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Item 7. Management’s Discussion and Analysis

2022-02-23 compared with 2021-02-26 · 366 added, 515 removed, 482 unchanged (65% of the section changed)

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

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

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

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

For ease of reference, we refer to the historical financial results of the Partnership’s assets prior to the acquisitions from Anadarko as being “our” historical financial results.

EXECUTIVE SUMMARY

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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.

To provide superior midstream service, we focus on ensuring the reliability and performance of our systems, creating sustainable cost efficiencies, enhancing our safety culture, and protecting the environment.

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

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Significant financial and operational events during the year ended December 31, 2021, included the following:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• WES Operating redeemed the total principal amount outstanding of $431.1 million of the 5.375% Senior Notes due 2021 at par value, pursuant to the optional redemption terms in WES Operating’s indenture.

• WES Operating purchased and retired $500.0 million of certain of its senior notes via a tender offer.

• We repurchased 8,707,869 common units on the open market for an aggregate purchase price of $167.2 million and 2,500,000 common units from Occidental for an aggregate purchase price of $50.2 million.

• Our fourth - quarter 2021 per - unit distribution of $0.32700 increased $0.004 from the third - quarter 2021 per - unit distribution of $0.32300.

• Natural - gas throughput attributable to WES totaled 4,148 MMcf/d for the year ended December 31, 2021, representing a 3% decrease compared to the year ended December 31, 2020.

• Crude - oil and NGLs throughput attributable to WES totaled 659 MBbls/d for the year ended December 31, 2021, representing a 6% decrease compared to the year ended December 31, 2020.

• Produced - water throughput attributable to WES totaled 703 MBbls/d for the year ended December 31, 2021, representing a 1% increase compared to the year ended December 31, 2020.

• 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.

• Gross margin was $2.0 billion for the year ended December 31, 2021, representing a 4% decrease compared to the year ended December 31, 2020.

See Key Performance Metrics within this Item 7.

• Adjusted gross margin for natural - gas assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $1.24 per Mcf for the year ended December 31, 2021, representing a 7% increase compared to the year ended December 31, 2020.

• Adjusted gross margin for crude - oil and NGLs assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $2.28 per Bbl for the year ended December 31, 2021, representing a 10% decrease compared to the year ended December 31, 2020.

• Adjusted gross margin for produced - water assets (as defined under the caption Key Performance Metrics within this Item 7) averaged $0.93 per Bbl for the year ended December 31, 2021, representing a 5% decrease compared to the year ended December 31, 2020.

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

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(Dec) 2019 Inc/

(Dec) 2020 2019 Inc/

Crude oil & NGLs

Produced water

Throughput for natural-gas assets (MMcf/d)

Delaware Basin 1,256 1,297 (3) % 1,226 6 %

DJ Basin 1,369 1,305 5 % 1,236 6 %

Equity investments 463 445 4 % 398 12 %

Other 1,215 1,386 (12) % 1,563 (11) %

Total throughput for natural - gas assets

4,303 4,433 (3) % 4,423 — %

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

Delaware Basin 183 189 (3) % 150 26 %

DJ Basin 90 101 (11) % 118 (14) %

Equity investments 366 381 (4) % 343 11 %

Other 33 41 (20) % 52 (21) %

Total throughput for crude - oil and NGLs assets

672 712 (6) % 663 7 %

Total throughput

Throughput for produced-water assets (MBbls/d)

Delaware Basin 717 712 1 % 556 28 %

Total throughput for produced - water assets

717 712 1 % 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

Our historical results of operations and cash flows for the periods presented may not be comparable to future or historic results of operations or cash flows for the reasons described below.

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

Commodity purchase and sale agreements .

Effective April 1, 2020, changes to marketing-contract terms with AESC terminated AESC’s prior status as an agent of the Partnership for third-party sales and established AESC as a customer of the Partnership.

Accordingly, we no longer recognize service revenues and/or product sales revenues and the equivalent cost of product expense for the marketing services performed by AESC.

Year-over-year variances for the year ended December 31, 2020, include the following impacts related to this change (i) decrease of $130.9 million in Service revenues – fee based, (ii) decrease of $29.7 million in Product sales, and (iii) decrease of $160.6 million in Cost of product expense.

These changes had no impact to Operating income (loss), Net income (loss), the balance sheets, cash flows, or any non-GAAP metric used to evaluate our operations (see How We Evaluate Our Operations within this Item 7).

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

Gathering and processing agreements.

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

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

Acquisitions and divestitures.

In February 2019, WES Operating acquired AMA from Anadarko.

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

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

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

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

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

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

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

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

General and administrative expenses.

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

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

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

Noncontrolling interests.

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

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

Commodity-price swap agreements .

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

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

Income taxes.

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

For periods subsequent to asset acquisitions from Anadarko, we are not subject to tax except for the Texas margin tax and, accordingly, do not record current and deferred federal income taxes related to such assets.

OUR OPERATIONS

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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 example, for the year ended December 31, 2021, our West Texas and DJ Basin assets provided (i) 47% and 35%, respectively, of Total revenues and other, (ii) 33% and 36%, respectively, each of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 60% and 29%, 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, 2021, 57% of Total revenues and other, 36% of our throughput for natural-gas assets (excluding equity-investment throughput), 89% 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.

In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payment, and/or cost-of-service commitments under certain of our contracts.

For the year ended December 31, 2021, 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.

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Quantitative and Qualitative Disclosures About Market Risk under Part II of this Form 10-K.

As a result of previous acquisitions from Anadarko and third parties, our results of operations, financial position, and cash flows may vary significantly in future periods.

See Items Affecting the Comparability of Our Financial Results within this Item 7.

HOW WE EVALUATE OUR OPERATIONS

Our management relies on certain financial and operational metrics to analyze our performance.

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

Adjusted gross margin, Adjusted EBITDA, and Free cash flow (see in Key Performance Metrics within this Item 7).

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

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Operating and maintenance expenses include, among other things, field labor, insurance, repair and maintenance, equipment rentals, fleet management, contract services, utility costs, and services provided to us or on our behalf.

For periods commencing on the date of and subsequent to the acquisition of assets from Anadarko, certain of these expenses are incurred under our services and secondment agreement with Occidental, which was amended and restated on December 31, 2019.

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

General and administrative expenses .

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

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

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

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

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

Safety performance .

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

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

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

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

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

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

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

System availability .

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

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

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

Non-GAAP financial measures

Adjusted gross margin.

We define Adjusted gross margin attributable to Western Midstream Partners, LP (“Adjusted gross margin”) as total revenues and other (less reimbursements for electricity-related expenses recorded as revenue), less cost of product, plus distributions from equity investments, and excluding the noncontrolling interests owners’ proportionate share of revenues and cost of product.

We believe Adjusted gross margin is an important performance measure of our operations’ profitability and performance as compared to other companies in the midstream industry.

Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds, percent-of-product, and keep-whole contracts, (ii) costs associated with the valuation of gas imbalances, and (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties.

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

See Key Performance Metrics within this Item 7.

Adjusted EBITDA.

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

We believe the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures, and make distributions.

Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks, and rating agencies, use, among other measures, to assess the following:

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

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

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

Free cash flow.

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

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

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

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

Reconciliation of non-GAAP financial measures.

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

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

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

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

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

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

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

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

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

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

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

Year Ended December 31,

thousands 2020 2019 2018

Reconciliation of Operating income (loss) to Adjusted gross margin

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

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

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

$ 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

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(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

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

Distributions from equity investments 278,797 264,828 216,977

Non-cash equity-based compensation expense 22,462 14,392 7,310

Interest expense 380,058 303,286 183,831

Income tax expense 10,278 13,472 58,934

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

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

Reconciliation of Net cash provided by operating activities to Adjusted EBITDA

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

Interest (income) expense, net 368,322 286,386 166,931

Uncontributed cash-based compensation awards — (1,102) 879

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

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

Other (income) expense, net (3)

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

Cash paid to settle interest-rate 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:

Accounts receivable, net 193,688 45,033 60,502

Accounts and imbalance payables and accrued liabilities, net

(144,437) 30,866 (45,605)

Other items, net (24,822) (54,876) 38,087

Adjusted EBITDA attributable to noncontrolling interests (2)

(50,607) (45,131) (42,843)

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

Cash flow information

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

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

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

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(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.

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

Year Ended December 31,

thousands 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 below-described key trends and uncertainties.

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

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

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

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

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

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

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

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

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

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

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

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.

Historically, we have accessed the debt and equity capital markets to raise money for growth projects and acquisitions.

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

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

Changes in regulations.

Our operations and the operations of our customers have been, and will continue to be, affected by political developments and federal, state, tribal, local, and other laws and regulations that are becoming more numerous, more stringent, and more complex.

These laws and regulations include, among other things, limitations on hydraulic fracturing and other oil and gas operations, pipeline safety and integrity requirements, permitting requirements, environmental protection measures such as limitations on methane and other GHG emissions, and restrictions on produced-water disposal wells.

In addition, in certain areas in which we operate, public protests of oil and gas operations are becoming more frequent.

The number and scope of the regulations with which we and our customers must comply has a meaningful impact on our and their businesses, and new or revised regulations, reinterpretations of existing regulations, and permitting delays or denials could adversely affect the throughput on and profitability of our assets.

Impact of inflation.

Although inflation in the United States has been relatively low in recent years, the U.S.

economy could experience significant inflation, which could increase our operating costs and capital expenditures materially and negatively impact our financial results.

To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees.

Impact of interest rates.

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

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

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

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

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

Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest-rate environment could have an adverse impact on our unit price and our ability to issue additional equity, or increase the cost of issuing equity, to make acquisitions, reduce debt, or for other purposes.

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

Effects of credit-rating downgrade.

Our costs of borrowing and ability to access the capital markets are affected by market conditions and the credit ratings assigned to WES Operating’s debt by the major credit rating agencies.

In 2020, Fitch Ratings (“Fitch”) and Standard and Poor’s (“S&P”) downgraded WES Operating’s long-term debt from “BBB-” to “BB” and Moody’s Investors Service (“Moody’s”) downgraded WES Operating’s long-term debt from “Ba1” to “Ba2.” As a result of these downgrades, WES Operating’s credit rating is below investment grade for all three major credit rating agencies, which results in the following:

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

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

• We may be obligated to provide financial assurance of our performance under certain contractual arrangements requiring us to post collateral in the form of letters of credit or cash.

At December 31, 2020, we had $ 5.1 million in letters of credit or cash-provided assurance of our performance outstanding under contractual arrangements with credit-risk-related contingent features.

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

Per-unit distribution and capital guidance.

During 2020, we announced per-unit distribution and cost reductions that are expected to continue into 2021.

These cash-preservation measures are intended to enhance our liquidity for the duration of the COVID-19 macroeconomic disruption and the weakened commodity-price environment;

however, the duration and severity of this pandemic and concomitant economic downturn remains uncertain.

There can be no assurance that these announced actions will provide sufficient liquidity for the required duration, and additional actions, including additional per-unit distribution reductions, may be necessary to manage through the current environment.

On February 23, 2021, we provided 2021 guidance as follows:

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

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

Acquisition opportunities.

We may pursue certain asset acquisitions where such acquisitions complement our existing asset base or allow us to capture operational efficiencies.

However, if we do not make additional acquisitions on an economically accretive basis, our future growth could be limited, and the acquisitions we make could reduce, rather than increase, our per-unit cash flows from operations.

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

Our historical results of operations and cash flows for the periods presented may not be comparable to future or historic results of operations or cash flows for the reasons described below.

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

Commodity purchase and sale agreements .

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, 2021, include the following impacts related to this change (i) decrease of $45.9 million in Service revenues – fee based, (ii) decrease of $21.2 million in Product sales, and (iii) decrease of $67.1 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 Key Performance Metrics 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.

Annual adjustments are made to cost-of-service rates charged under these agreements, and for certain of them, a cumulative catch-up revenue adjustment related to services already provided may be recorded.

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.

Weather-related impacts.

In February 2021, the U.S.

experienced winter storm Uri, bringing extreme cold temperatures, ice, and snow to the central U.S., including Texas, and in March 2021, Colorado experienced a historic blizzard.

Winter storm Uri adversely affected our volumes for approximately ten days and the blizzard in Colorado likewise disrupted our assets in that state.

We estimate the impact of these weather events reduced our net income and Adjusted EBITDA (as defined under the caption Key Performance Metrics within this Item 2) for the year ended December 31, 2021, by approximately $30 million due to lower volumes, the impact of commodity prices, and higher operating expenses related to utilities.

We recognized long-lived asset and other impairments of $30.5 million, $203.9 million, and $6.3 million for the years ended December 31, 2021, 2020, and 2019, respectively.

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, beginning in 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.

Acquisitions and divestitures.

During the second quarter of 2021, the third party exercised its option to purchase the Bison treating facility and the sale closed.

We received total proceeds of $8.0 million, $7.0 million in the fourth quarter of 2020 and $1.0 million when the sale closed in the second quarter of 2021, resulting in a net gain on sale of $5.4 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.

In February 2019, WES Operating acquired AMA from Anadarko.

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

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

RESULTS OF OPERATIONS

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$ 916,292 $ 527,012 $ 697,241

Key performance metrics (3)

Adjusted gross margin $ 2,718,205 $ 2,428,077 $ 1,978,205

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

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.

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

Total operating expenses includes amounts charged by related parties for services received.

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

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

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

For reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, see How We Evaluate Our Operations—Reconciliation of non-GAAP financial measures within this Item 7.

For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2021” refer to the comparison of the year ended December 31, 2021, to the year ended December 31, 2020, and any increases or decreases “for the year ended December 31, 2020” refer to the comparison of the year ended December 31, 2020, to the year ended December 31, 2019.

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Gathering, treating, and transportation 306 331 (8) % 320 3 %

331 320 3 % 295 8 %

Equity investments (3)

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Total throughput 672 712 (6) % 663 7 %

712 663 7 % 536 24 %

Throughput attributable to noncontrolling interests (2)

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Gathering and disposal 717 712 1 % 556 28 %

712 556 28 % 239 133 %

Throughput attributable to noncontrolling interests (2)

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_________________________________________________________________________________________

(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.

(1) Represents the 14.81% share of average Fort Union throughput (until divested in October 2020), 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.

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Natural-gas assets

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

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

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

Gathering, treating, and transportation throughput decreased by 77 MMcf/d for the year ended December 31, 2021, primarily due to (i) decreased volumes at the Bison treating facility, which was sold to a third party during the second quarter of 2021 and (ii) production declines and the impact of winter storm Uri at the Springfield gas - gathering system.

These decreases were offset partially by increased production in areas around the Marcellus Interest systems.

Processing throughput decreased by 71 MMcf/d for the year ended December 31, 2021, primarily due to (i) lower production and the impact of winter storm Uri at the West Texas complex, (ii) the Granger straddle plant being held idle beginning in the third quarter of 2020, and (iii) lower volumes at the Granger and Brasada complexes due to production declines in the areas.

These decreases were offset partially by higher volumes at the DJ Basin complex primarily due to an additional third-party connection to Latham Train II beginning January 1, 2021.

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 18 MMcf/d for the year ended December 31, 2021, primarily due to increased volumes on Red Bluff Express and at the Mi Vida plant, partially offset by (i) decreased volumes at the Rendezvous system due to production declines in the area and (ii) decreased volumes at the Fort Union system, which was sold to a third party during the fourth quarter of 2020.

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 decreased by 25 MBbls/d for the year ended December 31, 2021, primarily due to (i) lower volumes at the DJ Basin and Springfield oil systems resulting from production declines in the areas and (ii) lower volumes at the DBM oil system due to lower production and the impact of winter storm Uri.

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 decreased by 15 MBbls/d for the year ended December 31, 2021, primarily due to decreased volumes on the Whitethorn pipeline, partially offset by increased volumes on the Saddlehorn pipeline.

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 5 MBbls/d for the year ended December 31, 2021, due to increased volumes at the DBM water systems resulting from (i) higher production in the area, primarily during the second half of 2021, and (ii) new third-party connections brought online during the fourth quarter of 2021.

These increases were offset partially by the impact of winter storm Uri.

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

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Service revenues – fee based $ 2,462,835 $ 2,584,323 (5) % $ 2,388,191 8 %

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

Service revenues – product based 122,584 48,369 153 % 70,127 (31) %

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

Total service revenues $ 2,585,419 $ 2,632,692 (2) % $ 2,458,318 7 %

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

Service revenues – fee based

Service revenues – fee based decreased by $121.5 million for the year ended December 31, 2021, primarily due to decreases of (i) $45.9 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), (ii) $36.4 million at the DBM oil system due to decreased throughput, including the impact of winter storm Uri, and lower lease revenue under the operating and maintenance agreement with Occidental, (iii) $23.4 million at the DJ Basin oil system due to an annual cost-of-service rate adjustment made during the fourth quarter of 2021 and decreased throughput, partially offset by a higher average gathering fee, (iv) $19.0 million at the DJ Basin complex due to decreased throughput on certain fee-based contracts, (v) $17.0 million at the Bison treating facility due to the expiration of a minimum-volume-commitment contract in the fourth quarter of 2020, decreased throughput, and the sale of the facility to a third party during the second quarter of 2021, and (vi) $14.3 million at the DBM water systems due to a lower average fee resulting from a cost - of - service rate redetermination effective January 1, 2021, partially offset by increased throughput.

These decreases were offset partially by increases of (i) $26.6 million at the West Texas complex due to a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, partially offset by decreased throughput, including the impact of winter storm Uri, and (ii) $13.1 million at the Springfield system due to cumulative catch-up adjustments for a change in estimated consideration made in 2021 and a higher cost - of - service rate effective January 1, 2021.

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 increased by $74.2 million for the year ended December 31, 2021, primarily due to increases of (i) $22.2 million at the West Texas complex due to an increase in electricity - related fees charged to customers during winter storm Uri, (ii) $20.5 million at the DJ Basin complex due to increased third - party volumes and average prices, and (iii) $8.9 million at the Granger complex, $8.5 million at the Hilight system, $6.9 million at the Chipeta complex, and $5.3 million at the MGR assets due to increased prices.

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

Year Ended December 31,

thousands except percentages and

per-unit amounts

2020 2019 Inc/

thousands except percentages and per-unit amounts 2021 2020 Inc/

(Dec) 2019 Inc/

Natural - gas sales

$ 83,102 $ 30,527 172 % $ 66,557 (54) %

NGLs sales 207,845 108,032 92 % 219,831 (51) %

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Natural-gas sales

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

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

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

Natural - gas sales increased by $52.6 million for the year ended December 31, 2021, primarily due to increases of (i) $49.0 million at the West Texas complex attributable to an increase in average prices, (ii) $9.6 million at the MGR assets attributable to an increase in average prices, partially offset by a decrease in volumes sold, and (iii) $1.8 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).

These increases were offset partially by decreases of $5.6 million at the DJ Basin complex and $4.9 million at the Granger complex attributable to decreases in volumes sold, partially offset by increases in average prices.

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, 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).

NGLs sales increased by $99.8 million for the year ended December 31, 2021, primarily due to increases of (i) $73.8 million at the West Texas complex attributable to an increase in average prices, partially offset by a decrease in volumes sold, (ii) $22.3 million at the Chipeta complex and $11.3 million at the Granger complex attributable to increases in average prices, and (iii) $6.5 million at the DJ Basin complex attributable to an increase in average prices and volumes sold.

These increases were offset partially by a decrease of $23.0 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).

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

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Equity income, net – related parties $ 204,645 $ 226,750 (10) % $ 237,518 (5) %

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.

Equity income, net – related parties decreased by $22.1 million for the year ended December 31, 2021, primarily due to decreases of (i) $30.8 million at Whitethorn LLC related to commercial activities and lower volumes, (ii) $4.7 million at White Cliffs due to lower volumes, and (iii) $4.0 million at Cactus II due to an increase in depreciation expense recorded in 2021.

These decreases were offset partially by increases of (i) $8.1 million at Mont Belvieu JV primarily from a load-reduction electricity credit received in the second quarter of 2021 related to winter storm Uri and (ii) $5.3 million and $4.6 million at Red Bluff Express and Saddlehorn, respectively, resulting from increased volumes.

Equity income, net – related parties decreased by $10.8 million for the year ended December 31, 2020, primarily due to decreases of (i) $38.8 million from Whitethorn LLC related to commercial activities and decreased volumes and (ii) $4.2 million from decreased rates at White Cliffs.

These decreases were offset partially by increases of (i) $11.4 million 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 (ii) $5.5 million at TEP, $5.3 million at Ranch Westex, $5.1 million at FRP, and $5.1 million at Red Bluff Express resulting from increased volumes.

Cost of Product and Operation and Maintenance Expenses

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(Dec) 2019 Inc/

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

Residue purchases $ 146,673 $ 65,193 125 % $ 100,570 (35) %

NGLs purchases 160,662 131,964 22 % 331,872 (60) %

Other 14,950 (9,069) NM 11,805 (177) %

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_________________________________________________________________________________________

NM — Not meaningful

NGLs purchases

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

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

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

Residue purchases

Residue purchases increased by $81.5 million for the year ended December 31, 2021, primarily due to increases of (i) $58.6 million at the West Texas complex, $6.7 million at the Chipeta complex, and $6.3 million at the Hilight system attributable to increases in average prices and (ii) $9.2 million at the MGR assets attributable to an increase in average prices, partially offset by a decrease in volumes purchased.

These increases were offset partially by a decrease of $5.2 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).

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.

NGLs purchases

NGLs purchases increased by $28.7 million for the year ended December 31, 2021, primarily due to increases of (i) $40.4 million at the West Texas complex, $13.7 million at the Chipeta complex, and $8.2 million at the Granger complex attributable to increases in average prices, (ii) $21.5 million at the DJ Basin complex attributable to an increase in average prices and volumes purchased, and (iii) $4.1 million at the Brasada complex attributable to an increase in average prices, partially offset by a decrease in volumes purchased.

These increases were offset partially by a decrease of $61.1 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).

Other items increased by $24.0 million for the year ended December 31, 2021, primarily due to increases of $29.1 million at the West Texas complex and $5.1 million at the Chipeta complex, primarily due to changes in imbalance positions, partially offset by a decrease of $11.7 million at the DJ Basin complex due to changes in imbalance positions.

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 increased by $0.4 million for the year ended December 31, 2021, primarily due to an increase of $7.6 million at the West Texas complex, mainly attributable to increased field-related expenses, as well as an increase in utilities expense resulting from the impact of winter storm Uri, partially offset by a decrease of $6.6 million at the Springfield system primarily due to decreased environmental and regulatory expenses.

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

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General and administrative $ 195,549 $ 155,769 26 % $ 114,591 36 %

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

Property and other taxes 64,267 68,340 (6) % 61,352 11 %

Depreciation and amortization 551,629 491,086 12 % 483,255 2 %

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

Goodwill impairment

441,017 — NM — NM

Long - lived asset and other impairments

30,543 203,889 (85) % 6,279 NM

Goodwill impairment — 441,017 (100) % — NM

Total other operating expenses $ 841,988 $ 1,360,101 (38) % $ 665,477 104 %

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

_________________________________________________________________________________________

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

General and administrative expenses

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

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

General and administrative expenses increased by $39.8 million for the year ended December 31, 2021, primarily due to increases of (i) $23.7 million in personnel costs, including increased bonus-related contributions under our employee savings plan and equity-based compensation expense, and (ii) $16.9 million in contract and consulting costs primarily related to information technology services and fees.

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.

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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.

For the year ended December 31, 2019, 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.

Property and other taxes

Property and other taxes decreased by $4.1 million for the year ended December 31, 2021, primarily due to ad valorem tax decreases at the West Texas complex due to realized tax savings during 2021, partially offset by ad valorem tax increases in the DJ Basin due to higher tax rates.

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 increased by $60.5 million for the year ended December 31, 2021, primarily due to increases of (i) $33.6 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 in the comparative prior period, (ii) $13.2 million at the Hilight system due to revisions in cost estimates related to asset retirement obligations, (iii) $8.2 million related to depreciation for capitalized information technology implementation costs related to the stand-up of WES as an independent organization, (iv) $7.3 million at the MGR assets due to an acceleration of depreciation expense, as well as revisions in cost estimates related to asset retirement obligations, and (v) $7.2 million at the West Texas complex resulting from capital projects being placed into service.

These increases were offset partially by a decrease of $17.4 million due to the sale of the Bison treating facility in the second quarter of 2021.

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.

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

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

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

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

Long-lived asset and other impairment expense

Long - lived asset and other impairment expense for the year ended December 31, 2021, was primarily due to (i) $14.2 million of impairments at the DJ Basin complex due to cancellation of projects and (ii) an $11.8 million other-than-temporary impairment of our investment in Ranch Westex.

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.

For further information on Long - lived asset and other impairment expense, 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

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Interest income – Anadarko note receivable $ — $ 11,736 (100) % $ 16,900 (31) %

$ 11,736 $ 16,900 (31) % $ 16,900 — %

Third parties

Long - term and short - term debt

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

Amortization of debt issuance costs and commitment fees

$ (366,570) $ (369,815) (1) % $ (315,872) 17 %

Finance lease liabilities (861) (1,510) (43) % — NM

Commitment fees and amortization of debt-related costs (12,705) (13,501) (6) % (12,424) 9 %

Capitalized interest 3,624 4,774 (24) % 26,980 (82) %

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APCWH Note Payable — — — % (1,833) (100) %

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

Finance lease liabilities — (6) (100) % (137) (96) %

Interest expense $ (376,512) $ (380,058) (1) % $ (303,286) 25 %

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.

Interest income - Anadarko note receivable decreased by $11.7 million and $5.2 million for the years ended December 31, 2021 and 2020, respectively, due to the exchange of the Anadarko note receivable under the Unit Redemption Agreement in September 2020.

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 decreased by $3.5 million for the year ended December 31, 2021, primarily due to decreases of (i) $21.2 million due to the redemption of the total principal amount outstanding of the 5.375% Senior Notes due 2021 on March 1, 2021, (ii) $5.7 million due to lower outstanding balances on the 4.000% Senior Notes due 2022, Floating Rate Notes due 2023, 3.950% Senior Notes due 2025, and 4.650% Senior Notes due 2026, portions of which were repaid during the third quarter of 2021, and (iii) $3.6 million due to lower outstanding borrowings under the RCF in 2021.

These decreases were offset partially by (i) an increase of $26.4 million in additional interest incurred from higher effective interest rates resulting from credit - rating downgrades on the 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050 and (ii) a decrease of $1.2 million in capitalized interest due to decreased capital expenditures.

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.

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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

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(Dec) 2019 Inc/

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

Other income (expense), net $ (623) $ 1,025 (161) % $ (123,785) (101) %

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)

3 unchanged sentences

Income (loss) before income taxes $ 934,192 $ 522,850 79 % $ 821,172 (36) %

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

Effective tax rate 1 % 2 % 9 %

Income tax expense (benefit) (9,807) 5,998 NM 13,472 (55) %

Effective tax rate NM 1 % 2 %

We are not a taxable entity for U.S.

4 unchanged sentences

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.

For the year ended December 31, 2021, the variance from the federal statutory rate was primarily impacted by a state margin rate reduction associated with Occidental’s settlement of state audit matters and our Texas margin tax liability.

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

KEY PERFORMANCE METRICS

Year Ended December 31,

thousands except percentages and per-unit amounts

2020 2019 Inc/

thousands except percentages and per-unit amounts 2021 2020 Inc/

(Dec) 2019 Inc/

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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.

We define Adjusted gross margin attributable to Western Midstream Partners, LP (“Adjusted gross margin”) as total revenues and other (less reimbursements for electricity - related expenses recorded as revenue), less cost of product, plus distributions from equity investments, and excluding the noncontrolling interest owners’ proportionate share of revenues and cost of product.

We believe Adjusted gross margin is an important performance measure of our operations’ profitability and performance as compared to other companies in the midstream industry.

Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent - of - proceeds, percent - of - product, and keep - whole contracts, (ii) costs associated with the valuation of gas and NGLs 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.

The electricity-related expenses included in our Adjusted gross margin definition relate to pass-through expenses that are reimbursed by certain customers (recorded as revenue with an offset recorded as Operation and maintenance expense).

Adjusted gross margin decreased by $50.7 million for the year ended December 31, 2021, primarily due to (i) decreased throughput and lower lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system, (ii) a decrease in distributions from Whitethorn LLC and Cactus II, (iii) decreased throughput and an annual cost-of-service rate adjustment made during the fourth quarter of 2021 at the DJ Basin oil 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), (iv) the expiration of a minimum-volume-commitment contract in the fourth quarter of 2020 and decreased throughput at the Bison treating facility, which was sold to a third party during the second quarter of 2021, (v) a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the DBM water systems, and (vi) decreased throughput on certain fee-based contracts at the DJ Basin complex.

These decreases were offset partially by (i) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the West Texas complex, (ii) cumulative catch-up adjustments for a change in estimated consideration made in 2021 and a higher cost - of - service rate effective January 1, 2021, at the Springfield system, and (iii) an increase in distributions from Red Bluff Express and Ranch Westex.

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 $0.08 for the year ended December 31, 2021, primarily due to (i) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2021, at the West Texas complex and (ii) a higher cost - of - service rate effective January 1, 2021, at the Springfield system.

These increases were offset partially by decreased throughput on certain fee-based contracts at the DJ Basin 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 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 decreased by $0.26 for the year ended December 31, 2021, primarily due to (i) an annual cost-of-service rate adjustment made during the fourth quarter of 2021 at the DJ Basin oil system and (ii) decreased throughput and lower lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system, which has a higher - than - average per - Bbl margin as compared to our other crude - oil and NGLs assets.

These decreases were offset partially by a higher cost - of - service rate effective January 1, 2021, at the Springfield system.

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.

Per - Bbl Adjusted gross margin for produced - water assets decreased by $0.05 for the year ended December 31, 2021, primarily due to a lower average fee resulting from a cost - of - service rate redetermination effective January 1, 2021.

Adjusted EBITDA.

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

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

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

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

Adjusted EBITDA decreased by $83.7 million for the year ended December 31, 2021, primarily due to (i) a $134.1 million increase in cost of product (net of lower of cost or market inventory adjustments), (ii) a $34.6 million increase in general and administrative expenses excluding non - cash equity - based compensation expense, and (iii) a $23.9 million decrease in distributions from equity investments.

These amounts were offset partially by (i) a $104.6 million increase in total revenues and other and (ii) a $4.1 million decrease in property taxes.

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.

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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.

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

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.

Free cash flow increased by $263.5 million for the year ended December 31, 2021, primarily due to (i) an increase of $129.4 million in net cash provided by operating activities, (ii) a decrease of $109.9 million in capital expenditures, (iii) a decrease of $15.0 million in contributions to equity investments, and (iv) a $9.2 million increase in distributions from equity investments in excess of cumulative earnings.

Free cash flow increased by $1,189.9 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.

Reconciliation of non-GAAP financial measures.

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

The GAAP measure used by us that is most directly comparable to Adjusted gross margin is gross margin.

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

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

Our non - GAAP financial measures of Adjusted gross margin, Adjusted EBITDA, and Free cash flow should not be considered as alternatives to the GAAP measures of gross margin, 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 gross margin, 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.

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) gross margin, net income (loss), and net cash provided by operating activities, and incorporating this knowledge into its decision - making processes.

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

The following tables present (i) a reconciliation of the GAAP financial measure of gross margin 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 2021 2020 2019

Reconciliation of Gross margin to Adjusted gross margin

Total revenues and other $ 2,877,155 $ 2,772,592 $ 2,746,174

Cost of product 322,285 188,088 444,247

Depreciation and amortization 551,629 491,086 483,255

Gross margin 2,003,241 2,093,418 1,818,672

Distributions from equity investments 254,901 278,797 264,828

Depreciation and amortization 551,629 491,086 483,255

Reimbursed electricity-related charges recorded as revenues 74,405 79,261 74,629

Adjusted gross margin attributable to noncontrolling interests (1)

67,850 65,835 64,049

Adjusted gross margin $ 2,667,516 $ 2,718,205 $ 2,428,077

Adjusted gross margin for natural - gas assets

$ 1,882,726 $ 1,820,926 $ 1,656,041

Adjusted gross margin for crude - oil and NGLs assets

547,134 647,390 578,100

Adjusted gross margin for produced - water assets

237,656 249,889 193,936

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

Year Ended December 31,

thousands 2021 2020 2019

Reconciliation of Net income (loss) to Adjusted EBITDA

Net income (loss) $ 943,999 $ 516,852 $ 807,700

Distributions from equity investments 254,901 278,797 264,828

Non - cash equity - based compensation expense

27,676 22,462 14,392

Interest expense 376,512 380,058 303,286

Income tax expense 4,403 10,278 13,472

Depreciation and amortization 551,629 491,086 483,255

Impairments (1)

30,543 644,906 6,279

Other expense 1,468 1,953 161,813

Gain (loss) on divestiture and other, net 44 8,634 (1,406)

Gain (loss) on early extinguishment of debt (24,944) 11,234 —

Equity income, net – related parties 204,645 226,750 237,518

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

Other income 585 2,785 37,792

Income tax benefit 14,210 4,280 —

Adjusted EBITDA attributable to noncontrolling interests (2)

49,901 50,607 45,131

Adjusted EBITDA $ 1,946,690 $ 2,030,366 $ 1,719,090

Reconciliation of Net cash provided by operating activities to Adjusted EBITDA

Net cash provided by operating activities $ 1,766,852 $ 1,637,418 $ 1,324,100

Interest (income) expense, net 376,512 368,322 286,386

Uncontributed cash-based compensation awards — — (1,102)

Accretion and amortization of long - term obligations, net

(7,635) (8,654) (8,441)

Current income tax expense (benefit) (37) 2,702 5,863

Other (income) expense, net (3)

623 (1,025) (1,549)

Cash paid to settle interest - rate swaps

— 25,621 107,685

Distributions from equity investments in excess of cumulative earnings – related parties 41,385 32,160 30,256

Changes in assets and liabilities:

Accounts receivable, net (16,366) 193,688 45,033

Accounts and imbalance payables and accrued liabilities, net (114,887) (144,437) 30,866

Other items, net (49,856) (24,822) (54,876)

Adjusted EBITDA attributable to noncontrolling interests (2)

(49,901) (50,607) (45,131)

Adjusted EBITDA $ 1,946,690 $ 2,030,366 $ 1,719,090

Cash flow information

Net cash provided by operating activities $ 1,766,852 $ 1,637,418 $ 1,324,100

Net cash used in investing activities (257,538) (448,254) (3,387,853)

Net cash provided by (used in) financing activities (1,752,237) (844,204) 2,071,573

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(1) Includes goodwill impairment for the year ended December 31, 2020.

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

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

(3) Excludes net non-cash losses on interest-rate swaps of $25.6 million for the year ended December 31, 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.

Year Ended December 31,

thousands 2021 2020 2019

Reconciliation of Net cash provided by operating activities to Free cash flow

Net cash provided by operating activities $ 1,766,852 $ 1,637,418 $ 1,324,100

Capital expenditures 313,674 423,602 1,189,254

Contributions to equity investments – related parties 4,435 19,388 128,393

Distributions from equity investments in excess of cumulative earnings – related parties 41,385 32,160 30,256

Free cash flow $ 1,490,128 $ 1,226,588 $ 36,709

Cash flow information

Net cash provided by operating activities $ 1,766,852 $ 1,637,418 $ 1,324,100

Net cash used in investing activities (257,538) (448,254) (3,387,853)

Net cash provided by (used in) financing activities (1,752,237) (844,204) 2,071,573

GENERAL TRENDS AND OUTLOOK

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

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

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

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

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

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

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

These market dynamics had an adverse impact on producers that provide throughput into our systems, and we experienced decreased throughput at many of our locations.

For example, NYMEX West Texas Intermediate crude - oil daily settlement prices during 2020 ranged from a high of $63.27 per barrel in January 2020 to a low below $20.00 per barrel in April 2020, and prices during 2021 ranged from a low of $47.62 per barrel in January 2021 to a high of $84.65 per barrel in October 2021.

Although commodity prices have rebounded to pre-pandemic levels, the extent and duration of the recent commodity - price volatility cannot be predicted, and 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 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) .

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

• As of December 31, 2021, it is reasonably possible that future commodity - price declines, prolonged depression of commodity prices, 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 intend to 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 intend to continue to evaluate the crude - oil, NGLs, and natural - gas price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility.

Liquidity and access to capital markets.

Historically, we have accessed the debt and equity capital markets to raise money to fund growth projects, acquisitions, and to refinance long-term debt.

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 strategy may become more challenging to execute.

Changes in regulations.

In addition, in certain areas in which we operate, public protests of oil and gas operations are becoming more frequent.

Impact of inflation and supply-chain disruptions.

Although inflation in the United States has been relatively low in recent years, the U.S.

economy currently is experiencing significant inflation relative to historical precedent, from, among other things, supply-chain disruptions caused by, or governmental stimulus or fiscal policies adopted in response to, the COVID-19 crisis.

More specifically, the bottlenecks and disruptions from the lingering effects of the COVID-19 crisis have caused difficulties within the U.S.

and global supply chains, creating logistical delays along with labor shortages.

A significant increase in inflation would raise our costs for labor, materials, and services, which could increase our operating costs and capital expenditures materially and negatively impact our financial results.

To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees.

Impact of interest rates.

Overall, short- and long-term interest rates increased during 2021, but remained low relative to historical averages.

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.

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

Acquisition opportunities.

We may pursue certain asset acquisitions where such acquisitions complement our existing asset base or allow us to capture operational efficiencies.

However, if we do not make additional acquisitions on an economically accretive basis, our future growth could be limited.

LIQUIDITY AND CAPITAL RESOURCES

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

Our primary cash uses include quarterly distributions, debt service, customary operating expenses, and capital expenditures.

Our sources of liquidity as of December 31, 2021, included cash and cash equivalents, cash flows generated from operations, available borrowing capacity under the RCF, and potential issuances of additional equity or debt securities.

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

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

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

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

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

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

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

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

See General Trends and Outlook within this Item 7.

We have made cash distributions to our unitholders each quarter since our initial public offering in 2012.

The Board declared a cash distribution to unitholders for the fourth quarter of 2021 of $0.32700 per unit, or $134.7 million in the aggregate.

The cash distribution was paid on February 14, 2022, to our unitholders of record at the close of business on January 31, 2022.

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

During the year ended December 31, 2021, we repurchased 8,707,869 common units on the open market for an aggregate purchase price of $167.2 million and 2,500,000 common units from Occidental for an aggregate purchase price of $50.2 million, fulfilling the entire $250.0 million authorized program.

The units were canceled immediately upon receipt.

In February 2022, we announced a buyback program of up to $1.0 billion of our common units through December 31, 2024.

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 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 our 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.

For the year ended December 31, 2022, we estimate that our total capital expenditures will be between $375.0 million to $475.0 million (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta).

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

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Working capital .

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

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

Working capital requirements are driven by changes in accounts receivable and accounts payable and other factors such as credit extended to, and the timing of collections from, our customers, and the level and timing of our spending for acquisitions, maintenance, and capital activities.

As of December 31, 2021, we had a $455.4 million working capital deficit, which we define as the amount by which current liabilities exceed current assets.

Our working capital deficit was primarily due to the 4.000% Senior Notes due 2022 of $502.1 million being classified as short-term debt on the consolidated balance sheet as of December 31, 2021.

As of December 31, 2021, there was $2.0 billion available for borrowing under the RCF.

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

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

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

Capital expenditures includes maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets;

and expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels.

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

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(1) For the years ended December 31, 2021, 2020, and 2019 included $3.6 million, $4.8 million, and $23.3 million, respectively, of capitalized interest.

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

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

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

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

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

Capital expenditures decreased by $109.9 million for the year ended December 31, 2021, primarily due to decreases of (i) $43.9 million at the DJ Basin complex primarily related to the completion of Latham Train II that commenced operations in the first quarter of 2020, and decreases in pipeline, well connection, and compression projects, (ii) $22.6 million at the West Texas complex primarily attributable to decreases in facility expansion, (iii) $15.7 million at the DBM oil system primarily related to the completion of the Loving ROTF Trains III and IV that commenced operations during the first and third quarters of 2020, respectively, and decreases in pipeline and well connection projects, (iv) $10.0 million at the DBM water systems primarily due to reduced construction of additional water - disposal facilities and gathering projects, and (v) $4.8 million at the DJ Basin oil system primarily related to decreases in pipeline projects.

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 .

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Operating activities .

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

Net cash provided by operating activities increased for the year ended December 31, 2021, primarily due to (i) the impact of changes in assets and liabilities, (ii) cash paid during the year ended December 31, 2020, to settle interest-rate swaps, and (iii) lower interest expense.

These increases were offset partially by (i) lower cash operating income, (ii) lower distributions from equity-investment earnings, and (iii) lower interest income.

Net cash provided by operating activities increased for the year ended December 31, 2020, primarily due to (i) higher cash operating income, (ii) lower cash paid to settle interest-rate swap agreements, and (iii) 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, 2021, 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;

• $313.7 million of capital expenditures, primarily related to construction, expansion, and asset - integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, and DBM oil system;

• $4.4 million of capital contributions primarily paid to Cactus II;

• $41.4 million of distributions received from equity investments in excess of cumulative earnings;

• $11.1 million of decreases to materials and supplies inventory;

• $8.0 million related to the sale of the Bison treating facility.

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

• $423.6 million of capital expenditures, primarily related to construction and expansion at the West Texas and DJ Basin complexes, DBM water systems, and DBM oil system;

• $57.8 million of increases to materials and supplies inventory;

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

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

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

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

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

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

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

Financing activities .

Net cash used in financing activities for the year ended December 31, 2021, included the following:

• $533.8 million of distributions paid to WES unitholders;

• $521.9 million to purchase and retire portions of certain of WES Operating’s senior notes via a tender offer;

• $480.0 million of repayments of outstanding borrowings under the RCF;

• $431.1 million to redeem the total principal amount outstanding of WES Operating’s 5.375% Senior Notes due 2021;

• $217.5 million of unit repurchases;

• $21.6 million of decreases in outstanding checks due mostly to ad valorem tax payments made at the end of 2020;

• $15.0 million of distributions paid to the noncontrolling interest owner of WES Operating;

• $9.1 million of distributions paid to the noncontrolling interest owner of Chipeta;

• $6.5 million of finance lease payments;

• $480.0 million of borrowings under the RCF, which were used for general partnership purposes and to purchase and retire portions of certain of WES Operating’s senior notes via a tender offer;

• $8.5 million of contributions from related parties.

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;

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• $32.5 million of unit repurchases;

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

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

• $14.2 million of finance lease payments;

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• $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;

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

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

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

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

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

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

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

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

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

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

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

• $502.5 million of distributions paid to WES unitholders;

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

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

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

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

Debt and credit facilities.

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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.

In mid - January 2020, WES Operating issued the Fixed - Rate 3.100% Senior Notes due 2025, 4.050% Senior Notes due 2030, and 5.250% Senior Notes due 2050 and the Floating - Rate Senior Notes due 2023.

Including the effects of the issuance prices, underwriting discounts, and interest - rate adjustments, the effective interest rates of the Senior Notes due 2025, 2030, and 2050, were 4.542%, 5.424%, and 6.629%, respectively, at December 31, 2021.

The interest rate on the Floating - Rate Senior Notes was 1.97% at December 31, 2021.

The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating.

In August 2021 and December 2021, Standard and Poor’s (“S&P”) and Fitch Ratings, respectively, upgraded WES Operating’s long-term debt from “BB” to “BB+.” In January 2022, S&P upgraded WES Operating’s long-term debt from “BB+” to “BBB-.” As a result of these upgrades, annualized borrowing costs will decrease by $23.6 million.

During the third quarter of 2021, WES Operating purchased and retired $500.0 million of certain of its senior notes via a tender offer.

During the first quarter of 2021, WES Operating redeemed the total principal amount outstanding of the 5.375% Senior Notes due 2021 at par value, pursuant to the optional redemption terms in WES Operating’s indenture.

During the year ended December 31, 2021, losses of $24.9 million were recognized for the retirement of these notes.

As of December 31, 2021, the 4.000% Senior Notes due 2022 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, 2021, WES Operating was in compliance with all covenants under the relevant governing indentures.

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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.

The RCF is expandable to a maximum of $2.5 billion and bears interest at LIBOR, plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based on WES Operating’s senior unsecured debt rating.

A required quarterly facility fee is paid ranging from 0.125% to 0.250% of the commitment amount (whether drawn or undrawn), which also is based on the senior unsecured debt rating.

In December 2019, WES Operating entered into an amendment to the RCF to, among other things, exercise the final one-year extension option to extend the maturity date of the RCF from February 2024 to February 2025, for each extending lender.

The maturity date with respect to each non-extending lender, whose commitments represent $100.0 million out of $2.0 billion of total commitments from all lenders, remains February 2024.

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

WES Operating’s $2.0 billion senior unsecured revolving credit facility is expandable to a maximum of $2.5 billion, and matures in February 2025 for each extending lender.

The non - extending lender’s commitments mature in February 2024 and represent $100.0 million out of $2.0 billion of total commitments from all lenders.

As of December 31, 2021, 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.

As of December 31, 2021, the interest rate on any outstanding RCF borrowings was 1.60% and the facility - fee rate was 0.25%.

The RCF bears interest at LIBOR, plus applicable margins ranging from 1.00% to 1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in each case plus applicable margins currently ranging from zero to 0.50%, based on WES Operating’s senior unsecured debt rating.

A required quarterly facility fee is paid ranging from 0.125% to 0.250% of the commitment amount (whether drawn or undrawn), which also is based on the senior unsecured debt rating.

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.

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

See General Trends and Outlook within this Item 7.

Term loan facility.

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

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

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

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

At December 31, 2021, WES Operating was in compliance with all covenants under the RCF.

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.

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

Certain of these equipment leases were amended during the third quarter of 2021 requiring reassessment of lease classification.

As a result, these leases were classified as operating leases.

As of December 31, 2021, we have future finance-lease payments of $3.9 million in 2022 and a total of $1.6 million in years thereafter.

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

APCWH Note Payable.

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

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

The APCWH Note Payable was repaid at Merger completion.

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

Interest-rate swaps.

In December 2018 and March 2019, WES Operating entered into interest-rate swap agreements with an aggregate notional principal amount of $750.0 million and $375.0 million, respectively, to manage interest-rate risk associated with anticipated debt issuances.

Pursuant to these swap agreements, WES Operating received a floating interest rate indexed to the three-month LIBOR and paid a fixed interest rate.

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

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

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

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

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

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

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

Asset retirement obligations.

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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.

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

As of December 31, 2021, we have future operating-lease payments of $10.7 million in 2022 and a total of $44.9 million in years thereafter.

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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.

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

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

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

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

commodity purchase and sale agreements;

the contribution agreements;

or the December 2019 Agreements.

or the Services Agreement.

ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING

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Net income (loss) attributable to WES $ 916,292 $ 527,012 $ 697,241

$ 527,012 $ 697,241 $ 551,571

Limited partner interests in WES Operating not held by WES (1)

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Other income (expense), net (11) (17) (79)

(17) (79) (192)

Income taxes 9 — —

Interest expense — — 245

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_________________________________________________________________________________________

(1) Represents the portion of net income (loss) allocated to the limited partner interests in WES Operating not held by WES.

The public held a 0% limited partner interest in WES Operating as of December 31, 2020 and 2019, and a 59.2% limited partner interest in WES Operating as of December 31, 2018.

A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating as of December 31, 2020 and 2019, and a 9.7% limited partner interest in WES Operating as of December 31, 2018.

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

A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating as of December 31, 2021, 2020, and 2019.

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

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Changes in working capital (11,315) 7,556 2,383

7,556 2,383 (854)

Other income (expense), net (11) (17) (79)

(17) (79) (192)

Income taxes 9 — —

Interest expense — — 245

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Increase (decrease) in outstanding checks (68) (35) —

Registration expenses related to the issuance of WES common units — 855 —

Unit repurchases 217,465 32,535 —

WGP RCF costs

Registration expenses related to the issuance of WES common units — — 855

WGP RCF repayments — — 28,000

Other 4,336 — —

WES Operating net cash provided by (used in) financing activities $ (1,730,780) $ (871,982) $ 2,063,338

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Noncontrolling interest.

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

WES Operating’s noncontrolling interest consists of the 25% third - party interest in Chipeta.

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

WES Operating distributions.

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

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

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

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

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

WES Operating distributes all of its available cash on a quarterly basis to WES Operating unitholders in proportion to their share of limited partner interests in WES Operating.

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

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

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

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.

CRITICAL ACCOUNTING ESTIMATES

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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.

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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.

Impairments of equity investments.

Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method of accounting.

Management assesses its equity investments for impairment whenever events or changes in circumstances indicate their carrying amount may have experienced a decline in value that is other than temporary.

When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying amount of the investment to determine whether the investment has been impaired.

Management assesses the fair value of equity investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales and discounted cash flow models.

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

We recognized long-lived asset and other impairments of $30.5 million (which includes an other-than-temporary impairment expense of an equity investment), $203.9 million (which includes an other-than-temporary impairment expense of an equity investment), and $6.3 million for the years ended December 31, 2021, 2020, and 2019, 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, 2021, 2020, and 2019.

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.

Impairment analyses for long-lived assets, goodwill, equity investments, and the initial recognition of asset retirement 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.

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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