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 I, Item 1 of this quarterly report, and the historical consolidated financial statements, and the notes thereto, which are included under Part II, Item 8 of the 2020 Form 10-K as filed with theSEC onFebruary 26, 2021 . 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 ofSeptember 30, 2021 (see Note 7-Equity Investments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q). We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental. CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS We have made in this Form 10-Q, and may make in other public filings, press releases, and statements by management, forward-looking statements concerning our operations, economic performance, and financial condition. These forward-looking statements include statements preceded by, followed by, or that otherwise include the words "believes," "expects," "anticipates," "intends," "estimates," "projects," "target," "goal," "plans," "objective," "should," or similar expressions or variations on such expressions. These statements discuss future expectations, contain projections of results of operations or financial condition, or include other "forward-looking" information. Although we and our general partner believe that the expectations reflected in our forward-looking statements are reasonable, neither we nor our general partner can provide any assurance that such expectations will prove correct. These forward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from expectations include, but are not limited to, the following:
•our ability to pay distributions to our unitholders;
•our assumptions about the energy market;
•future throughput (including Occidental production) that is gathered or processed by, or transported through our assets;
•our operating results; •competitive conditions; •technology;
•the availability of capital resources to fund acquisitions, capital expenditures, and other contractual obligations, and our ability to access financing through the debt or equity capital markets;
•the supply of, demand for, and price of, oil, natural gas, NGLs, and related products or services;
•commodity-price risks inherent in percent-of-proceeds, percent-of-product, and keep-whole contracts;
•weather and natural disasters;
•inflation;
•the availability of goods and services;
•general economic conditions, internationally, domestically, or in the jurisdictions in which we are doing business;
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•federal, state, and local laws and state-approved voter ballot initiatives, including those laws or ballot initiatives that limit producers' hydraulic-fracturing activities or other oil and natural-gas development or operations;
•environmental liabilities;
•legislative or regulatory changes, including changes affecting our status as a partnership for federal income tax purposes;
•changes in the financial or operational condition of Occidental;
•the creditworthiness of Occidental or our other counterparties, including financial institutions, operating partners, and other parties;
•changes in Occidental's capital program, corporate strategy, or other desired areas of focus;
•our commitments to capital projects;
•our ability to access liquidity under the RCF;
•our ability to repay debt;
•the impact from disruptions caused by winter storm Uri or the blizzard in the
state of
•conflicts of interest among us, our general partner and its related parties, including Occidental, with respect to, among other things, the allocation of capital and operational and administrative costs, and our future business opportunities;
•our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;
•our ability to acquire assets on acceptable terms from third parties;
•non-payment or non-performance of significant customers, including under gathering, processing, transportation, and disposal agreements;
•the timing, amount, and terms of future issuances of equity and debt securities;
•the outcome of pending and future regulatory, legislative, or other proceedings or investigations, and continued or additional disruptions in operations that may occur as we and our customers comply with any regulatory orders or other state or local changes in laws or regulations;
•the economic uncertainty from the worldwide outbreak of the coronavirus ("COVID-19"); and
•other factors discussed below, in "Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Estimates" included in the 2020 Form 10-K, in our quarterly reports on Form 10-Q, and in our other public filings and press releases.
Risk factors and other factors noted throughout or incorporated by reference in this Form 10-Q could cause actual results to differ materially from those contained in any forward-looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
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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 in Texas , New Mexico , the Rocky
Mountains (Colorado , Utah , and Wyoming ), and North-central Pennsylvania . As of
September 30, 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 36 3 - -
Natural-gas processing plants/trains 24 3 - 5
NGLs pipelines 2 - - 5
Natural-gas pipelines 5 - - 1
Crude-oil pipelines 3 1 - 4
_________________________________________________________________________________________
(1)Includes the DBM water systems.
Significant financial and operational events during the nine months ended
•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.
•WES Operating purchased and retired
•We repurchased 5,586,419 common units for an aggregate purchase price of
•Our third-quarter 2021 per-unit distribution of
•Natural-gas throughput attributable to WES totaled 4,081 MMcf/d and 4,132 MMcf/d for the three and nine months endedSeptember 30, 2021 , respectively, representing a 4% decrease and 6% decrease compared to the three months endedJune 30, 2021 , and nine months endedSeptember 30, 2020 , respectively. •Crude-oil and NGLs throughput attributable to WES totaled 641 MBbls/d and 645 MBbls/d for the three and nine months endedSeptember 30, 2021 , respectively, representing a 7% decrease and 11% decrease compared to the three months endedJune 30, 2021 , and nine months endedSeptember 30, 2020 , respectively. •Produced-water throughput attributable to WES totaled 735 MBbls/d and 673 MBbls/d for the three and nine months endedSeptember 30, 2021 , respectively, representing a 7% increase and 5% decrease compared to the three months endedJune 30, 2021 , and nine months endedSeptember 30, 2020 , respectively. •Gross margin was$541.6 million and$1.5 billion for the three and nine months endedSeptember 30, 2021 , respectively, representing an 8% increase and 5% decrease compared to the three months endedJune 30, 2021 , and nine months endedSeptember 30, 2020 , respectively. See Key Performance Metrics within this Item 2. 40
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•Adjusted gross margin for natural-gas assets (as defined under the caption Key Performance Metrics within this Item 2) averaged$1.31 per Mcf and$1.24 per Mcf for the three and nine months endedSeptember 30, 2021 , respectively, representing an 8% increase compared to the three months endedJune 30, 2021 , and nine months endedSeptember 30, 2020 . •Adjusted gross margin for crude-oil and NGLs assets (as defined under the caption Key Performance Metrics within this Item 2) averaged$2.52 per Bbl and$2.46 per Bbl for the three and nine months endedSeptember 30, 2021 , respectively, representing a 5% increase and 2% decrease compared to the three months endedJune 30, 2021 , and nine months endedSeptember 30, 2020 , respectively. •Adjusted gross margin for produced-water assets (as defined under the caption Key Performance Metrics within this Item 2) averaged$0.94 per Bbl and$0.93 per Bbl for the three and nine months endedSeptember 30, 2021 , respectively, representing a 2% increase and 5% decrease compared to the three months endedJune 30, 2021 , and nine months endedSeptember 30, 2020 , respectively. The following table provides additional information on throughput for the periods presented below: Three Months Ended Nine Months Ended June 30, Inc/ Inc/ September 30, 2021 2021 (Dec) September 30, 2021 September 30, 2020 (Dec) Throughput for natural-gas assets (MMcf/d) Delaware Basin 1,274 1,244 2 % 1,217 1,330 (8) % DJ Basin 1,368 1,413 (3) % 1,375 1,342 2 % Equity investments 443 457 (3) % 447 451 (1) % Other 1,152 1,310 (12) % 1,248 1,416 (12) % Total throughput for natural-gas assets 4,237 4,424 (4) % 4,287 4,539 (6) % Throughput for crude-oil and NGLs assets (MBbls/d) Delaware Basin 185 184 1 % 177 192 (8) % DJ Basin 87 98 (11) % 89 109 (18) % Equity investments 350 386 (9) % 358 395 (9) % Other 32 33 (3) % 34 42 (19) % Total throughput for crude-oil and NGLs assets 654 701 (7) % 658 738 (11) % Throughput for produced-water assets (MBbls/d) Delaware Basin 750 702 7 % 687 726 (5) % Total throughput for produced-water assets 750 702 7 % 687 726 (5) % 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 to have reduced net income and Adjusted EBITDA (as defined under the caption Key Performance Metrics within this Item 2) for the nine months endedSeptember 30, 2021 , by approximately$30 million due to lower volumes, the impact of commodity-prices, and higher operating expenses related to utilities. The estimated impact of the adverse winter weather on our operations and financial results may change and those changes may be material. Any additional inclement weather in the future, or other adverse conditions, including resolution of litigation and other legal disputes and the COVID-19 pandemic and resulting mitigation factors, may have an adverse impact on our operations and financial results. 41
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COVID-19. 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 had 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 require 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. WES continues to monitor the COVID-19 situation closely, and as state and federal governments issue additional guidance, we will update our own policies in response 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- andEPA -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. Commodity purchase and sale agreements. EffectiveApril 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 nine months endedSeptember 30, 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 2). See Note 6-Related-Party Transactions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. 42
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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. 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 . 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 2 for additional information.
•An extended period of diminished earnings may restrict our ability to fully access our RCF, which contains various customary covenants, certain events of default, and a maximum consolidated leverage ratio based on Adjusted EBITDA (as defined in the covenant) related to the trailing twelve-month period. Further, any future waivers or amendments to the RCF also may trigger pricing increases for available credit. See Liquidity and Capital Resources-Debt and credit facilities within this Item 2 for additional information. •As ofSeptember 30, 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 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. ACQUISITIONS AND DIVESTITURESFort Union and Bison facilities. 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. See Note 3-Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for further information. 43
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RESULTS OF OPERATIONS
OPERATING RESULTS
In November 2020 , the SEC issued a final rule to modernize and simplify
Management's Discussion and Analysis and certain financial disclosure
requirements in SEC Regulation S-K. As permitted by this final rule, the
analysis herein reflects the optional approach to discuss results of operations
on a sequential-quarter basis, which we believe will provide information that is
most useful to investors in assessing our quarterly results of operations going
forward. In addition, as required by the final rule, we have continued to
include a comparison of the current year-to-date period to the prior
year-to-date period.
For purposes of the following discussion, any increases or decreases "for the
three months ended September 30, 2021 " refer to the comparison of the three
months ended September 30, 2021 , to the three months ended June 30, 2021 ; and
any increases or decreases "for the nine months ended September 30, 2021 " refer
to the comparison of the nine months ended September 30, 2021 , to the nine
months ended September 30, 2020 .
The following tables and discussion present a summary of our results of
operations:
Three Months Ended Nine Months Ended
September 30, June 30, September 30, September 30,
thousands 2021 2021 2021 2020
Total revenues and other (1) $ 763,840 $
719,131
48,506 58,666 159,337 176,788
Total operating expenses (1) 428,716 444,074 1,307,010 1,792,290
Gain (loss) on divestiture and other, net (364) 1,225 278 (3,651)
Operating income (loss) 383,266 334,948 1,010,550 505,959
Interest income - Anadarko note
receivable - - - 11,736
Interest expense (93,257) (95,290) (287,040) (278,811)
Gain (loss) on early extinguishment of
debt (24,655) - (24,944) 10,372
Other income (expense), net 110 84 (1,013) 612
Income (loss) before income taxes 265,464 239,742 697,553 249,868
Income tax expense (benefit) 1,826 1,465 4,403 3,792
Net income (loss) 263,638 238,277 693,150 246,076
Net income (loss) attributable to
noncontrolling interests 7,913 7,018 20,375 (17,045)
Net income (loss) attributable to Western
Midstream Partners, LP (2) $ 255,725 $
231,259
$ 705,407 $ 677,236 $ 1,997,267 $ 2,069,801 Adjusted EBITDA 531,580 491,126 1,465,816 1,546,386 Free cash flow 320,031 379,776 913,629 762,364
_________________________________________________________________________________________
(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 I, Item 1 of this Form
10-Q.
(2)For reconciliations to comparable consolidated results of WES Operating, see
Items Affecting the Comparability of Financial Results with WES Operating within
this Item 2.
(3)Adjusted gross margin, Adjusted EBITDA, and Free cash flow are defined under
the caption Key Performance Metrics within this Item 2. For reconciliations of
these non-GAAP financial measures to their most directly comparable financial
measures calculated and presented in accordance with GAAP, see Key Performance
Metrics-Reconciliation of non-GAAP financial measures within this Item 2.
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Throughput
Three Months Ended Nine Months Ended
June 30, Inc/ Inc/
September 30, 2021 2021 (Dec) September 30, 2021 September 30, 2020 (Dec)
Throughput for natural-gas assets (MMcf/d)
Gathering, treating, and
transportation 378 534 (29) % 477 551 (13) %
Processing 3,416 3,433 - % 3,363 3,537 (5) %
Equity investments (1) 443 457 (3) % 447 451 (1) %
Total throughput 4,237 4,424 (4) % 4,287 4,539 (6) %
Throughput attributable to
noncontrolling interests (2) 156 159 (2) % 155 162 (4) %
Total throughput attributable to
WES for natural-gas assets 4,081 4,265 (4) % 4,132 4,377 (6) %
Throughput for crude-oil and NGLs assets (MBbls/d)
Gathering, treating, and
transportation 304 315 (3) % 300 343 (13) %
Equity investments (3) 350 386 (9) % 358 395 (9) %
Total throughput 654 701 (7) % 658 738 (11) %
Throughput attributable to
noncontrolling interests (2) 13 14 (7) % 13 15 (13) %
Total throughput attributable to
WES for crude-oil and NGLs assets 641 687 (7) % 645 723 (11) %
Throughput for produced-water assets (MBbls/d)
Gathering and disposal 750 702 7 % 687 726 (5) %
Throughput attributable to
noncontrolling interests (2) 15 14 7 % 14 15 (7) %
Total throughput attributable to
WES for produced-water assets 735 688 7 % 673 711 (5) %
_________________________________________________________________________________________
(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 156 MMcf/d for the three months endedSeptember 30, 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 in areas around the Marcellus Interest andSpringfield gas-gathering systems. Gathering, treating, and transportation throughput decreased by 74 MMcf/d for the nine months endedSeptember 30, 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. Processing throughput decreased by 17 MMcf/d for the three months endedSeptember 30, 2021 , primarily due to decreased production in areas around theDJ Basin complex, partially offset by increased production in areas around theWest Texas complex. 45
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Processing throughput decreased by 174 MMcf/d for the nine months endedSeptember 30, 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 complex due to production declines in the area. 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 . Equity-investment throughput decreased by 14 MMcf/d for the three months endedSeptember 30, 2021 , primarily due to decreased volumes at the Mi Vida and RanchWestex plants and the Rendezvous system. Equity-investment throughput decreased by 4 MMcf/d for the nine months endedSeptember 30, 2021 , primarily due to (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. These decreases were offset partially by increased volumes onRed Bluff Express resulting from increased pipeline commitments.
Crude-oil and NGLs assets
Gathering, treating, and transportation throughput decreased by 11 MBbls/d for the three months endedSeptember 30, 2021 , primarily due to decreased production in areas around theDJ Basin oil system. Gathering, treating, and transportation throughput decreased by 43 MBbls/d for the nine months endedSeptember 30, 2021 , primarily due to (i) lower volumes at theDJ Basin oil system resulting from production declines in the area and (ii) lower volumes at the DBM oil system due to lower production and the impact of winter storm Uri. Equity-investment throughput decreased by 36 MBbls/d for the three months endedSeptember 30, 2021 , primarily due to decreased volumes on the Whitethorn pipeline and TEP, partially offset by increased volumes on the Cactus II pipeline resulting from an incentive rate implemented in the second quarter of 2021. Equity-investment throughput decreased by 37 MBbls/d for the nine months endedSeptember 30, 2021 , primarily due to decreased volumes on the Whitethorn pipeline, partially offset by increased volumes on the Saddlehorn pipeline.
Produced-water assets
Gathering and disposal throughput increased by 48 MBbls/d for the three months endedSeptember 30, 2021 , due to increased volumes at the DBM water systems resulting from higher production in the area. Gathering and disposal throughput decreased by 39 MBbls/d for the nine months endedSeptember 30, 2021 , due to decreased volumes at the DBM water systems resulting from lower production and the impact of winter storm Uri. 46
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Service Revenues
Three Months Ended Nine Months Ended
September 30, June 30, Inc/ September 30, September 30, Inc/
thousands except percentages 2021 2021 (Dec) 2021 2020 (Dec)
Service revenues - fee based
5 %$ 1,841,742 $ 1,980,546 (7) % Service revenues - product based 28,812 27,803 4 % 88,267 35,237 150 % Total service revenues$ 679,294 $ 646,788 5 %$ 1,930,009 $ 2,015,783 (4) %
Service revenues - fee based
Service revenues - fee based increased by$31.5 million for the three months endedSeptember 30, 2021 , primarily due to increases of (i)$18.9 million due to revenue recorded in the third quarter of 2021 that was previously constrained (see Note 2-Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q) and (ii)$14.2 million at theWest Texas complex resulting from increased throughput. Service revenues - fee based decreased by$138.8 million for the nine months endedSeptember 30, 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 Executive Summary-Commodity purchase and sale agreements within this Item 2), (ii)$37.9 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)$23.8 million at the DBM water systems resulting from decreased throughput, including the impact of winter storm Uri, and a lower average fee resulting from a cost-of-service rate redetermination effectiveJanuary 1, 2021 , (iv)$20.9 million at theDJ Basin complex due to decreased throughput on certain fee-based contracts, (v)$12.1 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)$9.6 million at theWest Texas complex from decreased throughput, including the impact of winter storm Uri. These decreases were offset partially by an increase of$18.9 million due to revenue recorded in the third quarter of 2021 that was previously constrained (see Note 2-Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q).
Service revenues - product based
Service revenues - product based increased by$1.0 million for the three months endedSeptember 30, 2021 , primarily due to increased pricing across several systems, partially offset by a decrease of$4.7 million at theWest Texas complex primarily due to a decrease in electricity-related fees charged to customers. Service revenues - product based increased by$53.0 million for the nine months endedSeptember 30, 2021 , primarily due to increases of (i)$15.6 million at theDJ Basin complex due to increased third-party volumes and average prices, (ii)$15.1 million at theWest Texas complex due to an increase in electricity-related fees charged to customers during winter storm Uri, and (iii)$6.5 million at the Granger complex,$6.3 million at the Hilight system, and$4.7 million at the Chipeta complex due to increased prices. 47
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Product Sales
Three Months Ended Nine Months Ended
thousands except
percentages and per-unit September 30, June 30, Inc/ September 30, September 30, Inc/
amounts 2021 2021 (Dec) 2021 2020 (Dec)
Natural-gas sales $ 32,151 $ 14,195 126 % $ 67,765 $ 23,934 183 %
NGLs sales 52,147 58,061 (10) % 159,594 84,557 89 %
Total Product sales $ 84,298 $ 72,256 17 % $ 227,359 $ 108,491 110 %
Per-unit gross average
sales price:
Natural gas (per Mcf) $ 4.10 $ 2.65 55 % $ 4.20 $ 1.32 NM
NGLs (per Bbl) 36.96 27.16 36 % 30.81 12.25 152 %
_________________________________________________________________________________________
NM-Not meaningful
Natural-gas sales
Natural-gas sales increased by$18.0 million for the three months endedSeptember 30, 2021 , primarily due to increases of (i)$13.1 million at theWest Texas complex attributable to an increase in average prices and volumes sold and (ii)$2.3 million at theDJ Basin complex and$2.1 million at the MGR assets attributable to an increase in average prices. Natural-gas sales increased by$43.8 million for the nine months endedSeptember 30, 2021 , primarily due to increases of (i)$37.2 million at theWest Texas complex and$7.4 million at the MGR assets attributable to increases in average prices and (ii)$1.8 million resulting from a change in accounting for the marketing contracts with AESC effectiveApril 1, 2020 (see Executive Summary-Commodity purchase and sale agreements within this Item 2). These increases were offset partially by decreases of$4.9 million at theDJ Basin complex and$4.3 million at the Granger complex attributable to decreases in volumes sold, partially offset by increases in average prices.
NGLs sales
NGLs sales decreased by$5.9 million for the three months endedSeptember 30, 2021 , primarily due to a decrease of$8.7 million at theWest Texas complex attributable to net changes in contract mix. This decrease was partially offset by an increase of$2.2 million at the Chipeta complex attributable to an increase in average prices and volumes sold. NGLs sales increased by$75.0 million for the nine months endedSeptember 30, 2021 , primarily due to increases of (i)$65.4 million at theWest Texas complex attributable to an increase in average prices, partially offset by decreased volumes sold and (ii)$15.9 million at the Chipeta complex and$8.7 million at the Granger complex attributable to increases in average prices. 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 Executive Summary-Commodity purchase and sale agreements within this Item 2).
Equity Income, Net - Related Parties
Three Months Ended Nine Months Ended
thousands except September 30, June 30, Inc/ September 30, September 30, Inc/
percentages 2021 2021 (Dec) 2021 2020 (Dec)
Equity income, net -
related parties $ 48,506 $ 58,666 (17) % $ 159,337 $ 176,788 (10) %
Equity income, net - related parties decreased by $10.2 million for the three
months ended September 30, 2021 , primarily due to decreases of $5.9 million at
Cactus II and $4.1 million at Mont Belvieu JV resulting from electricity credits
received in the second quarter of 2021 related to winter storm Uri.
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Equity income, net - related parties decreased by$17.5 million for the nine months endedSeptember 30, 2021 , primarily due to decreases of (i)$24.1 million atWhitethorn LLC related to commercial activities and lower volumes and (ii)$4.8 million and$4.2 million at Cactus II and White Cliffs, respectively, due to lower volumes. These decreases were offset partially by increases of (i)$6.4 million and$5.1 million at Saddlehorn and Red Bluff Express, respectively, due to higher volumes and (ii)$4.4 million at Mont Belvieu JV from a load-reduction electricity credit received in the second quarter of 2021 related to winter storm Uri.
Cost of Product and Operation and Maintenance Expenses
Three Months Ended Nine Months Ended
September 30, June 30, Inc/ September 30, September 30, Inc/thousands except percentages 2021 2021 (Dec) 2021 2020 (Dec) Residue purchases$ 32,123 $ 23,019 40 %$ 113,046 $ 43,998 157 % NGLs purchases 51,440 42,305 22 % 124,664 111,809 11 % Other (331) 12,720 (103) % 12,535 (2,196) NM Cost of product 83,232 78,044 7 % 250,245 153,611 63 % Operation and maintenance 140,838 153,028 (8) % 434,198 436,670 (1) % Total Cost of product and Operation and maintenance expenses$ 224,070 $ 231,072 (3) %$ 684,443 $ 590,281 16 % Residue purchases Residue purchases increased by$9.1 million for the three months endedSeptember 30, 2021 , primarily due to increases of (i)$4.0 million at theWest Texas complex attributable to an increase in average prices and volumes purchased and (ii)$2.2 million at the MGR assets attributable to an increase in average prices. Residue purchases increased by$69.0 million for the nine months endedSeptember 30, 2021 , primarily due to increases of$45.4 million at theWest Texas complex,$7.7 million at the Chipeta complex,$6.6 million at the MGR assets,$5.4 million at the Granger complex, and$5.3 million at the Hilight system attributable to increases in average prices. 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 Executive Summary-Commodity purchase and sale agreements within this Item 2).
NGLs purchases
NGLs purchases increased by$9.1 million for the three months endedSeptember 30, 2021 , primarily due to increases of (i)$5.5 million at theDJ Basin complex attributable to an increase in average prices and (ii)$2.2 million at the Chipeta complex attributable to an increase in average prices and volumes purchased. NGLs purchases increased by$12.9 million for the nine months endedSeptember 30, 2021 , primarily due to increases of$31.5 million at theWest Texas complex,$24.7 million at theDJ Basin complex,$9.4 million at the Chipeta complex, and$5.8 million at the Granger complex attributable to increases in average prices. 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 Executive Summary-Commodity purchase and sale agreements within this Item 2).
Other items
Other items decreased by$13.1 million for the three months endedSeptember 30, 2021 , primarily due to decreases of$8.1 million at theWest Texas complex and$3.1 million at theDJ Basin complex, primarily attributable to changes in imbalance positions. Other items increased by$14.7 million for the nine months endedSeptember 30, 2021 , primarily due to an increase of$31.2 million at theWest Texas complex, partially offset by a decrease of$16.7 million at theDJ Basin complex, both primarily attributable to changes in imbalance positions. 49
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Operation and maintenance expense
Operation and maintenance expense decreased by$12.2 million for the three months endedSeptember 30, 2021 , primarily due to decreases of (i)$5.9 million at theWest Texas complex attributable to reduced utilities expense and surface maintenance and plant repairs and (ii)$4.8 million at theDJ Basin complex due to an environmental liability of$4.1 million recorded in the second quarter of 2021. Operation and maintenance expense decreased by$2.5 million for the nine months endedSeptember 30, 2021 , primarily due to decreases of (i)$7.5 million at theWest Texas complex, primarily attributable to reduced salaries and wages, surface maintenance and plant repairs, and safety expense; partially offset by increased utilities expense primarily resulting from the impact of winter storm Uri, (ii)$5.8 million at theDJ Basin complex attributable to reduced surface maintenance and plant repairs, and (iii)$3.8 million at the DBM water systems attributable to lower disposal fees resulting from reduced volumes and lower surface-use fees, partially offset by increased utilities expense and surface maintenance and plant repairs, including the impact of winter storm Uri. These decreases were offset partially by an increase of$10.2 million at the DBM oil system, primarily attributable to increases in field-related expenses, chemicals and treating services, and utilities expense primarily resulting from the impact of winter storm Uri. Other Operating Expenses Three Months Ended Nine Months Ended September 30, June 30, Inc/ September 30, September 30, Inc/ thousands except percentages 2021 2021 (Dec) 2021 2020 (Dec) General and administrative$ 50,409 $ 44,448 13 %$ 139,973 $ 118,466 18 % Property and other taxes 13,641 17,967 (24) % 45,992 57,263 (20) % Depreciation and amortization 139,002 137,849 1 % 407,404 384,688 6 % Long-lived asset and other impairments 1,594 12,738 (87) % 29,198 200,575 (85) % Goodwill impairment - - - % - 441,017 (100) % Total other operating expenses$ 204,646 $ 213,002 (4) %$ 622,567 $ 1,202,009 (48) %
General and administrative expenses
General and administrative expenses increased by$6.0 million for the three months endedSeptember 30, 2021 , primarily due to increases of (i)$4.4 million in personnel costs and (ii)$2.0 million in contract and consulting costs. General and administrative expenses increased by$21.5 million for the nine months endedSeptember 30, 2021 , primarily due to increases of (i)$16.2 million in personnel costs primarily related to increased bonus-related contributions under our employee savings plan and equity-based compensation expense, and (ii)$6.3 million in contract and consulting costs primarily related to information technology services and fees. Property and other taxes Property and other taxes decreased by$4.3 million for the three months endedSeptember 30, 2021 , primarily due to ad valorem tax decreases at theWest Texas complex and DBM oil system due to favorable differences between actual and estimated tax payments related to the 2021 fiscal year. Property and other taxes decreased by$11.3 million for the nine months endedSeptember 30, 2021 , primarily due to ad valorem tax decreases at theWest Texas complex due to favorable differences between actual and estimated tax payments related to the 2020 fiscal year. 50
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Depreciation and amortization expense
Depreciation and amortization expense increased by$22.7 million for the nine months endedSeptember 30, 2021 , primarily due to increases of (i)$16.9 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)$7.1 million related to depreciation for capitalized information technology implementation costs related to the stand-up of WES as an independent organization, (iii)$6.3 million at theWest Texas complex resulting from capital projects being placed into service, and (iv)$3.8 million at theSpringfield system due to an acceleration of depreciation expense for revised service life assumptions. These increases were offset partially by decreases of (i)$13.4 million due to the sale of the Bison treating facility and (ii)$3.3 million at a transportation asset inSouthwest Wyoming , primarily as a result of downward asset retirement obligation revisions made in the first quarter of 2021.
Long-lived asset and other impairment expense
Long-lived asset and other impairment expense for the three months endedJune 30, 2021 , was primarily due to an$11.6 million other-than-temporary impairment of our investment in Ranch Westex. Long-lived asset and other impairment expense for the three months endedMarch 31, 2021 , was primarily due to$13.5 million of impairments at theDJ Basin complex due to cancellation of projects. Long-lived asset and other impairment expense for the nine months endedSeptember 30, 2020 , was primarily due to (i)$150.2 million of impairments for assets located inWyoming andUtah , (ii) impairments of$14.8 million primarily at theDJ Basin complex, DBM water systems, andWest Texas complex due to cancellation of projects, and (iii) impairments of rights-of-way for$6.2 million at theDJ Basin complex. For further information on Long-lived asset and other impairment expense, see Note 8-Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
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 9-Goodwill in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. 51
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Interest Income - Anadarko Note Receivable and Interest Expense
Three Months Ended Nine Months Ended
September 30, June 30, Inc/ September 30, September 30, Inc/
thousands except percentages 2021 2021 (Dec) 2021 2020 (Dec)
Interest income - Anadarko
note receivable $ - $ - - % $ - $ 11,736 (100) %
Third parties
Long-term and short-term
debt $ (90,913) $ (92,487) (2) % $ (279,122) $ (273,620) 2 %
Finance lease liabilities (218) (292) (25) % (808) (1,162) (30) %
Commitment fees and
amortization of debt-related
costs (3,147) (3,179) (1) % (9,664) (10,052) (4) %
Capitalized interest 1,021 668 53 % 2,554 6,066 (58) %
Related parties
Finance lease liabilities - - - % - (43) (100) %
Interest expense $ (93,257) $ (95,290) (2) % $ (287,040) $ (278,811) 3 %
Interest income
Interest income - Anadarko note receivable decreased by $11.7 million for the
nine months ended September 30, 2021 , 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 I, Item 1 of this Form 10-Q.
Interest expense
Interest expense decreased by$2.0 million for the three months endedSeptember 30, 2021 , primarily due to lower outstanding balances as a result of the purchase and retirement of portions of certain of the senior notes. Interest expense increased by$8.2 million for the nine months endedSeptember 30, 2021 , primarily due to (i)$27.4 million of 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$3.5 million in capitalized interest due to decreased capital expenditures. These increases were offset partially by decreases of (i)$18.4 million due to lower outstanding balances on the 5.375% Senior Notes due 2021 that were called onMarch 1, 2021 and the purchase and retirement of portions of certain of the senior notes during the third quarter of 2021 and (ii)$3.9 million due to lower outstanding borrowings under the RCF in 2021. See Liquidity and Capital Resources-Debt and credit facilities within this Item 2. Income Tax Expense (Benefit) Three Months Ended Nine Months Ended thousands except September 30, June 30, Inc/ Inc/ percentages 2021 2021 (Dec) September 30, 2021 September 30, 2020 (Dec) Income (loss) before income taxes$ 265,464 $ 239,742 11 % $ 697,553 $ 249,868 179 % Income tax expense (benefit) 1,826 1,465 25 % 4,403 3,792 16 % Effective tax rate 1 % 1 % 1 % 2 % We are not a taxable entity forU.S. federal income tax purposes; therefore, our federal statutory rate is zero percent. However, income apportionable toTexas is subject toTexas margin tax. For all periods presented, the variance from the federal statutory rate primarily was due to ourTexas margin tax liability. 52
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KEY PERFORMANCE METRICS
Three Months Ended Nine Months Ended
thousands except percentages and
Inc/ September 30, September 30, Inc/
per-unit amounts 2021 2021 (Dec) 2021 2020 (Dec)
Adjusted gross margin for
natural-gas assets $ 492,708 $ 469,409 5 % $ 1,394,506 $ 1,384,632 1 %
Adjusted gross margin for
crude-oil and NGLs assets 148,939 150,317 (1) % 432,401 494,481 (13) %
Adjusted gross margin for
produced-water assets 63,760 57,510 11 % 170,360 190,688 (11) %
Adjusted gross margin 705,407 677,236 4 % 1,997,267 2,069,801 (4) %
Per-Mcf Adjusted gross margin
for natural-gas assets (1) 1.31 1.21 8 % 1.24 1.15 8 %
Per-Bbl Adjusted gross margin
for crude-oil and NGLs assets
(2) 2.52 2.40 5 % 2.46 2.50 (2) %
Per-Bbl Adjusted gross margin
for produced-water assets (3) 0.94 0.92 2 % 0.93 0.98 (5) %
Adjusted EBITDA 531,580 491,126 8 % 1,465,816 1,546,386 (5) %
Free cash flow 320,031 379,776 (16) % 913,629 762,364 20 %
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(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. 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. 53
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Adjusted gross margin increased by$28.2 million for the three months endedSeptember 30, 2021 , primarily due to (i) increased throughput at theWest Texas complex and DBM water systems and (ii) revenue recorded in the third quarter of 2021 that was previously constrained (see Note 2-Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q). These increases were offset partially by (i) a decrease in distributions from Mont Belvieu JV and (ii) decreased throughput at theDJ Basin complex. Adjusted gross margin decreased by$72.5 million for the nine months endedSeptember 30, 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 , (iii) decreased throughput and a lower average fee resulting from a cost-of-service rate redetermination effectiveJanuary 1, 2021 , at the DBM water systems, (iv) decreased throughput on certain fee-based contracts at theDJ Basin complex, and (v) 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. These decreases were offset partially by (i) revenue recorded in the third quarter of 2021 that was previously constrained, (ii) higher average commodity prices at the MGR assets, and (iii) an increase in distributions from Red Bluff Express and Saddlehorn. Per-Mcf Adjusted gross margin for natural-gas assets increased by$0.10 for the three months endedSeptember 30, 2021 , primarily due to (i) revenue recorded in the third quarter of 2021 that was previously constrained at theSpringfield gas-gathering system and (ii) increased throughput at theWest Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets. These increases were offset partially by decreased throughput 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 nine months endedSeptember 30, 2021 , primarily due to (i) a higher cost-of-service rate effectiveJanuary 1, 2021 , at theWest Texas complex and (ii) revenue recorded in the third quarter of 2021 that was previously constrained at theSpringfield gas-gathering 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-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by$0.12 for the three months endedSeptember 30, 2021 , primarily due to (i) revenue recorded in the third quarter of 2021 that was previously constrained and (ii) decreased volumes on the Whitethorn pipeline, which has a lower-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets. These increases were offset partially by (i) lower lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system and (ii) a decrease in distributions from Mont Belvieu JV. Per-Bbl Adjusted gross margin for crude-oil and NGLs assets decreased by$0.04 for the nine months endedSeptember 30, 2021 , primarily due to (i) 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 and (ii) a decrease in distributions from FRP and Cactus II. These decreases were offset partially by (i) a higher cost-of-service rate effectiveJanuary 1, 2021 , at theDJ Basin oil system and (ii) revenue recorded in the third quarter of 2021 that was previously constrained. Per-Bbl Adjusted gross margin for produced-water assets increased by$0.02 for the three months endedSeptember 30, 2021 , primarily due to increased throughput on volumes with higher-than-average per-Bbl margins. Per-Bbl Adjusted gross margin for produced-water assets decreased by$0.05 for the nine months endedSeptember 30, 2021 , primarily due to a lower average fee resulting from a cost-of-service rate redetermination effectiveJanuary 1, 2021 . 54
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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
•the viability of acquisitions and capital expenditures and the returns on investment of various investment opportunities.
Adjusted EBITDA increased by$40.5 million for the three months endedSeptember 30, 2021 , primarily due to (i) a$44.7 million increase in total revenues and other, (ii) a$12.2 million decrease in operation and maintenance expenses, and (iii) a$4.3 million decrease in property taxes. These amounts were offset partially by (i) an$8.2 million decrease in distributions from equity investments, (ii) a$6.1 million increase in general and administrative expenses excluding non-cash equity-based compensation expense, and (iii) a$5.2 million increase in cost of product (net of lower of cost or market inventory adjustments). Adjusted EBITDA decreased by$80.6 million for the nine months endedSeptember 30, 2021 , primarily due to (i) a$96.8 million increase in cost of product (net of lower of cost or market inventory adjustments), (ii) a$17.2 million increase in general and administrative expenses excluding non-cash equity-based compensation expense, and (iii) a$14.7 million decrease in distributions from equity investments. These amounts were offset partially by (i) a$32.8 million increase in total revenues and other and (ii) an$11.3 million decrease 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 Executive Summary-Commodity purchase and sale agreements within this Item 2). 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 decreased by$59.7 million for the three months endedSeptember 30, 2021 , primarily due to a decrease of$60.8 million in net cash provided by operating activities, partially offset by a decrease of$3.2 million in contributions to equity investments. Free cash flow increased by$151.3 million for the nine months endedSeptember 30, 2021 , primarily due to (i) a decrease of$154.5 million in capital expenditures, (ii) a decrease of$15.3 million in contributions to equity investments, and (iii) an$8.3 million increase in distributions from equity investments in excess of cumulative earnings. These amounts were offset partially by a decrease of$26.9 million in net cash provided by operating activities. See Capital Expenditures and Historical Cash Flow within this Item 2 for further information. 55
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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:
Three Months Ended Nine Months Ended
September 30, June 30, September 30, September 30,
thousands 2021 2021 2021 2020Reconciliation of Gross margin to Adjusted gross margin Total revenues and other
$ 763,840 $
719,131
83,232 78,044 250,245 153,611
Depreciation and amortization 139,002 137,849 407,404 384,688
Gross margin 541,606 503,238 1,500,296 1,586,813
Add:
Distributions from equity investments 62,711 70,947 194,847 209,566 Depreciation and amortization 139,002 137,849 407,404 384,688
Less:
Reimbursed electricity-related charges recorded as revenues 19,725 17,585 54,622 61,100 Adjusted gross margin attributable to noncontrolling interests (1) 18,187 17,213 50,658 50,166 Adjusted gross margin$ 705,407 $
677,236
148,939 150,317 432,401 494,481
Adjusted gross margin for produced-water
assets 63,760 57,510 170,360 190,688
_________________________________________________________________________________________
(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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Three Months Ended Nine Months Ended
September 30, June 30, September 30, September 30,
thousands 2021 2021 2021 2020Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss)
$ 263,638 $
238,277
62,711 70,947 194,847 209,566
Non-cash equity-based compensation
expense 6,979 7,121 20,834 16,527
Interest expense 93,257 95,290 287,040 278,811
Income tax expense 1,826 1,465 4,403 8,072
Depreciation and amortization 139,002 137,849 407,404 384,688
Impairments (1) 1,594 12,738 29,198 641,592
Other expense 4 30 1,252 1,953
Less:
Gain (loss) on divestiture and other, net (364) 1,225 278 (3,651)
Gain (loss) on early extinguishment of
debt (24,655) - (24,944) 10,372
Equity income, net - related parties 48,506 58,666 159,337 176,788
Interest income - Anadarko note
receivable - - - 11,736
Other income 109 84 193 2,373
Income tax benefit - - - 4,280
Adjusted EBITDA attributable to
noncontrolling interests (2) 13,835 12,616 37,448 39,001
Adjusted EBITDA $ 531,580 $
491,126
93,257 95,290 287,040 267,075
Accretion and amortization of long-term
obligations, net (1,871) (1,914) (5,873) (6,482)
Current income tax expense (benefit) 824 749 2,128 1,399
Other (income) expense, net (110) (84) 1,013 (612)
Cash paid to settle interest-rate swaps - - - 19,181
Distributions from equity investments in
excess of cumulative earnings - related
parties 8,702 9,232 30,075 21,750
Changes in assets and liabilities:
Accounts receivable, net 61,609 38,982 130,773 192,338
Accounts and imbalance payables and
accrued liabilities, net (17,204) (55,758) (56,495) (37,814)
Other items, net 8,875 (34,866) 9,609 (3,341)
Adjusted EBITDA attributable to
noncontrolling interests (2) (13,835) (12,616) (37,448) (39,001)
Adjusted EBITDA $ 531,580 $
491,126
(80,883) (59,932) (187,287) (426,670)
Net cash provided by (used in) financing
activities (516,161) (142,982) (1,262,767) (667,140)
_________________________________________________________________________________________
(1)Includes goodwill impairment for the nine months endedSeptember 30, 2020 . See Note 9-Goodwill in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. (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. 57
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Three Months Ended Nine Months Ended
September 30, June 30, September 30, September 30,
thousands 2021 2021 2021 2020
Reconciliation of Net cash provided by operating activities to Free cash flow
Net cash provided by operating activities $ 391,333 $ 452,111 $ 1,104,994 $ 1,131,893
Less:
Capital expenditures 79,829 78,145 217,757 372,262
Contributions to equity investments -
related parties 175 3,422 3,683 19,017
Add:
Distributions from equity investments in excess of cumulative earnings - related parties 8,702 9,232 30,075 21,750 Free cash flow$ 320,031 $
379,776
(80,883) (59,932) (187,287) (426,670)
Net cash provided by (used in) financing
activities (516,161) (142,982) (1,262,767) (667,140)
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LIQUIDITY AND CAPITAL RESOURCES
Our primary cash uses include quarterly distributions, debt service, customary
operating expenses, and capital expenditures. Our sources of liquidity as of
September 30, 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 and debt service
requirements. The amount of future distributions to unitholders will depend on
our results of operations, financial condition, capital requirements, and other
factors, and will be determined by the Board of Directors on a quarterly basis.
We may rely on external financing sources, including equity and debt issuances,
to fund capital expenditures and future acquisitions. However, we also may use
operating cash flows to fund capital expenditures or acquisitions, which could
result in borrowings under the RCF to pay distributions or to fund other
short-term working capital requirements.
Under our partnership agreement, we distribute all of our available cash (beyond
proper reserves as defined in our partnership agreement) within 55 days
following each quarter's end. Our cash flow and resulting ability to make cash
distributions are dependent on our ability to generate cash flow from
operations. Generally, our available cash is our cash on hand at the end of a
quarter after the payment of our expenses and the establishment of cash reserves
and cash on hand resulting from working capital borrowings made after the end of
the quarter. The general partner establishes cash reserves to provide for the
proper conduct of our business, including (i) reserves to fund future capital
expenditures, (ii) to comply with applicable laws, debt instruments, or other
agreements, or (iii) to provide funds for unitholder distributions for any one
or more of the next four quarters. We have made cash distributions to our
unitholders each quarter since our initial public offering in 2012. The Board of
Directors declared a cash distribution to unitholders for the third quarter of
2021 of $0.32300 per unit, or $134.9 million in the aggregate. The cash
distribution is payable on November 12, 2021 , to our unitholders of record at
the close of business on November 1, 2021 .
In November 2020 , we announced a buyback program of up to $250.0 million of our
common units through December 31, 2021 . The common units may be purchased from
time to time in the open market at prevailing market prices or in privately
negotiated transactions. The timing and amount of purchases under the program
will be determined based on ongoing assessments of capital needs, our financial
performance, the market price of the common units, and other factors, including
organic growth and acquisition opportunities and general market conditions. The
program does not obligate us to purchase any specific dollar amount or number of
units and may be suspended or discontinued at any time. During the nine months
ended September 30, 2021 , we repurchased 5,586,419 common units on the open
market for an aggregate purchase price of $104.4 million . We canceled the units
immediately upon receipt. As of September 30, 2021 , we had an authorized amount
of $113.1 million remaining under the Purchase Program.
Management continuously monitors our leverage position and coordinates our
capital expenditures and quarterly distributions with expected cash inflows and
projected debt service requirements. We will continue to evaluate funding
alternatives, including additional borrowings and the issuance of debt or equity
securities, to secure funds as needed or to refinance maturing debt balances
with longer-term debt issuances. Our ability to generate cash flows is subject
to a number of factors, some of which are beyond our control. Read Risk Factors
under Part II, Item 1A of this Form 10-Q.
Working capital. 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 other capital
activities. As of September 30, 2021 , we had a $550.6 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 (i) the 4.000%
Senior Notes due 2022 of $502.1 million and (ii) $220.0 million of outstanding
borrowings under the RCF being classified as short-term debt on the consolidated
balance sheet as of September 30, 2021 . As of September 30, 2021 , there was $1.8
billion available for borrowing under the RCF. See Note 10-Selected Components
of Working Capital and Note 11-Debt and Interest Expense in the Notes to
Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
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Capital expenditures. Our business is capital intensive, requiring significant
investment to maintain and improve existing facilities or to develop new
midstream infrastructure. Capital expenditures includes maintenance capital
expenditures, which include those expenditures required to maintain existing
operating capacity and service capability of our assets, such as to replace
system components and equipment that have been subject to significant use over
time, become obsolete, or reached the end of their useful lives, to remain in
compliance with regulatory or legal requirements, or to complete additional well
connections to maintain existing system throughput and related cash flows; and
expansion capital expenditures, which include expenditures to construct new
midstream infrastructure and expenditures incurred to extend the useful lives of
our assets, reduce costs, increase revenues, or increase system throughput or
capacity from current levels, including well connections that increase existing
system throughput.
Capital expenditures in the consolidated statements of cash flows reflect
capital expenditures on a cash basis, when payments are made. Capital incurred
is presented on an accrual basis. Capital expenditures as presented in the
consolidated statements of cash flows and capital incurred were as follows:
Nine Months Ended
September 30,
thousands 2021 2020
Capital expenditures (1) $ 217,757 $ 372,262
Capital incurred (1) 224,080 251,315
_________________________________________________________________________________________
(1)For the nine months ended
Capital expenditures decreased by$154.5 million for the nine months endedSeptember 30, 2021 , primarily due to decreases of (i)$66.8 million at theWest Texas complex primarily attributable to decreases in facility expansion and pipeline projects, (ii)$41.0 million at theDJ 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, (iii)$19.5 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, and (iv)$11.0 million at the DBM water systems primarily due to reduced construction of additional water-disposal facilities and gathering projects. 60
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Historical cash flow. The following table and discussion present a summary of
our net cash flows provided by (used in) operating, investing, and financing
activities:
Nine Months Ended
September 30,
thousands 2021 2020
Net cash provided by (used in):
Operating activities $ 1,104,994 $ 1,131,893
Investing activities (187,287) (426,670)
Financing activities (1,262,767) (667,140)
Net increase (decrease) in cash and cash equivalents
Operating activities. Net cash provided by operating activities decreased for the nine months endedSeptember 30, 2021 , primarily due to (i) lower cash operating income, (ii) lower distributions from equity investments, (iii) lower interest income, and (iv) higher interest expense. These decreases were offset partially by (i) the impact of changes in assets and liabilities and (ii) cash paid during the nine months endedSeptember 30, 2020 , to settle interest-rate swaps. Refer to Operating Results within this Item 2 for a discussion of our results of operations as compared to the prior period.
Investing activities. Net cash used in investing activities for the nine months
ended
•$217.8 million of capital expenditures, primarily related to construction, expansion, and asset-integrity projects at theWest Texas complex, DBM water systems,DJ Basin complex, and DBM oil system;
•$3.7 million of capital contributions primarily paid to Cactus II;
•$2.0 million of purchases from related parties;
•$30.1 million of distributions received from equity investments in excess of cumulative earnings; and
•$8.0 million related to the sale of the Bison treating facility.
Net cash used in investing activities for the nine months ended
•$372.3 million of capital expenditures, primarily related to construction and expansion at theWest Texas andDJ Basin complexes, DBM water systems, and DBM oil system;
•$57.1 million of increases to materials and supplies inventory;
•$19.0 million of capital contributions primarily paid to Cactus II and FRP for construction activities; and
•$21.8 million of distributions received from equity investments in excess of cumulative earnings.
Financing activities. Net cash used in financing activities for the nine months
ended
•$521.9 million to purchase and retire portions of certain of WES Operating's senior notes via a tender offer;
•$431.1 million to redeem the total principal amount outstanding of WES Operating's 5.375% Senior Notes due 2021;
•$398.9 million of distributions paid to WES unitholders;
•$180.0 million of repayments of outstanding borrowings under the RCF;
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•$104.4 million of unit repurchases;
•$11.8 million of decreases in outstanding checks due mostly to ad valorem tax payments made at the end of 2020;
•$9.9 million of distributions paid to the noncontrolling interest owner of WES Operating;
•$5.3 million of finance lease payments;
•$2.7 million of distributions paid to the noncontrolling interest owner of Chipeta;
•$400.0 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; and
•$6.7 million of contributions from related parties.
Net cash used in financing activities for the nine months ended
•$3.0 billion of repayments of outstanding borrowings under the Term loan facility;
•$600.0 million of repayments of outstanding borrowings under the RCF;
•$563.6 million of distributions paid to WES unitholders;
•$180.4 million to purchase and retire portions of WES Operating's 5.375% Senior Notes due 2021, 4.000% Senior Notes due 2022, and Floating-Rate Senior Notes via open-market repurchases;
•$12.2 million of finance lease payments;
•$11.5 million of distributions paid to the noncontrolling interest owner of WES Operating;
•$3.9 million of distributions paid to the noncontrolling interest owner of Chipeta;
•$3.5 billion of net proceeds from the Fixed-Rate Senior Notes and Floating-Rate Senior Notes issued inJanuary 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; and
•$20.0 million of a one-time cash contribution from Occidental received inJanuary 2020 , pursuant to the Services Agreement, for anticipated transition costs required to establish stand-alone human resources and information technology functions. 62
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Debt and credit facilities. As ofSeptember 30, 2021 , the carrying value of outstanding debt was$7.1 billion . See Note 11-Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. WES Operating Senior Notes. Inmid-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, atSeptember 30, 2021 . The interest rate on the Floating-Rate Senior Notes was 2.23% atSeptember 30, 2021 . The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating. InAugust 2021 , Standard and Poor's ("S&P") upgraded WES Operating's long-term debt from "BB" to "BB+." As a result of the S&P upgrade, annualized borrowing costs will decrease by$7.9 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. For the three months endedSeptember 30, 2021 , losses of$24.7 million were recognized for the early retirement of these notes. 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. As ofSeptember 30, 2021 , the 4.000% Senior Notes due 2022 were classified as short-term debt on the consolidated balance sheet. AtSeptember 30, 2021 , WES Operating was in compliance with all covenants under the relevant governing indentures. We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or debt agreements through cash purchases, exchanges, open-market repurchases, privately negotiated transactions, tender offers, or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity position and requirements, contractual restrictions, and other factors. The amounts involved may be material. Revolving credit facility. WES Operating's$2.0 billion senior unsecured revolving credit facility is expandable to a maximum of$2.5 billion , and matures inFebruary 2025 for each extending lender. The non-extending lender's commitments mature inFebruary 2024 and represent$100.0 million out of$2.0 billion of total commitments from all lenders. As ofSeptember 30, 2021 , there were$220.0 million of outstanding borrowings and$5.1 million of outstanding letters of credit, resulting in$1.8 billion of available borrowing capacity under the RCF. AtSeptember 30, 2021 , the interest rate on any outstanding RCF borrowings was 1.58% and the facility-fee rate was 0.25%. The RCF contains certain covenants that limit, among other things, WES Operating's ability, and that of certain of its subsidiaries, to incur additional indebtedness, grant certain liens, merge, consolidate, or allow any material change in the character of its business, enter into certain related-party transactions and use proceeds other than for partnership purposes. The RCF also contains various customary covenants, certain events of default, and a maximum consolidated leverage ratio as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated EBITDA for the most-recent four-consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions. As a result of certain covenants contained in the RCF, our capacity to borrow under the RCF may be limited. AtSeptember 30, 2021 , WES Operating was in compliance with all covenants under the RCF. Any outstanding RCF borrowings are classified as short-term debt on the consolidated balance sheet due to management's intent to repay within the next twelve months. Finance lease liabilities. During the first quarter of 2020, WES entered into finance leases with third parties for equipment and vehicles extending through 2029. Certain equipment leases were amended during the third quarter of 2021 requiring reassessment of lease classification. As a result, these leases are now classified as operating leases resulting in a reduction of$19.6 million in Net property, plant, and equipment and$20.3 million in Short-term and Long-term debt. The operating leases resulted in additions of$4.8 million in Other assets,$3.1 million in Accrued liabilities, and$2.4 million in Other liabilities, on the consolidated balance sheet. As ofSeptember 30, 2021 , we have future lease payments of$1.3 million for the remainder of 2021 and a total of$5.4 million in years thereafter. 63
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Credit risk. We bear credit risk through exposure to non-payment or non-performance by our counterparties, including Occidental, financial institutions, customers, and other parties. Generally, non-payment or non-performance results from a customer's inability to satisfy payables to us for services rendered, minimum-volume-commitment deficiency payments owed, or volumes owed pursuant to gas-imbalance agreements. We examine and monitor the creditworthiness of customers and may establish credit limits for customers. A substantial portion of our throughput is sourced from producers, including Occidental, that recently received credit-rating downgrades. We are subject to the risk of non-payment or late payment by producers for gathering, processing, transportation, and disposal fees. Additionally, we continue to evaluate counterparty credit risk and, in certain circumstances, are exercising our rights to request adequate assurance. We expect our exposure to the concentrated risk of non-payment or non-performance to continue for as long as our commercial relationships with Occidental generate a significant portion of our revenues. While Occidental is our contracting counterparty, gathering and processing arrangements with affiliates of Occidental on most of our systems include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. We also are party to agreements with Occidental under which Occidental is required to indemnify us for certain environmental claims, losses arising from rights-of-way claims, failures to obtain required consents or governmental permits, and income taxes with respect to the assets previously acquired fromAnadarko . See Note 6-Related-Party Transactions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q. 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; the contribution agreements; or the Services Agreement.
ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING
Our consolidated financial statements include the consolidated financial results of WES Operating. Our results of operations do not differ materially from the results of operations and cash flows of WES Operating, which are reconciled below.
Reconciliation of net income (loss). The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows:
Three Months Ended Nine Months Ended
September 30, June 30, September 30, September 30,
thousands 2021 2021 2021 2020
Net income (loss) attributable to WES $ 255,725 $ 231,259 $ 672,775 $ 263,121
Limited partner interests in WES
Operating not held by WES (1) 5,214 4,754 13,779 5,426
General and administrative expenses (2) (280) 1,600 2,206 2,683
Other income (expense), net (4) (2) (9) (6)
Income taxes 3 - 3 -
Net income (loss) attributable to WES
Operating $ 260,658 $
237,611
_________________________________________________________________________________________
(1)Represents the portion of net income (loss) allocated to the limited partner
interests in WES Operating not held by WES. A subsidiary of Occidental held a
2.0% limited partner interest in WES Operating for all periods presented.
(2)Represents general and administrative expenses incurred by WES separate from,
and in addition to, those incurred by WES Operating.
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Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows:
Nine Months Ended
September 30,
thousands 2021 2020
WES net cash provided by operating activities $ 1,104,994 $ 1,131,893
General and administrative expenses (1) 2,206 2,683
Non-cash equity-based compensation expense 7,040 (5,372)
Changes in working capital (10,045) 4,774
Other income (expense), net (9) (6)
Income taxes 3 -
WES Operating net cash provided by operating activities $
1,104,189
WES net cash provided by (used in) financing activities$ (1,262,767) $ (667,140) Distributions to WES unitholders (2) 398,896 563,579 Distributions to WES from WES Operating (3) (486,621) (565,577) Increase (decrease) in outstanding checks 58 316 Unit repurchases 104,366 - Other 3,492 -
WES Operating net cash provided by (used in) financing activities
$
(1,242,576)
_________________________________________________________________________________________
(1)Represents general and administrative expenses incurred by WES separate from,
and in addition to, those incurred by WES Operating.
(2)Represents distributions to WES common unitholders paid under WES's
partnership agreement. See Note 4-Partnership Distributions and Note 5-Equity
and Partners' Capital in the Notes to Consolidated Financial Statements under
Part I, Item 1 of this Form 10-Q.
(3)Difference attributable to elimination in consolidation of WES Operating's
distributions on partnership interests owned by WES. See Note 4-Partnership
Distributions and Note 5-Equity and Partners' Capital in the Notes to
Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Noncontrolling interest. WES Operating's noncontrolling interest consists of the
25% third-party interest in Chipeta. See Note 1-Description of Business and
Basis of Presentation in the Notes to Consolidated Financial Statements under
Part I, Item 1 of this Form 10-Q.
WES Operating distributions. 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 I,
Item 1 of this Form 10-Q.
CRITICAL ACCOUNTING ESTIMATES
The preparation of consolidated financial statements in accordance with GAAP
requires management to make informed judgments and estimates that affect the
amounts of assets and liabilities as of the date of the financial statements and
the amounts of revenues and expenses recognized during the periods reported.
There have been no significant changes to our critical accounting estimates from
those disclosed in our annual report on Form 10-K for the fiscal year ended
December 31, 2020 .
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