WESTERN MIDSTREAM PARTNERS, LP The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements, wherein WES Operating is fully consolidated, and which are included under Part II, Item 8 of this Form 10-K, and the information set forth in Risk Factors under Part I, Item 1A of this Form 10-K. The Partnership's assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as ofDecember 31, 2021 (see Note 7-Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K). We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental. EXECUTIVE SUMMARY We are a midstream energy company organized as a publicly traded partnership, engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering and disposing of produced water. In our capacity as a natural-gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and as an agent for our customers under certain contracts. 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 inTexas ,New Mexico , theRocky Mountains (Colorado ,Utah , andWyoming ), and North-centralPennsylvania . As ofDecember 31, 2021 , our assets and investments consisted of the following: Wholly Owned and Operated Non-Operated Equity Operated Interests Interests Interests Gathering systems (1) 17 2 3 1 Treating facilities 37 3 - - Natural-gas processing plants/trains 24 3 - 5 NGLs pipelines 2 - - 5 Natural-gas pipelines 5 - - 1 Crude-oil pipelines 3 1 - 4
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(1)Includes the DBM water systems.
Significant financial and operational events during the year ended
•WES Operating redeemed the total principal amount outstanding of
•WES Operating purchased and retired
•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
•Natural-gas throughput attributable to WES totaled 4,148 MMcf/d for the year endedDecember 31, 2021 , representing a 3% decrease compared to the year endedDecember 31, 2020 . •Crude-oil and NGLs throughput attributable to WES totaled 659 MBbls/d for the year endedDecember 31, 2021 , representing a 6% decrease compared to the year endedDecember 31, 2020 . 64
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•Produced-water throughput attributable to WES totaled 703 MBbls/d for the year endedDecember 31, 2021 , representing a 1% increase compared to the year endedDecember 31, 2020 .
•Gross margin was
•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 endedDecember 31, 2021 , representing a 7% increase compared to the year endedDecember 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 endedDecember 31, 2021 , representing a 10% decrease compared to the year endedDecember 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 endedDecember 31, 2021 , representing a 5% decrease compared to the year endedDecember 31, 2020 . The following table provides additional information on throughput for the periods presented below: Year Ended December 31, Inc/ Inc/ 2021 2020 (Dec) 2019 (Dec) 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 % 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 %
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OUR OPERATIONS
Our results primarily are driven by the volumes of natural gas, NGLs, crude oil,
and produced water we service through our systems. In our operations, we
contract with customers to provide midstream services focused on natural gas,
NGLs, crude oil, and produced water. We gather natural gas from individual wells
or production facilities located near our gathering systems and the natural gas
may be compressed and delivered to a processing plant, treating facility, or
downstream pipeline, and ultimately to end users. We treat and process a
significant portion of the natural gas that we gather so that it will satisfy
required specifications for pipeline transportation. We gather crude oil from
individual wells or production facilities located near our gathering systems,
and in some cases, treat or stabilize the crude oil to satisfy required
specifications for pipeline transportation. We also gather and dispose of
produced water.
We operate in Texas , New Mexico , Colorado , Utah , Wyoming , and North-central
Pennsylvania , with a substantial portion of our business concentrated in West
Texas and the Rocky Mountains . For example, for the year ended December 31,
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, 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. This type of
contract provides us with a relatively stable revenue stream that is not subject
to direct commodity-price risk, except to the extent that (i) we retain and sell
drip condensate that is recovered during the gathering of natural gas from the
wellhead or production facilities or (ii) actual recoveries differ from
contractual recoveries under a limited number of processing agreements.
We also have indirect exposure to commodity-price risk in that the relatively
volatile commodity-price environment has caused and may continue to cause
current or potential customers to delay drilling or shut-in production in
certain areas, which would reduce the volumes of hydrocarbons available to our
systems. We also bear limited commodity-price risk through the settlement of
imbalances. Read Item 7A. Quantitative and Qualitative Disclosures About Market
Risk under Part II of this Form 10-K.
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HOW WE EVALUATE OUR OPERATIONS
Our management relies on certain financial and operational metrics to analyze
our performance. These metrics are significant factors in assessing our
operating results and profitability and include (i) throughput, (ii) operating
and maintenance expenses, (iii) general and administrative expenses, and (iv)
the following non-GAAP financial measures: Adjusted gross margin, Adjusted
EBITDA, and Free cash flow (see in Key Performance Metrics within this Item 7).
Throughput. Throughput is a significant operating variable that we use to assess
our ability to generate revenues. To maintain or increase throughput on our
systems, we must connect to additional wells or production facilities. Our
success in maintaining or increasing throughput is impacted by the successful
drilling of new wells by producers that are dedicated to our systems,
recompletions of existing wells connected to our systems, our ability to secure
volumes from new wells drilled on non-dedicated acreage, and our ability to
attract natural-gas, crude-oil, NGLs, or produced-water volumes currently
serviced by our competitors.
Operating and maintenance expenses. We monitor operating and maintenance
expenses to assess the impact of these costs on asset profitability and to
evaluate the overall efficiency of our operations. Operating and maintenance
expenses include, among other things, field labor, insurance, repair and
maintenance, equipment rentals, fleet management, contract services, utility
costs, and services provided to us or on our behalf.
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.
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, 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. 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 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. 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. 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.
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Weather-related impacts. InFebruary 2021 , theU.S. experienced winter storm Uri, bringing extreme cold temperatures, ice, and snow to the centralU.S. , includingTexas , and inMarch 2021 ,Colorado experienced a historic blizzard. Winter storm Uri adversely affected our volumes for approximately ten days and the blizzard inColorado 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 endedDecember 31, 2021 , by approximately$30 million due to lower volumes, the impact of commodity prices, and higher operating expenses related to utilities. Impairments. We recognized long-lived asset and other impairments of$30.5 million ,$203.9 million , and$6.3 million for the years endedDecember 31, 2021 , 2020, and 2019, respectively. During the year endedDecember 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. OnDecember 31, 2019 , we entered into theDecember 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. 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 ofAnadarko as part of the consideration paid for prior acquisitions fromAnadarko , and (iv) the Class C units issued by WES Operating to a subsidiary ofAnadarko as part of the funding for the acquisition of DBM. Acquisitions and divestitures. InOctober 2020 , we (i) sold our 14.81% interest inFort Union , which was accounted for under the equity method of accounting, and (ii) entered into an option agreement to sell the Bison treating facility, located inNortheast Wyoming , to a third party. 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. InFebruary 2019 , WES Operating acquired AMA fromAnadarko . InJanuary 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. 68
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RESULTS OF OPERATIONS
OPERATING RESULTS
The following tables and discussion present a summary of our results of
operations:
Year Ended December 31,
thousands 2021 2020 2019
Total revenues and other (1) $
2,877,155
204,645 226,750 237,518
Total operating expenses (1) 1,745,573 2,129,063 1,750,943
Gain (loss) on divestiture and other, net 44 8,634 (1,406)
Operating income (loss) 1,336,271 878,913 1,231,343
Interest income - Anadarko note receivable - 11,736 16,900
Interest expense (376,512) (380,058) (303,286)
Gain (loss) on early extinguishment of debt (24,944) 11,234 -
Other income (expense), net (623) 1,025 (123,785)
Income (loss) before income taxes 934,192 522,850 821,172
Income tax expense (benefit) (9,807) 5,998 13,472
Net income (loss) 943,999 516,852 807,700
Net income (loss) attributable to noncontrolling
interests 27,707 (10,160) 110,459
Net income (loss) attributable to
$
916,292
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(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. For purposes of the following discussion, any increases or decreases "for the year endedDecember 31, 2021 " refer to the comparison of the year endedDecember 31, 2021 , to the year endedDecember 31, 2020 , and any increases or decreases "for the year endedDecember 31, 2020 " refer to the comparison of the year endedDecember 31, 2020 , to the year endedDecember 31, 2019 . 69
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Throughput
Year Ended December 31,
Inc/ Inc/
2021 2020 (Dec) 2019 (Dec)
Throughput for natural-gas assets (MMcf/d)
Gathering, treating, and transportation 466 543 (14) % 528 3 %
Processing 3,374 3,445 (2) % 3,497 (1) %
Equity investments (1) 463 445 4 % 398 12 %
Total throughput 4,303 4,433 (3) % 4,423 - %
Throughput attributable to noncontrolling
interests (2) 155 159 (3) % 175 (9) %
Total throughput attributable to WES for
natural-gas assets 4,148 4,274 (3) % 4,248 1 % Throughput for crude-oil and NGLs assets (MBbls/d) Gathering, treating, and transportation
306 331 (8) % 320 3 %
Equity investments (3) 366 381 (4) % 343 11 %
Total throughput 672 712 (6) % 663 7 %
Throughput attributable to noncontrolling
interests (2) 13 14 (7) % 13 8%
Total throughput attributable to WES for crude-oil and NGLs assets 659 698 (6) % 650 7 % Throughput for produced-water assets (MBbls/d) Gathering and disposal 717 712 1 % 556 28 % Throughput attributable to noncontrolling interests (2) 14 14 - % 11 27 % Total throughput attributable to WES for produced-water assets 703 698 1 % 545 28 %
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(1)Represents the 14.81% share of averageFort Union throughput (until divested inOctober 2020 ), 22% share of average Rendezvous throughput, 50% share of averageMi Vida and Ranch Westex throughput, and 30% share of averageRed Bluff Express throughput. (2)For all periods presented, includes (i) the 2.0% Occidental subsidiary-owned limited partner interest in WES Operating and (ii) for natural-gas assets, the 25% third-party interest in Chipeta, which collectively represent WES's noncontrolling interests. (3)Represents the 10% share of average White Cliffs throughput; 25% share of average Mont Belvieu JV throughput; 20% share of average TEG, TEP, Whitethorn, and Saddlehorn throughput; 33.33% share of average FRP throughput; and 15% share of averagePanola and Cactus II throughput.
Natural-gas assets
Gathering, treating, and transportation throughput decreased by 77 MMcf/d for the year endedDecember 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 theSpringfield gas-gathering system. These decreases were offset partially by increased production in areas around the Marcellus Interest systems. Gathering, treating, and transportation throughput increased by 15 MMcf/d for the year endedDecember 31, 2020 , primarily due to increased production in areas around the Marcellus Interest systems, partially offset by production declines in areas around the Bison treating facility andSpringfield gas-gathering system. Processing throughput decreased by 71 MMcf/d for the year endedDecember 31, 2021 , primarily due to (i) lower production and the impact of winter storm Uri at theWest 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 theDJ Basin complex primarily due to an additional third-party connection to Latham Train II beginningJanuary 1, 2021 . 70
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Processing throughput decreased by 52 MMcf/d for the year endedDecember 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 theWest Texas andDJ Basin complexes, (ii) the start-up of Latham Train II at theDJ Basin complex during the first quarter of 2020, and (iii) the start-up of Mentone Train II at theWest Texas complex inMarch 2019 . Equity-investment throughput increased by 18 MMcf/d for the year endedDecember 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 theFort 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 endedDecember 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 theFort 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.
Crude-oil and NGLs assets
Gathering, treating, and transportation throughput decreased by 25 MBbls/d for the year endedDecember 31, 2021 , primarily due to (i) lower volumes at theDJ Basin andSpringfield 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 endedDecember 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 theDJ Basin oil system due to production declines in the area. Equity-investment throughput decreased by 15 MBbls/d for the year endedDecember 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 endedDecember 31, 2020 , primarily due to (i) the acquisition of our interest in Cactus II inJune 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.
Produced-water assets
Gathering and disposal throughput increased by 5 MBbls/d for the year endedDecember 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 endedDecember 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. 71
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Service Revenues
Year Ended December 31,
Inc/ Inc/
thousands except percentages 2021 2020 (Dec) 2019 (Dec)
Service revenues - fee based $ 2,462,835 $
2,584,323 (5) %
122,584 48,369 153 % 70,127 (31) %
Total service revenues $ 2,585,419 $ 2,632,692 (2) % $ 2,458,318 7 %
Service revenues - fee based
Service revenues - fee based decreased by$121.5 million for the year endedDecember 31, 2021 , primarily due to decreases of (i)$45.9 million , resulting from a change in accounting for the marketing contracts with AESC effectiveApril 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 theDJ 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 theDJ 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 effectiveJanuary 1, 2021 , partially offset by increased throughput. These decreases were offset partially by increases of (i)$26.6 million at theWest Texas complex due to a higher average fee resulting from a cost-of-service rate redetermination effectiveJanuary 1, 2021 , partially offset by decreased throughput, including the impact of winter storm Uri, and (ii)$13.1 million at theSpringfield system due to cumulative catch-up adjustments for a change in estimated consideration made in 2021 and a higher cost-of-service rate effectiveJanuary 1, 2021 . Service revenues - fee based increased by$196.1 million for the year endedDecember 31, 2020 , primarily due to increases of (i)$98.1 million at theWest Texas complex and$97.9 million at theDJ 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 effectiveDecember 31, 2019 , (iii)$59.3 million at the DBM water systems from increased throughput, and (iv)$21.4 million at theSpringfield 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 effectiveApril 1, 2020 (see Items Affecting the Comparability of Our Financial Results-Commodity purchase and sale agreements within this Item 7).
Service revenues - product based
Service revenues - product based increased by$74.2 million for the year endedDecember 31, 2021 , primarily due to increases of (i)$22.2 million at theWest Texas complex due to an increase in electricity-related fees charged to customers during winter storm Uri, (ii)$20.5 million at theDJ 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 endedDecember 31, 2020 , primarily due to (i) decreased third-party volumes at theDJ Basin complex and MGR assets and (ii) decreased pricing across several systems. 72
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Product Sales
Year Ended December 31,
thousands except percentages and Inc/ Inc/
per-unit amounts 2021 2020 (Dec) 2019 (Dec)
Natural-gas sales $ 83,102 $ 30,527 172 % $ 66,557 (54) %
NGLs sales 207,845 108,032 92 % 219,831 (51) %
Total Product sales $ 290,947 $ 138,559 110 % $ 286,388 (52) %
Per-unit gross average sales price:
Natural gas (per Mcf) $ 4.31 $ 1.45 197 % $ 1.65 (12) %
NGLs (per Bbl) 33.69 13.14 156 % 20.93 (37) %
Natural-gas sales
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
NGLs sales increased by$99.8 million for the year endedDecember 31, 2021 , primarily due to increases of (i)$73.8 million at theWest 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 theDJ 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 effectiveApril 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 endedDecember 31, 2020 , primarily due to decreases of (i)$34.0 million at theWest 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 effectiveApril 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 theDJ 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. 73
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Equity Income, Net - Related Parties
Year Ended December 31,
Inc/ Inc/
thousands except percentages 2021 2020 (Dec) 2019 (Dec)
Equity income, net - related parties $ 204,645 Equity income, net - related parties decreased by$22.1 million for the year endedDecember 31, 2021 , primarily due to decreases of (i)$30.8 million atWhitethorn 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 endedDecember 31, 2020 , primarily due to decreases of (i)$38.8 million fromWhitethorn 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 inJune 2018 , which began delivering crude oil during the third quarter of 2019, and (ii)$5.5 million at TEP,$5.3 million at RanchWestex ,$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
Year Ended December 31,
Inc/ Inc/
thousands except percentages 2021 2020 (Dec) 2019 (Dec)
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) %
Cost of product 322,285 188,088 71 % 444,247 (58) %
Operation and maintenance 581,300 580,874 - % 641,219 (9) %
Total Cost of product and Operation and
maintenance expenses $ 903,585 $ 768,962 18 % $ 1,085,466 (29) %
_________________________________________________________________________________________
NM-Not meaningful
Residue purchases
Residue purchases increased by$81.5 million for the year endedDecember 31, 2021 , primarily due to increases of (i)$58.6 million at theWest 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 effectiveApril 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 endedDecember 31, 2020 , primarily due to decreases of (i)$21.1 million resulting from a change in accounting for the marketing contracts with AESC effectiveApril 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 theDJ 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. 74
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NGLs purchases
NGLs purchases increased by$28.7 million for the year endedDecember 31, 2021 , primarily due to increases of (i)$40.4 million at theWest 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 theDJ 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 effectiveApril 1, 2020 (see Items Affecting the Comparability of Our Financial Results-Commodity purchase and sale agreements within this Item 7). NGLs purchases decreased by$199.9 million for the year endedDecember 31, 2020 , primarily due to decreases of (i)$139.5 million resulting from a change in accounting for the marketing contracts with AESC effectiveApril 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 theWest 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.
Other items
Other items increased by$24.0 million for the year endedDecember 31, 2021 , primarily due to increases of$29.1 million at theWest 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 theDJ Basin complex due to changes in imbalance positions. Other items decreased by$20.9 million for the year endedDecember 31, 2020 , primarily due to decreases of (i)$10.3 million at theWest Texas complex due to changes in imbalance positions and (ii)$10.0 million at theDJ Basin complex due to a decrease in transportation costs and changes in imbalance positions.
Operation and maintenance expense
Operation and maintenance expense increased by$0.4 million for the year endedDecember 31, 2021 , primarily due to an increase of$7.6 million at theWest 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 theSpringfield system primarily due to decreased environmental and regulatory expenses. Operation and maintenance expense decreased by$60.3 million for the year endedDecember 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 theWest 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 theSpringfield 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. 75
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Other Operating Expenses
Year Ended
Inc/ Inc/
thousands except percentages 2021 2020 (Dec) 2019 (Dec)
General and administrative $ 195,549 $ 155,769 26 % $ 114,591 36 %
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
30,543 203,889 (85) % 6,279 NM
Goodwill impairment - 441,017 (100) % - NM
Total other operating expenses $ 841,988 General and administrative expenses
General and administrative expenses increased by$39.8 million for the year endedDecember 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 endedDecember 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 ofDecember 31, 2019 . General and administrative expenses also increased by$6.0 million for the year endedDecember 31, 2020 , primarily due to increases in corporate expenses and professional fees. See Note 6-Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. For the year endedDecember 31, 2019 , General and administrative expenses were determined by rate estimation and allocated to us from Occidental pursuant to the omnibus agreements. Effective with theDecember 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 endedDecember 31, 2021 , primarily due to ad valorem tax decreases at theWest Texas complex due to realized tax savings during 2021, partially offset by ad valorem tax increases in theDJ Basin due to higher tax rates. Property and other taxes increased by$7.0 million for the year endedDecember 31, 2020 , primarily due to ad valorem tax increases of$6.5 million at theDJ Basin complex due to capital projects being placed into service, including the completion ofLatham Train I inNovember 2019 . This increase was offset partially by ad valorem tax decreases inUtah andWest Texas due to lower valuations and lower tax rates.
Depreciation and amortization expense
Depreciation and amortization expense increased by$60.5 million for the year endedDecember 31, 2021 , primarily due to increases of (i)$33.6 million at theDJ Basin complex, primarily as a result of a change in estimate for asset retirement obligations for theThird 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 theWest 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. 76
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Depreciation and amortization expense increased by$7.8 million for the year endedDecember 31, 2020 , primarily due to increases of (i)$11.9 million and$5.9 million at theWest 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 inWyoming due to revisions in cost estimates related to asset retirement obligations. These amounts were offset partially by decreases of (i)$10.6 million at theDJ Basin complex primarily as a result of a change in estimate for asset retirement obligations for theThird Creek gathering system of$32.7 million , offset by increased depreciation expense of$22.1 million for capital projects being placed into service, (ii)$10.3 million at the Hilight system primarily attributable to revisions in cost estimates related to asset retirement obligations and an acceleration of depreciation expense in the comparative prior period, and (iii)$5.3 million at the Chipeta complex primarily due to lower depreciation as a result of the impairment incurred during the first quarter of 2020. See Note 12-Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for more information regarding asset retirement obligations.
Long-lived asset and other impairment expense
Long-lived asset and other impairment expense for the year endedDecember 31, 2021 , was primarily due to (i)$14.2 million of impairments at theDJ 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 endedDecember 31, 2020 , was primarily due to (i)$150.2 million of impairments for assets located inWyoming andUtah , (ii) a$29.4 million other-than-temporary impairment of our investment in Ranch Westex, (iii) impairments of$16.7 million at theDJ 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 endedDecember 31, 2019 , was primarily due to impairments of$4.9 million at theDJ Basin complex due to impairments of rights-of-way and cancellation of projects. 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.
During the three months endedMarch 31, 2020 , an interim goodwill impairment test was performed due to significant unit-price declines triggered by the combined impacts from the global outbreak of COVID-19 and the oil-market disruption. As a result of the interim impairment test, a goodwill impairment of$441.0 million was recognized for the gathering and processing reporting unit. For additional information, see Note 10-Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 77
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Interest Income - Anadarko Note Receivable and Interest Expense
Year Ended December 31,
Inc/ Inc/
thousands except percentages 2021 2020 (Dec) 2019 (Dec)
Interest income - Anadarko note
receivable $ - $ 11,736 (100) % $ 16,900 (31) %
Third parties
Long-term and short-term debt $ (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) %
Related parties
APCWH Note Payable - - - % (1,833) (100) %
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 $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 endedDecember 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 onMarch 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 endedDecember 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 inJanuary 2020 and (ii) a decrease of$22.2 million in capitalized interest due to decreased capital expenditures. These increases were offset partially by decreases of (i)$75.0 million that occurred as a result of the repayment and termination of the Term loan facility inJanuary 2020 and (ii)$15.5 million due to lower outstanding borrowings under the RCF in 2020. See Liquidity and Capital Resources-Debt and credit facilities within this Item 7. 78
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Other Income (Expense), Net
Year Ended December 31,
Inc/ Inc/
thousands except percentages 2021 2020 (Dec) 2019 (Dec)
Other income (expense), net $ (623) $ 1,025 (161) % $ (123,785) (101) %
Other income (expense), net increased by
Income Tax Expense (Benefit)
Year Ended December 31,
Inc/ Inc/
thousands except percentages 2021 2020 (Dec) 2019 (Dec)
Income (loss) before income taxes $ 934,192 $ 522,850 79 % $ 821,172 (36) %
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. federal income tax purposes; therefore, our
federal statutory rate is zero percent. However, income apportionable to Texas
is subject to Texas margin tax. Income attributable to the AMA assets prior to
and including February 2019 was subject to federal and state income tax. Income
earned on the AMA assets for periods subsequent to February 2019 was subject
only to Texas margin tax on income apportionable to Texas .
For the year ended December 31, 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.
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KEY PERFORMANCE METRICS
Year Ended December 31,
thousands except percentages and per-unit Inc/ Inc/
amounts 2021 2020 (Dec) 2019 (Dec)
Adjusted gross margin for natural-gas
assets $ 1,882,726 $ 1,820,926 3 % $ 1,656,041 10 %
Adjusted gross margin for crude-oil and
NGLs assets 547,134 647,390 (15) % 578,100 12 %
Adjusted gross margin for produced-water
assets 237,656 249,889 (5) % 193,936 29 %
Adjusted gross margin 2,667,516 2,718,205 (2) % 2,428,077 12 %
Per-Mcf Adjusted gross margin for
natural-gas assets (1) 1.24 1.16 7 % 1.07 8 %
Per-Bbl Adjusted gross margin for
crude-oil and NGLs assets (2) 2.28 2.54 (10) % 2.44 4 %
Per-Bbl Adjusted gross margin for
produced-water assets (3) 0.93 0.98 (5) % 0.97 1 %
Adjusted EBITDA 1,946,690 2,030,366 (4) % 1,719,090 18 %
Free cash flow 1,490,128 1,226,588 21 % 36,709 NM
_________________________________________________________________________________________
(1)Average for period. Calculated as Adjusted gross margin for natural-gas assets, divided by total throughput (MMcf/d) attributable to WES for natural-gas assets.
(2)Average for period. Calculated as Adjusted gross margin for crude-oil and NGLs assets, divided by total throughput (MBbls/d) attributable to WES for crude-oil and NGLs assets.
(3)Average for period. Calculated as Adjusted gross margin for produced-water assets, divided by total throughput (MBbls/d) attributable to WES for produced-water assets.
Adjusted gross margin. We define Adjusted gross margin attributable toWestern 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). 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. Adjusted gross margin decreased by$50.7 million for the year endedDecember 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 fromWhitethorn LLC and Cactus II, (iii) decreased throughput and an annual cost-of-service rate adjustment made during the fourth quarter of 2021 at theDJ 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 effectiveJanuary 1, 2021 , at the DBM water systems, and (vi) decreased throughput on certain fee-based contracts at theDJ Basin complex. These decreases were offset partially by (i) a higher average fee resulting from a cost-of-service rate redetermination effectiveJanuary 1, 2021 , at theWest Texas complex, (ii) cumulative catch-up adjustments for a change in estimated consideration made in 2021 and a higher cost-of-service rate effectiveJanuary 1, 2021 , at theSpringfield system, and (iii) an increase in distributions from Red Bluff Express and Ranch Westex. 80
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Adjusted gross margin increased by$290.1 million for the year endedDecember 31, 2020 , primarily due to (i) increased throughput at theWest Texas andDJ 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 effectiveDecember 31, 2019 , at the DBM oil system, (iii) the acquisition of our interest in Cactus II inJune 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 theSpringfield 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 fromWhitethorn 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. Per-Mcf Adjusted gross margin for natural-gas assets increased by$0.08 for the year endedDecember 31, 2021 , primarily due to (i) a higher average fee resulting from a cost-of-service rate redetermination effectiveJanuary 1, 2021 , at theWest Texas complex and (ii) a higher cost-of-service rate effectiveJanuary 1, 2021 , at theSpringfield system. These increases were offset partially by decreased throughput on certain fee-based contracts at theDJ 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 endedDecember 31, 2020 , primarily due to increased throughput at theWest Texas andDJ Basin complexes, which have higher-than-average per-Mcf margins 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 endedDecember 31, 2021 , primarily due to (i) an annual cost-of-service rate adjustment made during the fourth quarter of 2021 at theDJ 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 effectiveJanuary 1, 2021 , at theSpringfield system. Per-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by$0.10 for the year endedDecember 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 effectiveDecember 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 fromWhitethorn LLC related to commercial activities. Per-Bbl Adjusted gross margin for produced-water assets decreased by$0.05 for the year endedDecember 31, 2021 , primarily due to a lower average fee resulting from a cost-of-service rate redetermination effectiveJanuary 1, 2021 . Adjusted EBITDA. We define Adjusted EBITDA attributable toWestern 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. We believe the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company's ability to incur and service debt, fund capital expenditures, and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks, and rating agencies, use, among other measures, to assess the following: •our operating performance as compared to other publicly traded partnerships in the midstream industry, without regard to financing methods, capital structure, or historical cost basis;
•the ability of our assets to generate cash flow to make distributions; and
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•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 endedDecember 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 endedDecember 31, 2020 , primarily due to (i) a$256.1 million decrease in cost of product (net of lower of cost or market inventory adjustments), (ii) a$60.3 million decrease in operation and maintenance expenses, (iii) a$26.4 million increase in total revenues and other, and (iv) a$14.0 million increase in distributions from equity investments. These amounts were offset partially by (i) a$33.1 million increase in general and administrative expenses excluding non-cash equity-based compensation expense and (ii) a$7.0 million increase in property taxes. The above-described variances in cost of product and total revenues and other include the impacts resulting from a change in accounting for the marketing contracts with AESC effectiveApril 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). 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. Free cash flow increased by$263.5 million for the year endedDecember 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 endedDecember 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. See Capital Expenditures and Historical Cash Flow within this Item 7 for further information. 82
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Reconciliation of non-GAAP financial measures. Adjusted gross margin, Adjusted
EBITDA, and Free cash flow are not defined in GAAP. The GAAP measure used by us
that is most directly comparable to Adjusted gross margin is 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.
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) 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 2019Reconciliation of Gross margin to Adjusted gross margin Total revenues and other
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
Add:
Distributions from equity investments 254,901 278,797 264,828 Depreciation and amortization 551,629 491,086 483,255
Less:
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
547,134 647,390 578,100
Adjusted gross margin for produced-water assets 237,656 249,889 193,936
_________________________________________________________________________________________
(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.
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Year Ended December 31,
thousands 2021 2020 2019
Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss)
$
943,999
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
Less:
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
$
1,766,852
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
$
1,766,852
(257,538) (448,254) (3,387,853)
Net cash provided by (used in) financing activities (1,752,237) (844,204) 2,071,573
_________________________________________________________________________________________
(1)Includes goodwill impairment for the year ended
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