10) %

_________________________________________________________________________________________

(1) Includes general and administrative expenses incurred on and subsequent to the date of the acquisition of assets from Anadarko, and a management services fee for expenses incurred by Anadarko for periods prior to the acquisition of such assets.

General and administrative expenses

General and administrative expenses increase d 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 partially offset by a decrease of $4.4 million in legal and consulting fees.

General and administrative expenses increase d by $13.2 million for the year ended December 31, 2018 , primarily due to (i) legal and consulting fees incurred in 2018 and (ii) personnel costs for which we reimbursed Occidental pursuant to the omnibus agreements.

These increases were partially offset by a decrease in bad debt expense.

For the years ended December 31, 2019 and 2018, General and administrative expenses were determined by rate estimation and allocated to us from Occidental pursuant to the omnibus agreements.

Effective with the December 2019 Agreements, WES began to incur such costs directly, or via direct charge from Occidental, pursuant to the terms of the Services Agreement.

General and administrative expenses increased by $41.2 million for the year ended December 31, 2020, primarily due to (i) $21.2 million related to information technology services provided by Occidental to WES and (ii) $16.4 million in personnel costs primarily resulting from WES securing its own dedicated workforce as of December 31, 2019.

General and administrative expenses also increased by $6.0 million for the year ended December 31, 2020, primarily due to increases in corporate expenses and professional fees.

See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

General and administrative expenses increased by $47.4 million for the year ended December 31, 2019, primarily due to increases of (i) $46.1 million of personnel costs for which we reimbursed Occidental pursuant to the omnibus agreements, primarily as a result of the rate-redetermination provisions in the omnibus agreements with Occidental, resulting in a 30% increase in reimbursements for general and administrative expenses incurred on our behalf, which took effect January 1, 2019, and (ii) $6.3 million of expenses related to equity awards.

These amounts were offset partially by a decrease of $4.4 million in legal and consulting fees.

Property and other taxes

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

Property and other taxes increased by $7.0 million for the year ended December 31, 2020, primarily due to ad valorem tax increases of $6.5 million at the DJ Basin complex due to capital projects being placed into service, including the completion of Latham Train I in November 2019.

This increase was offset partially by ad valorem tax decreases in Utah and West Texas due to lower valuations and lower tax rates.

Property and other taxes increased by $9.5 million for the year ended December 31, 2019, primarily due to ad valorem tax increases (i) at the West Texas complex due to the start-up of Mentone Train I in November 2018 and (ii) at the DJ Basin complex due to the completion of capital projects.

Depreciation and amortization expense

Depreciation and amortization expense increase d 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.

Depreciation and amortization expense increased by $7.8 million for the year ended December 31, 2020, primarily due to increases of (i) $11.9 million and $5.9 million at the West Texas complex and DBM oil system, respectively, resulting from capital projects being placed into service, (ii) $7.8 million of amortization expense related to finance leases, and (iii) $3.3 million for a pipeline in Wyoming due to revisions in cost estimates related to asset retirement obligations.

These amounts were offset partially by decreases of (i) $10.6 million at the DJ Basin complex primarily as a result of a change in estimate for asset retirement obligations for the Third Creek gathering system of $32.7 million, offset by increased depreciation expense of $22.1 million for capital projects being placed into service, (ii) $10.3 million at the Hilight system primarily attributable to revisions in cost estimates related to asset retirement obligations and an acceleration of depreciation expense in the comparative prior period, and (iii) $5.3 million at the Chipeta complex primarily due to lower depreciation as a result of the impairment incurred during the first quarter of 2020.

See Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for more information regarding asset retirement obligations.

Depreciation and amortization expense increased by $94.1 million for the year ended December 31, 2019, primarily due to increases of (i) $36.4 million at the West Texas complex, (ii) $24.8 million at the DBM water systems, (iii) $13.6 million at the DBM oil system, and (iv) $8.2 million at the DJ Basin complex, all due to capital projects being placed into service.

In addition, for the year ended December 31, 2019, there was an increase of $7.5 million at the Hilight system, primarily due to an acceleration of depreciation expense and revisions in cost estimates related to asset retirement obligations.

For further information regarding capital projects, see Liquidity and Capital Resources—Capital expenditures within this Item 7.

Depreciation and amortization expense increase d by $70.4 million for the year ended December 31, 2018 , primarily due to increases of (i) $30.4 million, $12.9 million, and $10.8 million at the West Texas complex, DBM water systems, and DBM oil system, respectively, due to capital projects being placed into service and (ii) $17.1 million at the DJ Basin complex related to the shutdown of the Third Creek gathering system (see Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

Impairment expense

Impairment expense for the year ended December 31, 2019 , was primarily due to impairments of $4.9 million at the DJ Basin complex.

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, (i v) $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 impairment expense for the periods presented, see Note 8—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II , Item 8 of this Form 10-K .

Interest Income – Affiliates and Interest Expense

Long-lived asset and other impairment expense

Long-lived asset and other impairment expense for the year ended December 31, 2020, was primarily due to (i) $150.2 million of impairments for assets located in Wyoming and Utah, (ii) a $29.4 million other-than-temporary impairment of our investment in Ranch Westex, (iii) impairments of $16.7 million at the DJ Basin complex primarily due to the cancellation of projects and impairments of rights-of-way, and (iv) impairments of $3.8 million at the DBM oil system primarily due to the cancellation of projects.

Long-lived asset and other impairment expense for the year ended December 31, 2019, was primarily due to impairments of $4.9 million at the DJ Basin complex due to impairments of rights-of-way and cancellation of projects.

Long-lived asset and other impairment expense for the year ended December 31, 2018, was primarily due to impairments of (i) $125.9 million at the Third Creek gathering system and $8.1 million at the Kitty Draw gathering system, (ii) $38.7 million at the Hilight system, (iii) $34.6 million at the MIGC system, (iv) $10.9 million at the GNB NGL pipeline, (v) $5.6 million at the Chipeta complex, and (vi) $2.6 million at the DBM oil system.

For further information on Long-lived asset and other impairment expense for the periods presented, see Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Goodwill impairment expense

During the three months ended March 31, 2020, an interim goodwill impairment test was performed due to significant unit-price declines triggered by the combined impacts from the global outbreak of COVID-19 and the oil-market disruption.

As a result of the interim impairment test, a goodwill impairment of $441.0 million was recognized for the gathering and processing reporting unit.

For additional information, see Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Interest Income – Anadarko Note Receivable and Interest Expense

Year Ended December 31,

thousands except percentages

Note receivable – Anadarko

Interest income – affiliates

thousands except percentages 2020 2019 Inc/

(Dec) 2018 Inc/

Interest income – Anadarko note receivable

$ 11,736 $ 16,900 (31) % $ 16,900 — %

Third parties

Long-term debt

Long-term and short-term debt $ (369,815) $ (315,872) 17 % $ (200,454) 58 %

Finance lease liabilities (1,510) — NM — NM

Amortization of debt issuance costs and commitment fees

(13,501) (12,424) 9 % (9,110) 36 %

Capitalized interest 4,774 26,980 (82) % 32,479 (17) %

Related parties

APCWH Note Payable — (1,833) (100) % (6,746) (73) %

Finance lease liabilities

Deferred purchase price obligation – Anadarko

Finance lease liabilities (6) (137) (96) % — NM

Interest expense $ (380,058) $ (303,286) 25 % $ (183,831) 65 %

Interest expense increase d 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 increase d by $41.3 million for the year ended December 31, 2018 , primarily due to (i) $46.3 million of interest incurred on the 4.500% Senior Notes due 2028 and 5.300% Senior Notes due 2048 that were issued in March 2018, (ii) $15.3 million of interest incurred on the 4.750% Senior Notes due 2028 and 5.500% Senior Notes due 2048 that were issued in August 2018, and (iii) $6.6 million of interest incurred on the APCWH Note Payable.

These increases were partially offset by an increase in capitalized interest of $23.4 million , primarily due to continued construction and expansion at (i) the DJ Basin complex, including construction of the Latham processing plant beginning in 2018, (ii) the West Texas complex, including construction of the Mentone processing plant beginning in the fourth quarter of 2017, and (iii) the DBM oil system, including construction of the ROTFs that commenced operations in 2018.

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.

Other Income (Expense), Net

Year Ended December 31,

thousands except percentages

Other income (expense), net

Other income (expense), net decrease d by $119.0 million for the year ended December 31, 2019 , primarily due to a net loss of $125.3 million on interest-rate swaps that were cash-settled in December 2019.

See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II , Item 8 of this Form 10-K for additional information.

Other income (expense), net decrease d by $6.1 million for the year ended December 31, 2018 , primarily due to a non-cash loss of $8.0 million on interest-rate swaps entered into in December 2018.

See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II , Item 8 of this Form 10-K for additional information.

Income Tax (Benefit) Expense

thousands except percentages 2020 2019 Inc/

(Dec) 2018 Inc/

Other income (expense), net $ 1,025 $ (123,785) NM $ (4,763) NM

Other income (expense), net increased by $124.8 million for the year ended December 31, 2020, primarily due to non-cash losses of $125.3 million on interest-rate swaps incurred during the year ended December 31, 2019.

All outstanding interest-rate swap agreements were settled in December 2019 (see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

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

Income Tax Expense (Benefit)

Year Ended December 31,

thousands except percentages

thousands except percentages 2020 2019 Inc/

(Dec) 2018 Inc/

Income (loss) before income taxes $ 522,850 $ 821,172 (36) % $ 689,588 19 %

Income tax (benefit) expense

Income tax expense (benefit) 5,998 13,472 (55) % 58,934 (77) %

Effective tax rate 1 % 2 % 9 %

1 unchanged sentence

federal income tax purposes;

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.

therefore, our federal statutory rate is zero percent.

However, income apportionable to Texas is subject to Texas margin tax.

Income attributable to the AMA assets prior to and including February 2019 was subject to federal and state income tax.

Income earned on the AMA assets for periods subsequent to February 2019 was only subject to Texas margin tax on income apportionable to Texas.

Income earned on the AMA assets for periods subsequent to February 2019 was subject only to Texas margin tax on income apportionable to Texas.

For the year ended December 31, 2020, the variance from the federal statutory rate primarily was due to our Texas margin tax liability.

For the years ended December 31, 2019 and 2018, the variance from the federal statutory rate primarily was due to federal and state taxes on pre-acquisition income attributable to assets previously acquired from Anadarko, and our share of applicable Texas margin tax.

KEY PERFORMANCE METRICS

1 unchanged sentence

thousands except percentages and per-unit amounts

2020 2019 Inc/

(Dec) 2018 Inc/

Adjusted gross margin for natural-gas assets

Adjusted gross margin for crude-oil, NGLs, and produced-water assets (1)

$ 1,820,926 $ 1,656,041 10 % $ 1,443,466 15 %

Adjusted gross margin for crude-oil and NGLs assets

647,390 578,100 12 % 447,131 29 %

Adjusted gross margin for produced-water assets

249,889 193,936 29 % 87,608 121 %

Adjusted gross margin 2,718,205 2,428,077 12 % 1,978,205 23 %

Per-Mcf Adjusted gross margin for natural-gas assets (1)

Per-Bbl Adjusted gross margin for crude-oil, NGLs, and produced-water assets (4)

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 EBITDA 2,030,366 1,719,090 18 % 1,466,445 17 %

Distributable cash flow (2)

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.

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.

Free cash flow 1,227,099 37,134 NM (704,464) (105) %

_________________________________________________________________________________________

(1) Average for period.

1 unchanged sentence

(2) 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.

Calculated as Adjusted gross margin for crude-oil and NGLs assets, divided by total throughput (MBbls/d) attributable to WES for crude-oil and NGLs assets.

(3) Average for period.

Calculated as Adjusted gross margin for produced-water assets, divided by total throughput (MBbls/d) attributable to WES for produced-water assets.

Adjusted gross margin, Adjusted EBITDA, and Free cash flow are defined under the caption How We Evaluate Our Operations within this Item 7.

Adjusted gross margin.

Adjusted gross margin increase d 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 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 in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

Adjusted gross margin increase d by $458.3 million for the year ended December 31, 2018 , 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) t he start-up of the DBM water systems beginning in the second quarter of 2017, (v) the acquisition of 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 (see Revenue 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 (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).

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

Per-Bbl Adjusted gross margin for crude-oil, NGLs, and produced-water assets decrease d by $0.16 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 increase d by $0.11 for the year ended December 31, 2018 , primarily due to (i) increased throughput and an annual cost-of-service rate adjustment in the fourth quarter of 2018 at the DJ Basin oil system, (ii) increased throughput at the DBM oil system, (iii) the acquisition of our interest 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.

Adjusted gross margin increased by $290.1 million for the year ended December 31, 2020, primarily due to (i) increased throughput at the West Texas and DJ Basin complexes and the DBM water systems, (ii) increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, at the DBM oil system, (iii) the acquisition of our interest in Cactus II in June 2018, which began delivering crude oil during the third quarter of 2019, (iv) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020, and (v) annual cost-of-service rate adjustments at the Springfield system that increased revenues in the fourth quarter of 2020 and decreased revenues in the fourth quarter of 2019 (see Revenue and cost of product under Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

These increases were offset partially by (i) a decrease in distributions from Whitethorn LLC related to commercial activities and (ii) a decrease at the Hilight system resulting from lower throughput and an accrual reversal in the first quarter of 2019 related to the Kitty Draw gathering-system shutdown.

Adjusted gross margin increased by $449.9 million for the year ended December 31, 2019, primarily due to (i) increased throughput at the West Texas and DJ Basin complexes, (ii) the start-up of new water-disposal systems during the third and fourth quarters of 2018, (iii) increased throughput and a higher average gathering fee due to a new agreement effective May 2018 at the DBM oil system, (iv) increased throughput, a higher average gathering fee, and an annual cost-of-service rate adjustment made during the fourth quarter of 2019 at the DJ Basin oil system, and (v) the acquisition of our interest in Whitethorn LLC in June 2018 and increased volumes on the Whitethorn pipeline.

These increases were offset partially by decreased throughput and an annual cost-of-service rate adjustment in the fourth quarter of 2019 at the Springfield system (see Revenue and cost of product under Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.09 for the year ended December 31, 2020, primarily due to increased throughput at the West Texas and DJ Basin complexes, which have higher-than-average per-Mcf margins as compared to our other natural-gas assets.

Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.06 for the year ended December 31, 2019, primarily due to increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets.

Per-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by $0.10 for the year ended December 31, 2020, primarily due to (i) increased throughput and the effect of the straight-line treatment of lease revenue under the new operating and maintenance agreement with Occidental effective December 31, 2019, at the DBM oil system and (ii) increased volumes on FRP resulting from a pipeline expansion project completed during the second quarter of 2020.

These increases were offset partially by a decrease in distributions from Whitethorn LLC related to commercial activities.

Per-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by $0.04 for the year ended December 31, 2019, primarily due to (i) increased throughput, a higher average gathering fee, and an annual cost-of-service rate adjustment made during the fourth quarter of 2019 at the DJ Basin oil system, (ii) increased throughput and a higher average gathering fee due to a new agreement effective May 2018 at the DBM oil system, and (iii) the acquisition of our interest in Whitethorn LLC in June 2018 and increased volumes on the Whitethorn pipeline.

Per-Bbl Adjusted gross margin for produced-water assets decreased by $0.05 for the year ended December 31, 2019, primarily due to increased throughput on volumes with lower-than-average per-Bbl margin.

Adjusted EBITDA.

Adjusted EBITDA increase d by $252.6 million for the year ended December 31, 2019 , primarily due to (i) an increase of $446.5 million in total revenues and other and (ii) an increase of $47.9 million in distributions from equity investments.

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

Adjusted EBITDA increase d by $296.8 million for the year ended December 31, 2018 , primarily due to (i) a $538.9 million decrease in cost of product (net of lower of cost or market inventory adjustments) and (ii) a $68.2 million increase in distributions from equity investments.

These amounts were partially offset by (i) a $135.2 million increase in operation and maintenance expenses, (ii) a $130.0 million decrease in total revenues and other, (iii) a $29.9 million decrease in business interruption proceeds, and (iv) an $11.1 million increase in general and administrative expenses excluding non-cash equity-based compensation expense.

Distributable cash flow.

Distributable cash flow increase d by $185.9 million for the year ended December 31, 2019 , primarily due to (i) an increase of $252.6 million in Adjusted EBITDA and (ii) $91.3 million of customer billings in excess of the amount recognized as Service revenues – fee based.

These amounts were partially offset by (i) an increase of $113.9 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, 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 Operations within this Item 7 and see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II , Item 8 of this Form 10-K .

Distributable cash flow increase d 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.

Adjusted EBITDA increased by $311.3 million for the year ended December 31, 2020, primarily due to (i) a $256.1 million decrease in cost of product (net of lower of cost or market inventory adjustments), (ii) a $60.3 million decrease in operation and maintenance expenses, (iii) a $26.4 million increase in total revenues and other, and (iv) a $14.0 million increase in distributions from equity investments.

These amounts were offset partially by (i) a $33.1 million increase in general and administrative expenses excluding non-cash equity-based compensation expense and (ii) a $7.0 million increase in property taxes.

The above-described variances in cost of product and total revenues and other include the impacts resulting from a change in accounting for the marketing contracts with AESC effective April 1, 2020, which had no net impact on Adjusted EBITDA (see Items Affecting the Comparability of Our Financial Results—Commodity purchase and sale agreements within this Item 7).

Adjusted EBITDA increased by $252.6 million for the year ended December 31, 2019, primarily due to (i) a $446.5 million increase in total revenues and other and (ii) a $47.9 million increase in distributions from equity investments.

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

Free cash flow.

Free cash flow increased by $1,190.0 million for the year ended December 31, 2020, primarily due to (i) a decrease of $765.7 million in capital expenditures, (ii) an increase of $313.3 million in net cash provided by operating activities, and (iii) a decrease of $109.0 million in contributions to equity investments.

Free cash flow increased by $741.6 million for the year ended December 31, 2019, primarily due to (i) a decrease of $759.8 million in capital expenditures and (ii) a decrease of $5.2 million in contributions to equity investments.

These amounts were offset partially by a decrease of $24.1 million in net cash provided by operating activities.

See Capital Expenditures and Historical Cash Flow within this Item 7 for further information.

LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are for capital expenditures, debt service, customary operating expenses, quarterly distributions, distributions to our noncontrolling interest owners, and strategic acquisitions.

Our sources of liquidity as of December 31, 2019 , included cash and cash equivalents, cash flows generated from operations, interest income on our $260.0 million note receivable from Anadarko, available borrowing capacity under the RCF, and issuances of additional equity or debt securities.

We believe that cash flows generated from these sources will be sufficient to satisfy our short-term working capital requirements, and long-term maintenance and expansion capital expenditure requirements.

Our primary cash uses include capital expenditures, debt service, customary operating expenses, quarterly distributions, and distributions to our noncontrolling interest owners.

Our sources of liquidity as of December 31, 2020, included cash and cash equivalents, cash flows generated from operations, available borrowing capacity under the RCF, and potential issuances of additional equity or debt securities.

We believe that cash flows generated from these sources will be sufficient to satisfy our short-term working capital requirements and long-term capital-expenditure requirements.

The amount of future distributions to unitholders will depend on our results of operations, financial condition, capital requirements, and other factors, and will be determined by the Board of Directors on a quarterly basis.

Due to our cash distribution policy, we expect to rely on external financing sources, including equity and debt issuances, to fund expansion capital expenditures and future acquisitions.

However, 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.

Our partnership agreement requires that we distribute all of our available cash (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.

We may rely on external financing sources, including equity and debt issuances, to fund capital expenditures and future acquisitions.

However, we also may use operating cash flows to fund capital expenditures or acquisitions, which could result in borrowings under the RCF to pay distributions or to fund other short-term working capital requirements.

Under our partnership agreement, we distribute all of our available cash (beyond proper reserves as defined in our partnership agreement) within 55 days following each quarter’s end.

Our cash flow and resulting ability to make cash distributions are dependent on our ability to generate cash flow from operations.

Generally, our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter.

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 general partner establishes cash reserves to provide for the proper conduct of our business, including (i) reserves to fund future capital expenditures, (ii) to comply with applicable laws, debt instruments, or other agreements, or (iii) to provide funds for unitholder distributions for any one or more of the next four quarters.

We have made cash distributions to our unitholders each quarter since our IPO in 2012.

The Board of Directors declared a cash distribution to unitholders for the fourth quarter of 2020 of $0.31100 per unit, or $131.3 million in the aggregate.

The cash distribution was paid on February 13, 2020 , to our unitholders of record at the close of business on January 31, 2020 .

Management continuously monitors our leverage po sition and coordinates our capital expenditure program, quarterly distributions, and acquisition strategy with our expected cash flows and projected debt-repayment schedule.

We will continue to evaluate funding alternatives, including additiona l borrowings and the issuance of debt or equity securities, to secure funds as needed or to refinance outstanding debt balances with longer-term debt issuances.

The cash distribution was paid on February 12, 2021, to our unitholders of record at the close of business on February 1, 2021.

See General Trends and Outlook within this Item 7.

In November 2020, we announced a buyback program of up to $250.0 million of our common units through December 31, 2021.

The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions.

The timing and amount of purchases under the program will be determined based on ongoing assessments of capital needs, our financial performance, the market price of the common units, and other factors, including organic growth and acquisition opportunities and general market conditions.

The program does not obligate us to purchase any specific dollar amount or number of units and may be suspended or discontinued at any time.

As of December 31, 2020, we had repurchased 2,368,711 common units through open-market purchases for a total of $32.5 million.

The units were canceled by the Partnership immediately upon receipt.

Management continuously monitors our leverage position and coordinates our capital expenditures and quarterly distributions with expected cash inflows and projected debt service requirements.

We will continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or to refinance maturing debt balances with longer-term debt issuances.

Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control.

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Working capital .

As of December 31, 2019 , we had an $83.5 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 need 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.

As of December 31, 2020, we had a $17.9 million working capital deficit, which we define as the amount by which current liabilities exceed current assets.

Working capital is an indication of liquidity and potential needs for short-term funding.

As of December 31, 2020, there was $2.0 billion available for borrowing under the RCF.

See Note 11—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 .

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.

Capital expenditures .

Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure.

We categorize capital expenditures as one of the following:

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;

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

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

Capital expenditures in the consolidated statements of cash flows reflect capital expenditures on a cash basis, when payments are made.

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Year Ended December 31,

Expansion capital expenditures

Maintenance capital expenditures

Total capital expenditures (1) (2)

thousands 2020 2019 2018

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.

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.

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.

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.

(2) Capital expenditures for the year ended December 31, 2018, included $762.8 million of pre-acquisition capital expenditures for AMA.

(3) Capital incurred for the year ended December 31, 2018, included $733.1 million of pre-acquisition capital incurred for AMA.

Acquisitions during 2019 included AMA and the 30% interest in Red Bluff Express.

Acquisitions during 2018 included a 20% interest in Whitethorn LLC, a 15% interest in Cactus II, and equipment purchases from affiliates.

Acquisitions during 2017 included the Additional DBJV System Interest, the additional interest in Ranch Westex, and equipment purchases from affiliates.

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, decrease d by $759.8 million for the year ended December 31, 2019 .

Expansion capital expenditures decrease d by $763.4 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 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 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 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 partially offset by an increase of $88.1 million at the DJ Basin complex primarily due to continued construction of the Latham processing plant.

Maintenance capital expenditures increase d 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.

Capital expenditures, excluding acquisitions, increase d by $921.7 million for the year ended December 31, 2018 .

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

Maintenance capital expenditures increase d 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.

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.

Acquisitions during 2018 included a 20% interest in Whitethorn LLC, a 15% interest in Cactus II, and related-party asset contributions.

See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Capital expenditures decreased by $765.7 million for the year ended December 31, 2020, primarily due to decreases of (i) $362.5 million at the DJ Basin complex primarily related to the completion of Latham Trains I and II that commenced operations in November 2019 and February 2020, respectively, as well as decreases in pipeline, well connection, and compression projects, (ii) $186.8 million at the West Texas complex primarily attributable to the completion of Mentone Train II that commenced operations in March 2019 and decreases in pipeline and well connection projects, (iii) $107.5 million at the DBM oil system primarily related to the completion of the Loving ROTF Train III that commenced operations in January 2020 and decreases in pipeline and well connection projects, and (iv) $90.4 million at the DBM water systems primarily due to reduced construction of additional water-disposal facilities and gathering projects.

Capital expenditures decreased by $759.8 million for the year ended December 31, 2019, primarily due to decreases of (i) $427.1 million at the West Texas complex primarily due to the completion of Mentone Trains I and II that commenced operations in November 2018 and March 2019, respectively, (ii) $240.1 million at the DBM oil system primarily due to the completion of the ROTFs that commenced operations in the second quarter of 2018, and (iii) $194.8 million at the DBM water systems due to the completion of the water systems that commenced operations in the third and fourth quarters of 2018.

These decreases were offset partially by an increase of $91.3 million at the DJ Basin complex, primarily due to continued construction of the Latham processing plant.

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:

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

Year Ended December 31,

thousands 2020 2019 2018

Net cash provided by (used in):

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Operating activities .

Net cash provided by operating activities decrease d for the year ended December 31, 2019 , primarily due to cash payments made for the settlement of the 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.

Net cash provided by operating activities increased for the year ended December 31, 2020, primarily due to higher cash operating income, lower cash paid to settle interest-rate swap agreements, and higher distributions from equity-investment earnings.

These increases were offset partially by higher interest expense.

Net cash provided by operating activities decreased for the year ended December 31, 2019, primarily due to cash paid to settle interest-rate swap agreements, partially offset by increases in distributions from equity investments and the impact of other changes in working capital items.

Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods.

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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;

• $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;

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

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

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

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

$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;

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

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

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

Financing activities .

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

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

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

• $695.8 million of distributions paid to WES unitholders;

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

• $32.5 million of unit repurchases;

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

• $14.2 million of finance lease payments;

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

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

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

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

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

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

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

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

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

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

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

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• $3.4 million of issuance costs incurred in connection with the Term loan facility.

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

$370.0 million 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;

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

Debt and credit facilities.

As of December 31, 2019 , the carrying value of outstanding debt was $8.0 billion .

As of December 31, 2020, the carrying value of outstanding debt was $7.9 billion and we have estimated future interest and RCF fee payments totaling $376.9 million in 2021.

See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

WES Operating Senior Notes .

In January 2020, WES Operating issued the following notes:

• Fixed-Rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050, offered to the public at prices of 99.962%, 99.900%, and 99.442%, respectively, of the face amount.

Including the effects of the issuance prices, underwriting discounts, and interest-rate adjustments (described below), the effective interest rates of the Senior Notes due 2025, 2030, and 2050, were 4.291%, 5.173%, and 6.375%, respectively, at December 31, 2020.

These effective interest rates will increase by 0.25% on February 1, 2021, due to credit-rating downgrades.

Interest is paid on each such series semi-annually on February 1 and August 1 of each year, beginning August 1, 2020;

• Floating-Rate Senior Notes due 2023.

As of December 31, 2020, the interest rate on the Floating-Rate Senior Notes was 2.07%.

Interest is paid quarterly in arrears on January 13, April 13, July 13, and October 13 of each year.

Interest is determined at a benchmark rate (which is initially a three-month LIBOR rate) on the interest determination date plus an initial spread of 0.85%.

Net proceeds from the Fixed-Rate Senior Notes and Floating-Rate Senior Notes were used to repay the $3.0 billion in outstanding borrowings under the Term loan facility and outstanding amounts under the RCF, and for general partnership purposes.

The interest payable on each of the Fixed-Rate Senior Notes and Floating-Rate Senior Notes is subject to adjustment from time to time if the credit rating assigned to such notes declines below certain specified levels or if credit-rating downgrades are subsequently followed by credit-rating upgrades.

As a result of credit-rating downgrades received from Fitch, S&P, and Moody’s, annualized borrowing costs will increase by $43.0 million.

See General Trends and Outlook within this Item 7.

During the year ended December 31, 2020, WES Operating purchased and retired $218.0 million of certain of its senior notes and Floating-Rate Senior Notes via open-market repurchases, and gains of $13.5 million were recognized for the early retirement of these notes.

As of December 31, 2020, the 5.375% Senior Notes due 2021 were classified as short-term debt on the consolidated balance sheet.

Subsequent to December 31, 2020, WES Operating delivered notice to redeem the 5.375% Senior Notes due 2021 on March 1, 2021, as per the optional redemption terms in WES Operating’s indenture.

At December 31, 2020, WES Operating was in compliance with all covenants under the relevant governing indentures.

In Fe bruary 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 purpo ses, matured in March 2019 and the $28.0 million of outstanding borrowings were repaid.

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.

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

Revolving credit facility.

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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 Executive Summary– December 2019 Agreements within this Item 7 for more information.

As of December 31, 2019 , there were $380.0 million of outstanding borrowings and $4.6 million of outstanding letters of credit, resulting in $1.6 billion of available borrowing capacity under the RCF.

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.

As of December 31, 2020, there were no outstanding borrowings and $5.1 million of outstanding letters of credit, resulting in $2.0 billion of available borrowing capacity under the RCF.

At December 31, 2020, the interest rate on any outstanding RCF borrowings was 1.64% and the facility-fee rate was 0.25%.

At December 31, 2020, WES Operating was in compliance with all covenants under the RCF.

As a result of credit-rating downgrades, beginning in the second quarter of 2020, the interest rate on our outstanding RCF borrowings increased by 0.20% and the RCF facility-fee rate increased by 0.05%, from 0.20% to 0.25%.

See General Trends and Outlook within this Item 7.

The RCF contains certain covenants that limit, among other things, WES Operating’s ability, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate, or allow any material change in the character of its business, enter into certain related-party transactions and use proceeds other than for partnership purposes.

The RCF also contains various customary covenants, certain events of default, and a maximum consolidated leverage ratio as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated EBITDA for the most-recent four-consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions.

As a result of certain covenants contained in the RCF, our capacity to borrow under the RCF may be limited.

See General Trends and Outlook within this Item 7.

Term loan facility.

In December 2018, WES Operating entered into the Term loan facility, the proceeds from which were used to fund substantially all of the cash portion of the consideration under the Merger Agreement and the payment of related transaction costs (see 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 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 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 events 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 Events in the Notes to Consolidated Financial Statements under Part II , Item 8 of this Form 10-K for additional information).

The RCF and Term loan facility contain 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 affiliate transactions and use 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 as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated Earnings Before Interest, Taxes, Depreciation, and Amortization for the most-recent four-consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions.

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 Executive Summary– December 2019 Agreements within this Item 7 for more information.

In December 2018, WES Operating entered into the Term loan facility, the proceeds from which were used to fund substantially all of the cash portion of the consideration under the Merger Agreement and the payment of related transaction costs (see Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

In January 2020, WES Operating repaid the outstanding borrowings with proceeds from the issuance of the Fixed-Rate Senior Notes and Floating-Rate Senior Notes and terminated the Term loan facility.

During the first quarter of 2020, a loss of $2.3 million was recognized for the early termination of the Term loan facility.

See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Finance lease liabilities.

WES subleased equipment from Occidental via finance leases that extended through April 2020.

During the first quarter of 2020, WES entered into finance leases with third parties for equipment and vehicles extending through 2029.

As of December 31, 2020, we have future finance-lease payments of $8.6 million in 2021 and a total of $28.1 million in years thereafter.

See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

APCWH Note Payable.

In June 2017, in connection with funding the construction of the APC water systems that were acquired as part of the AMA acquisition, APCWH entered into an eight-year note payable agreement with Anadarko.

This note payable had a maximum borrowing limit of $500.0 million , including accrued interest, 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.

The APCWH Note Payable was repaid at Merger completion (see Executive Summary— Merger transactions within this Item 7 ).

This note payable had a maximum borrowing limit of $500.0 million, including accrued interest.

The APCWH Note Payable was repaid at Merger completion.

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

Interest-rate swaps.

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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, 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.

In November and December 2019, WES Operating entered into additional interest-rate swap agreements with an aggregate notional principal amount of $1,125.0 million, effectively offsetting the swap agreements entered into in December 2018 and March 2019.

In December 2019, all outstanding interest-rate swap agreements were settled.

As part of the settlement, WES Operating made cash payments of $107.7 million and recorded an accrued liability of $25.6 million to be paid quarterly in 2020.

These cash payments were classified as cash flows from operating activities in the consolidated statement of cash flows.

For the year ended December 31, 2020, WES Operating made cash payments of $25.6 million.

These cash payments were classified as cash flows from operating activities in the consolidated statements of cash flows.

We did not apply hedge accounting and, therefore, gains and losses associated with the interest-rate swap agreements were recognized in earnings.

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.

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.

See Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Asset retirement obligations.

When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in properties, plant, and equipment.

Revisions in estimated asset retirement obligations may result from changes in estimated asset retirement costs, inflation rates, discount rates, and the estimated timing of settlement.

As of December 31, 2020, we expect to incur asset retirement costs of $20.2 million in 2021 and a total of $260.3 million in years thereafter.

For additional information, see Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Operating leases.

We have entered into operating leases that extend through 2039 for corporate offices, shared field offices, easements, and equipment supporting our operations, with both Occidental and third parties as lessors.

As of December 31, 2020, we have future operating-lease payments of $4.0 million in 2021 and a total of $46.5 million in years thereafter.

See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Pipeline commitments.

In December 2020, we entered into a five-year transportation contract, which became effective on January 1, 2021, with a volume commitment on the Red Bluff Express pipeline.

As of December 31, 2020, we have estimated future minimum-volume-commitment fees of $3.7 million in 2021 and a total of $14.8 million in years thereafter.

Credit risk .

We bear credit risk through exposure to non-payment or non-performance by our counterparties, including Occidental, financial institutions, customers, and other parties.

Generally, non-payment or non-performance results from a customer’s inability to satisfy payables to us for services rendered or volumes owed pursuant to gas imbalance agreements.

We examine and monitor the creditworthiness of third-party customers and may establish credit limits for third-party customers.

A substantial portion of our throughput, however, comes from producers, including Occidental, that have investment-grade ratings.

We are subject to the risk of non-payment or late payment by Occidental for gathering, processing, transportation, and disposal fees and for proceeds from the sale of residue, NGLs, and condensate to Occidental.

We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain dependent on Occidental for over 50% of our revenues.

Additionally, we are exposed to credit risk on the note receivable from Anadarko.

Generally, non-payment or non-performance results from a customer’s inability to satisfy payables to us for services rendered, minimum-volume-commitment deficiency payments owed, or volumes owed pursuant to gas-imbalance agreements.

We examine and monitor the creditworthiness of customers and may establish credit limits for customers.

A substantial portion of our throughput is sourced from producers, including Occidental, that recently received credit-rating downgrades.

We are subject to the risk of non-payment or late payment by producers for gathering, processing, transportation, and disposal fees.

Through December 31, 2020, we were also dependent on Occidental to remit payments to us for the value of volumes of residue gas, NGLs, crude oil, and condensate that it purchased from us under our commodity purchase and sale agreements.

Additionally, we continue to evaluate counterparty credit risk and, in certain circumstances, are exercising our rights to request adequate assurance.

We expect our exposure to the concentrated risk of non-payment or non-performance to continue for as long as our commercial relationships with Occidental generate a significant portion of our revenues.

While Occidental is our contracting counterparty, gathering and processing arrangements with affiliates of Occidental on most of our systems include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market.

We also are party to agreements with Occidental under which Occidental is required to indemnify us for certain environmental claims, losses arising from rights-of-way claims, failures to obtain required consents or governmental permits, and income taxes with respect to the assets previously acquired from Anadarko.

See Note 6—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part II , Item 8 of this Form 10-K .

Our ability to make 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-gas and NGLs purchase agreements;

Anadarko’s note payable to WES Operating;

See Note 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Our ability to make cash distributions to our unitholders may be adversely impacted if Occidental becomes unable to perform under the terms of gathering, processing, transportation, and disposal agreements;

commodity purchase and sale agreements;

the contribution agreements;

or the December 2019 Agreements (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 ).

or the December 2019 Agreements.

ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING

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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:

Reconciliation of net income (loss).

The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows:

Year Ended December 31,

thousands 2020 2019 2018

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

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.

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.

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 in the Notes to Consolidated Financial Statements under Part II , Item 8 of this Form 10-K .

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 2020 2019 2018

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 capital

7,556 2,383 (854)

Other income (expense), net

(17) (79) (192)

Interest expense

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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 repurchases 32,535 — —

WGP RCF costs

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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.

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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.

Difference attributable to elimination upon consolidation of WES Operating’s distributions on partnership interests owned by WES.

(3) Difference attributable to elimination in consolidation of WES Operating’s distributions on partnership interests owned by WES.

See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K .

Noncontrolling interest.

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

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

WES Operating distributions.

WES Operating distributes all of its available cash (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.

WES Operating distributes all of its available cash (beyond proper reserves as defined in its partnership agreement) to WES Operating unitholders of record on the applicable record date within 45 days following each quarter’s end.

Immediately prior to the Merger closing, the WES Operating IDRs and general partner units were converted into WES Operating common units and a non-economic general partner interest in WES Operating, and at Merger completion, all WES Operating common units held by the public and subsidiaries of Anadarko (other than common units held by WES, WES Operating GP, and 6.4 million common units held by a subsidiary of Anadarko) were converted into WES common units.

Beginning first quarter of 2019, WES Operating makes cash distributions to WES and WGRAH, a subsidiary of Occidental, in respect of 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.

Beginning with the first quarter of 2019, WES Operating has made quarterly cash distributions to WES and WGRAH, a subsidiary of Occidental, in proportion to their share of limited partner interests in WES Operating.

For each quarter ended March 31, 2020, June 30, 2020, and September 30, 2020, WES Operating distributed $143.4 million to its limited partners.

For the quarter ended December 31, 2020, WES Operating distributed $127.5 million to its limited partners.

See Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K .

WES Operating LTIP.

Concurrent with the Merger closing, we assumed the Western Gas Partners, LP 2017 Long-Term Incentive Plan.

See Note 6—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

Asset retirement obligations

Capital expenditures

Credit facility fees

Environmental obligations

Operating leases

Asset retirement obligations.

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.

Capital expenditures.

Included in this amount are capital obligations related to our expansion projects.

We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual obligations made in advance of the actual expenditures.

See Note 15—Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Credit facility fees.

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

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.

See Note 6—Related-Party Transactions 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, 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.

See 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.

The preparation of consolidated financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and the amounts of revenues and expenses recognized during the periods reported.

On an ongoing basis, management reviews its estimates, including those related to property, plant, and equipment, other intangible assets, goodwill, equity investments, asset retirement obligations, litigation, environmental liabilities, income taxes, revenues, and fair values.

Although these estimates are based on management’s best available knowledge of current and expected future events, changes in facts and circumstances, or discovery of new information may result in revised estimates, and actual results may differ from these estimates.

M anagement 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 in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Impairments of tangible assets.

Property, plant, and equipment generally is stated at the lower of historical cost less accumulated depreciation or fair value if impaired.

Because prior acquisitions of assets from Anadarko were transfers of net assets between entities under common control, the assets acquired initially were recorded at Anadarko’s historic carrying value.

Management considers the following to be its most critical accounting estimates that involve judgment and discusses the selection and development of these estimates with our general partner’s Audit Committee.

For additional information concerning accounting policies, see Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Service revenues – fee based.

Certain of our midstream services contracts have minimum-volume commitment demand fees and fees that require periodic rate redeterminations based on the related facility cost of service.

These fees include fixed and variable consideration that are recognized on a consistent per-unit rate over the term of the contract.

Annual adjustments are made to the cost-of-service rates charged to customers, and a cumulative catch-up revenue adjustment related to services already provided to the minimum volumes under the contract may be recorded in future periods, with revenues for the remaining term of the contract recognized on a consistent per-unit rate based on the total expected variable consideration under the contract.

The cost-of-service rates are calculated using a contractually specified rate of return and estimates including long-term assumptions for capital invested, receipt volumes, and operating and maintenance expenses.

If management determines it is probable that a significant reversal in the cumulative catch-up revenue adjustment could occur, the variable consideration may be constrained up to the amount of the probable significant reversal.

During the year ended December 31, 2020, revenue was constrained under one of our gas-gathering and oil-gathering contracts due to uncertainty related to ongoing legal proceedings and commercial negotiations with the counterparties to the contracts.

Future revenue reversals could occur to the extent the outcome of the legal proceedings and commercial negotiations differ from our current assumptions.

See Revenue and cost of product in Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Contract balances in Note 2—Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Impairments of property, plant, and equipment and other intangible assets.

Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired.

Because prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control, the assets acquired were initially recorded at Anadarko’s historic carrying value.

Assets acquired in a business combination or non-monetary exchange with a third party are initially recorded at fair value.

Property, plant, and equipment balances are evaluated for potential impairment when events or changes in circumstances indicate that their carrying amounts may not be recoverable from expected undiscounted cash flows from the use and eventual disposition of an asset.

If the 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 changes in our business and economic conditions and their implications for 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.

Significant downward revisions in production forecasts or changes in future development plans by producers, to the extent they affect our operations, may necessitate assessment of the carrying amount of the affected assets for recoverability.

Management assesses property, plant, and equipment, together with any associated materials and supplies inventory and intangible assets, for impairment when events or changes in circumstances indicate their carrying values may not be recoverable.

Changes in our business and economic conditions are evaluated for their implications on recoverability of the assets’ carrying values.

Significant downward revisions in production forecasts or changes in future development plans by producers, to the extent they affect our operations, may necessitate an impairment assessment.

Impairments exist when the carrying value of a long-lived asset exceeds the total estimated undiscounted net cash flows from the future use and eventual disposition of the asset.

When alternative courses of action for future use of a long-lived asset are under consideration, estimates of future undiscounted net cash flows incorporate the possible outcomes and probabilities of their occurrence.

The primary assumptions used to estimate undiscounted future net cash flows include long-range customer production forecasts and revenue, capital, and operating expense estimates.

The measure of impairments to be recognized, if any, depends upon management’s estimate of the asset’s fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available.

See Note 8—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for a description of impairments recorded during the years ended December 31, 2019 , 2018 , and 2017 .

Among other things, management estimates fair value (i) of long-lived assets for impairment testing, (ii) of reporting units for goodwill impairment testing when necessary, (iii) of assets and liabilities acquired in a business combination or exchanged in non-monetary transactions, (iv) for the initial measurement of asset retirement obligations, (v) for the initial measurement of environmental obligations assumed in a third-party acquisition, and (vi) of interest-rate swaps.

When 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 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 .

Management applies judgment in the grouping of assets for impairment assessment, determining whether there is an impairment indicator, and determinations about the future use of such assets.

If an impairment exists, an impairment loss is measured as the excess of the asset’s carrying value over its estimated fair value, such that the asset’s carrying value is adjusted down to its estimated fair value with an offsetting charge to impairment expense.

Management’s estimate of the asset’s fair value may be determined based on the estimates of future discounted net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available.

We recognized long-lived asset and other impairments of $203.9 million (which includes an other-than-temporary impairment expense of an equity investment), $6.3 million, and $230.6 million for the years ended December 31, 2020, 2019, and 2018, respectively.

See Note 9—Property, Plant, and Equipment and Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for a description of impairments recorded during the years ended December 31, 2020, 2019, and 2018.

Impairment of goodwill.

Goodwill is recorded when the purchase price of a business acquired exceeds the fair market value of the tangible and separately measurable intangible net assets.

Goodwill also includes the allocated historic carrying value of midstream goodwill attributed to assets previously acquired from Anadarko.

Our goodwill has been allocated to two reporting units:

(i) gathering and processing and (ii) transportation.

We evaluate goodwill for impairment at the reporting unit level annually, as of October 1, or more often as facts and circumstances warrant.

An initial qualitative assessment is performed to determine the likelihood of whether goodwill is impaired and if deemed necessary based on this assessment, a quantitative assessment is then performed.

If the quantitative assessment indicates that the carrying value of the reporting unit, including goodwill, exceeds its fair value, a goodwill impairment is recorded for the amount by which the reporting unit’s carrying value exceeds its fair value.

When qualitatively evaluating whether the fair value of a reporting unit is less than its carrying value, relevant events and circumstances are assessed, including significant changes in our unit price, significant declines in commodity prices, significant increases in operating and capital costs, impairments recognized, acquisitions and disposals of assets, changes in throughput and producer activity, and significant declines in trading multiples for our peers.

Quoted market prices for our reporting units are not available.

Management determines fair value using various valuation techniques, including market EBITDA multiples and discounted cash-flow analysis.

Management considers observable transactions in the market, and trading multiples for peers, to determine an appropriate multiple to apply against our projected EBITDA.

The EBITDA multiples are based on current and historic multiples for comparable midstream companies of similar size and business profit to WES.

The EBITDA projections require significant assumptions including, among others, future throughput volumes based on current expectations of producer activity and operating costs.

This approach may be supplemented by a discounted cash-flow analysis.

Key assumptions in this analysis include the use of an appropriate discount rate, terminal-year multiples, and estimated future cash flows, including estimates of throughput, capital expenditures, operating, and general and administrative costs.

Different assumptions regarding these key inputs could have a significant impact on fair value and the amount of recorded impairment, if any.

During the three months ended March 31, 2020, we performed an interim goodwill impairment test due to a significant decline in the trading price of our common units, triggered by the combined impacts from the global outbreak of COVID-19 and the oil-market disruption resulting from significantly lower global demand and corresponding oversupply of crude oil.

We primarily used the market approach and Level-3 inputs to estimate the fair value of our two reporting units.

The market approach was based on multiples of EBITDA and our projected future EBITDA.

The reasonableness of the market approach was tested against an income approach that was based on a discounted cash-flow analysis.

We also reviewed the reasonableness of the total fair value of both reporting units to the market capitalization as of March 31, 2020, and the reasonableness of an implied acquisition premium.

As a result of the interim impairment test, we recognized a goodwill impairment of $441.0 million during the first quarter of 2020, which reduced the carrying value of goodwill for the gathering and processing reporting unit to zero.

Goodwill allocated to the transportation reporting unit of $4.8 million as of March 31, 2020, was not impaired.

Impairment analyses for long-lived assets, goodwill, equity investments and the initial recognition of asset retirement obligations and environmental obligations use Level-3 inputs.

Management also estimates the fair value of assets and liabilities acquired in a third-party business combination or exchanged in non-monetary transactions, and interest-rate swaps.

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

RECENT ACCOUNTING DEVELOPMENTS

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 .

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.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis