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.

Table of Contents

WESTERN ~~GAS EQUITY~~MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

3.4. PARTNERSHIP DISTRIBUTIONS ~~(CONTINUED)~~

~~WES’s~~The 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, 2023	May 1, 2023
June 30	0.5625		221,442		August 14, 2023	July 31, 2023
September 30	0.575		223,432		November 13, 2023	November 1, 2023
December 31	0.575		223,438		February 13, 2024	February 1, 2024
2024
March 31	$	0.875	$	340,858	May 15, 2024	May 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 ~~incentive~~unit 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 quarterly~~Operating. See Note 5. WES Operating made and/or declared the following cash distributions ~~that WES makes prior~~ to its ~~liquidation and, as~~limited partners for the ~~holder~~periods presented:


thousands Quarters Ended	Total Quarterly Cash Distribution		Distribution Date





2023
March 31 (1)	$	342,895	May 2023
June 30	226,260		August 2023
September 30	229,446		November 2023
December 31	229,446		February 2024
2024
March 31	$	347,675	May 2024

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

Table of the incentive distribution rights (“IDRs”), was entitled to incentive distributions at the maximum distribution sharing percentage of 48.0% for all periods presented, after the minimum quarterly distribution and the target distribution levels had been achieved. The maximum distribution sharing percentage of 49.5% does not include any distributions that WES GP may receive on common units that it may acquire.Contents

WESTERN MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4.(UNAUDITED)

5. EQUITY AND PARTNERS’ CAPITAL

Holdings of ~~WGP~~Partnership 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, Anadarko~~March 31, 2024, Occidental held ~~178,587,365 of WGP’s~~185,181,578 common units, representing ~~an 81.6%~~a 47.6% limited partner interest in ~~WGP,~~the Partnership, and through its ownership of ~~WGP GP, Anadarko~~the general partner, Occidental indirectly held ~~the entire non-economic~~9,060,641 general partner units, representing a 2.3% general partner interest in ~~WGP.~~the Partnership. The public held ~~40,345,776 WGP~~195,308,560 common units, representing ~~an 18.4%~~a 50.1% limited partner interest in ~~WGP.~~the Partnership.

Partnership equity repurchases.In ~~June 2016, Anadarko sold 12,500,000~~2022, the Board authorized the Partnership to buy back up to $1.25 billion of ~~its WGP~~the 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 expense~~time 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 completed~~Holdings of WES Operating equity. As of March 31, 2024, (i) the ~~public issuance~~Partnership, directly and indirectly through its ownership of ~~9,200,000 7.50% tangible equity units (“TEUs”), including 1,200,000 TEUs pursuant to~~WES Operating GP, owned a 98.0% limited partner interest and the ~~full exercise~~entire 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).

~~Net~~Partnership’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-average~~weighted-average number of common units outstanding during the period. ~~Dilutive~~Diluted net income (loss) per common unit ~~is calculated by dividing~~includes the ~~limited partners’ interest in~~effect 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 amounts	2024		2023
Net income (loss)
Limited partners’ interest in net income (loss)	$	559,500	$	198,959
Weighted-average common units outstanding
Basic	380,024		384,468
Dilutive effect of non-vested phantom units	1,604		1,282
Diluted	381,628		385,750
Excluded due to anti-dilutive effect	279		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 in~~Operating’s net income (loss) ~~assuming conversion of the WES Series A Preferred units into WES~~per 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 the~~for WES ~~assets (as defined in~~ ~~Note 1) acquired from Anadarko for periods prior to WES’s acquisition of the WES assets~~Operating 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~~).

Table of Contents

WESTERN ~~GAS EQUITY~~MIDSTREAM 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 Preferred~~tables summarize material related-party transactions included in the Partnership’s consolidated financial statements:


Consolidated statements of operations

	Three Months Ended March 31,
thousands		2024		2023
Revenues and other
Service revenues – fee based		$	489,729	$	423,501
Service revenues – product based		14,057		8,116
Product sales		(3,977)		17,168
Total revenues and other		499,809		448,785
Equity income, net – related parties (1)		32,819		39,021
Operating expenses
Cost of product (2)		(27,412)		(3,947)
Operation and maintenance		1,439		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
thousands	March 31, 2024		December 31, 2023
Assets
Accounts receivable, net	$	389,721	$	358,141
Other current assets	3,277		1,260
Equity investments (1)	546,078		904,535
Other assets	43,534		43,216
Total assets	982,610		1,307,152
Liabilities
Accounts and imbalance payables	38,739		38,541
Accrued liabilities	5,009		4,979
Other liabilities (2)	362,604		335,320
Total liabilities	406,352		378,840

(1)See Note 7.

(2)Includes contract liabilities from contracts with customers. See Note 2.

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

Table of Contents

WESTERN ~~GAS EQUITY~~MIDSTREAM 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,
thousands	2024		2023
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 parties	19,033		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 ~~affiliates~~the Partnership’s consolidated financial statements:


Consolidated statements of operations

	Three Months Ended March 31,
thousands		2024		2023
General and administrative (1)		$	1,306	$	1,281

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





Consolidated balance sheets
thousands	March 31, 2024		December 31, 2023
Accounts receivable, net (1)	$	407,881	$	358,141
Other current assets	3,218		1,235
Other assets	40,108		41,405
Accounts and imbalance payables	38,739		69,472
Accrued liabilities	4,692		4,662

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


Consolidated statements of cash flows

	Three Months Ended March 31,
thousands		2024		2023
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.

Table of Contents

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 ~~WES~~the Partnership from services provided to ~~Anadarko as well as~~Occidental and from the sale of ~~residue~~natural 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 natural~~connection 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 affiliate~~Anadarko 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 ~~Anadarko~~Javelin 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 ~~affiliates~~related 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 ~~expenses~~expense is paid by ~~Anadarko,~~Occidental, which results in ~~affiliate~~related-party transactions pursuant to the reimbursement provisions of the ~~omnibus~~Partnership’s and WES Operating’s agreements with Occidental. Cost of ~~WES~~product expense includes amounts related to certain continuing marketing arrangements with affiliates of Occidental, related-party imbalances, and ~~WGP. Affiliate~~transactions 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 ~~affiliate~~related-party revenues, and ~~third-party~~third-party expenses ~~do not~~ bear ano direct relationship to ~~third-party~~third-party revenues. ~~See~~ ~~Note 2~~

Services Agreement.Occidental performed certain centralized corporate functions for ~~further information related to contributions of assets to~~the 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. Prior~~Operating pursuant to the ~~acquisition~~agreement dated as of December 31, 2019, by and among Occidental, Anadarko, and WES ~~assets, third-party sales~~Operating GP (“Services Agreement”). Most of the administrative and ~~purchases related to such assets were received or paid in cash~~operational 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 related~~Partnership 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 value~~terms 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.

Table of Contents

WESTERN ~~GAS EQUITY~~MIDSTREAM 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 gains~~Construction reimbursement agreements and ~~losses upon settlement~~purchases 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 recognized~~certain midstream infrastructure for Occidental in the ~~consolidated statements~~Partnership’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 statements~~operation. 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 for~~incurred 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.

~~Table of Contents~~

~~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 Anadarko~~Partnership on a ~~majority of its systems. WES’s natural gas gathering, treating and transportation throughput (excluding equity investment throughput) attributable to production owned~~cost 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).~~

~~Table of Contents~~

~~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 also~~Additionally, 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, 2017~~Partnership’s business, the Partnership purchases and ~~2016,~~sells equipment, inventory, and ~~$0.3 million for each~~other 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, 2017~~Partnership entered into a Commercial Understanding Agreement (“CUA”). Under the CUA, certain West Texas surface-use and ~~2016.~~

~~Equipment purchases~~salt-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 ~~statements~~balance 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.

~~Table of Contents~~

~~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.~~ ~~Anadarko~~Customer concentration. Occidental was the only customer from ~~whom~~which 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:


thousands	Balance at December 31, 2023		Equity 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
Rendezvous	10,815		(578)		(237)		(464)		—		9,536
Mont Belvieu JV	88,556		51		(442)		(6,047)		(82,118)		—
TEG	15,185		169		(175)		(200)		—		14,979
TEP	172,559		7,218		(7,281)		(635)		—		171,861
FRP	186,551		11,727		(11,770)		(1,803)		—		184,705
Whitethorn LLC	144,799		1,185		3,326		(4,924)		(144,386)		—
Saddlehorn	101,760		4,200		(4,124)		(3,096)		(98,740)		—
Panola	18,716		74		(74)		(1,021)		(17,695)		—
Mi Vida	45,424		2,068		(2,050)		—		—		45,442
Red Bluff Express	106,922		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.

Table of Contents

WESTERN ~~GAS EQUITY~~MIDSTREAM 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:




thousands	Estimated Useful Life	March 31, 2024		December 31, 2023
Land	N/A	$	12,442	$	12,504
Gathering systems – pipelines	30 years	5,935,848		5,890,607
Gathering systems – compressors	15 years	2,602,110		2,553,602
Processing complexes and treating facilities	25 years	3,775,379		3,745,332
Transportation pipeline and equipment	3 to 48 years	259,227		259,314
Produced-water disposal systems	20 years	1,103,001		1,098,616
Assets under construction	N/A	560,417		479,368
Other	3 to 40 years	909,211		906,088
Total property, plant, and equipment		15,157,635		14,945,431
Less accumulated depreciation		5,432,343		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 represent~~represents 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 ~~nine~~three months ended ~~September 30, 2017, WES~~March 31, 2023, the Partnership recognized ~~impairments of $170.1 million, including an~~a 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 by~~resulting from a contract termination notice received in the ~~low commodity price environment. Also during 2016, WES recognized impairments~~first quarter of ~~$9.4 million, primarily related~~2023. This asset was impaired to its estimated fair value of $22.8 million. The fair value was measured using the ~~cancellation~~income 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 complex~~producer activity and ~~Springfield and DBJV systems, and the abandonment of compressors at the MIGC system.~~

operating costs.

Table of Contents

WESTERN ~~GAS EQUITY~~MIDSTREAM 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
thousands Fort
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 amortization 2,964
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.

~~Table of Contents~~

~~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 Partnership				WES Operating


thousands	March 31, 2024		December 31, 2023		March 31, 2024		December 31, 2023
Trade receivables, net	$	720,169	$	665,892	$	738,328	$	665,892
Other receivables, net	182		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 Partnership				WES Operating


thousands	March 31, 2024		December 31, 2023		March 31, 2024		December 31, 2023
NGLs inventory	$	2,650	$	2,557	$	2,650	$	2,557
Imbalance receivables	8,125		5,056		8,125		5,056
Prepaid insurance	15,707		21,065		13,904		18,571
Contract assets	8,708		9,595		8,708		9,595
Other	15,560		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 Partnership				WES Operating


thousands	March 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 payable	4,201		2,908		4,201		2,908
Contract liabilities	11,875		16,866		11,875		16,866
Accrued payroll and benefits	30,598		55,237		—		2,243
Other	35,098		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

Table of Contents

WESTERN ~~GAS EQUITY~~MIDSTREAM PARTNERS, LP AND WESTERN MIDSTREAM OPERATING, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

9.10. DEBT AND INTEREST EXPENSE

~~At September 30, 2017, WGP’s~~WES Operating is the borrower for all outstanding debt ~~consisted~~and is expected to be the borrower for all future debt issuances. The following table presents the outstanding debt:


	March 31, 2024						December 31, 2023
thousands	Principal		Carrying Value		Fair Value (1)		Principal		Carrying Value		Fair Value (1)
Short-term debt

Commercial paper	$	100,000	$	99,933	$	99,933	$	613,885	$	610,312	$	610,312
Finance lease liabilities	8,461		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 2025	348,645		347,631		341,763		349,163		347,938		341,415
4.650% Senior Notes due 2026	467,204		465,848		458,425		467,204		465,705		459,617
4.500% Senior Notes due 2028	350,175		347,923		338,199		357,094		354,665		346,121
4.750% Senior Notes due 2028	381,848		379,816		370,935		382,888		380,747		374,767
6.350% Senior Notes due 2029	600,000		593,364		622,248		600,000		593,069		626,994
4.050% Senior Notes due 2030	1,100,612		1,093,906		1,025,726		1,104,593		1,097,609		1,036,097
6.150% Senior Notes due 2033	750,000		741,302		769,373		750,000		741,125		780,203
5.450% Senior Notes due 2044	600,000		594,070		551,802		600,000		594,031		545,154
5.300% Senior Notes due 2048	700,000		687,798		611,492		700,000		687,735		614,082
5.500% Senior Notes due 2048	350,000		342,947		310,674		350,000		342,913		312,365
5.250% Senior Notes due 2050	1,000,000		984,276		895,150		1,000,000		984,206		895,440

Finance lease liabilities	30,394		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.

Table of Contents

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:


thousands	Carrying 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 liabilities	2,751
Other	1,905
Balance at March 31, 2024	$	7,380,473

(1)Net of borrowings ~~under~~and 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 WES~~Operating purchased and ~~WGP’s outstanding debt as~~retired $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 activity~~a 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 under~~March 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.

~~WES~~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 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 ~~indentures~~relevant governing ~~its outstanding notes.~~indentures.

Table of Contents

WESTERN ~~GAS EQUITY~~MIDSTREAM 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 $250.0~~March 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, 2017~~March 31, 2024 and ~~2016,~~2023, the interest rate on ~~the~~any 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, 2017~~March 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,
thousands		2024		2023

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 interest		5,327		2,525

Interest expense		$	(94,506)	$	(81,670)

•Adjusted gross margin ~~attributable to WES~~ for natural-gas assets (as defined under the caption ~~Key Performance Metrics~~Reconciliation 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.

Table of Contents

•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 Metrics~~Reconciliation 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 ~~same~~three 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, 2024	December 31, 2023	Inc/ (Dec)		March 31, 2023	Inc/ (Dec)
Throughput for natural-gas assets (MMcf/d)
Delaware Basin	1,761	1,704	3	%	1,569	12	%
DJ Basin	1,372	1,341	2	%	1,306	5	%
Powder River Basin	406	369	10	%	33	NM
Equity investments	508	489	4	%	423	20	%
Other	1,117	1,145	(2)	%	915	22	%
Total throughput for natural-gas assets	5,164	5,048	2	%	4,246	22	%
Throughput for crude-oil and NGLs assets (MBbls/d)
Delaware Basin	225	225	—	%	205	10	%
DJ Basin	87	81	7	%	69	26	%
Powder River Basin	23	20	15	%	—	NM
Equity investments	202	347	(42)	%	314	(36)	%
Other	39	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 Basin	1,149	1,076	7	%	977	18	%



Total throughput for produced-water assets	1,149	1,076	7	%	977	18	%

NM—Not meaningful

Table of Contents

~~Anadarko’s Colorado Response.~~ ~~Following a home explosion~~OUTLOOK

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 measures~~our 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 wells~~the 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 Basin~~first 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 tested~~a 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”) issued~~three months ended March 31, 2024, ranged from a ~~two-phase Notice~~low of $70.38 per barrel in January 2024 to ~~Operators (“NTO”) requiring all operators to inventory and integrity test existing flowlines within 1,000 feet~~a 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 requirements~~consequence of the ~~NTO. In August 2017, following a three-month review~~current 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 facilities~~commodity-price volatility, and the ~~amine treating units at~~associated direct and indirect impact on our business, cannot be predicted. To address the ~~inlet~~risks 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 returned~~volumes available for us to service in ~~December 2016. Train III (with capacity~~the 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 returned~~significant inflation relative to ~~full service~~historical 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 damage~~response to, the ~~processing facility~~COVID-19 crisis and ~~resulting lack~~in 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 referred~~our existing agreements, we have the ability to ~~as the “DBM outage.” See~~ ~~Note 1—Description~~recover a portion of ~~Business and Basis of Presentation~~increased costs in the ~~Notes~~form 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 1~~interest 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.

Table of Contents

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 Divestitures~~combined proceeds received in the ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1~~first 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 $750.0~~2024 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 resulted~~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 ~~statements~~statement of operations. ~~See~~ ~~Note 2—Acquisitions and Divestitures~~The sale of the interests in the ~~Notes to Consolidated Financial Statements~~ ~~under Part I, Item 1~~Mont 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.~~ ~~During~~our 33.75% interest in the ~~second quarter~~Marcellus 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 ~~$16.4~~approximately $65.0 million that will be recorded as Gain (loss) on divestiture and other, net in the consolidated ~~statements~~statement of ~~operations.~~

~~During~~operations during the ~~fourth~~second quarter of ~~2016,~~2024. As of March 31, 2024, the ~~Hugoton system, located in Southwest Kansas and Oklahoma, was sold~~Marcellus 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 in~~be considered held for sale. At March 31, 2024, the consolidated ~~statements~~balance 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.

~~Presentation~~Meritage. In October 2023, we closed on the acquisition of ~~WES assets.The term “WES assets” includes both~~Meritage 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 owned~~RCF.

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 Statements~~10—Debt and Interest Expense under Part I, Item 1 of this Form ~~10-Q)~~10-Q.

Table of Contents

RESULTS OF OPERATIONS

OPERATING RESULTS

The following tables and discussion present a summary of our results of operations:


	Three Months Ended


thousands	March 31, 2024		December 31, 2023		March 31, 2023
Total revenues and other (1)	$	887,729	$	858,208	$	733,982
Equity income, net – related parties	32,819		36,120		39,021
Total operating expenses (1)	480,791		495,977		480,673
Gain (loss) on divestiture and other, net	239,617		(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 debt	524		—		—
Other income (expense), net	2,346		2,862		1,215
Income (loss) before income taxes	587,738		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 interests	13,386		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 Divestitures~~6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form ~~10-Q). Further, after~~10-Q.

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

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.

Table of Contents

Throughput


	Three Months Ended


	March 31, 2024	December 31, 2023	Inc/ (Dec)		March 31, 2023	Inc/ (Dec)
Throughput for natural-gas assets (MMcf/d)
Gathering, treating, and transportation	606	516	17	%	369	64	%
Processing	4,050	4,043	—	%	3,454	17	%
Equity investments (1)	508	489	4	%	423	20	%
Total throughput	5,164	5,048	2	%	4,246	22	%
Throughput attributable to noncontrolling interests (2)	174	172	1	%	139	25	%
Total throughput attributable to WES for natural-gas assets	4,990	4,876	2	%	4,107	21	%
Throughput for crude-oil and NGLs assets (MBbls/d)
Gathering, treating, and transportation	374	368	2	%	309	21	%
Equity investments (1)	202	347	(42)	%	314	(36)	%
Total throughput	576	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 disposal	1,149	1,076	7	%	977	18	%
Throughput attributable to noncontrolling interests (2)	23	22	5	%	20	15	%
Total throughput attributable to WES for produced-water assets	1,126	1,054	7	%	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.

Table of Contents

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 percentages	March 31, 2024		December 31, 2023		Inc/ (Dec)		March 31, 2023		Inc/ (Dec)
Service revenues – fee based	$	781,262	$	763,837	2	%	$	647,867	21	%
Service revenues – product based	66,740		49,515		35	%	46,810		43	%
Total service revenues	$	848,002	$	813,352	4	%	$	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 assets~~Meritage, 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 virtue~~a 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.

Table of Contents

Product Sales


	Three Months Ended


thousands except percentages and per-unit amounts	March 31, 2024		December 31, 2023		Inc/ (Dec)		March 31, 2023		Inc/ (Dec)
Natural-gas sales	$	3,194	$	14,213	(78)	%	$	2,775	15	%
NGLs sales	36,098		30,475		18	%	36,250		—	%
Total Product sales	$	39,292	$	44,688	(12)	%	$	39,025	1	%
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		7	%

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 percentages	March 31, 2024		December 31, 2023		Inc/ (Dec)		March 31, 2023		Inc/ (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 ~~consolidation~~interests in the first quarter of ~~WES) and WES may be required~~2024. These decreases were partially offset by an increase of $4.8 million at Whitethorn LLC due to ~~recast our financial statements to include the~~commercial 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 units~~prior to the ~~public through an underwritten offering. We did not receive any proceeds from, or incur any expense~~divestment 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 pursuant~~Equity income, net – related parties decreased by $6.2 million compared to the ~~full exercise~~three months ended March 31, 2023, primarily due to decreases of ~~the underwriters’ over-allotment option,~~$6.8 million at ~~a price~~Mont Belvieu JV due to the ~~public~~divestment 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~~

Table of Contents

Cost of Product and Operation and Maintenance Expenses


	Three Months Ended


thousands except percentages	March 31, 2024		December 31, 2023		Inc/ (Dec)		March 31, 2023		Inc/ (Dec)
Residue purchases	$	9,228	$	7,931	16	%	$	15,638	(41)	%
NGLs purchases	70,425		60,303		17	%	51,829		36	%
Other	(33,574)		(27,431)		(22)	%	(16,008)		(110)	%
Cost of product	46,079		40,803		13	%	51,459		(10)	%
Operation and maintenance	194,939		200,426		(3)	%	174,239		12	%
Total Cost of product and Operation and maintenance expenses	$	241,018	$	241,229	—	%	$	225,698	7	%

Residue purchases

Residue purchases decreased by $6.4 million compared to ~~private investors. Pursuant~~the three months ended March 31, 2023, primarily due to ~~an agreement between WES and~~decreases 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 on~~Granger 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’ Capital~~contract 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.

Table of Contents

Other Operating Expenses


	Three Months Ended


thousands except percentages	March 31, 2024		December 31, 2023		Inc/ (Dec)		March 31, 2023		Inc/ (Dec)
General and administrative	$	67,839	$	73,060	(7)	%	$	51,117	33	%
Property and other taxes	13,920		16,497		(16)	%	6,831		104	%
Depreciation and amortization	157,991		165,187		(4)	%	144,626		9	%
Long-lived asset and other impairments	23		4		NM		52,401		(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.

~~ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS~~

Table of Contents

Interest Expense

~~Our consolidated financial statements include~~


	Three Months Ended


thousands except percentages	March 31, 2024		December 31, 2023		Inc/ (Dec)		March 31, 2023		Inc/ (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 interest	5,327		5,018		6	%	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 WES~~three 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% ownership~~federal statutory rate is zero percent. However, income apportionable to Texas is subject to Texas margin tax.

Table of Contents

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 GP~~owners’ proportionate share of revenues and ~~WES GP’s control~~cost of ~~WES. Our only cash-generating assets consist~~product. We believe Adjusted gross margin is an important performance measure of our ~~partnership interests~~operations’ 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. As~~NGLs pursuant to our percent-of-proceeds, percent-of-product, and keep-whole contracts, (ii) costs associated with the valuation of gas and NGLs imbalances, (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 ~~results~~offload 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 materially~~cost or market inventory adjustments recorded in cost of product), less (i) gain (loss) on divestiture and other, net, (ii) gain (loss) on early extinguishment of debt, (iii) income from equity investments, (iv) interest income, (v) income tax benefit, (vi) other income, and (vii) the noncontrolling interest owners’ proportionate share of revenues and expenses. We believe the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and ~~cash flows~~that 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 separate~~•our operating performance as compared to other publicly traded partnerships in the midstream industry, without regard to financing methods, capital structure, or historical cost basis;

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

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

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.

Table of Contents

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


thousands	March 31, 2024		December 31, 2023		March 31, 2023
Reconciliation of Gross margin to Adjusted gross margin
Total revenues and other	$	887,729	$	858,208	$	733,982
Less:
Cost of product	46,079		40,803		51,459
Depreciation and amortization	157,991		165,187		144,626
Gross margin	683,659		652,218		537,897
Add:
Distributions from equity investments	48,337		46,661		51,975
Depreciation and amortization	157,991		165,187		144,626
Less:
Reimbursed electricity-related charges recorded as revenues	24,695		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.

Table of Contents

To facilitate investor and industry analysis, we ~~incur~~also disclose per-Mcf Adjusted gross margin for natural-gas assets, per-Bbl Adjusted gross margin for crude-oil and NGLs assets, and per-Bbl Adjusted gross margin for produced-water assets.


	Three Months Ended


thousands except per-unit amounts	March 31, 2024		December 31, 2023		March 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.

Table of Contents


	Three Months Ended


thousands	March 31, 2024		December 31, 2023		March 31, 2023
Reconciliation of Net income (loss) to Adjusted EBITDA
Net income (loss)	$	586,216	$	295,752	$	208,341
Add:
Distributions from equity investments	48,337		46,661		51,975
Non-cash equity-based compensation expense	9,423		9,970		7,199
Interest expense	94,506		97,622		81,670
Income tax expense	1,522		1,405		1,416
Depreciation and amortization	157,991		165,187		144,626
Impairments	23		4		52,401
Other expense	112		71		200
Less:
Gain (loss) on divestiture and other, net	239,617		(6,434)		(2,118)
Gain (loss) on early extinguishment of debt	524		—		—
Equity income, net – related parties	32,819		36,120		39,021

Other income	2,346		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, net	94,506		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 parties	19,033		7,389		12,366
Changes in assets and liabilities:
Accounts receivable, net	53,714		17,773		4,037
Accounts and imbalance payables and accrued liabilities, net	100,383		(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 activities	396,849		(1,068,707)		(179,178)
Net cash provided by (used in) financing activities	(774,098)		378,700		(297,257)

Table of Contents


	Three Months Ended


thousands	March 31, 2024		December 31, 2023		March 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 expenditures	193,789		198,653		173,088
Contributions to equity investments – related parties	—		—		110
Add:
Distributions from equity investments in excess of cumulative earnings – related parties	19,033		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 activities	396,849		(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.

Table of Contents

KEY PERFORMANCE METRICS


	Three Months Ended


thousands except percentages and per-unit amounts	March 31, 2024		December 31, 2023		Inc/ (Dec)		March 31, 2023		Inc/ (Dec)



Adjusted gross margin	$	845,052	$	819,381	3	%	$	695,155	22	%
Per-Mcf Adjusted gross margin for natural-gas assets (1)	1.32		1.29		2	%	1.30		2	%
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 EBITDA	608,409		570,665		7	%	498,695		22	%
Free cash flow	224,952		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.

Table of Contents

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 separate~~excluding 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 ~~addition~~capital expenditures.

Free cash flow increased by $83.4 million compared to ~~those incurred~~the 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.

Table of Contents

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 adjustment~~Board on ~~WGP’s interest in WES is reflected as an adjustment to WGP’s partners’ capital.~~

~~Distributions.~~ ~~Our~~a 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 of~~following 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’s~~on our ability to ~~make~~generate 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 exclusively~~our business, including (i) to fund ~~our working~~future capital ~~borrowings. As of September 30, 2017, we had no outstanding borrowings and $30.0 million available~~expenditures, (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 activities~~unitholder 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 purposes~~any 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⁾

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 ~~third~~first quarter of ~~2017~~2024 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 ~~WES~~our unitholders of record at the close of business on ~~November 2, 2017. In connection~~May 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 ~~closing~~regular first-quarter distribution of the ~~DBM acquisition~~following year (beginning in ~~November 2014, WES issued Class C units that will receive distributions~~2023), in a target amount equal to Free cash flow generated in the ~~form~~prior 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 C~~cash 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 Distributions~~may be purchased from time to time in the ~~Notes~~open market at prevailing market prices or in privately negotiated transactions. The timing and amount of purchases under the program will be determined based on ongoing assessments of capital needs, our financial performance, the market price of 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 Statements~~purchase 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 management~~Management continuously monitors ~~its~~our leverage position and ~~coordinates its~~other financial projections to manage the capital ~~expenditure program, quarterly distributions~~structure 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 flows~~requirements, contractual restrictions, and ~~projected debt-repayment schedule. WES’s management will continue to evaluate funding alternatives, including additional borrowings~~other 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 ~~its~~our control. Read Risk Factors under Part II, Item 1A of this Form 10-Q.

Table of Contents

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 ~~need~~needs for ~~short-term~~short-term funding. Working capital requirements are driven by changes in accounts receivable and accounts payable and other factors such as credit extended to, and the timing of collections from, ~~WES’s~~our customers, and the level and timing of ~~its~~our spending for acquisitions, maintenance, and ~~expansion activity. WES’s~~other capital activities. As of March 31, 2024, we had a $358.2 million working capital ~~deficit~~surplus, 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 for~~March 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 capital~~Capital 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’s~~our assets, ~~such as to replace system components~~ and equipment that have been subject to significant use over time, become obsolete or reached the end of their useful lives, to remain in compliance with regulatory or legal requirements or to complete additional well connections to maintain existing system throughput and related cash flows (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’s~~Acquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows:


	Three Months Ended March 31,

thousands	2024		2023
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 ~~nine~~three 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 increase~~increases of (i) ~~$70.4~~$12.4 million at the ~~DBJV system~~West Texas complex, primarily attributable to engineering and ~~$23.7~~equipment 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 ~~construction~~purchase 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 ~~decreases~~a 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~~

Table of Chipeta’s capital expenditures and excluding acquisitions) from an originally reported $900.0 million to $1.0 billion, to a current range of $800.0 million to $850.0 million. WES has also updated its estimated maintenance capital expenditures from an originally reported $60.0 million to $80.0 million, to a current range of $50.0 million to $55.0 million. Based on the midpoint of the ranges, the total capital expenditure and maintenance capital expenditure estimates represent decreases of 13% and 25%, respectively, from the initial 2017 estimates due to increased capital efficiency and shifting capital spending into later periods.Contents

~~WES~~’~~s historical~~Historical cash flow. The following table and discussion present a summary of ~~WES’s~~our net cash flows provided by (used in) operating, ~~activities,~~ investing, ~~activities~~ and financing activities:


	Three Months Ended March 31,

thousands	2024		2023
Net cash provided by (used in):
Operating activities	$	399,708	$	302,424
Investing activities	396,849		(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 ~~Activities~~activities. Net cash provided by operating activities increased for the ~~nine~~three months ended ~~September 30, 2017, decreased~~March 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’s~~our results of operations as compared to the prior ~~period, refer to~~ ~~Operating Results~~ ~~within this Item 2.~~periods.

Investing ~~Activities~~activities. Net cash ~~used in~~provided by investing activities for the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2024, primarily included the following:

•$~~417.8~~582.7 million of ~~capital expenditures, net of $1.4 million of contributions in aid of construction costs from affiliates, primarily~~proceeds 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;

•$~~23.0~~19.0 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 ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2023, primarily included the following:

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

~~$367.8~~173.1 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 ~~expansion~~asset-integrity projects at the West Texas complex, DBM water systems, DBM oil system, and DJ Basin ~~complexes and the DBJV system;~~complex;

•$~~4.0~~18.3 million of ~~cash paid for equipment purchases from Anadarko;~~increases to materials and supplies inventory; and

•$~~16.6~~12.4 million of distributions received from equity investments in excess of cumulative ~~earnings; and~~earnings.

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

Financing ~~Activities~~activities. Net cash used in financing activities for the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2024, primarily included the following:

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

•$~~589.3~~229.1 million of distributions paid to WES ~~unitholders;~~unitholders and noncontrolling interest owners; and

•$~~37.3~~14.5 million to purchase and retire portions of certain of WES Operating’s senior notes via open-market repurchases.

Net cash ~~paid to Anadarko~~used 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;

•$~~9.0~~203.1 million of distributions paid to ~~the~~WES unitholders and noncontrolling interest ~~owner of Chipeta;~~owners;

•$~~250.0~~100.0 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;

Table of Contents

•$~~490.3~~7.1 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;~~

~~$600.0~~220.0 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 Expense~~we 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 1~~the 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.~~

~~WES~~certain 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 $250.0~~Operating purchased and retired $134.9 million of ~~outstanding WES~~certain 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 its~~through exposure to ~~non-payment~~non-payment or ~~non-performance~~non-performance by ~~its~~our counterparties, including ~~Anadarko,~~Occidental, financial institutions, customers, and other parties. Generally, ~~non-payment~~non-payment or ~~non-performance~~non-performance results from a customer’s inability to satisfy payables to ~~WES~~us for services rendered, minimum-volume-commitment deficiency payments owed, or volumes owed pursuant to ~~gas imbalance~~gas- or NGLs-imbalance agreements. ~~WES examines~~We examine and ~~monitors~~monitor 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-payment~~non-payment or late payment by ~~Anadarko~~producers for gathering, processing, transportation, and ~~transportation fees~~disposal fees. Additionally, we continue to evaluate counterparty credit risk and, ~~for proceeds from the sale~~in certain circumstances, are exercising our contractual rights to request adequate assurance of ~~residue, NGLs and condensate to Anadarko.~~performance.

~~WES expects its~~We expect our exposure to the concentrated risk of ~~non-payment~~non-payment or ~~non-performance~~non-performance to continue for as long as ~~it remains substantially dependent~~our commercial relationships with Occidental generate a significant portion of our revenues. While Occidental is our contracting counterparty, gathering and processing arrangements with affiliates of Occidental on ~~Anadarko for its revenues. Additionally, WES is exposed~~most of our systems include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to ~~credit risk on the note receivable from Anadarko. WES is also party~~bring 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’s~~Our ability to make cash distributions to ~~its~~our unitholders may be adversely impacted if ~~Anadarko~~Occidental becomes unable to perform under the terms of ~~its~~ gathering, processing, transportation, and ~~transportation agreements, natural gas~~disposal agreements.

Table of Contents

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 payable~~cash flows of WES Operating, which are reconciled below.

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


	Three Months Ended


thousands	March 31, 2024		December 31, 2023		March 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	—		6		—
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 services~~Operating not held by WES. A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating for all periods presented.

(2)Represents general and ~~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,
thousands	2024		2023
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
Other	19,364		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 projects~~partnership agreement. See Note 4—Partnership Distributions and ~~various operating leases. Refer to~~Note ~~9—Debt~~5—Equity and ~~Interest Expense~~ ~~and~~ ~~Note 10—Commitments and Contingencies~~Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form ~~10-Q for an update~~10-Q.

(3)Difference attributable to ~~WES’s contractual obligations as~~elimination 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 leases~~Operating’s distributions on partnership interests owned by WES. See Note 4—Partnership Distributions and ~~standby letters of credit. The information pertaining to operating leases~~Note 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, included~~Partners’ Capital in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Table of Contents

~~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 price~~Commodity-price risk. ~~Certain of WES’s processing services are provided~~There have been no significant changes to our commodity-price risk discussion from the disclosure set forth under ~~percent-of-proceeds and keep-whole agreements~~Part II, Item 7A in ~~which Anadarko is typically responsible~~our 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 Affiliates~~2023, except as noted below and in ~~the~~ ~~Notes to Consolidated Financial Statements~~Outlook under Part I, Item 12 of this Form 10-Q.

~~We consider WES’s exposure to commodity price risk associated with~~For the ~~above-described arrangements to be minimal given the existence~~three months ended March 31, 2024, 95% of ~~the commodity price swap agreements with Anadarko~~our wellhead natural-gas volume (excluding equity investments) and ~~the relatively small amount~~100% of ~~WES’s operating income (loss) that is impacted by changes in market prices. Accordingly, WES does not expect that a~~our 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’s~~our operating income (loss), financial condition, or cash flows for the next ~~twelve~~12 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 rate~~Interest-rate risk. ~~In June 2017, the~~ The Federal Open Market Committee ~~raised the~~increased its target range four times for the federal funds rate ~~from 3/4~~in 2023 and has made no changes to ~~one percent to one to 1 1/4 percent. This increase, and any~~its 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, WGP~~March 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 each~~that bear interest at a rate based on ~~LIBOR~~the Secured Overnight Financing Rate (“SOFR”) or an alternative base rate at ~~WGP’s or WES’s~~WES Operating’s option ~~respectively. A~~and (ii) $100.0 million of outstanding commercial paper borrowings. While a 10% change in ~~LIBOR~~the applicable benchmark interest rate would ~~have resulted in a nominal change in net income (loss) and~~not 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-rate~~short-term or variable-rate debt may be ~~incurred~~issued in the future, either under the ~~WES RCF, WGP~~ RCF or other financing sources, including commercial ~~bank~~paper borrowings or debt issuances.

Table of Contents

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and Chief Financial Officer of ~~WGP’s~~WES’s general partner and WES Operating GP (for purposes of this Item 4, “Management”) performed an evaluation of ~~WGP’s~~WES’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. ~~Our~~WES’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 file~~are filed or ~~submit~~submitted 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 file~~are filed or ~~submit~~submitted under the Exchange Act is accumulated and communicated to ~~our~~ management, including ~~our~~the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, Management concluded that ~~WGP’s~~WES’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 been~~were no ~~change~~changes in ~~our~~WES’s or WES Operating’s internal control over financial reporting during the quarter ended ~~September 30, 2017,~~March 31, 2024, that ~~has~~have materially affected, or isare reasonably likely to materially affect, ~~WGP’s~~WES’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 management~~Management 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-K~~10-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 1A~~open market or in privately negotiated transactions under the $1.25 billion Purchase Program during the first quarter of 2024:


Period	Total number of units purchased	Average 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 on~~Item 1 of this Form 10-Q for additional details.

Table of Contents

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 discussions~~executive officers to enter into trading plans designed to comply with ~~Anadarko management. We have identified these risk factors as important factors that could cause~~Rule 10b5-1. During the three months ended March 31, 2024, none of our ~~actual results to differ materially from those contained~~executive officers or directors adopted or terminated a Rule 10b5-1 trading arrangement (as defined in ~~any written~~Item 408(a)(1)(i) of Regulation S-K) or ~~oral forward-looking statements made by us~~adopted or ~~on our behalf.~~terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).

Table of Contents

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	Contribution Agreement and Agreement and Plan of Merger, dated as of November 7, 2018, by and among Anadarko Petroleum Corporation, Anadarko E&P Onshore LLC, APC Midstream Holdings, LLC, Western Gas Equity Partners, LP, Western Gas Equity Holdings, LLC, Western Gas Partners, LP, Western Gas Holdings, LLC, Clarity Merger Sub, LLC, WGR Asset Holding Company LLC, WGR Operating, LP, Kerr-McGee Gathering LLC, Kerr-McGee Worldwide Corporation and Delaware Basin Midstream, LLC (incorporated by reference to Exhibit 2.1 to Western Gas Equity Partners, LP’s Current Report on Form 8-K filed on November 8, 2018, File No. 001-35753).
	3.	1	Certificate of Limited Partnership of Western Gas Equity Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 of Western Gas Equity Partners, LP filed on November 5, 2012, File No. 333-184763).
	3.	2	Certificate of Amendment to Certificate of Limited Partnership of Western Gas Equity Partners, LP, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
	3.	3	Second Amended and Restated Agreement of Limited Partnership of Western Midstream Partners, LP, dated as of December 31, 2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on January 6, 2020, File No. 001-35753).
	3.	4	Certificate of Formation of Western Gas Equity Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Equity Partners, LP’s Registration Statement on Form S-1 filed on November 5, 2012, File No. 333-184763).
	3.	5	Certificate of Amendment to Certificate of Formation of Western Gas Equity Holdings, LLC, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.2 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
	3.	6	Second Amended and Restated Limited Liability Company Agreement of Western Midstream Holdings, LLC, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.7 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
	3.	7	Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of Western Midstream Holdings, LLC, dated February 28, 2019 (incorporated by reference to Exhibit 3.1 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on March 26, 2019, File No. 001-35753).
	3.	8	Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
	3.	9	Third Amended and Restated Agreement of Limited Partnership of Western Midstream Operating, LP, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.5 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
	3.	10	Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
	3.	11	Certificate of Amendment to Certificate of Formation of Western Gas Holdings, LLC, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.4 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
	3.	12	Third Amended and Restated Limited Liability Company Agreement of Western Midstream Operating GP, LLC, dated as of February 28, 2019 (incorporated by reference to Exhibit 3.8 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).
	3.	13	Certificate of Merger of Clarity Merger Sub, LLC with and into Western Gas Partners, LP, effective as of February 28, 2019 (incorporated by reference to Exhibit 3.3 to Western Midstream Partners, LP’s Current Report on Form 8-K filed on February 28, 2019, File No. 001-35753).

Table of Contents


Exhibit Number			Description
	4.	1	Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
	4.	2	Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
	4.	3	First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
	4.	4	Fourth Supplemental Indenture, dated as of June 28, 2012, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
	4.	5	Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
	4.	6	Sixth Supplemental Indenture, dated as of March 20, 2014, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
	4.	7	Form of 5.450% Senior Notes due 2044 (incorporated by reference to Exhibit 4.4, which is included as Exhibit A to Exhibit 4.2, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).
	4.	8	Seventh Supplemental Indenture, dated as of June 4, 2015, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
	4.	9	Form of 3.950% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).
	4.	10	Eighth Supplemental Indenture, dated as of July 12, 2016, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).
	4.	11	Form of 4.650% Senior Notes due 2026 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).
	4.	12	Ninth Supplemental Indenture, dated as of March 2, 2018, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
	4.	13	Form of 4.500% Senior Notes due 2028 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
	4.	14	Form of 5.300% Senior Notes due 2048 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 2, 2018, File No. 001-34046).
	4.	15	Tenth Supplemental Indenture, dated as of August 9, 2018, by and between Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 9, 2018, File No. 001-34046).
	4.	16	Form of 4.750% Senior Notes due 2028 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 9, 2018, File No. 001-34046).

Table of Contents


Exhibit Number			Description
	4.	17	Form of 5.500% Senior Notes due 2048 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1, to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 9, 2018, File No. 001-34046).
	4.	18	Eleventh Supplemental Indenture, dated as of January 13, 2020, by and between Western Midstream Operating, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
	4.	19	Form of Floating Rate Senior Notes due 2023 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A-1 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
	4.	20	Form of 3.100% Senior Notes due 2025 (incorporated by reference to Exhibit 4.3, which is included as Exhibit A-2 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
	4.	21	Form of 4.050% Senior Notes due 2030 (incorporated by reference to Exhibit 4.4, which is included as Exhibit A-3 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
	4.	22	Form of 5.250% Senior Notes due 2050 (incorporated by reference to Exhibit 4.5, which is included as Exhibit A-4 to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on January 13, 2020, File No. 001-34046).
	4.	23	Twelfth Supplemental Indenture, dated as of April 4, 2023, by and between Western Midstream Operating, LP, as Issuer, and Computershare Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on April 5, 2023, File No. 001-34046).
	4.	24	Form of 6.150% Senior Notes due 2033 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on April 5, 2023, File No. 001-34046).
	4.	25	Thirteenth Supplemental Indenture, dated as of September 29, 2023, by and between Western Midstream Operating, LP, as Issuer, and Computershare Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on September 29, 2023, File No. 001-34046).
	4.	26	Form of 6.350% Senior Notes due 2029 (incorporated by reference to Exhibit 4.2, which is included as Exhibit A to Exhibit 4.1 to Western Midstream Operating, LP’s Current Report on Form 8-K filed on September 29, 2023, File No. 001-34046).
*	10.	1	Form of 2024 Phantom Unit Award Agreement (Time-Based Awards).
*	10.	2	Form of 2024 Phantom Unit Award Agreement (TUR Awards).
*	10.	3	Form of 2024 Phantom Unit Award Agreement (ROA Awards).


































*	31.	1	Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Partners, LP.
*	31.	2	Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Partners, LP.
*	31.	3	Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Operating, LP.
*	31.	4	Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 - Western Midstream Operating, LP.
**	32.	1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Western Midstream Partners, LP.
**	32.	2	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Western Midstream Operating, LP.

Table of Contents

Exhibit
Number

Description

101.

~~Exhibit~~

~~Number~~

INS

~~Description~~

~~2.1#~~

Contribution, Conveyance and Assumption Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, Anadarko Petroleum Corporation, WGR Holdings, LLC, Western Gas Resources, Inc., WGR Asset Holding Company LLC, Western Gas Operating, LLC and WGR Operating, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).

~~2.2#~~

Contribution Agreement, dated as of November 11, 2008, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on November 13, 2008, File No. 001-34046).

~~2.3#~~

Contribution Agreement, dated as of July 10, 2009, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Anadarko Uintah Midstream, LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).

~~2.4#~~

Contribution Agreement, dated as of January 29, 2010 by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, Mountain Gas Resources LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010 File No. 001-34046).

~~2.5#~~

Contribution Agreement, dated as of July 30, 2010, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).

~~2.6#~~

Purchase and Sale Agreement, dated as of January 14, 2011, by and among Western Gas Partners, LP, Kerr-McGee Gathering LLC and Encana Oil & Gas (USA) Inc. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 18, 2011 File No. 001-34046).

~~2.7#~~

Contribution Agreement, dated as of December 15, 2011, by and among Western Gas Resources, Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 15, 2011, File No. 001-34046).

~~2.8#~~

Contribution Agreement, dated as of February 27, 2013, by and among Anadarko Marcellus Midstream, L.L.C., Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP, Anadarko Petroleum Corporation and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).

~~2.9#~~

Contribution Agreement, dated as of February 27, 2014, by and among WGR Asset Holding Company LLC, APC Midstream Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.9 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 28, 2014, File No. 001-34046).

~~2.10#~~

Agreement and Plan of Merger, dated October 28, 2014, by and among Western Gas Partners, LP, Maguire Midstream LLC and Nuevo Midstream, LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on October 28, 2014, File No. 001-34046).

~~2.11#~~

Purchase and Sale Agreement, dated as of March 2, 2015, by and among WGR Asset Holding Company LLC, Delaware Basin Midstream, LLC, Western Gas Partners, LP, and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 3, 2015, File No. 001-34046).



~~Exhibit~~ ~~Number~~		~~Description~~
~~2.12#~~		Amendment No. 1 to Purchase and Sale Agreement, dated as of May 22, 2017, by and between WGR Asset Holding Company LLC and Delaware Basin Midstream, LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 23, 2017, File No. 001-34046).
~~2.13#~~		Contribution Agreement, dated as of February 24, 2016, by and among WGR Asset Holding Company, LLC, APC Midstream Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP and Anadarko Petroleum Corporation (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 1, 2016, File No.001-34046).
~~2.14#~~		Interest Swap and Purchase Agreement, dated February 9, 2017, among Western Gas Partners, LP, WGR Operating, LP, Delaware Basin JV Gathering, LLC, Williams Partners L.P., Williams Midstream Gas Services LLC and Appalachia Midstream Services, L.L.C. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 9, 2017, File No. 001-34046).
~~3.1~~		Certificate of Limited Partnership of Western Gas Equity Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 of Western Gas Equity Partners, LP filed on November 5, 2012, File No. 333-184763).
~~3.2~~		First Amended and Restated Agreement of Limited Partnership of Western Gas Equity Partners, LP, dated as of December 12, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Equity Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-35753).
~~3.3~~		Certificate of Formation of Western Gas Equity Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Equity Partners, LP’s Registration Statement on Form S-1 filed on November 5, 2012, File No. 333-184763).
~~3.4~~		Amended and Restated Limited Liability Company Agreement of Western Gas Equity Holdings, LLC, dated as of December 12, 2012 (incorporated by reference to Exhibit 3.2 to Western Gas Equity Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-35753).
~~3.5~~		Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
~~3.6~~		Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 14, 2016 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 16, 2016, File No. 001-34046).
~~3.7~~		Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 14, 2016 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 16, 2016, File No. 001-34046).
~~3.8~~		Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated February 22, 2017 (incorporated by reference to Exhibit 3.4 to Western Gas Partners, LP’s Annual Report on Form 10-K filed on February 23, 2017, File No. 001-34046).
~~3.9~~		Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
~~3.10~~		Second Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated December 12, 2012 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
~~4.1~~		~~Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).~~
~~4.2~~		Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
~~4.3~~		First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).

~~Exhibit~~

~~Number~~

~~Description~~

~~4.4~~

~~Form of 5.375% Senior Notes due 2021 (incorporated by reference to Exhibit 4.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).~~

~~4.5~~

Fourth Supplemental Indenture, dated as of June 28, 2012, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).

~~4.6~~

~~Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).~~

~~4.7~~

Fifth Supplemental Indenture, dated as of August 14, 2013, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).

~~4.8~~

~~Form of 2.600% Senior Notes due 2018 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).~~

~~4.9~~

Sixth Supplemental Indenture, dated as of March 20, 2014, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).

~~4.10~~

~~Form of 5.450% Senior Notes due 2044 (incorporated by reference to Exhibit 4.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 20, 2014, File No. 001-34046).~~

~~4.11~~

Seventh Supplemental Indenture, dated as of June 4, 2015, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).

~~4.12~~

~~Form of 3.950% Senior Notes due 2025 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 4, 2015, File No. 001-34046).~~

~~4.13~~

Eighth Supplemental Indenture, dated as of July 12, 2016, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).

~~4.14~~

~~Form of 4.650% Senior Notes due 2026 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 12, 2016, File No. 001-34046).~~

31.1*

~~Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.~~

31.2*

~~Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.~~

32.1**

~~Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.~~

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.

SCH

Inline XBRL Schema Document

101.CAL**

101.

CAL

Inline XBRL Calculation Linkbase Document

101.DEF**

101.

DEF

Inline XBRL Definition Linkbase Document

101.LAB**

101.

LAB

Inline XBRL Label Linkbase Document

101.PRE**

101.

PRE

Inline 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.

Table of Contents

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. Fink~~Michael P. Ure President and Chief Executive Officer Western ~~Gas Equity~~Midstream Holdings, LLC (as general partner of Western ~~Gas Equity~~Midstream Partners, LP)

May 8, 2024
		/s/ Kristen S. Shults
~~November 1, 2017~~

	~~/s/ Jaime R. Casas~~
	~~Jaime R. Casas~~Kristen S. Shults Senior Vice President and Chief Financial Officer ~~and Treasurer~~ Western ~~Gas Equity~~Midstream Holdings, LLC (as general partner of Western ~~Gas Equity~~Midstream 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)

6264


		Commission file number:
~~Delaware~~	~~46-0967367~~
(State or other jurisdiction of incorporation or ~~organization)~~ organization:			(I.R.S. Employer Identification No.) :
Western Midstream Partners, LP		001-35753		Delaware	46-0967367
~~1201 Lake Robbins Drive~~ ~~The Woodlands, Texas~~ Western Midstream Operating, LP		001-34046		~~77380~~
~~(Address of principal executive offices)~~Delaware			~~(Zip Code)~~26-1075808


			Defined Term						Definition
			Anadarko						Anadarko 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/d						42 U.S. gallons measured at 60 degrees Fahrenheit, barrels per day, thousand barrels per day.
			Board						The board of directors of WES’s general partner.

			Chipeta						Chipeta Processing, LLC, in which we are the managing member of and own a 75% interest.

			Condensate						A natural-gas liquid with a low vapor pressure compared to drip condensate, mainly composed of propane, butane, pentane, and heavier hydrocarbon fractions.
			DBM water systems						Produced-water gathering and disposal systems in West Texas.

			DJ Basin complex						The 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 Act						The Securities Exchange Act of 1934, as amended.


			FRP						Front Range Pipeline LLC, in which we own a 33.33% interest.
			GAAP						Generally accepted accounting principles in the United States.
			General partner						Western Midstream Holdings, LLC, the general partner of the Partnership.
			Imbalance						Imbalances 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/d						Thousand cubic feet, million cubic feet, million cubic feet per day.
			Meritage						Meritage Midstream Services II, LLC, which was acquired by the Partnership on October 13, 2023.

			Mi Vida						Mi Vida JV LLC, in which we own a 50% interest.
			MLP						Master 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.

			Occidental						Occidental 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 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.

			RCF						WES Operating’s $2.0 billion senior unsecured revolving credit facility.
			Red Bluff Express						Red 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.
			Rendezvous						Rendezvous Gas Services, LLC, in which we own a 22% interest.


			Defined Term						Definition
			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).
			SEC						U.S. Securities and Exchange Commission.
			Services Agreement						That 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 oil						A 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.


			TEG						Texas Express Gathering LLC, in which we own a 20% interest.
			TEP						Texas Express Pipeline LLC, in which we own a 20% interest.
			WES Operating						Western Midstream Operating, LP, formerly known as Western Gas Partners, LP, and its subsidiaries.
			WES Operating GP						Western Midstream Operating GP, LLC, the general partner of WES Operating.
			West Texas complex						The Delaware Basin Midstream complex and DBJV and Haley systems.
			WGRAH						WGR Asset Holding Company LLC, a subsidiary of Occidental.
			White Cliffs						White 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 Program						The $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.



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



	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			—


þ☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


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


WESTERN MIDSTREAM PARTNERS, LP
WESTERN MIDSTREAM OPERATING, LP
(Exact name of registrant as specified in its charter)


TABLE OF CONTENTS
							PAGE
					~~PAGE~~
PART I	FINANCIAL INFORMATION (UNAUDITED)
		Item 1.	Financial Statements
			Western Midstream Partners, LP
			Consolidated Statements of Operations for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31 , 202 4 and ~~2016~~2023			6
			Consolidated Balance Sheets as of ~~September 30, 2017,~~M arch 3 1 , 202 4 , and December 31, ~~2016~~202 3			7
			Consolidated ~~Statement~~Statements of Equity and Partners’ Capital for the ~~nine~~ three months ended ~~September 30, 2017~~March 3 1 , 202 4 and 202 3			8
			Consolidated Statements of Cash Flows for three months ended March 31, 2024 and 2023			9
			Western Midstream Operating, LP
			Consolidated Statements of Operations for the three months ended March 31, 2024 and 2023			10
			Consolidated Balance Sheets as of M arch 3 1 , 2024, and December 31, 2023			11
			Consolidated Statements of Equity and Partners’ Capital for the three months ended March 3 1 , 202 4 and 202 3			12
			Consolidated Statements of Cash Flows for the ~~nine~~ three months ended ~~September 30, 2017~~March 31 , 202 4 and ~~2016~~202 3			913
			Notes to Consolidated Financial Statements			1014
			Note 1. Description of Business and Basis of Presentation			1014
			Note 2. Revenue from Contracts with Customers			17
			Note 3. Acquisitions and Divestitures			1519
			Note 3.4. Partnership Distributions			1720
			Note 4.5. Equity and Partners’ Capital			1922
			Note 5.6. Related-Party Transactions ~~with Affiliates~~			2123
			Note 7. Equity Investments			26
			Note 6.8. Property, Plant, and Equipment			2627

			Note ~~7. Equity Investments~~			27
	~~Note 8.~~9. Selected Components of Working Capital	28
			Note 9.10. Debt and Interest Expense			29
			Note ~~10.~~11. Commitments and Contingencies			3031

		Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			3132
			Cautionary Note Regarding Forward-Looking Statements			3132
			Executive Summary			3334
			Outlook			36
			Acquisitions and Divestitures			3537

			~~Equity Offerings~~Results of Operations			3638
			Operating Results			38
			Reconciliation of Non-GAAP Financial Measures			45
			Key Performance Metrics			50
			Liquidity and Capital Resources			52
			Items Affecting the Comparability of Financial Results with WES Operating			3656
			~~Results of Operations~~Critical Accounting Estimates			3957
			~~Operating Results~~			39
	~~Key Performance Metrics~~	46
	~~Liquidity and Capital Resources~~	52
	~~Contractual Obligations~~	56
	~~Off-Balance Sheet Arrangements~~	57
	Recent Accounting Developments	57
		Item 3.	Quantitative and Qualitative Disclosures About Market Risk			57
		Item 4.	Controls and Procedures			58
PART II				OTHER INFORMATION
		Item 1.	Legal Proceedings			58
		Item 1A.	Risk Factors			58
		Item 6.2.	~~Exhibits~~Unregistered Sales of Equity Securities and Use of Proceeds			58
		Item 5.	Other Information			59
		Item 6.	Exhibits			60



	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


⁽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~~.


	Partners’ Capital
thousands	Common 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


(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.~~



	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


⁽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.


thousands	Common 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


	Wholly Owned and Operated	Operated Interests	Non-Operated Interests	Equity Interests
Gathering systems (1)	18	2	3	1
Treating facilities	38	3	—	—
Natural-gas processing plants/trains	24	3	—	1
NGLs pipelines	3	—	—	4
Natural-gas pipelines	6	—	—	1
Crude-oil pipelines	3	1	—	1



	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



	~~Percentage Interest~~
~~Equity investments~~ ⁽¹⁾
~~Fort Union~~	~~14.81~~	%
~~White Cliffs~~	10	%
~~Rendezvous~~	22	%
~~Mont Belvieu JV~~	25	%
~~TEP~~	20	%
~~TEG~~	20	%
~~FRP~~	~~33.33~~	%
~~Proportionate consolidation~~ ⁽²⁾
~~Marcellus Interest systems~~	~~33.75~~	%
~~Newcastle system~~	50	%
~~Springfield system~~	~~50.1~~	%
~~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.~~


	Percentage Interest
Full consolidation
Chipeta (1)	75.00	%
Proportionate consolidation (2)
Springfield system	50.10	%
Marcellus Interest systems	33.75	%
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	%




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 recognized	1,974

Contract assets balance at March 31, 2024	$	39,338



Contract assets at March 31, 2024
Other current assets	$	8,708
Other assets	30,630
Total contract assets from contracts with customers	$	39,338




thousands
Contract liabilities balance at December 31, 2023	$	445,499
Cash received or receivable, excluding revenues recognized during the period	36,960

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 liabilities	458,869
Total contract liabilities from contracts with customers	$	470,744


thousands
Remainder of 2024	$	881,845
2025	1,113,716
2026	1,029,954
2027	919,010
2028	712,825
Thereafter	2,001,043
Total	$	6,658,393



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		—	—



	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	$	—		$	—


⁽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.~~


thousands
Assets acquired:
Cash and cash equivalents	$	38,412
Accounts receivable, net	34,060
Other current assets	1,980
Property, plant, and equipment	926,347
Other assets	6,498
Total assets acquired	1,007,297
Liabilities assumed:
Accounts payable and accrued liabilities	34,733
Other current liabilities	5,451
Asset retirement obligation	22,156
Other liabilities	28,356
Total liabilities assumed	90,696
Net assets acquired	$	916,601