Table of Contents


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017March 31, 2024

Or
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to      
Commission file number: 001-35753
WESTERN GAS EQUITY PARTNERS, LP
(Exact name of registrant as specified in its charter)
WESTERN MIDSTREAM PARTNERS, LP
WESTERN MIDSTREAM OPERATING, LP
(Exact name of registrant as specified in its charter)
Commission file number:
Delaware46-0967367
(State or other jurisdiction of
incorporation or organization)
organization:
(I.R.S. Employer
Identification No.)
:
Western Midstream Partners, LP001-35753Delaware46-0967367
1201 Lake Robbins Drive
The Woodlands, Texas
Western Midstream Operating, LP
001-3404677380
(Address of principal executive offices)Delaware(Zip Code)26-1075808
Address of principal executive offices:Zip Code:Registrant’s telephone number, including area code:
Western Midstream Partners, LP9950 Woodloch Forest Drive, Suite 2800The Woodlands,Texas77380(346)786-5000
Western Midstream Operating, LP9950 Woodloch Forest Drive, Suite 2800The Woodlands,Texas77380(346)786-5000
(832) 636-6000
(Registrant’s telephone number, including area code)Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading symbolName of exchange
on which registered
Common units outstanding as of May 3, 2024:
Western Midstream Partners, LPCommon unitsWESNew York Stock Exchange380,490,963
Western Midstream Operating, LPNoneNoneNoneNone
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨
Western Midstream Partners, LPYesþNo¨
Western Midstream Operating, LPYesþNo¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-TS-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨
Western Midstream Partners, LPYesþNo¨
Western Midstream Operating, LPYesþNo¨




Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-acceleratednon-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-212b-2 of the Exchange Act.
Western Midstream Partners, LPLarge Accelerated FilerAccelerated FilerNon-accelerated FilerSmaller Reporting CompanyEmerging Growth Company
þ
Western Midstream Operating, LP
Large accelerated filer þAccelerated FilerAccelerated Filer
Accelerated filer ¨
Non-accelerated Filer
Smaller Reporting Company
Non-accelerated filer ¨
Smaller reporting company ¨
Emerging growth company ¨
Growth Company
þ(Do not check if a smaller reporting company)
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.¨
Western Midstream Partners, LP¨
Western Midstream Operating, LP¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-212b-2 of the Exchange Act).    Yes  ¨    No  þ
There were 218,933,141 common units outstanding
Western Midstream Partners, LPYesNoþ
Western Midstream Operating, LPYesNoþ

FILING FORMAT

This quarterly report on Form 10-Q is a combined report being filed by two separate registrants: Western Midstream Partners, LP and Western Midstream Operating, LP. Western Midstream Operating, LP is a consolidated subsidiary of Western Midstream Partners, LP that has publicly traded debt, but does not have any publicly traded equity securities. Information contained herein related to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrant.

Part I, Item 1 of October 30, 2017.


TABLE OF CONTENTS

this quarterly report includes separate financial statements (i.e., consolidated statements of operations, consolidated balance sheets, consolidated statements of equity and partners’ capital, and consolidated statements of cash flows) for Western Midstream Partners, LP and Western Midstream Operating, LP. The accompanying Notes to Consolidated Financial Statements, which are included under Part I, Item 1 of this quarterly report, and Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is included under Part I, Item 2 of this quarterly report, are presented on a combined basis for each registrant, with any material differences between the registrants disclosed separately.



TABLE OF CONTENTS
PAGE
PAGE
PART I
Item 1.
Item 2.
Item 3.
Item 4.
PART II
Item 1.
Item 1A.
Item 6.2.
Item 5.
Item 6.

3



COMMONLY USED TERMSABBREVIATIONS AND DEFINITIONSTERMS


Western Gas Equity Partners, LP (“WGP”) is a Delaware master limited partnership formed by Anadarko Petroleum CorporationReferences to own three types of partnership interests in Western Gas Partners, LP and its subsidiaries (“WES”). For purposes of this Form 10-Q, “WGP,” “we,” “us,” “our,” “Western Gas Equity Partners,“WES,” “the Partnership,” or like terms refers“Western Midstream Partners, LP” refer to Western Midstream Partners, LP (formerly Western Gas Equity Partners, LP in its individual capacity or to Western Gas Equity Partners, LPLP) and its subsidiaries, including the general partnersubsidiaries. The following list of WES, Western Gas Holdings, LLC,abbreviations and WES, as the context requires. Asterms are used in this Form 10-Q, the identified terms and definitions below have the following meanings:document:
Additional DBJV System Interest: WES’s additional 50% interest in the DBJV system acquired from a third party in March 2017.
Affiliates: Subsidiaries
Defined TermDefinition
AnadarkoAnadarko Petroleum Corporation and its subsidiaries, excluding our general partner, which became a wholly owned subsidiary of Occidental upon closing of the Occidental Merger on August 8, 2019.
Barrel, Bbl, Bbls/d, MBbls/d42 U.S. gallons measured at 60 degrees Fahrenheit, barrels per day, thousand barrels per day.
BoardThe board of directors of WES’s general partner.
ChipetaChipeta Processing, LLC, in which we are the managing member of and own a 75% interest.
CondensateA natural-gas liquid with a low vapor pressure compared to drip condensate, mainly composed of propane, butane, pentane, and heavier hydrocarbon fractions.
DBM water systemsProduced-water gathering and disposal systems in West Texas.
DJ Basin complexThe Platte Valley, Fort Lupton, Wattenberg, Lancaster, and Latham processing plants, and the Wattenberg gathering system.
EBITDA
Earnings before interest, taxes, depreciation, and amortization. For a definition of “Adjusted EBITDA,” see Reconciliation of Non-GAAP Financial Measures under Part I, Item 2 of this Form 10-Q.
Exchange ActThe Securities Exchange Act of 1934, as amended.
FRPFront Range Pipeline LLC, in which we own a 33.33% interest.
GAAPGenerally accepted accounting principles in the United States.
General partnerWestern Midstream Holdings, LLC, the general partner of the Partnership.
ImbalanceImbalances result from (i) differences between gas and NGLs volumes nominated by customers and gas and NGLs volumes received from those customers and (ii) differences between gas and NGLs volumes received from customers and gas and NGLs volumes delivered to those customers.
Marcellus Interest
The 33.75% interest in the Larry’s Creek, Seely, and Warrensville gas-gathering systems and related facilities located in northern Pennsylvania that we sold in April 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q).
Mcf, MMcf, MMcf/dThousand cubic feet, million cubic feet, million cubic feet per day.
MeritageMeritage Midstream Services II, LLC, which was acquired by the Partnership on October 13, 2023.
Mi VidaMi Vida JV LLC, in which we own a 50% interest.
MLPMaster limited partnership.
Mont Belvieu JV
Enterprise EF78 LLC, in which we owned a 25% interest that we sold in February 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q).
Natural-gas liquid(s) or NGL(s)The combination of ethane, propane, normal butane, isobutane, and natural gasolines that, when removed from natural gas, become liquid under various levels of pressure and temperature.
OccidentalOccidental Petroleum Corporation and, as the context requires, its subsidiaries, excluding our general partner.
Panola
Panola Pipeline Company, LLC, in which we owned a 15% interest that we sold in March 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q).
Powder River Basin complex
The Hilight system and assets acquired from Meritage, which includes a gathering system, processing plants, and the Thunder Creek NGL pipeline (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q).
Produced waterByproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs.
RCFWES Operating’s $2.0 billion senior unsecured revolving credit facility.
Red Bluff ExpressRed Bluff Express Pipeline, LLC, in which we own a 30% interest.
Related parties
Occidental, the Partnership’s equity interests (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q), and the Partnership and WES Operating for transactions that eliminate upon consolidation.
RendezvousRendezvous Gas Services, LLC, in which we own a 22% interest.
4


Defined TermDefinition
Residue
The natural gas remaining after the unprocessed natural-gas stream has been processed or treated.
Saddlehorn
Saddlehorn Pipeline Company, LLC, in which we owned a 20% interest that we sold in March 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q).
SECU.S. Securities and Exchange Commission.
Services AgreementThat certain amended and restated Services, Secondment, and Employee Transfer Agreement, dated as of December 31, 2019, by and among Occidental, Anadarko, and WES Operating GP.
Skim oilA crude-oil byproduct that is recovered during the produced-water gathering and disposal process.
Springfield system
The Springfield gas-gathering system and Springfield oil-gathering system.
TEGTexas Express Gathering LLC, in which we own a 20% interest.
TEPTexas Express Pipeline LLC, in which we own a 20% interest.
WES OperatingWestern Midstream Operating, LP, formerly known as Western Gas Partners, LP, and its subsidiaries.
WES Operating GPWestern Midstream Operating GP, LLC, the general partner of WES Operating.
West Texas complexThe Delaware Basin Midstream complex and DBJV and Haley systems.
WGRAHWGR Asset Holding Company LLC, a subsidiary of Occidental.
White CliffsWhite Cliffs Pipeline, LLC, in which we own a 10% interest.
Whitethorn LLC
Whitethorn Pipeline Company LLC, in which we owned a 20% interest that we sold in February 2024 (see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q).
Whitethorn
A crude-oil and condensate pipeline, and related storage facilities, owned by Whitethorn LLC.
$1.25 billion Purchase ProgramThe $1.25 billion buyback program ending December 31, 2024. The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions.

5

Table of Anadarko, excluding us, but including equity interests in Fort Union, White Cliffs, Rendezvous, the Mont Belvieu JV, TEP, TEG, and FRP.Contents
Anadarko: Anadarko Petroleum Corporation and its subsidiaries, excluding us and WGP GP.
Barrel or Bbl: 42 U.S. gallons measured at 60 degrees Fahrenheit.
Bbls/d: Barrels per day.
Board of Directors or Board: The board of directors of WGP GP.
Btu: British thermal unit; the approximate amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Chipeta: Chipeta Processing, LLC.
Condensate: A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
COP: Continuous offering programs.
Cryogenic: The process in which liquefied gases are used to bring natural gas volumes to very low temperatures (below approximately -238 degrees Fahrenheit) to separate natural gas liquids from natural gas. Through cryogenic processing, more natural gas liquids are extracted than when traditional refrigeration methods are used.
DBJV: Delaware Basin JV Gathering LLC.
DBJV system: A gathering system and related facilities located in the Delaware Basin in Loving, Ward, Winkler and Reeves Counties in West Texas.
DBM: Delaware Basin Midstream, LLC.
DBM complex: The cryogenic processing plants, gas gathering system, and related facilities and equipment in West Texas that serve production from Reeves, Loving and Culberson Counties, Texas and Eddy and Lea Counties, New Mexico.
DBM water systems: Two produced-water disposal systems in West Texas.
DJ Basin complex: The Platte Valley system, Wattenberg system and Lancaster plant, all of which were combined into a single complex in the first quarter of 2014.
EBITDA: Earnings before interest, taxes, depreciation, and amortization. For a definition of “Adjusted EBITDA,” see the caption Key Performance Metrics under Part I, Item 2 of this Form 10-Q.
Equity investment throughput: WES’s 14.81% share of average Fort Union throughput, 22% share of average Rendezvous throughput, 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEP and TEG throughput and 33.33% share of average FRP throughput.
Exchange Act: The Securities Exchange Act of 1934, as amended.

Fort Union: Fort Union Gas Gathering, LLC.
Fractionation: The process of applying various levels of higher pressure and lower temperature to separate a stream of natural gas liquids into ethane, propane, normal butane, isobutane and natural gasoline for end-use sale.
FRP: Front Range Pipeline LLC.
GAAP: Generally accepted accounting principles in the United States.
Hydraulic fracturing: The injection of fluids into the wellbore to create fractures in rock formations, stimulating the production of oil or gas.
Imbalance: Imbalances result from (i) differences between gas and NGL volumes nominated by customers and gas and NGL volumes received from those customers and (ii) differences between gas and NGL volumes received from customers and gas and NGL volumes delivered to those customers.
IPO: Initial public offering.
LIBOR: London Interbank Offered Rate.
Marcellus Interest: WES’s 33.75% interest in the Larry’s Creek, Seely and Warrensville gas gathering systems and related facilities located in northern Pennsylvania. Formerly defined as the “Anadarko-Operated Marcellus Interest”.
MBbls/d: One thousand barrels per day.
MGR: Mountain Gas Resources, LLC.
MGR assets: The Red Desert complex and the Granger straddle plant.
MLP: Master limited partnership.
MMBtu: One million British thermal units.
MMcf: One million cubic feet.
MMcf/d: One million cubic feet per day.
Mont Belvieu JV: Enterprise EF78 LLC.
Natural gas liquid(s) or NGL(s): The combination of ethane, propane, normal butane, isobutane and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.
Non-Operated Marcellus Interest: The 33.75% interest in the Liberty and Rome gas gathering systems and related facilities located in northern Pennsylvania that was transferred to a third party in March 2017 pursuant to the Property Exchange.
Produced water: Byproduct associated with the production of crude oil and natural gas that often contains a number of dissolved solids and other materials found in oil and gas reservoirs.
Property Exchange: WES’s acquisition of the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration, as further described in our Forms 8-K filed with the SEC on February 9, 2017, and March 23, 2017.
Red Desert complex: The Patrick Draw processing plant, the Red Desert processing plant, associated gathering lines, and related facilities.
Rendezvous: Rendezvous Gas Services, LLC.
Residue: The natural gas remaining after the unprocessed natural gas stream has been processed or treated.

SEC: U.S. Securities and Exchange Commission.
Springfield: Springfield Pipeline LLC.
Springfield interest: Springfield’s 50.1% interest in the Springfield system.
Springfield gas gathering system: A gas gathering system and related facilities located in Dimmit, La Salle, Maverick and Webb Counties in South Texas.
Springfield oil gathering system: An oil gathering system and related facilities located in Dimmit, La Salle, Maverick and Webb Counties in South Texas.
Springfield system: The Springfield gas gathering system and Springfield oil gathering system.
TEFR Interests: The interests in TEP, TEG and FRP.
TEG: Texas Express Gathering LLC.
TEP: Texas Express Pipeline LLC.
TEUs: 7.50% Tangible equity units.
WES: Western Gas Partners, LP.
WES GP: Western Gas Holdings, LLC, the general partner of WES.
WES RCF: WES’s senior unsecured revolving credit facility.
WGP: Western Gas Equity Partners, LP.
WGP GP or general partner: Western Gas Equity Holdings, LLC, the general partner of WGP.
WGP RCF: The WGP senior secured revolving credit facility.
WGP LTIP: Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan.
WGP WCF: The WGP working capital facility.
White Cliffs: White Cliffs Pipeline, LLC.
2018 Notes: WES’s 2.600% Senior Notes due 2018.
2021 Notes: WES’s 5.375% Senior Notes due 2021.
2022 Notes: WES’s 4.000% Senior Notes due 2022.
2025 Notes: WES’s 3.950% Senior Notes due 2025.
2026 Notes: WES’s 4.650% Senior Notes due 2026.
2044 Notes: WES’s 5.450% Senior Notes due 2044.
$500.0 million COP: WES’s COP contemplated by the registration statement filed with the SEC in July 2017 authorizing the issuance of up to an aggregate of $500.0 million of WES common units.


PART I.FINANCIAL INFORMATION (UNAUDITED)


Item 1.Financial Statements


WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended 
March 31,
thousands except per-unit amounts20242023
Revenues and other
Service revenues – fee based$781,262 $647,867 
Service revenues – product based66,740 46,810 
Product sales39,292 39,025 
Other435 280 
Total revenues and other (1)
887,729 733,982 
Equity income, net – related parties32,819 39,021 
Operating expenses
Cost of product46,079 51,459 
Operation and maintenance194,939 174,239 
General and administrative67,839 51,117 
Property and other taxes13,920 6,831 
Depreciation and amortization157,991 144,626 
Long-lived asset and other impairments (2)
23 52,401 
Total operating expenses (3)
480,791 480,673 
Gain (loss) on divestiture and other, net239,617 (2,118)
Operating income (loss)679,374 290,212 
Interest expense(94,506)(81,670)
Gain (loss) on early extinguishment of debt524 — 
Other income (expense), net2,346 1,215 
Income (loss) before income taxes587,738 209,757 
Income tax expense (benefit)1,522 1,416 
Net income (loss)586,216 208,341 
Net income (loss) attributable to noncontrolling interests13,386 4,696 
Net income (loss) attributable to Western Midstream Partners, LP$572,830 $203,645 
Limited partners’ interest in net income (loss):
Net income (loss) attributable to Western Midstream Partners, LP$572,830 $203,645 
General partner interest in net (income) loss(13,330)(4,686)
Limited partners’ interest in net income (loss) (4)
559,500 198,959 
Net income (loss) per common unit – basic (4)
$1.47 $0.52 
Net income (loss) per common unit – diluted (4)
$1.47 $0.52 
Weighted-average common units outstanding – basic (4)
380,024 384,468 
Weighted-average common units outstanding – diluted (4)
381,628 385,750 

  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands except per-unit amounts 2017 2016 2017 2016
Revenues and other – affiliates        
Gathering, processing and transportation $157,303
 $189,465
 $484,601
 $563,916
Natural gas and natural gas liquids sales 185,002
 135,847
 489,172
 336,385
Other 8,822
 
 8,822
 
Total revenues and other – affiliates 351,127
 325,312
 982,595
 900,301
Revenues and other – third parties        
Gathering, processing and transportation 148,884
 125,727
 428,835
 346,416
Natural gas and natural gas liquids sales 74,139
 28,189
 201,318
 43,200
Other 545
 2,417
 3,590
 3,533
Total revenues and other – third parties 223,568
 156,333
 633,743
 393,149
Total revenues and other 574,695
 481,645
 1,616,338
 1,293,450
Equity income, net – affiliates 21,519
 20,294
 62,708
 56,801
Operating expenses        
Cost of product (1)
 239,223
 145,643
 631,859
 326,959
Operation and maintenance (1)
 79,536
 74,755
 229,444
 226,141
General and administrative (1)
 12,922
 12,112
 37,595
 36,514
Property and other taxes 11,215
 10,670
 35,433
 33,113
Depreciation and amortization 72,539
 67,246
 216,272
 199,646
Impairments 2,159
 2,392
 170,079
 11,313
Total operating expenses 417,594
 312,818
 1,320,682
 833,686
Gain (loss) on divestiture and other, net 72
 (6,230) 135,017
 (8,769)
Proceeds from business interruption insurance claims 
 13,667
 29,882
 16,270
Operating income (loss) 178,692
 196,558
 523,263
 524,066
Interest income – affiliates 4,225
 4,225
 12,675
 12,675
Interest expense (2)
 (36,117) (31,301) (108,447) (76,869)
Other income (expense), net 311
 165
 1,029
 270
Income (loss) before income taxes 147,111
 169,647
 428,520
 460,142
Income tax (benefit) expense 510
 472
 4,905
 7,431
Net income (loss) 146,601
 169,175
 423,615
 452,711
Net income (loss) attributable to noncontrolling interests 50,399
 77,778
 146,529
 190,635
Net income (loss) attributable to Western Gas Equity Partners, LP $96,202
 $91,397
 $277,086
 $262,076
Limited partners’ interest in net income (loss):        
Net income (loss) attributable to Western Gas Equity Partners, LP $96,202
 $91,397
 $277,086
 $262,076
Pre-acquisition net (income) loss allocated to Anadarko 
 
 
 (11,326)
Limited partners’ interest in net income (loss) (3)
 96,202

91,397
 277,086
 250,750
Net income (loss) per common unit – basic and diluted $0.44
 $0.42
 $1.27
 $1.15
Weighted-average common units outstanding – basic and diluted 218,933
 218,922
 218,931
 218,921
(1)Total revenues and other includes related-party amounts of $499.8 million and $448.8 million for the three months ended March 31, 2024 and 2023, respectively. See Note 6.
(2)See Note 8.
(3)Total operating expenses includes related-party amounts of $(26.0) million and $(3.1) million for the three months ended March 31, 2024 and 2023, respectively, all primarily related to changes in imbalance positions. See Note 6.
(4)See Note 5.
6

WESTERN MIDSTREAM PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
thousands except number of unitsMarch 31,
2024
December 31,
2023
ASSETS
Current assets
Cash and cash equivalents$295,246 $272,787 
Accounts receivable, net720,351 666,637 
Other current assets50,750 52,986 
Total current assets1,066,347 992,410 
Property, plant, and equipment
Cost15,157,635 14,945,431 
Less accumulated depreciation5,432,343 5,290,415 
Net property, plant, and equipment9,725,292 9,655,016 
Goodwill4,783 4,783 
Other intangible assets673,491 681,408 
Equity investments546,078 904,535 
Other assets (1)
249,479 233,455 
Total assets (2)
$12,265,470 $12,471,607 
LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables$377,499 $362,451 
Short-term debt
108,394 617,748 
Accrued ad valorem taxes48,525 61,285 
Accrued liabilities173,721 262,572 
Total current liabilities708,139 1,304,056 
Long-term liabilities
Long-term debt
7,272,079 7,283,556 
Deferred income taxes15,698 15,468 
Asset retirement obligations366,755 359,185 
Other liabilities526,508 480,212 
Total long-term liabilities
8,181,040 8,138,421 
Total liabilities (3)
8,889,179 9,442,477 
Equity and partners’ capital
Common units (380,490,138 and 379,519,983 units issued and outstanding at March 31, 2024, and December 31, 2023, respectively)3,225,562 2,894,231 
General partner units (9,060,641 units issued and outstanding at March 31, 2024, and December 31, 2023)11,313 3,193 
Total partners’ capital3,236,875 2,897,424 
Noncontrolling interests139,416 131,706 
Total equity and partners’ capital3,376,291 3,029,130 
Total liabilities, equity, and partners’ capital$12,265,470 $12,471,607 

(1)Other assets includes $5.5 million and $5.7 million of NGLs line-fill inventory as of March 31, 2024, and December 31, 2023, respectively. Other assets also includes $107.1 million and $96.3 million of materials and supplies inventory as of March 31, 2024, and December 31, 2023, respectively.
(2)Total assets includes related-party amounts of $982.6 million and $1.3 billion as of March 31, 2024, and December 31, 2023, respectively, which includes related-party Accounts receivable, net of $389.7 million and $358.1 million as of March 31, 2024, and December 31, 2023, respectively. See Note 6.
(3)Total liabilities includes related-party amounts of $406.4 million and $378.8 million as of March 31, 2024, and December 31, 2023, respectively. See Note 6.

(1)
Cost of product includes product purchases from Anadarko (as defined in Note 1) of $22.9 million and $60.5 million for the three and nine months ended September 30, 2017, respectively, and $21.3 million and $68.0 million for the three and nine months ended September 30, 2016, respectively. Operation and maintenance includes charges from Anadarko of $18.1 million and $53.7 million for the three and nine months ended September 30, 2017, respectively, and $15.1 million and $50.7 million for the three and nine months ended September 30, 2016, respectively. General and administrative includes charges from Anadarko of $10.4 million and $29.6 million for the three and nine months ended September 30, 2017, respectively, and $9.7 million and $28.2 million for the three and nine months ended September 30, 2016, respectively. See Note 5.
(2)
Includes affiliate (as defined in Note 1) amounts of zero and $(0.1) million for the three and nine months ended September 30, 2017, respectively, and $1.2 million and $12.1 million for the three and nine months ended September 30, 2016, respectively. See Note 2 and Note 9.
(3)
Represents net income (loss) earned on and subsequent to the date of acquisition of WES assets (as defined in Note 1). See Note 4.

See accompanying Notes to Consolidated Financial Statements.

7
6

Table of Contents

WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP
CONSOLIDATED BALANCE SHEETSSTATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
(UNAUDITED)
Partners’ Capital
thousandsCommon
Units
General Partner
Units
Noncontrolling
Interests
Total
Balance at December 31, 2023$2,894,231 $3,193 $131,706 $3,029,130 
Net income (loss)559,500 13,330 13,386 586,216 
Distributions to Chipeta noncontrolling interest owner  (1,085)(1,085)
Distributions to noncontrolling interest owner of WES Operating  (4,591)(4,591)
Distributions to Partnership unitholders(218,228)(5,210) (223,438)
Equity-based compensation expense
9,423   9,423 
Other(19,364)  (19,364)
Balance at March 31, 2024$3,225,562 $11,313 $139,416 $3,376,291 
thousands except number of units September 30, 
 2017
 December 31, 
 2016
ASSETS    
Current assets    
Cash and cash equivalents $153,036
 $359,072
Accounts receivable, net (1)
 192,437
 223,021
Other current assets 13,497
 13,498
Total current assets 358,970
 595,591
Note receivable – Anadarko 260,000
 260,000
Property, plant and equipment    
Cost 7,582,178
 6,861,942
Less accumulated depreciation 2,074,464
 1,812,010
Net property, plant and equipment 5,507,714
 5,049,932
Goodwill 417,610
 417,610
Other intangible assets 782,376
 803,698
Equity investments 573,622
 594,208
Other assets 15,627
 15,058
Total assets $7,915,919
 $7,736,097
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL    
Current liabilities    
Accounts and imbalance payables (2)
 $302,848
 $247,076
Accrued ad valorem taxes 33,020
 23,121
Accrued liabilities (3)
 57,699
 45,190
Total current liabilities 393,567
 315,387
Long-term debt 3,371,886
 3,119,461
Deferred income taxes 10,284
 6,402
Asset retirement obligations and other 146,248
 142,641
Deferred purchase price obligation – Anadarko (4)
 
 41,440
Total long-term liabilities 3,528,418
 3,309,944
Total liabilities 3,921,985
 3,625,331
Equity and partners’ capital    
Common units (218,933,141 and 218,928,570 units issued and outstanding at September 30, 2017, and December 31, 2016, respectively) 1,067,269
 1,048,143
Total partners’ capital 1,067,269
 1,048,143
Noncontrolling interests 2,926,665
 3,062,623
Total equity and partners’ capital 3,993,934
 4,110,766
Total liabilities, equity and partners’ capital $7,915,919
 $7,736,097

Partners’ Capital
thousandsCommon
Units
General Partner
Units
Noncontrolling
Interests
Total
Balance at December 31, 2022$2,969,604 $2,105 $136,406 $3,108,115 
Net income (loss)198,959 4,686 4,696 208,341 
Distributions to Chipeta noncontrolling interest owner— — (2,240)(2,240)
Distributions to noncontrolling interest owner of WES Operating— — (4,271)(4,271)
Distributions to Partnership unitholders(192,039)(4,530)— (196,569)
Unit repurchases (1)
(7,061)— — (7,061)
Equity-based compensation expense
7,199 — — 7,199 
Other(11,950)— — (11,950)
Balance at March 31, 2023$2,964,712 $2,261 $134,591 $3,101,564 

(1)See Note 5.
(1)
Accounts receivable, net includes amounts receivable from affiliates (as defined in Note 1) of $78.3 million and $76.4 million as of September 30, 2017, and December 31, 2016, respectively. Accounts receivable, net as of December 31, 2016, also includes an insurance claim receivable related to an incident at the DBM complex. See Note 1.
(2)
Accounts and imbalance payables includes affiliate amounts of $0.2 millionand zero as of September 30, 2017, and December 31, 2016, respectively.
(3)
Accrued liabilities includes affiliate amounts of $0.3 millionand zero as of September 30, 2017, and December 31, 2016, respectively.
(4)
See Note 2.

See accompanying Notes to Consolidated Financial Statements.

8
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WESTERN GAS EQUITY PARTNERS, LP
CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL
(UNAUDITED)
  Partners’ Capital    
thousands 
Net
Investment
by Anadarko
 
Common
Units
 
Noncontrolling
Interests
 Total
Balance at December 31, 2016 $
 $1,048,143
 $3,062,623
 $4,110,766
Net income (loss) 
 277,086
 146,529
 423,615
Above-market component of swap agreements with Anadarko (1)
 
 46,719
 
 46,719
WES equity transactions, net (2)
 
 10,800
 (10,983) (183)
Distributions to Chipeta noncontrolling interest owner 
 
 (9,049) (9,049)
Distributions to noncontrolling interest owners of WES 
 
 (262,888) (262,888)
Distributions to WGP unitholders 
 (324,290) 
 (324,290)
Acquisitions from affiliates (30) 30
 
 
Revision to Deferred purchase price obligation – Anadarko (3)
 
 4,165
 
 4,165
Contributions of equity-based compensation to WES by Anadarko 
 3,333
 
 3,333
Net pre-acquisition contributions from (distributions to) Anadarko 30
 
 
 30
Net contributions from (distributions to) Anadarko of other assets 
 1,373
 
 1,373
Other 
 (90) 433
 343
Balance at September 30, 2017 $
 $1,067,269
 $2,926,665
 $3,993,934
(1)
See Note 5.
(2)
Includes the impact of WES’s (as defined in Note 1) equity offerings as described in Note 4. The $10.8 million increase to partners’ capital, together with net income (loss) attributable to Western Gas Equity Partners, LP, totaled $287.9 million for the nine months ended September 30, 2017.
(3)
See Note 2.


See accompanying Notes to Consolidated Financial Statements.

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WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 Three Months Ended 
March 31,
thousands20242023
Cash flows from operating activities
Net income (loss)$586,216 $208,341 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization157,991 144,626 
Long-lived asset and other impairments
23 52,401 
Non-cash equity-based compensation expense
9,423 7,199 
Deferred income taxes230 924 
Accretion and amortization of long-term obligations, net
2,190 1,692 
Equity income, net – related parties(32,819)(39,021)
Distributions from equity-investment earnings – related parties
29,304 39,609 
(Gain) loss on divestiture and other, net(239,617)2,118 
(Gain) loss on early extinguishment of debt(524)— 
Other112 200 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net(53,714)(4,037)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net(100,383)(136,460)
Change in other items, net41,276 24,832 
Net cash provided by operating activities399,708 302,424 
Cash flows from investing activities
Capital expenditures(193,789)(173,088)
Acquisitions from third parties(443)— 
Contributions to equity investments – related parties (110)
Distributions from equity investments in excess of cumulative earnings – related parties19,033 12,366 
Proceeds from the sale of assets to third parties582,739 — 
(Increase) decrease in materials and supplies inventory and other(10,691)(18,346)
Net cash provided by (used in) investing activities396,849 (179,178)
Cash flows from financing activities
Borrowings, net of debt issuance costs 220,000 
Repayments of debt(14,503)(313,138)
Commercial paper borrowings (repayments), net(510,379)— 
Increase (decrease) in outstanding checks766 18,768 
Distributions to Partnership unitholders (1)
(223,438)(196,569)
Distributions to Chipeta noncontrolling interest owner(1,085)(2,240)
Distributions to noncontrolling interest owner of WES Operating(4,591)(4,271)
Unit repurchases (7,061)
Other(20,868)(12,746)
Net cash provided by (used in) financing activities(774,098)(297,257)
Net increase (decrease) in cash and cash equivalents22,459 (174,011)
Cash and cash equivalents at beginning of period272,787 286,656 
Cash and cash equivalents at end of period$295,246 $112,645 
Supplemental disclosures
Interest paid, net of capitalized interest$130,885 $133,245 
Income taxes paid (reimbursements received) 1,270 
Accrued capital expenditures116,751 91,067 

(1)Includes related-party amounts. See Note 6.
  Nine Months Ended September 30,
thousands 2017 2016
Cash flows from operating activities    
Net income (loss) $423,615
 $452,711
Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
Depreciation and amortization 216,272
 199,646
Impairments 170,079
 11,313
Non-cash equity-based compensation expense 3,751
 3,759
Deferred income taxes 3,882
 2,321
Accretion and amortization of long-term obligations, net 3,701
 (8,820)
Equity income, net – affiliates (62,708) (56,801)
Distributions from equity investment earnings – affiliates 64,313
 59,671
(Gain) loss on divestiture and other, net (135,017) 8,769
Lower of cost or market inventory adjustments 140
 41
Changes in assets and liabilities:    
(Increase) decrease in accounts receivable, net (47,137) (41,266)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net 4,127
 24,227
Change in other items, net (2,549) (871)
Net cash provided by operating activities 642,469

654,700
Cash flows from investing activities    
Capital expenditures (419,193) (372,725)
Contributions in aid of construction costs from affiliates 1,386
 4,927
Acquisitions from affiliates (3,910) (716,465)
Acquisitions from third parties (155,298) 
Investments in equity affiliates (384) 139
Distributions from equity investments in excess of cumulative earnings – affiliates 16,255
 16,592
Proceeds from the sale of assets to affiliates 
 623
Proceeds from the sale of assets to third parties 23,370
 7,819
Proceeds from property insurance claims 22,977
 18,398
Net cash used in investing activities (514,797)
(1,040,692)
Cash flows from financing activities    
Borrowings, net of debt issuance costs 249,989
 1,120,580
Repayments of debt 
 (880,000)
Settlement of the Deferred purchase price obligation – Anadarko (1)
 (37,346) 
Increase (decrease) in outstanding checks 3,310
 (1,070)
Proceeds from the issuance of WES common units, net of offering expenses (183) 
Proceeds from the issuance of WES Series A Preferred units, net of offering expenses 
 686,937
Distributions to WGP unitholders (2)
 (324,290) (276,114)
Distributions to Chipeta noncontrolling interest owner (9,049) (11,257)
Distributions to noncontrolling interest owners of WES (262,888) (211,877)
Net contributions from (distributions to) Anadarko 30
 (29,335)
Above-market component of swap agreements with Anadarko (2)
 46,719
 34,782
Net cash provided by (used in) financing activities (333,708)
432,646
Net increase (decrease) in cash and cash equivalents (206,036)
46,654
Cash and cash equivalents at beginning of period 359,072
 99,694
Cash and cash equivalents at end of period $153,036

$146,348
Supplemental disclosures    
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko (1)
 $(4,094) $(172,249)
Net distributions to (contributions from) Anadarko of other assets (1,373) 581
Interest paid, net of capitalized interest 98,956
 83,352
Taxes paid 189
 67
Accrued capital expenditures 165,732
 49,328
Fair value of properties and equipment from non-cash third party transactions (1)
 551,453
 
(1)
See Note 2.
(2)
See Note 5.

See accompanying Notes to Consolidated Financial Statements.

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Table of Contents
WESTERN GASMIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
 Three Months Ended 
March 31,
thousands20242023
Revenues and other
Service revenues – fee based$781,262 $647,867 
Service revenues – product based66,740 46,810 
Product sales39,292 39,025 
Other435 280 
Total revenues and other (1)
887,729 733,982 
Equity income, net – related parties32,819 39,021 
Operating expenses
Cost of product46,079 51,459 
Operation and maintenance194,939 174,239 
General and administrative67,479 50,885 
Property and other taxes13,920 6,831 
Depreciation and amortization157,991 144,626 
Long-lived asset and other impairments (2)
23 52,401 
Total operating expenses (3)
480,431 480,441 
Gain (loss) on divestiture and other, net239,617 (2,118)
Operating income (loss)679,734 290,444 
Interest expense(94,506)(81,670)
Gain (loss) on early extinguishment of debt524 — 
Other income (expense), net2,287 1,190 
Income (loss) before income taxes588,039 209,964 
Income tax expense (benefit)1,522 1,416 
Net income (loss)586,517 208,548 
Net income (loss) attributable to noncontrolling interest1,686 535 
Net income (loss) attributable to Western Midstream Operating, LP$584,831 $208,013 

(1)Total revenues and other includes related-party amounts of $499.8 million and $448.8 million for the three months ended March 31, 2024 and 2023, respectively. See Note 6.
(2)See Note 8.
(3)Total operating expenses includes related-party amounts of $(24.7) million and $(1.9) million for the three months ended March 31, 2024 and 2023, respectively, all primarily related to changes in imbalance positions. See Note 6.

See accompanying Notes to Consolidated Financial Statements.
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Table of Contents
WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
thousands except number of unitsMarch 31,
2024
December 31,
2023
ASSETS
Current assets
Cash and cash equivalents$289,464 $268,184 
Accounts receivable, net738,487 666,615 
Other current assets48,888 50,468 
Total current assets1,076,839 985,267 
Property, plant, and equipment
Cost15,157,635 14,945,431 
Less accumulated depreciation5,432,343 5,290,415 
Net property, plant, and equipment9,725,292 9,655,016 
Goodwill4,783 4,783 
Other intangible assets673,491 681,408 
Equity investments546,078 904,535 
Other assets (1)
246,053 231,644 
Total assets (2)
$12,272,536 $12,462,653 
LIABILITIES, EQUITY, AND PARTNERS’ CAPITAL
Current liabilities
Accounts and imbalance payables$377,358 $392,752 
Short-term debt
108,394 617,748 
Accrued ad valorem taxes48,525 61,285 
Accrued liabilities143,026 203,461 
Total current liabilities677,303 1,275,246 
Long-term liabilities
Long-term debt
7,272,079 7,283,556 
Deferred income taxes15,698 15,468 
Asset retirement obligations366,755 359,185 
Other liabilities523,083 476,844 
Total long-term liabilities
8,177,615 8,135,053 
Total liabilities (3)
8,854,918 9,410,299 
Equity and partners’ capital
Common units (318,675,578 units issued and outstanding at March 31, 2024, and December 31, 2023)3,391,694 3,027,031 
Total partners’ capital3,391,694 3,027,031 
Noncontrolling interest25,924 25,323 
Total equity and partners’ capital3,417,618 3,052,354 
Total liabilities, equity, and partners’ capital$12,272,536 $12,462,653 

(1)Other assets includes $5.5 million and $5.7 million of NGLs line-fill inventory as of March 31, 2024, and December 31, 2023, respectively. Other assets also includes $107.1 million and $96.3 million of materials and supplies inventory as of March 31, 2024, and December 31, 2023, respectively.
(2)Total assets includes related-party amounts of $997.3 million and $1.3 billion as of March 31, 2024, and December 31, 2023, respectively, which includes related-party Accounts receivable, net of $407.9 million and $358.1 million as of March 31, 2024, and December 31, 2023, respectively. See Note 6.
(3)Total liabilities includes related-party amounts of $406.0 million and $409.5 million as of March 31, 2024, and December 31, 2023, respectively. See Note 6.
See accompanying Notes to Consolidated Financial Statements.
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WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF EQUITY AND PARTNERS’ CAPITAL
(UNAUDITED)
thousandsCommon
Units
Noncontrolling
Interest
Total
Balance at December 31, 2023$3,027,031 $25,323 $3,052,354 
Net income (loss)584,831 1,686 586,517 
Distributions to Chipeta noncontrolling interest owner (1,085)(1,085)
Distributions to WES Operating unitholders(229,446) (229,446)
Contributions of equity-based compensation from WES
9,278  9,278 
Balance at March 31, 2024$3,391,694 $25,924 $3,417,618 

thousandsCommon
Units
Noncontrolling
Interest
Total
Balance at December 31, 2022$3,092,012 $28,095 $3,120,107 
Net income (loss)208,013 535 208,548 
Distributions to Chipeta noncontrolling interest owner— (2,240)(2,240)
Distributions to WES Operating unitholders(213,513)— (213,513)
Contributions of equity-based compensation from WES
7,058 — 7,058 
Balance at March 31, 2023$3,093,570 $26,390 $3,119,960 
See accompanying Notes to Consolidated Financial Statements.
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Table of Contents
WESTERN MIDSTREAM OPERATING, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 Three Months Ended 
March 31,
thousands20242023
Cash flows from operating activities
Net income (loss)$586,517 $208,548 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization157,991 144,626 
Long-lived asset and other impairments
23 52,401 
Non-cash equity-based compensation expense
9,278 7,058 
Deferred income taxes230 924 
Accretion and amortization of long-term obligations, net
2,190 1,692 
Equity income, net – related parties(32,819)(39,021)
Distributions from equity-investment earnings – related parties
29,304 39,609 
(Gain) loss on divestiture and other, net(239,617)2,118 
(Gain) loss on early extinguishment of debt(524)— 
Other112 200 
Changes in assets and liabilities:
(Increase) decrease in accounts receivable, net(71,872)(5,048)
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net(102,341)(148,148)
Change in other items, net42,177 26,009 
Net cash provided by operating activities380,649 290,968 
Cash flows from investing activities
Capital expenditures(193,789)(173,088)
Acquisitions from third parties(443)— 
Contributions to equity investments – related parties (110)
Distributions from equity investments in excess of cumulative earnings – related parties19,033 12,366 
Proceeds from the sale of assets to third parties582,739 — 
(Increase) decrease in materials and supplies inventory and other(10,691)(18,346)
Net cash provided by (used in) investing activities396,849 (179,178)
Cash flows from financing activities
Borrowings, net of debt issuance costs 220,000 
Repayments of debt(14,503)(313,138)
Commercial paper borrowings (repayments), net(510,379)— 
Increase (decrease) in outstanding checks699 18,726 
Distributions to WES Operating unitholders (1)
(229,446)(213,513)
Distributions to Chipeta noncontrolling interest owner(1,085)(2,240)
Other(1,504)(796)
Net cash provided by (used in) financing activities(756,218)(290,961)
Net increase (decrease) in cash and cash equivalents21,280 (179,171)
Cash and cash equivalents at beginning of period268,184 286,101 
Cash and cash equivalents at end of period$289,464 $106,930 
Supplemental disclosures
Interest paid, net of capitalized interest$130,885 $133,245 
Income taxes paid (reimbursements received) 1,270 
Accrued capital expenditures116,751 91,067 

(1)Includes related-party amounts. See Note 6.
See accompanying Notes to Consolidated Financial Statements.
13

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


1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION


General. Western Gas EquityMidstream Partners, LP is a Delaware master limited partnership (“MLP”) formed in September 2012 to own three types of partnership interests in2012. Western Gas Partners, LP. Western Gas Equity Partners, LP was formed by converting WGR Holdings, LLC into a limited partnership and changing its name. Western Gas Partners,Midstream Operating, LP (together with its subsidiaries, “WES”“WES Operating”) is a Delaware MLPlimited partnership formed by Anadarko Petroleum Corporation in 2007 to acquire, own, develop, and operate midstream energy assets. Western Midstream Partners, LP owns, directly and indirectly, a 98.0% limited partner interest in WES Operating, and directly owns all of the outstanding equity interests of Western Midstream Operating GP, LLC, which holds the entire non-economic general partner interest in WES Operating.
For purposes of these consolidated financial statements, “WGP”the “Partnership” refers to Western Gas EquityMidstream Partners, LP in its individual capacity or to Western Gas EquityMidstream Partners, LP and its subsidiaries, including Western Gas Holdings,Midstream Operating GP, LLC and WES Operating, as the context requires. “WES Operating GP” refers to Western Gas Holdings,Midstream Operating GP, LLC, individually as the general partner of WES and excludes WES. WGP’sOperating. The Partnership’s general partner, Western Gas EquityMidstream Holdings, LLC (“WGP GP”(the “general partner”), is a wholly owned subsidiary of AnadarkoOccidental Petroleum Corporation. WES GP owns all of“Occidental” refers to Occidental Petroleum Corporation, as the context requires, and its subsidiaries, excluding the general partner interest in WES, which constitutes substantially all of its business, which primarily is to manage the affairs and operations of WES. Refer to Note 4 for a discussion of WGP’s holdings of WES equity.partner. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding WGP and WGP GP, and “affiliates”Western Midstream Holdings, LLC. Anadarko became a wholly owned subsidiary of Occidental as a result of Occidental’s acquisition by merger of Anadarko on August 8, 2019. “Related parties” refers to subsidiariesOccidental (see Note 6), the Partnership’s investments accounted for under the equity method of Anadarko, excluding WGP, but including equity interests in Fort Union Gas Gathering, LLC (“Fort Union”accounting (see Note 7), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” “MGR assets” refers to the Red Desert complex and the Granger straddle plant.Partnership and WES Operating for transactions that eliminate upon consolidation (see Note 6).
WESThe Partnership is engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, natural-gas liquids (“NGLs”), and crude oil; and gathering and disposing of produced water. WES provides these midstream services for Anadarko,In its capacity as well as for third-party producersa natural-gas processor, the Partnership also buys and customers.sells natural gas, NGLs, and condensate on behalf of itself and its customers under certain contracts. As of September 30, 2017, WES’sMarch 31, 2024, the Partnership’s assets and investments consisted of the following:
Wholly
Owned and
Operated
Operated
Interests
Non-Operated
Interests
Equity
Interests
Gathering systems (1)
18 
Treating facilities38 — — 
Natural-gas processing plants/trains
24 — 
NGLs pipelines— — 
Natural-gas pipelines
— — 
Crude-oil pipelines
— 

(1)Includes the DBM water systems.
  
Owned and
Operated
 
Operated
Interests
 
Non-Operated
Interests
 
Equity
Interests
Gathering systems 12
 3
 3
 2
Treating facilities 19
 3
 
 3
Natural gas processing plants/trains 19
 5
 
 2
NGL pipelines 2
 
 
 3
Natural gas pipelines 5
 
 
 
Oil pipelines 
 1
 
 1


These assets and investments are located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), North-central Pennsylvania and Texas. During the second quarter of 2017, WES commenced operation of two produced-water disposal systems in West Texas, which are included within Gathering systems in the table above. Train VI, an additional processing plant at the DBM complex, is expected to commence operations during the fourth quarter of 2017.


North-central Pennsylvania.
10
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Table of Contents
WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)


Basis of presentation. The following table outlines WES’s ownership interests and the accounting method of consolidation used in WES’s consolidated financial statements:
Percentage Interest
Equity investments (1)
Fort Union14.81%
White Cliffs10%
Rendezvous22%
Mont Belvieu JV25%
TEP20%
TEG20%
FRP33.33%
Proportionate consolidation (2)
Marcellus Interest systems33.75%
Newcastle system50%
Springfield system50.1%
Full consolidation
Chipeta (3)
75%
DBJV system (4)
100%
(1)
Investments in non-controlled entities over which WES exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to WES’s share of average throughput for these investments.
(2)
WGP proportionately consolidates WES’s associated share of the assets, liabilities, revenues and expenses attributable to these assets.
(3)
The 25% interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interests in the consolidated financial statements, in addition to the noncontrolling interests noted below.
(4)
WES acquired an additional 50% interest in the DBJV system (the “Additional DBJV System Interest”) from a third party on March 17, 2017. See Note 2.

The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements and include the accounts of WGPthe Partnership and entities in which it holds a controlling financial interest, including WES Operating, WES Operating GP, proportionately consolidated interests, and WES GP.equity investments (see table below). All significant intercompany transactions have been eliminated.
The following table outlines the ownership interests and the accounting method of consolidation used in the consolidated financial statements for entities not wholly owned (see Note 7):
Percentage Interest
Full consolidation
Chipeta (1)
75.00 %
Proportionate consolidation (2)
Springfield system50.10 %
Marcellus Interest systems33.75 %
Equity investments(3)
Mi Vida JV LLC (“Mi Vida”)50.00 %
Front Range Pipeline LLC (“FRP”)33.33 %
Red Bluff Express Pipeline, LLC (“Red Bluff Express”)30.00 %
Rendezvous Gas Services, LLC (“Rendezvous”)22.00 %
Texas Express Pipeline LLC (“TEP”)20.00 %
Texas Express Gathering LLC (“TEG”)20.00 %
White Cliffs Pipeline, LLC (“White Cliffs”)10.00 %

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

Certain information and note disclosures commonly included in annual financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the accompanying consolidated financial statements and notes should be read in conjunction with WGP’s 2016the Partnership’s 2023 Form 10-K, as filed with the SEC on February 23, 2017.21, 2024. Management believes that the disclosures made are adequate to make the information not misleading.
The consolidated financial results of WES Operating are included in WGP’sthe Partnership’s consolidated financial statements due to WGP’s 100% ownership interest in WES GP and WES GP’s control of WES.statements. Throughout these notes to consolidated financial statements, and to the extent material, any differences between the consolidated financial results of WGPthe Partnership and WES Operating are discussed separately. WGP has no independent operations or material assets other than its partnership interests in WES. WGP’sThe Partnership’s consolidated financial statements differ from those of WES Operating primarily as a result of (i) the presentation of noncontrolling interest ownership (attributable to the limited partner(see Noncontrolling interests in WES held by the public, other subsidiaries of Anadarko and private investors, see Note 4) below), (ii) the elimination of WES Operating GP’s investment in WES Operating with WES Operating GP’s underlying capital account, (iii) the general and administrative expenses incurred by WGP,the Partnership, which are separate from, and in addition to, those incurred by WES Operating, (iv) the inclusion of the impact of WGPPartnership equity balances and WGPPartnership distributions, and (v) WGP’s senior secured revolving credit facility (“WGP RCF”). See Note 9.


transactions between the Partnership and WES Operating that eliminate upon consolidation.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)


Variable interest entity.WES is a variable interest entity (“VIE”) because the partners in WES with equity at risk lack the power, through voting or similar rights, to direct the activities that most significantly impact WES’s economic performance. A reporting entity that concludes it has a variable interest in a VIE must evaluate whether it has a controlling financial interest in the VIE, such that it is the VIE’s primary beneficiary and should consolidate. WGP is the primary beneficiary of WES and therefore should consolidate because (i) WGP has the power to direct the activities of WES that most significantly affect its economic performance and (ii) WGP has the right to receive benefits or the obligation to absorb losses that could be potentially significant to WES. As noted above, WGP has no independent operations or material assets other than its partnership interests in WES. The assets of WES cannot be used by WGP for general partnership purposes. WES’s long-term debt is recourse to WES GP, which is wholly owned by WGP. In turn, WES GP is indemnified by wholly owned subsidiaries of Anadarko for any claims made against WES GP under the indentures governing WES’s outstanding notes or borrowings under WES’s senior unsecured revolving credit facility (“WES RCF”). WES’s sources of liquidity include cash and cash equivalents, cash flows generated from operations, interest income on its $260.0 million note receivable from Anadarko, available borrowing capacity under the WES RCF, and issuances of additional equity or debt securities. As further discussed in Note 2, WGP purchased WES common units in connection with WES’s financing of an acquisition from Anadarko in March 2016.

Noncontrolling interests. WGP’s noncontrolling interests in the consolidated financial statements consistPresentation of the following for all periods presented: (i) the 25% interest in Chipeta held by a third-party member, (ii) the publicly held limited partner interests in WES, (iii) the 2,011,380 WES common units issued by WES to other subsidiaries of Anadarko as part of the consideration paid for the acquisitions of the Non-Operated Marcellus Interest, the TEFR Interests and Springfield, and (iv) the WES Class C units issued by WES to a subsidiary of Anadarko as part of the funding for the acquisition of Delaware Basin Midstream, LLC (“DBM”).Partnership’s assets. The WES Series A Preferred units issued to private investors as part of the funding of the Springfield acquisition were also noncontrolling interests in the consolidated financial statements until converted into WES common units in 2017. See Note 2 and Note 4.
When WES issues equity, the carrying amount of the noncontrolling interest reported by WGP is adjusted to reflect the noncontrolling ownership interest in WES. The resulting impact of such noncontrolling interest adjustment on WGP’s interest in WES is reflected as an adjustment to WGP’s partners’ capital.

Presentation of WES assets. The term “WES assets” includes both thePartnership’s assets indirectlyinclude assets owned and theownership interests accounted for by the Partnership under the equity method (see Note 7) by WGPof accounting, through its 98.0% partnership interestsinterest in WES Operating, as of September 30, 2017. Because WGPMarch 31, 2024 (see Note 7). The Partnership also owns and controls the entire non-economic general partner interest in and controls WES Operating GP, and WGP GPthe Partnership’s general partner is owned and controlled by Anadarko, each of WES’s acquisitions of WES assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, WES assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by WES. Further, after an acquisition of WES assets from Anadarko, WES and WGP (by virtue of its consolidation of WES) may be required to recast their financial statements to include the activities of such WES assets from the date of common control.Occidental.
For those periods requiring recast, the consolidated financial statements for periods prior to the acquisition of WES assets from Anadarko are prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if WES had owned the WES assets during the periods reported. Net income (loss) attributable to the WES assets acquired from Anadarko for periods prior to WES’s acquisition of the WES assets is not allocated to the limited partners.

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

Noncontrolling interests. The Partnership’s noncontrolling interests in the consolidated financial statements consist of (i) the 25% third-party interest in Chipeta and (ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary. WES Operating’s noncontrolling interest in the consolidated financial statements consists of the 25% third-party interest in Chipeta. See Note 5.

Segments. The Partnership’s operations continue to be organized into a single operating segment, the assets of which gather, compress, treat, process, and transport natural gas; gather, stabilize, and transport condensate, NGLs, and crude oil; and gather and dispose of produced water in the United States.
In November 2023, the Financial Accounting Standards Board issued Accounting Standards Update 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” The standard improves reportable segment disclosure requirements for public business entities primarily through enhanced disclosures about significant segment expenses that are regularly provided to the chief operating decision maker and included within each reported measure of segment profit (referred to as the “significant expense principle”). The standard will become effective for the Partnership for the fiscal year 2024 annual financial statements and certain prior-period amountsinterim financial statements thereafter and will be applied retrospectively for all prior periods presented in the financial statements, with early adoption permitted. The Partnership plans to adopt the standard when it becomes effective beginning with the fiscal year 2024 annual financial statements. The Partnership is currently evaluating the impact this guidance will have been reclassifiedon disclosures in the Notes to conformConsolidated Financial Statements. This standard will have no impact to the current-year presentation.Partnership’s financial statements, but will result in additional disclosure.



Equity-based compensation. During the three months ended March 31, 2024, the Partnership issued 970,155 common units under its long-term incentive plans. Compensation expense was $9.4 million and $7.2 million for the three months ended March 31, 2024 and 2023, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

2. REVENUE FROM CONTRACTS WITH CUSTOMERS
1.  DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)

The following table summarizes revenue from contracts with customers:
Insurance recoveries. Involuntary conversions result
 Three Months Ended 
March 31,
thousands20242023
Revenue from customers
Service revenues – fee based$781,262 $647,867 
Service revenues – product based66,740 46,810 
Product sales39,292 39,025 
Total revenue from customers887,294 733,702
Revenue from other than customers
Other435 280 
Total revenues and other$887,729 $733,982 

Contract balances. Receivables from the loss of an asset because of some unforeseen event (e.g., destruction due to fire). Some of these eventscustomers, which are insurable and resultincluded in property damage insurance recovery. Amounts that are received from insurance carriers areAccounts receivable, net of any deductibles related to the covered event. A receivable is recorded from insurance to the extent a loss is recognized from an involuntary conversion event and the likelihood of recovering such loss is deemed probable. To the extent that any insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. A gain on involuntary conversion is recognized when the amount received from insurance exceeds the net book value of the retired asset(s). In addition, gains related to insurance recoveries are not recognized until all contingencies related to such proceeds have been resolved, that is, a cash payment is received from the insurance carrier or there is a binding settlement agreement with the carrier that clearly states that a payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, in the consolidated balance sheets were $711.0 million and presented$661.6 million as capital expenditures in the consolidated statements of cash flows. With respect to business interruption insurance claims, income is recognized only when cash proceeds are received from insurers, which are presented in the consolidated statements of operations as a component of Operating income (loss).
On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. The majority of the damage from the incident was to the liquid handling facilities and the amine treating units at the inlet of the complex. Train II (with capacity of 100 MMcf/d) sustained the most damage of the processing trains and returned to service in December 2016. Train III (with capacity of 200 MMcf/d) experienced minimal damage and returned to full service in May 2016. During the quarter ended March 31, 2017, a $5.7 million loss was recorded in Gain (loss) on divestiture and other, net in the consolidated statements of operations, related to a change in WES’s estimate of the amount that would be recovered under the property insurance claim based on further discussions with insurers. During the second quarter of 2017, WES reached a settlement with insurers and final proceeds were received. As of September 30, 2017,2024, and December 31, 2016,2023, respectively.
Contract assets primarily relate to (i) revenue accrued but not yet billed under cost-of-service contracts with fixed and variable fees and (ii) accrued deficiency fees the consolidated balance sheets include receivables of zero and $30.0 million, respectively, forPartnership expects to charge customers once the property insurance claimrelated performance periods are completed. The following table summarizes activity related to the incident at the DBM complex. During the nine months ended September 30, 2017, WES received $52.9 million in cash proceedscontract assets from insurers in final settlement of WES’s claims related to the incident at the DBM complex, including $29.9 million in proceeds from business interruption insurance claims and $23.0 million in proceeds from property insurance claims.contracts with customers:

Recently adopted accounting standards. Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the assets will not be considered a business. If the screen is not met, the assets must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. WGP’s adoption of this ASU on January 1, 2017, using a prospective approach, could have a material impact on future consolidated financial statements as goodwill will not be allocated to divestitures or recorded on acquisitions that are not considered businesses.
ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and eliminates the exception for an intra-entity transfer of an asset other than inventory. WGP adopted this ASU on January 1, 2017, using a modified retrospective approach, with no impact to its consolidated financial statements.


thousands
Contract assets balance at December 31, 2023$39,292 
Amounts transferred to Accounts receivable, net that were included in the contract assets balance at the beginning of the period(1,928)
Additional estimated revenues recognized1,974
Contract assets balance at March 31, 2024$39,338
Contract assets at March 31, 2024
Other current assets$8,708
Other assets30,630
Total contract assets from contracts with customers$39,338
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

2. REVENUE FROM CONTRACTS WITH CUSTOMERS
1.  DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)

New accounting standards issued but not yet adopted. ASU 2016-18, StatementContract liabilities primarily relate to (i) fixed and variable fees under cost-of-service contracts that are received from customers for which revenue recognition is deferred, (ii) aid-in-construction payments received from customers that must be recognized over the expected period of Cash Flows (Topic 230): Restricted Cash requires an entitycustomer benefit, and (iii) fees that are charged to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to providecustomers for only a reconciliationportion of the totalscontract term and must be recognized as revenues over the expected period of customer benefit. The following table summarizes activity related to contract liabilities from contracts with customers:
thousands
Contract liabilities balance at December 31, 2023$445,499 
Cash received or receivable, excluding revenues recognized during the period36,960
Revenues recognized that were included in the contract liability balance at the beginning of the period(11,715)
Contract liabilities balance at March 31, 2024$470,744
Contract liabilities at March 31, 2024
Accrued liabilities$11,875
Other liabilities458,869
Total contract liabilities from contracts with customers$470,744

Transaction price allocated to remaining performance obligations. Revenues expected to be recognized from certain performance obligations that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalentsare unsatisfied (or partially unsatisfied) as of March 31, 2024, are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. WGP will adopt this ASU on January 1, 2018, and does not expecttable below. The Partnership applies the adoption to have a material impact on its consolidated financial statements.
ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable, with early adoption permitted. WGP will adopt this ASU on January 1, 2018, and does not expect the adoption to have a material impact on its consolidated statement of cash flows.
ASU 2016-02, Leases (Topic 842) requires lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. The provisions of ASU 2016-02 also modify the definition of a lease and outline the requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. WGP plans to elect certain practical expedients when implementing the new lease standard, which means WGP will not have to reassess the accounting for contracts that commenced prior to adoption. WGP has preliminarily determined WES’s portfolio of leased assets and is reviewing all related contracts to determine the impact that adoption will have on its consolidated financial statements. WGP is also evaluating the impact of this ASU on its systems, processes, and internal controls. WGP will complete its evaluationoptional exemptions in 2018 and adopt this new standard on January 1, 2019, using a modified retrospective approach for all comparative periods presented.
ASU 2014-09, Revenue from Contracts with Customers (Topic 606)supersedes current revenue recognition requirements and requiresdoes not disclose consideration for remaining performance obligations with an entityoriginal expected duration of one year or less or for variable consideration related to recognize revenue when it transfers promised goods or services tounsatisfied (or partially unsatisfied) performance obligations. Therefore, the following table represents only a portion of expected future revenues from existing contracts as most future revenues from customers are dependent on future variable customer volumes and, in an amount that reflects the consideration the entity expects to be entitled to in exchangesome cases, variable commodity prices for those goods or services. Additional disclosures will be required to describe the nature, amount, timing, and uncertainty of revenue and cash flows from contracts with customers. WGP has completed an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. While WGP does not currently expect net income to be materially impacted, it has concluded that WES is acting as an agent in the sale of certain volumes on behalf of WES’s customers based on the requirements of the new ASU. This conclusion will result in the reduction of Natural gas and natural gas liquids sales revenues and a corresponding reduction to cost of product expense related to WES’s contracts with these customers. In addition, WGP expects to recognize revenue for commodities received as noncash consideration in exchange for services provided and revenue and associated cost of product expense for the subsequent sale of those same commodities. This recognition will result in an increase to revenues for gathering and processing activities and cost of product expense with no impact on net income. WGP expects to recognize additional revenues for certain customer contributions related to capital cost recoveries that were previously accounted for as a reduction to capitalized property, plant and equipment. WGP also expects changes in the timing of recognizing revenue for certain fees due to the fee structure of certain contracts. WGP continues to evaluate the impact of these and other provisions of the ASU on its accounting policies, internal controls, and consolidated financial statements. Although WGP has not finalized the quantitative impact of the new standard, based on the assessment completed to date, WGP does not expect the adoption of this standard will have a material impact on its net income. WGP will complete its evaluation during the fourth quarter of 2017 and will adopt this new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to equity and partners’ capital.volumes.

thousands
Remainder of 2024$881,845 
20251,113,716 
20261,029,954 
2027919,010 
2028712,825 
Thereafter2,001,043 
Total$6,658,393 


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

2.3. ACQUISITIONS AND DIVESTITURES


TheMont Belvieu JV, Whitethorn LLC, Panola, and Saddlehorn. During the first quarter of 2024, the Partnership closed on the sale of the following table presentsequity investments to third parties: (i) the acquisitions completed by WES during 2017 and 2016, and identifies the funding sources for such acquisitions:
thousands except unit and percent amounts 
Acquisition
Date
 Percentage
Acquired
 Borrowings 
Cash
On Hand
 
WES Common Units
Issued
 WES Series A Preferred Units Issued
Springfield system (1)
 03/14/2016 50.1% $247,500
 $
 2,089,602
 14,030,611
DBJV system (2)
 03/17/2017 50% 
 155,000
 
 
(1)
WES acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for $750.0 million, consisting of $712.5 million in cash and the issuance of 1,253,761 of WES common units. Springfield owns a 50.1% interest in an oil gathering system and a gas gathering system, such interest being referred to in this report as the “Springfield interest.” The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. WES financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on the WES RCF, (ii) the issuance of 835,841 of WES common units to WGP and (iii) the issuance of WES Series A Preferred units to private investors. See Note 4 for further information regarding WES’s Series A Preferred units. WGP financed the purchase of the WES common units by borrowing $25.0 million under the WGP RCF. See Note 9.
(2)
WES acquired the Additional DBJV System Interest from a third party. See Property exchange below.

Property exchange. On March 17, 2017, WES acquired the Additional DBJV System Interest from a third party in exchange for (a) WES’s 33.75% non-operated25.00% interest in two natural gas gathering systems located in northern PennsylvaniaEnterprise EF78 LLC (the “Non-Operated Marcellus Interest”“Mont Belvieu JV”), commonly referred to as(ii) the Liberty and Rome systems, and (b) $155.0 million of cash consideration (collectively, the “Property Exchange”). WES previously held a 50%20.00% interest in Whitethorn Pipeline Company LLC (“Whitethorn LLC”), (iii) the 15.00% interest in Panola Pipeline Company, LLC (“Panola”), and operated,(iv) the DBJV system.
20.00% interest in Saddlehorn Pipeline Company, LLC (“Saddlehorn”). The Property Exchange is reflected as a nonmonetary transaction wherebycombined proceeds received in the acquired Additional DBJV System Interest is recorded at the fair valuefirst quarter of the divested Non-Operated Marcellus Interest plus the $155.02024 of $588.6 million of cash consideration. The Property Exchange resultedincludes $5.9 million in pro-rata distributions through closing, resulting in a net gain on sale of $125.7$239.7 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statementsstatement of operations. ResultsThe sale of operations attributable to the Property Exchange were includedinterests in the consolidated statement of operations beginningMont Belvieu JV and Whitethorn LLC also resolved outstanding legal proceedings associated with those assets.

Marcellus Interest systems. In April 2024, the Partnership closed on the acquisition datesale of its 33.75% interest in the first quarterMarcellus Interest systems for proceeds of 2017.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

2.  ACQUISITIONS AND DIVESTITURES (CONTINUED)

DBJV acquisition - Deferred purchase price obligation - Anadarko.Prior to WES’s agreement with Anadarko to settle its deferred purchase price obligation early, the consideration that would have been paid by WES for the March 2015 acquisition of Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko, consisted of a cash payment to Anadarko due on March 31, 2020. The cash payment would have been equal to (a) eight multiplied by the average of WES’s share in the Net Earnings (see definition below) of DBJV for the calendar years 2018 and 2019, less (b) WES’s share of all capital expenditures incurred for DBJV between March 1, 2015, and February 29, 2020. Net Earnings was defined as all revenues less cost of product, operating expenses and property taxes, in each case attributable to DBJV on an accrual basis. In May 2017, WES reached an agreement with Anadarko to settle this obligation whereby WES made a cash payment to Anadarko of $37.3$206.2 million, equal to the estimated net present value of the obligation at March 31, 2017.
The following table summarizes the financial statement impact of the Deferred purchase price obligation - Anadarko:
  Deferred purchase price obligation - Anadarko 
Estimated future payment obligation (1)
Balance at December 31, 2016 $41,440
 $56,455
Accretion expense (2)
 71
  
Revision to Deferred purchase price obligation – Anadarko (3)
 (4,165)  
Settlement of the Deferred purchase price obligation – Anadarko (37,346)  
Balance at September 30, 2017 $
 $
(1)
Calculated using Level 3 inputs.
(2)
Accretion expense was recorded as a charge to Interest expense in the consolidated statements of operations.
(3)
Recorded as revisions within Common units in the consolidated balance sheet and consolidated statement of equity and partners’ capital.

Helper and Clawson systems divestiture. During the second quarter of 2017, the Helper and Clawson systems, located in Utah, were sold to a third party, resulting in aan estimated net gain on sale of $16.4approximately $65.0 million that will be recorded as Gain (loss) on divestiture and other, net in the consolidated statement of operations during the second quarter of 2024. As of March 31, 2024, the Marcellus Interest systems satisfied criteria to be considered held for sale. At March 31, 2024, the consolidated balance sheet included current assets of $6.6 million, long-term assets of $142.7 million, current liabilities of $5.9 million, and long-term liabilities of $2.1 million associated with assets held for sale.

Meritage. On October 13, 2023, the Partnership closed on the acquisition of Meritage Midstream Services II, LLC (“Meritage”) for $885.0 million (subject to certain customary post-closing adjustments) funded with cash, including proceeds from the Partnership’s $600.0 million senior note issuance in September 2023 (see Note 10) and borrowings on the senior unsecured revolving credit facility (“RCF”). The cash purchase price, adjusted for working capital and certain customary post-closing adjustments and reduced by the $38.4 million of cash acquired (as presented in the table below), was $878.2 million.
The assets acquired, located in Converse, Campbell, and Johnson counties, Wyoming, include approximately 1,500 miles of high- and low-pressure natural-gas gathering pipelines, approximately 380 MMcf/d of natural-gas processing capacity, and the Thunder Creek NGL pipeline, which is a 120 mile, 38 MBbls/d FERC-regulated NGL pipeline that connects to the processing facility. The acquisition expands the Partnership’s existing Powder River Basin asset base, increasing total natural-gas processing capacity in that region to 440 MMcf/d.
The Meritage acquisition has been accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the Meritage acquisition were recorded in the consolidated balance sheet at their estimated fair values as of the acquisition date. Results of operations attributable to the Meritage acquisition were included in the Partnership’s consolidated statements of operations.

Hugoton system divestiture. Duringoperations beginning on the acquisition date in the fourth quarter of 2016, the Hugoton system, located in Southwest Kansas and Oklahoma, was sold to a third party, resulting in a net loss on sale of $12.0 million recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. WES allocated $1.6 million in goodwill to this divestiture.2023.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

3. ACQUISITIONS AND DIVESTITURES
3.
The following is the final acquisition-date fair value for the assets acquired and liabilities assumed in the Meritage acquisition on October 13, 2023.

thousands
Assets acquired:
Cash and cash equivalents$38,412 
Accounts receivable, net34,060 
Other current assets1,980 
Property, plant, and equipment926,347 
Other assets6,498 
Total assets acquired1,007,297 
Liabilities assumed:
Accounts payable and accrued liabilities34,733 
Other current liabilities5,451 
Asset retirement obligation22,156 
Other liabilities28,356 
Total liabilities assumed90,696 
Net assets acquired$916,601 

The acquisition-date fair values are based on an assessment of the fair value of the assets acquired and liabilities assumed in the Meritage acquisition using inputs that are not observable in the market and thus represent Level 3 inputs. The fair values of the processing plants, gathering system, and related facilities and equipment are based on market and cost approaches.

4. PARTNERSHIP DISTRIBUTIONS


WGP partnershipPartnership distributions. WGP’sUnder its partnership agreement, requires WGP to distributethe Partnership distributes all of its available cash (as defined in its partnership agreement) to WGP unitholders of record on the applicable record date within 55 days of the end offollowing each quarter. The Board of Directors of WGP GP (the “Board of Directors”) declared the following cash distributions to WGP unitholders for the periods presented:
thousands except per-unit amounts
Quarters Ended
 
Total Quarterly
Distribution
per Unit
 
Total Quarterly
Cash Distribution
 
Date of
Distribution
2016      
March 31 $0.42375
 $92,767
 May 2016
June 30 0.43375
 94,958
 August 2016
September 30 0.44750
 97,968
 November 2016
December 31 0.46250
 101,254
 February 2017
2017      
March 31 $0.49125
 $107,549
 May 2017
June 30 0.52750
 115,487
 August 2017
September 30 (1)
 0.53750
 117,677
 November 2017
(1)
The Board of Directors declared a cash distribution to WGP unitholders for the third quarter of 2017 of $0.53750 per unit, or $117.7 million in aggregate. The cash distribution is payable on November 22, 2017, to WGP unitholders of record at the close of business on November 2, 2017.

WES partnership distributions. WES’s partnership agreement requires WES to distribute all of its available cash (as defined in WES’s partnership agreement) to WES unitholders of record on the applicable record date within 45 days of the end of each quarter. The Board of Directors of WES GP declared the following cash distributions to WES’s common and general partner unitholders for the periods presented:
thousands except per-unit amounts
Quarters Ended
 Total Quarterly
Distribution
per Unit
 Total Quarterly
Cash Distribution
 Date of
Distribution
2016      
March 31 $0.815
 $158,905
 May 2016
June 30 0.830
 162,827
 August 2016
September 30 0.845
 166,742
 November 2016
December 31 0.860
 170,657
 February 2017
2017      
March 31 $0.875
 $188,753
 May 2017
June 30 0.890
 207,491
 August 2017
September 30 (1)
 0.905
 212,038
 November 2017
(1)
The Board of Directors of WES GP declared a cash distribution to WES unitholders for the third quarter of 2017 of $0.905 per unit, or $212.0 million in aggregate, including incentive distributions, but excluding distributions on WES Class C units (see WESClass C unit distributions below). The cash distribution is payable on November 13, 2017, to WES unitholders of record at the close of business on November 2, 2017.


17

Table of Contents
WESTERN GAS EQUITY PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

3.  PARTNERSHIP DISTRIBUTIONS (CONTINUED)

WES’s available cash.quarter’s end. The amount of available cash (as(beyond proper reserves as defined in WES’sthe partnership agreement) generally is all cash on hand at the end of the quarter, plus, at the discretion of WES GP,the general partner, working capital borrowings made subsequent to the end of such quarter, less the amount of cash reserves established by WES GPthe general partner to provide for the proper conduct of WES’sthe Partnership’s business, including reserves(i) to fund future capital expenditures; (ii) to comply with applicable laws, debt instruments, or other agreements; or (iii) to provide funds for unitholder distributions to WES unitholders and to WES GP for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement. Working capital borrowings may only be those that, at the time of such borrowings, werearrangement and are intended to be repaid or refinanced within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.unitholder distributions.


WES Class C unit distributions. WES’s Class C units receive quarterly distributions at a rate equivalent to WES’s common units. The distributions are paid in the form of additional Class C units (“PIK Class C units”) until the scheduled conversion date on March 1, 2020 (unless earlier converted), and the Class C units are disregarded with respect to WES’s distributions of WES’s available cash until they are converted to WES common units. The number of additional PIK Class C units to be issued in connection with a distribution payable on the Class C units is determined by dividing the corresponding distribution attributable to the Class C units by the volume-weighted-average price of WES’s common units for the ten days immediately preceding the payment date for the WES common unit distribution, less a 6% discount. WES records the PIK Class C unit distributions at fair value at the time of issuance. This Level 2 fair value measurement uses WES’s unit price as a significant input in the determination of the fair value. See Note 4 for further discussion of the WES Class C units.

WES Series A Preferred unit distributions. As further described in Note 4, WES issued Series A Preferred units representing limited partner interests in WES to private investors in 2016. The Series A Preferred unitholders received quarterly distributions in cash equal to $0.68 per Series A Preferred unit, subject to certain adjustments. The following table summarizes the Series A Preferred unitholders’ cash distributions for the periods presented:
20
thousands except per-unit amounts
Quarters Ended
 
Total Quarterly
Distribution
per Unit
 
Total Quarterly
Cash Distribution
 
Date of
Distribution
2016      
March 31 (1)
 $0.68
 $1,887
 May 2016
June 30 (2)
 0.68
 14,082
 August 2016
September 30 0.68
 14,907
 November 2016
December 31 0.68
 14,908
 February 2017
2017      
March 31 $0.68
 $7,453
 May 2017
(1)
Quarterly per unit distribution prorated for the 18-day period during which 14,030,611 WES Series A Preferred units were outstanding during the first quarter of 2016.
(2)
Full quarterly per unit distribution on 14,030,611 WES Series A Preferred units and quarterly per unit distribution prorated for the 77-day period during which 7,892,220 WES Series A Preferred units were outstanding during the second quarter of 2016.

On March 1, 2017, 50% of the outstanding WES Series A Preferred units converted into WES common units on a one-for-one basis, and on May 2, 2017, the remaining WES Series A Preferred units converted into WES common units on a one-for-one basis. Such converted WES common units were entitled to distributions made to WES common unitholders with respect to the quarter during which the applicable conversion occurred and did not include a prorated WES Series A Preferred unit distribution.


18

WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

3.4. PARTNERSHIP DISTRIBUTIONS (CONTINUED)


WES’sThe Board of Directors of the general partner interest(the “Board”) declared the following cash distributions to the Partnership’s unitholders for the periods presented:
thousands except per-unit amounts
Quarters Ended
Total Quarterly
Per-unit
Distribution
Total Quarterly
Cash Distribution
Distribution
Date
Record
Date
2023
March 31 (1)
$0.856 $336,987 May 15, 2023May 1, 2023
June 300.5625 221,442 August 14, 2023July 31, 2023
September 300.575 223,432 November 13, 2023November 1, 2023
December 310.575 223,438 February 13, 2024February 1, 2024
2024
March 31$0.875 $340,858 May 15, 2024May 1, 2024

(1)Includes the regular quarterly distribution of $0.500 per unit, or $196.8 million, as well as the Enhanced Distribution of $0.356 per unit discussed below.

To facilitate the distribution of available cash, during 2022 the Partnership adopted a financial policy that provided for an additional distribution (“Enhanced Distribution”) to be paid in conjunction with the regular first-quarter distribution of the following year (beginning in 2023), in a target amount equal to Free cash flow generated in the prior year after subtracting Free cash flow used for the prior year’s debt repayments, regular-quarter distributions, and incentiveunit repurchases. In April 2023, the Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, related to the Partnership’s 2022 performance, which was paid in conjunction with the regular first-quarter 2023 distribution rights. Ason May 15, 2023.

WES Operating partnership distributions. WES Operating makes quarterly cash distributions to the Partnership and WGR Asset Holding Company LLC (“WGRAH”), a subsidiary of September 30, 2017,Occidental, in proportion to their share of limited partner interests in WES GP was entitled to 1.5% of all quarterlyOperating. See Note 5. WES Operating made and/or declared the following cash distributions that WES makes prior to its liquidation and, aslimited partners for the holderperiods presented:
thousands
Quarters Ended
Total Quarterly
Cash Distribution
Distribution
Date
2023
March 31 (1)
$342,895 May 2023
June 30226,260 August 2023
September 30229,446 November 2023
December 31229,446 February 2024
2024
March 31$347,675May 2024

(1)Includes amounts related to the Enhanced Distribution discussed above.
21


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


Holdings of WGPPartnership equity. WGP’s The Partnership’s common units are listed on the New York Stock Exchange under the ticker symbol “WGP.“WES.” As of September 30, 2017, AnadarkoMarch 31, 2024, Occidental held 178,587,365 of WGP’s185,181,578 common units, representing an 81.6%a 47.6% limited partner interest in WGP,the Partnership, and through its ownership of WGP GP, Anadarkothe general partner, Occidental indirectly held the entire non-economic9,060,641 general partner units, representing a 2.3% general partner interest in WGP.the Partnership. The public held 40,345,776 WGP195,308,560 common units, representing an 18.4%a 50.1% limited partner interest in WGP.the Partnership.

Partnership equity repurchases.In June 2016, Anadarko sold 12,500,0002022, the Board authorized the Partnership to buy back up to $1.25 billion of its WGPthe Partnership’s common units through December 31, 2024 (the “$1.25 billion Purchase Program”). The common units may be purchased from time to the public through an underwritten offering. WGP did not receive any proceeds from, or incur any expensetime in the public offering.open market at prevailing market prices or in privately negotiated transactions. During the three months ended March 31, 2024, there were no common units repurchased. During the three months ended March 31, 2023, the Partnership repurchased 285,688 common units for an aggregate purchase price of $7.1 million. The units were canceled immediately upon receipt. As of March 31, 2024, the Partnership had an authorized amount of $627.8 million remaining under the program.


Tangible equity units. In June 2015, Anadarko completedHoldings of WES Operating equity. As of March 31, 2024, (i) the public issuancePartnership, directly and indirectly through its ownership of 9,200,000 7.50% tangible equity units (“TEUs”), including 1,200,000 TEUs pursuant toWES Operating GP, owned a 98.0% limited partner interest and the full exerciseentire non-economic general partner interest in WES Operating and (ii) Occidental, through its ownership of WGRAH, owned a 2.0% limited partner interest in WES Operating, which is reflected as a noncontrolling interest within the consolidated financial statements of the underwriters’ over-allotment option, at a price to the public of $50.00 per TEU. Each TEU that Anadarko issued consists of (1) a prepaid equity purchase contract for WGP common units owned by Anadarko (subject to Anadarko’s right to elect to deliver shares of its common stock in lieu of such WGP common units) and (2) a senior amortizing note due June 7, 2018. WGP did not receive any proceeds from, or incur any expense in, the public offering.Partnership (see Note 1).


NetPartnership’s net income (loss) per common unit. For WGP, The common and general partner unitholders’ allocation of net income (loss) attributable to the Partnership was equal to their cash distributions plus their respective allocations of undistributed earnings or losses in accordance with their weighted-average ownership percentage during each period using the two-class method.
The Partnership’s basic net income (loss) per common unit is calculated by dividing the limited partners’ interest in net income (loss) by the weighted-averageweighted-average number of common units outstanding during the period. DilutiveDiluted net income (loss) per common unit is calculated by dividingincludes the limited partners’ interest ineffect of outstanding units issued under the Partnership’s long-term incentive plans.
The following table provides a reconciliation between basic and diluted net income (loss) adjusted for distributions on the per common unit:
 Three Months Ended 
March 31,
thousands except per-unit amounts20242023
Net income (loss)
Limited partners’ interest in net income (loss)$559,500 $198,959 
Weighted-average common units outstanding
Basic380,024 384,468 
Dilutive effect of non-vested phantom units1,604 1,282 
Diluted381,628 385,750 
Excluded due to anti-dilutive effect279 663 
Net income (loss) per common unit
Basic$1.47 $0.52 
Diluted$1.47 $0.52 

WES Series A Preferred units and a reallocation of the limited partners’ interest inOperating’s net income (loss) assuming conversion of the WES Series A Preferred units into WESper common units by the weighted-average number of WGP common units outstanding during the period. As of May 2, 2017, all WES Series A Preferred units were converted into WES common units on a one-for-one basis. The impact of the Series A Preferred units assuming conversion to WES common units would be anti-dilutive for all periods presented.unit. Net income (loss) per common unit is calculated assuming that cash distributions are equal to the net income attributable to WGP. Net income (loss) attributable to thefor WES assets (as defined in Note 1) acquired from Anadarko for periods prior to WES’s acquisition of the WES assetsOperating is not allocated to the limited partners when calculating net income (loss) per common unit. Net income equal to the amount of available cash (as defined by WGP’s partnership agreement) is allocated to WGP common unitholders consistent with actual cash distributions.calculated because it has no publicly traded units.

Holdings of WES equity. As of September 30, 2017, WGP held 50,132,046 WES common units, representing a 29.8% limited partner interest in WES, and, through its ownership of WES GP, WGP indirectly held 2,583,068 general partner units, representing a 1.5% general partner interest in WES, and 100% of WES’s incentive distribution rights. As of September 30, 2017, (i) other subsidiaries of Anadarko collectively held 2,011,380 WES common units and 12,977,633 Class C units, representing an aggregate 9.0% limited partner interest in WES and (ii) the public held 100,458,679 WES common units, representing a 59.7% limited partner interest in WES, which are all reflected as noncontrolling interests within the consolidated financial statements of WGP (see Note 1 and Note 2).



19
22

WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

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

WES Class C units. In November 2014, WES issued 10,913,853 Class C units to Anadarko Midstream Holdings (“AMH”), pursuant to a Unit Purchase Agreement with Anadarko and AMH. The Class C units were issued to partially fund WES’s acquisitionSummary of DBM.
When issued, the WES Class C units were scheduled to convert into WES common units on a one-for-one basis on December 31, 2017. In February 2017, Anadarko elected to extend the conversion date of the WES Class C units to March 1, 2020. WES can elect to convert the Class C units earlier or Anadarko can extend the conversion date again.

WES Series A Preferred units. In 2016, WES issued 21,922,831 WES Series A Preferred units to private investors. Pursuant to an agreement between WES and the holders of the WES Series A Preferred units, 50% of the WES Series A Preferred units converted into WES common units on a one-for-one basis on March 1, 2017, and the remaining Series A Preferred units converted on a one-for-one basis on May 2, 2017. WES has an effective registration statement with the SEC relating to the public resale of the WES common units issued upon conversion of the WES Series A Preferred units.

WES interests.related-party transactions. The following table summarizes WES’s common, Class C, Series A Preferredtables summarize material related-party transactions included in the Partnership’s consolidated financial statements:
Consolidated statements of operations
 Three Months Ended 
March 31,
thousands20242023
Revenues and other
Service revenues – fee based$489,729 $423,501 
Service revenues – product based14,057 8,116 
Product sales(3,977)17,168 
Total revenues and other499,809 448,785 
Equity income, net – related parties (1)
32,819 39,021 
Operating expenses
Cost of product (2)
(27,412)(3,947)
Operation and maintenance1,439 747 
General and administrative 67 
Total operating expenses(25,973)(3,133)

(1)See Note 7.
(2)Includes related-party natural-gas and general partner units issued during the nine months ended September 30, 2017:NGLs imbalances.

Consolidated balance sheets
thousandsMarch 31,
2024
December 31,
2023
Assets
Accounts receivable, net$389,721 $358,141 
Other current assets3,277 1,260 
Equity investments (1)
546,078 904,535 
Other assets43,534 43,216 
Total assets982,610 1,307,152 
Liabilities
Accounts and imbalance payables38,739 38,541 
Accrued liabilities5,009 4,979 
Other liabilities (2)
362,604 335,320 
Total liabilities406,352 378,840 

(1)See Note 7.
(2)Includes contract liabilities from contracts with customers. See Note 2.
23
  
WES
Common
Units
 
WES
Class C
Units
 
WES
Series A
Preferred
Units
 
WES
General
Partner
Units
 Total
Balance at December 31, 2016 130,671,970
 12,358,123
 21,922,831
 2,583,068
 167,535,992
PIK Class C units 
 619,510
 
 
 619,510
Conversion of Series A Preferred units 21,922,831
 
 (21,922,831) 
 
Long-Term Incentive Plan award vestings 7,304
 
 
 
 7,304
Balance at September 30, 2017 152,602,105
 12,977,633
 
 2,583,068
 168,162,806


20

WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

6. RELATED-PARTY TRANSACTIONS
5.  TRANSACTIONS WITH AFFILIATES

Consolidated statements of cash flows
Three Months Ended 
March 31,
thousands20242023
Distributions from equity-investment earnings – related parties
$29,304 $39,609 
Contributions to equity investments – related parties (110)
Distributions from equity investments in excess of cumulative earnings – related parties19,033 12,366 
Distributions to Partnership unitholders (1)
(111,689)(99,671)
Distributions to WES Operating unitholders (2)
(4,591)(4,271)

(1)Represents common and general partner unit distributions paid to Occidental pursuant to the partnership agreement of the Partnership (see Note 4 and Note 5).
Affiliate transactions. Revenues(2)Represents distributions paid to Occidental, through its ownership of WGRAH, pursuant to WES Operating’s partnership agreement (see Note 4 and Note 5).

The following tables summarize material related-party transactions for WES Operating (which are included in the Partnership’s consolidated financial statements) to the extent the amounts differ materially from affiliatesthe Partnership’s consolidated financial statements:
Consolidated statements of operations
 Three Months Ended 
March 31,
thousands20242023
General and administrative (1)
$1,306 $1,281 

(1)Includes an intercompany service fee between the Partnership and WES Operating.

Consolidated balance sheets
thousandsMarch 31,
2024
December 31,
2023
Accounts receivable, net (1)
$407,881 $358,141 
Other current assets3,218 1,235 
Other assets40,108 41,405 
Accounts and imbalance payables38,739 69,472 
Accrued liabilities4,692 4,662 

(1)Includes balances related to transactions between the Partnership and WES Operating.

Consolidated statements of cash flows
Three Months Ended 
March 31,
thousands20242023
Distributions to WES Operating unitholders (1)
$(229,446)$(213,513)

(1)Represents distributions paid to the Partnership and Occidental, through its ownership of WGRAH, pursuant to WES Operating’s partnership agreement. See Note 4 and Note 5.
24

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

Related-party revenues. Related-party revenues include amounts earned by WESthe Partnership from services provided to Anadarko as well asOccidental and from the sale of residuenatural gas, condensate, and NGLs to Anadarko. Occidental.

Gathering and processing agreements. The Partnership has significant gathering, processing, and produced-water disposal arrangements with affiliates of Occidental on most of its systems. While Occidental is the contracting counterparty of the Partnership, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on the Partnership’s facilities and infrastructure to bring their volumes to market. Natural-gas throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 31% and 35% for the three months ended March 31, 2024 and 2023, respectively. Crude-oil and NGLs throughput (excluding equity-investment throughput) attributable to production owned or controlled by Occidental was 89% and 88% for the three months ended March 31, 2024 and 2023, respectively. Produced-water throughput attributable to production owned or controlled by Occidental was 77% and 80% for the three months ended March 31, 2024 and 2023, respectively.
The Partnership is currently discussing varying interpretations of certain contractual provisions with Occidental regarding the calculation of the cost-of-service rates under an oil-gathering contract related to the Partnership’s DJ Basin oil-gathering system. If such discussions are resolved in a manner adverse to the Partnership, such resolution could have a negative impact on the Partnership’s financial condition and results of operations, including a reduction in rates and a non-cash charge to earnings.
In addition, WES purchases naturalconnection with the sale of its Eagle Ford assets in 2017, Anadarko remained the primary counterparty to the Partnership’s Brasada gas processing agreement and entered into an agency relationship with Sanchez Energy Corporation (“Sanchez”), subsequently Mesquite Energy, Inc. (“Mesquite”), that allowed Mesquite to process gas under such agreement. In December 2021, the Brasada gas processing agreement was assigned from an affiliateAnadarko to Mesquite effective July 1, 2023. For this reason, Anadarko is not liable for any obligations under the Brasada gas processing agreement after June 30, 2023. For all periods presented, either Mesquite or its successor, a subsidiary of AnadarkoJavelin Energy Partners, performed Anadarko’s obligations under the Brasada gas processing agreement pursuant to its agency arrangement with Anadarko.

Marketing Transition Services Agreement. During the year ended December 31, 2020, Occidental provided marketing-related services to certain of the Partnership’s subsidiaries (the “Marketing Transition Services Agreement”). While the Partnership still has some marketing agreements with affiliates of Occidental, on January 1, 2021, the Partnership began marketing and selling substantially all of its crude oil, residue gas, purchase agreements. and NGLs directly to third parties.

Related-party expenses. Operation and maintenance expense includes amounts accrued for or paid to affiliatesrelated parties for field-related costs, shared field offices, and easements (see Related-party commercial agreement below) supporting the operation of WES assets, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis, and other disbursements.Partnership’s operations at certain assets. A portion of general and administrative expensesexpense is paid by Anadarko,Occidental, which results in affiliaterelated-party transactions pursuant to the reimbursement provisions of the omnibusPartnership’s and WES Operating’s agreements with Occidental. Cost of WESproduct expense includes amounts related to certain continuing marketing arrangements with affiliates of Occidental, related-party imbalances, and WGP. Affiliatetransactions with affiliates accounted for under the equity method of accounting. See Marketing Transition Services Agreement in the section above. Related-party expenses do not bear ano direct relationship to affiliaterelated-party revenues, and third-partythird-party expenses do not bear ano direct relationship to third-partythird-party revenues. See Note 2

Services Agreement.Occidental performed certain centralized corporate functions for further information related to contributions of assets tothe Partnership and WES by Anadarko.

Cash management. Anadarko operates a cash management system whereby excess cash from most of its subsidiaries’ separate bank accounts is generally swept to centralized accounts. PriorOperating pursuant to the acquisitionagreement dated as of December 31, 2019, by and among Occidental, Anadarko, and WES assets, third-party salesOperating GP (“Services Agreement”). Most of the administrative and purchases related to such assets were received or paid in cashoperational services previously provided by Anadarko within its centralized cash management system. The outstanding affiliate balances were entirely settled through an adjustment to net investment by Anadarko in connection with the acquisition of WES assets. SubsequentOccidental fully transitioned to the acquisition of WES assets from Anadarko, transactions relatedPartnership by December 31, 2021, with certain limited transition services remaining in place pursuant to such assets are cash-settled directly with third parties and with Anadarko affiliates. Chipeta cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of WES.

Note receivable - Anadarko. Concurrently with the closing of WES’s May 2008 initial public offering, WES loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%, payable quarterly. The fair valueterms of the note receivable from Anadarko was $313.2 million and $313.3 million at September 30, 2017, and December 31, 2016, respectively. The fair value of the note reflects consideration of credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest rate, based on quoted market prices of similar debt instruments. Accordingly, the fair value of the note receivable from Anadarko is measured using Level 2 inputs.Services Agreement.


WGP working capital facility.On November 1, 2012, WGP entered into a $30.0 million working capital facility (the “WGP WCF”) with Anadarko as the lender. The WGP WCF is available exclusively to fund WGP’s working capital borrowings. The WGP WCF will mature on November 1, 2017. See Note 9.

Commodity price swap agreements. WES has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price risk inherent in its percent-of-proceeds and keep-whole contracts. Notional volumes for each of the commodity price swap agreements are not specifically defined. Instead, the commodity price swap agreements apply to the actual volume of natural gas, condensate and NGLs purchased and sold. The commodity price swap agreements do not satisfy the definition of a derivative financial instrument and, therefore, are not required to be measured at fair value.



21
25

WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

6. RELATED-PARTY TRANSACTIONS
5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

The following table summarizes gainsConstruction reimbursement agreements and losses upon settlementpurchases and sales with related parties. From time to time, the Partnership enters into construction reimbursement agreements with Occidental providing that the Partnership will manage the construction of WES’s commodity price swap agreements recognizedcertain midstream infrastructure for Occidental in the consolidated statementsPartnership’s areas of operations:
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands 2017 2016 2017 2016
Gains (losses) on commodity price swap agreements related to sales: (1)
        
Natural gas sales $6,284
 $719
 $12,022
 $12,962
Natural gas liquids sales (7,210) 15,939
 (9,680) 56,489
Total (926) 16,658
 2,342
 69,451
Gains (losses) on commodity price swap agreements related to purchases (2)
 (117) (9,248) (2,928) (45,032)
Net gains (losses) on commodity price swap agreements $(1,043) $7,410
 $(586) $24,419
(1)
Reported in affiliate Natural gas and natural gas liquids sales in the consolidated statementsoperation. Such arrangements generally provide for a reimbursement of operations in the period in which the related sale is recorded.
(2)
Reported in Cost of product in the consolidated statements of operations in the period in which the related purchase is recorded.

Revenues or costs attributable to volumes settled during 2016 and 2017 forincurred by the DJ Basin complex and 2017 for the MGR assets are recognized in the consolidated statements of operations at the applicable market price in the tables below. WES also records a capital contribution from Anadarko in its consolidated statement of equity and partners’ capital for the amount by which the swap price exceeds the applicable market price in the tables below. The commodity price swap agreement for the Hugoton system was in place until its divestiture in October 2016. For the nine months ended September 30, 2017, the capital contribution from Anadarko was $46.7 million. The tables below summarize the swap prices compared to the forward market prices:
  DJ Basin Complex
per barrel except natural gas 2016 - 2017 Swap Prices 
2016 Market Prices (1)
 
2017 Market Prices (1)
Ethane $18.41
 $0.60
 $5.09
Propane 47.08
 10.98
 18.85
Isobutane 62.09
 17.23
 26.83
Normal butane 54.62
 16.86
 26.20
Natural gasoline 72.88
 26.15
 41.84
Condensate 76.47
 34.65
 45.40
Natural gas (per MMBtu) 5.96
 2.11
 3.05
(1)
Represents the New York Mercantile Exchange (“NYMEX”) forward strip price as of December 8, 2015 and December 1, 2016, for the 2016 Market Prices and 2017 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.


22

WESTERN GAS EQUITY PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)
  MGR Assets
per barrel except natural gas 2016 - 2017 Swap Prices 
2017 Market Prices (1)
Ethane $23.11
 $4.08
Propane 52.90
 19.24
Isobutane 73.89
 25.79
Normal butane 64.93
 25.16
Natural gasoline 81.68
 45.01
Condensate 81.68
 53.55
Natural gas (per MMBtu) 4.87
 3.05
(1)
Represents the NYMEX forward strip price as of December 1, 2016, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.

Gathering and processing agreements. WES has significant gathering and processing arrangements with affiliates of AnadarkoPartnership on a majority of its systems. WES’s natural gas gathering, treating and transportation throughput (excluding equity investment throughput) attributable to production ownedcost or controlled by Anadarko was 33% and 34% for the three and nine months ended September 30, 2017, respectively, and 37% and 38% for the three and nine months ended September 30, 2016, respectively. WES’s natural gas processing throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 39% and 42% for the three and nine months ended September 30, 2017, respectively, and 51% and 55% for the three and nine months ended September 30, 2016, respectively. WES’s crude, NGL and produced water gathering, treating and transportation throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was 54% and 50% for the three and nine months ended September 30, 2017, respectively, and 67% and 64% for the three and nine months ended September 30, 2016, respectively.cost-plus basis.

Commodity purchase and sale agreements. WES sells a significant amount of its natural gas, condensate and NGLs to Anadarko Energy Services Company (“AESC”), Anadarko’s marketing affiliate. In addition, WES purchases natural gas, condensate and NGLs from AESC pursuant to purchase agreements. WES’s purchase and sale agreements with AESC are generally one-year contracts, subject to annual renewal.

Acquisitions from Anadarko. On March 14, 2016, WES acquired Springfield from Anadarko (see Note 2).


23

WESTERN GAS EQUITY PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

WGP LTIP. WGP GP awards phantom units under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (“WGP LTIP”) to its independent directors and executive officers. The phantom units awarded to the independent directors vest one year from the grant date, while awards granted to executive officers are subject to graded vesting over a three-year service period. Compensation expense under the WGP LTIP is recognized over the vesting period and was $63,000 and $0.2 million for the three and nine months ended September 30, 2017, respectively, and $57,000 and $0.2 million for the three and nine months ended September 30, 2016, respectively.

WGP LTIP and Anadarko Incentive Plan. General and administrative expenses included $1.2 million and $3.2 million for the three and nine months ended September 30, 2017, respectively, and $1.4 million and $3.7 million for the three and nine months ended September 30, 2016, respectively, of equity-based compensation expense, allocated to WES by Anadarko, for awards granted to the executive officers of WES GP and other employees under the WGP LTIP and the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan (“Anadarko Incentive Plan”). Of this amount, $3.3 million is reflected as contributions to partners’ capital in the consolidated statement of equity and partners’ capital for the nine months ended September 30, 2017.

WES LTIP. WES GP awards phantom units under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“WES LTIP”) primarily to its independent directors, but alsoAdditionally, from time to time, to its executive officers and Anadarko employees performing services for WES. The phantom units awarded to the independent directors vest one year from the grant date, while all other awards are subject to graded vesting over a three-year service period. Compensation expense is recognized over the vesting period and was $0.1 million for eachin support of the three months ended September 30, 2017Partnership’s business, the Partnership purchases and 2016,sells equipment, inventory, and $0.3 million for eachother miscellaneous assets from or to Occidental or its affiliates.

Related-party commercial agreement. During the first quarter of 2021, an affiliate of Occidental and certain wholly owned subsidiaries of the nine months ended September 30, 2017Partnership entered into a Commercial Understanding Agreement (“CUA”). Under the CUA, certain West Texas surface-use and 2016.

Equipment purchasessalt-water disposal agreements were amended to reduce usage fees owed by the Partnership in exchange for the forgiveness of certain deficiency fees owed by Occidental and sales.other unrelated contractual amendments. The following table summarizes WES’s purchases from and sales to Anadarko of pipe and equipment:
  Nine Months Ended September 30,
  2017 2016 2017 2016
thousands Purchases Sales
Cash consideration $3,910
 $3,965
 $
 $623
Net carrying value (5,283) (3,366) 
 (605)
Partners’ capital adjustment $(1,373) $599
 $
 $18

Contributions in aid of construction costs from affiliates. On certain of WES’s capital projects, Anadarko is obligated to reimburse WES for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. The cash receipts resulting from such reimbursements are presented as “Contributions in aid of construction costs from affiliates” within the investing sectionpresent value of the reduced usage fees under the CUA was $30.0 million at the time the agreement was executed. Also, as a result of the amendments under the CUA, these agreements are classified as operating leases and a $30.0 million right-of-use (“ROU”) asset, included in Other assets on the consolidated statementsbalance sheets, was recognized during the first quarter of cash flows.2021. The ROU asset is being amortized to Operation and maintenance expense through 2038, the remaining term of the agreements.



24

WESTERN GAS EQUITY PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

5.  TRANSACTIONS WITH AFFILIATES (CONTINUED)

Summary of affiliate transactions. The following table summarizes material affiliate transactions. See Note 2 for discussion of affiliate acquisitions and related funding.
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands 2017 2016 2017 2016
Revenues and other (1)
 $351,127
 $325,312
 $982,595
 $900,301
Equity income, net – affiliates (1)
 21,519
 20,294
 62,708
 56,801
Cost of product (1)
 22,902
 21,254
 60,497
 67,979
Operation and maintenance (2)
 18,110
 15,052
 53,661
 50,688
General and administrative (3)
 10,414
 9,655
 29,637
 28,179
Operating expenses 51,426
 45,961
 143,795
 146,846
Interest income (4)
 4,225
 4,225
 12,675
 12,675
Interest expense (5)
 
 (1,173) 71
 (12,097)
Settlement of the Deferred purchase price obligation – Anadarko (6)
 
 
 (37,346) 
Distributions to WGP unitholders (7)
 94,205
 77,462
 264,533
 235,587
Distributions to WES unitholders (8)
 1,790
 1,670
 5,280
 3,915
Above-market component of swap agreements with Anadarko 18,049
 18,417
 46,719
 34,782
(1)
Represents amounts earned or incurred on and subsequent to the date of the acquisition of WES assets, as well as amounts earned or incurred by Anadarko on a historical basis related to WES assets prior to the acquisition of such assets by WES, recognized under gathering, treating or processing agreements, and purchase and sale agreements.
(2)
Represents expenses incurred on and subsequent to the date of the acquisition of WES assets, as well as expenses incurred by Anadarko on a historical basis related to WES assets prior to the acquisition of such assets by WES.
(3)
Represents general and administrative expense incurred on and subsequent to the date of WES’s acquisition of WES assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of WES assets by WES. These amounts include equity-based compensation expense allocated to WES and WGP by Anadarko (see WES LTIP and WGP LTIP and Anadarko Incentive Plan within this Note 5) and amounts charged by Anadarko under the WGP and WES omnibus agreements.
(4)
Represents interest income recognized on the note receivable from Anadarko.
(5)
Includes amounts related to WES’s Deferred purchase price obligation - Anadarko (see Note 2 and Note 9).
(6)
Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see Note 2).
(7)
Represents distributions paid under WGP’s partnership agreement (see Note 3 and Note 4).
(8)
Represents distributions paid to other subsidiaries of Anadarko under WES’s partnership agreement (see Note 3 and Note 4).

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



7. EQUITY INVESTMENTS

The following tables present the financial statement impact of the Partnership’s equity investments for the three months ended March 31, 2024:

thousandsBalance at December 31, 2023Equity
income, net
Distributions
Distributions
in excess of
cumulative
earnings (1)
Acquisitions and Divestitures (2)
Balance at March 31, 2024
White Cliffs$13,248 $1,285 $(1,285)$(843)$ $12,405 
Rendezvous10,815 (578)(237)(464) 9,536 
Mont Belvieu JV88,556 51 (442)(6,047)(82,118) 
TEG15,185 169 (175)(200) 14,979 
TEP172,559 7,218 (7,281)(635) 171,861 
FRP186,551 11,727 (11,770)(1,803) 184,705 
Whitethorn LLC144,799 1,185 3,326 (4,924)(144,386) 
Saddlehorn101,760 4,200 (4,124)(3,096)(98,740) 
Panola18,716 74 (74)(1,021)(17,695) 
Mi Vida45,424 2,068 (2,050)  45,442 
Red Bluff Express106,922 5,420 (5,192)  107,150 
Total$904,535 $32,819 $(29,304)$(19,033)$(342,939)$546,078 

(1)Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, are calculated on an individual-investment basis.
(2)See Note 3.

During the first quarter of 2024, the Partnership closed on the sale of the following equity investments to third parties: (i) the 25.00% interest in Mont Belvieu JV, (ii) the 20.00% interest in Whitethorn LLC, (iii) the 15.00% interest in Panola, and (iv) the 20.00% interest in Saddlehorn. See Note 3.
25
26

WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

6.8. PROPERTY, PLANT, AND EQUIPMENT


A summary of the historical cost of WES’s property, plant, and equipment is as follows:
thousandsEstimated Useful LifeMarch 31,
2024
December 31,
2023
LandN/A$12,442 $12,504 
Gathering systems – pipelines30 years5,935,848 5,890,607 
Gathering systems – compressors15 years2,602,110 2,553,602 
Processing complexes and treating facilities25 years3,775,379 3,745,332 
Transportation pipeline and equipment3 to 48 years259,227 259,314 
Produced-water disposal systems
20 years1,103,001 1,098,616 
Assets under constructionN/A560,417 479,368 
Other3 to 40 years909,211 906,088 
Total property, plant, and equipment15,157,635 14,945,431 
Less accumulated depreciation5,432,343 5,290,415 
Net property, plant, and equipment$9,725,292 $9,655,016 
thousands Estimated Useful Life September 30, 2017 December 31, 2016
Land n/a $4,271
 $4,012
Gathering systems and processing complexes 3 to 47 years 6,972,302
 6,462,053
Pipelines and equipment 15 to 45 years 139,344
 139,646
Assets under construction n/a 434,432
 226,626
Other 3 to 40 years 31,829
 29,605
Total property, plant and equipment   7,582,178
 6,861,942
Accumulated depreciation   2,074,464
 1,812,010
Net property, plant and equipment   $5,507,714
 $5,049,932


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


Impairments.Long-lived asset impairments. During the ninethree months ended September 30, 2017, WESMarch 31, 2023, the Partnership recognized impairments of $170.1 million, including ana long-lived asset impairment of $158.8$52.1 million atfor assets located in the Granger complex, which was impaired to its estimated fair value of $48.5 million using the income approach and Level 3 fair value inputs, due to a reduced throughput fee as a result of a producer’s bankruptcy. Also during the period, WES recognized additional impairments of $11.3 million, primarily related to (i) a $3.7 million impairment at the Granger straddle plant, which was impaired to its estimated salvage value of $0.6 million using the income approach and Level 3 fair value inputs, (ii) a $3.1 million impairment of the Fort Union equity investment (see Note 7), (iii) a $2.0 million impairment of an idle facility in northeast Wyoming, which was impaired to its estimated salvage value of $0.4 million using the market approach and Level 3 fair value inputs, and (iv) the cancellation of a pipeline project in West Texas.
During 2016, WES recognized impairments of $15.5 million, including an impairment of $6.1 million at the Newcastle system, which was impaired to its estimated fair value of $3.1 million using the income approach and Level 3 fair value inputs,Rockies due to a reduction in estimated future cash flows caused byresulting from a contract termination notice received in the low commodity price environment. Also during 2016, WES recognized impairmentsfirst quarter of $9.4 million, primarily related2023. This asset was impaired to its estimated fair value of $22.8 million. The fair value was measured using the cancellationincome approach and Level-3 fair value inputs. The income approach was based on the Partnership’s projected future EBITDA and free cash flows, which requires significant assumptions including, among others, future throughput volumes based on current expectations of projects at the DJ Basin complexproducer activity and Springfield and DBJV systems, and the abandonment of compressors at the MIGC system.


operating costs.
26
27

WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

7.  EQUITY INVESTMENTS

The following table presents the activity of WES’s equity investments for the nine months ended September 30, 2017:
 Equity Investments
thousandsFort
Union
 White
Cliffs
 Rendezvous Mont
Belvieu JV
 TEG TEP FRP Total
Balance at December 31, 2016$12,833
 $47,319
 $46,739
 $112,805
 $15,846
 $189,194
 $169,472
 $594,208
Investment earnings (loss), net of amortization2,964
 9,984
 840
 20,430
 2,325
 13,332
 12,833
 62,708
Impairment expense (1)
(3,110) 


 
 
 
 
 (3,110)
Contributions
 277
 
 
 
 107
 
 384
Distributions(3,359) (9,548) (2,296) (20,459) (2,167) (13,520) (12,964) (64,313)
Distributions in excess of cumulative earnings (2)
(1,662) (2,325) (1,616) (2,316) 
 (6,091) (2,245) (16,255)
Balance at September 30, 2017$7,666
 $45,707
 $43,667
 $110,460
 $16,004
 $183,022
 $167,096
 $573,622
(1)
Recorded in Impairments in the consolidated statements of operations.
(2)
Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis.

The investment balance in Fort Union at September 30, 2017, is $3.1 million less than WES’s underlying equity in Fort Union’s net assets due to an impairment loss recognized by WES in the second quarter of 2017 for its investment in Fort Union. This investment was impaired to its estimated fair value of $8.5 million, using the income approach and Level 3 fair value inputs.


27

WESTERN GAS EQUITY PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

8.9. SELECTED COMPONENTS OF WORKING CAPITAL


A summary of accounts receivable, net is as follows:
The PartnershipWES Operating
thousandsMarch 31,
2024
December 31,
2023
March 31,
2024
December 31,
2023
Trade receivables, net$720,169 $665,892 $738,328 $665,892 
Other receivables, net182 745 159 723 
Total accounts receivable, net$720,351 $666,637 $738,487 $666,615 
thousands September 30, 2017 December 31, 2016
Trade receivables, net $192,394
 $192,606
Other receivables, net 43
 30,415
Total accounts receivable, net $192,437
 $223,021


A summary of other current assets is as follows:
The PartnershipWES Operating
thousandsMarch 31,
2024
December 31,
2023
March 31,
2024
December 31,
2023
NGLs inventory$2,650 $2,557 $2,650 $2,557 
Imbalance receivables8,125 5,056 8,125 5,056 
Prepaid insurance15,707 21,065 13,904 18,571 
Contract assets8,708 9,595 8,708 9,595 
Other15,560 14,713 15,501 14,689 
Total other current assets$50,750 $52,986 $48,888 $50,468 
thousands September 30, 2017 December 31, 2016
Natural gas liquids inventory $8,459
 $7,126
Imbalance receivables 2,103
 3,483
Prepaid insurance 2,935
 2,889
Total other current assets $13,497
 $13,498


A summary of accrued liabilities is as follows:
The PartnershipWES Operating
thousandsMarch 31,
2024
December 31,
2023
March 31,
2024
December 31,
2023
Accrued interest expense$86,369 $124,937 $86,369 $124,937 
Short-term asset retirement obligations
3,790 7,606 3,790 7,606 
Short-term remediation and reclamation obligations
1,790 5,490 1,790 5,490 
Income taxes payable4,201 2,908 4,201 2,908 
Contract liabilities11,875 16,866 11,875 16,866 
Accrued payroll and benefits30,598 55,237  2,243 
Other35,098 49,528 35,001 43,411 
Total accrued liabilities$173,721 $262,572 $143,026 $203,461 
thousands September 30, 2017 December 31, 2016
Accrued interest expense $45,624
 $39,834
Short-term asset retirement obligations 3,976
 3,114
Short-term remediation and reclamation obligations 630
 630
Income taxes payable 1,024
 1,006
Other 6,445
 606
Total accrued liabilities $57,699
 $45,190


28

WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

9.10. DEBT AND INTEREST EXPENSE


At September 30, 2017, WGP’sWES Operating is the borrower for all outstanding debt consistedand is expected to be the borrower for all future debt issuances. The following table presents the outstanding debt:
 March 31, 2024December 31, 2023
thousandsPrincipalCarrying
Value
Fair
Value (1)
PrincipalCarrying
Value
Fair
Value (1)
Short-term debt
Commercial paper$100,000 $99,933 $99,933 $613,885 $610,312 $610,312 
Finance lease liabilities8,461 8,461 8,461 7,436 7,436 7,436 
Total short-term debt
$108,461 $108,394 $108,394 $621,321 $617,748 $617,748 
Long-term debt
3.100% Senior Notes due 2025$663,831 $662,804 $649,658 $666,481 $665,145 $650,765 
3.950% Senior Notes due 2025348,645 347,631 341,763 349,163 347,938 341,415 
4.650% Senior Notes due 2026467,204 465,848 458,425 467,204 465,705 459,617 
4.500% Senior Notes due 2028350,175 347,923 338,199 357,094 354,665 346,121 
4.750% Senior Notes due 2028381,848 379,816 370,935 382,888 380,747 374,767 
6.350% Senior Notes due 2029600,000 593,364 622,248 600,000 593,069 626,994 
4.050% Senior Notes due 20301,100,612 1,093,906 1,025,726 1,104,593 1,097,609 1,036,097 
6.150% Senior Notes due 2033750,000 741,302 769,373 750,000 741,125 780,203 
5.450% Senior Notes due 2044600,000 594,070 551,802 600,000 594,031 545,154 
5.300% Senior Notes due 2048700,000 687,798 611,492 700,000 687,735 614,082 
5.500% Senior Notes due 2048350,000 342,947 310,674 350,000 342,913 312,365 
5.250% Senior Notes due 20501,000,000 984,276 895,150 1,000,000 984,206 895,440 
Finance lease liabilities30,394 30,394 30,394 28,668 28,668 28,668 
Total long-term debt
$7,342,709 $7,272,079 $6,975,839 $7,356,091 $7,283,556 $7,011,688 

(1)Fair value is measured using the market approach and Level-2 fair value inputs.
29

WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
10. DEBT AND INTEREST EXPENSE

Debt activity. The following table presents the debt activity for the three months ended March 31, 2024:
thousandsCarrying Value
Balance at December 31, 2023$7,901,304 
Commercial paper borrowings (repayments), net (1)
(510,379)
Repayment of 3.100% Senior Notes due 2025(2,650)
Repayment of 3.950% Senior Notes due 2025(518)
Repayment of 4.500% Senior Notes due 2028(6,919)
Repayment of 4.750% Senior Notes due 2028(1,040)
Repayment of 4.050% Senior Notes due 2030(3,981)
Finance lease liabilities2,751
Other1,905
Balance at March 31, 2024$7,380,473

(1)Net of borrowings underand repayments related to commercial paper notes with original maturities of 90 days or less.

WES Operating Senior Notes. WES Operating issued the WGP RCF and WES’s 5.375% Senior Notes due 2021 (the “2021 Notes”), 4.000% Senior Notes due 2022 (the “2022 Notes”), 2.600% Senior Notes due 2018 (the “2018 Notes”), 5.450% Senior Notes due 2044 (the “2044 Notes”), 3.950%Fixed-Rate 3.100% Senior Notes due 2025, (the “2025 Notes”), 4.650%4.050% Senior Notes due 2026 (the “2026 Notes”)2030, 5.250% Senior Notes due 2050, and borrowings on the Floating-Rate Senior Notes due 2023 in January 2020. 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 3.290%, 4.169%, and 5.363%, respectively, at March 31, 2024, and were 3.790%, 4.671%, and 5.869%, respectively, at March 31, 2023. The effective interest rate of these notes is subject to adjustment from time to time due to a change in credit rating.
During the three months ended March 31, 2024, WES RCF.
The following table presents WESOperating purchased and WGP’s outstanding debt asretired $15.1 million of September 30, 2017,certain of its senior notes via open-market repurchases with cash from operations (see Debt activity above) and December 31, 2016:
  September 30, 2017 December 31, 2016
thousands Principal 
Carrying
Value
 
Fair
Value (1)
 Principal 
Carrying
Value
 
Fair
Value (1)
WGP RCF $28,000
 $28,000
 $28,000
 $28,000
 $28,000
 $28,000
2021 Notes 500,000
 495,541
 536,712
 500,000
 494,734
 536,252
2022 Notes 670,000
 668,795
 693,789
 670,000
 668,634
 681,723
2018 Notes 350,000
 349,558
 351,770
 350,000
 349,188
 351,531
2044 Notes 600,000
 593,206
 634,283
 600,000
 593,132
 615,753
2025 Notes 500,000
 491,653
 503,322
 500,000
 490,971
 492,499
2026 Notes 500,000
 495,133
 525,069
 500,000
 494,802
 518,441
WES RCF 250,000
 250,000
 250,000
 
 
 
Total long-term debt $3,398,000
 $3,371,886
 $3,522,945
 $3,148,000
 $3,119,461
 $3,224,199
(1)
Fair value is measured using the market approach and Level 2 inputs.

Debt activity. The following table presents WES and WGP’s debt activitya gain of $0.5 million was recognized for the nine months ended September 30, 2017:
thousands Carrying Value
Balance at December 31, 2016 $3,119,461
WES RCF borrowings 250,000
Other 2,425
Balance at September 30, 2017 $3,371,886

WGP RCF.early retirement of portions of these notes. As of September 30, 2017, WGP had $28.0 million of outstanding borrowings and $222.0 million available for borrowing underMarch 31, 2024, the WGP RCF, which matures in March 2019. As of September 30, 2017 and 2016, the interest rate on the outstanding WGP RCF borrowings was 3.24% and 2.53%, respectively. The commitment fee rate was 0.30% at September 30, 2017 and 2016. At September 30, 2017, WGP was in compliance with all covenants under the WGP RCF.

WGP WCF. As of September 30, 2017, WGP had no outstanding borrowings and $30.0 million available for borrowing under the WGP WCF. The interest rate on the WGP WCF was 2.74% and 2.03% at September 30, 2017 and 2016, respectively. At September 30, 2017, WGP was in compliance with all covenants under the WGP WCF. The WGP WCF will mature on November 1, 2017, and WGP does not intend to renew this facility.

WES3.100% Senior Notes. The 2018 Notes which are due in August 2018,2025 were classified as long-term debt on the consolidated balance sheet at September 30, 2017, as WES Operating has the ability and intent to refinance these obligations using long-term debt. At September 30, 2017,Subsequent to March 31, 2024, WES Operating purchased and retired $134.9 million of certain of its senior notes via open-market repurchases.
During the third quarter of 2023, WES Operating completed the public offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029. Net proceeds from the offering were used to fund a portion of the aggregate purchase price for the Meritage acquisition (see Note 3), to pay related costs and expenses, and for general partnership purposes. During the second quarter of 2023, WES Operating completed the public offering of $750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033. Net proceeds from the offering were used to repay borrowings under the RCF and for general partnership purposes. In addition, during 2023, WES Operating purchased and retired $276.7 million of certain of its senior notes via open-market repurchases and redeemed the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value with cash on hand.
As of March 31, 2024, WES Operating was in compliance with all covenants under the indenturesrelevant governing its outstanding notes.indentures.



29
30

WESTERN GAS EQUITYMIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

9.10. DEBT AND INTEREST EXPENSE (CONTINUED)


Revolving credit facility. In April 2023, WES RCF. Operating (i) repaid all then-outstanding borrowings under its RCF with proceeds from the 6.150% Senior Notes due 2033 offering, and (ii) entered into an amendment to its RCF to, among other things, extend the maturity date to April 2028 and provide for a maximum borrowing capacity up to $2.0 billion, expandable to a maximum of $2.5 billion, through the maturity date.
As of September 30, 2017, WES had $250.0March 31, 2024, there were no outstanding borrowings and $0.5 million of outstanding WES RCF borrowings and $4.6 million in outstanding letters of credit, resulting in $945.4 million available for$1.9 billion in effective borrowing capacity under the RCF, after taking into account the $100.0 million of outstanding commercial paper borrowings (see below), for which we maintain availability under the RCF as support for WES RCF, which matures in February 2020.Operating’s commercial paper program. As of September 30, 2017March 31, 2024 and 2016,2023, the interest rate on theany outstanding WES RCF borrowings was 2.54%6.63% and 1.82%6.21%, respectively. The facility-fee rate was 0.20% at September 30, 2017March 31, 2024 and 2016. At September 30, 2017,2023. As of March 31, 2024, WES Operating was in compliance with all covenants under the RCF.

Commercial paper program. In November 2023, WES RCF.operating entered into an unsecured commercial paper program under which it may issue (and have outstanding at any one time) an aggregate principal amount up to $2.0 billion. WES Operating intends to maintain a minimum aggregate available borrowing capacity under the RCF equal to the aggregate amount of outstanding commercial paper borrowings. The maturities of the notes may vary, but may not exceed 397 days. As of March 31, 2024, there were $100.0 million aggregate principal amount of short-term notes outstanding under the commercial paper program at a weighted-average interest rate of 6.00% and weighted-average maturity of four days.


Interest expense. The following table summarizes the amounts included in interest expense:
 Three Months Ended 
March 31,
thousands20242023
Long-term and short-term debt
$(95,956)$(81,151)
Finance lease liabilities(677)(163)
Commitment fees and amortization of debt-related costs(3,200)(2,881)
Capitalized interest5,327 2,525 
Interest expense$(94,506)$(81,670)

  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands 2017 2016 2017 2016
Third parties        
Long-term debt $(36,223) $(31,795) $(106,412) $(88,123)
Amortization of debt issuance costs and commitment fees (2,009) (2,022) (5,955) (5,517)
Capitalized interest 2,115
 1,343
 3,991
 4,674
Total interest expense – third parties (36,117) (32,474) (108,376) (88,966)
Affiliates        
Deferred purchase price obligation – Anadarko (1)
 
 1,173
 (71) 12,097
Total interest expense – affiliates 
 1,173
 (71) 12,097
Interest expense $(36,117) $(31,301) $(108,447) $(76,869)
(1)
See Note 2 for a discussion of the Deferred purchase price obligation - Anadarko.

10.11. COMMITMENTS AND CONTINGENCIES


Environmental obligations. The Partnership is subject to various environmental-remediation obligations arising from federal, state, and local regulations regarding air and water quality, hazardous and solid waste disposal, and other environmental matters. As of March 31, 2024 and December 31, 2023, the consolidated balance sheets included $3.5 million and $7.3 million, respectively, of liabilities for remediation and reclamation obligations. The current portion of these amounts is included in Accrued liabilities, and the long-term portion of these amounts is included in Other liabilities.

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


Other commitments. WES The Partnership has short-term payment obligations, or commitments, that include, among other things, a revolving credit facility, other third-party long-term debt, obligations related to itsthe Partnership’s capital spending programs, as well as those of its unconsolidated affiliates. As of September 30, 2017, WES had unconditionalpipeline and offload commitments, and various operating and finance leases. The payment obligations for servicesrelated to be rendered or products to be delivered in connection with itsthe Partnership’s capital projects of $143.3 million,spending programs, the majority of which is expected to be paid in the next twelve months. These commitments12 months, primarily relate primarily to expansion, construction, and asset-integrity projects at the DBJV system and theWest Texas complex, DBM water systems, DJ Basin complex, Powder River Basin complex, and DBM complexes.oil system.

31
Lease commitments. Anadarko, on WES’s behalf, has entered into lease arrangements for corporate offices, shared field offices and a warehouse supporting WES’s operations, and equipment leases for which Anadarko charges WES rent. The leases for the corporate offices and shared field offices extend through 2028 and 2033, respectively, and the lease for the warehouse expired in February 2017.

WES’s rent expense associated with office, warehouse and equipment leases was $11.3 million and $30.7 million for the three and nine months ended September 30, 2017, respectively, and $8.9 million and $26.2 million for the three and nine months ended September 30, 2016, respectively.
Table of Contents


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations


The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements, in whichwherein WES Operating is fully consolidated, and which are included under Part I, Item 1 of this quarterly report, as well as ourand the historical consolidated financial statements, and the notes thereto, which are included under Part II, Item 8 of our 2016the 2023 Form 10-K as filed with the SEC on February 23, 2017.21, 2024.
The Partnership’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as of March 31, 2024 (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 from time to time make in other public filings, press releases, and statements by management, forward-lookingforward-looking statements concerning WES’sour operations, economic performance, and financial condition. These forward-lookingforward-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”“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”“forward-looking” information.
Although we and WGP GPour general partner believe that the expectations reflected in such forward-lookingour forward-looking statements are reasonable, neither we nor WGP GPour general partner can giveprovide any assurance that such expectations will prove to have been correct. These forward-lookingforward-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 expected receipt of,unitholders and the amountsamount of distributions from WES;such distributions;


WES’s and Anadarko’sour assumptions about the energy market;


WES’s future throughput (including AnadarkoOccidental production) whichthat is gathered or processed by, or transported through, WES’sour assets;


our operating results of WES;results;


competitive conditions;


technology;


the availability of capital resources to fund acquisitions, capital expenditures, and other contractual obligations, of WES, and WES’sour ability to access those resources from Anadarko orfinancing through the debt or equity capital markets;


the supply of, demand for, and price of oil, natural gas, NGLs, and related products or services;


WES’s ability to mitigate exposure to the commodity-price risks inherent in its percent-of-proceedspercent-of-proceeds, percent-of-product, keep-whole, and keep-whole contracts through the extension of WES’s commodity price swap agreements with Anadarko, or otherwise;fixed-recovery processing contracts;


weather and natural disasters;


inflation;


the availability of goods and services;


general economic conditions, internationally, domestically, or in the jurisdictions in which WES iswe are doing business;

32



federal, state, and local laws and state-approved voter ballot initiatives, including those laws or ballot initiatives that limit Anadarko and other producers’ hydraulic-fracturing activities or other oil and natural-gas development or operations;


environmental liabilities;


legislative or regulatory changes, including changes affecting our or WES’s status as a partnership for federal income tax purposes;


changes in the financial or operational condition of WES or Anadarko;Occidental;


the creditworthiness of AnadarkoOccidental or WES’sour other counterparties, including financial institutions, operating partners, and other parties;


changes in WES’s or Anadarko’sOccidental’s capital program, corporate strategy, or other desired areas of focus;


WES’sour commitments to capital projects;


WES’sour ability to useaccess liquidity under the WES RCF;RCF and commercial paper program;


our and WES’s ability to repay debt;


the resolution of litigation or other disputes;

conflicts of interest among WES, WES GP, WGPus and WGP GP,our general partner and affiliates,its related parties, including Anadarko;Occidental, with respect to, among other things, the allocation of capital and operational and administrative costs, and our future business opportunities;


WES’sour ability to maintain and/or obtain rights to operate itsour assets on land owned by third parties;


our or WES’s ability to acquire assets on acceptable terms from Anadarkothird parties;

non-payment or third parties, and Anadarko’s ability to generate an inventorynon-performance of assets suitable for acquisition;

non-payment or non-performance of Anadarko or WES’s other significant customers, including under WES’s gathering, processing, transportation, and transportation agreements and its $260.0 million note receivable from Anadarko;disposal agreements;


the timing, amount, and terms of our or WES’s future issuances of equity and debt securities;


the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the National Transportation Safety Board (“NTSB”), related to Anadarko’s operations in Colorado, and continued or additional disruptions in operations that may occur as Anadarkowe and WESour customers comply with any regulatory orders or other state or local changes in laws or regulations in Colorado;regulations;

cyber-attacks or security breaches; 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 our 2016the 2023 Form 10-K, and10-K, in our quarterly reports on Form 10-Q,10-Q, and in our other public filings and press releases.


The riskRisk 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-lookingforward-looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward-lookingforward-looking statements, whether as a result of new information, future events, or otherwise.

33


EXECUTIVE SUMMARY


We were formed by Anadarko in September 2012 by converting WGR Holdings, LLC into an MLP and changing its name to Western Gas Equity Partners, LP. We closed our IPO in December 2012 and own WES GP andare a significant limited partner interest in WES, a growth-oriented Delaware MLP formed by Anadarko to acquire, own, develop and operate midstream energy assets. Our consolidated financial statements include the consolidated financial results of WES due to our 100% ownership interest in WES GP and WES GP’s control of WES. Our only cash-generating assets consist of ourcompany organized as a publicly traded partnership, interests in WES, and we currently have no independent operations.
WES currently owns or has investments in assets located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania and Texas. WES is 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. WES provides theseIn our capacity as a natural-gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and our customers under certain contracts. To provide superior midstream services for Anadarko, as well as for third-party producersservice, we focus on ensuring the reliability and customers.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, 2017, WES’sMarch 31, 2024, our assets and investments consisted of the following:
Wholly
Owned and
Operated
Operated
Interests
Non-Operated
Interests
Equity
Interests
Gathering systems (1)
18 
Treating facilities38 — — 
Natural-gas processing plants/trains
24 — 
NGLs pipelines— — 
Natural-gas pipelines
— — 
Crude-oil pipelines
— 

(1)Includes the DBM water systems.
  
Owned and
Operated
 
Operated
Interests
 
Non-Operated
Interests
 
Equity
Interests
Gathering systems 12
 3
 3
 2
Treating facilities 19
 3
 
 3
Natural gas processing plants/trains 19
 5
 
 2
NGL pipelines 2
 
 
 3
Natural gas pipelines 5
 
 
 
Oil pipelines 
 1
 
 1


Significant financial and operational events during the ninethree months ended September 30, 2017,March 31, 2024, included the following:


We raised our distributionDuring the first quarter of 2024, we (i) closed on the sale of several equity investments to $0.53750 per unitthird parties for combined proceeds of $588.6 million, which included $5.9 million in pro-rata distributions through closing, and (ii) entered into a definitive agreement for the third quarterdivestment of 2017, representing a 2% increase overour 33.75% interest in the distribution for the second quarter of 2017 and a 20% increase over the distribution for the third quarter of 2016.

In March 2017, WES acquired the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration, resultingsystems, which closed in a net gain of $125.7 million.April 2024. See Acquisitions and Divestitures within this Item 2 for additional information.


In May 2017, WES reached an agreement with Anadarko to settle the outstanding Deferred purchase price obligation - Anadarko, whereby WES made a cash payment to AnadarkoOperating purchased and retired $15.1 million of $37.3 million during the second quarter of 2017.

On March 1, 2017, 50% of the outstanding WES Series A Preferred units converted into WES common units on a one-for-one basis, and on May 2, 2017, the remaining WES Series A Preferred units converted into WES common units on a one-for-one basis. See Equity Offerings within this Item 2 for additional information.

During the second quarter of 2017, WES commenced operation of the DBM water systems (included within Gathering systems in the table above).

In June 2017, WES closed on the salecertain of its Helper and Clawson systems, which resulted in a net gain on divestituresenior notes via open-market repurchases.

Our first-quarter 2024 per-unit distribution of $16.4 million. See Acquisitions and Divestitures within this Item 2 for additional information.
$0.875 increased $0.300 from the fourth-quarter 2023 per-unit distribution of $0.575.


In February 2017, Anadarko electedNatural-gas throughput attributable to extend the conversion date of the WES Class C units from December 31, 2017, to March 1, 2020.


WES received $52.9 million in cash proceeds from insurers in final settlement of its claims related to the incident at the DBM complex, including $29.9 million for business interruption insurance claims and $23.0 million for property insurance claims. See Liquidity and Capital Resources within this Item 2 for additional information.

WES raised its distribution to $0.905 per unittotaled 4,990 MMcf/d for the third quarter of 2017,three months ended March 31, 2024, representing a 2% increase over the distribution for the second quarter of 2017 and a 7%21% increase overcompared to the distribution for the third quarter of 2016.three months ended December 31, 2023, and March 31, 2023, respectively.


ThroughputCrude-oil and NGLs throughput attributable to WES for natural gas assets totaled 3,427 MMcf/d and 3,610 MMcf/d for the three and nine months ended September 30, 2017, respectively, representing a 16% and 8% decrease, respectively, compared to the same periods in 2016.

Throughput for crude, NGL and produced water assets totaled 209 MBbls/d and 187565 MBbls/d for the three and nine months ended September 30, 2017, respectively,March 31, 2024, representing a 13%20% decrease and 1% increase, respectively, an 8% decreasecompared to the same periods in 2016.three months ended December 31, 2023, and March 31, 2023, respectively.


WES’s operating income (loss)Produced-water throughput attributable to WES totaled 1,126 MBbls/d for the three months ended March 31, 2024, representing a 7% increase and an 18% increase compared to the three months ended December 31, 2023, and March 31, 2023, respectively.

Gross margin was $179.5 million and $525.5$683.7 million for the three and nine months ended September 30, 2017, respectively,March 31, 2024, representing a 9% decrease5% increase and 0% change, respectively,a 27% increase compared to the same periods in 2016.three months ended December 31, 2023, and March 31, 2023, respectively. See Reconciliation of Non-GAAP Financial Measures within this Item 2.


Adjusted gross margin attributable to WES for natural-gas assets (as defined under the caption Key Performance MetricsReconciliation of Non-GAAP Financial Measures within this Item 2) averaged $0.97 per Mcf and $0.92$1.32 per Mcf for the three and nine months ended September 30, 2017, respectively,March 31, 2024, representing an 18% and 12%a 2% increase respectively, compared to the same periods in 2016.three months ended December 31, 2023, and March 31, 2023.
34



Adjusted gross margin for crude NGL-oil and NGLs assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 2) averaged $2.92 per Bbl for the three months ended March 31, 2024, representing a 20% increase and a 10% increase compared to the three months ended December 31, 2023, and March 31, 2023, respectively.

Adjusted gross margin for produced-water assets (as defined under the caption Key Performance MetricsReconciliation of Non-GAAP Financial Measures within this Item 2) averaged $2.03 per Bbl and $2.05$0.95 per Bbl for the three and nine months ended September 30, 2017, respectively,March 31, 2024, representing an 8%a 10% increase and 2% decrease, respectively,a 17% increase compared to the samethree months ended December 31, 2023, and March 31, 2023, respectively.

The following table provides additional information on throughput for the periods in 2016.presented below:
Three Months Ended
March 31, 2024December 31, 2023Inc/
(Dec)
March 31, 2023Inc/
(Dec)
Throughput for natural-gas assets (MMcf/d)
Delaware Basin1,761 1,704 %1,569 12 %
DJ Basin1,372 1,341 %1,306 %
Powder River Basin406 369 10 %33 NM
Equity investments508 489 %423 20 %
Other1,117 1,145 (2)%915 22 %
Total throughput for natural-gas assets
5,164 5,048 %4,246 22 %
Throughput for crude-oil and NGLs assets (MBbls/d)
Delaware Basin225 225 — %205 10 %
DJ Basin87 81 %69 26 %
Powder River Basin23 20 15 %— NM
Equity investments202 347 (42)%314 (36)%
Other39 42 (7)%35 11 %
Total throughput for crude-oil and NGLs assets
576 715 (19)%623 (8)%
Throughput for produced-water assets (MBbls/d)
Delaware Basin1,149 1,076 %977 18 %
Total throughput for produced-water assets
1,149 1,076 %977 18 %

NMNot meaningful
35


Anadarko’s Colorado Response. Following a home explosionOUTLOOK

We expect our business 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 producer activity. Our business is primarily driven by the level of production of crude oil and natural gas by producers in Firestone, Colorado in April 2017, Anadarko took precautionary measuresour areas of operation. This activity, however, can be impacted negatively by, among other things, commodity-price fluctuations and operational challenges. Fluctuating crude-oil, natural-gas, and NGLs prices can reduce the level of our customers’ activities and change the allocation of capital within their own asset portfolios. Such fluctuations can also impact us directly to shut in all operated vertical wellsthe extent we take ownership of and sell certain volumes at the tailgate of our plants for our own account. During 2020, oil and natural-gas prices were negatively impacted by the worldwide macroeconomic downturn that followed the global outbreak of COVID-19. In 2021, prices began to increase and in the DJ Basinfirst quarter of 2022, commodity prices increased significantly in connection with the war in Ukraine. For example, the New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude-oil daily settlement prices during 2023 ranged from a low of $66.74 per barrel in March 2023 to conduct additional inspections. It subsequently testeda high of $93.68 per barrel in September 2023, and permanently plugged, abandoned, and capped all one-inch return lines associated with these wells. In May 2017,prices during the Colorado Oil & Gas Conservation Commission (“COGCC”) issuedthree months ended March 31, 2024, ranged from a two-phase Noticelow of $70.38 per barrel in January 2024 to Operators (“NTO”) requiring all operators to inventory and integrity test existing flowlines within 1,000 feeta high of $83.47 per barrel in March 2024. Similar disruptions could occur as a building unit and abandon all inactive flowlines in such areas. During the third quarter, Anadarko substantially completed the requirementsconsequence of the NTO. In August 2017, following a three-month reviewcurrent conflict in the Middle East. The extent and duration of oil and gas operations, the Governor of Colorado announced several policy initiatives designed to enhance public safety, which are to be implemented over the next several months through rulemaking or legislation. Anadarko continues to work cooperatively with state regulators and others and is also cooperating with the NTSB in its investigation related to the incident.

Significant Item Affecting Comparability. On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. The majority of the damage was to the liquid handling facilitiescommodity-price volatility, and the amine treating units atassociated direct and indirect impact on our business, cannot be predicted. To address the inletrisks posed by fluctuating commodity prices, we intend to continue evaluating the relevant price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility.
Additionally, even when the commodity-price environments are favorable, our customers must manage numerous operational challenges, including severe weather disruptions, downstream and produced-water takeaway constraints, seismicity concerns, new regulatory requirements, and the ability to optimize the efficiency and results of large, complex drilling programs. Our producers’ ability to mitigate or manage such challenges can have a significant impact on the complex. Train II (with capacity of 100 MMcf/d) sustained the most damage of the processing trains and returnedvolumes available for us to service in December 2016. Train III (with capacitythe short term. For this reason, we strive to work proactively with our customers whenever possible to provide high levels of 200 MMcf/d)reliability on our systems and help them meet these operational challenges as they arise.

Impact of inflation and supply-chain disruptions. The U.S. economy has recently experienced minimal damage and returnedsignificant inflation relative to full servicehistorical precedent, from, among other things, supply-chain disruptions caused by, or governmental stimulus or fiscal policies adopted in May 2016. For ease of reference throughout the remainder of this Management’s Discussion and Analysis, the damageresponse to, the processing facilityCOVID-19 crisis and resulting lackin connection with the war in Ukraine. More specifically, the continued bottlenecks and disruptions have caused difficulties within the U.S. and global supply chains, creating logistical delays along with labor shortages. Continued inflation has raised our costs for steel products, automation components, power supply, labor, materials, fuel, and services, which has increased our operating costs and capital expenditures. Increases in inflationary pressure could materially and negatively impact our financial results. To the extent permitted by regulations and escalation provisions in certain of processing capacity and associated financial statement impact is referredour existing agreements, we have the ability to as the “DBM outage.” See Note 1—Descriptionrecover a portion of Business and Basis of Presentationincreased costs in the Notesform of higher fees.

Impact of interest rates. Short- and long-term interest rates can be volatile, resulting in immediate changes to Consolidated Financial Statements under Part I, Item 1interest expense on RCF borrowings and commercial paper borrowings. Any future increases in interest rates likely will result in additional increases in financing costs. As with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of this Form 10-Q.investors who invest in our units, and a rising interest-rate environment could have an adverse impact on our unit price and our ability to issue additional equity, or increase the cost of issuing equity, to make acquisitions, to reduce debt, or for other purposes. However, we expect our cost of capital to remain competitive, as our competitors face similar interest-rate dynamics.

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ACQUISITIONS AND DIVESTITURES


Acquisitions. Mont Belvieu JV, Whitethorn LLC, Panola, and Saddlehorn. During the first quarter of 2024, we closed on the sale of the following equity investments to third parties: (i) the 25.00% interest in Mont Belvieu JV, (ii) the 20.00% interest in Whitethorn LLC, (iii) the 15.00% interest in Panola, and (iv) the 20.00% interest in Saddlehorn. The following table presents the acquisitions completed by WES during 2017 and 2016, and identifies the funding sources for such acquisitions. See Note 2—Acquisitions and Divestiturescombined proceeds received in the Notes to Consolidated Financial Statements under Part I, Item 1first quarter of this Form 10-Q.
thousands except unit and percent amounts 
Acquisition
Date
 Percentage
Acquired
 Borrowings 
Cash
On Hand
 
WES Common Units
Issued
 WES Series A Preferred Units Issued
Springfield system (1)
 03/14/2016 50.1% $247,500
 $
 2,089,602
 14,030,611
DBJV system (2)
 03/17/2017 50% 
 155,000
 
 
(1)
WES acquired Springfield from Anadarko for $750.02024 of $588.6 million includes $5.9 million consisting of $712.5 million in cash and the issuance of 1,253,761 of WES common units. Springfield owns a 50.1% interest in the Springfield system. WES financed the cash portion of the acquisition through: (i) borrowings of $247.5 million on the WES RCF, (ii) the issuance of 835,841 of WES common units to WGP and (iii) the issuance of WES Series A Preferred units to private investors. See Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for further information regarding WES’s Series A Preferred units. WGP financed the purchase of the WES common units by borrowing $25.0 million under the WGP RCF. See Note 9—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
(2)
WES acquired the Additional DBJV System Interest from a third party. See Property exchange below.

Property exchange. On March 17, 2017, WES acquired the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration. WES previously held a 50% interest in, and operated, the DBJV system. The Property Exchange resultedpro-rata distributions through closing, resulting in a net gain on sale of $125.7$239.7 million that was recorded as Gain (loss) on divestiture and other, net in the consolidated statementsstatement of operations. See Note 2—Acquisitions and DivestituresThe sale of the interests in the Notes to Consolidated Financial Statements under Part I, Item 1Mont Belvieu JV and Whitethorn LLC also resolved outstanding legal proceedings associated with those assets.

Marcellus Interest systems. In April 2024, we closed on the sale of this Form 10-Q.

Divestitures. Duringour 33.75% interest in the second quarterMarcellus Interest systems for proceeds of 2017, the Helper and Clawson systems, located in Utah, were sold to a third party,$206.2 million, resulting in aan estimated net gain on sale of $16.4approximately $65.0 million that will be recorded as Gain (loss) on divestiture and other, net in the consolidated statementsstatement of operations.
Duringoperations during the fourthsecond quarter of 2016,2024. As of March 31, 2024, the Hugoton system, located in Southwest Kansas and Oklahoma, was soldMarcellus Interest systems satisfied criteria to a third party, resulting in a net loss on sale of $12.0 million recorded as Gain (loss) on divestiture and other, net inbe considered held for sale. At March 31, 2024, the consolidated statementsbalance sheet included current assets of operations.$6.6 million, long-term assets of $142.7 million, current liabilities of $5.9 million, and long-term liabilities of $2.1 million associated with assets held for sale.


PresentationMeritage. In October 2023, we closed on the acquisition of WES assets.The term “WES assets” includes bothMeritage for $885.0 million (subject to certain customary post-closing adjustments) funded with cash, including proceeds from our $600.0 million senior note issuance in September 2023and borrowings on the assets indirectly ownedRCF.

See Note 3—Acquisitions and the interests accounted for under the equity method (See Divestitures and Note 7—Equity Investments in the Notes to Consolidated Financial Statements10—Debt and Interest Expense under Part I, Item 1 of this Form 10-Q)10-Q.

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RESULTS OF OPERATIONS

OPERATING RESULTS

The following tables and discussion present a summary of our results of operations:
Three Months Ended
thousandsMarch 31, 2024December 31, 2023March 31, 2023
Total revenues and other (1)
$887,729 $858,208 $733,982 
Equity income, net – related parties32,819 36,120 39,021 
Total operating expenses (1)
480,791 495,977 480,673 
Gain (loss) on divestiture and other, net239,617 (6,434)(2,118)
Operating income (loss)679,374 391,917 290,212 
Interest expense(94,506)(97,622)(81,670)
Gain (loss) on early extinguishment of debt524 — — 
Other income (expense), net2,346 2,862 1,215 
Income (loss) before income taxes587,738 297,157 209,757 
Income tax expense (benefit)1,522 1,405 1,416 
Net income (loss)586,216 295,752 208,341 
Net income (loss) attributable to noncontrolling interests13,386 7,398 4,696 
Net income (loss) attributable to Western Midstream Partners, LP (2)
$572,830 $288,354 $203,645 

(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 us through our partnership interests in WES as of September 30, 2017. Because Anadarko controls WES through its ownership and control of us, and because we own the entire interest in WES GP, each of WES’s acquisitions of WES assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, WES assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by WES (see related parties for services received. See Note 2—Acquisitions and Divestitures6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q). Further, after10-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.

For purposes of the following discussion, any increases or decreases refer to the comparison of the three months ended March 31, 2024, to the three months ended December 31, 2023, or to the three months ended March 31, 2023, as applicable.
38

Throughput
Three Months Ended
March 31, 2024December 31, 2023Inc/
(Dec)
March 31, 2023Inc/
(Dec)
Throughput for natural-gas assets (MMcf/d)
Gathering, treating, and transportation606 516 17 %369 64 %
Processing4,050 4,043 — %3,454 17 %
Equity investments (1)
508 489 %423 20 %
Total throughput5,164 5,048 %4,246 22 %
Throughput attributable to noncontrolling interests (2)
174 172 %139 25 %
Total throughput attributable to WES for natural-gas assets
4,990 4,876 %4,107 21 %
Throughput for crude-oil and NGLs assets (MBbls/d)
Gathering, treating, and transportation374 368 %309 21 %
Equity investments (1)
202 347 (42)%314 (36)%
Total throughput576 715 (19)%623 (8)%
Throughput attributable to noncontrolling interests (2)
11 13 (15)%12 (8)%
Total throughput attributable to WES for crude-oil and NGLs assets
565 702 (20)%611 (8)%
Throughput for produced-water assets (MBbls/d)
Gathering and disposal1,149 1,076 %977 18 %
Throughput attributable to noncontrolling interests (2)
23 22 %20 15 %
Total throughput attributable to WES for produced-water assets
1,126 1,054 %957 18 %

(1)Represents our share of average throughput for investments accounted for under the equity method of accounting.
(2)Includes (i) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary and (ii) for natural-gas assets, the 25% third-party interest in Chipeta, which collectively represent WES’s noncontrolling interests.

Natural-gas assets
Total throughput attributable to WES for natural-gas assets increased by 114 MMcf/d compared to the three months ended December 31, 2023, primarily due to (i) higher volumes at the West Texas and DJ Basin complexes due to increased production in the areas, (ii) higher volumes at the Powder River Basin complex due to the Meritage acquisition, and (iii) higher volumes on the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline. These increases were offset partially by lower volumes at the Granger complex due to a contract expiration in the fourth quarter of 2023.
Total throughput attributable to WES for natural-gas assets increased by 883 MMcf/d compared to the three months ended March 31, 2023, primarily due to (i) higher volumes at the Powder River Basin complex due to the Meritage acquisition, (ii) higher volumes at the West Texas and DJ Basin complexes due to increased production in the areas, (iii) higher volumes at the MIGC and Marcellus Interest systems and the Chipeta and Brasada complexes, (iv) higher volumes on the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline, and (v) higher volumes at the Springfield gas-gathering system due to new third-party production. These increases were offset partially by lower volumes at the Granger complex due to a contract expiration in the fourth quarter of 2023.

Crude-oil and NGLs assets
Total throughput attributable to WES for crude-oil and NGLs assets decreased by 137 MBbls/d compared to the three months ended December 31, 2023, primarily due to the divestiture of Whitethorn LLC, Mont Belvieu JV, Saddlehorn, and Panola in the first quarter of 2024.

39

Total throughput attributable to WES for crude-oil and NGLs assets decreased by 46 MBbls/d compared to the three months ended March 31, 2023, primarily due to the divestiture of Whitethorn LLC, Mont Belvieu JV, Saddlehorn, and Panola in the first quarter of 2024. These decreases were offset partially by (i) higher volumes on the Thunder Creek NGL pipeline which was acquired as part of the Meritage acquisition and (ii) higher volumes at the DBM and DJ Basin oil systems resulting from increased production in the areas.

Produced-water assets
Total throughput attributable to WES for produced-water assets increased by 72 MBbls/d and 169 MBbls/d compared to the three months ended December 31, 2023, and March 31, 2023, respectively, due to higher production.

Service Revenues
Three Months Ended
thousands except percentagesMarch 31, 2024December 31, 2023Inc/
(Dec)
March 31, 2023Inc/
(Dec)
Service revenues – fee based$781,262 $763,837 %$647,867 21 %
Service revenues – product based66,740 49,515 35 %46,810 43 %
Total service revenues$848,002 $813,352 %$694,677 22 %

Service revenues – fee based
Service revenues – fee based increased by $17.4 million compared to the three months ended December 31, 2023, primarily due to increases of (i) $16.5 million at the West Texas complex as a result of a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, increased throughput, and increased deficiency fees on certain contracts with increasing throughput minimums, (ii) $13.4 million at the DBM water systems due to a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, and increased throughput, (iii) $6.3 million at the Powder River Basin complex as a result of increased throughput attributable to the acquisition of WES assetsMeritage, and (iv) $5.9 million at the DJ Basin complex due to increased throughput. These increases were offset partially by decreases of (i) $12.6 million at the Springfield system primarily due to an annual cost-of-service rate adjustment that increased revenue during the fourth quarter of 2023, (ii) $7.4 million at the DJ Basin oil system primarily due to an annual cost-of-service rate adjustment that increased revenue during the fourth quarter of 2023, partially offset by increased throughput, and (iii) $2.3 million at the Granger complex primarily due to a contract expiration in the fourth quarter of 2023.
Service revenues – fee based increased by $133.4 million compared to the three months ended March 31, 2023, primarily due to increases of (i) $48.9 million at the Powder River Basin complex attributable to the acquisition of Meritage, (ii) $45.8 million at the West Texas complex as a result of increased throughput, a higher average fee resulting from Anadarko, we (by virtuea cost-of-service rate redetermination effective January 1, 2024, and increased deficiency fees on certain contracts with increasing throughput minimums, (iii) $26.0 million at the DBM water systems as a result of increased throughput and a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, (iv) $20.4 million at the DJ Basin complex due to increased throughput, and (v) $6.7 million at the DBM oil system as a result of increased throughput and a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024. These increases were offset partially by decreases of (i) $6.6 million at the Brasada complex due to a change in contract terms effective July 1, 2023, (ii) $2.8 million at the DJ Basin oil system primarily due to decreased deficiency fees on demand volumes, partially offset by increased throughput, and (iii) $2.3 million at the Granger complex primarily due to a contract expiration in the fourth quarter of 2023.

Service revenues – product based
Service revenues – product based increased by $17.2 million compared to the three months ended December 31, 2023, primarily due to increases of $12.4 million at the West Texas complex as a result of increased volumes sold and $2.4 million at the DJ Basin complex due to increased average prices.
Service revenues – product based increased by $19.9 million compared to the three months ended March 31, 2023, primarily due to increases of $14.8 million at the West Texas complex primarily due to increased volumes sold and $2.4 million at the DBM water systems due to increased volumes sold and average prices.
40

Product Sales
Three Months Ended
thousands except percentages and per-unit amountsMarch 31, 2024December 31, 2023Inc/
(Dec)
March 31, 2023Inc/
(Dec)
Natural-gas sales
$3,194 $14,213 (78)%$2,775 15 %
NGLs sales36,098 30,475 18 %36,250 — %
Total Product sales$39,292 $44,688 (12)%$39,025 %
Per-unit gross average sales price:
Natural gas (per Mcf)$1.25 $1.63 (23)%$1.75 (29)%
NGLs (per Bbl)30.93 31.62 (2)%28.78 %

Natural-gas sales
Natural-gas sales decreased by $11.0 million compared to the three months ended December 31, 2023, primarily due to decreases of (i) $8.3 million at the West Texas complex as a result of decreased volumes sold and average prices and (ii) $2.8 million at the DJ Basin complex as a result of decreased volumes sold.
Natural-gas sales increased by $0.4 million compared to the three months ended March 31, 2023, primarily due to an increase of $2.7 million at the DJ Basin complex as a result of increased average prices, partially offset by decreased volumes sold. This increase was offset partially by a decrease of $2.2 million at the West Texas complex due to decreased average prices, partially offset by increased volumes sold.

NGLs sales

NGLs sales increased by $5.6 million compared to the three months ended December 31, 2023, primarily due to increases of (i) $3.7 million and $1.6 million at the DJ Basin and Chipeta complexes, respectively, due to increased average prices and (ii) $2.4 million at the Powder River Basin complex as a result of increased volumes sold attributable to the acquisition of Meritage. These increases were offset partially by a decrease of $8.2 million at the West Texas complex due to a mix in contract structures, partially offset by increased average prices.
NGLs sales decreased by $0.2 million compared to the three months ended March 31, 2023, primarily due to decreases of $7.7 million and $5.8 million at the DJ Basin and West Texas complexes, respectively, due to decreased average prices, partially offset by increased volumes sold. These decreases were offset partially by increases of (i) $6.4 million at the Powder River Basin complex attributable to the acquisition of Meritage, (ii) $2.5 million at the DBM water systems due to increased skim-oil volumes sold and average prices, and (iii) $2.4 million at the Chipeta complex due to increased volumes sold.

Equity Income, Net – Related Parties
Three Months Ended
thousands except percentagesMarch 31, 2024December 31, 2023Inc/
(Dec)
March 31, 2023Inc/
(Dec)
Equity income, net – related parties$32,819 $36,120 (9)%$39,021 (16)%

Equity income, net – related parties decreased by $3.3 million compared to the three months ended December 31, 2023, primarily due to decreases of $6.9 million at Mont Belvieu JV and $2.2 million at Saddlehorn due to the divestment of our consolidationinterests in the first quarter of WES) and WES may be required2024. These decreases were partially offset by an increase of $4.8 million at Whitethorn LLC due to recast our financial statements to include thecommercial activities of such WES assets from the date of common control.


EQUITY OFFERINGS

Public equity offerings. In June 2016, Anadarko sold 12,500,000 of its WGP common unitsprior to the public through an underwritten offering. We did not receive any proceeds from, or incur any expensedivestment of our interest in the public offering.first quarter of 2024.

Tangible equity units. In June 2015, Anadarko completed the public issuance of 9,200,000 7.50% TEUs, including 1,200,000 TEUs pursuantEquity income, net – related parties decreased by $6.2 million compared to the full exercisethree months ended March 31, 2023, primarily due to decreases of the underwriters’ over-allotment option,$6.8 million at a priceMont Belvieu JV due to the publicdivestment of $50.00 per TEU. Each TEU that Anadarko issued consists of (1) a prepaid equity purchase contract for WGP common units owned by Anadarko (subject to Anadarko’s right to elect to deliver shares of its common stock in lieu of such WGP common units) and (2) a senior amortizing note due June 7, 2018. We did not receive any proceeds from, or incur any expenseour interest in the public offering.first quarter of 2024 and $2.9 million at TEP. These decreases were partially offset by increases of $1.9 million and $1.8 million at Red Bluff Express and FRP, respectively.


WES Series A Preferred units. In 2016, WES issued 21,922,831 WES Series A Preferred units
41

Cost of Product and Operation and Maintenance Expenses
Three Months Ended
thousands except percentagesMarch 31, 2024December 31, 2023Inc/
(Dec)
March 31, 2023Inc/
(Dec)
Residue purchases$9,228 $7,931 16 %$15,638 (41)%
NGLs purchases70,425 60,303 17 %51,829 36 %
Other(33,574)(27,431)(22)%(16,008)(110)%
Cost of product46,079 40,803 13 %51,459 (10)%
Operation and maintenance194,939 200,426 (3)%174,239 12 %
Total Cost of product and Operation and maintenance expenses$241,018 $241,229 — %$225,698 %

Residue purchases
Residue purchases decreased by $6.4 million compared to private investors. Pursuantthe three months ended March 31, 2023, primarily due to an agreement between WES anddecreases of (i) $5.1 million at the holders of the WES Series A Preferred units, 50% of the WES Series A Preferred units converted into WES common units onGranger complex due to a one-for-one basis on March 1, 2017, and the remaining WES Series A Preferred units converted on a one-for-one basis on May 2, 2017. See Note 4—Equity and Partners’ Capitalcontract expiration in the fourth quarter of 2023 and (ii) $1.9 million at the West Texas complex due to lower average prices.

NGLs purchases
NGLs purchases increased by $10.1 million compared to the three months ended December 31, 2023, primarily due to increased volumes purchased at the West Texas complex.
NGLs purchases increased by $18.6 million compared to the three months ended March 31, 2023, primarily due to increases of (i) $16.7 million at the West Texas complex attributable to increased volumes purchased, (ii) $2.4 million at the Powder River Basin complex attributable to the acquisition of Meritage, and (iii) $2.3 million at the DBM water systems due to increased skim-oil volumes and average prices. These increases were offset partially by a decrease of $5.2 million at the DJ Basin complex primarily due to a change in contract mix during the first quarter of 2024.

Other items
Other items decreased by $6.1 million compared to the three months ended December 31, 2023, primarily due to a decrease of $10.3 million at the West Texas complex due to changes in imbalance positions, partially offset by an increase of $4.2 million at the Powder River Basin complex due to changes in imbalance positions.
Other items decreased by $17.6 million compared to the three months ended March 31, 2023, primarily due to decreases of (i) $13.7 million at the West Texas complex due to changes in imbalance positions, partially offset by higher offload costs, and (ii) $2.7 million and $2.6 million at the Chipeta and DJ Basin complexes, respectively, attributable to changes in imbalance positions.

Operation and maintenance expense
Operation and maintenance expense decreased by $5.5 million compared to the three months ended December 31, 2023, primarily due to decreases of (i) $2.4 million in equipment rental costs, (ii) $2.0 million in each of utility expense and equipment maintenance and repair expense, (iii) $1.8 million in mechanical-integrity costs, and (iv) $1.7 million in land-related costs. These decreases were offset partially by an increase of $5.9 million in salaries and wages costs.
Operation and maintenance expense increased by $20.7 million compared to the three months ended March 31, 2023, primarily due to increases of (i) $11.4 million in salaries and wages costs, (ii) $4.6 million in utility expense, (iii) $2.9 million in chemical and treating services, and (iv) $2.9 million in land-related costs.

42

Other Operating Expenses
Three Months Ended
thousands except percentagesMarch 31, 2024December 31, 2023Inc/
(Dec)
March 31, 2023Inc/
(Dec)
General and administrative$67,839 $73,060 (7)%$51,117 33 %
Property and other taxes13,920 16,497 (16)%6,831 104 %
Depreciation and amortization157,991 165,187 (4)%144,626 %
Long-lived asset and other impairments
23 NM52,401 (100)%
Total other operating expenses$239,773 $254,748 (6)%$254,975 (6)%

General and administrative expenses
General and administrative expenses decreased by $5.2 million compared to the three months ended December 31, 2023, primarily due to a decrease of $6.2 million in contract labor and consulting costs, partially offset by an increase of $1.1 million in personnel costs.
General and administrative expenses increased by $16.7 million compared to the three months ended March 31, 2023, primarily due to increases of (i) $7.1 million in personnel costs, (ii) $5.5 million in information technology costs, and (iii) $1.6 million in contract labor and consulting expense.

Property and other taxes
Property and other taxes decreased by $2.6 million compared to the three months ended December 31, 2023, primarily due to a decrease in the ad valorem property tax accrual related to the finalization of 2023 assessments at the DJ Basin complex.
Property and other taxes increased by $7.1 million compared to the three months ended March 31, 2023, primarily due to a lower ad valorem property tax accrual recorded during the first quarter of 2023 related to the finalization of 2022 assessments at the DJ Basin complex.

Depreciation and amortization expense
Depreciation and amortization expense decreased by $7.2 million compared to the three months ended December 31, 2023, primarily due to decreases of (i) $2.9 million at the DJ Basin complex due to updated salvage values and (ii) $1.7 million and $1.2 million at the Red Desert and Powder River Basin complexes, respectively, due to asset retirement obligation revisions.
Depreciation and amortization expense increased by $13.4 million compared to the three months ended March 31, 2023, primarily due to increases of (i) $15.1 million at the Powder River Basin complex attributable to the acquisition of Meritage and (ii) $4.8 million and $3.1 million at the West Texas complex and DBM water systems, respectively, primarily related to capital projects being placed into service. These increases were offset partially by a decrease of $7.9 million at the DJ Basin complex primarily due to acceleration of depreciation expense during 2023 and updated salvage values.

Long-lived asset and other impairment expense
Long-lived asset and other impairment expense for the three months ended March 31, 2023, was primarily due to a $52.1 million impairment for assets located in the Rockies.
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.


43
ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS


Interest Expense
Our consolidated financial statements include
Three Months Ended
thousands except percentagesMarch 31, 2024December 31, 2023Inc/
(Dec)
March 31, 2023Inc/
(Dec)
Long-term and short-term debt
$(95,956)$(98,977)(3)%$(81,151)18 %
Finance lease liabilities(677)(467)45 %(163)NM
Commitment fees and amortization of debt-related costs(3,200)(3,196)— %(2,881)11 %
Capitalized interest5,327 5,018 %2,525 111 %
Interest expense$(94,506)$(97,622)(3)%$(81,670)16 %

Interest expense decreased by $3.1 million compared to the consolidated financial results of WESthree months ended December 31, 2023, primarily due to a decrease of $5.7 million resulting from no outstanding borrowings under the RCF during the first quarter of 2024, partially offset by an increase of $2.7 million due to borrowings on the commercial paper program that was established during the fourth quarter of 2023.
Interest expense increased by $12.8 million compared to the three months ended March 31, 2023, primarily due to increases of (i) $11.7 million of interest incurred on the 6.150% Senior Notes due 2033 that were issued during the second quarter of 2023, (ii) $9.8 million of interest incurred on the 6.350% Senior Notes due 2029 that were issued during the third quarter of 2023, and (iii) $5.7 million due to borrowings on the commercial paper program that was established during the fourth quarter of 2023. These increases were offset partially by decreases of (i) $4.5 million due to credit-rating related interest rate changes and lower outstanding balances on certain senior notes, (ii) $7.0 million due to no outstanding borrowings under the RCF during the first quarter of 2024, and (iii) $2.8 million due to higher capitalized interest. See Liquidity and Capital Resources—Debt and credit facilities within this Item 2.

Income Tax Expense (Benefit)

We are not a taxable entity for U.S. federal income tax purposes; therefore, our 100% ownershipfederal statutory rate is zero percent. However, income apportionable to Texas is subject to Texas margin tax.

44

RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

Adjusted gross margin. We define Adjusted gross margin attributable to Western Midstream Partners, LP (“Adjusted gross margin”) as total revenues and other (less reimbursements for electricity-related expenses recorded as revenue), less cost of product, plus distributions from equity investments, and excluding the noncontrolling interest in WES GPowners’ proportionate share of revenues and WES GP’s controlcost of WES. Our only cash-generating assets consistproduct. We believe Adjusted gross margin is an important performance measure of our partnership interestsoperations’ profitability and performance as compared to other companies in WES,the midstream industry. Cost of product expenses include (i) costs associated with the purchase of natural gas and we currently have no independent operations. AsNGLs pursuant to our percent-of-proceeds, percent-of-product, and keep-whole contracts, (ii) costs associated with the valuation of gas and NGLs imbalances, (iii) costs associated with our obligations under certain contracts to redeliver a result,volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties, and (iv) costs associated with our resultsoffload commitments with third parties providing firm-processing capacity. The electricity-related expenses included in our Adjusted gross margin definition relate to pass-through expenses that are recorded as Operation and maintenance expense with an offset recorded as revenue for the reimbursement by certain customers.

Adjusted EBITDA. We define Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) as net income (loss), plus (i) distributions from equity investments, (ii) non-cash equity-based compensation expense, (iii) interest expense, (iv) income tax expense, (v) depreciation and amortization, (vi) impairments, and (vii) other expense (including lower of operations do not differ materiallycost 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 cash flowsthat Adjusted EBITDA is a widely accepted financial indicator of WES, which are reconciled below.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:

General and administrative expenses. As a separateour 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.

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 represents the amount of cash that is available in aggregate for distributions, debt repayments, and other general partnership purposes.


45

Adjusted gross margin, Adjusted EBITDA, and Free cash flow are not defined in GAAP. The GAAP measure 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 that are most directly comparable to Adjusted EBITDA. The GAAP measure 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
thousandsMarch 31, 2024December 31, 2023March 31, 2023
Reconciliation of Gross margin to Adjusted gross margin
Total revenues and other$887,729 $858,208 $733,982 
Less:
Cost of product46,079 40,803 51,459 
Depreciation and amortization157,991 165,187 144,626 
Gross margin683,659 652,218 537,897 
Add:
Distributions from equity investments48,337 46,661 51,975 
Depreciation and amortization157,991 165,187 144,626 
Less:
Reimbursed electricity-related charges recorded as revenues24,695 25,273 23,569 
Adjusted gross margin attributable to noncontrolling interests (1)
20,240 19,412 15,774 
Adjusted gross margin$845,052 $819,381 $695,155 

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


46

To facilitate investor and industry analysis, we incuralso 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.
Three Months Ended
thousands except per-unit amountsMarch 31, 2024December 31, 2023March 31, 2023
Gross margin
Gross margin for natural-gas assets (1)
$511,584 $484,688 $393,673 
Gross margin for crude-oil and NGLs assets (1)
93,578 103,228 89,281 
Gross margin for produced-water assets (1)
85,041 70,509 59,549 
Per-Mcf Gross margin for natural-gas assets (2)
1.09 1.04 1.03 
Per-Bbl Gross margin for crude-oil and NGLs assets (2)
1.78 1.57 1.59 
Per-Bbl Gross margin for produced-water assets (2)
0.81 0.71 0.68 
Adjusted gross margin
Adjusted gross margin for natural-gas assets
$597,163 $579,278 $480,009 
Adjusted gross margin for crude-oil and NGLs assets
150,269 157,048 145,577 
Adjusted gross margin for produced-water assets
97,620 83,055 69,569 
Per-Mcf Adjusted gross margin for natural-gas assets (3)
1.32 1.29 1.30 
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets (3)
2.92 2.43 2.65 
Per-Bbl Adjusted gross margin for produced-water assets (3)
0.95 0.86 0.81 

(1)Excludes corporate-level depreciation and amortization.
(2)Average for period. Calculated as Gross margin for natural-gas assets, crude-oil and NGLs assets, or produced-water assets, divided by the respective total throughput (MMcf or MBbls) for natural-gas assets, crude-oil and NGLs assets, or produced-water assets.
(3)Average for period. Calculated as Adjusted gross margin for natural-gas assets, crude-oil and NGLs assets, or produced-water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural-gas assets, crude-oil and NGLs assets, or produced-water assets.

47

Three Months Ended
thousandsMarch 31, 2024December 31, 2023March 31, 2023
Reconciliation of Net income (loss) to Adjusted EBITDA
Net income (loss)$586,216 $295,752 $208,341 
Add:
Distributions from equity investments48,337 46,661 51,975 
Non-cash equity-based compensation expense
9,423 9,970 7,199 
Interest expense94,506 97,622 81,670 
Income tax expense1,522 1,405 1,416 
Depreciation and amortization157,991 165,187 144,626 
Impairments23 52,401 
Other expense112 71 200 
Less:
Gain (loss) on divestiture and other, net239,617 (6,434)(2,118)
Gain (loss) on early extinguishment of debt524 — — 
Equity income, net – related parties32,819 36,120 39,021 
Other income2,346 2,862 1,215 
Adjusted EBITDA attributable to noncontrolling interests (1)
14,415 13,459 11,015 
Adjusted EBITDA$608,409 $570,665 $498,695 
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA
Net cash provided by operating activities$399,708 $473,300 $302,424 
Interest (income) expense, net94,506 97,622 81,670 
Accretion and amortization of long-term obligations, net
(2,190)(2,174)(1,692)
Current income tax expense (benefit)1,292 1,315 492 
Other (income) expense, net(2,346)(2,862)(1,215)
Distributions from equity investments in excess of cumulative earnings – related parties19,033 7,389 12,366 
Changes in assets and liabilities:
Accounts receivable, net53,714 17,773 4,037 
Accounts and imbalance payables and accrued liabilities, net100,383 (19,021)136,460 
Other items, net(41,276)10,782 (24,832)
Adjusted EBITDA attributable to noncontrolling interests (1)
(14,415)(13,459)(11,015)
Adjusted EBITDA$608,409 $570,665 $498,695 
Cash flow information
Net cash provided by operating activities$399,708 $473,300 $302,424 
Net cash provided by (used in) investing activities396,849 (1,068,707)(179,178)
Net cash provided by (used in) financing activities(774,098)378,700 (297,257)

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

48

Three Months Ended
thousandsMarch 31, 2024December 31, 2023March 31, 2023
Reconciliation of Net cash provided by operating activities to Free cash flow
Net cash provided by operating activities$399,708 $473,300 $302,424 
Less:
Capital expenditures193,789 198,653 173,088 
Contributions to equity investments – related parties — 110 
Add:
Distributions from equity investments in excess of cumulative earnings – related parties19,033 7,389 12,366 
Free cash flow$224,952 $282,036 $141,592 
Cash flow information
Net cash provided by operating activities$399,708 $473,300 $302,424 
Net cash provided by (used in) investing activities396,849 (1,068,707)(179,178)
Net cash provided by (used in) financing activities(774,098)378,700 (297,257)

Gross margin. Refer to Operating Results within this Item 2 for a discussion of the components of Gross margin as compared to the prior periods, including Service Revenues, Product Sales, Cost of Product (Residue purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense).
Gross margin increased by $31.4 million compared to the three months ended December 31, 2023, due to (i) a $29.5 million increase in total revenues and other and (ii) a $7.2 million decrease in depreciation and amortization. These amounts were offset partially by a $5.3 million increase in cost of product.
Gross margin increased by $145.8 million compared to the three months ended March 31, 2023, due to (i) a $153.7 million increase in total revenues and other and (ii) a $5.4 million decrease in cost of product. These amounts were offset partially by a $13.4 million increase in depreciation and amortization.

Net income (loss). Refer to Operating Results within this Item 2 for a discussion of the primary components of Net income (loss) as compared to the prior periods.
Net income (loss) increased by $290.5 million compared to the three months ended December 31, 2023, primarily due to (i) a $246.1 million increase in gain (loss) on divestiture and other, net, (ii) a $29.5 million increase in total revenues and other, and (iii) a $15.2 million decrease in total operating expenses.
Net income (loss) increased by $377.9 million compared to the three months ended March 31, 2023, primarily due to (i) a $241.7 million increase in gain (loss) on divestiture and other, net and (ii) a $153.7 million increase in total revenues and other. These amounts were offset partially by (i) a $12.8 million increase in interest expense and (ii) a $6.2 million decrease in equity income, net – related parties.

Net cash provided by operating activities. Refer to Historical cash flow within this Item 2 for a discussion of the primary components of Net cash provided by operating activities as compared to the prior periods.

49

KEY PERFORMANCE METRICS
Three Months Ended
thousands except percentages and per-unit amountsMarch 31, 2024December 31, 2023Inc/
(Dec)
March 31, 2023Inc/
(Dec)
Adjusted gross margin$845,052 $819,381 %$695,155 22 %
Per-Mcf Adjusted gross margin for natural-gas assets (1)
1.32 1.29 %1.30 %
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets (1)
2.92 2.43 20 %2.65 10 %
Per-Bbl Adjusted gross margin for produced-water assets (1)
0.95 0.86 10 %0.81 17 %
Adjusted EBITDA608,409 570,665 %498,695 22 %
Free cash flow224,952 282,036 (20)%141,592 59 %

(1)Average for period. Calculated as Adjusted gross margin for natural-gas assets, crude-oil and NGLs assets, or produced-water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural-gas assets, crude-oil and NGLs assets, or produced-water assets.

Adjusted gross margin. Adjusted gross margin increased by $25.7 million compared to the three months ended December 31, 2023, primarily due to (i) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, increased throughput, and increased deficiency fees on certain contracts with increasing throughput minimums at the West Texas complex, (ii) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, and increased throughput at the DBM water systems, (iii) increased throughput at the DJ Basin complex, (iv) commercial activities prior to the divestment of our interest in the first quarter of 2024 at Whitethorn LLC, and (v) increased throughput and a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, at the DBM oil system. These increases were offset partially by decreases due to annual cost-of-service rate adjustments that increased revenue during the fourth quarter of 2023 at the Springfield and DJ Basin oil systems.
Adjusted gross margin increased by $149.9 million compared to the three months ended March 31, 2023, primarily due to (i) increased throughput, a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, and increased deficiency fees on certain contracts with increasing throughput minimums at the West Texas complex, (ii) increased throughput at the Powder River Basin complex attributable to the acquisition of Meritage, (iii) a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, and increased throughput at the DBM water systems, and (iv) increased throughput at the DJ Basin complex. These increases were offset partially by (i) decreased processing fees at the Brasada complex resulting from a change in contract terms effective July 1, 2023, and (ii) a decrease in distributions from TEP.
Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.03 compared to the three months ended December 31, 2023, primarily due to increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets, in addition to a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, and increased deficiency fees on certain contracts with increasing throughput minimums. This increase was offset partially by a decrease resulting from an annual cost-of-service rate adjustment that increased revenue during the fourth quarter of 2023 at the Springfield system.
Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.02 compared to the three months ended March 31, 2023, primarily due to (i) increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets, in addition to a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, and increased deficiency fees on certain contracts with increasing throughput minimums, and (ii) increased throughput at the DJ Basin 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 processing fees at the Brasada complex resulting from a change in contract terms effective July 1, 2023.

50

Per-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by $0.49 compared to the three months ended December 31, 2023, primarily due to the sale of our interests in Whitethorn LLC, Saddlehorn, Panola, and Mont Belvieu JV in the first quarter of 2024, all of which had lower-than-average per-Bbl margins as compared to our other crude-oil and NGLs assets. These increases were offset partially by decreases related to (i) an annual cost-of-service rate adjustment that increased revenue during the fourth quarter of 2023, partially offset by increased throughput, at the DJ Basin oil system, which has a higher-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, and (ii) an annual cost-of-service rate adjustment that increased revenue during the fourth quarter of 2023 at the Springfield system.
Per-Bbl Adjusted gross margin for crude-oil and NGLs assets increased by $0.27 compared to the three months ended March 31, 2023, primarily due to (i) the sale of our interests in Whitethorn LLC, Saddlehorn, Panola, and Mont Belvieu JV in the first quarter of 2024, all of which had lower-than-average per-Bbl margins as compared to our other crude-oil and NGLs assets, and (ii) increased throughput and a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, 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 increases were offset partially by (i) decreased deficiency fees on demand volumes at the DJ Basin oil system and (ii) a decrease in distributions from TEP.
Per-Bbl Adjusted gross margin for produced-water assets increased by $0.09 and $0.14 compared to the three months ended December 31, 2023, and March 31, 2023, respectively, primarily due to increased throughput and a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024.

Adjusted EBITDA. Adjusted EBITDA increased by $37.7 million compared to the three months ended December 31, 2023, primarily due to (i) a $29.5 million increase in total revenues and other, (ii) a $5.5 million decrease in operation and maintenance expenses, (iii) a $4.7 million decrease in general and administrative expenses which are separateexcluding non-cash equity-based compensation expense, and (iv) a $2.6 million decrease in property taxes. These amounts were offset partially by a $5.2 million increase in cost of product (net of lower of cost or market inventory adjustments).
Adjusted EBITDA increased by $109.7 million compared to the three months ended March 31, 2023, primarily due to (i) a $153.7 million increase in total revenues and other and (ii) a $5.3 million decrease in cost of product (net of lower of cost or market inventory adjustments). These amounts were offset partially by (i) a $20.7 million increase in operation and maintenance expenses, (ii) a $14.5 million increase in general and administrative expenses excluding non-cash equity-based compensation expense, (iii) a $7.1 million increase in property and other taxes, and (iv) a $3.6 million decrease in distributions from equity investments.

Free cash flow.Free cash flow decreased by $57.1 million compared to the three months ended December 31, 2023, primarily due to a $73.6 million decrease in net cash provided by operating activities, partially offset by (i) an $11.6 million increase in distributions from equity investments in excess of cumulative earnings and (ii) a $4.9 million decrease in additioncapital expenditures.
Free cash flow increased by $83.4 million compared to those incurredthe three months ended March 31, 2023, primarily due to (i) a $97.3 million increase in net cash provided by WES.operating activities and (ii) a $6.7 million increase in distributions from equity investments in excess of cumulative earnings. These amounts were offset partially by a $20.7 million increase in capital expenditures.
See Capital Expenditures and Historical Cash Flow within this Item 2 for further information.

51

LIQUIDITY AND CAPITAL RESOURCES

Our primary cash uses include equity and debt service, operating expenses, and capital expenditures. Our sources of liquidity, as of March 31, 2024, included cash and cash equivalents, cash flows generated from operations, effective borrowing capacity under the RCF, our commercial paper program, 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 following table summarizes the amounts we reimbursed to Anadarko, separate from, and in addition to, those reimbursed by WES:
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands 2017 2016 2017 2016
General and administrative expenses $131
 $64
 $197
 $192
Public company expenses 386
 408
 1,452
 2,062
Total reimbursement $517
 $472
 $1,649
 $2,254

Noncontrolling interests. The interest in Chipeta held by a third-party member is already reflected as a noncontrolling interest in WES’s consolidated financial statements. In addition, the limited partner interests in WES held by other subsidiaries of Anadarko, private investors (up to the final conversion date of the Series A Preferred units on May 2, 2017) and the public are reflected as noncontrolling interests in the consolidated financial statements (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 for further information).
When WES issues equity, the carrying amount of future distributions to unitholders will be determined by the noncontrolling interest reported by WGP is adjusted to reflect the noncontrolling ownership interest in WES. The resulting impact of such noncontrolling interest adjustmentBoard on WGP’s interest in WES is reflected as an adjustment to WGP’s partners’ capital.

Distributions. Oura quarterly basis. Under our partnership agreement, requires that we distribute all of our available cash (as(beyond proper reserves as defined in our partnership agreement) within 55 days after the end offollowing each quarter. Our only cash-generating assets are our partnership interests in WES, consisting of general partner units, common units and incentive distribution rights, on which we expect to receive quarterly distributions from WES.quarter’s end. Our cash flow and resulting ability to make cash distributions are therefore completely dependent upon WES’son our ability to makegenerate cash distributions with respect to our partnership interests in WES.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.


Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan. Concurrently with The general partner establishes cash reserves to provide for the WGP IPO, WGP GP adopted the WGP LTIP. Equity-based compensation expense attributable to grants made under the WGP LTIP impacts cash flows from operating activities only to the extent cash payments are made to a participant in lieuproper conduct of issuance of WGP common units to the participant. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for further information.

WGP RCF. In March 2016, we entered into a $250.0 million WGP RCF which matures in March 2019. The WGP RCF may be used to buy WES common units and for general partnership purposes.
As of September 30, 2017, we had $28.0 million of outstanding borrowings and $222.0 million available for borrowing under the WGP RCF. At September 30, 2017, the interest rate on WGP RCF was 3.24%, the commitment fee rate was 0.30% and we were in compliance with all covenants under the WGP RCF. See Note 9—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for further information.

WGP WCF. On November 1, 2012, we entered into the WGP WCF, a $30.0 million working capital facility with Anadarko as the lender. The facility is available exclusivelyour business, including (i) to fund our workingfuture capital borrowings. As of September 30, 2017, we had no outstanding borrowings and $30.0 million availableexpenditures, (ii) to comply with applicable laws, debt instruments, or other agreements, or (iii) to provide funds for borrowing under the WGP WCF. WGP WCF bears interest at LIBOR plus 1.50%, and the interest rate was 2.74% at September 30, 2017. At September 30, 2017, we were in compliance with all covenants under the WGP WCF. The WGP WCF will mature on November 1, 2017, and we do not intend to renew this facility.

Reconciliation of net income (loss) attributable to Western Gas Partners, LP to net income (loss) attributable to Western Gas Equity Partners, LP. The differences between net income (loss) attributable to WES and net income (loss) attributable to WGP are reconciled as follows:
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands 2017 2016 2017 2016
Net income (loss) attributable to WES $143,506
 $167,746
 $418,846
 $448,327
Limited partner interests in WES not held by WGP (1)
 (45,992) (75,098) (137,974) (182,128)
General and administrative expenses (2)
 (764) (730) (2,193) (2,972)
Other income (expense), net 25
 12
 60
 46
Property and other taxes 
 
 
 (15)
Interest expense (573) (533) (1,653) (1,182)
Net income (loss) attributable to WGP $96,202
 $91,397
 $277,086
 $262,076
(1)
Represents the portion of net income (loss) allocated to the limited partner interests in WES not held by WGP. As of September 30, 2017 and 2016, the public held a 59.7% and 60.0% limited partner interest in WES, respectively. Other subsidiaries of Anadarko separately held a 9.0% and 8.5% limited partner interest in WES as of September 30, 2017 and 2016, respectively. 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.
(2)
Represents general and administrative expenses incurred by WGP separate from, and in addition to, those incurred by WES.


Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activitiesunitholder distributions for WGP and WES are reconciled as follows:
  Nine Months Ended 
 September 30,
thousands 2017 2016
WES net cash provided by operating activities $645,099
 $657,738
General and administrative expenses (1)
 (2,193) (2,972)
Non-cash equity-based compensation expense 178
 189
Changes in working capital 471
 540
Other income (expense), net 60
 46
Property and other taxes 
 (15)
Interest expense (1,653) (1,182)
Debt related amortization and other items, net 507
 356
WGP net cash provided by operating activities $642,469
 $654,700
     
WES net cash provided by (used in) financing activities $(335,792) $429,368
Proceeds from the issuance of WES common units, net of offering expenses (2)
 
 (25,000)
Distributions to WGP unitholders (3)
 (324,290) (276,114)
Distributions to WGP from WES (4)
 326,374
 278,412
WGP RCF borrowings, net of issuance costs 
 25,980
WGP net cash provided by (used in) financing activities $(333,708) $432,646
(1)
Represents general and administrative expenses incurred by WGP separate from, and in addition to, those incurred by WES.
(2)
Represents the difference attributable to elimination upon consolidation of proceeds to WES from the issuance of WES common units to WGP as part of funding the Springfield acquisition. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
(3)
Represents distributions to WGP common unitholders paid under WGP’s partnership agreement. See Note 3—Partnership Distributions and Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
(4)
Difference attributable to elimination upon consolidation of WES’s distributions on partnership interests owned by WGP. See Note 3—Partnership Distributions and Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


RESULTS OF OPERATIONS

OPERATING RESULTS

The following tables and discussion present a summary of WES’s results of operations:
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands 2017 2016 2017 2016
Total revenues and other (1)
 $574,695
 $481,645
 $1,616,338
 $1,293,450
Equity income, net – affiliates 21,519
 20,294
 62,708
 56,801
Total operating expenses (1)
 416,830
 312,088
 1,318,489
 830,699
Gain (loss) on divestiture and other, net 72
 (6,230) 135,017
 (8,769)
Proceeds from business interruption insurance claims (2)
 
 13,667
 29,882
 16,270
Operating income (loss) 179,456
 197,288
 525,456
 527,053
Interest income – affiliates 4,225
 4,225
 12,675
 12,675
Interest expense (35,544) (30,768) (106,794) (75,687)
Other income (expense), net 286
 153
 969
 224
Income (loss) before income taxes 148,423
 170,898
 432,306
 464,265
Income tax (benefit) expense 510
 472
 4,905
 7,431
Net income (loss) 147,913
 170,426
 427,401
 456,834
Net income attributable to noncontrolling interest 4,407
 2,680
 8,555
 8,507
Net income (loss) attributable to Western Gas Partners, LP (3)
 $143,506
 $167,746
 $418,846
 $448,327
Key performance metrics (4)
        
Adjusted gross margin attributable to Western Gas Partners, LP $344,416
 $343,981
 $1,009,520
 $984,459
Adjusted EBITDA attributable to Western Gas Partners, LP 257,835
 278,170
 787,664
 759,834
Distributable cash flow 231,859
 237,315
 695,587
 628,602
(1)
Revenues and other include amounts earned by WES from services provided to its affiliates, as well as from the sale of residue and NGLs to its affiliates. Operating expenses include amounts charged by WES affiliates for services as well as reimbursement of amounts paid by affiliates to third parties on WES’s behalf. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
(2)
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.
(3)
For reconciliations to comparable consolidated results of WGP, see Items Affecting the Comparability of Financial Results within this Item 2.
(4)
Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable 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 measures within this Item 2.

For purposesany one or more of the following discussion, any increases or decreases “for the three months ended September 30, 2017” refer to the comparison of the three months ended September 30, 2017, to the three months ended September 30, 2016; any increases or decreases “for the nine months ended September 30, 2017” refer to the comparison of the nine months ended September 30, 2017, to the nine months ended September 30, 2016; and any increases or decreases “for the three and nine months ended September 30, 2017” refer to the comparison of these 2017 periods to the corresponding three and nine month periods ended September 30, 2016.


Throughput
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,

 2017 2016 
Inc/
(Dec)
 2017 2016 
Inc/
(Dec)
Throughput for natural gas assets (MMcf/d)            
Gathering, treating and transportation 784
 1,562
 (50)% 1,029
 1,556
 (34)%
Processing 2,588
 2,448
 6 % 2,528
 2,301
 10 %
Equity investment (1)
 159
 179
 (11)% 160
 178
 (10)%
Total throughput for natural gas assets 3,531
 4,189
 (16)% 3,717
 4,035
 (8)%
Throughput attributable to noncontrolling interest for natural gas assets 104
 119
 (13)% 107
 127
 (16)%
Total throughput attributable to Western Gas Partners, LP for natural gas assets 3,427
 4,070
 (16)% 3,610
 3,908
 (8)%
Throughput for crude, NGL and produced water assets (MBbls/d)            
Gathering, treating and transportation 77
 58
 33 % 57
 59
 (3)%
Equity investment (2)
 132
 127
 4 % 130
 126
 3 %
Total throughput for crude, NGL and produced water assets 209
 185
 13 % 187
 185
 1 %
(1)
Represents WES’s 14.81% share of average Fort Union throughput and 22% share of average Rendezvous throughput.
(2)
Represents WES’s 10% share of average White Cliffs throughput, 25% share of average Mont Belvieu JV throughput, 20% share of average TEG and TEP throughput, and 33.33% share of average FRP throughput.

Natural gas assets

Gathering, treating and transportation throughput decreased by 778 MMcf/d and 527 MMcf/d for the three and nine months ended September 30, 2017, respectively, primarily due to the Property Exchange in March 2017 (decreases of 594 MMcf/d and 341 MMcf/d, respectively), production declines in the areas around the Marcellus Interest (decreases of 38 MMcf/d and 52 MMcf/d, respectively) and Springfield gas gathering systems (decreases of 40 MMcf/d and 47 MMcf/d, respectively), and the sale of the Hugoton system in October 2016 (decreases of 52 MMcf/d and 54 MMcf/d, respectively).
Processing throughput increased by 140 MMcf/d and 227 MMcf/d for the three and nine months ended September 30, 2017, respectively, primarily due to the DBM outage in 2016 and the start-up of Train IV and Train V at the DBM complex in May 2016 and October 2016, respectively. These increases were partially offset by production declines in the areas around the Chipeta complex and MGR assets.
Equity investment throughput decreased by 20 MMcf/d and 18 MMcf/d for the three and nine months ended September 30, 2017, respectively, due to decreased throughput at the Rendezvous and Fort Union systems due to production declines in the area.

Crude, NGL and produced water assets
Gathering, treating and transportation throughput increased by 19 MBbls/d for the three months ended September 30, 2017, primarily due to the start-up of operations at the DBM water systems during the second quarter of 2017, partially offset by decreased throughput at the Springfield oil gathering system due to production declines in the area.
Gathering, treating and transportation throughput decreased by 2 MBbls/d for the nine months ended September 30, 2017, primarily due to decreased throughput at the Springfield oil gathering system due to production declines in the area, partially offset by throughput from the DBM water systems that commenced operation during the second quarter of 2017.
Equity investment throughput increased by 5 MBbls/d and 4 MBbls/d for the three and nine months ended September 30, 2017, respectively, primarily due to increased volumes on FRP and TEG as a result of increased NGL production and an increase at the Mont Belvieu JV due to higher inlet throughput. These increases were partially offset by decreased throughput at White Cliffs as a result of a competitive pipeline commencing service in September 2016.

Gathering, Processing and Transportation Revenues
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands except percentages 2017 2016 
Inc/
(Dec)
 2017 2016 
Inc/
(Dec)
Gathering, processing and transportation revenues $306,187
 $315,192
 (3)% $913,436
 $910,332
 %

Revenues from gathering, processing and transportation decreased by $9.0 million for the three months ended September 30, 2017, primarily due to decreases of (i) $15.4 million due to the Property Exchange in March 2017, (ii) $7.4 million at the Springfield system, $2.6 million at the Chipeta complex and $1.6 million at the Marcellus Interest systems in each case due to throughput decreases, (iii) $4.7 million due to the sale of the Hugoton system in October 2016 and (iv) $2.8 million at the Granger complex due to a lower processing fee. These decreases were partially offset by increases of (i) $16.2 million at the DBM complex due to increased throughput (see Operating Results–Throughput within this Item 2), (ii) $8.5 million at the DJ Basin complex due to increased throughput and a higher throughput fee and (iii) $3.0 million at the DBM water systems that commenced operation during the second quarter of 2017.
Revenues from gathering, processing and transportation increased by $3.1 million for the nine months ended September 30, 2017, primarily due to increases of (i) $72.6 million at the DBM complex due to increased throughput (see Operating Results–Throughput within this Item 2), (ii) $23.1 million at the DJ Basin complex due to increased throughput and a higher throughput fee and (iii) $4.1 million at the DBM water systems that commenced operation during the second quarter of 2017. These increases were partially offset by decreases of (i) $25.7 million at the Springfield system, $10.8 million at the Chipeta complex and $7.6 million at the Marcellus Interest systems in each case due to throughput decreases, (ii) $28.5 million due to the Property Exchange in March 2017, (iii) $14.4 million due to the sale of the Hugoton system in October 2016 and (iv) $7.0 million at the Granger complex due to a lower processing fee.

Natural Gas and Natural Gas Liquids Sales
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands except percentages and per-unit amounts 2017 2016 
Inc/
(Dec)
 2017 2016 
Inc/
(Dec)
Natural gas sales (1)
 $100,395
 $72,658
 38% $273,256
 $155,251
 76%
Natural gas liquids sales (1)
 158,746
 91,378
 74% 417,234
 224,334
 86%
Total $259,141
 $164,036
 58% $690,490
 $379,585
 82%
Average price per unit (1):
            
Natural gas (per Mcf) $2.89
 $2.70
 7% $2.96
 $2.41
 23%
Natural gas liquids (per Bbl) 22.99
 19.10
 20% 21.63
 19.45
 11%
(1)
Excludes amounts considered above market with respect to WES’s swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016) that were recorded as capital contributions in the consolidated statement of equity and partners’ capital. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

For the three and nine months ended September 30, 2017, average natural gas and NGL prices included the effects of commodity price swap agreements attributable to sales for the MGR assets and DJ Basin complex. For the three and nine months ended September 30, 2016, average natural gas and NGL prices included the effects of commodity price swap agreements attributable to sales for the Hugoton system, MGR assets and DJ Basin complex. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
The increase in natural gas sales of $27.7 million for the three months ended September 30, 2017, was primarily due to increases of (i) $15.6 million at the DJ Basin complex due to an increase in the swap market price and volumes sold and (ii) $14.8 million at the DBM complex due to an increase in volumes sold (see Operating Results–Throughput within this Item 2). These increases were partially offset by a decrease of $3.0 million at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.

The increase in natural gas sales of $118.0 million for the nine months ended September 30, 2017, was primarily due to increases of (i) $75.2 million at the DBM complex due to an increase in average price and volumes sold (see Operating Results–Throughput within this Item 2), (ii) $44.3 million at the DJ Basin complex due to an increase in the swap market price and volumes sold and (iii) $4.8 million at the Hilight system due to an increase in average price. These increases were partially offset by a decrease of $9.2 million at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.
The increase in NGLs sales of $67.4 million and $192.9 million for the three and nine months ended September 30, 2017, respectively, was primarily due to increases of (i) $62.7 million and $184.5 million, respectively, at the DBM complex due to an increase in average price and volumes sold (see Operating Results–Throughput within this Item 2), (ii) $15.9 million and $38.1 million, respectively, at the DJ Basin complex due to an increase in the swap market price and volumes sold and (iii) $3.3 million and $11.3 million, respectively, at the Hilight system due to an increase in average price. These increases were partially offset by decreases during the three and nine months ended September 30, 2017, of $17.7 million and $49.9 million, respectively, at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.

Other Revenues
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands except percentages 2017 2016 
Inc/
(Dec)
 2017 2016 
Inc/
(Dec)
Other revenues $9,367
 $2,417
 NM $12,412
 $3,533
 NM
NM-Not Meaningful

For the three and nine months ended September 30, 2017, other revenues increased by $7.0 million and $8.9 million, respectively, primarily due to deficiency fees at the Chipeta complex.

Equity Income, Net – Affiliates
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands except percentages 2017 2016 
Inc/
(Dec)
 2017 2016 
Inc/
(Dec)
Equity income, net – affiliates $21,519
 $20,294
 6% $62,708
 $56,801
 10%

For the three and nine months ended September 30, 2017, equity income, net – affiliates increased by $1.2 million and $5.9 million, respectively, primarily due to an increase in equity income from the Mont Belvieu JV due to increased volumes processed. In addition, for the nine months ended September 30, 2017, equity income, net – affiliates increased due to WES’s 14.81% share of an impairment loss determined by the managing partner of Fort Union in the first quarter of 2016.


Cost of Product and Operation and Maintenance Expenses
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands except percentages 2017 2016 
Inc/
(Dec)
 2017 2016 
Inc/
(Dec)
NGL purchases (1)
 $136,636
 $66,822
 104% $359,616
 $149,547
 140 %
Residue purchases (1)
 90,264
 70,376
 28% 256,387
 156,774
 64 %
Other 12,323
 8,445
 46% 15,856
 20,638
 (23)%
Cost of product 239,223
 145,643
 64% 631,859
 326,959
 93 %
Operation and maintenance 79,536
 74,755
 6% 229,444
 226,141
 1 %
Total cost of product and operation and maintenance expenses $318,759
 $220,398
 45% $861,303
 $553,100
 56 %
(1)
Excludes amounts considered above market with respect to WES’s swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016) that were recorded as capital contributions in the consolidated statement of equity and partners’ capital. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Cost of product expense for the three and nine months ended September 30, 2017, included the effects of commodity price swap agreements attributable to purchases for the MGR assets and DJ Basin complex. Cost of product expense for the three and nine months ended September 30, 2016, included the effects of commodity price swap agreements attributable to purchases for the Hugoton system, MGR assets and DJ Basin complex. See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
NGL purchases increased by $69.8 million and $210.1 million for the three and nine months ended September 30, 2017, respectively, primarily due to increases of (i) $61.4 million and $177.1 million, respectively, at the DBM complex due to an increase in average price and volumes purchased (see Operating Results–Throughput within this Item 2), (ii) $13.2 million and $43.2 million, respectively, at the DJ Basin complex due to an increase in the swap market price and volumes purchased and (iii) $2.7 million and $9.2 million, respectively, at the Hilight system due to an increase in average price, partially offset by a decrease in volumes purchased. These increases were partially offset by decreases during the three and nine months ended September 30, 2017, of $9.5 million and $26.6 million, respectively, at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.
Residue purchases increased by $19.9 million and $99.6 million for the three and nine months ended September 30, 2017, respectively, primarily due to increases of (i) $12.6 million and $68.7 million, respectively, at the DBM complex due to an increase in average price and volumes purchased (see Operating Results–Throughput within this Item 2) and (ii) $12.3 million and $36.5 million, respectively, at the DJ Basin complex due to an increase in the swap market price and volumes purchased. In addition, for the nine months ended September 30, 2017, there was an increase of $4.6 million at the Hilight system due to an increase in average price. These increases were partially offset by decreases during the three and nine months ended September 30, 2017, of $3.9 million and $12.0 million, respectively, at the MGR assets due to the partial equity treatment of the above-market swap agreement beginning January 1, 2017.
Other items increased by $3.9 million for the three months ended September 30, 2017, primarily due to changes in affiliate contract terms at the DJ Basin complex. Other items decreased by $4.8 million for the nine months ended September 30, 2017, primarily due to fees paid in 2016 for rerouting volumes due to the DBM outage, partially offset by changes in affiliate contract terms at the DJ Basin complex in 2017.
Operation and maintenance expense increased by $4.8 million for the three months ended September 30, 2017, primarily due to increases of (i) $2.6 million due to the Property Exchange in March 2017, (ii) $1.4 million in utilities expense primarily at the DJ Basin and DBM complexes and (iii) $1.4 million in salaries and wages primarily at the Springfield system. Operation and maintenance expense increased by $3.3 million for the nine months ended September 30, 2017, primarily due to an increase of $3.0 million due to the Property Exchange in March 2017.


Other Operating Expenses
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands except percentages 2017 2016 
Inc/
(Dec)
 2017 2016 
Inc/
(Dec)
General and administrative $12,158
 $11,382
 7 % $35,402
 $33,542
 6%
Property and other taxes 11,215
 10,670
 5 % 35,433
 33,098
 7%
Depreciation and amortization 72,539
 67,246
 8 % 216,272
 199,646
 8%
Impairments 2,159
 2,392
 (10)% 170,079
 11,313
 NM
Total other operating expenses $98,071
 $91,690
 7 % $457,186
 $277,599
 65%
NM-Not Meaningful

General and administrative expenses increased by $0.8 million and $1.9 million for the three and nine months ended September 30, 2017, respectively, primarily due to increases in personnel costs for which WES reimbursed Anadarko pursuant to the WES omnibus agreement and bad debt expense, partially offset by decreases in legal and consulting fees.
Property and other taxes increased by $0.5 million for the three months ended September 30, 2017, primarily due to an ad valorem tax increase at the DJ Basin complex, partially offset by a decrease at the DBM complex. Property and other taxes increased by $2.3 million for the nine months ended September 30, 2017, primarily due to ad valorem tax increases at the DBM complex and DBJV system.
Depreciation and amortization expense increased by $5.3 million and $16.6 million for the three and nine months ended September 30, 2017, respectively, primarily due to depreciation expense increases of (i) $5.2 million and $10.3 million, respectively, due to the Property Exchange in March 2017, (ii) $2.4 million and $9.1 million, respectively, related to capital projects at the DBM complex and (iii) $2.8 million and $8.4 million, respectively, at the Bison facility due to a change in the estimated property life. These increases were partially offset by decreases during the three and nine months ended September 30, 2017, of (i) $1.4 million and $5.4 million, respectively, due to the sale of the Hugoton system in October 2016, (ii) $2.4 million and $4.9 million, respectively, at the Granger complex due to an impairment recorded in the first quarter of 2017 (see impairment expense below) and (iii) $1.6 million and $2.4 million, respectively, at the DJ Basin complex due to a change in estimated salvage values.
Impairment expense decreased by $0.2 million for the three months ended September 30, 2017, primarily due to a $2.0 million impairment of an idle facility in northeast Wyoming (see Note 6—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q), as compared to impairments in 2016 primarily related to the cancellation of projects at the DBJV and Marcellus Interest systems.
Impairment expense increased by $158.8 million for the nine months ended September 30, 2017, primarily due to the following items occurring in 2017 (i) a $158.8 million impairment at the Granger complex, (ii) a $3.7 million impairment at the Granger straddle plant, (iii) a $3.1 million impairment at the Fort Union system, (iv) a $2.0 million impairment of an idle facility in northeast Wyoming and (v) the cancellation of a pipeline project in West Texas. Impairment expense for the nine months ended September 30, 2016, was primarily due to (i) a $6.1 million impairment at the Newcastle system, (ii) the cancellation of projects at the DJ Basin complex and DBJV system and (iii) the abandonment of compressors at the MIGC system. See Note 6—Property, Plant and Equipment in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


Interest Income – Affiliates and Interest Expense
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands except percentages 2017 2016 
Inc/
(Dec)
 2017 2016 
Inc/
(Dec)
Note receivable – Anadarko $4,225
 $4,225
  % $12,675
 $12,675
  %
Interest income – affiliates $4,225
 $4,225
  % $12,675
 $12,675
  %
Third parties            
Long-term debt $(35,992) $(31,612) 14 % $(105,772) $(87,711) 21 %
Amortization of debt issuance costs and commitment fees (1,667) (1,672)  % (4,942) (4,747) 4 %
Capitalized interest 2,115
 1,343
 57 % 3,991
 4,674
 (15)%
Affiliates            
Deferred purchase price obligation – Anadarko (1)
 
 1,173
 (100)% (71) 12,097
 (101)%
Interest expense $(35,544) $(30,768) 16 % $(106,794) $(75,687) 41 %
(1)
See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for a discussion of the Deferred purchase price obligation - Anadarko.

Interest expense increased by $4.8 million and $31.1 million for the three and nine months ended September 30, 2017, respectively, primarily due to (i) accretion revisions in 2016 recorded as reductions to interest expense for the Deferred purchase price obligation - Anadarko (see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q), (ii) interest incurred on the 2026 Notes issued in July 2016 and (iii) interest incurred on the additional 2044 Notes issued in October 2016. These increases were partially offset during the nine months ended September 30, 2017, by additional interest incurred on the RCF in 2016 as a result of higher outstanding borrowings. Capitalized interest increased by $0.8 million for the three months ended September 30, 2017, primarily due to the construction of Train VI beginning in the fourth quarter of 2016 and the purchase of long-lead items associated with the Mentone plant, partially offset by a decrease primarily due to the completion of Train V in October 2016, all located at the DBM complex. Capitalized interest decreased by $0.7 million for the nine months ended September 30, 2017, primarily due to the completion of Trains IV and V in May 2016 and October 2016, respectively, partially offset by an increase due to the construction of Train VI beginning in the fourth quarter of 2016 and the purchase of long-lead items associated with the Mentone plant, all located at the DBM complex. See Note 9—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Income Tax (Benefit) Expense
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands except percentages 2017 2016 
Inc/
(Dec)
 2017 2016 
Inc/
(Dec)
Income (loss) before income taxes $148,423
 $170,898
 (13)% $432,306
 $464,265
 (7)%
Income tax (benefit) expense 510
 472
 8 % 4,905
 7,431
 (34)%
Effective tax rate % %   1% 2%  

WES is not a taxable entity for U.S. federal income tax purposes. However, WES’s income apportionable to Texas is subject to Texas margin tax. For the nine months ended September 30, 2016, the variance from the federal statutory rate was primarily due to federal and state taxes on pre-acquisition income attributable to the WES assets acquired from Anadarko, and WES’s share of Texas margin tax. For all other periods presented, the variance from the federal statutory rate, which is zero percent as a non-taxable entity, was primarily due to WES’s share of Texas margin tax.
Income attributable to the Springfield system prior to and including February 2016 was subject to federal and state income tax. Income earned on the Springfield system for periods subsequent to February 2016 was only subject to Texas margin tax on income apportionable to Texas.


KEY PERFORMANCE METRICS
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands except percentages and per-unit amounts 2017 2016 
Inc/
(Dec)
 2017 2016 
Inc/
(Dec)
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (1)
 $305,337
 $306,393
  % $904,620
 $877,583
 3 %
Adjusted gross margin for crude, NGL and produced water assets (2)
 39,079
 37,588
 4 % 104,900
 106,876
 (2)%
Adjusted gross margin attributable to Western Gas Partners, LP (3)
 344,416
 343,981
  % 1,009,520
 984,459
 3 %
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets (4)
 0.97
 0.82
 18 % 0.92
 0.82
 12 %
Adjusted gross margin per Bbl for crude, NGL and produced water assets (5)
 2.03
 2.20
 (8)% 2.05
 2.10
 (2)%
Adjusted EBITDA attributable to Western Gas Partners, LP (3)
 257,835
 278,170
 (7)% 787,664
 759,834
 4 %
Distributable cash flow (3)
 231,859
 237,315
 (2)% 695,587
 628,602
 11 %
(1)
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues and other for natural gas assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for natural gas assets, plus distributions from WES’s equity investments in Fort Union and Rendezvous, and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. See the reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets to its most comparable GAAP measure below.
(2)
Adjusted gross margin for crude, NGL and produced water assets is calculated as total revenues and other for crude, NGL and produced water assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for crude, NGL and produced water assets, plus distributions from WES’s equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests. See the reconciliation of Adjusted gross margin for crude, NGL and produced water assets to its most comparable GAAP measure below.
(3)
For a reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the descriptions below.
(4)
Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets, divided by total throughput (MMcf/d) attributable to Western Gas Partners, LP for natural gas assets.
(5)
Average for period. Calculated as Adjusted gross margin for crude, NGL and produced water assets, divided by total throughput (MBbls/d) for crude, NGL and produced water assets.

Adjusted gross margin attributable to Western Gas Partners, LP. WES defines Adjusted gross margin attributable to Western Gas Partners, LP (“Adjusted gross margin”) as total revenues and other, less cost of product and reimbursements for electricity-related expenses recorded as revenue, plus distributions from equity investments and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. WES believes Adjusted gross margin is an important performance measure of the core profitability of its operations, as well as its operating performance as compared to that of other companies in the industry.
Adjusted gross margin increased by $0.4 million and $25.1 million for the three and nine months ended September 30, 2017, respectively, primarily due to (i) an increase in throughput at the DBM complex, (ii) an increase in processed volumes at the DJ Basin complex and (iii) the start-up of operations at the DBM water systems during the second quarter of 2017. These increases were partially offset by decreases from (i) the Property Exchange in March 2017, (ii) lower throughput at the Springfield and Marcellus Interest systems, (iii) the partial equity treatment of the above-market swap agreement at the MGR assets beginning January 1, 2017, and (iv) the sale of the Hugoton system in October 2016.

To facilitate investor and industry analyst comparisons between WES and its peers, WES also discloses Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets and Adjusted gross margin per Bbl for crude, NGL and produced water assets. Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets increased by $0.15 and $0.10 for the three and nine months ended September 30, 2017, respectively, primarily due to the Property Exchange in March 2017 and increased throughput at the DBM complex. Adjusted gross margin per Bbl for crude, NGL and produced water assets decreased by $0.17 for the three months ended September 30, 2017, primarily due to (i) lower throughput at the Springfield oil gathering system, (ii) lower distributions received from the Mont Belvieu JV and (iii) the start-up of operations at the DBM water systems during the second quarter of 2017. Adjusted gross margin per Bbl for crude, NGL and produced water assets decreased by $0.05 for the nine months ended September 30, 2017, primarily due to (i) lower throughput at the Springfield oil gathering system and (ii) the start-up of operations at the DBM water systems during the second quarter of 2017. These decreases were partially offset during the three and nine months ended September 30, 2017, by higher distributions received from TEP.

Adjusted EBITDA attributable to Western Gas Partners, LP. WES defines Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) as net income (loss) attributable to Western Gas Partners, LP, plus distributions from equity investments, non-cash equity-based compensation expense, interest expense, income tax expense, depreciation and amortization, impairments, and other expense (including lower of cost or market inventory adjustments recorded in cost of product), less gain (loss) on divestiture and other, net, income from equity investments, interest income, income tax benefit, and other income. WES believes that the presentation of Adjusted EBITDA provides information useful to investors in assessing its 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 WES’s management and external users of WES’s consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following, among other measures:

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

the ability of WES’s assets to generate cash flow to make distributions; and

the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.

Adjusted EBITDA decreased by $20.3 million for the three months ended September 30, 2017, primarily due to a $93.6 million increase in cost of product (net of lower of cost or market inventory adjustments), a $13.7 million decrease in business interruption proceeds, a $4.8 million increase in operation and maintenance expenses, and a $1.7 million increase in net income attributable to noncontrolling interest. These amounts were partially offset by a $93.1 million increase in total revenues and other and a $2.0 million increase in distributions from equity investments.
Adjusted EBITDA increased by $27.8 million for the nine months ended September 30, 2017, primarily due to a $322.9 million increase in total revenues and other, a $13.6 million increase in business interruption proceeds and a $4.3 million increase in distributions from equity investments. These amounts were partially offset by a $304.8 million increase in cost of product (net of lower of cost or market inventory adjustments), a $3.3 million increase in operation and maintenance expenses, a $2.4 million increase in general and administrative expenses excluding non-cash equity-based compensation expense, and a $2.3 million increase in property and other tax expense.


Distributable cash flow. WES defines “Distributable cash flow” as Adjusted EBITDA, plus interest income and the net settlement amounts from the sale and/or purchase of natural gas, condensate and NGLs under WES’s commodity price swap agreements to the extent such amounts are not recognized as Adjusted EBITDA, less net cash paid (or to be paid) for interest expense (including amortization of deferred debt issuance costs originally paid in cash, offset by non-cash capitalized interest), maintenance capital expenditures, Series A Preferred unit distributions and income taxes. WES compares Distributable cash flow to the cash distributions WES expects to pay its unitholders. Using this measure, WES’s management can quickly compute the Coverage ratio of distributable cash flow to planned cash distributions. WES believes Distributable cash flow is useful to investors because this measurement is used by many companies, analysts and others in the industry as a performance measurement tool to evaluate WES’s operating and financial performance and compare it with the performance of other publicly traded partnerships.
While Distributable cash flow is a measure WES uses to assess its ability to make distributions to its unitholders, it should not be viewed as indicative of the actual amount of cash that WES has available for distributions or that it plans to distribute for a given period. Furthermore, to the extent Distributable cash flow includes realized amounts recorded as capital contributions from Anadarko attributable to activity under WES’s commodity price swap agreements, it is not a reflection of WES’s ability to generate cash from operations.
Distributable cash flow decreased by $5.5 million for the three months ended September 30, 2017, primarily due to a $20.3 million decrease in Adjusted EBITDA and a $4.4 million increase in net cash paid for interest expense. These amounts were partially offset by a $14.9 million decrease in WES Series A Preferred unit distributions and a $4.7 million decrease in cash paid for maintenance capital expenditures.
Distributable cash flow increased by $67.0 million for the nine months ended September 30, 2017, primarily due to a $27.8 million increase in Adjusted EBITDA, a $23.4 million decrease in WES Series A Preferred unit distributions, a $22.2 million decrease in cash paid for maintenance capital expenditures and an $11.9 million increase in the above-market component of the swap agreements with Anadarko. These amounts were partially offset by an $18.3 million increase in net cash paid for interest expense.

Reconciliation of non-GAAP measures.Adjusted gross margin, Adjusted EBITDA and Distributable cash flow are not defined in GAAP. The GAAP measure used by WES that is most directly comparable to Adjusted gross margin is operating income (loss), while net income (loss) attributable to Western Gas Partners, LP and net cash provided by operating activities are the GAAP measures used by WES that are most directly comparable to Adjusted EBITDA. The GAAP measure used by WES that is most directly comparable to Distributable cash flow is net income (loss) attributable to Western Gas Partners, LP. WES’s non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow should not be considered as alternatives to the GAAP measures of operating income (loss), net income (loss) attributable to Western Gas Partners, LP, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP. Adjusted gross margin, Adjusted EBITDA and Distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect operating income (loss), net income (loss) attributable to Western Gas Partners, LP and net cash provided by operating activities. Adjusted gross margin, Adjusted EBITDA and Distributable cash flow should not be considered in isolation or as a substitute for analysis of WES’s results as reported under GAAP. WES’s definitions of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow may not be comparable to similarly titled measures of other companies in WES’s industry, thereby diminishing their utility.

WES’s management compensates for the limitations of Adjusted gross margin, Adjusted EBITDA and Distributable cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted gross margin, Adjusted EBITDA and Distributable cash flow compared to (as applicable) operating income (loss), net income (loss) attributable to Western Gas Partners, LP and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes. WES believes that investors benefit from having access to the same financial measures that its management uses in evaluating its operating results.
The following tables present (a) a reconciliation of the GAAP financial measure of operating income (loss) to the non-GAAP financial measure of Adjusted gross margin, (b) a reconciliation of the GAAP financial measures of net income (loss) attributable to Western Gas Partners, LP and net cash provided by operating activities to the non-GAAP financial measure of Adjusted EBITDA and (c) a reconciliation of the GAAP financial measure of net income (loss) attributable to Western Gas Partners, LP to the non-GAAP financial measure of Distributable cash flow:
  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands 2017 2016 2017 2016
Reconciliation of Operating income (loss) to Adjusted gross margin attributable to Western Gas Partners, LP        
Operating income (loss) $179,456
 $197,288
 $525,456
 $527,053
Add:        
Distributions from equity investments 29,145
 27,133
 80,568
 76,263
Operation and maintenance 79,536
 74,755
 229,444
 226,141
General and administrative 12,158
 11,382
 35,402
 33,542
Property and other taxes 11,215
 10,670
 35,433
 33,098
Depreciation and amortization 72,539
 67,246
 216,272
 199,646
Impairments 2,159
 2,392
 170,079
 11,313
Less:        
Gain (loss) on divestiture and other, net 72
 (6,230) 135,017
 (8,769)
Proceeds from business interruption insurance claims 
 13,667
 29,882
 16,270
Equity income, net – affiliates 21,519
 20,294
 62,708
 56,801
Reimbursed electricity-related charges recorded as revenues 14,323
 15,170
 42,338
 45,707
Adjusted gross margin attributable to noncontrolling interest 5,878
 3,984
 13,189
 12,588
Adjusted gross margin attributable to Western Gas Partners, LP $344,416
 $343,981
 $1,009,520
 $984,459
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets $305,337
 $306,393
 $904,620
 $877,583
Adjusted gross margin for crude, NGL and produced water assets 39,079
 37,588
 104,900
 106,876


  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands 2017 2016 2017 2016
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Adjusted EBITDA attributable to Western Gas Partners, LP        
Net income (loss) attributable to Western Gas Partners, LP $143,506
 $167,746
 $418,846
 $448,327
Add:        
Distributions from equity investments 29,145
 27,133
 80,568
 76,263
Non-cash equity-based compensation expense 1,258
 1,469
 3,479
 4,018
Interest expense 35,544
 30,768
 106,794
 75,687
Income tax expense 510
 472
 4,905
 7,431
Depreciation and amortization (1)
 71,812
 66,589
 214,213
 197,678
Impairments 2,159
 2,392
 170,079
 11,313
Other expense (1)
 
 40
 140
 96
Less:        
Gain (loss) on divestiture and other, net 72
 (6,230) 135,017
 (8,769)
Equity income, net – affiliates 21,519
 20,294
 62,708
 56,801
Interest income – affiliates 4,225
 4,225
 12,675
 12,675
Other income (1)
 283
 150
 960
 272
Adjusted EBITDA attributable to Western Gas Partners, LP $257,835
 $278,170
 $787,664
 $759,834
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA attributable to Western Gas Partners, LP        
Net cash provided by operating activities $211,947
 $263,872
 $645,099
 $657,738
Interest (income) expense, net 31,319
 26,543
 94,119
 63,012
Uncontributed cash-based compensation awards 78
 290
 (94) 448
Accretion and amortization of long-term obligations, net (1,055) 121
 (3,194) 9,176
Current income tax (benefit) expense 395
 131
 1,023
 5,110
Other (income) expense, net (286) (153) (969) (224)
Distributions from equity investments in excess of cumulative earnings – affiliates 7,034
 5,981
 16,255
 16,592
Changes in operating working capital of Western Gas Partners, LP:        
Accounts receivable, net 56,335
 7,866
 46,972
 41,108
Accounts and imbalance payables and accrued liabilities, net (45,982) (26,330) (4,007) (24,103)
Other 3,181
 3,184
 3,065
 1,445
Adjusted EBITDA attributable to noncontrolling interest of Western Gas Partners, LP (5,131) (3,335) (10,605) (10,468)
Adjusted EBITDA attributable to Western Gas Partners, LP $257,835
 $278,170
 $787,664
 $759,834
Cash flow information of Western Gas Partners, LP        
Net cash provided by operating activities     $645,099
 $657,738
Net cash used in investing activities     (514,797) (1,040,692)
Net cash provided by (used in) financing activities     (335,792) 429,368
(1)
Includes WES’s 75% share of depreciation and amortization; other expense; and other income attributable to the Chipeta complex.


  Three Months Ended 
 September 30,
 Nine Months Ended 
 September 30,
thousands except Coverage ratio 2017 2016 2017 2016
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Distributable cash flow and calculation of the Coverage ratio        
Net income (loss) attributable to Western Gas Partners, LP $143,506
 $167,746
 $418,846
 $448,327
Add:        
Distributions from equity investments 29,145
 27,133
 80,568
 76,263
Non-cash equity-based compensation expense 1,258
 1,469
 3,479
 4,018
Non-cash settled - interest expense, net (1)
 
 (1,173) 71
 (12,097)
Income tax (benefit) expense 510
 472
 4,905
 7,431
Depreciation and amortization (2)
 71,812
 66,589
 214,213
 197,678
Impairments 2,159
 2,392
 170,079
 11,313
Above-market component of swap agreements with Anadarko (3)
 18,049
 18,417
 46,719
 34,782
Other expense (2)
 
 40
 140
 96
Less:        
Gain (loss) on divestiture and other, net 72
 (6,230) 135,017
 (8,769)
Equity income, net – affiliates 21,519
 20,294
 62,708
 56,801
Cash paid for maintenance capital expenditures (2)
 10,591
 15,306
 33,115
 55,288
Capitalized interest 2,115
 1,343
 3,991
 4,674
Cash paid for (reimbursement of) income taxes 
 
 189
 67
Series A Preferred unit distributions 
 14,907
 7,453
 30,876
Other income (2)
 283
 150
 960
 272
Distributable cash flow $231,859
 $237,315
 $695,587
 $628,602
Distributions declared (4)
        
Limited partners of WES – common units $138,105
   $397,850
  
General partner of WES 73,933
   210,432
  
Total $212,038
   $608,282
  
Coverage ratio 1.09
x  1.14
x 
(1)
Includes amounts related to the Deferred purchase price obligation - Anadarko. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
(2)
Includes WES’s 75% share of depreciation and amortization; other expense; cash paid for maintenance capital expenditures; and other income attributable to the Chipeta complex.
(3)
See Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
(4)
Reflects WES cash distributions of $0.905 and $2.670 per unit declared for the three and nine months ended September 30, 2017, respectively.


LIQUIDITY AND CAPITAL RESOURCES

WES’s primary cash requirements are for acquisitions and capital expenditures, debt service, customary operating expenses, quarterly distributions to its limited partners and to WES GP, and distributions to its noncontrolling interest owner. WES’s sources of liquidity as of September 30, 2017, included cash and cash equivalents, cash flows generated from operations, interest income on WES’s $260.0 million note receivable from Anadarko, available borrowing capacity under the WES RCF, and issuances of additional equity or debt securities. WES believes that cash flows generated from these sources will be sufficient to satisfy its short-term working capital requirements and long-term maintenance and expansion capital expenditure requirements. The amount of future distributions to unitholders will depend on its results of operations, financial condition, capital requirements and other factors, including the extension of WES’s commodity price swap agreements, and will be determined by WES GP’s Board of Directors on a quarterly basis. Due to WES’s cash distribution policy, WES expects to rely on external financing sources, including equity and debt issuances, to fund expansion capital expenditures and future acquisitions. However, to limit interest expense, WES may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under the WES RCF to pay distributions or fund other short-term working capital requirements.
During the second quarter of 2017, WES reached a settlement with insurers related to the insurance claim filed for the incident at the DBM complex and final proceeds were received. Recoveries from the business interruption claim related to the DBM outage were recognized as income when cash proceeds were received from insurers. During the nine months ended September 30, 2017, WES received $52.9 million in cash proceeds from insurers in final settlement of its claims related to the incident at the DBM complex, including $29.9 million for business interruption insurance claims and $23.0 million for property insurance claims (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 has made cash distributions to its unitholders each quarter since its IPO and has increased its quarterly distribution each quarter since the second quarter of 2009.next four quarters. The Board of Directors of WES GP declared a cash distribution to WES unitholders for the thirdfirst quarter of 20172024 of $0.905$0.875 per unit, or $212.0$340.9 million in aggregate, including incentive distributions, but excluding distributions on WES’s Class C units.the aggregate. The cash distribution is payable on November 13, 2017,May 15, 2024, to WESour unitholders of record at the close of business on November 2, 2017. In connectionMay 1, 2024.
To facilitate the distribution of available cash, during 2022 we adopted a financial policy that provided for an additional distribution (“Enhanced Distribution”) to be paid in conjunction with the closingregular first-quarter distribution of the DBM acquisitionfollowing year (beginning in November 2014, WES issued Class C units that will receive distributions2023), in a target amount equal to Free cash flow generated in the formprior year after subtracting Free cash flow used for the prior year’s debt repayments, regular-quarter distributions, and unit repurchases. This Enhanced Distribution is subject to Board discretion, the establishment of additional Class Ccash reserves for the proper conduct of our business, and is also contingent on the attainment of prior year-end net leverage thresholds (the ratio of our total principal debt outstanding less total cash on hand as of the end of such period, as compared to our trailing-twelve-months Adjusted EBITDA) after taking the Enhanced Distribution for such prior year into effect. Free cash flow and Adjusted EBITDA are defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 2.
In 2022, we announced a common-unit buyback program of up to $1.25 billion through December 31, 2024. The common units until March 1, 2020, unless earlier converted (see Note 3—Partnership Distributionsmay be purchased from time to time in the Notesopen 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 our common units, and other factors, including organic growth and acquisition opportunities and general market conditions. The program does not obligate us to Consolidated Financial Statementspurchase any specific dollar amount or number of units and may be suspended or discontinued at any time. During the three months ended March 31, 2024, there were no common units repurchased. During the three months ended March 31, 2023, we repurchased 285,688 common units for an aggregate purchase price of $7.1 million. The units were canceled immediately upon receipt. As of March 31, 2024, we had an authorized amount of $627.8 million remaining under Part I, Item 1 of this Form 10-Q). The Class C unit distribution, if paid in cash, would have been $11.7 million for the third quarter of 2017.program.
WES’s managementManagement continuously monitors itsour leverage position and coordinates itsother financial projections to manage the capital expenditure program, quarterly distributionsstructure according to long-term objectives. We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or financing 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 acquisition strategy with its expected cash flowsrequirements, contractual restrictions, and projected debt-repayment schedule. WES’s management will continue to evaluate funding alternatives, including additional borrowingsother factors, and the issuance of debt or equity securities, to secure funds as needed or to refinance outstanding debt balances with longer term notes. To facilitate a potential debt or equity securities issuance, WES has the ability to sell securities under its shelf registration statements. WES’samounts involved may be material. Our ability to generate cash flows is subject to a number of factors, some of which are beyond itsour control. Read Risk Factors under Part II, Item 1A of this Form 10-Q.


52

Working capital. As of September 30, 2017, WES had a $35.0 million working capital deficit, which it defines as the amount by which current liabilities exceed current assets. Working capital is an indication of liquidity and potential needneeds for short-termshort-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, WES’sour customers, and the level and timing of itsour spending for acquisitions, maintenance, and expansion activity. WES’sother capital activities. As of March 31, 2024, we had a $358.2 million working capital deficitsurplus, which we define as of September 30, 2017, was primarily due to the costs incurred related to continued construction and expansion at the DBM and DJ Basin complexes and the DBJV system.amount by which current assets exceed current liabilities. As of September 30, 2017, WES had $945.4 million available forMarch 31, 2024, there was $1.9 billion in effective borrowing capacity under the WES RCF.RCF, after taking into account the $100.0 million of outstanding commercial paper borrowings, for which we maintain availability under the RCF as support for our commercial paper program. See Note 9—Selected Components of Working Capital and Note 10—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.



Capital expenditures. WES’s Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. WES categorizes capitalCapital expenditures as either of the following: 

include maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of WES’sour 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 (for fiscal year 2017, WES GP’s Board of Directors has approved Estimated Maintenance Capital Expenditures (as defined in WES’s partnership agreement) of $18.0 million per quarter); or

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

levels.
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. WES’sAcquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows:
Three Months Ended 
March 31,
thousands20242023
Acquisitions$443 $— 
Capital expenditures (1)
193,789 173,088 
Capital incurred (1)
210,930 181,803 

(1)For the three months ended March 31, 2024 and 2023, included $5.3 million and $2.5 million, respectively, of capitalized interest.
  Nine Months Ended 
 September 30,
thousands 2017 2016
Acquisitions $159,208
 $716,465
     
Expansion capital expenditures $384,416
 $312,505
Maintenance capital expenditures 33,391
 55,293
Total capital expenditures (1) (2)
 $417,807
 $367,798
     
Capital incurred (2)
 $504,286
 $355,674

(1)
Capital expenditures for the nine months ended September 30, 2017 and 2016, are presented net of $1.4 million and $4.9 million, respectively, of contributions in aid of construction costs from affiliates.
(2)
For the nine months ended September 30, 2017 and 2016, included $4.0 million and $4.7 million, respectively, of capitalized interest.

Acquisitions during 2017 included the Additional DBJV System Interest and equipment purchases from Anadarko. Acquisitions during 2016 included Springfield and equipment purchases from Anadarko. See Note 2—Acquisitions and Divestitures and Note 5—Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
Capital expenditures excluding acquisitions, increased by $50.0$20.7 million for the ninethree months ended September 30, 2017. Expansion capital expenditures increased by $71.9 million (including a $0.7 million decrease in capitalized interest) for the nine months ended September 30, 2017,March 31, 2024, primarily due to an increaseincreases of (i) $70.4$12.4 million at the DBJV systemWest Texas complex, primarily attributable to engineering and $23.7equipment milestone payments for the North Loving Plant, (ii) $10.9 million related to the acquisition of Meritage, (iii) $6.2 million at the DJ Basin complex both due to pipe and compression projects and (ii) an increase of $50.9 million due to the constructionpurchase of a field office in the DBM water system.first quarter of 2024 and an increase in well connection and pipeline projects, and (iv) $5.4 million in corporate-level capital expenditures. These increases were offset partially offset by decreasesa decrease of $60.3$13.3 million at the DBM complex and $9.9 million at the Haley system. Maintenance capital expenditures decreased by $21.9 million for the nine months ended September 30, 2017, primarily at the DBM complex due to repairs made in 2016 as a result of the DBM outage and at the Non-Operated Marcellus Interestwater systems due to the Property Exchange in March 2017.reduced construction of water-disposal wells and facilities and well-connect projects.
WES has updated its estimated total capital expenditures for the year ending December 31, 2017, (including its 75% share
53


WESs historicalHistorical cash flow. The following table and discussion present a summary of WES’sour net cash flows provided by (used in) operating, activities, investing, activities and financing activities:
Three Months Ended 
March 31,
thousands20242023
Net cash provided by (used in):
Operating activities$399,708 $302,424 
Investing activities396,849 (179,178)
Financing activities(774,098)(297,257)
Net increase (decrease) in cash and cash equivalents$22,459 $(174,011)
  Nine Months Ended 
 September 30,
thousands 2017 2016
Net cash provided by (used in):    
Operating activities $645,099
 $657,738
Investing activities (514,797) (1,040,692)
Financing activities (335,792) 429,368
Net increase (decrease) in cash and cash equivalents $(205,490) $46,414


Operating Activitiesactivities. Net cash provided by operating activities increased for the ninethree months ended September 30, 2017, decreasedMarch 31, 2024, primarily due to the impact of changes in working capital items. Also,higher cash operating income, partially offset by lower distributions from equity investments and higher interest expense. Refer to Operating Results within this Item 2 for a discussion of WES’sour results of operations as compared to the prior period, refer to Operating Results within this Item 2.periods.


Investing Activitiesactivities. Net cash used inprovided by investing activities for the ninethree months ended September 30, 2017,March 31, 2024, primarily included the following:

$417.8582.7 million of capital expenditures, net of $1.4 million of contributions in aid of construction costs from affiliates, primarilyproceeds related to construction and expansion at the DBM and DJ Basin complexes and the DBJV system;

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

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

$23.3 million of net proceeds from the sale of the Helper and Clawson systems in Utah;several equity investments to third parties;


$23.019.0 million of proceeds from property insurance claims attributable to the DBM outage; and

$16.3 million of distributions received from equity investments in excess of cumulative earnings.earnings;


$193.8 million of capital expenditures, primarily related to expansion, construction, and asset-integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, Powder River Basin complex, and DBM oil system; and

$10.7 million of increases to materials and supplies inventory.

Net cash used in investing activities for the ninethree months ended September 30, 2016,March 31, 2023, primarily included the following:

$712.5 million of cash paid for the acquisition of Springfield;

$367.8173.1 million of capital expenditures, net of $4.9 million of contributions in aid of construction costs from affiliates, primarily related to plant construction, expansion, and expansionasset-integrity projects at the West Texas complex, DBM water systems, DBM oil system, and DJ Basin complexes and the DBJV system;complex;


$4.018.3 million of cash paid for equipment purchases from Anadarko;increases to materials and supplies inventory; and


$16.612.4 million of distributions received from equity investments in excess of cumulative earnings; andearnings.


$18.4 million of proceeds from property insurance claims attributable to the DBM outage.

Financing Activitiesactivities. Net cash used in financing activities for the ninethree months ended September 30, 2017,March 31, 2024, primarily included the following:

$510.4 million of net repayments under the commercial paper program;

$589.3229.1 million of distributions paid to WES unitholders;unitholders and noncontrolling interest owners; and


$37.314.5 million to purchase and retire portions of certain of WES Operating’s senior notes via open-market repurchases.

Net cash paid to Anadarkoused in financing activities for the settlement of WES’s Deferred purchase price obligation - Anadarko;three months ended March 31, 2023, primarily included the following:

$213.1 million to redeem the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value;

$9.0203.1 million of distributions paid to theWES unitholders and noncontrolling interest owner of Chipeta;owners;


$250.0100.0 million of borrowings under the WES RCF, which were used for WES’s general partnership purposes; and

$46.7 million of capital contribution from Anadarko related to the above-market component of swap agreements.

Net cash provided by financing activities for the nine months ended September 30, 2016, included the following:

$880.0 million of repayments of outstanding borrowings under the WES RCF;
54



$490.37.1 million of distributions paid to WES unitholders;unit repurchases; and


$29.3 million of net distributions paid to Anadarko representing pre-acquisition intercompany transactions attributable to Springfield;

$11.3 million of distributions paid to the noncontrolling interest owner of Chipeta;

$600.0220.0 million of borrowings under the WES RCF, which were used to fund a portion of the Springfield acquisition and for WES’s general partnership purposes, including funding capital expenditures;purposes.


$494.6 million of net proceeds from the WES 2026 Notes offering in July 2016, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of the outstanding borrowings under the WES RCF;

$440.0 million of net proceeds from the issuance of 14,030,611 WES Series A Preferred units in March 2016, all of which was used to fund a portion of the acquisition of Springfield;

$246.9 million of net proceeds from the issuance of 7,892,220 WES Series A Preferred units in April 2016, all of which was used to pay down amounts borrowed under the WES RCF in connection with the acquisition of Springfield;

$25.0 million of net proceeds from the sale of WES common units to WGP, all of which was used to fund a portion of the acquisition of Springfield; and

$34.8 million of capital contribution from Anadarko related to the above-market component of swap agreements.

Debt and credit facility. At September 30, 2017, WES’s debt consisted of $500.0 million aggregate principal amount of the 2021 Notes, $670.0 million aggregate principal amount of the 2022 Notes, $350.0 million aggregate principal amount of the 2018 Notes, $600.0 million aggregate principal amount of the 2044 Notes, $500.0 million aggregate principal amount of the 2025 Notes, $500.0 million aggregate principal amount of the 2026 Notes and $250.0 million of borrowings outstanding under the WES RCF.facilities. As of September 30, 2017,March 31, 2024, the carrying value of WES’s outstanding debt was $3.3 billion. See Note 9—Debt$7.4 billion and Interest Expensewe have $1.9 billion in effective borrowing capacity under WES Operating’s $2.0 billion RCF, after taking into account the Notes to Consolidated Financial Statements$100.0 million of outstanding commercial paper borrowings, for which we maintain availability under Part I, Item 1the RCF as support for WES Operating’s commercial paper program.
During the three months ended March 31, 2024, WES Operating purchased and retired $15.1 million of this Form 10-Q.

WEScertain of its senior notes via open-market repurchases with cash from operations and a gain of $0.5 million was recognized for the early retirement of portions of these notes. As of March 31, 2024, the 3.100% Senior Notes. The 2018 Notes, which are due in August 2018,2025 were classified as long-term debt on the consolidated balance sheet at September 30, 2017, as WES Operating has the ability and intent to refinance these obligations using long-term debt. At September 30, 2017,Subsequent to March 31, 2024, WES was in compliance with all covenants under the indentures governing its outstanding notes.

WES RCF. As of September 30, 2017, WES had $250.0Operating purchased and retired $134.9 million of outstanding WEScertain of its senior notes via open-market repurchases.
For additional information on our senior notes, RCF, borrowings and $4.6 million in outstanding letters of credit, resulting in $945.4 million available for borrowing under the WES RCF, which matures in February 2020. At September 30, 2017, the interest rate on the WES RCF was 2.54%, the facility fee rate was 0.20%commercial paper program, see Note 10—Debt and WES was in compliance with all covenants under the WES RCF.


Deferred purchase price obligation - Anadarko.Prior to WES’s agreement with Anadarko to settle its deferred purchase price obligation early, the consideration that would have been paid by WES for the March 2015 acquisition of DBJV from Anadarko, consisted of a cash payment to Anadarko due on March 31, 2020. The cash payment would have been equal to (a) eight multiplied by the average of WES’s shareInterest Expense in the Net Earnings (see definition below) of DBJV for the calendar years 2018 and 2019, less (b) WES’s share of all capital expenditures incurred for DBJV between March 1, 2015, and February 29, 2020. Net Earnings was defined as all revenues less cost of product, operating expenses and property taxes, in each case attributable to DBJV on an accrual basis. In May 2017, WES reached an agreement with Anadarko to settle this obligation whereby WES made a cash payment to Anadarko of $37.3 million, equal to the estimated net present value of the obligation at March 31, 2017. See Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


Securities. WES may issue an indeterminate amount of common units and various debt securities under its effective shelf registration statement on file with the SEC. WES may also issue common units under its $500.0 million COP, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of WES’s offerings.
WES has an effective registration statement with the SEC relating to the public resale of the WES common units issued upon conversion of the WES Series A Preferred units. See Note 4—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for a discussion of the WES Series A Preferred units.

Credit risk. As stated above, our assets consist solely of ownership interests in WES. Accordingly, we are dependent upon WES’s ability to pay cash distributions to us. WES bears We bear credit risk represented by itsthrough exposure to non-paymentnon-payment or non-performancenon-performance by itsour counterparties, including Anadarko,Occidental, financial institutions, customers, and other parties. Generally, non-paymentnon-payment or non-performancenon-performance results from a customer’s inability to satisfy payables to WESus for services rendered, minimum-volume-commitment deficiency payments owed, or volumes owed pursuant to gas imbalancegas- or NGLs-imbalance agreements. WES examinesWe examine and monitorsmonitor the creditworthiness of third-party customers and may establish credit limits for third-party customers.
WES is dependent upon a single producer, Anadarko, for a substantial portion of its volumes (excluding equity investment throughput), and WES does not maintain a credit limit with respect to Anadarko. Consequently, WES is We are subject to the risk of non-paymentnon-payment or late payment by Anadarkoproducers for gathering, processing, transportation, and transportation feesdisposal fees. Additionally, we continue to evaluate counterparty credit risk and, for proceeds from the salein certain circumstances, are exercising our contractual rights to request adequate assurance of residue, NGLs and condensate to Anadarko.performance.
WES expects itsWe expect our exposure to the concentrated risk of non-paymentnon-payment or non-performancenon-performance to continue for as long as it remains substantially dependentour 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 Anadarko for its revenues. Additionally, WES is exposedmost of our systems include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to credit risk on the note receivable from Anadarko. WES is also partybring their volumes to agreements with Anadarko under which Anadarko is required to indemnify WES 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 acquired from Anadarko. Finally, WES has entered into various commodity price swap agreements with Anadarko in order to reduce its exposure to a majority of the commodity price risk inherent in its percent-of-proceeds and keep-whole contracts, and is subject to performance risk thereunder.market. See Note 5—6—Related-Party Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.
WES’sOur ability to make cash distributions to itsour unitholders may be adversely impacted if AnadarkoOccidental becomes unable to perform under the terms of its gathering, processing, transportation, and transportation agreements, natural gasdisposal agreements.

55

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 NGL purchase agreements, Anadarko’s note payablecash 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
thousandsMarch 31, 2024December 31, 2023March 31, 2023
Net income (loss) attributable to WES$572,830 $288,354 $203,645 
Limited partner interest in WES Operating not held by WES (1)
11,700 5,906 4,161 
General and administrative expenses (2)
360 1,016 232 
Other income (expense), net(59)(61)(25)
Income taxes — 
Net income (loss) attributable to WES Operating$584,831 $295,221 $208,013 

(1)Represents the portion of net income (loss) allocated to the limited partner interest in WES omnibus agreement, the servicesOperating 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 secondment agreement, contribution agreements or the commodity price swap agreements.administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.


Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows:
CONTRACTUAL OBLIGATIONS
Three Months Ended 
March 31,
thousands20242023
WES net cash provided by operating activities$399,708 $302,424 
General and administrative expenses (1)
360 232 
Non-cash equity-based compensation expense
(145)(141)
Changes in working capital(19,215)(11,522)
Other income (expense), net(59)(25)
WES Operating net cash provided by operating activities$380,649 $290,968 
WES net cash provided by (used in) financing activities$(774,098)$(297,257)
Distributions to WES unitholders (2)
223,438 196,569 
Distributions to WES from WES Operating (3)
(224,855)(209,242)
Increase (decrease) in outstanding checks(67)(42)
Unit repurchases 7,061 
Other19,364 11,950 
WES Operating net cash provided by (used in) financing activities$(756,218)$(290,961)

(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 contractual obligations include, among other things, a revolving credit facility, other third-party long-term debt, capital obligations related to its expansion projectspartnership agreement. See Note 4—Partnership Distributions and various operating leases. Refer toNote 9—Debt5—Equity and Interest Expense and Note 10—Commitments and ContingenciesPartners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q for an update10-Q.
(3)Difference attributable to WES’s contractual obligations aselimination in consolidation of September 30, 2017, including, but not limited to, increases in committed capital.


OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements. WES does not have any off-balance sheet arrangements other than operating leasesOperating’s distributions on partnership interests owned by WES. See Note 4—Partnership Distributions and standby letters of credit. The information pertaining to operating leasesNote 5—Equity and WES’s standby letters of credit required for this item is provided under Note 10—Commitments and Contingencies and Note 9—Debt and Interest Expense, respectively, includedPartners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.


56

RECENT ACCOUNTING DEVELOPMENTS

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 Statementsunder 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, 2023.

RECENT ACCOUNTING DEVELOPMENTS

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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk


Commodity priceCommodity-price risk. Certain of WES’s processing services are providedThere have been no significant changes to our commodity-price risk discussion from the disclosure set forth under percent-of-proceeds and keep-whole agreementsPart II, Item 7A in which Anadarko is typically responsibleour Form 10-K for the marketing of the natural gas, condensate and NGLs. Under percent-of-proceeds agreements, WES receives a specified percentage of the net proceeds from the sale of residue and/or NGLs. Under keep-whole agreements, WES keeps 100% of the NGLs produced and the processed natural gas, or value of the natural gas, is returned to the producer, and since some of the gas is used and removed during processing, WES compensates the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas used.
To mitigate WES’s exposure to a majority of the commodity price risk inherent in its percent-of-proceeds and keep-whole contracts, WES currently has in place commodity price swap agreements with Anadarko covering activity at the DJ Basin complex and the MGR assets. On December 1, 2016, WES renewed these commodity price swap agreements throughyear ended December 31, 2017, with an effective date of January 1, 2017. See Note 5—Transactions with Affiliates2023, except as noted below and in the Notes to Consolidated Financial StatementsOutlook under Part I, Item 12 of this Form 10-Q.
We consider WES’s exposure to commodity price risk associated withFor the above-described arrangements to be minimal given the existencethree months ended March 31, 2024, 95% of the commodity price swap agreements with Anadarkoour wellhead natural-gas volume (excluding equity investments) and the relatively small amount100% of WES’s operating income (loss) that is impacted by changes in market prices. Accordingly, WES does not expect that aour crude-oil and produced-water throughput (excluding equity investments) were serviced under fee-based contracts. A 10% increase or decrease in commodity prices would not have a material impact on WES’sour operating income (loss), financial condition, or cash flows for the next twelve12 months, excluding the effect of imbalances described below.imbalances.
We bear a limited degree of commodity price risk through our investment in WES with respect to settlement of WES’s natural gas imbalances that arise from differences in gas volumes received into WES’s systems and gas volumes delivered by WES to customers, as well as instances where WES’s actual liquids recovery or fuel usage varies from the contractually stipulated amounts. Natural gas volumes owed to or by WES that are subject to monthly cash settlement are valued according to the terms of the contract as of the balance sheet dates, and generally reflect market index prices. Other natural gas volumes owed to or by WES are valued at WES’s weighted-average cost of natural gas as of the balance sheet dates and are settled in-kind. WES’s exposure to the impact of changes in commodity prices on outstanding imbalances depends on the timing of settlement of the imbalances.

Interest rateInterest-rate risk. In June 2017, the The Federal Open Market Committee raised theincreased its target range four times for the federal funds rate from 3/4in 2023 and has made no changes to one percent to one to 1 1/4 percent. This increase, and anyits target range during the three months ended March 31, 2024. Any future increases in the federal funds rate likely will ultimately result in an increase in financing costs. As of September 30, 2017, WGPMarch 31, 2024, WES Operating had $28.0 million of borrowings under the WGP RCF and WES had $250.0 million of(i) no outstanding borrowings under the WES RCF. The WGP RCF and WES RCF eachthat bear interest at a rate based on LIBORthe Secured Overnight Financing Rate (“SOFR”) or an alternative base rate at WGP’s or WES’sWES Operating’s option respectively. Aand (ii) $100.0 million of outstanding commercial paper borrowings. While a 10% change in LIBORthe applicable benchmark interest rate would have resulted in a nominal change in net income (loss) andnot materially impact interest expense on our outstanding borrowings at March 31, 2024, it would impact the fair value of any borrowings under the WES RCF and WGP RCF at September 30, 2017.senior notes.
Additional variable-rateshort-term or variable-rate debt may be incurredissued in the future, either under the WES RCF, WGP RCF or other financing sources, including commercial bankpaper borrowings or debt issuances.



57

Item 4. Controls and Procedures


Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and Chief Financial Officer of WGP’sWES’s general partner and WES Operating GP (for purposes of this Item 4, “Management”) performed an evaluation of WGP’sWES’s and WES Operating’s disclosure controls and procedures as defined in Rules 13a-15(e)13a-15(e) and 15d-15(e)15d-15(e) of the Exchange Act. OurWES’s and WES Operating’s disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we fileare filed or submitsubmitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by us in the reports that we fileare filed or submitsubmitted under the Exchange Act is accumulated and communicated to our management, including ourthe principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, Management concluded that WGP’sWES’s and WES Operating’s disclosure controls and procedures were effective as of September 30, 2017.March 31, 2024.


Changes in Internal Control Over Financial Reporting. There has beenwere no changechanges in ourWES’s or WES Operating’s internal control over financial reporting during the quarter ended September 30, 2017,March 31, 2024, that hashave materially affected, or isare reasonably likely to materially affect, WGP’sWES’s or WES Operating’s internal control over financial reporting.


PART II.OTHER INFORMATION


Item 1. Legal Proceedings


Kerr-McGee Gathering LLC (“KMGG”), one of WES’s wholly owned subsidiaries, is currently in negotiations with the U.S. Environmental Protection Agency (the “EPA”) and the Department of Justice with respect to alleged non-compliance with the leak detection and repair requirements of the federal Clean Air Act at its Fort Lupton facility in the DJ Basin complex.
Also, WGR Operating, LP, another wholly owned subsidiary of WES, is currently in negotiations with the EPA with respect to alleged non-compliance with the leak detection and repair requirements of the federal Clean Air Act at its Granger, Wyoming facility. Although WES’s management cannot predict the outcome of settlement discussions in these matters, WES’s management believes that it is reasonably likely a resolution of these matters will result in a fine or penalty for each matter in excess of $100,000.
We are not engaged in any material litigation. Except as discussed above, WES is not a party to any legal, regulatory, or administrative proceedings other than proceedings arising in the ordinary course of its business. WES’s managementManagement believes that there are no such proceedings for which a final disposition could have a material adverse effect on its results of operations, cash flows, or financial condition, or for which disclosure is otherwise required by Item 103 of Regulation S-K.S-K.

Item 1A. Risk Factors


Security holders and potential investors in our securities should carefully consider the risk factors set forth under Part I, Item 1A in our Form 10-K10-K for the year ended December 31, 2016,2023, together with all of the other information included in this document, and in our other public filings, press releases, and public discussions with management. Additionally, for a full discussion

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table sets forth information with respect to repurchases made by WES of its common units in the risks associated with Anadarko’s business, see Item 1Aopen market or in privately negotiated transactions under the $1.25 billion Purchase Program during the first quarter of 2024:
PeriodTotal number of units purchasedAverage price paid per unit
Total number of units purchased as part of publicly announced plans or programs (1)
Approximate dollar value of units that may yet be purchased under the plans or programs(1)
January 1-31, 2024— $— — $627,807,310 
February 1-29, 2024— — — 627,807,310 
March 1-31, 2024— — — 627,807,310 
Total— — — 
______________________________________________________________________________________
(1)In 2022, the Board authorized WES to buy back up to $1.25 billion of our common units through December 31, 2024. See Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, in Anadarko’s Form 10-K for the year ended December 31, 2016, Anadarko’s quarterly reports onItem 1 of this Form 10-Q for additional details.

58

Item 5. Other Information

Insider Trading Arrangements

Rule 10b5-1 under the Exchange Act provides an affirmative defense that enables prearranged transactions in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits our directors and Anadarko’s other public filings, press releases and public discussionsexecutive officers to enter into trading plans designed to comply with Anadarko management. We have identified these risk factors as important factors that could causeRule 10b5-1. During the three months ended March 31, 2024, none of our actual results to differ materially from those containedexecutive officers or directors adopted or terminated a Rule 10b5-1 trading arrangement (as defined in any writtenItem 408(a)(1)(i) of Regulation S-K) or oral forward-looking statements made by usadopted or on our behalf.terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).



59


Item 6. Exhibits


Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.


Exhibit Index
Exhibit
Number
Description
#2.1
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
60

Exhibit
Number
Description
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
61

Exhibit
Number
Description
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.26
*10.1
*10.2
*10.3
*31.1
*31.2
*31.3
*31.4
**32.1
**32.2
62

Exhibit
Number
Description
*101.
Exhibit
Number
INS
Description
2.1#
2.2#
2.3#
2.4#
2.5#
2.6#
2.7#
2.8#
2.9#
2.10#
2.11#

Exhibit
Number
Description
2.12#
2.13#
2.14#
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
4.1
4.2
4.3

Exhibit
Number
Description
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
31.1*
31.2*
32.1**
101.INS*XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)
101.SCH**101.SCHInline XBRL Schema Document
101.CAL**101.CALInline XBRL Calculation Linkbase Document
101.DEF**101.DEFInline XBRL Definition Linkbase Document
101.LAB**101.LABInline XBRL Label Linkbase Document
101.PRE**101.PREInline XBRL Presentation Linkbase Document
*104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

#Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.

63


SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

WESTERN MIDSTREAM PARTNERS, LP
May 8, 2024
/s/ Michael P. Ure
WESTERN GAS EQUITY PARTNERS, LP
November 1, 2017
/s/ Benjamin M. Fink
Benjamin M. FinkMichael P. Ure
President and Chief Executive Officer
Western Gas EquityMidstream Holdings, LLC
(as general partner of Western Gas EquityMidstream Partners, LP)
May 8, 2024
/s/ Kristen S. Shults
November 1, 2017
/s/ Jaime R. Casas
Jaime R. CasasKristen S. Shults
Senior Vice President and Chief Financial Officer and Treasurer
Western Gas EquityMidstream Holdings, LLC
(as general partner of Western Gas EquityMidstream Partners, LP)
WESTERN MIDSTREAM OPERATING, LP
May 8, 2024
/s/ Michael P. Ure
Michael P. Ure
President and Chief Executive Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)
May 8, 2024
/s/ Kristen S. Shults
Kristen S. Shults
Senior Vice President and Chief Financial Officer
Western Midstream Operating GP, LLC
(as general partner of Western Midstream Operating, LP)


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