~~Bbls = barrels~~

~~Bcf = billion cubic feet~~


GCF						Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF. The GCF assets have been temporarily idled to reduce operating expenses.
General Partner						EnLink Midstream GP, LLC, the general partner of ENLK.
GIP						Global Infrastructure Management, LLC, an independent infrastructure fund manager, itself, its affiliates, or managed fund vehicles, including GIP III Stetson I, L.P., GIP III Stetson II, L.P., and their affiliates.
ISDAs						International Swaps and Derivatives Association Agreements.
LIBOR						U.S. Dollar London Interbank Offered Rate.
Managing Member						EnLink Midstream Manager, LLC, the managing member of ENLC.
Merger						On January 25, 2019, NOLA Merger Sub, LLC (previously a wholly-owned subsidiary of ENLC) merged with and into ENLK with ENLK continuing as the surviving entity and a subsidiary of ENLC.
Midland Basin						A large sedimentary basin in West Texas.
Mbbls						Thousand barrels.
MMbbls						Million barrels.
MMbtu						Million British thermal units.
MMcf						Million cubic feet.
MMgals						Million gallons.
MVC						Minimum volume commitment.
NGL						Natural gas liquid.
NGP						NGP Natural Resources XI, LP.

Operating Partnership						EnLink Midstream Operating, LP, a Delaware limited partnership and wholly owned subsidiary of ENLK.
ORV						ENLK’s Ohio River Valley crude oil, condensate stabilization, natural gas compression, and brine disposal assets in the Utica and Marcellus shales.
OTC						Over-the-counter.
Permian Basin						A large sedimentary basin that includes the Midland and Delaware Basins primarily in West Texas and New Mexico.
POL contracts						Percentage-of-liquids contracts.
POP contracts						Percentage-of-proceeds contracts.
Revolving Credit Facility						A $1.40 billion unsecured revolving credit facility entered into by ENLC that matures on June 3, 2027, which includes a $500.0 million letter of credit subfacility. The Revolving Credit Facility is guaranteed by ENLK.

Series B Preferred Unit						ENLK’s Series B Cumulative Convertible Preferred Unit.
Series C Preferred Unit						ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Unit.
SOFR						Secured overnight financing rate.
STACK						Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.


Term Loan						A term loan originally in the amount of $850.0 million entered into by ENLK on December 11, 2018 with Bank of America, N.A., as Administrative Agent, Bank of Montreal and Royal Bank of Canada, as Co-Syndication Agents, Citibank, N.A. and Wells Fargo Bank, National Association, as Co-Documentation Agents, and the lenders party thereto, which ENLC assumed in connection with the Merger and the obligations of which ENLK guaranteed. The Term Loan was paid upon maturity on December 10, 2021.

~~Gal = gallon~~

~~Mcf = thousand cubic feet~~

~~MMBtu = million British thermal units~~

~~MMcf = million cubic feet~~

~~NGL = natural gas liquid and natural gas liquids~~

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)


	September 30, 2022		December 31, 2021
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	26.2
Accounts receivable:
Trade, net of allowance for bad debt of $0.1 and $0.3, respectively	137.0		94.9
Accrued revenue and other	810.6		693.3

Fair value of derivative assets	76.2		22.4
Other current assets	175.0		83.6
Total current assets	1,198.8		920.4
Property and equipment, net of accumulated depreciation of $4,694.2 and $4,332.0, respectively	6,497.7		6,388.3
Intangible assets, net of accumulated amortization of $891.7 and $795.1, respectively	953.1		1,049.7

Investment in unconsolidated affiliates	71.6		28.0
Fair value of derivative assets	0.7		0.2
Other assets, net	91.4		96.6
Total assets	$	8,813.3	$	8,483.2
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	208.7	$	139.6

Accrued gas, NGLs, condensate, and crude oil purchases (1)	678.1		521.5
Fair value of derivative liabilities	52.2		34.9
Other current liabilities	218.3		202.9
Total current liabilities	1,157.3		898.9
Long-term debt, net of unamortized issuance cost	4,537.4		4,363.7

Other long-term liabilities	90.2		93.9
Deferred tax liability, net	153.6		137.5
Fair value of derivative liabilities	0.8		2.2

Members’ equity:
Members’ equity (474,566,135 and 484,277,258 units issued and outstanding, respectively)	1,259.2		1,325.8
Accumulated other comprehensive loss	(1.3)		(1.4)
Non-controlling interest	1,616.1		1,662.6
Total members’ equity	2,874.0		2,987.0
Commitments and contingencies (Note 16)
Total liabilities and members’ equity	$	8,813.3	$	8,483.2

____________________________

September 30, 2017 December 31, 2016
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents $ 141.9
$ 11.7
Accounts receivable:
Trade, net of allowance for bad debt of $0.1 and $0.1, respectively 42.5
63.9
Accrued revenue and other 432.4
369.6
Related party 121.5
100.2
Fair value of derivative assets 4.6
1.3
Natural gas and NGLs inventory, prepaid expenses and other 73.4
33.5
Investment in unconsolidated affiliates—current —
193.1
Total current assets 816.3
773.3
Property and equipment, net of accumulated depreciation of $2,428.5 and $2,124.1, respectively 6,568.8
6,256.7
Fair value of derivative assets 0.1
—
Intangible assets, net of accumulated amortization of $267.8 and $171.6, respectively 1,528.0
1,624.2
Goodwill 1,542.2
1,542.2
Investment in unconsolidated affiliates—non-current 86.1
77.3
Other assets, net 6.8
2.2
Total assets $ 10,548.3
$ 10,275.9
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable $ 65.2
$ 69.2
Accounts payable to related party 36.8
10.4
Accrued gas, NGLs, condensate and crude oil purchases 376.6
333.3
Fair value of derivative liabilities 7.2
7.6
Installment payable, net of discount of $7.0 and $0.5, respectively 243.0
249.5
Other current liabilities 235.2
217.5
Total current liabilities 964.0
887.5
Long-term debt 3,540.5
3,295.3
Asset retirement obligations 14.0
13.5
Installment payable, net of discount of $26.3 at December 31, 2016 —
223.7
Other long-term liabilities 38.7
42.5
Deferred tax liability 550.2
542.6

Redeemable non-controlling interest 4.6
5.2

Members’ equity:
Members’ equity (180,586,977 and 180,049,316 units issued and outstanding, respectively) 1,763.5
1,880.9
Accumulated other comprehensive loss (2.0 ) —
Non-controlling interest 3,674.8
3,384.7
Total members’ equity 5,436.3
5,265.6
Commitments and contingencies (Note 15)

Total liabilities and members’ equity $ 10,548.3
$ 10,275.9
(1)Includes related party accounts payable balances of $4.3 million and $1.6 million at September 30, 2022 and December 31, 2021, respectively.

See accompanying notes to consolidated financial statements.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Operations

(In millions, except per unit data)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(Unaudited)
Revenues:
Product sales	$	2,384.4	$	1,610.2	$	6,798.8	$	3,968.7
Midstream services	258.6		211.0		699.2		629.2
Gain (loss) on derivative activity	20.5		(33.6)		(6.2)		(155.2)
Total revenues	2,663.5		1,787.6		7,491.8		4,442.7
Operating costs and expenses:
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	2,131.1		1,400.8		6,030.7		3,390.6
Operating expenses	136.8		106.9		386.6		260.0
Depreciation and amortization	162.6		153.0		474.5		455.9

(Gain) loss on disposition of assets	(0.8)		(0.4)		3.9		(0.7)
General and administrative	34.5		28.2		91.9		80.3

Total operating costs and expenses	2,464.2		1,688.5		6,987.6		4,186.1
Operating income	199.3		99.1		504.2		256.6
Other income (expense):
Interest expense, net of interest income	(60.4)		(60.1)		(171.0)		(180.1)
Loss on extinguishment of debt	(5.7)		—		(6.2)		—
Loss from unconsolidated affiliate investments	(1.7)		(2.3)		(4.0)		(9.9)
Other income	0.3		—		0.6		0.1
Total other expense	(67.5)		(62.4)		(180.6)		(189.9)
Income before non-controlling interest and income taxes	131.8		36.7		323.6		66.7
Income tax expense	(15.2)		(4.4)		(17.1)		(12.4)
Net income	116.6		32.3		306.5		54.3
Net income attributable to non-controlling interest	35.8		30.4		105.2		86.7
Net income (loss) attributable to ENLC	$	80.8	$	1.9	$	201.3	$	(32.4)
Net income (loss) attributable to ENLC per unit:
Basic common unit	$	0.17	$	—	$	0.42	$	(0.07)
Diluted common unit	$	0.17	$	—	$	0.41	$	(0.07)

____________________________

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(Unaudited)
Revenues:
Product sales $ 1,056.7
$ 771.0
$ 2,973.9
$ 2,097.8
Product sales—related parties 35.3
43.1
107.3
99.3
Midstream services 136.4
125.7
395.7
348.5
Midstream services—related parties 175.0
165.3
507.6
488.5
Loss on derivative activity (5.5 ) (0.5 ) (1.1 ) (6.6 )
Total revenues 1,397.9
1,104.6
3,983.4
3,027.5
Operating costs and expenses:
Cost of sales (1) 1,053.2
788.2
2,987.9
2,106.8
Operating expenses 102.1
98.0
308.8
296.3
General and administrative 31.3
29.3
98.5
94.7
(Gain) loss on disposition of assets 1.1
(3.0 ) 0.8
(2.9 )
Depreciation and amortization 136.3
126.2
407.1
373.0
Impairments 1.8
—
8.8
873.3
Gain on litigation settlement —
—
(26.0 ) —
Total operating costs and expenses 1,325.8
1,038.7
3,785.9
3,741.2
Operating income (loss) 72.1
65.9
197.5
(713.7 )
Other income (expense):
Interest expense, net of interest income (49.6 ) (48.4 ) (142.2 ) (138.9 )
Gain on extinguishment of debt —
—
9.0
—
Income (loss) from unconsolidated affiliates 4.4
1.1
5.0
(0.5 )
Other income 0.3
0.1
0.5
0.1
Total other expense (44.9 ) (47.2 ) (127.7 ) (139.3 )
Income (loss) before non-controlling interest and income taxes 27.2
18.7
69.8
(853.0 )
Income tax provision (3.1 ) (7.6 ) (9.3 ) (6.0 )
Net income (loss) 24.1
11.1
60.5
(859.0 )
Net income (loss) attributable to non-controlling interest 17.9
10.4
50.3
(402.9 )
Net income (loss) attributable to EnLink Midstream, LLC $ 6.2
$ 0.7
$ 10.2
$ (456.1 )
Net income (loss) attributable to EnLink Midstream, LLC per unit:
Basic common unit $ 0.03
$ —
$ 0.06
$ (2.54 )
Diluted common unit $ 0.03
$ —
$ 0.06
$ (2.54 )
(1)Includes related party cost of sales of $5.6 million and $4.9 million for the three months ended September 30, 2022 and 2021, respectively, and $25.3 million and $11.7 million for the nine months endedSeptember 30, 2022and 2021, respectively.


~~(1)~~	~~Includes related party cost of sales of~~ ~~$47.3 million~~ ~~and~~ ~~$33.7 million~~ ~~for the three months ended~~ ~~September 30, 2017~~ ~~and~~ ~~2016, respectively, and~~ ~~$126.9 million~~ ~~and~~ ~~$126.0 million~~ ~~for the~~ ~~nine months ended September 30, 2017~~ ~~and2016, respectively.~~

See accompanying notes to consolidated financial statements.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income ~~(Loss)~~

(In millions)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(Unaudited)
Net income	$	116.6	$	32.3	$	306.5	$	54.3
Unrealized gain on designated cash flow hedge (1)	—		3.8		0.1		11.1
Comprehensive income	116.6		36.1		306.6		65.4
Comprehensive income attributable to non-controlling interest	35.8		30.4		105.2		86.7
Comprehensive income (loss) attributable to ENLC	$	80.8	$	5.7	$	201.4	$	(21.3)

____________________________

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(Unaudited)
Net income (loss) $ 24.1
$ 11.1
$ 60.5
$ (859.0 )
Loss on designated cash flow hedge, net of tax benefit of $0.2 million —
—
(2.0 ) —
Comprehensive income (loss) 24.1
11.1
58.5
(859.0 )
Comprehensive income (loss) attributable to non-controlling interest 17.9
10.4
48.7
(402.9 )
Comprehensive income (loss) attributable to EnLink Midstream, LLC $ 6.2
$ 0.7
$ 9.8
$ (456.1 )
(1)Includes tax expense of $1.2 million and $3.4 million for the three and nine months ended September 30, 2021, respectively.

See accompanying notes to consolidated financial statements.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated ~~Statement~~Statements of Changes in Members’ Equity

~~Nine Months Ended September 30, 2017~~

(In millions)


	Common Units			Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total
	$		Units	$		$		$
	(Unaudited)
Balance, December 31, 2021	$	1,325.8	484.3	$	(1.4)	$	1,662.6	$	2,987.0
Conversion of unit-based awards for common units, net of units withheld for taxes	(4.2)		1.2	—		—		(4.2)
Unit-based compensation	8.1		—	—		—		8.1
Contributions from non-controlling interests	—		—	—		7.3		7.3
Distributions	(56.4)		—	—		(34.6)		(91.0)
Unrealized gain on designated cash flow hedge	—		—	0.1		—		0.1
Redemption of Series B Preferred Units	—		—	—		(50.5)		(50.5)
Common units repurchased	(17.0)		(2.1)	—		—		(17.0)
Net income	35.2		—	—		30.8		66.0
Balance, March 31, 2022	1,291.5		483.4	(1.3)		1,615.6		2,905.8
Conversion of unit-based awards for common units, net of units withheld for taxes	(0.2)		—	—		—		(0.2)
Unit-based compensation	5.7		—	—		—		5.7
Contributions from non-controlling interests	—		—	—		2.0		2.0
Distributions	(55.3)		—	—		(42.2)		(97.5)

Common units repurchased	(33.7)		(3.6)	—		—		(33.7)
Net income	85.3		—	—		38.6		123.9
Balance, June 30, 2022	1,293.3		479.8	(1.3)		1,614.0		2,906.0
Conversion of unit-based awards for common units, net of units withheld for taxes	(8.1)		1.4	—		—		(8.1)
Unit-based compensation	11.4		—	—		—		11.4
Contributions from non-controlling interests	—		—	—		4.9		4.9
Distributions	(55.7)		—	—		(38.6)		(94.3)

Common units repurchased	(62.5)		(6.6)	—		—		(62.5)
Net income	80.8		—	—		35.8		116.6
Balance, September 30, 2022	$	1,259.2	474.6	$	(1.3)	$	1,616.1	$	2,874.0

Common Units Accumulated Other Comprehensive Loss Non-Controlling Interest Total Redeemable Non-Controlling Interest (Temporary Equity)
$ Units $ $ $ $
(Unaudited)
Balance, December 31, 2016 $ 1,880.9
180.0
$ —
$ 3,384.7
$ 5,265.6
$ 5.2
Issuance of common units by ENLK —
—
—
92.3
92.3
—
Issuance of Series C Preferred Units by ENLK —
—
—
393.7
393.7
—
Conversion of restricted units for common units, net of units withheld for taxes (5.0 ) 0.6
—
—
(5.0 ) —
Non-controlling interest’s impact of conversion of restricted units —
—
—
(5.2 ) (5.2 ) —
Unit-based compensation 17.2
—
—
17.3
34.5
—
Change in equity due to issuance of units by ENLK (0.3 ) —
—
0.5
0.2
—
Non-controlling interest distributions —
—
—
(306.3 ) (306.3 ) —
Non-controlling interest contribution —
—
—
46.2
46.2
—
Distributions to members (139.5 ) —
—
—
(139.5 ) —
Distributions to redeemable non-controlling interest —
—
—
—
—
(0.6 )
Contribution from Devon to ENLK —
—
—
1.3
1.3
—
Loss on designated cash flow hedge —
—
(2.0 ) —
(2.0 ) —
Net income 10.2
—
—
50.3
60.5
—
Balance, September 30, 2017 $ 1,763.5
180.6
$ (2.0 ) $ 3,674.8
$ 5,436.3
$ 4.6

See accompanying notes to consolidated financial statements.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of ~~Cash Flows~~Changes in Members’ Equity (Continued)

(In millions)


	Common Units			Accumulated Other Comprehensive Loss		Non-Controlling Interest		Total		Redeemable Non-Controlling Interest (Temporary Equity)
	$		Units	$		$		$		$
	(Unaudited)
Balance, December 31, 2020	$	1,508.8	489.4	$	(15.3)	$	1,719.5	$	3,213.0	$	—
Conversion of unit-based awards for common units, net of units withheld for taxes	(1.2)		0.7	—		—		(1.2)		—
Unit-based compensation	6.5		—	—		—		6.5		—
Contributions from non-controlling interests	—		—	—		0.9		0.9		—
Distributions	(47.1)		—	—		(25.8)		(72.9)		(0.2)
Unrealized gain on designated cash flow hedge (1)	—		—	3.6		—		3.6		—
Fair value adjustment related to redeemable non-controlling interest	(0.1)		—	—		—		(0.1)		0.2

Net income (loss)	(12.7)		—	—		25.3		12.6		—
Balance, March 31, 2021	1,454.2		490.1	(11.7)		1,719.9		3,162.4		—
Conversion of unit-based awards for common units, net of units withheld for taxes	(0.2)		0.1	—		—		(0.2)		—
Unit-based compensation	6.4		—	—		—		6.4		—
Contributions from non-controlling interests	—		—	—		1.0		1.0		—
Distributions	(46.7)		—	—		(36.0)		(82.7)		—
Unrealized gain on designated cash flow hedge (2)	—		—	3.7		—		3.7		—
Common units repurchased	(2.0)		(0.3)	—		—		(2.0)		—
Net income (loss)	(21.6)		—	—		31.0		9.4		—
Balance, June 30, 2021	1,390.1		489.9	(8.0)		1,715.9		3,098.0		—
Conversion of unit-based awards for common units, net of units withheld for taxes	(0.5)		0.2	—		—		(0.5)		—
Unit-based compensation	6.4		—	—		—		6.4		—
Contributions from non-controlling interests	—		—	—		0.5		0.5		—
Distributions	(46.6)		—	—		(26.2)		(72.8)		—
Unrealized gain on designated cash flow hedge (3)	—		—	3.8		—		3.8		—

Common units repurchased	(12.5)		(2.1)	—		—		(12.5)		—
Net income	1.9		—	—		30.4		32.3		—
Balance, September 30, 2021	$	1,338.8	488.0	$	(4.2)	$	1,720.6	$	3,055.2	$	—

____________________________

Nine Months Ended September 30,
2017 2016
(Unaudited)
Cash flows from operating activities:
Net income (loss) $ 60.5
$ (859.0 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments 8.8
873.3
Depreciation and amortization 407.1
373.0
(Gain) loss on disposition of assets 0.8
(2.9 )
Non-cash unit-based compensation 38.9
22.5
Loss on derivatives recognized in net income (loss) 1.1
6.6
Gain on extinguishment of debt (9.0 ) —
Cash settlements on derivatives (5.9 ) 9.5
Amortization of debt issue costs 3.0
2.9
Amortization of net discount on notes and installment payable 18.8
36.9
Redeemable non-controlling interest expense —
0.3
(Income) loss from unconsolidated affiliates (5.0 ) 0.5
Other 12.6
5.5
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue and other (56.7 ) (17.9 )
Natural gas and NGLs inventory, prepaid expenses and other (48.4 ) 11.9
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities 101.8
49.4
Net cash provided by operating activities 528.4
512.5
Cash flows from investing activities, net of assets acquired and liabilities assumed:
Additions to property and equipment (662.5 ) (423.7 )
Acquisition of business, net of cash acquired —
(791.5 )
Proceeds from insurance settlement 0.2
0.3
Proceeds from sale of unconsolidated affiliate investment 189.7
—
Proceeds from sale of property 1.8
4.7
Investment in unconsolidated affiliates (11.8 ) (45.0 )
Distribution from unconsolidated affiliates in excess of earnings 7.3
51.6
Net cash used in investing activities (475.3 ) (1,203.6 )
Cash flows from financing activities:
Proceeds from borrowings 2,213.4
1,667.7
Payments on borrowings (1,955.6 ) (1,484.5 )
Payment of installment payable for EnLink Oklahoma T.O. acquisition (250.0 ) —
Payments on capital lease obligations (2.1 ) (3.2 )
Debt financing costs (5.5 ) (4.7 )
Mandatorily redeemable non-controlling interest —
(4.0 )
Conversion of restricted units, net of units withheld for taxes (5.0 ) (1.2 )
Conversion of ENLK restricted units, net of units withheld for taxes (5.2 ) (1.2 )
Proceeds from issuance of ENLK common units 92.3
110.6
Distributions to non-controlling interests (306.9 ) (284.3 )
Distribution to members (139.5 ) (139.0 )
Contribution from Devon 1.3
1.4
Proceeds from issuance of ENLK Series B Preferred Units —
724.1
Proceeds from issuance of ENLK Series C Preferred Units 393.7
—
Contributions by non-controlling interests 46.2
151.5
Net cash provided by financing activities 77.1
733.2
Net increase in cash and cash equivalents 130.2
42.1
Cash and cash equivalents, beginning of period 11.7
18.0
Cash and cash equivalents, end of period $ 141.9
$ 60.1
Cash paid for interest $ 94.7
$ 71.2
Cash paid (refund) for income taxes $ 4.1
$ (5.6 )
(1)Includes tax expense of $1.1 million.

(2)Includes tax expense of $1.1 million.

(3)Includes tax expense of $1.2 million.

See accompanying notes to consolidated financial statements.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In millions)


	Nine Months Ended September 30,
	2022		2021
	(Unaudited)
Cash flows from operating activities:
Net income	$	306.5	$	54.3
Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization	474.5		455.9
Utility credits redeemed (earned)	27.9		(38.2)
Deferred income tax expense	16.1		12.2
(Gain) Loss on disposition of assets	3.9		(0.7)
Non-cash unit-based compensation	23.7		19.3
Amortization of designated cash flow hedge	0.1		9.6
Non-cash (gain) loss on derivatives recognized in net income	(36.5)		37.5
Loss on extinguishment of debt	6.2		—
Amortization of debt issuance costs and net discount of senior unsecured notes	3.7		3.9


Loss from unconsolidated affiliate investments	4.0		9.9
Other operating activities	(4.7)		(4.2)
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other	(142.7)		(196.5)
Natural gas and NGLs inventory, prepaid expenses, and other	(112.9)		(80.3)
Accounts payable, accrued product purchases, and other accrued liabilities	256.1		316.5
Net cash provided by operating activities	825.9		599.2
Cash flows from investing activities:
Additions to property and equipment	(213.2)		(104.7)


Contributions to unconsolidated affiliate investments	(46.3)		—
Acquisitions, net of cash acquired	(289.5)		(56.7)
Other investing activities	2.0		6.0
Net cash used in investing activities	(547.0)		(155.4)
Cash flows from financing activities:
Proceeds from borrowings	3,431.5		829.5
Repayments on borrowings	(3,265.0)		(1,034.5)
Debt financing costs	(13.4)		(0.1)
Payment of installment payable for the Amarillo Rattler Acquisition	(10.0)		—
Payment of inactive easement commitment	(10.0)		—
Distributions to members	(167.4)		(140.4)
Distributions to non-controlling interests	(115.4)		(88.2)
Redemption of Series B Preferred Units	(50.5)		—
Contributions from non-controlling interests	14.2		2.4
Common unit repurchases	(113.2)		(14.5)
Conversion of unit-based awards for common units, net of units withheld for taxes	(12.5)		(1.9)
Other financing activities	6.6		0.4
Net cash used in financing activities	(305.1)		(447.3)
Net decrease in cash and cash equivalents	(26.2)		(3.5)
Cash and cash equivalents, beginning of period	26.2		39.6
Cash and cash equivalents, end of period	$	—	$	36.1

Supplemental disclosures of cash flow information:
Cash paid for interest	$	152.4	$	130.1
Cash paid for income taxes	$	0.7	$	0.2
Non-cash investing activities:
Non-cash accrual of property and equipment	$	2.5	$	5.1
Non-cash acquisitions	$	—	$	16.9
Right-of-use assets obtained in exchange for operating lease liabilities	$	22.0	$	10.7

See accompanying notes to consolidated financial statements.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, ~~2017~~2022

(Unaudited)

(1) General

In this report, the terms “Company” or ~~“Registrant”~~“Registrant,” as well as the terms “ENLC,” “our,” “we,” “us,” ~~and “its,”~~or like terms, are sometimes used as abbreviated references to EnLink Midstream, LLC itself or EnLink Midstream, LLC together with its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the ~~“Partnership” and “ENLK”~~“Partnership,” “ENLK,” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including ~~EnLink Midstream~~the Operating ~~LP and EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”). EnLink Oklahoma T.O.~~Partnership.

Please read the notes to the consolidated financial statements in conjunction with the Definitions page set forth in this report prior to Part I—Financial Information.

a.Organization of Business

ENLC is ~~sometimes used to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP together with its consolidated subsidiaries.~~


~~(a)~~	~~Organization of Business~~

~~EnLink Midstream, LLC is~~ a ~~publicly traded~~ Delaware limited liability company formed in October 2013. The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.”

~~Our assets consist~~ ENLC owns all of equity interests in EnLink Midstream Partners, LP and EnLink Oklahoma T.O. ENLK is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. EnLink Oklahoma T.O. is a partnership held by us and ENLK and is engaged in the gathering and processing of natural gas. As of September 30, 2017, our interests in ENLK and EnLink Oklahoma T.O. consist of the following:

~~88,528,451~~ENLK’s common units ~~representing an aggregate 21.8% limited partner interest in ENLK;~~

~~100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of ENLK (the “General Partner”), which~~and also owns ~~a 0.4% general partner interest and~~ all of the ~~incentive distribution rights in ENLK;~~membership interests of the General Partner. The General Partner manages ENLK’s operations and activities.

~~16% limited partner interest in EnLink Oklahoma T.O.~~b.Nature of Business


~~(b)~~	~~Nature of Business~~

We primarily focus on providing midstream energy services, ~~including~~ including:

•gathering, ~~transmission,~~compressing, treating, processing, ~~fractionation, storage, condensate stabilization, brine services~~transporting, storing, and ~~marketing to producers of~~selling natural ~~gas, NGLs,~~gas;

•fractionating, transporting, storing, and selling NGLs; and

•gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and ~~condensate.~~ condensate, in addition to brine disposal services.

~~We connect~~As of September 30, 2022, our midstream energy asset network includes approximately 12,500 miles of pipelines, 25 natural gas processing plants with approximately 5.9 Bcf/d of processing capacity, seven fractionators with approximately 320,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers.

Our natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems ~~which~~ consist of networks of pipelines that collect natural gas from points at or near producing wells and transport it to our processing plants or to larger pipelines for further transmission. We operate processing plants that remove NGLs from the natural gas stream ~~which~~that is transported to the processing plants by our own gathering systems or by ~~major interstate and intrastate~~third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, ~~other markets~~marketers, and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from ~~third party~~third-party gathering and transmission systems and deliver natural gas to industrial end-users, utilities, and other pipelines.

Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane, and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from ~~east~~East Texas and from our ~~south~~South Louisiana processing plants. Our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our ~~west~~West Texas and ~~central~~Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers.

~~We also provide a variety~~Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate ~~services, which include crude oil and condensate gathering and transmission~~ via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We ~~have~~also purchase crude oil and condensate ~~terminal facilities~~from producers and other supply sources and sell that ~~provide market access for~~ crude oil and condensate ~~producers.~~through our terminal facilities to various markets.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodities purchased.

(2) Significant Accounting Policies


~~(a)~~	~~Basis of Presentation~~

a.Basis of Presentation

The accompanying consolidated financial statements ~~are~~have been prepared in accordance with the instructions to Form 10-Q, are unaudited, and do not include all the information and disclosures required by ~~generally accepted accounting principles in the United States of America (“GAAP”)~~GAAP for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022. Certain reclassifications were made to the financial statements for the prior period to conform to current period presentation. The effect of these reclassifications had no impact on previously reported members’ equity or net income. All significant intercompany balances and transactions have been eliminated in consolidation.


~~(b)~~	~~Adopted Accounting Standards~~

~~In March 2016,~~b.Revenue Recognition

The following table summarizes the ~~Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-09,~~ ~~Compensation~~—~~Stock Compensation (Topic 718): Improvements~~contractually committed fees (in millions) that we expect to ~~Employee Share-Based Payment Accounting~~ (“ASU 2016-09”), which simplifies several aspects related to the accounting for share-based payment transactions. Effective January 1, 2017, we adopted ASU 2016-09. We prospectively adopted the guidance that requires excess tax benefits and deficiencies be recognized on the income statement. The cash flow statement guidance requires the presentation of excess tax benefits and deficiencies as an operating activity and the presentation of cash paid by an employer when directly withholding shares for tax-withholding purposes as a financing activity, and this treatment is consistent withrecognize in our historical accounting treatment. Finally, we elected to estimate the number of awards that are expected to vest, which is consistent with our historical accounting treatment. The adoption of the new guidance did not materially affect the consolidated statements of operations, ~~for~~in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. Under these agreements, our customers or suppliers agree to transport or process a minimum volume of commodities on our system over an agreed period. If a customer or supplier fails to meet the ~~three and nine months ended September 30, 2017.~~

~~In January 2017,~~minimum volume specified in such agreement, the ~~FASB issued ASU 2017-04,~~ ~~Intangibles~~—~~Goodwill and Other (Topic 350)~~—~~Simplifying~~customer or supplier is obligated to pay a contractually determined fee based upon the ~~Test for Goodwill Impairment~~ (“ASU 2017-04”). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in Accounting Standards Codification (“ASC”) 350, ~~Intangibles~~—~~Goodwill and Other~~ (“ASC 350”). As a result, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. In January 2017, we elected to early adopt ASU 2017-04,shortfall between actual volumes and the ~~adoption had no impact on our consolidated financial statements. We will perform future goodwill impairment tests according to ASU 2017-04.~~


~~(c)~~	~~Accounting Standards to be Adopted~~contractually stated volumes. All amounts in ~~Future Periods~~

~~In February 2016,~~ the ~~FASB issued ASU 2016-02,~~ ~~Leases (Topic 842)~~—~~Amendments to~~table below are determined using the ~~FASB Accounting Standards Codification~~ ~~(“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on~~contractually-stated MVC or firm transportation volumes specified for each period multiplied by the balance sheet by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements and lease term assessments including variable lease payment, discount rate and lease incentives. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those annual periods. Early adoption is permitted. Entities are required to adopt ASU 2016-02 using a modified retrospective transition. We are currently assessing the impact of adopting ASU 2016-02. This assessment includes the gathering and evaluation of our current lease contracts and the analysis of contracts that may contain lease components. While we cannot currently estimate the quantitative effect that ASU 2016-02 will have on our consolidated financial statements, the adoption of ASU 2016-02 will increase our asset and liability balances on the consolidated balance sheetsrelevant deficiency or reservation fee. Actual amounts could differ due to the ~~required~~timing of revenue recognition or reductions to cost of ~~right-of-use assets~~sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. We record revenue under MVC and ~~corresponding lease liabilities for all lease obligations~~firm transportation contracts during periods of shortfall when it is known that ~~are currently classified~~the customer cannot, or will not, make up the deficiency. These fees do not represent the shortfall amounts we expect to collect under our MVC and firm transportation contracts, as ~~operating leases. In addition, there are industry-specific concerns with~~we generally do not expect volume shortfalls to equal the ~~implementation~~full amount of ~~ASU 2016-02, including~~ the ~~application of ASU 2016-02 to~~contractual MVCs and firm transportation contracts ~~involving easements/right-of-ways, which will require further evaluation before we are able to fully assess the impact on our consolidated financial statements.~~during these periods.


Contractually Committed Fees	Commitments
2022 (remaining)	$	34.4
2023	126.2
2024	99.6
2025	67.1
2026	59.9
Thereafter	293.6
Total	$	680.8

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~In May 2014, the FASB issued ASU 2014-09,~~ ~~Revenue from Contracts with Customers~~ ~~(“ASU 2014-09”), which established ASC Topic 606,~~ ~~Revenue from Contracts with Customers~~ (“ASC 606”). ASC 606 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which they expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 will also require significantly expanded disclosures containing qualitative and quantitative information regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In May 2016, the FASB issued ASU 2016-12, ~~Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients~~ (“ASU 2016-12”), which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles, including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied using the modified retrospective or full retrospective transition methods, with early application permitted for annual reporting periods beginning after December 15, 2016. We will adopt ASC 606 using the modified retrospective method for annual and interim reporting periods beginning January 1, 2018.

We have aggregated and reviewed our contracts that are within the scope of ASC 606. Based on our evaluation to date, we do not anticipate the adoption of ASC 606 will have a material impact on our results of operations, financial condition or cash flows. However, ASC 606 will affect how certain transactions are recorded in the financial statements. For each contract with a customer, we will need to identify our performance obligations, of which the identification includes careful evaluation of when control and the economic benefits of the commodities transfer from our customer to us. The evaluation of control will change the way we account for certain transactions, specifically those in which there is both a commodity purchase component and a service component. For contracts where control of commodities transfers to us before we perform our services, we generally have no performance obligation for our services, and accordingly, we will not consider these revenue-generating contracts. Based on that determination, all fees or fee-equivalent deductions stated in such contracts would reduce the cost to purchase commodities. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we have performance obligations for our services. Accordingly, we will consider the satisfaction of these performance obligations as revenue-generating and recognize these fees as midstream service revenues at the time we satisfy our performance obligations. For contracts where control of commodities never transfers to us and we simply earn a fee for our services, we will recognize these fees as midstream services revenues at the time we satisfy our performance obligations. Based on our review of our performance obligations in our contracts with customers, we will change the statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. This reclassification of revenues and costs will have no effect on operating income.

Our performance obligations represent promises to transfer a series of distinct goods or services that are satisfied over time and that are substantially the same to the customer. As permitted by ASC 606, we will utilize the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date. Accordingly, ASC 606 will not significantly affect the timing of income and expense on the statement of operations, and we will continue to recognize revenue at the time commodities are delivered or services are performed.

Based on the disclosure requirements of ASC 606, upon adoption, we expect to provide expanded disclosures relating to our revenue recognition policies and how these relate to our revenue-generating contractual performance obligations. In addition, we expect to present revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues.

~~(d) Property & Equipment~~

~~Impairment Review.~~ We evaluate our property and equipment for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment loss is recognized equal to the excess of the asset’s carrying value over its fair value. For the nine months ended September 30, 2017, we recognized impairments of $8.8 million, which related to the carrying values of rights-of-way that we are no longer using and an abandoned brine disposal well.

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

~~(e) Comprehensive Income (Loss)~~

Comprehensive income (loss) is composed of net income (loss) and other comprehensive income (loss), which consists of the effective portion of gains or losses on derivative financial instruments that qualify as cash flow hedges pursuant to ASC 815, ~~Derivatives and Hedging~~ (“ASC 815”). For the three and nine months ended September 30, 2017, we reclassified an immaterial amount of losses from accumulated other comprehensive income (loss) to earnings. For additional information, see “Note 13—Derivatives.”

(3) Acquisition

On ~~January 7, 2016, ENLC~~July 1, 2022, we acquired all of the equity interest in the gathering and ~~ENLK acquired~~processing assets of Crestwood Equity Partners LP located in the Barnett Shale, for a ~~16%~~cash purchase price of $275.0 million plus working capital of $14.5 million. These assets include approximately 400 miles of lean and ~~84% voting interest, respectively,~~rich gas gathering pipeline and three processing plants with 425 MMcf/d of total processing capacity. We completed this acquisition to increase the scale of our North Texas assets and realize efficiencies by redeploying redundant assets to our other segments, including the Permian segment in ~~EnLink Oklahoma T.O. for approximately $1.4 billion. The first installment of $1.02 billion for~~ the ~~acquisition was paid at closing. The second installment of $250.0 million was paid on January 6, 2017,~~near-term and the ~~final installment of $250.0 million is due no later than January 7, 2018. ENLK’s installment payables are valued net of discount within~~CCS business in the ~~total purchase price.~~future.

The first installment of approximately $1.02 billion was funded by (a) approximately $783.6 million in cash paid by ENLK, which was primarily derived from the issuance of Series B Cumulative Convertible Preferred Units (“Series B Preferred Units”), (b) 15,564,009 common units representing limited liability company interests in ENLC issued directly by ENLC and (c) approximately $22.2 million in cash paid by ENLC. The transaction was accounted for using the acquisition method.

The following table presents ~~the consideration ENLC and ENLK paid and~~ the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):


Consideration
Cash (including working capital payment)	$	289.5

Purchase price allocation (1)
Assets acquired:
Current assets	$	17.3
Property and equipment	275.0
Liabilities assumed:
Current liabilities	(2.8)
Net assets acquired	$	289.5

Consideration:
Cash $ 805.8
Issuance of ENLC common units 214.9
ENLK’s total installment payable, net of discount of $79.1 million assuming payments made on January 7, 2017 and 2018 420.9
Total consideration $ 1,441.6

Purchase Price Allocation:
Assets acquired:
Current assets (including $12.8 million in cash) $ 23.0
Property, plant and equipment 406.1
Intangibles 1,051.3
Liabilities assumed:
Current liabilities (38.8 )
Total identifiable net assets $ 1,441.6
____________________________

(1)The ~~fair value~~purchase price allocation was based on preliminary estimates and assumptions, which are subject to change within the measurement period (up to one year from the acquisition date), as we finalize the valuations of the assets acquired and liabilities assumed ~~are based on inputs that are not observable in~~upon the ~~market and thus represent Level 3 inputs. We recognized intangible assets related to customer relationships and determined their fair value using~~closing of the ~~income approach. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 15 years.~~acquisition.

We incurred ~~a total of $4.8~~$0.4 million of ~~direct~~ transaction costs ~~of which $4.4 million was recognized as expense~~ for the three and nine months ended September 30, ~~2016.~~2022. These costs are ~~included~~incurred in general and administrative ~~expenses~~costs in the accompanying consolidated statements of operations.

For the three months ended September 30, 2022, we recognized $20.6 million of revenue and $12.6 million of net income related to the assets acquired.

The following unaudited pro forma condensed consolidated financial information (in millions) for the three and nine months ended September 30, ~~2016, we recognized $77.3 million~~2022 and ~~$149.5 million of revenues, respectively, and $4.4 million and $27.9 million of net loss, respectively, related~~2021 gives effect to the July 1, 2022 acquisition of Barnett Shale assets ~~acquired.~~from Crestwood Equity Partners LP as if it had occurred on January 1, 2021. The unaudited pro forma condensed consolidated financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transaction taken place on the dates indicated and is not intended to be a projection of future results.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Pro forma total revenues	$	2,663.5	$	1,803.7	$	7,528.8	$	4,485.8
Pro forma net income	$	116.6	$	35.6	$	320.8	$	58.1

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(4) ~~Goodwill and~~ Intangible Assets

~~Goodwill~~

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The fair value of goodwill is based on inputs that are not observable in the market and thus represent Level 3 inputs. We evaluate goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.

We perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples and estimated future cash flows, including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among other factors. Impairment determinations involve significant assumptions and judgments, and differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.

During February 2016, we determined that weakness in the overall energy sector, driven by low commodity prices, together with a decline in our unit price, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units. Based on this analysis, a goodwill impairment loss for our Texas, Crude and Condensate, and Corporate reporting units in the amount of $873.3 million was recognized in the first quarter of 2016 and is included as an impairment loss on the consolidated statement of operations for the nine months ended September 30, 2016. We concluded that the fair value of our Oklahoma reporting unit exceeded its carrying value, and the amount of goodwill disclosed on the consolidated balance sheet associated with this reporting unit is recoverable. Therefore, no goodwill impairment was identified or recorded for this reporting unit as a result of our goodwill impairment analysis.

During the first quarter of 2017, we elected to early adopt ASU 2017-04, which simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in ASC 350. Although no goodwill impairment tests were required during the nine months ended September 30, 2017, we will perform future goodwill impairment tests according to ASU 2017-04. For additional information, see “Note 2—Significant Accounting Policies.”

~~Intangible Assets~~

Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which ~~range~~ranged from ~~ten~~10 to ~~twenty~~20 years at the time the intangible assets were originally recorded. The weighted average amortization period for intangible assets is 14.9 years.

The following table represents our change in carrying value of intangible assets (in millions):


	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
Nine Months Ended September 30, 2022
Customer relationships, beginning of period	$	1,844.8	$	(795.1)	$	1,049.7
Amortization expense	—		(96.6)		(96.6)

Customer relationships, end of period	$	1,844.8	$	(891.7)	$	953.1

Gross Carrying Amount Accumulated Amortization Net Carrying Amount
Nine Months Ended September 30, 2017
Customer relationships, beginning of period $ 1,795.8
$ (171.6 ) $ 1,624.2
Amortization expense —
(96.2 ) (96.2 )
Customer relationships, end of period $ 1,795.8
$ (267.8 ) $ 1,528.0

~~The weighted average amortization period is 15.0 years.~~ Amortization expense was ~~approximately $31.2~~$31.9 million ~~and $29.9 million~~ for each of the three months ended September 30, ~~2017~~2022 and ~~2016, respectively,~~2021, and ~~$96.2~~$96.6 million and ~~$87.4~~$94.4 million for the nine months ended September 30, ~~2017~~2022 and ~~2016,~~2021, respectively.

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions):


2022 (remaining)	$	31.8
2023	127.6
2024	127.6
2025	110.2
2026	106.3
Thereafter	449.6

Total	$	953.1

2017 (remaining) $ 30.8
2018 123.4
2019 123.4
2020 123.4
2021 123.4
Thereafter 1,003.6
Total $ 1,528.0

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(5) Related Party Transactions

~~We engage in various transactions~~(a) Transactions with ~~Devon Energy Corporation (“Devon”) and other related parties.~~ Cedar Cove JV

For the three and nine months ended September 30, ~~2017, Devon accounted for 15.0%~~2022, we recorded cost of sales of $5.6 million and ~~15.4% of our revenues,~~$25.3 million, respectively, and for the three and nine months ended September 30, ~~2016, Devon accounted for 18.9%~~2021, we recorded cost of sales of $4.9 million and ~~19.4%~~$11.7 million, respectively, related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at our ~~revenues, respectively. We~~Central Oklahoma processing facilities. Additionally, we had an accounts ~~receivable balance~~payable balances related to transactions with ~~Devon~~the Cedar Cove JV of ~~$121.5~~$4.3 million and $1.6 million at September 30, ~~2017~~2022 and ~~$100.2 million at~~ December 31, ~~2016. Additionally,~~2021, respectively.

(b) Transactions with GIP

General and Administrative Expenses. For the nine months ended September 30, 2021, we ~~had an accounts payable balance~~recorded general and administrative expenses of $0.2 million related to personnel secondment services provided by GIP. We did not record any expenses related to transactions with ~~Devon of $36.8 million at~~GIP for the three months ended September 30, ~~2017~~2021 and ~~$10.4 million at December 31, 2016.~~ for the three and nine months ended September 30, 2022.

GIP Repurchase Agreement. On February 15, 2022, we and GIP entered into an agreement pursuant to which we are repurchasing, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in any quarter is calculated such that GIP’s then-existing economic ownership percentage of our outstanding common units is maintained after our repurchases of common units from public unitholders are taken into account, and the per unit price we pay to GIP is the average per unit price paid by us for the common units repurchased from public unitholders. See “Note 9—Members’ Equity” for additional information on the activity relating to the GIP repurchase agreement.

Management believes ~~these~~the foregoing transactions ~~are~~with related parties were executed on terms that are fair and reasonable ~~and are consistent with terms for transactions with unrelated third parties.~~to us. The amounts related to related party transactions are specified in the accompanying consolidated financial statements.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(6) Long-Term Debt

As of September 30, ~~2017~~2022 and December 31, ~~2016,~~2021, long-term debt consisted of the following (in millions):


	September 30, 2022						December 31, 2021
	Outstanding Principal		Premium (Discount)		Long-Term Debt		Outstanding Principal		Premium (Discount)		Long-Term Debt

Revolving Credit Facility due 2027 (1)	$	70.0	$	—	$	70.0	$	15.0	$	—	$	15.0
AR Facility due 2025 (2)	500.0		—		500.0		350.0		—		350.0
ENLK’s 4.40% Senior unsecured notes due 2024	97.9		—		97.9		521.8		0.7		522.5
ENLK’s 4.15% Senior unsecured notes due 2025	421.6		(0.2)		421.4		720.8		(0.4)		720.4
ENLK’s 4.85% Senior unsecured notes due 2026	491.0		(0.3)		490.7		491.0		(0.3)		490.7
ENLC’s 5.625% Senior unsecured notes due 2028	500.0		—		500.0		500.0		—		500.0
ENLC’s 5.375% Senior unsecured notes due 2029	498.7		—		498.7		498.7		—		498.7
ENLC’s 6.50% Senior unsecured notes due 2030	700.0		—		700.0		—		—		—
ENLK’s 5.60% Senior unsecured notes due 2044	350.0		(0.2)		349.8		350.0		(0.2)		349.8
ENLK’s 5.05% Senior unsecured notes due 2045	450.0		(5.2)		444.8		450.0		(5.5)		444.5
ENLK’s 5.45% Senior unsecured notes due 2047	500.0		(0.1)		499.9		500.0		(0.1)		499.9
Debt classified as long-term	$	4,579.2	$	(6.0)	4,573.2		$	4,397.3	$	(5.8)	4,391.5
Debt issuance cost (3)					(35.8)						(27.8)

Long-term debt, net of unamortized issuance cost					$	4,537.4					$	4,363.7

September 30, 2017 December 31, 2016
Outstanding Principal Premium (Discount) Long-Term Debt Outstanding Principal Premium (Discount) Long-Term Debt
ENLK credit facility due 2020 (1) $ —
$ —
$ —
$ 120.0
$ —
$ 120.0
ENLC credit facility due 2019 (2) 74.0
—
74.0
27.8
—
27.8
2.70% Senior unsecured notes due 2019 400.0
(0.2 ) 399.8
400.0
(0.3 ) 399.7
7.125% Senior unsecured notes due 2022 —
—
—
162.5
16.0
178.5
4.40% Senior unsecured notes due 2024 550.0
2.3
552.3
550.0
2.5
552.5
4.15% Senior unsecured notes due 2025 750.0
(1.0 ) 749.0
750.0
(1.1 ) 748.9
4.85% Senior unsecured notes due 2026 500.0
(0.6 ) 499.4
500.0
(0.7 ) 499.3
5.60% Senior unsecured notes due 2044 350.0
(0.2 ) 349.8
350.0
(0.2 ) 349.8
5.05% Senior unsecured notes due 2045 450.0
(6.5 ) 443.5
450.0
(6.6 ) 443.4
5.45% Senior unsecured notes due 2047 500.0
(0.1 ) 499.9
—
—
—
Debt classified as long-term $ 3,574.0
$ (6.3 ) $ 3,567.7
$ 3,310.3
$ 9.6
$ 3,319.9
Debt issuance cost (3) (27.2 ) (24.6 )
Long-term debt, net of unamortized issuance cost $ 3,540.5
$ 3,295.3
____________________________


~~(1)~~	~~Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was2.3%~~at~~December 31, 2016~~.


~~(2)~~	~~Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was~~ ~~3.2% and 3.4% at September 30, 2017 and December 31, 2016, respectively.~~


~~(3)~~	~~Net of amortization of~~ ~~$11.9 million~~ ~~and~~ ~~$9.0 million~~ at ~~September 30, 2017~~ ~~and~~ ~~December 31, 2016, respectively.~~

(1)The effective interest rate was 6.9% and 3.9% at September 30, 2022 and December 31, 2021, respectively.

~~ENLC~~(2)The effective interest rate was 4.0% and 1.2% at September 30, 2022 and December 31, 2021, respectively.

(3)Net of accumulated amortization of $13.4 million and $18.4 million at September 30, 2022 and December 31, 2021, respectively.

Revolving Credit Facility

~~We have a $250.0 million~~On June 3, 2022, we amended and restated our prior revolving credit facility by entering into the Revolving Credit Facility. As a result, we recognized a $0.5 million loss on extinguishment of debt. The Revolving Credit Facility amended our prior revolving credit facility by, among other things, (i) decreasing the lenders’ commitments under the Revolving Credit Facility from $1.75 billion to $1.40 billion, (ii) modifying the leverage ratio financial covenant calculation to net from the funded indebtedness numerator the lesser of (a) consolidated unrestricted cash of ENLC and (b) $50.0 million, (iii) removing the consolidated interest coverage ratio financial covenant, (iv) extending the maturity date from January 25, 2024 to June 3, 2027, (v) replacing the ability of ENLC to elect that ~~matures~~borrowings accrue interest at LIBOR, plus a margin, with the ability of ENLC to elect that borrowings accrue interest at a forward-looking term rate based on ~~March 7, 2019~~SOFR (“Term SOFR”), plus a margin and ~~includes~~ a ~~$125.0~~Term SOFR spread adjustment, (vi) increasing the size of a permitted receivables financing to $500.0 million ~~letter~~from $350.0 million, and (vii) permitting, but not requiring, the establishment by ENLC (subject to approval by Bank of America, N.A., as administrative agent, and lenders holding a majority of the revolving commitments) of specified key performance indicators with respect to environmental, social, and/or governance targets that may result in a pricing increase or decrease under the Revolving Credit Facility of up to 0.05% per annum for the margin on borrowings and letters of credit ~~subfacility (the “ENLC Credit Facility”). Our obligations~~and 0.02% per annum for the commitment fees.

Borrowings under the ~~ENLC~~Revolving Credit Facility ~~are guaranteed~~bear interest at ENLC’s options at Term SOFR plus a Term SOFR spread adjustment of 0.10% per annum (“Adjusted Term SOFR”) and an applicable margin (ranging from 1.125% to 2.00%) or the Base Rate (the highest of the federal funds rate plus 0.50%, Adjusted Term SOFR plus 1.0% or the administrative agent's prime rate) plus an applicable margin (ranging from 0.125% to 1.00%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ~~two~~ENLC of ~~our wholly-owned subsidiaries~~certain covenants governing the Revolving Credit Facility, amounts outstanding under the Revolving Credit Facility, if any, may become due and ~~secured by first priority liens on (i) 88,528,451 ENLK common units~~payable immediately.

There were $70.0 million in outstanding borrowings and $46.6 million in outstanding letters of credit under the ~~100% membership~~Revolving Credit Facility as of September 30, 2022.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us and (iii) any additional equity interests subsequently pledged as collateral under the ENLC Credit Facility.

The ENLC Credit Facility contains certain financial, operational and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter, and include (i) maintaining a maximum consolidated leverage ratio (as defined in the ENLC Credit Facility, but generally computed as the ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the ENLC Credit Facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the ENLC Credit Facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) of 2.50 to 1.00 unless an investment grade event (as defined in the ENLC Credit Facility) occurs.

Borrowings under the ENLC Credit Facility bear interest at our option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.75% to 2.50%) or the Base Rate (the highest of the Federal Funds Rate plus 0.5%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from 0.75% to 1.50%). The applicable margins vary depending on our leverage ratio. Upon breach by us of certain covenants governing the ENLC Credit Facility, amounts outstanding under the ENLC Credit Facility, if any, may become due and payable immediately and the liens securing the ENLC Credit Facility could be foreclosed upon. At September 30, ~~2017, ENLC was~~2022, we were in compliance with and ~~expects~~expect to be in compliance with the financial covenants inof the ~~ENLC~~Revolving Credit Facility for at least the next twelve months.

AR Facility

On October 21, 2020, EnLink Midstream Funding, LLC, a bankruptcy-remote special purpose entity that is an indirect subsidiary of ENLC (the “SPV”) entered into the AR Facility. We are the primary beneficiary of the SPV, and we consolidate its assets and liabilities, which consisted primarily of billed and unbilled accounts receivable of $882.4 million as of September 30, 2022.

On August 1, 2022, we amended certain terms of the AR Facility to, among other things, increase the commitments thereunder from $350.0 million to $500.0 million and extend the scheduled termination date from September 24, 2024 to August 1, 2025. As of September 30, ~~2017,~~2022, the AR Facility had a borrowing base of $500.0 million and there were ~~no outstanding letters of credit and $74.0~~$500.0 million in outstanding borrowings under the ~~ENLC Credit Facility, leaving approximately $176.0 million available for future borrowing based on the borrowing capacity of $250.0 million.~~AR Facility.

~~ENLK Credit Facility~~

ENLK has a $1.5 billion unsecured revolving credit facility that matures on March 6, 2020 (the “ENLK Credit Facility”), which includes a $500.0 million letter of credit subfacility. Under the ENLK Credit Facility, ENLK is permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under the ENLK Credit Facility by an additional amount not to exceed $500.0 million and (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of the ENLK Credit Facility by one year on each occasion. The ENLK Credit Facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (which is defined in the ENLK Credit Facility and includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If ENLK consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLK can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

Borrowings under the ENLK Credit Facility bear interest at ENLK’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.00% to 1.75%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin (ranging from zero percent to 0.75%). The applicable margins vary depending on ENLK’s credit rating. If ENLK breaches certain covenants governing the ENLK Credit Facility, amounts outstanding under the ENLK Credit Facility, if any, may become due and payable immediately. At September 30, ~~2017, ENLK was~~2022, we were in compliance with and ~~expects~~expect to be in compliance with the financial covenants inof the ~~ENLK Credit~~AR Facility for at least the next twelve months.

AsIssuances and Repurchases of Senior Unsecured Notes

On August 31, 2022, ENLC completed the sale of $700.0 million in aggregate principal amount of ENLC’s 6.50% senior unsecured notes due September 1, 2030 (the “2030 Notes”) at 100% of their face value. Interest on the 2030 Notes will be payable on March 1 and September 1 of each year beginning on March 1, 2023, until their maturity on September 1, 2030. The 2030 Notes are fully and unconditionally guaranteed by ENLK. We used the net proceeds of approximately $693.0 million and available cash to settle ENLK’s debt tender offer to repurchase $700.0 million in aggregate principal amount of its senior unsecured notes. The repurchased notes consisted of $404.4 million of outstanding aggregate principal amount of ENLK’s 4.40% senior unsecured notes due 2024 (the “2024 Notes”) and $295.6 million of outstanding aggregate principal amount of ENLK’s 4.15% senior unsecured notes due 2025 (the “2025 Notes”). Total consideration for the repurchased 2024 Notes and the 2025 Notes was $715.8 million, including $21.0 million of debt tender premium.

Activity related to the repurchases of ENLK’s senior unsecured notes from the settled debt tender offer consisted of the following (in millions):


	Three and Nine Months Ended September 30, 2022
Debt repurchased	$	700.0
Aggregate payments	(715.8)
Net discount on repurchased debt	(1.0)
Accrued interest on repurchased debt	10.5
Loss on extinguishment of debt	$	(6.3)

Additionally, for the three and nine months ended September 30, ~~2017, there were $9.2 million in outstanding letters of credit and no outstanding borrowings under the ENLK Credit Facility, leaving approximately $1.5 billion available for future borrowing.~~

~~All other material terms and conditions~~2022, we repurchased a portion of the ~~ENLK Credit Facility are described~~outstanding 2024 Notes and 2025 Notes in ~~Part II, “Item 8. Financial Statements~~open market transactions. We did not repurchase any senior unsecured notes in open market transactions during the three and ~~Supplementary Data—Note 6”~~nine months ended September 30, 2021.

Activity related to the repurchases of ENLK’s senior unsecured notes in ~~our Annual Report on Form 10-K for~~open market transactions consisted of the ~~year ended December 31, 2016.~~following (in millions):


	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
Debt repurchased	$	21.1	$	23.1
Aggregate payments	(20.7)		(22.7)

Accrued interest on repurchased debt	0.2		0.2
Gain on extinguishment of debt	$	0.6	$	0.6

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~Senior Unsecured Notes due 2047~~

On May 11, 2017, ENLK issued $500.0 million in aggregate principal amount of ENLK’s 5.450% senior unsecured notes due June 1, 2047 (the “2047 Notes”) at a price to the public of 99.981% of their face value. Interest payments on the 2047 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2017. Net proceeds of approximately $495.2 million were used to repay outstanding borrowings under the ENLK Credit Facility and for general partnership purposes.

~~Redemption of Senior Unsecured Notes due 2022~~

On June 1, 2017, ENLK redeemed $162.5 million in aggregate principal amount of ENLK’s 7.125% senior unsecured notes (the “2022 Notes”) at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174.1 million, which resulted in a gain on extinguishment of debt of $9.0 million for the nine months ended September 30, 2017.

(7) Income Taxes

~~Income taxes included on the consolidated financial statements were~~The components of our income tax expense are as follows ~~for the periods presented~~ (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Current income tax expense	$	(0.3)	$	(0.1)	$	(1.0)	$	(0.2)
Deferred income tax expense	(14.9)		(4.3)		(16.1)		(12.2)
Income tax expense	$	(15.2)	$	(4.4)	$	(17.1)	$	(12.4)

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
ENLC income tax expense $ 3.1
$ 7.6
$ 9.3
$ 6.0
Total income tax expense $ 3.1
$ 7.6
$ 9.3
$ 6.0

The following schedule reconciles ~~total~~ income tax expense ~~(benefit)~~ and the amount calculated by applying the statutory U.S. federal tax rate to income before non-controlling interest and income taxes (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Expected income tax benefit (expense) based on federal statutory rate	$	(20.0)	$	(2.0)	$	(45.9)	$	4.2
State income tax benefit (expense), net of federal benefit	(2.6)		(0.3)		(6.2)		0.5
Unit-based compensation (1)	1.4		(0.2)		(0.6)		(3.1)

Change in valuation allowance	10.9		(1.6)		39.0		(3.8)
Oklahoma statutory rate change (2)	—		—		—		(7.6)
Other	(4.9)		(0.3)		(3.4)		(2.6)
Income tax expense	$	(15.2)	$	(4.4)	$	(17.1)	$	(12.4)

____________________________

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Tax expense (benefit) at statutory federal rate (35%) $ 3.3
$ 2.0
$ 6.8
$ (158.0 )
State income taxes expense (benefit), net of federal tax benefit 0.2
3.1
0.5
(11.8 )
Income tax expense from partnership 0.5
2.6
0.7
1.3
Unit-based compensation (1) —
—
2.3
—
Non-deductible expense related to asset impairment —
(0.1 ) —
173.8
Other (0.9 ) —
(1.0 ) 0.7
Total income tax expense $ 3.1
$ 7.6
$ 9.3
$ 6.0
(1)Related to book-to-tax differences recorded upon the vesting of restricted incentive units.


~~(1)~~	~~Related~~ ~~to tax deficiencies recorded on vested units, which were recognized in accordance with the adoption of ASU 2016-09.~~

(2)Oklahoma House Bill 2960 resulted in a change in the corporate income tax rate from 6% to 4%. Accordingly, we recorded deferred tax expense in the amount of $7.6 million for the nine months ended September 30, 2021 due to a remeasurement of deferred tax assets.

~~(8) Certain Provisions~~Deferred Tax Assets and Liabilities

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The deferred tax liabilities, net of deferred tax assets, are included in “Deferred tax liability, net” in the consolidated balance sheets. As of September 30, 2022, we had $153.6 million of deferred tax liabilities, net of $553.2 million of deferred tax assets, which included a $112.6 million valuation allowance. As of December 31, 2021, we had $137.5 million of deferred tax liabilities, net of $481.6 million of deferred tax assets, which included a $151.6 million valuation allowance.

A valuation allowance is established to reduce deferred tax assets if all, or some portion, of such assets will more than likely not be realized. We have established a valuation allowance primarily related to federal and state tax operating loss carryforwards for which we do not believe a tax benefit is more likely than not to be realized. As of September 30, 2022, management believes it is more likely than not that the Company will realize the benefits of the ~~Partnership Agreement~~deferred tax assets, net of valuation allowance.


~~(a)~~	~~Issuance of ENLK Common Units~~

In November 2014, ENLK entered into an Equity Distribution Agreement (the “2014 EDA”) with BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC to sell up to $350.0 million in aggregate gross sales of ENLK common units from time to time through an “at the market” equity offering program.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

In August 2017, ENLK ceased trading under the 2014 EDA and entered into an Equity Distribution Agreement (the “2017 EDA”) with UBS Securities LLC, Barclays Capital Inc., BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC (collectively, the “Sales Agents”) to sell up to $600.0 million in aggregate gross sales of ENLK common units from time to time through an “at the market” equity offering program. ENLK may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. ENLK has no obligation to sell any(8) Certain Provisions of the ~~common units under the 2017 EDA and may at any time suspend solicitation and offers under the 2017 EDA.~~ENLK Partnership Agreement

For the nine months ended September 30, 2017, ENLK sold an aggregate of approximately 5.3 million common units under the 2014 EDA and 2017 EDA, generating proceeds of approximately $92.3 million (net of approximately $0.9 million of commissions and $0.2 million of registration fees). ENLK used the net proceeds for general partnership purposes. a.Series B Preferred Units

As of September 30, ~~2017, approximately $580.1 million remains available to be issued under the 2017 EDA.~~

~~(b) ENLK~~2022 and December 31, 2021, there were 54,168,359 and 57,501,693 Series B Preferred Units issued and outstanding, respectively.

In January ~~2016, ENLK issued an aggregate of 50,000,000~~2022, we redeemed 3,333,334 Series B Preferred Units ~~representing ENLK limited partner interests to Enfield Holdings, L.P. (“Enfield”) in~~for total consideration of $50.5 million plus accrued distributions. In addition, upon such redemption, a ~~private placement for a cash purchase~~corresponding number of ENLC Class C Common Units were automatically cancelled. The redemption price represents 101% of ~~$15.00 per~~the preferred units’ par value. In connection with the Series B Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the private placement were used to partially fund ENLK’s portion of the purchase price payable in connectionredemption, we have agreed with the acquisition of ENLK’s EnLink Oklahoma T.O. assets. Affiliates of the Goldman Sachs Group, Inc. and affiliates of TPG Global, LLC own interests in the general partner of Enfield. The Series B Preferred Units are convertible into ENLK common units on a one-for-one basis, subject to certain adjustments (a) in full, at ENLK’s option, if the volume weighted average price of a common unit over the 30-trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of ENLK’s general partner or the managing member of ENLC, allholders of the Series B Preferred Units that we will ~~automatically convert into~~pay cash in lieu of making a number of common units equal to the greater of (i) the number of common units into which the Series B Preferred Units would then convert and (ii) the number of Series B Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP.

~~For the quarter ended March 31, 2016~~quarterly PIK distribution through the distribution declared for the fourth quarter ~~ended June 30, 2017, Enfield received a quarterly distribution equal to an annual rate~~ of 8.5% on the Issue Price payable in-kind in the form of additional Series B Preferred Units. For the quarter ended September 30, 2017 and each subsequent quarter, Enfield is entitled to receive a quarterly distribution, subject to certain adjustments, equal to an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Series B Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the Issue Price.2022.

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

A summary of the distribution activity relating to the Series B Preferred Units ~~for~~during the nine months ended September 30, ~~2017~~2022 and ~~2016~~2021 is provided below:


Declaration period	Distribution paid as additional Series B Preferred Units	Cash distribution (in millions)		Date paid/payable
2022
Fourth Quarter of 2021	—	$	19.2	February 11, 2022 (1)
First Quarter of 2022	—	$	17.5	May 13, 2022 (2)
Second Quarter of 2022	—	$	17.3	August 12, 2022
Third Quarter of 2022	—	$	17.3	November 14, 2022

2021
Fourth Quarter of 2020	150,494	$	16.9	February 12, 2021
First Quarter of 2021	150,871	$	17.0	May 14, 2021
Second Quarter of 2021	151,248	$	17.0	August 13, 2021
Third Quarter of 2021	151,626	$	17.1	November 12, 2021

____________________________

Declaration period Distribution paid-in kind (1) Cash Distribution (in millions) Date paid/payable
2017
Fourth Quarter of 2016 1,130,131
$ —
February 13, 2017
First Quarter of 2017 1,154,147
$ —
May 12, 2017
Second Quarter of 2017 1,178,672
$ —
August 11, 2017
Third Quarter of 2017 410,681
$ 15.9
November 13, 2017

2016
First Quarter of 2016 992,445
$ —
May 12, 2016
Second Quarter of 2016 1,083,589
$ —
August 11, 2016
Third Quarter of 2016 1,106,616
$ —
November 10, 2016
(1)In December 2021 and January 2022, we paid $0.9 million and $1.0 million, respectively, of accrued distributions related to the fourth quarter of 2021 on redeemed Series B Preferred Units. The remaining distribution of $17.3 million related to the fourth quarter of 2021 was paid on February 11, 2022.


~~(1)~~	~~Represents distributions paid or payable on the Series B Preferred Units through issuance of additional Series B Preferred Units.~~


~~(c)~~	~~Issuance of ENLK Series C Preferred Units~~

(2)In January 2022, we paid $0.3 million of accrued distributions related to the first quarter of 2022 on redeemed Series B Preferred Units. The remaining distribution of $17.2 million related to the first quarter of 2022 was paid on May 13, 2022.

~~In September 2017, ENLK issued 400,000~~

b.Series C ~~Fixed-to-Floating Rate Cumulative Redeemable Perpetual~~ Preferred Units ~~(the “Series C Preferred Units”) representing ENLK limited partner interests at a price to the public~~

As of ~~$1,000 per unit. ENLK used the net proceeds of $393.7 million for capital expenditures, general partnership purposes~~September 30, 2022 and ~~to repay borrowings under the ENLK Credit Facility. The~~December 31, 2021, there were 400,000 Series C Preferred Units ~~represent perpetual equity interests in~~issued and outstanding, respectively. ENLK ~~and, unlike ENLK indebtedness, will not give rise~~distributed$12.0 million to ~~a claim for payment~~holders of ~~a principal amount at a particular date. As to the payment of distributions and amounts payable on a liquidation event, the~~ Series C Preferred Units ~~rank senior to ENLK’s common units~~during the nine months ended September 30, 2022 and to each other class of limited partner interests or other equity securities established after the issue date of the Series C Preferred Units that is not expressly made senior or on parity with the Series C Preferred Units. The Series C Preferred Units will rank junior to the Series B Preferred Units with respect to the payment of distributions, and junior to the Series B Preferred Units and all current and future indebtedness with respect to amounts payable upon a liquidation event. Income is allocated2021, respectively. There was no distribution activity related to the Series C Preferred Units ~~in an amount equal to~~during the ~~earned distributions for the respective reporting period.~~

At any time on or after December 15, 2022, ENLK may redeem, at ENLK’s option, in whole or in part, the Series C Preferred Units at a redemption price in cash equal to $1,000 per Series C Preferred Unit plus an amount equal to all accumulated and unpaid distributions, whether or not declared. ENLK may undertake multiple partial redemptions. In addition, at any time within 120 days after the conclusion of any review or appeal process instituted by ENLK following certain rating agency events, ENLK may redeem, at ENLK’s option, the Series C Preferred Units in whole at a redemption price in cash per unit equal to $1,020 plus an amount equal to all accumulated and unpaid distributions, whether or not declared.

~~Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15~~^th ~~day of June and December of each year through and including December 15,~~three months ended September 30, 2022 and ~~thereafter, quarterly in arrears on the 15~~^th day of March, June, September and December of each year, in each case, if and when declared by ENLK’s general partner out of legally available funds for such purpose. The initial distribution rate for the Series C Preferred Units from and including the date of original issue to, but not including, December 15, 2022 is 6.0% per annum. On and after December 15, 2022, distributions on the Series C Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to an annual floating rate of the three-month LIBOR plus a spread of 4.11%.2021.


~~(d)~~	~~ENLK Common Unit Distributions~~

Unless restricted by the terms of the ENLK Credit Facility and/or the indentures governing ENLK’s unsecured senior notes, ENLK must make distributions of 100% of available cash, as defined in its partnership agreement, within 45 days following the end of each quarter. Distributions are made to the General Partner in accordance with its current percentage interest with the remainder to the common unitholders, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. The General Partner is not entitled to incentive

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(9) Members’ Equity

~~distributions with respect~~

a.Common Unit Repurchase Program

In November 2020, the board of directors of the Managing Member (the “Board”) authorized a common unit repurchase program for the repurchase of up to ~~(i) distributions on the ENLK Series B Preferred Units until such units convert into~~$100.0 million of outstanding ENLC common units and reauthorized such program in April 2021. The Board reauthorized ENLC’s common unit repurchase program and reset the amount available for repurchases of outstanding common units at up to $100.0 million effective January 1, 2022. In July 2022, the Board increased the amount available for repurchases to $200.0 million. Repurchases under the common unit repurchase program will be made, in accordance with applicable securities laws, from time to time in open market or ~~(ii)~~private transactions and may be made pursuant to a trading plan meeting the ~~Series C Preferred Units.~~requirements of Rule 10b5-1 under the Exchange Act. The repurchases will depend on market conditions and may be discontinued at any time.

On February 15, 2022, we and GIP entered into an agreement pursuant to which we agreed to repurchase, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the preceding quarter from public unitholders under our common unit repurchase program. See “Note 5—Related Party Transactions” for additional information on our ENLC common unit repurchase agreement with GIP.

The ~~General Partner owns~~following table summarizes our ENLC common unit repurchase activity for the ~~general partner interest in ENLK~~three and all of its incentive distribution rights. The General Partner is entitled to receive incentive distributions if the amount ENLK distributes with respect to any quarter exceeds levels specified in its partnership agreement. Under the quarterly incentive distribution provisions, the General Partner is entitled to 13.0% of amounts ENLK distributes in excess of $0.25 per unit, 23.0% of the amounts ENLK distributes in excess of $0.3125 per unit and 48.0% of amounts ENLK distributes in excess of $0.375 per unit.

~~A summary of ENLK’s distribution activity relating to the common units for the~~ nine months ended September 30, ~~2017~~2022 and ~~2016 is provided below:~~2021 (in millions, except for unit amounts):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Publicly held ENLC common units	4,051,626		2,076,545		9,066,838		2,394,296
ENLC common units held by GIP (1)	2,530,507		—		3,205,602		—
Total ENLC common units	6,582,133		2,076,545		12,272,440		2,394,296

Aggregate cost for publicly held ENLC common units	$	38.5	$	12.5	$	83.2	$	14.5
Aggregate cost for ENLC common units held by GIP	24.0		—		30.0		—
Total aggregate cost for ENLC common units	$	62.5	$	12.5	$	113.2	$	14.5

Average price paid per publicly held ENLC common unit	$	9.49	$	6.02	$	9.18	$	6.05
Average price paid per ENLC common unit held by GIP (2)	$	9.47	$	—	$	9.35	$	—

Declaration period Distribution/unit Date paid/payable
2017
Fourth Quarter of 2016 $ 0.39
February 13, 2017
First Quarter of 2017 $ 0.39
May 12, 2017
Second Quarter of 2017 $ 0.39
August 11, 2017
Third Quarter of 2017 $ 0.39
November 13, 2017

2016
Fourth Quarter of 2015 $ 0.39
February 11, 2016
First Quarter of 2016 $ 0.39
May 12, 2016
Second Quarter of 2016 $ 0.39
August 11, 2016
Third Quarter of 2016 $ 0.39
November 11, 2016
____________________________


~~(e)~~	~~Allocation of ENLK Income~~

(1)For the three and nine months ended September 30, 2022, the units represent GIP’s pro rata share of the aggregate number of common units repurchased by us under our common unit repurchase program during the third quarter and the period from February 15, 2022 (the date on which the Repurchase Agreement was signed) through June 30, 2022, respectively.

~~Net income is allocated~~(2)For the three and nine months ended September 30, 2022, the per unit price we paid to GIP was the average per unit price paid by us for publicly held ENLC common units repurchased during the third quarter and from February 15, 2022 (the date on which the Repurchase Agreement was signed) through June 30, 2022, respectively, less broker commissions, which were not paid with respect to GIP units.

Additionally, on October 31, 2022, we repurchased 3,538,101 ENLC common units held by GIP at an aggregate cost of $33.5 million, or an average of $9.47 per common unit. These units represent GIP’s pro rata share of the aggregate number of common units repurchased by us during the three months ended September 30, 2022. The per unit price we paid to GIP was the same as the average per unit price paid by us for publicly held ENLC common units repurchased during the same period, less broker commissions, which were not paid with respect to the General Partner in an amount equal to its incentive distribution rights as described in (d) above. The General Partner’s share of net income consists of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of ENLK’s net income adjusted for ENLC’s unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows (in millions):GIP units.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Income allocation for incentive distributions $ 14.8
$ 14.4
$ 44.1
$ 42.4
Unit-based compensation attributable to ENLC’s restricted units (4.2 ) (3.6 ) (16.9 ) (11.2 )
General Partner share of net income (loss) —
—
0.1
(2.4 )
General Partner interest in net income $ 10.6
$ 10.8
$ 27.3
$ 28.8

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(9) Members' Equity~~

~~(a)~~b.Earnings Per Unit and Dilution Computations

As required under ASC 260, Earnings Per Share, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities for earnings per unit calculations. The following table reflects the computation of basic and diluted earnings per ~~limited partner units~~unit for the periods presented (in millions, except per unit amounts):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Distributed earnings allocated to:
Common units (1)	$	53.7	$	45.8	$	162.4	$	137.7
Unvested restricted units (1)	1.4		1.0		3.9		3.2
Total distributed earnings	$	55.1	$	46.8	$	166.3	$	140.9
Undistributed income (loss) allocated to:
Common units	$	25.1	$	(43.9)	$	34.2	$	(169.3)
Unvested restricted units	0.6		(1.0)		0.8		(4.0)
Total undistributed income (loss)	$	25.7	$	(44.9)	$	35.0	$	(173.3)
Net income (loss) attributable to ENLC allocated to:
Common units	$	78.8	$	1.9	$	196.6	$	(31.6)
Unvested restricted units	2.0		—		4.7		(0.8)
Total net income (loss) attributable to ENLC	$	80.8	$	1.9	$	201.3	$	(32.4)
Net income (loss) attributable to ENLC per unit:
Basic	$	0.17	$	—	$	0.42	$	(0.07)
Diluted	$	0.17	$	—	$	0.41	$	(0.07)

____________________________

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
EnLink Midstream, LLC interest in net income (loss) $ 6.2
$ 0.7
$ 10.2
$ (456.1 )
Distributed earnings allocated to:
Common units (1) (2) $ 46.0
$ 45.9
$ 138.0
$ 137.4
Unvested restricted units (1) (2) 0.7
0.6
1.9
1.6
Total distributed earnings $ 46.7
$ 46.5
$ 139.9
$ 139.0
Undistributed loss allocated to:
Common units $ (39.9 ) $ (45.1 ) $ (128.0 ) $ (588.3 )
Unvested restricted units (0.6 ) (0.7 ) (1.7 ) (6.8 )
Total undistributed loss $ (40.5 ) $ (45.8 ) $ (129.7 ) $ (595.1 )
Net income (loss) allocated to:
Common units $ 6.1
$ 0.8
$ 10.0
$ (450.9 )
Unvested restricted units 0.1
(0.1 ) 0.2
(5.2 )
Total net income (loss) $ 6.2
$ 0.7
$ 10.2
$ (456.1 )
Basic and diluted net income (loss) per unit:
Basic $ 0.03
$ —
$ 0.06
$ (2.54 )
Diluted $ 0.03
$ —
$ 0.06
$ (2.54 )
(1)Represents distribution activity consistent with the distribution activity table below.


~~(1)~~	For the three months ended September 30, 2017 and 2016, distributed earnings included a declared distribution of $0.255 per unit payable on November 14, 2017 and a distribution of $0.255 per unit paid on November 14, 2016, respectively.

~~(2)~~

For the nine months ended September 30, 2017, distributed earnings included distributions of $0.255 per unit paid on May 15, 2017 and August 14, 2017 and a declared distribution of $0.255 per unit payable on November 14, 2017. For the nine months ended September 30, 2016, distributed earnings included distributions of $0.255 per unit paid on May 13, 2016, $0.255 per unit paid on August 12, 2016, and $0.255 per unit paid on November 14, 2016.

The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):


	Three Months Ended September 30,		Nine Months Ended September 30,
	2022	2021	2022	2021
Basic weighted average units outstanding:
Weighted average common units outstanding	477.2	488.6	481.0	489.6

Diluted weighted average units outstanding:
Weighted average basic common units outstanding	477.2	488.6	481.0	489.6
Dilutive effect of unvested restricted units (1)	7.2	6.2	6.9	—

Total weighted average diluted common units outstanding	484.4	494.8	487.9	489.6

____________________________

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Basic and diluted earnings per unit:
Weighted average common units outstanding 180.6
180.0
180.4
179.6
Diluted weighted average units outstanding:
Weighted average basic common units outstanding 180.6
180.0
180.4
179.6
Dilutive effect of non-vested restricted incentive units (1) 1.2
1.1
1.3
—
Total weighted average diluted common units outstanding 181.8
181.1
181.7
179.6
(1)All common unit equivalents were antidilutive for the nine months ended September 30, 2021, since a net loss existed for that period.


~~(1)~~	~~For the nine months ended September 30, 2016, all common unit equivalents were antidilutive since a net loss existed for that period.~~

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the ~~periods~~period presented.

~~(b) Distributions~~

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

c.Distributions

A summary of our distribution activity ~~relating~~related to the ENLC common units for the nine months ended September 30, ~~2017~~2022 and ~~2016,~~2021, respectively, is provided below:


Declaration period	Distribution/unit		Date paid/payable
2022
Fourth Quarter of 2021	$	0.1125	February 11, 2022
First Quarter of 2022	$	0.1125	May 13, 2022
Second Quarter of 2022	$	0.1125	August 12, 2022
Third Quarter of 2022	$	0.1125	November 14, 2022

2021
Fourth Quarter of 2020	$	0.09375	February 12, 2021
First Quarter of 2021	$	0.09375	May 14, 2021
Second Quarter of 2021	$	0.09375	August 13, 2021
Third Quarter of 2021	$	0.09375	November 12, 2021

Declaration period Distribution/unit Date paid/payable
2017
Fourth Quarter of 2016 $ 0.255
February 14, 2017
First Quarter of 2017 $ 0.255
May 15, 2017
Second Quarter 2017 $ 0.255
August 14, 2017
Third Quarter 2017 $ 0.255
November 14, 2017

2016
Fourth Quarter of 2015 $ 0.255
February 12, 2016
First Quarter of 2016 $ 0.255
May 13, 2016
Second Quarter 2016 $ 0.255
August 12, 2016
Third Quarter 2016 $ 0.255
November 14, 2016

~~(10) Asset Retirement Obligations~~

~~The schedule below summarizes the changes in our asset retirement obligations (in millions):~~

Nine Months Ended September 30, 2017
Balance, beginning of period $ 13.5
Accretion expense 0.5
Balance, end of period $ 14.0

Asset retirement obligations of $14.0 million and $13.5 million were included in “Asset retirement obligations” as non-current liabilities on the consolidated balance sheets as of September 30, 2017 and December 31, 2016, respectively.

~~(11) Investment in Unconsolidated Affiliates~~

~~Our unconsolidated investments consisted of:~~

~~a contractual right to the economic benefits and burdens associated with Devon’s 38.75% ownership interest in Gulf Coast Fractionators (“GCF”) at September 30, 2017 and December 31, 2016;~~

an approximate 30% ownership in Cedar Cove Midstream LLC (the “Cedar Cove JV”) at September 30, 2017 and December 31, 2016. On November 9, 2016, we formed the Cedar Cove JV with Kinder Morgan, Inc., which consists of gathering and compression assets in Blaine County, Oklahoma, the heart of the Sooner Trend Anadarko Basin Canadian and Kingfisher Counties play; and

~~an approximate 31% common unit ownership interest in Howard Energy Partners (“HEP”) at December 31, 2016, which was sold in March 2017 for aggregate net proceeds of $189.7 million.~~

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(10) Investment in Unconsolidated Affiliates

On May 16, 2022, we formed a joint venture with WhiteWater Midstream, LLC, Devon Energy Corporation, and MPLX LP (the “Matterhorn JV”) to construct a pipeline designed to transport up to 2.5 Bcf/d of natural gas through approximately 490 miles of 42-inch pipeline from the Waha Hub in West Texas to Katy, Texas (the “Matterhorn Express Pipeline”).

As of September 30, 2022, our unconsolidated investments consisted of a 38.75% ownership in GCF, a 30% ownership in the Cedar Cove JV, and a 15% ownership in the Matterhorn JV. The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
GCF
Contributions	$	0.9	$	—	$	1.4	$	—
Distributions	$	—	$	—	$	—	$	(3.5)
Equity in loss	$	(0.8)	$	(1.7)	$	(2.4)	$	(8.1)

Cedar Cove JV

Distributions	$	(0.2)	$	(0.1)	$	(0.6)	$	(0.3)
Equity in loss	$	(0.6)	$	(0.6)	$	(1.3)	$	(1.8)

Matterhorn JV
Contributions	$	18.8	$	—	$	44.9	$	—

Equity in loss	$	(0.3)	$	—	$	(0.3)	$	—

Total
Contributions	$	19.7	$	—	$	46.3	$	—
Distributions	$	(0.2)	$	(0.1)	$	(0.6)	$	(3.8)
Equity in loss	$	(1.7)	$	(2.3)	$	(4.0)	$	(9.9)

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Gulf Coast Fractionators
Contributions $ —
$ —
$ —
$ —
Distributions $ 3.5
$ 0.9
$ 10.6
$ 4.4
Equity in income $ 4.5
$ 2.2
$ 8.5
$ 1.1

Howard Energy Partners
Contributions (1) $ —
$ 3.2
$ —
$ 45.0
Distributions (2) $ —
$ 36.5
$ —
$ 47.9
Equity in loss (3) $ —
$ (1.1 ) $ (3.4 ) $ (1.6 )

Cedar Cove JV
Contributions $ 1.5
$ —
$ 11.8
$ —
Distributions $ 0.5
$ —
$ 0.8
$ —
Equity in loss $ (0.1 ) $ —
$ (0.1 ) $ —

Total
Contributions (1) $ 1.5
$ 3.2
$ 11.8
$ 45.0
Distributions (2) $ 4.0
$ 37.4
$ 11.4
$ 52.3
Equity in income (loss) (3) $ 4.4
$ 1.1
$ 5.0
$ (0.5 )


~~(1)~~	~~Contributions for the~~ ~~three and nine~~ ~~months ended~~ ~~September 30, 2016~~ ~~included~~ ~~$3.2 million~~ ~~and~~ ~~$32.7 million, respectively, of contributions to HEP for preferred units issued by HEP, which were redeemed during the third quarter of 2016.~~


~~(2)~~	~~Distributions for the~~ ~~three and nine~~ ~~months ended~~ ~~September 30, 2016~~ ~~included a redemption of~~ ~~$32.7 million~~ ~~of preferred units issued by HEP.~~


~~(3)~~	~~Includes a loss of$3.4 million for the nine months ended September 30, 2017~~ ~~from the sale of our HEP interests.~~

The following table shows the balances related to our investment in unconsolidated affiliates as of September 30, ~~2017~~2022 and December 31, ~~2016~~2021 (in millions):


	September 30, 2022		December 31, 2021
GCF	$	27.0	$	28.0
Cedar Cove JV (1)	(3.7)		(1.8)
Matterhorn JV	44.6		—
Total investment in unconsolidated affiliates	$	67.9	$	26.2

____________________________

(1)As of September 30, 2022 and December 31, 2021, our investment in the Cedar Cove JV is classified as “Other long-term liabilities” on the consolidated balance sheets.

September 30, 2017 December 31, 2016
Gulf Coast Fractionators $ 46.4
$ 48.5
Howard Energy Partners —
193.1
Cedar Cove JV 39.7
28.8
Total investment in unconsolidated affiliates $ 86.1
$ 270.4

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

~~(12)~~(Unaudited)

(11) Employee Incentive Plans


~~(a)~~	~~Long-Term Incentive Plans~~

~~ENLC and ENLK each have similar unit-based compensation payment plans for officers and employees. ENLC grants unit-based awards under the EnLink Midstream, LLC 2014~~ a.Long-Term Incentive ~~Plan (the “LLC Plan”), and ENLK grants unit-based awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”).~~Plans

We account for unit-based compensation in accordance with ASC 718,~~Stock Compensation~~ ~~(“ASC 718”),~~ which requires that compensation related to all unit-based awards be recognized onin the consolidated financial statements. Unit-based

~~Table~~ compensation cost is valued at fair value at the date of ~~Contents~~

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

~~compensation cost~~grant, and that grant date fair value is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to our officers and employees is recorded by ENLK since ENLC has no substantial or managed operating activities other than its interests in ENLK and EnLink Oklahoma T.O.

Amounts recognized on the consolidated financial statements with respect to these plans are as follows (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Cost of unit-based compensation charged to operating expense	$	1.3	$	1.5	$	4.1	$	4.9
Cost of unit-based compensation charged to general and administrative expense	10.1		4.9		19.6		14.4
Total unit-based compensation expense	$	11.4	$	6.4	$	23.7	$	19.3
Amount of related income tax benefit recognized in net income (1)	$	2.7	$	1.5	$	5.6	$	4.5

____________________________

(1)For the three and nine months ended September 30, 2022, the amount of related income tax benefit recognized in net income excluded $1.4 million of income tax benefit and $0.6 million of income tax expense, respectively, related to book-to-tax differences recorded upon the vesting of restricted units. For the three and nine months ended September 30, 2021, the amount of related income tax benefit recognized in net income excluded $0.2 million and $3.1 million of income tax expense, respectively, related to book-to-tax differences recorded upon the vesting of restricted units.

Three Months Ended September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Cost of unit-based compensation charged to general and administrative expense $ 7.4
$ 5.8
$ 28.5
$ 17.7
Cost of unit-based compensation charged to operating expense 2.8
1.6
10.4
4.8
Total unit-based compensation expense $ 10.2
$ 7.4
$ 38.9
$ 22.5
Non-controlling interest in unit-based compensation $ 3.9
$ 2.7
$ 14.6
$ 8.3
Amount of related income tax benefit recognized in net income (1) $ 2.4
$ 1.7
$ 9.1
$ 5.4


~~(1)~~	~~For the nine months ended September 30, 2017, the amount of related income tax benefit recognized in net income excluded $2.3 million of income tax expense related~~ ~~to tax deficiencies recorded on vested units, which were recognized in accordance with the adoption of ASU 2016-09.~~


~~(b)~~	~~EnLink Midstream Partners, LP Restricted Incentive Units~~

b.ENLC Restricted Incentive Units

~~ENLK~~

ENLC restricted incentive units ~~are~~were valued at their fair value at the date of grant, which is equal to the market value of ~~the~~ENLC common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, ~~2017~~2022 is provided below:


	Nine Months Ended September 30, 2022
ENLC Restricted Incentive Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	7,507,471		$	5.46
Granted (1)	2,461,950		8.83
Vested (1)(2)	(2,198,511)		7.88
Forfeited	(348,431)		7.13
Non-vested, end of period	7,422,479		$	5.78
Aggregate intrinsic value, end of period (in millions)	$	66.0

____________________________

(1)Restricted incentive units typically vest at the end of three years. In March 2022, ENLC granted 193,935 restricted incentive units with a fair value of $1.7 million. These restricted incentives units vested immediately and are included in the restricted incentive units granted and vested line items.

(2)Vested units included 709,189 ENLC common units withheld for payroll taxes paid on behalf of employees.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Nine Months Ended
September 30, 2017
EnLink Midstream Partners, LP Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value
Non-vested, beginning of period 2,024,820
$ 19.05
Granted (1) 859,595
18.41
Vested (1)(2) (851,753 ) 25.90
Forfeited (32,225 ) 16.28
Non-vested, end of period 2,000,437
$ 15.91
Aggregate intrinsic value, end of period (in millions) $ 33.5


~~(1)~~	~~Restricted incentive units typically vest at the end of three years. In March 2017,~~ ~~ENLK~~ ~~granted~~ ~~262,288~~ ~~restricted incentive units with a fair value of~~ ~~$5.1 million~~ ~~to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.~~


~~(2)~~	~~Vested units included~~ ~~273,848~~ ~~units withheld for payroll taxes paid on behalf of employees.~~

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three and nine months ended September 30, ~~2017~~2022 and ~~2016~~2021 is provided below (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
ENLC Restricted Incentive Units:	2022		2021		2022		2021
Aggregate intrinsic value of units vested	$	11.1	$	1.5	$	19.3	$	5.4
Fair value of units vested	$	6.1	$	3.6	$	17.3	$	16.1

Three Months Ended September 30, Nine Months Ended September 30,
EnLink Midstream Partners, LP Restricted Incentive Units: 2017 2016 2017 2016
Aggregate intrinsic value of units vested $ 0.6
$ 0.3
$ 16.3
$ 4.1
Fair value of units vested $ 1.1
$ 0.5
$ 22.1
$ 9.5

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

As of September 30, ~~2017,~~2022, there ~~was $14.6~~were $20.5 million of unrecognized compensation ~~cost~~costs that related to non-vested ~~ENLK~~ENLC restricted incentive units. ~~That cost is~~These costs are expected to be recognized over a weighted-average period of ~~1.7~~1.8 years.


~~(c)~~	~~EnLink Midstream Partners, LP Performance Units~~

~~For the nine months ended September 30, 2017, the General Partner and EnLink Midstream Manager, LLC, our managing member, granted~~c.ENLC Performance Units

ENLC grants performance awards under the ~~GP Plan and the LLC Plan, respectively.~~2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive ~~units~~units) granted thereunder is dependent on the achievement of certain ~~total shareholder return (“TSR”)~~ performance goals ~~relative to the TSR achievement of a peer group of companies (the “Peer Companies”)~~ over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding ENLC and ENLK (collectively, “EnLink”), on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of ENLC’s and ENLK’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of such units ~~range~~ranges from zero to 200% of the units granted depending on the ~~EnLink TSR as compared~~extent to which the ~~TSR of~~related performance goals are achieved over the ~~Peer Companies on the vesting date. The fair value of each~~relevant performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLK’s common units and the designated peer group securities; (iii) an estimated ranking of ENLK among the designated peer group; and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years. The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:period.

EnLink Midstream Partners, LP Performance Units: March 2017
Beginning TSR Price $ 17.55
Risk-free interest rate 1.62 %
Volatility factor 43.94 %
Distribution yield 8.7 %

The following table presents a summary of the performance units:


	Nine Months Ended September 30, 2022
ENLC Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	3,574,827		$	6.40
Granted	1,204,882		11.60
Vested (1)	(1,265,207)		10.94
Forfeited	(147,232)		11.90
Non-vested, end of period	3,367,270		$	6.31
Aggregate intrinsic value, end of period (in millions)	$	29.9

____________________________

Nine Months Ended
September 30, 2017
EnLink Midstream Partners, LP Performance Units: Number of Units Weighted Average Grant-Date Fair Value
Non-vested, beginning of period 408,637
$ 18.27
Granted 176,648
25.73
Forfeited —
—
Non-vested, end of period 585,285
$ 20.52
Aggregate intrinsic value, end of period (in millions) $ 9.8

As of September 30, 2017, there was $5.9 million of unrecognized compensation cost that related to non-vested ENLK performance units. That cost is expected to be recognized over a weighted-average period of 1.9 years.

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~


~~(d)~~	~~EnLink Midstream, LLC Restricted Incentive Units~~

~~ENLC restricted incentive~~(1)Vested units ~~are valued at their fair value at the date of grant, which is equal to the market value of the~~included 676,156 ENLC common units withheld for payroll taxes paid on ~~such date. A summary~~behalf of ~~the restricted incentive unit activity for the nine months ended September 30, 2017 is provided below:~~employees.

Nine Months Ended
September 30, 2017
EnLink Midstream, LLC Restricted Incentive Units: Number of Units Weighted Average Grant-Date Fair Value
Non-vested, beginning of period 1,897,298
$ 19.96
Granted (1) 817,201
19.24
Vested (1)(2) (775,973 ) 28.28
Forfeited (31,636 ) 16.53
Non-vested, end of period 1,906,890
$ 16.32
Aggregate intrinsic value, end of period (in millions) $ 32.9


~~(1)~~	~~Restricted incentive units typically vest at the end of three years. In March 2017,~~ ~~ENLC~~ ~~granted~~ ~~258,606~~ ~~restricted incentive units with a fair value of~~ ~~$5.0 million~~ ~~to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.~~


~~(2)~~	~~Vested units included~~ ~~238,312~~ ~~units withheld for payroll taxes paid on behalf of employees.~~

A summary of the ~~restricted incentive~~performance units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the ~~three and~~ nine months ended September 30, ~~2017~~2022 and ~~2016~~2021 is provided below (in millions):.


										Three Months Ended September 30,				Nine Months Ended September 30,
	Three Months Ended September 30,				Nine Months Ended September 30,
EnLink Midstream, LLC Restricted Incentive Units:	2017		2016		2017		2016
ENLC Performance Units:									ENLC Performance Units:	2022		2021		2022		2021
Aggregate intrinsic value of units vested	$	0.6	$	0.3	$	15.2	$	4.1	Aggregate intrinsic value of units vested	$	10.2	$	—	$	15.8	$	0.6
Fair value of units vested	$	1.1	$	0.6	$	21.9	$	12.4	Fair value of units vested	$	4.5	$	—	$	15.5	$	4.4

As of September 30, ~~2017,~~2022, there ~~was $14.2~~were $12.9 million of unrecognized compensation ~~cost~~costs that related to non-vested ENLC ~~restricted incentive~~performance units. ~~The cost is~~These costs are expected to be recognized over a weighted-average period of ~~1.8~~2.0 years.


~~(e)~~	~~EnLink Midstream, LLC’s Performance Units~~

For the nine months ended September 30, 2017, ENLC granted performance awards under the LLC Plan. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200% of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC’s common units and the designated peer group securities; (iii) an estimated ranking of ENLC among the designated peer group and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:


ENLC Performance Units:	June 2022			March 2022 (1)			January 2021
Grant-date fair value	$	11.71		$	11.90		$	4.70
Beginning TSR price	$	8.54		$	8.83		$	3.71
Risk-free interest rate	3.35		%	2.15		%	0.17		%
Volatility factor	76.00		%	75.00		%	71.00		%

____________________________

EnLink Midstream, LLC Performance Units: March 2017
Beginning TSR Price $ 18.29
Risk-free interest rate 1.62 %
Volatility factor 52.07 %
Distribution yield 5.4 %

~~The following table presents a summary of the performance units:~~

Nine Months Ended
September 30, 2017
EnLink Midstream, LLC Performance Units: Number of Units Weighted Average Grant-Date Fair Value
Non-vested, beginning of period 384,264
$ 19.30
Granted 164,575
28.77
Forfeited —
—
Non-vested, end of period 548,839
$ 22.14
Aggregate intrinsic value, end of period (in millions) $ 9.5

~~As of September 30, 2017, there was $6.0 million of unrecognized compensation cost that related to non-vested~~(1)Excludes certain ENLC performance ~~units. That cost is expected~~units awarded March 1, 2022 with vesting conditions based on performance metrics. The 88,863 ENLC performance units have a grant-date fair value of $8.90 and are scheduled to ~~be recognized over a weighted-average period of 2.0 years.~~vest in February 2023.

~~(13)~~(12) Derivatives

Interest Rate Swaps

~~We periodically enter into~~The components of the unrealized gain on designated cash flow hedge related to changes in the fair value of our interest rate swaps in connection with new debt issuances. During the debt issuance process, we are exposed to variability in future long-term debt interest payments that may result from changes in the benchmark interest rate (commonly the U.S. Treasury yield) prior to the debt being issued. In order to hedge this variability, we enter into interest rate swaps to effectively lock in the benchmark interest rate at the inception of the swap. Prior to 2017, we did not designate interest rate swapswere as ~~hedges and, therefore, included the associated settlement gains and losses as~~follows (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Change in fair value of interest rate swaps	$	—	$	5.0	$	0.1	$	14.5
Tax expense	—		(1.2)		—		(3.4)
Unrealized gain on designated cash flow hedge	$	—	$	3.8	$	0.1	$	11.1

The interest expense, ~~on the consolidated statements of operations.~~

In May 2017, we entered into an interest rate swap in connection with the issuance of the 2047 Notes. In accordance with ASC 815, we designated this swap as a cash flow hedge. Upon settlement of the interest rate swap in May 2017, we recorded the associated $2.2 million settlement loss inrecognized from accumulated other comprehensive loss onfrom the ~~consolidated balance sheets. We will amortize~~monthly settlement of our interest rate swaps and amortization of the ~~settlement loss into interest expense on the~~termination payments, included in our consolidated statements of operations ~~over the term of the 2047 Notes. There was no ineffectiveness related to the hedge. We have no open interest rate swap positions~~were as ~~of September 30, 2017. In addition, the settlement loss is included as an operating cash outflow on the consolidated statements of cash flows.~~follows (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Interest expense	$	—	$	5.0	$	0.1	$	14.6

~~For the three and nine months ended September 30, 2017, we amortized an immaterial amount of the settlement loss into interest expense from accumulated other comprehensive income (loss).~~ We expect to recognize an additional $0.1 million of interest expense out of accumulated other comprehensive ~~income (loss)~~loss over the next twelve months.

In July 2016, we entered into an interest rate swap in connection with ENLK’s issuance of its 4.85% senior unsecured notes due 2026. We did not designate this swap as a cash flow hedge. Upon settlement of the interest rate swap in July 2016, we recorded the associated $0.4 million gain on settlement in other income (expense) in the consolidated statements of operations for the three and nine months ended September 30, 2016.

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

Commodity Swaps

We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations. Commodity swaps are used to manage and hedge price and location risk related to these market exposures. Commodity swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of crude, condensate, natural gas and NGLs. We do not designate commodity swap transactions as cash flow or fair value hedges for hedge accounting treatment under ASC 815. Therefore, changes in the fair value of our derivatives are recorded in revenue in the period incurred. In addition, our risk management policy does not allow us to take speculative positions with our derivative contracts.

We commonly enter into index (float-for-float) or fixed-for-float swaps in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, NGLs and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. They are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate and crude, fixed-for-float swaps are used to protect cash flows against price fluctuations: (1) where we receive a percentage of liquids as a fee for processing third-party gas or where we receive a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation components of our business and (3) where we are mitigating the price risk for product held in inventory or storage.

The components of gain (loss) on derivative activity onin the consolidated statements of operations related to commodity swaps are (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Change in fair value of derivatives	$	18.2	$	(1.2)	$	38.4	$	(32.9)
Realized gain (loss) on derivatives	2.3		(32.4)		(44.6)		(122.3)
Gain (loss) on derivative activity	$	20.5	$	(33.6)	$	(6.2)	$	(155.2)

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Change in fair value of derivatives $ (3.3 ) $ (1.6 ) $ 3.8
$ (16.0 )
Realized gain (loss) on derivatives (2.2 ) 1.1
(4.9 ) 9.4
Loss on derivative activity $ (5.5 ) $ (0.5 ) $ (1.1 ) $ (6.6 )

The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions):


	September 30, 2022		December 31, 2021
Fair value of derivative assets—current	$	76.2	$	22.4
Fair value of derivative assets—long-term	0.7		0.2
Fair value of derivative liabilities—current	(52.2)		(34.9)
Fair value of derivative liabilities—long-term	(0.8)		(2.2)
Net fair value of commodity swaps	$	23.9	$	(14.5)

September 30, 2017 December 31, 2016
Fair value of derivative assets — current $ 4.6
$ 1.3
Fair value of derivative assets — long-term 0.1
—
Fair value of derivative liabilities — current (7.2 ) (7.6 )
Net fair value of derivatives $ (2.5 ) $ (6.3 )

Assets and liabilities related to our derivative contracts are included in the fair value of derivative assets and liabilities, and the change in fair value of these contracts is recorded net as a gain (loss) on derivative activity on the consolidated statements of operations. We estimate the fair value of all of our derivative contracts based upon actively-quoted prices of the underlying commodities.

Set forth below are the summarized notional volumes and fair values of all instruments related to commodity swaps that we held for price risk management purposes and the related physical offsets at September 30, ~~2017~~2022 (in ~~millions)~~millions, except volumes). The remaining term of the contracts extend no later than ~~October 2018.~~January 2024.

September 30, 2022

Commodity

Instruments

Unit

Volume

Net Fair Value

NGL (short contracts)

Swaps

MMgals

(113.0)

24.7

NGL (long contracts)

Swaps

MMgals

7.8

(0.3)

Natural gas (short contracts)

Swaps

MMbtu

(25.5)

9.4

Natural gas (long contracts)

Swaps

MMbtu

20.6

(14.4)

Crude and condensate (short contracts)

Swaps

MMbbls

(2.5)

11.1

Crude and condensate (long contracts)

Swaps

MMbbls

2.2

(6.6)

Total fair value of commodity swaps

23.9

September 30, 2017
Commodity Instruments Unit Volume Fair Value
NGL (short contracts) Swaps Gallons (35.8 ) $ (4.9 )
NGL (long contracts) Swaps Gallons 25.1
1.9
Natural Gas (short contracts) Swaps MMBtu (20.5 ) 1.3
Natural Gas (long contracts) Swaps MMBtu 23.2
(0.7 )
Condensate (short contracts) Swaps MMbbls 0.1
(0.1 )
Total fair value of derivatives $ (2.5 )

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with ~~two types of counterparties,~~ financial institutions ~~and other energy companies,~~ when entering into financial derivatives on commodities. We have entered into Master ~~International Swaps and Derivatives Association Agreements (“ISDAs”)~~ISDAs that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing commodity swap contracts, ~~our~~the maximum loss on our gross receivable position of ~~$4.7~~$76.9 million as of September 30, ~~2017~~2022 would be reduced to ~~$1.7~~$30.3 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

~~(14)~~

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(13) Fair Value Measurements

~~ASC 820,~~ ~~Fair Value Measurements~~Assets and ~~Disclosures~~ (“ASC 820”), sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under ASC 820 is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

ASC 820 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

Our derivative contracts primarily consist of commodity swap contracts, which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly-quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy.

~~Net assets (liabilities)~~liabilities measured at fair value on a recurring basis are summarized below (in millions):


	Level 2
	September 30, 2022		December 31, 2021

Commodity swaps (1)	$	23.9	$	(14.5)

____________________________

Level 2
September 30, 2017 December 31, 2016
Commodity Swaps (1) $ (2.5 ) $ (6.3 )
Total $ (2.5 ) $ (6.3 )
(1) The fair values of commodity swaps represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.


~~(1)~~	The fair values of derivative contracts included in assets or liabilities for risk management activities represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

Fair Value of Financial Instruments

The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):


	September 30, 2022				December 31, 2021
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt (1)	$	4,537.4	$	4,072.5	$	4,363.7	$	4,520.0
Installment payable (2)	$	—	$	—	$	10.0	$	10.0
Contingent consideration (2)	$	4.4	$	4.4	$	6.9	$	6.9

____________________________

September 30, 2017 December 31, 2016
Carrying Value
Fair
Value
Carrying Value
Fair
Value
Long-term debt (1) $ 3,540.5
$ 3,638.7
$ 3,295.3
$ 3,253.6
Installment Payables $ 243.0
$ 243.7
$ 473.2
$ 476.6
Obligations under capital lease $ 4.4
$ 3.7
$ 6.6
$ 6.1
(1)The carrying value of long-term debt is reduced by debt issuance cost, net of accumulated amortization, of $35.8 million and $27.8 million as of September 30, 2022 and December 31, 2021, respectively. The respective fair values do not factor in debt issuance costs.

(2)Consideration for the Amarillo Rattler Acquisition included a $10.0 million installment payable, which was paid on April 30, 2022, and a contingent component capped at $15.0 million and payable, if at all, between 2024 and 2026 based on Diamondback E&P LLC’s drilling activity above historical levels. Estimated fair values were calculated using a discounted cash flow analysis that utilized Level 3 inputs.


~~(1)~~	~~The carrying value of long-term debt is reduced by debt issuance costs of~~ ~~$27.2 million and $24.6 million at September 30, 2017 and December 31, 2016,~~ ~~respectively. The respective fair values do not factor in debt issuance costs.~~

The carrying amounts of our cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

ENLK had no outstanding borrowings under the ENLK Credit Facility as of September 30, 2017 and $120.0 million of outstanding borrowings under the ENLK Credit Facility as of December 31, 2016. ENLC had $74.0 million and $27.8 million in outstanding borrowings under the ENLC Credit Facility as of September 30, 2017 and December 31, 2016, respectively. As borrowings under the credit facilities accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facilities. As of September 30, 2017 and December 31, 2016, ENLK had total borrowings under senior unsecured notes of $3.5 billion and $3.1 billion, respectively, maturing between 2019 and 2047 with fixed interest rates ranging from 2.7% to 5.6% and 2.7% to 7.1%, respectively. The fair values of all senior unsecured notes ~~and installment payables~~ as of September 30, ~~2017~~2022 and December 31, ~~2016~~2021 were based on Level 2 inputs from third-party market quotations. ~~The fair values of obligations under capital leases were calculated using Level 2 inputs from third-party banks.~~

~~(15) Commitments and Contingencies~~


~~(a)~~	~~Severance and Change in Control Agreements~~

Certain members of our management are parties to severance and change of control agreements with EnLink Midstream Operating, LP. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individuals from, among other things, competing with the General Partner or its affiliates during his or her employment. In addition, the severance and change of control agreements prohibit subject individuals from, among other things, disclosing confidential information about the General Partner or its affiliates or interfering with a client or customer of the General Partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment.


~~(b)~~	~~Environmental Issues~~

The operation of pipelines, plants and other facilities for the gathering, processing, transmitting, stabilizing, fractionating, storing or disposing of natural gas, NGLs, crude oil, condensate, brine and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner, partner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, oil spill prevention, climate change, endangered species and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must account for compliance with environmental laws and regulations and safety standards. Federal, state, or local administrative decisions, developments in the federal or state court systems, or other governmental or judicial actions may influence the interpretation and enforcement of environmental laws and regulations and may thereby increase compliance costs. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(14) Segment Information

We evaluate the financial performance of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian, Louisiana, Oklahoma, and North Texas segments. Identification of the majority of our operating segments is based principally upon geographic regions served:

•Permian Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and our crude oil operations in the Midland and Delaware Basins in West Texas and Eastern New Mexico;

•Louisiana Segment. The Louisiana segment includes our natural gas and NGL pipelines, natural gas processing plants, natural gas and NGL storage facilities, and fractionation facilities located in Louisiana and our crude oil operations in ORV;

•Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, northern Oklahoma Woodford, STACK, and CNOW shale areas;

•North Texas Segment. The North Texas segment includes our natural gas gathering, processing, and transmission activities in North Texas; and

•Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, GCF in South Texas, and the Matterhorn JV in West Texas and our corporate assets and expenses.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

We evaluate the performance of our operating segments based on segment profit and adjusted gross margin. Adjusted gross margin is a non-GAAP financial measure. Summarized financial information ~~compliance with these laws~~for our reportable segments is shown in the following tables (in millions):


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2022
Natural gas sales	$	361.6	$	383.8	$	114.5	$	42.8	$	—	$	902.7
NGL sales	0.2		1,067.4		1.7		1.4		—		1,070.7
Crude oil and condensate sales	280.7		97.0		33.3		—		—		411.0

Product sales	642.5		1,548.2		149.5		44.2		—		2,384.4

NGL sales—related parties	380.3		46.3		203.2		139.7		(769.5)		—
Crude oil and condensate sales—related parties	—		—		—		2.6		(2.6)		—
Product sales—related parties	380.3		46.3		203.2		142.3		(772.1)		—
Gathering and transportation	20.9		22.1		45.9		49.9		—		138.8
Processing	11.1		0.4		31.4		39.5		—		82.4
NGL services	—		19.5		—		0.1		—		19.6
Crude services	5.7		8.1		3.0		0.1		—		16.9
Other services	0.2		0.4		0.2		0.1		—		0.9
Midstream services	37.9		50.5		80.5		89.7		—		258.6




Other services—related parties	—		0.1		—		—		(0.1)		—
Midstream services—related parties	—		0.1		—		—		(0.1)		—
Revenue from contracts with customers	1,060.7		1,645.1		433.2		276.2		(772.2)		2,643.0
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(903.3)		(1,517.8)		(315.3)		(166.9)		772.2		(2,131.1)
Realized gain (loss) on derivatives	1.3		3.3		0.6		(2.9)		—		2.3
Change in fair value of derivatives	2.4		4.0		9.5		2.3		—		18.2
Adjusted gross margin	161.1		134.6		128.0		108.7		—		532.4
Operating expenses	(49.7)		(37.6)		(23.5)		(26.0)		—		(136.8)
Segment profit	111.4		97.0		104.5		82.7		—		395.6
Depreciation and amortization	(36.8)		(39.7)		(51.5)		(33.4)		(1.2)		(162.6)

Gain on disposition of assets	—		0.1		0.1		0.6		—		0.8
General and administrative	—		—		—		—		(34.5)		(34.5)
Interest expense, net of interest income	—		—		—		—		(60.4)		(60.4)
Loss on extinguishment of debt	—		—		—		—		(5.7)		(5.7)
Loss from unconsolidated affiliate investments	—		—		—		—		(1.7)		(1.7)
Other income	—		—		—		—		0.3		0.3
Income (loss) before non-controlling interest and income taxes	$	74.6	$	57.4	$	53.1	$	49.9	$	(103.2)	$	131.8
Capital expenditures	$	61.7	$	6.5	$	18.2	$	6.5	$	1.6	$	94.5

____________________________

(1)Includes related party cost of sales of $5.6 million for the three months ended September 30, 2022.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2021
Natural gas sales	$	159.3	$	183.2	$	58.2	$	32.2	$	—	$	432.9
NGL sales	0.4		898.6		0.3		(0.1)		—		899.2
Crude oil and condensate sales	194.4		62.5		21.2		—		—		278.1

Product sales	354.1		1,144.3		79.7		32.1		—		1,610.2

NGL sales—related parties	301.4		39.5		180.2		131.2		(652.3)		—
Crude oil and condensate sales—related parties	—		—		—		1.5		(1.5)		—
Product sales—related parties	301.4		39.5		180.2		132.7		(653.8)		—
Gathering and transportation	12.8		16.3		44.6		39.0		—		112.7
Processing	7.5		0.9		26.5		27.0		—		61.9
NGL services	—		16.9		—		—		—		16.9
Crude services	5.5		10.3		2.8		0.1		—		18.7
Other services	0.2		0.4		0.1		0.1		—		0.8
Midstream services	26.0		44.8		74.0		66.2		—		211.0



Crude services—related parties	—		—		0.1		—		(0.1)		—
Other services—related parties	—		0.1		—		—		(0.1)		—
Midstream services—related parties	—		0.1		0.1		—		(0.2)		—
Revenue from contracts with customers	681.5		1,228.7		334.0		231.0		(654.0)		1,821.2
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(576.6)		(1,110.8)		(218.0)		(149.4)		654.0		(1,400.8)
Realized loss on derivatives	(8.7)		(14.9)		(6.8)		(2.0)		—		(32.4)
Change in fair value of derivatives	10.2		(8.8)		(2.3)		(0.3)		—		(1.2)
Adjusted gross margin	106.4		94.2		106.9		79.3		—		386.8
Operating expenses	(37.3)		(30.5)		(19.8)		(19.3)		—		(106.9)
Segment profit	69.1		63.7		87.1		60.0		—		279.9
Depreciation and amortization	(35.4)		(34.6)		(52.3)		(28.5)		(2.2)		(153.0)

Gain on disposition of assets	0.1		0.2		—		0.1		—		0.4
General and administrative	—		—		—		—		(28.2)		(28.2)
Interest expense, net of interest income	—		—		—		—		(60.1)		(60.1)

Loss from unconsolidated affiliate investments	—		—		—		—		(2.3)		(2.3)

Income (loss) before non-controlling interest and income taxes	$	33.8	$	29.3	$	34.8	$	31.6	$	(92.8)	$	36.7

Capital expenditures	$	25.8	$	0.4	$	10.3	$	3.3	$	0.6	$	40.4

____________________________

(1)Includes related party cost of sales of $4.9 million for the three months ended September 30, 2021.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2022
Natural gas sales	$	880.2	$	868.2	$	277.9	$	106.1	$	—	$	2,132.4
NGL sales	0.2		3,382.6		8.4		1.4		—		3,392.6
Crude oil and condensate sales	884.3		280.9		108.6		—		—		1,273.8

Product sales	1,764.7		4,531.7		394.9		107.5		—		6,798.8

NGL sales—related parties	1,207.6		126.3		653.9		452.4		(2,440.2)		—
Crude oil and condensate sales—related parties	—		—		0.3		9.6		(9.9)		—
Product sales—related parties	1,207.6		126.3		654.2		462.0		(2,450.1)		—
Gathering and transportation	54.4		54.1		133.3		129.3		—		371.1
Processing	28.8		1.2		85.4		95.0		—		210.4
NGL services	—		61.8		—		0.2		—		62.0
Crude services	16.0		26.7		9.9		0.5		—		53.1
Other services	0.6		1.2		0.4		0.4		—		2.6
Midstream services	99.8		145.0		229.0		225.4		—		699.2



Crude services—related parties	—		—		0.1		—		(0.1)		—
Other services—related parties	—		0.2		—		—		(0.2)		—
Midstream services—related parties	—		0.2		0.1		—		(0.3)		—
Revenue from contracts with customers	3,072.1		4,803.2		1,278.2		794.9		(2,450.4)		7,498.0
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(2,628.0)		(4,425.7)		(913.4)		(514.0)		2,450.4		(6,030.7)
Realized loss on derivatives	(11.3)		(5.8)		(18.9)		(8.6)		—		(44.6)
Change in fair value of derivatives	9.0		10.2		10.6		8.6		—		38.4
Adjusted gross margin	441.8		381.9		356.5		280.9		—		1,461.1
Operating expenses	(145.3)		(105.4)		(67.6)		(68.3)		—		(386.6)
Segment profit	296.5		276.5		288.9		212.6		—		1,074.5
Depreciation and amortization	(110.6)		(114.6)		(154.7)		(90.5)		(4.1)		(474.5)

Gain (loss) on disposition of assets	—		0.3		0.5		(4.7)		—		(3.9)
General and administrative	—		—		—		—		(91.9)		(91.9)
Interest expense, net of interest income	—		—		—		—		(171.0)		(171.0)
Loss on extinguishment of debt	—		—		—		—		(6.2)		(6.2)
Loss from unconsolidated affiliate investments	—		—		—		—		(4.0)		(4.0)
Other income	—		—		—		—		0.6		0.6
Income (loss) before non-controlling interest and income taxes	$	185.9	$	162.2	$	134.7	$	117.4	$	(276.6)	$	323.6
Capital expenditures	$	130.6	$	18.5	$	45.1	$	17.7	$	5.1	$	217.0

____________________________

(1)Includes related party cost of sales of $25.3 million for the nine months ended September 30, 2022.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2021
Natural gas sales	$	381.7	$	426.4	$	139.7	$	109.4	$	—	$	1,057.2
NGL sales	0.9		2,231.2		1.3		1.0		—		2,234.4
Crude oil and condensate sales	472.1		154.5		50.5		—		—		677.1

Product sales	854.7		2,812.1		191.5		110.4		—		3,968.7

NGL sales—related parties	661.8		93.3		430.4		306.4		(1,491.9)		—
Crude oil and condensate sales—related parties	—		—		0.1		5.1		(5.2)		—
Product sales—related parties	661.8		93.3		430.5		311.5		(1,497.1)		—
Gathering and transportation	34.3		48.5		141.8		117.6		—		342.2
Processing	21.7		1.9		70.5		81.1		—		175.2
NGL services	—		56.0		—		0.2		—		56.2
Crude services	13.0		29.8		9.5		0.5		—		52.8
Other services	0.6		1.3		0.5		0.4		—		2.8
Midstream services	69.6		137.5		222.3		199.8		—		629.2



Crude services—related parties	—		—		0.2		—		(0.2)		—
Other services—related parties	—		2.4		—		—		(2.4)		—
Midstream services—related parties	—		2.4		0.2		—		(2.6)		—
Revenue from contracts with customers	1,586.1		3,045.3		844.5		621.7		(1,499.7)		4,597.9
Cost of sales, exclusive of operating expenses and depreciation and amortization (1)	(1,304.5)		(2,690.1)		(533.9)		(361.8)		1,499.7		(3,390.6)
Realized loss on derivatives	(69.8)		(32.0)		(15.7)		(4.8)		—		(122.3)
Change in fair value of derivatives	(3.0)		(18.6)		(9.4)		(1.9)		—		(32.9)
Adjusted gross margin	208.8		304.6		285.5		253.2		—		1,052.1
Operating expenses	(52.9)		(91.4)		(57.3)		(58.4)		—		(260.0)
Segment profit	155.9		213.2		228.2		194.8		—		792.1
Depreciation and amortization	(103.5)		(106.8)		(153.6)		(86.0)		(6.0)		(455.9)

Gain on disposition of assets	0.2		0.3		—		0.2		—		0.7
General and administrative	—		—		—		—		(80.3)		(80.3)
Interest expense, net of interest income	—		—		—		—		(180.1)		(180.1)

Loss from unconsolidated affiliate investments	—		—		—		—		(9.9)		(9.9)
Other income	—		—		—		—		0.1		0.1
Income (loss) before non-controlling interest and income taxes	$	52.6	$	106.7	$	74.6	$	109.0	$	(276.2)	$	66.7

Capital expenditures	$	78.6	$	5.4	$	17.1	$	7.6	$	1.1	$	109.8

____________________________

(1)Includes related party cost of sales of $11.7 million for the nine months ended September 30, 2021.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The table below represents information about segment assets as of September 30, 2022 and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows. However, we cannot provide assurance that future events, such as changes in existing laws, regulations, or enforcement policies, the promulgation of new laws or regulations, or the discovery or development of new factual circumstances will not cause us to incur material costs. Environmental regulations have historically become more stringent over timeDecember 31, 2021 (in millions):


Segment Identifiable Assets:	September 30, 2022		December 31, 2021
Permian	$	2,553.8	$	2,358.6
Louisiana	2,487.0		2,428.6
Oklahoma	2,533.3		2,619.5
North Texas	1,130.2		896.8
Corporate (1)	109.0		179.7
Total identifiable assets	$	8,813.3	$	8,483.2

____________________________

(1)Accounts receivable and ~~thus, there can be no assurance as~~accrued revenue sold to the ~~amount or timing~~SPV for collateral under the AR Facility are included within the Permian, Louisiana, Oklahoma, and North Texas segments.

(15) Other Information

The following tables present additional detail for other current assets and other current liabilities, which consists of ~~future expenditures~~the following (in millions):


Other current assets:	September 30, 2022		December 31, 2021
Natural gas and NGLs inventory	$	149.8	$	49.4
Prepaid expenses and other	25.2		34.2
Other current assets	$	175.0	$	83.6


Other current liabilities:	September 30, 2022		December 31, 2021
Accrued interest	$	62.1	$	47.2
Accrued wages and benefits, including taxes	30.5		33.1
Accrued ad valorem taxes	38.9		28.3
Capital expenditure accruals	22.1		23.2

Short-term lease liability	22.9		18.1
Installment payable (1)	—		10.0
Inactive easement commitment (2)	—		9.8
Operating expense accruals	15.8		9.6
Other	26.0		23.6
Other current liabilities	$	218.3	$	202.9

____________________________

(1)Consideration for ~~environmental compliance or remediation.~~the Amarillo Rattler Acquisition included an installment payable, which was paid on April 30, 2022.

(2)Amount related to an inactive easement commitment, which was paid in August 2022.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(16) Commitments and Contingencies

In February 2021, the ~~second quarter~~areas in which we operate experienced a severe winter storm, with extreme cold, ice, and snow occurring over an unprecedented period of ~~2017,~~approximately 10 days (“Winter Storm Uri”). As a result of Winter Storm Uri, we ~~reached a settlement agreement with the Ohio Environmental Protection Agency with respect~~have encountered customer billing disputes related to the ~~previously disclosed notices~~delivery of ~~violation (“NOVs”) relating to certain of our ORV operations~~gas during the storm, including one that ~~were previously operated by a joint venture partner.~~resulted in litigation. The ~~settlement payment~~litigation is ~~not material to our results of operations, financial condition or cash flows.~~

On July 29, 2016, after concluding a multi-year internal environmental compliance assessment of our Louisiana operations, we commenced discussions with the Louisiana Department of Environmental Quality (“LDEQ”) relating to: (a) a global settlement to resolve environmental noncompliance discovered or investigated during our assessment involving several of our Louisiana facilities and (b) notices of potential violation and NOVs received from the LDEQ. We have taken appropriate measures to resolve all instances of noncompliance. In the third quarter of 2017, we reached a global settlement with the LDEQ pursuant to which we paid approximately $0.3 million.

~~As part of our ongoing environmental and regulatory compliance efforts, we discovered instances of non-compliance with certain environmental regulations at~~between one of our ~~north Texas plants~~subsidiaries, EnLink Gas Marketing, LP (“EnLink Gas”), and ~~self-reported these matters~~Koch Energy Services, LLC (“Koch”) in the 162nd District Court in Dallas County, Texas. The dispute centers on whether EnLink Gas was excused from delivering gas or performing under certain delivery or purchase obligations during Winter Storm Uri, given our declaration of force majeure during the storm. Koch has invoiced us approximately $53.9 million (after subtracting amounts owed to EnLink Gas) and does not recognize the ~~Texas Commission on Environment Quality (“TCEQ”). On October 4, 2017,~~declaration of force majeure. We believe the declaration of force majeure was valid and appropriate and we ~~received and accepted an Agreed Order from the TCEQ related~~intend to ~~these instances of non-compliance. The final penalty assessed was not material to the results~~vigorously defend against Koch’s claims.

Another of our ~~operations, financial condition or cash flows.~~subsidiaries, EnLink Energy GP, LLC, is also involved in litigation arising out of Winter Storm Uri. This matter is a multi-district litigation currently pending in Harris County, Texas, in which multiple individual plaintiffs assert personal injury and property damage claims arising out of Winter Storm Uri against an aggregate of over 350 power generators, transmission/distribution utility, retail electric provider, and natural gas defendants across over 150 filed cases. We believe the claims against our subsidiary lack merit and we intend to vigorously defend against such claims.

~~Finally,~~In addition, we continue to await a ruling from the Pipeline and Hazardous Materials Safety Administration regarding the notice of potential violation discussed in our Annual Report on Form 10-K for the year ended December 31, 2016.


~~(c)~~	~~Litigation Contingencies~~

We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not, individually or in the aggregate, have a material adverse effect on our financial position, results of operations, or cash flows.

In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due We may also be involved from time to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans but was removed to the United States District Court for the Eastern District of Louisiana. The amount of damages is unspecified. Our subsidiary, EnLink LIG, LLC, is one of the named defendants as the owner of pipelinestime in the area. On February 13, 2015, the court granted defendants’ joint motion to dismiss and dismissed the plaintiff’s claims with prejudice. Plaintiffs appealed the matter to the United States Court of Appeals for the Fifth Circuit. On March 3, 2017, the Court of Appeals affirmed the district court’s dismissal of the plaintiff’s claims. On March 17, 2017, the plaintiff filed a petition for rehearing. On April 12, 2017, the Court of Appeals denied the plaintiffs petition for rehearing. On July 11, 2017, the plaintiffs filed a petition for appeal with the United States Supreme Court, which was denied on October 30, 2017.

~~We own and operate a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed~~future in various proceedings in the ~~vicinity~~normal course of ~~this~~business, including litigation on disputes related to contracts, property rights, property use or damage (including nuisance claims), personal injury, or the value of pipeline ~~and underground storage reservoirs, resulting in damage to certain~~easements or other rights obtained through the exercise of our facilities. In order to recover our losses from responsible parties, we sued the operator of a failed cavern in the area, and its insurers, seeking recovery for these losses, as well as other parties we alleged contributed to the formation of the sinkhole. We also filed a claim with our insurers, which our insurers denied. We disputed the denial and sued our insurers. We have reached settlements regarding the entirety of our claims in both lawsuits. In August 2014, we received a partial settlement with respect to our claims in the amount of $6.1 million. We secured additional settlement payments in aggregate amounts of $17.5 million and $8.5 million in March 2017 and June 2017, respectively, which resulted in the recognition of “Gain on litigation settlement” on the consolidated statements of operations of $26.0 million for the nine months ended September 30, 2017.eminent domain or common carrier rights.

Table ofo f Contents

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

In June 2014, a group of landowners in Assumption Parish, Louisiana added our subsidiary, EnLink Processing Services, LLC, as a defendant in a pending lawsuit in the 23rd Judicial Court, Assumption Parish, Louisiana they had filed against other defendants relating to claims arising from the Bayou Corne Sinkhole. Plaintiffs alleged that EnLink Processing Services, LLC’s negligence contributed to the formation of the sinkhole. The amount of damages was unspecified. EnLink Processing Services, LLC reached a settlement with the plaintiffs in February 2017, funded by EnLink Processing Services, LLC’s insurance carriers. The plaintiffs’ claims against EnLink Processing Services, LLC were dismissed with prejudice in March 2017.

~~(16) Segment Information~~

Identification of the majority of our operating segments is based principally upon geographic regions served and the nature of operating activity. Our reportable segments consist of the following: natural gas gathering, processing, transmission and fractionation operations located in north Texas and the Midland and Delaware basins in west Texas (“Texas”), the pipelines, processing plants, storage facilities and NGL assets in Louisiana (“Louisiana”), natural gas gathering and processing operations located throughout Oklahoma (“Oklahoma”) and crude rail, truck, pipeline and barge facilities in west Texas, south Texas, Louisiana and the Ohio River Valley (“Crude and Condensate”). Operating activity for intersegment eliminations is shown in the Corporate segment. Our sales are derived from external domestic customers. We evaluate the performance of our operating segments based on operating revenues and segment profits.

Corporate assets consist primarily of cash, property and equipment, including software, for general corporate support, debt financing costs and unconsolidated affiliate investments in GCF and the Cedar Cove JV as of September 30, 2017 and December 31, 2016. As of December 31, 2016, our Corporate assets included our unconsolidated affiliate investment in HEP. In December 2016, we entered into an agreement to sell our ownership interest in HEP, and we finalized the sale in March 2017.

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

~~Summarized financial information for our reportable segments is shown in the following tables (in millions):~~

Texas Louisiana Oklahoma Crude and Condensate Corporate Totals
Three Months Ended September 30, 2017
Product sales $ 80.8
$ 642.3
$ 42.5
$ 291.1
$ —
$ 1,056.7
Product sales—related parties 130.6
10.0
94.6
—
(199.9 ) 35.3
Midstream services 29.1
50.3
44.3
12.7
—
136.4
Midstream services—related parties 106.7
35.9
63.0
4.8
(35.4 ) 175.0
Cost of sales (198.5 ) (662.7 ) (148.2 ) (279.1 ) 235.3
(1,053.2 )
Operating expenses (41.1 ) (24.8 ) (17.1 ) (19.1 ) —
(102.1 )
Loss on derivative activity —
—
—
—
(5.5 ) (5.5 )
Segment profit (loss) $ 107.6
$ 51.0
$ 79.1
$ 10.4
$ (5.5 ) $ 242.6
Depreciation and amortization $ (52.5 ) $ (29.3 ) $ (40.2 ) $ (11.7 ) $ (2.6 ) $ (136.3 )
Impairments $ —
$ —
$ —
$ (1.8 ) $ —
$ (1.8 )
Goodwill $ 232.0
$ —
$ 190.3
$ —
$ 1,119.9
$ 1,542.2
Capital expenditures $ 39.1
$ 7.5
$ 107.7
$ 13.3
$ 2.1
$ 169.7

Three Months Ended September 30, 2016
Product sales $ 61.3
$ 430.9
$ 16.2
$ 262.6
$ —
$ 771.0
Product sales—related parties 81.9
24.4
36.0
—
(99.2 ) 43.1
Midstream services 27.5
57.2
24.2
16.8
—
125.7
Midstream services—related parties 109.5
29.9
47.7
5.2
(27.0 ) 165.3
Cost of sales (134.1 ) (471.5 ) (58.3 ) (250.5 ) 126.2
(788.2 )
Operating expenses (42.9 ) (23.5 ) (12.6 ) (19.0 ) —
(98.0 )
Loss on derivative activity —
—
—
—
(0.5 ) (0.5 )
Segment profit (loss) $ 103.2
$ 47.4
$ 53.2
$ 15.1
$ (0.5 ) $ 218.4
Depreciation and amortization $ (48.7 ) $ (28.8 ) $ (35.6 ) $ (10.7 ) $ (2.4 ) $ (126.2 )
Goodwill $ 232.0
$ —
$ 190.3
$ —
$ 1,119.9
$ 1,542.2
Capital expenditures $ 51.8
$ 15.4
$ 58.3
$ 12.8
$ 8.6
$ 146.9

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

Texas Louisiana Oklahoma Crude and Condensate Corporate Totals
Nine Months Ended September 30, 2017
Product sales $ 240.5
$ 1,735.5
$ 84.7
$ 913.2
$ —
$ 2,973.9
Product sales—related parties 352.6
25.6
221.4
0.8
(493.1 ) 107.3
Midstream services 85.1
159.7
105.2
45.7
—
395.7
Midstream services—related parties 319.0
100.2
171.8
13.4
(96.8 ) 507.6
Cost of sales (554.7 ) (1,803.1 ) (335.9 ) (884.1 ) 589.9
(2,987.9 )
Operating expenses (127.9 ) (74.8 ) (45.9 ) (60.2 ) —
(308.8 )
Loss on derivative activity —
—
—
—
(1.1 ) (1.1 )
Segment profit (loss) $ 314.6
$ 143.1
$ 201.3
$ 28.8
$ (1.1 ) $ 686.7
Depreciation and amortization $ (161.9 ) $ (86.8 ) $ (115.3 ) $ (35.8 ) $ (7.3 ) $ (407.1 )
Impairments $ —
$ —
$ —
$ (8.8 ) $ —
$ (8.8 )
Goodwill $ 232.0
$ —
$ 190.3
$ —
$ 1,119.9
$ 1,542.2
Capital expenditures $ 107.1
$ 55.8
$ 383.4
$ 64.4
$ 25.6
$ 636.3

Nine Months Ended September 30, 2016
Product sales $ 165.7
$ 1,118.1
$ 32.9
$ 781.1
$ —
$ 2,097.8
Product sales—related parties 191.9
47.0
69.1
1.1
(209.8 ) 99.3
Midstream services 78.1
165.1
57.3
48.0
—
348.5
Midstream services—related parties 331.7
68.1
134.4
14.4
(60.1 ) 488.5
Cost of sales (329.0 ) (1,199.1 ) (109.2 ) (739.4 ) 269.9
(2,106.8 )
Operating expenses (125.2 ) (72.2 ) (37.2 ) (61.7 ) —
(296.3 )
Loss on derivative activity —
—
—
—
(6.6 ) (6.6 )
Segment profit (loss) $ 313.2
$ 127.0
$ 147.3
$ 43.5
$ (6.6 ) $ 624.4
Depreciation and amortization $ (143.6 ) $ (86.7 ) $ (104.2 ) $ (31.7 ) $ (6.8 ) $ (373.0 )
Impairments $ (473.1 ) $ —
$ —
$ (93.2 ) $ (307.0 ) $ (873.3 )
Goodwill $ 232.0
$ —
$ 190.3
$ —
$ 1,119.9
$ 1,542.2
Capital expenditures $ 132.3
$ 52.2
$ 190.6
$ 17.0
$ 15.4
$ 407.5

~~The table below represents information about segment assets as of September 30, 2017 and December 31, 2016 (in millions):~~

Segment Identifiable Assets: September 30, 2017 December 31, 2016
Texas $ 3,113.0
$ 3,142.6
Louisiana 2,395.5
2,349.3
Oklahoma 2,814.7
2,524.5
Crude and Condensate 847.2
836.8
Corporate 1,377.9
1,422.7
Total identifiable assets $ 10,548.3
$ 10,275.9

~~ENLINK MIDSTREAM, LLC~~

~~Notes to Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

~~The following table reconciles the segment profits reported above to the operating income (loss) as reported on the consolidated statements of operations (in millions):~~

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Segment profits $ 242.6
$ 218.4
$ 686.7
$ 624.4
General and administrative expenses (31.3 ) (29.3 ) (98.5 ) (94.7 )
Gain (loss) on disposition of assets (1.1 ) 3.0
(0.8 ) 2.9
Depreciation and amortization (136.3 ) (126.2 ) (407.1 ) (373.0 )
Impairments (1.8 ) —
(8.8 ) (873.3 )
Gain on litigation settlement —
—
26.0
—
Operating income (loss) $ 72.1
$ 65.9
$ 197.5
$ (713.7 )

~~(17) Supplemental Cash Flow Information~~

~~The following schedule summarizes non-cash financing activities for the periods presented (in millions):~~

Nine Months Ended September 30,
2017 2016
Non-cash financing activities:
Non-cash issuance of ENLC common units (1) $ —
$ 214.9
Installment payable, net of discount of $79.1 million (2) —
420.9


~~(1)~~	~~Non-cash ENLC common units were issued as partial consideration for the acquisition of EnLink Oklahoma T.O. assets. See “Note 3—Acquisition” for further discussion.~~


~~(2)~~	ENLK incurred installment purchase obligations, net of discount, payable to the seller in connection with the EnLink Oklahoma T.O. assets. ENLK paid the first installment on January 6, 2017 and will pay the final installment no later than January 7, 2018. See “Note 3—Acquisition~~” for further discussion.~~

~~(18) Other Information~~

~~The following tables present additional detail for other current assets and other current liabilities, which consists of the following (in millions):~~

September 30, 2017 December 31, 2016
Natural gas and NGLs inventory $ 59.1
$ 17.4
Prepaid expenses and other 14.3
16.1
Natural gas and NGLs inventory, prepaid expenses and other $ 73.4
$ 33.5

September 30, 2017 December 31, 2016
Accrued interest $ 64.8
$ 34.2
Accrued wages and benefits, including taxes 23.2
19.0
Accrued ad valorem taxes 33.5
23.5
Capital expenditure accruals 43.6
64.6
Onerous performance obligations 15.4
15.9
Other 54.7
60.3
Other current liabilities $ 235.2
$ 217.5

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

~~You should~~Please read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report. In addition, please refer to the Definitions page set forth in this report prior to Part I—Financial Information.

In this report, the terms “Company” or “Registrant,” as well as the terms “ENLC,” “our,” “we,” ~~and~~ “us,” or like terms, are sometimes used as abbreviated references to EnLink Midstream, LLC itself or EnLink Midstream, LLC together with its consolidated subsidiaries, including ENLK and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” ~~“ENLK”~~“ENLK,” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including ~~EnLink Midstream~~the Operating LP and EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”). EnLink Oklahoma T.O. is sometimes used to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP together with its consolidated subsidiaries.Partnership.

Overview

~~We are~~ENLC is a Delaware limited liability company formed in October 2013. ~~Our~~ENLC’s assets consist of equity interests in EnLink Midstream Partners, LP and EnLink Oklahoma T.O. EnLink Midstream Partners, LP is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. EnLink Oklahoma T.O., a partnership owned by ENLK and ENLC, is engaged in the gathering and processing of natural gas. Our interests in EnLink Midstream Partners, LP and EnLink Oklahoma T.O. consistedall of the ~~following as of September 30, 2017:~~

~~88,528,451~~outstanding common units ~~representing an aggregate 21.8% limited partner interest in ENLK;~~

~~100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner~~ of ENLK ~~(the “General Partner”), which owns a 0.4% general partner interest~~ and all of the ~~incentive distribution rights in ENLK;~~membership interests of the General Partner. All of our midstream energy assets are owned and

~~16% limited partner interest in EnLink Oklahoma T.O.~~

~~Each of~~ operated by ENLK and ~~EnLink Oklahoma T.O. is required by~~ its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of ENLK’s or EnLink Oklahoma T.O.’s business, as applicable, or to provide for future distributions.

The incentive distribution rights in ENLK entitle us to receive an increasing percentage of cash distributed by ENLK as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each common unit has received $0.25 for that quarter, 23.0% of all cash distributed after each common unit has received $0.3125 for that quarter and 48.0% of all cash distributed after each common unit has received $0.375 for that quarter.

Since we control the General Partner, we reflect our ownership interest in ENLK on a consolidated basis. Our consolidated results of operations are derived from the results of operations of ENLK and also include our deferred taxes, interest of non-controlling interests in ENLK’s net income, interest income (expense) and general and administrative expenses specific to ENLC that are not reflected in ENLK’s results of operations. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of ENLK.

subsidiaries. We primarily focus on providing midstream energy services, ~~including~~ including:

•gathering, compressing, treating, processing, ~~transmission, fractionation, storage, condensate stabilization, brine services~~transporting, storing, and ~~marketing to producers of~~selling natural ~~gas, NGLs,~~gas;

•fractionating, transporting, storing, and selling NGLs; and

•gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and ~~condensate. Our~~condensate, in addition to brine disposal services.

As of September 30, 2022, our midstream energy asset network includes approximately ~~11,000~~12,500 miles of pipelines, 2025 natural gas processing plants with approximately ~~4.5 billion cubic feet per day~~5.9 Bcf/d of processing capacity, 7seven fractionators with approximately ~~260,000 barrels per day~~320,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. We manage and report our activities primarily according to the nature of activity and geography.

We ~~have five reportable segments:~~evaluate the financial performance of our segments by including realized and unrealized gains and losses resulting from commodity swaps activity in the Permian, Louisiana, Oklahoma, and North Texas segments. Identification of the majority of our operating segments is based principally upon geographic regions served:

•North Texas Segment. The North Texas segment includes our natural gas gathering, processing, ~~transmission~~ and ~~fractionation operations in north Texas and the Midland and Delaware basins in west Texas;~~

~~Oklahoma Segment. The Oklahoma segment includes our natural gas gathering and processing~~transmission activities in ~~Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, Sooner Trend Anadarko Basin Canadian~~North Texas; and

~~Kingfisher Counties (“STACK”), South Central Oklahoma Oil Province (“SCOOP”) and Central Northern Oklahoma Woodford Shale areas;~~

~~Louisiana Segment. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities and NGL assets located in Louisiana;~~

~~Crude and Condensate Segment~~. The Crude and Condensate segment includes our Ohio River Valley (“ORV”) crude oil, condensate, condensate stabilization, natural gas compression and brine disposal activities in the Utica and Marcellus Shales, our crude oil operations in the Permian Basin and our crude oil activities associated with our Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale; and

•Corporate ~~Segment~~. Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, ~~our contractual right to~~GCF in South Texas, and the ~~economic burdens and benefits associated with Devon’s ownership interest~~Matterhorn JV in ~~Gulf Coast Fractionators (“GCF”) in south~~West Texas and our ~~general partnership property~~corporate assets and expenses. Until March 2017, the Corporate segment included our unconsolidated affiliate investment in Howard Energy Partners (“HEP”). In December 2016, we entered into an agreement to sell our ownership interest in HEP, and we finalized the sale in March 2017.

We manage our consolidated operations by focusing on adjusted gross ~~operating~~ margin because our business is generally to gather, process, transport, or market natural gas, NGLs, crude oil, and condensate using our assets for a fee. We earn our fees through various fee-based contractual arrangements, which include stated ~~fixed-fee~~fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodity purchase. While our transactions vary in form, the essential element of ~~each transaction~~most of our transactions is the use of our assets to transport a product or provide a processed product to an end-user or marketer at the tailgate of the plant, pipeline, or barge, ~~terminal~~truck, or ~~pipeline. We define~~rail terminal. Adjusted gross ~~operating margin as operating revenue minus cost of sales. Gross operating~~ margin is a non-GAAP financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately ~~95%~~90% of our

adjusted gross ~~operating~~ margin was derived from fee-based ~~services~~contractual arrangements with nominimal direct commodity price exposure for the nine months ended September 30, ~~2017. We reflect revenue as “Product sales”~~2022.

Our revenues and ~~“Midstream services” on the consolidated statements of operations.~~

~~We generate revenues~~adjusted gross margins are generated from eight primary sources:

•gathering and transporting natural gas, NGLs, and ~~NGLs~~crude oil on the pipeline systems we own;

•processing natural gas at our processing plants;

•fractionating and marketing recovered NGLs;

•providing compression services;

•providing crude oil and condensate transportation and terminal services;

•providing condensate stabilization services;

•providing brine disposal services; and

•providing ~~gas, crude, and NGL storage.~~

~~Our gross operating margins are determined primarily by the volumes of:~~

natural gas, ~~gathered, transported, purchased and sold through our pipeline systems;~~

~~natural gas processed at our processing facilities;~~

~~NGLs handled at our fractionation facilities;~~

crude oil, and ~~condensate handled at~~NGL storage.

The following customers individually represented greater than 10% of our ~~crude terminals;~~

consolidated revenues for the three and nine months ended September 30, 2022 and 2021. The loss of these customers would have a material adverse impact on our results of operations because the revenues and adjusted gross margin received from transactions with these customers is material to us. No other customers represented greater than 10% of our consolidated revenues during the periods presented.

~~crude oil and condensate gathered, transported, purchased and sold;~~


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021

Dow Hydrocarbons and Resources LLC	14.5	%	14.0	%	14.4	%	14.5	%
Marathon Petroleum Corporation	11.8	%	12.2	%	14.4	%	13.1	%

~~brine disposed;~~

~~condensate stabilized; and~~

~~gas, crude, and NGLs stored.~~

We ~~typically~~ gather, transport, or store gas owned by others ~~for a fee~~under fee-only contract arrangements based either on the volume of gas gathered, transported, or ~~stored.~~stored or, for firm transportation arrangements, a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We also buy natural gas from producers ~~plants~~ or shippers at ~~either a fixed discount to~~ a market index orless a ~~percentage~~fee-based deduction subtracted from the purchase price of the ~~market index,~~natural gas. We then gather or transport the natural gas and ~~then transport and resell~~sell the natural gas at ~~the same market index. The fixed discount difference to~~ a market index, ~~represents~~thereby earning a margin through the ~~fee for using our assets.~~fee-based deduction. We attempt to execute substantially all purchases and sales concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the fee we will receive for each natural gas transaction. ~~Our gathering and transportation fee related to a percentage of the index price can be adversely affected by declines in the price of natural gas.~~ We are also party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally

match our purchase obligations. However, over time, the supplies that we have under contract may decline due to reduced drilling or other causes, and we may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In our purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased.

On occasion we have entered into certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and we capture the difference in the indices (also referred to as “basis spread”), less the transportation expenses from the two areas, as our fee. Changes in the basis spread can increase or decrease our margins or potentially result in losses. For example, we are a party to one contract associated with our north Texas operations with a term to 2019 to supply approximately 150,000 MMBtu/d of gas. We buy gas for this contract on several different production-area indices and sell the gas into a different market area index. We realize a cash loss on the delivery of gas under this contract each month based on current prices. The fair value of this performance obligation was recorded based on forecasted discounted cash obligations in excess of market prices under this gas delivery contract. As of September 30, 2017, the balance sheet reflects a liability of $31.4 million related to this performance obligation. Narrower basis spreads in recent periods have increased the losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse.

We typically ~~transport and fractionate or store NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. We also~~ buy mixed NGLs from our suppliers to our gas processing plants at a fixed discount to market indices for the component NGLs with a deduction for our fractionation fee. We subsequently sell the fractionated NGL products based on the same index-based prices. To a lesser extent, we transport and fractionate or store NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. The operating results of our NGL fractionation business are largely dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With our fractionation business, we also have the opportunity for product upgrades for each of the discrete NGL products. We realize higher adjusted gross ~~operating~~ margins from product upgrades during periods with higher NGL prices.

We ~~typically~~ gather or transport crude oil and condensate owned by others by rail, truck, pipeline, and barge facilities ~~for a net fee-based margin.~~under fee-only contract arrangements based on volumes gathered or transported. We also buy crude oil and condensate on our own gathering systems, third-party systems, and trucked from ~~a producer~~producers at a ~~fixed discount to~~market index less a ~~market index,~~stated transportation deduction. We then transport and resell the crude oil and condensate ~~at the same market index.~~through a process of basis and fixed price trades. We execute substantially all purchases and sales concurrently, thereby establishing the ~~fee~~net margin we will receive for each crude oil and condensate transaction.

We realize adjusted gross ~~operating~~ margins from our gathering and processing services primarily through different contractual arrangements: processing ~~margins~~margin (“margin”)~~, percentage~~ contracts, POL contracts, POP contracts, fixed-fee based contracts, or a combination of ~~liquids (“POL”), percentage~~these contractual arrangements. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” for a detailed description of ~~proceeds (“POP”)~~these contractual arrangements. Under any of these gathering and processing arrangements, we may earn a fee for the services performed, or ~~fixed-fee based.~~we may buy and resell the gas and/or NGLs as part of the processing arrangement and realize a net margin as our fee. Under margin contract arrangements, our adjusted gross ~~operating~~

margins are higher during periods of high NGL prices relative to natural gas prices. ~~Gross operating~~Adjusted gross margin results under POL contracts are impacted only by the value of the liquids produced with margins higher during periods of higher liquids prices. ~~Gross operating~~Adjusted gross margin results under POP contracts are impacted only by the value of the natural gas and liquids produced with margins higher during periods of higher natural gas and liquids prices. Under fixed-fee based contracts, our adjusted gross ~~operating~~ margins are driven by throughput volume. ~~See “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”~~

Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services, and utilities. These costs are normally fairly stable across broad volume ranges and therefore do not normally increase or decrease significantly in the short term with increases or decreases in the volume of gas, liquids, crude oil, and condensate moved through or by our assets.

CCS Business

We are currently developing an integrated offering to bring CCS services to businesses along the ~~asset.~~Mississippi River corridor in Louisiana, one of the highest CO2 emitting regions in the United States. We believe our existing asset footprint, including our extensive network of natural gas pipelines in Louisiana, our operating expertise and our customer relationships, provide EnLink an advantage in building a CCS business.

Recent Developments Affecting Industry Conditions and Our Business

~~Organic Growth~~Current Market Environment

~~Black Coyote Crude Oil Gathering System.~~ WeThe midstream energy business environment and our business are ~~expanding~~affected by the level of production of natural gas and oil in the ~~core~~areas in which we operate and the various factors that affect this production, including commodity prices, capital markets trends, competition, and regulatory changes. We believe these factors will continue to affect production and therefore the demand for midstream services and our business in the future. To the extent these factors vary from our underlying assumptions, our business and actual results could vary materially from market expectations and from the assumptions discussed in this section.

Production levels by our exploration and production customers are driven in large part by the level of oil and natural gas prices. New drilling activity is necessary to maintain or increase production levels as oil and natural gas wells experience production declines over time. New drilling activity generally moves in the ~~STACK play in Central Oklahoma with the construction of a new~~same direction as crude oil ~~gathering system that~~and natural gas prices as those prices drive investment returns and cash flow available for reinvestment by exploration and production companies. Accordingly, our operations are affected by the level of crude, natural gas, and NGL prices, the relationship among these prices, and related activity levels from our customers.

There has been, and we ~~refer to as “Black Coyote.” Black Coyote~~believe there will ~~primarily be built on dedicated acreage from Devon, who will be the main shipper on the system. The system is expected~~continue to be, ~~operational~~volatility in commodity prices and in the relationships among NGL, crude oil, and natural gas prices. Commodity markets have now recovered from the reduction in global demand and low market prices experienced in 2020 due to the COVID-19 pandemic. However, oil and natural gas prices continue to remain volatile. Oil and natural gas prices rose during 2021 and rose especially rapidly in the first ~~quarter~~half of ~~2018.~~

~~Chisholm Plants.~~ ~~In April 2017, we completed construction~~2022 due to various factors, including a rebound in demand from economic activity after COVID-19 shutdowns, supply issues, and geopolitical events, including Russia’s invasion of ~~a new cryogenic~~Ukraine. Since that time, both oil and natural gas ~~processing plant, referred to as Chisholm II, which provides 200 MMcf/d of processing capacity and is tied to new and existing pipelines~~prices have moderated from their peaks earlier in the ~~STACK~~year, although as of the date of this report, the market price for both oil and ~~SCOOP plays~~natural gas are at higher levels than either has traded in ~~Oklahoma. The new capacity is supported by new~~recent years.

Capital markets and ~~existing long-term contracts.~~

the demands of public investors also affect producer behavior, production levels, and our business. Over the last several years, public investors have exerted pressure on oil and natural gas producers to increase capital discipline and focus on higher investment returns even if it means lower growth. In addition, ~~we commenced construction~~the ability of ~~a new processing plant referred to as Chisholm III in April 2017. Chisholm III will provide an additional 200 MMcf/d of processing capacity and will be tied to new and existing pipelines~~companies in the ~~STACK~~oil and ~~SCOOP plays. Construction is scheduled~~gas industry to ~~be completed~~access the capital markets on favorable terms has been negatively impacted during this same period. This demand by investors for increased capital discipline from energy companies, as well as the difficulties in accessing capital markets, led to more modest capital investment by producers, curtailed drilling and production activity, and, accordingly, slower growth for us and other midstream companies during the ~~fourth quarter~~past few years. This trend was amplified in 2020 by the COVID-19 pandemic, which reduced demand for commodities. However, in response to the rise of ~~2017.~~oil and natural gas prices during 2021 and in 2022 to date, capital investments by United States oil and natural gas producers have begun to rise, although global capital investments by oil and natural gas producers remain below historical levels and producers continue to remain cautious.

~~Greater Chickadee Crude Oil Gathering System~~.Producers generally focus their drilling activity on certain producing basins depending on commodity price fundamentals and favorable drilling economics. In ~~March 2017, we completed construction and began operations of a crude oil gathering system in Upton and Midland counties, Texas~~the last few years, many producers have increasingly focused their activities in the Permian Basin, because of the availability of higher investment returns. Currently, a large percentage of all drilling rigs operating in the

United States are operating in the Permian Basin. We continue to experience a robust increase in volumes in our Permian segment as our operations in that basin are in a favorable position relative to producer activity. As a result of this concentration of drilling activity in the Permian Basin, other basins, including those in which we operate in Oklahoma and North Texas, have experienced reduced investment and declines in volumes produced. However, the rise in commodity prices during 2022 has led to renewed producer interest in both Oklahoma and North Texas and we expect activity to increase in both areas for the remainder of 2022 and during 2023.

Our Louisiana segment, while subject to commodity price trends, is less dependent on gathering and processing activities and more affected by industrial demand for the natural gas and NGLs that we ~~refer to as “Greater Chickadee.” Greater Chickadee includes over 185 miles~~supply. Industrial demand along the Gulf Coast region has remained strong throughout 2021 and through the first three quarters of ~~high-~~2022, supported by regional industrial activity and ~~low-pressure pipelines that transport crude oil volumes to several major market outlets~~export markets. Our activities and, ~~other key hub centers~~in turn, our financial performance in the ~~Midland, Texas area. Greater Chickadee also includes multiple central tank batteries, together with pump, truck injection~~Louisiana segment is highly dependent on the availability of natural gas and ~~storage stations~~NGLs produced by our upstream gathering and processing business and by other market participants. To date, the supply of natural gas and NGLs has remained at levels sufficient for us to ~~maximize shipping~~supply our customers, and ~~delivery options for our producer customers.~~

~~Marathon Petroleum Joint Venture~~. In March 2017, we completed construction and began operating a new NGL pipeline, which is part of our 50/50 joint venture with a subsidiary of Marathon Petroleum Company (“Marathon Petroleum”). This joint venture, Ascension Pipeline Company, LLC (the “Ascension JV”),maintaining such supply is a ~~bolt-on project to~~key business focus.

For additional discussion regarding these factors, see “Item 1A—Risk Factors—Business and Industry Risks” in our ~~Cajun-Sibon NGL system and is supported by long-term, fee-based contracts with Marathon Petroleum.~~

~~Lobo Natural Gas Gathering and Processing Facilities~~. The Lobo facilities are part of our joint venture (the “Delaware Basin JV”) with an affiliate of NGP Natural Resources XI, LP (“NGP”). In the first quarter of 2017, we completed the expansion of a 75-mile gathering system located in Texas and New MexicoAnnual Report on Form 10-K for our Lobo II processing facility. In the second quarter of 2017, we completed the construction of an additional expansion of the Lobo II processing facility, which provides an additional 60 MMcf/d of processing capacity. Furthermore, we are constructing an additional expansion to Lobo II, which will increase capacity by 30 MMcf/d and is expected to be completed during the fourth quarter of 2017.

In addition, we will be expanding the gas processing capacity at our Lobo facilities by 200 MMcf/d through construction of the Lobo III processing facility, which is expected to be operational by the second half of 2018.

~~Sale of Non-Core Assets~~

~~In March 2017, we finalized the sale of our ownership interest in HEP for net proceeds of $189.7 million. For~~ the year ended December 31, ~~2016,~~2021 filed with the Commission on February 16, 2022.

Regulatory Developments

On January 20, 2021, the Biden Administration came into office and immediately issued a number of executive orders related to climate change and the production of oil and gas that could affect our operations and those of our customers, particularly those who may operate on public lands. While none of these initiatives to date have materially affected our operations or those of our customers, the Biden Administration could seek, in the future, to put into place executive orders, policy and regulatory reviews, or seek to have Congress pass legislation that could adversely affect the production of oil and natural gas, and our operations and those of our customers.

Only a small percentage of our operations are derived from customers operating on public land, mainly in the Delaware Basin. Our operations in the Delaware Basin are expected to represent only approximately 6% of our total segment profit, net to EnLink, during 2022. In addition, we ~~recorded~~have a robust program to monitor and prevent methane emissions in our operations and we maintain a comprehensive environmental program that is embedded in our operations. However, our activities that take place on public lands require that we and our producer customers obtain leases, permits, and other approvals from the federal government. While the future rules and rulemaking initiatives under the Biden Administration remain uncertain, the regulations that might result from such initiatives, could lead to increased costs for us or our customers, difficulties in obtaining leases, permits, and other approvals for us and our customers, reduced utilization of our gathering, processing, and pipeline systems or reduced rates under renegotiated transportation or storage agreements in affected regions.

On August 16, 2022, the U.S. government enacted the Inflation Reduction Act of 2022 (the "IRA") into law. The enhancements to the 45Q carbon sequestration tax credits provided by the IRA should expand and support the development of our CCS business, while the other provisions are not expected to have a material impact to our business.

Any regulatory changes could adversely affect our business, financial condition, results of operations or cash flows, including our ability to make cash distributions to our unitholders. For more information, see our risk factors under “Environmental, Legal Compliance, and Regulatory Risk” in Section 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

Other Recent Developments

Organic Growth and Acquisition

Acquisition of Barnett Shale Assets. On July 1, 2022, we acquired all of the equity interest in the gathering and processing assets of Crestwood Equity Partners LP located in the Barnett Shale, for a cash purchase price of $275.0 million plus working capital of $14.5 million. These assets include approximately 400 miles of lean and rich gas gathering pipeline and three processing plants with 425 MMcf/d of total processing capacity. See “Item 1. Financial Statements—Note 3” for more information regarding this acquisition.

Matterhorn Express Pipeline Joint Venture. On May 16, 2022, we entered into an ~~impairment loss~~agreement with WhiteWater Midstream, LLC, Devon Energy Corporation, and MPLX LP to construct a pipeline designed to transport up to 2.5 Bcf/d of ~~$20.1~~natural gas through approximately 490 miles of 42-inch pipeline from Waha Hub in West Texas to Katy, Texas. Supply for the Matterhorn JV will be sourced from multiple upstream connections in the Permian Basin, including direct connections to processing facilities in the Midland Basin through an approximately 75-mile lateral, as well as a direct connection to the 3.2 Bcf/d Agua

Blanca Pipeline. The Matterhorn Express Pipeline is expected to be in service in the third quarter of 2024, pending the receipt of customary regulatory and other approvals.

Phantom Processing Plant. In November 2021, we began moving equipment and facilities associated with the Thunderbird processing plant in Central Oklahoma to the Midland Basin. We completed the relocation of the Phantom processing plant in October 2022, which increased our Permian Basin processing capacity by 235 MMcf/d.

CCS Business

ExxonMobil Agreement. In October 2022, we entered into a transportation services agreement with a subsidiary of ExxonMobil in connection with the development of a CCS project in the Mississippi River corridor in southeastern Louisiana. Under this agreement, we will deliver CO2 from the Mississippi River corridor to ExxonMobil’s storage location in Vermilion Parish. The reserved capacity available under this agreement is up to 10 million metric tonnes per year, with initial reserved capacity of 3.2 million metric tonnes per year, beginning in early 2025.

BKV Agreement. In June 2022, we entered into an agreement with BKV to develop a CCS project in the Barnett Shale. Under this agreement, we will separate CO2 from lean gas in our North Texas gathering systems and from rich gas delivered to our natural gas processing plant in Bridgeport, Texas. The CO2 waste stream will then be captured, compressed, transported, and sequestered by BKV, beginning in late 2023.

Debt and Equity

Amended AR Facility Agreement. On August 1, 2022, we amended certain terms of the AR Facility to, among other things, increase the commitments thereunder from $350.0 million to ~~reduce~~$500.0 million and extend the ~~carrying value of~~scheduled termination date from September 24, 2024 to August 1, 2025. See “Item 1. Financial Statements—Note 6” for more information.

Amended and Restated Revolving Credit Agreement. On June 3, 2022, we amended and restated our ~~investment to~~prior revolving credit facility by entering into the ~~expected sales price. Upon the final sale of HEP in March 2017, we recorded an additional loss of $3.4 million~~Revolving Credit Facility. See “Item 1. Financial Statements—Note 6” for ~~the nine months ended September 30, 2017.~~more information.

Senior Unsecured Notes ~~due 2047~~

Issuance and Repurchases. On ~~May 11, 2017, ENLK issued $500.0~~August 31, 2022, ENLC completed the sale of $700.0 million in aggregate principal amount of ~~ENLK’s 5.450%~~ENLC’s 6.50% senior unsecured notes due ~~June~~September 1, ~~2047 (the “2047 Notes”) at a price~~2030. We used the net proceeds from the sale to the public of 99.981% of their face value. Interest payments on the 2047 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2017. Net proceeds of approximately $495.2 million were usedsettle ENLK’s debt tender offer to ~~repay outstanding borrowings under the ENLK Credit Facility and for general partnership purposes.~~

~~Redemption of Senior Unsecured Notes due 2022~~

~~On June 1, 2017, ENLK redeemed $162.5~~repurchase $700.0 million in aggregate principal amount of ~~ENLK’s 7.125%~~its senior unsecured notes, ~~(the “2022 Notes”) at 103.6%~~consisting of the ~~principal amount, plus accrued unpaid interest,~~2024 Notes and 2025 Notes. Additionally, for ~~aggregate cash consideration of $174.1 million, which resulted in a gain on extinguishment of debt of $9.0 million for~~ the three and nine months ended September 30, ~~2017.~~2022, we repurchased a portion of the outstanding 2024 Notes and 2025 Notes in open market transactions. See “Item 1. Financial Statements—Note 6” for more information regarding the activity related to our senior unsecured notes.

~~Issuance~~Common Unit Repurchase Program. Effective January 1, 2022, the Board reauthorized our common unit repurchase program and reset the amount available for repurchases of ~~ENLK Common Units~~outstanding common units at up to $100.0 million. In July 2022, the Board increased the amount available for repurchase to $200.0 million. See “Item 1. Financial Statements—Note 9” for more information regarding our common unit repurchase program.

~~In November 2014, ENLK~~GIP Repurchase Agreement. On February 15, 2022, we and GIP entered into an ~~Equity Distribution Agreement (the “2014 EDA”) with BMO Capital Markets Corp. and other sales agents~~agreement pursuant to ~~sell up to $350.0 million~~which we are repurchasing, on a quarterly basis, a pro rata portion of the ENLC common units held by GIP, based upon the number of common units purchased by us during the applicable quarter from public unitholders under our common unit repurchase program. The number of ENLC common units held by GIP that we repurchase in ~~aggregate gross sales~~any quarter is calculated such that GIP’s then-existing economic ownership percentage of ~~ENLK’s~~our outstanding common units is maintained after our repurchases of common units from ~~time~~public unitholders are taken into account, and the per unit price we pay to ~~time through an “at~~GIP is the ~~market” equity offering program.~~

In August 2017, ENLK ceased trading under the 2014 EDA and entered into an Equity Distribution Agreement (the “2017 EDA”) with UBS Securities LLC and other sales agents (collectively, the “Sales Agents”) to sell up to $600.0 million in aggregate gross sales of ENLK’s common units from time to time through an “at the market” equity offering program. ENLK may also sell common units to any Sales Agent as principalaverage per unit price paid by us for ~~the Sales Agent’s own account at a price agreed upon at the time of sale. ENLK has no obligation to sell any of~~ the common units ~~under the 2017 EDA and may at any time suspend solicitation and offers under the 2017 EDA.~~

~~For the nine months ended September 30, 2017, ENLK sold an aggregate~~repurchased from public unitholders. See “Item 1. Financial Statements—Note 9” for more information regarding repurchases of ~~approximately 5.3 million~~ENLC common units ~~under the 2014 EDA and 2017 EDA, generating proceeds~~held by GIP.

Redemption of approximately $92.3 million (net of approximately $0.9 million of commissions and $0.2 million of registration fees). ENLK used the net proceeds for general partnership purposes. As of September 30, 2017, approximately $580.1 million remains available to be issued under the 2017 EDA.

~~Issuance of ENLK~~ Series CB Preferred ~~Units~~

Units. In ~~September 2017, ENLK issued 400,000~~January 2022, we redeemed 3,333,334 Series ~~C Fixed-to-Floating Rate Cumulative Redeemable Perpetual~~B Preferred Units ~~(the “Series~~for total consideration of $50.5 million plus accrued distributions. In addition, upon such redemption, a corresponding number of ENLC Class C ~~Preferred Units”) representing ENLK limited partner interests at a~~Common Units were automatically cancelled. The redemption price torepresents 101% of the public of $1,000 per unit. ENLK used the net proceeds of $393.7 million for capital expenditures, general partnership purposes and to repay borrowings under the ENLK Credit Facility. The Series C Preferred Units represent perpetual equity interests in ENLK and, unlike ENLK’s indebtedness, will not give rise to a claim for payment of a principal amount at a particular date. As to the payment of distributions and amounts payable on a liquidation event,preferred units’ par value. In connection with the Series CB Preferred ~~Units rank senior to ENLK’s common units and to each other class of limited partner interests or other equity securities established after~~Unit redemption, we have agreed with the ~~issue date~~holders of the Series CB Preferred Units that ~~is not expressly made senior or on parity~~we will pay cash in lieu of making a quarterly PIK distribution through the distribution declared for the fourth quarter of 2022. See “Item 1. Financial Statements—Note 8” for more information regarding distributions with ~~the Series C Preferred Units. The Series C Preferred Units will rank junior~~respect to the Series B Preferred Units with respect to the payment of distributions, and junior to the Series B Preferred Units and all current and future indebtedness with respect to amounts payable upon a liquidation event. Income is allocated to the Series C Preferred Units in an amount equal to the earned distributions for the respective reporting period.Units.

~~Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15~~^th ~~day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15~~^th day of March, June, September and December of each year, in each case, if and when declared by ENLK’s general partner out of legally available funds for such purpose. The initial distribution rate for the Series C Preferred Units from and including the date of original issue to, but not including, December 15, 2022 is 6.0% per annum. On and after December 15, 2022, distributions on the Series C Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to an annual floating rate of the three-month LIBOR plus a spread of 4.11%.

Non-GAAP Financial Measures

~~We include~~To assist management in assessing our business, we use the following non-GAAP financial measures: ~~Cash available for distribution~~adjusted gross margin; adjusted earnings before interest, taxes, and ~~gross operating margin.~~depreciation and amortization (“adjusted EBITDA”); and free cash flow after distributions.

~~Cash Available for Distribution~~Adjusted Gross Margin

We ~~calculate cash available for distribution as distributions due to us from ENLK and our interest in EnLink Oklahoma T.O.~~define adjusted EBITDA (as defined herein), less our share of maintenance capital attributable to our interest in EnLink Oklahoma T.O., our specific general and administrative costs as a separate public reporting entity, the interest costs associated with our debt and current taxes attributable to our earnings, plus our standalone impairment expense (if any). ENLC’s share of EnLink Oklahoma T.O. growth capital expenditures are funded by borrowings under the ENLC Credit Facility and are not considered in determining ENLC’s cash flow available for distribution.

Cash available for distribution is a supplemental performance measure used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others. As ENLC is a holding company without any direct operations, ENLC primarily generates value for its unitholders by generating returns on its investments in other entities and subsequently distributing these returns in cash to its unitholders. Therefore, cash available for distribution serves as an important measure of ENLC’s profitability and serves as an indicator of ENLC’s success in providing a cash return on its investments to its unitholders.

~~processing assets up to their original operating capacity, to maintain pipeline and equipment reliability, integrity and safety and to address environmental laws and regulations.~~

The GAAP measure most directly comparable to cash available for distribution is net income (loss). Cash available for distribution should not be considered as an alternative to GAAP net income (loss). Cash available for distribution is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Because cash available for distribution excludes some items that affect net income (loss) and is defined differently by different companies in our industry, our definition of cash available for distribution may not be comparable to similarly-titled measures of other companies, thereby diminishing its utility.

~~The following is a calculation of ENLC’s cash available for distribution (in millions):~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Distribution declared by ENLK associated with (1):
General partner interest $ 0.6
$ 0.5
$ 1.9
$ 1.6
Incentive distribution rights 14.8
14.4
44.1
42.4
ENLK common units owned 34.5
34.6
103.6
103.6
Total share of ENLK distributions declared $ 49.9
$ 49.5
$ 149.6
$ 147.6
Adjusted EBITDA of EnLink Oklahoma T.O. (2) 6.9
2.9
14.6
5.9
Transaction costs (3) —
—
—
0.6
Total cash available $ 56.8
$ 52.4
$ 164.2
$ 154.1
Uses of cash:
General and administrative expenses (1.1 ) (0.9 ) (3.7 ) (3.8 )
Current income taxes (4) (0.1 ) —
(0.3 ) —
Interest expense (0.7 ) (0.4 ) (1.7 ) (1.0 )
Maintenance capital expenditures (5) (0.1 ) —
(0.1 ) —
Total cash used $ (2.0 ) $ (1.3 ) $ (5.8 ) $ (4.8 )
ENLC cash available for distribution $ 54.8
$ 51.1
$ 158.4
$ 149.3


~~(1)~~	~~Represents distributions to be paid to ENLC on~~ ~~November 13, 2017~~ ~~and distributions paid on~~ ~~August 11, 2017~~, ~~May 12, 2017, November 11, 2016~~, ~~August 11, 2016~~ ~~and~~ ~~May 12, 2016.~~


~~(2)~~	Represents ENLC’s interest in EnLink Oklahoma T.O. adjusted EBITDA, which is disbursed to ENLC by EnLink Oklahoma T.O. on a monthly basis. EnLink Oklahoma T.O. adjusted EBITDA is defined as earnings before depreciation and amortization and provision for income taxes and includes allocated expenses from ENLK.


~~(3)~~	~~Represents acquisition transaction costs attributable to ENLC’s~~ ~~16%~~ ~~interest in EnLink Oklahoma T.O, which are considered growth capital expenditures as part of the cost of the assets acquired.~~


~~(4)~~	~~Represents ENLC’s stand-alone current tax expense.~~


~~(5)~~	~~Represents ENLC’s interest in EnLink Oklahoma T.O.s’ maintenance capital expenditures which is netted against the monthly disbursement of EnLink Oklahoma T.O.s’ adjusted EBITDA per (2) above.~~

~~The following table provides a reconciliation of ENLC net income (loss) to ENLC cash available for distribution (in millions):~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net income (loss) of ENLC $ 24.1
$ 11.1
$ 60.5
$ (859.0 )
Less: Net income (loss) attributable to ENLK 25.5
18.8
73.2
(536.6 )
Net loss of ENLC excluding ENLK $ (1.4 ) $ (7.7 ) $ (12.7 ) $ (322.4 )
ENLC's share of distributions from ENLK (1) 49.9
49.4
149.6
147.5
ENLC's interest in EnLink Oklahoma T.O.'s non-cash expenses (2) 4.6
3.6
12.8
10.4
ENLC deferred income tax expense (3) 2.5
5.0
8.3
4.7
ENLC corporate goodwill impairment —
—
—
307.0
Non-controlling interest share of ENLK's net income (loss) (4) (0.9 ) 0.6
0.3
1.1
Other items (5) 0.1
0.2
0.1
1.0
ENLC cash available for distribution $ 54.8
$ 51.1
$ 158.4
$ 149.3


~~(1)~~	~~Represents distributions declared by ENLK and to be paid to ENLC onNovember 13, 2017and distributions paid by ENLK to ENLC on~~ ~~August 11, 2017~~, ~~May 12, 2017, November 11, 2016~~, ~~August 11, 2016~~ ~~and~~ ~~May 12, 2016.~~


~~(2)~~	~~Includes depreciation and amortization and unit-based compensation expense allocated to EnLink Oklahoma T.O.~~ ~~for the three and nine~~ ~~months ended~~ ~~September 30, 2017, and depreciation and amortization for thethree and nine~~ ~~months ended~~ ~~September 30, 2016.~~


~~(3)~~	~~Represents ENLC’s stand-alone deferred taxes.~~


~~(4)~~	~~Represents NGP’s~~ ~~49.9%~~ share of adjusted EBITDA from the Delaware Basin JV, which was formed in August 2016, Marathon Petroleum’s 50% share of adjusted EBITDA from the Ascension JV, which began operations in April 2017, and other minor non-controlling interests.

~~(5)~~

~~Represents transaction costs attributable to ENLC’s share of the acquisition of EnLink Oklahoma T.O.~~ ~~for the three and nine~~ ~~months ended~~ ~~September 30, 2016, ENLC’s interest in EnLink Oklahoma T.O.s’ maintenance capital expenditures (which is netted against the monthly disbursement of EnLink Oklahoma T.O.s’ adjusted EBITDA) for the~~ ~~three and nine months ended September 30, 2017~~ ~~and other non-cash items not included in cash available for distribution.~~

~~Gross Operating Margin~~

~~We define~~ gross ~~operating~~ margin as revenues less cost of ~~sales.~~sales, exclusive of operating expenses and depreciation and amortization. We present adjusted gross ~~operating~~ margin by segment in “Results of Operations.” We disclose adjusted gross ~~operating~~ margin in addition to ~~total revenue~~gross margin as defined by GAAP because it is the primary performance measure used by our ~~management.~~management to evaluate consolidated operations. We believe adjusted gross ~~operating~~ margin is an important measure because, in general, our business is ~~to purchase and resell natural gas, NGLs, condensate and crude oil for a margin or~~ to gather, process, transport, or market natural gas, NGLs, condensate, and crude oil for a ~~fee.~~fee or to purchase and resell natural gas, NGLs, condensate, and crude oil for a margin. Operating expense is a separate measure used by our management to evaluate the operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities, and contract services comprise the most significant portion of our operating expenses. We ~~do not deduct~~exclude all operating expenses and depreciation and amortization from ~~total revenue in calculating~~adjusted gross ~~operating~~ margin because these expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. The GAAP measure most directly comparable to adjusted gross ~~operating~~ margin is ~~operating income (loss). Gross operating~~gross margin. Adjusted gross margin should not be considered an alternative to, or more meaningful than, ~~operating income (loss)~~gross margin as determined in accordance with GAAP. ~~Gross operating~~Adjusted gross margin has important limitations because it excludes all operating ~~costs~~expenses and depreciation and amortization that affect ~~operating income (loss) except cost of sales.~~gross margin. Our adjusted gross ~~operating~~ margin may not be comparable to ~~similarly-titled~~similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

The following table ~~provides~~reconciles total revenues and gross margin to adjusted gross margin (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Total revenues	$	2,663.5	$	1,787.6	$	7,491.8	$	4,442.7
Cost of sales, exclusive of operating expenses and depreciation and amortization	(2,131.1)		(1,400.8)		(6,030.7)		(3,390.6)
Operating expenses	(136.8)		(106.9)		(386.6)		(260.0)
Depreciation and amortization	(162.6)		(153.0)		(474.5)		(455.9)
Gross margin	233.0		126.9		600.0		336.2
Operating expenses	136.8		106.9		386.6		260.0
Depreciation and amortization	162.6		153.0		474.5		455.9
Adjusted gross margin	$	532.4	$	386.8	$	1,461.1	$	1,052.1

Adjusted EBITDA

We define adjusted EBITDA as net income (loss) plus (less) interest expense, net of interest income; depreciation and amortization; impairments; (income) loss from unconsolidated affiliate investments; distributions from unconsolidated affiliate investments; (gain) loss on disposition of assets; (gain) loss on extinguishment of debt; unit-based compensation; income tax expense (benefit); unrealized (gain) loss on commodity swaps; costs associated with the relocation of processing facilities; accretion expense associated with asset retirement obligations; transaction costs; non-cash expense related to changes in the fair value of contingent consideration; (non-cash rent); and (non-controlling interest share of adjusted EBITDA from joint ventures). Adjusted EBITDA is one of the primary metrics used in our short-term incentive program for compensating employees. In addition, adjusted EBITDA is used as a ~~reconciliation~~supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to assess:

•the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;

•the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make cash distributions to our unitholders;

•our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing methods or capital structure; and

•the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

The GAAP measures most directly comparable to adjusted EBITDA are net income (loss) and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA may not be comparable to ~~gross~~similarly titled measures of other companies because other companies may not calculate adjusted EBITDA in the same manner.

Adjusted EBITDA does not include interest expense, net of interest income; income tax expense (benefit); and depreciation and amortization. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we have capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating ~~margin~~activities as determined under GAAP, as well as adjusted EBITDA, to evaluate our overall performance.

The following table reconciles net income to adjusted EBITDA (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Net income	$	116.6	$	32.3	$	306.5	$	54.3
Interest expense, net of interest income	60.4		60.1		171.0		180.1
Depreciation and amortization	162.6		153.0		474.5		455.9

Loss from unconsolidated affiliate investments	1.7		2.3		4.0		9.9
Distributions from unconsolidated affiliate investments	0.2		0.1		0.6		3.8
(Gain) loss on disposition of assets	(0.8)		(0.4)		3.9		(0.7)
Loss on extinguishment of debt	5.7		—		6.2		—
Unit-based compensation	11.4		6.4		23.7		19.3
Income tax expense	15.2		4.4		17.1		12.4
Unrealized (gain) loss on commodity swaps	(18.2)		1.2		(38.4)		32.9
Costs associated with the relocation of processing facilities (1)	9.7		8.8		32.1		26.6
Other (2)	(3.1)		(0.2)		(2.4)		(0.2)
Adjusted EBITDA before non-controlling interest	361.4		268.0		998.8		794.3
Non-controlling interest share of adjusted EBITDA from joint ventures (3)	(18.0)		(11.6)		(51.4)		(31.0)
Adjusted EBITDA, net to ENLC	$	343.4	$	256.4	$	947.4	$	763.3

____________________________

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Operating income (loss) $ 72.1
$ 65.9
197.5
$ (713.7 )

Add (deduct):
Operating expenses 102.1
98.0
308.8
296.3
General and administrative expenses 31.3
29.3
98.5
94.7
(Gain) loss on disposition of assets 1.1
(3.0 ) 0.8
(2.9 )
Depreciation and amortization 136.3
126.2
407.1
373.0
Impairments 1.8
—
8.8
873.3
Gain on litigation settlement —
—
(26.0 ) —
Gross operating margin $ 344.7
$ 316.4
$ 995.5
$ 920.7

~~Results~~(1)Represents cost incurred that are not part of ~~Operations~~

~~The table below sets forth certain financial and operating data for the periods indicated. We manage~~ our ongoing operations ~~by focusing on gross operating margin, which we define as revenue less cost of sales as reflected in the table below (in millions, except volumes):~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Texas Segment
Revenues $ 347.2
$ 280.2
$ 997.2
$ 767.4
Cost of sales (198.5 ) (134.1 ) (554.7 ) (329.0 )
Total gross operating margin $ 148.7
$ 146.1
$ 442.5
$ 438.4
Louisiana Segment
Revenues $ 738.5
$ 542.4
$ 2,021.0
$ 1,398.3
Cost of sales (662.7 ) (471.5 ) (1,803.1 ) (1,199.1 )
Total gross operating margin $ 75.8
$ 70.9
$ 217.9
$ 199.2
Oklahoma Segment
Revenues $ 244.4
$ 124.1
$ 583.1
$ 293.7
Cost of sales (148.2 ) (58.3 ) (335.9 ) (109.2 )
Total gross operating margin $ 96.2
$ 65.8
$ 247.2
$ 184.5
Crude and Condensate Segment
Revenues $ 308.6
$ 284.6
$ 973.1
$ 844.6
Cost of sales (279.1 ) (250.5 ) (884.1 ) (739.4 )
Total gross operating margin $ 29.5
$ 34.1
$ 89.0
$ 105.2
Corporate
Revenues $ (240.8 ) $ (126.7 ) $ (591.0 ) $ (276.5 )
Cost of sales 235.3
126.2
589.9
269.9
Total gross operating margin $ (5.5 ) $ (0.5 ) $ (1.1 ) $ (6.6 )
Total
Revenues $ 1,397.9
$ 1,104.6
$ 3,983.4
$ 3,027.5
Cost of sales (1,053.2 ) (788.2 ) (2,987.9 ) (2,106.8 )
Total gross operating margin $ 344.7
$ 316.4
$ 995.5
$ 920.7

Midstream Volumes:
Texas
Gathering and Transportation (MMBtu/d) 2,251,700
2,579,500
2,265,900
2,657,600
Processing (MMBtu/d) 1,194,300
1,172,200
1,178,800
1,188,100
Louisiana
Gathering and Transportation (MMBtu/d) 2,009,300
1,754,400
1,960,300
1,602,400
Processing (MMBtu/d) 443,400
487,900
452,500
496,400
NGL Fractionation (Gals/d) 5,814,800
5,259,400
5,630,600
5,194,700
Oklahoma
Gathering and Transportation (MMBtu/d) 889,200
624,500
787,400
620,300
Processing (MMBtu/d) 872,200
570,100
753,500
571,800
Crude and Condensate
Crude Oil Handling (Bbls/d) 95,700
72,800
104,500
98,300
Brine Disposal (Bbls/d) 4,800
3,700
4,700
3,500

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016~~

~~Gross Operating Margin.~~ Gross operating margin was $344.7 million for the three months ended September 30, 2017 compared to $316.4 million for the three months ended September 30, 2016, an increase of $28.3 million, or 8.9%, duerelated to the ~~following:~~

~~Texas Segment.~~ ~~Gross operating margin in~~relocation of equipment and facilities from the ~~Texas segment~~ ~~increased $2.6 million, which was primarily due to a $7.3 million increase from our Permian Basin~~Thunderbird processing ~~assets as a result of higher volumes. This increase was partially offset by a $2.4 million decrease due to volume declines across our north Texas assets~~plant and ~~a $2.0 million decrease due to the sale of the North Texas Pipeline (the “NTPL”) assets in December 2016.~~

~~Louisiana Segment.~~ ~~Gross operating margin in the Louisiana segment~~ ~~increased $4.9 million, which was primarily due to a $3.2 million increase from our gas~~Battle Ridge processing ~~and transmission assets as a result of volume increases and a $1.8 million increase from our NGL business partially due to the start-up of our Ascension JV assets in April 2017.~~

~~Oklahoma Segment.~~ ~~Gross operating margin~~plant in the Oklahoma segment ~~increased $30.4 million, which~~to the Permian segment. The relocation of equipment and facilities from the Battle Ridge processing plant was ~~primarily due to higher volumes on our central Oklahoma assets.~~

~~Crude and Condensate Segment.~~ ~~Gross operating margin~~completed in the ~~Crude~~third quarter of 2021 and ~~Condensate segment~~ ~~decreased $4.6 million, which was primarily due~~we completed the relocation of equipment and facilities from the Thunderbird processing plant in October 2022.

(2)Includes transaction costs, non-cash expense related to a $3.8 million decrease as a result of condensate stabilization volume declines and transportation rate decreases on our ORV assets, in addition to a $2.3 million decrease from volume declines for the Permian Basin trucking business. These decreases were partially offset by a $2.2 million increase due to the Greater Chickadee gathering system, which became fully operationalchanges in the ~~first quarter~~fair value of ~~2017.~~

~~Corporate Segment.~~ ~~Gross operating margin in the Corporate segment~~ decreased $5.0 million as a result of losses on derivative activity. For the three months ended September 30, 2017, there were unrealized losses of $3.3 million and realized losses of $2.2 million. For the three months ended September 30, 2016, there were unrealized losses of $1.6 million, partially offset by realized gains of $1.1 million.

Certain gathering and processing agreements in our Texas, Oklahoma and Crude and Condensate segments provide for a quarterly or annual minimum volume commitment (“MVC”). Under these agreements, our customers agree to ship and/or process a minimum volume of production on our systems over an agreed time period. If a customer under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under agreements with MVCs during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in the subsequent period.

~~Revenue recorded for the shortfall between actual production volumes and the MVC is as follows (in millions):~~

Texas Oklahoma Crude and Condensate Total
Three Months Ended
September 30, 2017
Midstream services $ —
$ 4.9
$ —
$ 4.9
Midstream services—related parties 15.9
4.0
3.1
23.0
Total $ 15.9
$ 8.9
$ 3.1
$ 27.9

September 30, 2016
Midstream services $ 0.4
$ 3.4
$ —
$ 3.8
Midstream services—related parties 7.7
4.4
5.2
17.3
Total $ 8.1
$ 7.8
$ 5.2
$ 21.1

~~Operating Expenses~~. Operating expenses were $102.1 million for the three months ended September 30, 2017 compared to $98.0 million for the three months ended September 30, 2016, an increase of $4.1 million, or 4.2%. The primary contributors to the total increase by segment were as follows (dollars in millions):

Three Months Ended
September 30, Change
2017 2016 $ %
Texas Segment $ 41.1
$ 42.9
$ (1.8 ) (4.2 )%
Louisiana Segment 24.8
23.5
1.3
5.5 %
Oklahoma Segment 17.1
12.6
4.5
35.7 %
Crude and Condensate Segment 19.1
19.0
0.1
0.5 %
Total $ 102.1
$ 98.0
$ 4.1
4.2 %

Operating expenses in the Oklahoma segment increased $4.5 million due to expanded operations, which resulted in increased labor and benefits charges and unit-based compensation expense due to increased headcount, as well as an increase in materials and supplies expense.

~~General and Administrative Expenses~~. General and administrative expenses were $31.3 million for the three months ended September 30, 2017 compared to $29.3 million for the three months ended September 30, 2016, an increase of $2.0 million, or 6.8%. The increase in general and administrative expenses was primarily due to $1.6 million of higher unit-based compensationcontingent consideration, accretion expense associated with ~~awards granted in 2017.~~asset retirement obligations and non-cash rent, which relates to lease incentives pro-rated over the lease term.

(3)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV and Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV.

~~Depreciation~~

Free Cash Flow After Distributions

We define free cash flow after distributions as adjusted EBITDA, net to ENLC, plus (less) (growth and ~~Amortization. Depreciation~~maintenance capital expenditures, excluding capital expenditures that were contributed by other entities and amortization expenses were $136.3 million for the three months ended September 30, 2017 compared to $126.2 million for the three months ended September 30, 2016, an increase of $10.1 million, or 8.0%. Of this increase, $4.5 million was attributablerelate to the ~~expansion~~non-controlling interest share of our ~~central Oklahoma assets; $4.3 million was attributable to the plant expansion~~consolidated entities); (interest expense, net of our Permian Basin processing assets; $1.2 million was attributable to the Greater Chickadee gathering system; and $0.7 million was attributable to the Ascension JV assets. These increases were partially offset by a $1.2 million decrease in depreciation expense attributable to the sale of NTPL in December 2016.

~~(Gain) Loss~~interest income); (distributions declared on ~~Disposition of Assets.~~ ~~Loss~~common units); (accrued cash distributions on disposition of assets was $1.1 million for the three months ended September 30, 2017 compared to a gain of $3.0 million for the three months ended September 30, 2016, a decrease of $4.1 million. The gain on disposition of assets for the three months ended September 30, 2016 was primarily due to the retirement of certain plant assets and asset dispositions that resulted in the receipt of proceeds greater than the carrying values of the assets.

~~Interest Expense~~. Interest expense was $49.6 million for the three months ended September 30, 2017 compared to $48.4 million for the three months ended September 30, 2016, an increase of $1.2 million, or 2.5%. Interest expense consisted of the following (in millions):

Three Months Ended
September 30,
2017 2016
ENLK senior notes $ 40.0
$ 35.1
ENLK Credit Facility 2.5
2.2
ENLC Credit Facility 0.6
0.3
Capitalized interest (1.1 ) (1.3 )
Amortization of debt issue costs and net discounts 7.5
13.6
Cash settlements on interest rate swaps —
(0.4 )
Other 0.1
(1.1 )
Total $ 49.6
$ 48.4

~~Income (Loss) from Unconsolidated Affiliate Investments.~~ Income from unconsolidated affiliate investments was $4.4 million for the three months ended September 30, 2017 compared to income of $1.1 million for the three months ended September 30, 2016, an increase of $3.3 million. This increase was primarily due to additional income from our GCF investment of $2.3 million for the three months ended September 30, 2017 as a result of higher fractionation revenues. In addition, for the three months ended September 30, 2016, income from unconsolidated affiliate investments included a loss of $1.1 million from our HEP investment, which was sold in March 2017.

~~Income Tax Benefit (Provision).~~ Income tax expense was $3.1 million for the three months ended September 30, 2017 compared to $7.6 million for the three months ended September 30, 2016, a decrease of $4.5 million. The decrease in income tax expense was primarily attributable to lower state income tax expense between periods. See “Item 1. Financial Statements—Note 7” for additional information.

~~Net Income (Loss) Attributable to Non-Controlling Interest.~~ Net income attributable to non-controlling interest was $17.9 million for the three months ended September 30, 2017 compared to net income of $10.4 million for the three months ended September 30, 2016, an increase of $7.5 million. This increase was primarily due to an increase in net income at ENLK and an increase in outstanding ENLK common units, Series B Preferred Units and Series C Preferred Units ~~that are not owned by ENLC.~~

~~Nine Months Ended September 30, 2017 Compared~~paid or expected to ~~Nine Months Ended September 30, 2016~~

~~Gross Operating Margin.~~ ~~Gross operating margin was $995.5 million for~~be paid); (costs associated with the ~~nine months ended September 30, 2017 compared~~relocation of processing facilities); non-cash interest (income)/expense; (contributions to ~~$920.7 million for the nine months ended September 30, 2016, an increase of $74.8 million, or 8.1%, due~~investment in unconsolidated affiliates); (payments to ~~the following:~~

~~Texas Segment.~~ ~~Gross operating margin in the Texas segment increased $4.1 million, which was primarily due to an $18.9 million increase~~terminate interest rate swaps); (current income taxes); and proceeds from our Permian Basin processing assets as a result of higher volumes. This increase was offset by a $14.8 million decrease from our North Texas processing, gathering and transmission assets due to volume declines across our system, including a $9.7 million decrease due to the sale of equipment and land.

Free cash flow after distributions is the ~~NTPL assets in December 2016.~~

~~Louisiana Segment.~~ ~~Gross operating margin in~~principal cash flow metric used by the ~~Louisiana segment increased $18.7 million, which was primarily due to a $10.0 million increase~~Company. Free cash flow after distributions is one of the primary metrics used in our ~~Louisiana gathering~~short-term incentive program for compensating employees. It is also used as a supplemental liquidity measure by our management and transmission assets due to additional volumes, a $3.8 million increase from our NGL transmission and fractionation assets due to additional NGL volumes received from our Oklahoma and Permian assets, and a $4.5 million increase due to the start-upby external users of our ~~Ascension JV assets during 2017.~~

~~Oklahoma Segment.~~ ~~Gross operating margin in~~financial statements, such as investors, commercial banks, research analysts, and others, to assess the Oklahoma segment increased $62.7 million, which was primarily due to a $68.4 million increase from our central Oklahoma assets as a result of higher volumes. This increase was partially offset by a $5.1 million decrease from our Northridge gathering and processing assets due to price and volume reductions under a third-party contract.

~~Crude and Condensate Segment.~~ Gross operating margin in the Crude and Condensate segment decreased $16.2 million, which was primarily due to a $10.2 million decrease as a result of condensate stabilization volume declines and transportation rate decreases on our ORV assets, in addition to a $7.9 million decrease as a result of volume declines for our Midland Basin trucking business. These declines were partially offset by a $4.0 million increase due to the Greater Chickadee gathering system becoming fully operational in the first quarter of 2017.

~~Corporate Segment.~~ Gross operating margin in the Corporate segment increased $5.5 million as a result of derivative activity. For the nine months ended September 30, 2017, there were unrealized gains of $3.8 million, offset by realized losses of $4.9 million. For the nine months ended September 30, 2016, there were unrealized losses of $16.0 million, partially offset by realized gains of $9.4 million.

~~Revenue recorded for the shortfall between actual production volumes and the MVC is as follows (in millions):~~

Texas Oklahoma Crude and Condensate Total
Nine Months Ended
September 30, 2017
Midstream services $ 0.8
$ 11.1
$ —
$ 11.9
Midstream services—related parties 42.1
12.0
5.9
60.0
Total $ 42.9
$ 23.1
$ 5.9
$ 71.9

September 30, 2016
Midstream services $ 1.6
$ 7.9
$ —
$ 9.5
Midstream services—related parties 16.5
4.2
5.2
25.9
Total $ 18.1
$ 12.1
$ 5.2
$ 35.4

~~Operating Expenses.~~ Operating expenses were $308.8 million for the nine months ended September 30, 2017 compared to $296.3 million for the nine months ended September 30, 2016, an increase of $12.5 million, or 4.2%. The primary contributors to the increase by segment were as follows (dollars in millions):

Nine Months Ended
September 30, Change
2017 2016 $ %
Texas Segment $ 127.9
$ 125.2
$ 2.7
2.2 %
Louisiana Segment 74.8
72.2
2.6
3.6 %
Oklahoma Segment 45.9
37.2
8.7
23.4 %
Crude and Condensate Segment 60.2
61.7
(1.5 ) (2.4 )%
Total $ 308.8
$ 296.3
$ 12.5
4.2 %

~~Texas Segment.~~ Operating expenses in the Texas segment increased $2.7 million primarily due to increased labor and benefits charges as a result of increased headcount and increased unit-based compensation expense, as well as increased operating costs from the Lobo II assets that went into service in the fourth quarter of 2016 as part of the Delaware Basin JV.

~~Louisiana Segment.~~ ~~Operating expenses in the Louisiana segment~~ ~~increased $2.6 million primarily due to increased regulatory, utilities, and materials and supplies expenses as a result of the start-up of the Ascension JV.~~

~~Oklahoma Segment.~~ Operating expenses in the Oklahoma segment increased $8.7 million primarily due to increased labor and benefits charges attributable to higher headcount and increased materials and supplies expense as a result of expanded operations.

~~General and Administrative Expenses~~. General and administrative expenses were $98.5 million for the nine months ended September 30, 2017 compared to $94.7 million for the nine months ended September 30, 2016, an increase of $3.8 million, or 4.0%. The primary contributors to the increase were as follows:

~~Unit-based compensation expense increased $10.8 million due to bonuses paid in the form of units that immediately vested in March 2017, as well as the accrual of annual bonuses for 2017.~~

We incurred $3.8 million of transaction costs and $1.5 million of transition service fees related to the EnLink Oklahoma T.O. acquisition for the nine months ended September 30, 2016, with no transaction costs incurred for the nine months ended September 30, 2017.

~~Salaries and wages expense decreased $1.9 million due to severance payments made during 2016.~~

~~Depreciation and Amortization.~~ Depreciation and amortization expenses were $407.1 million for the nine months ended September 30, 2017 compared to $373.0 million for the nine months ended September 30, 2016, an increase of $34.1 million, or 9.1%. Of this increase, $18.0 million was attributable to the plant expansionability of our ~~Permian Basin processing assets; $10.9 million was attributable~~assets to ~~the expansion of~~generate cash sufficient to pay interest costs, pay back our central Oklahoma assets; $3.7 million was attributable to the Greater Chickadee gathering system; $3.4 million was attributable to the acceleration of depreciation for some north Texas compressor stations decommissioned during 2017; $1.8 million was attributable to the Ascension JV assets; and the remaining increase was attributable to other assets placed in service. These increases were partially offset by a $3.5 million decrease in depreciation expense related to the sale of NTPL in December 2016.

~~(Gain) Loss on Disposition of Assets.~~ Loss on disposition of assets was $0.8 million for the nine months ended September 30, 2017 compared to a gain of $2.9 million for the nine months ended September 30, 2016, a decrease of $3.7 million. The gain on disposition for the nine months ended September 30, 2016 was due to the retirement of certain plant assets and asset dispositions that resulted in the receipt of proceeds greater than the carrying values of the assets.

~~Gain on Litigation Settlement.~~ ~~We recognized a gain on litigation settlement of $26.0 million for the nine months ended September 30, 2017. See “Item 1. Financial Statements—Note 15” for additional information.~~

~~Gain on Extinguishment of Debt.~~ We recognized a gain on extinguishment of debt of $9.0 million for the nine months ended September 30, 2017 due to the redemption of the 2022 Notes. See “Item 1. Financial Statements—Note 6” for additional information.

~~Impairments.~~ Impairment expense was $8.8 million for the nine months ended September 30, 2017 compared to $873.3 million for the nine months ended September 30, 2016, a decrease of $864.5 million. For the nine months ended September 30, 2017, we recognized impairments related to expired rights-of-way and an abandoned brine disposal well. For the nine months ended September 30, 2016, we recognized an impairment on goodwill of $566.3 million related to our Texas and Crude and Condensate segments, as well as $307.0 million related to our Corporate segment.

~~Interest Expense.~~ Interest expense was $142.2 million for the nine months ended September 30, 2017 compared to $138.9 million for the nine months ended September 30, 2016, an increase of $3.3 million, or 2.4%. Net interest expense consisted of the following (in millions):

Nine Months Ended
September 30,
2017 2016
ENLK senior notes $ 115.0
$ 95.1
ENLK Credit Facility 8.4
9.6
ENLC Credit Facility 1.5
0.7
Capitalized interest (5.1 ) (5.5 )
Amortization of debt issue cost and net discounts (premium) 21.9
39.8
Cash settlements on interest rate swaps —
(0.4 )
Mandatory redeemable non-controlling interest —
0.3
Other 0.5
(0.7 )
Total $ 142.2
$ 138.9

~~Income (Loss) from Unconsolidated Affiliate Investments.~~ Income from unconsolidated affiliate investments was $5.0 million for the nine months ended September 30, 2017 compared to a loss of $0.5 million for the nine months ended September 30, 2016, an increase of $5.5 million. The increase was primarily due to additional income of $7.4 million from our GCF investment for the nine months ended September 30, 2017 as a result of higher fractionation revenues and lower operating expenses.Partially offsetting this increase, income from our HEP investment decreased $1.8 million due to a $1.6 million loss for the nine months ended September 30, 2016 and a $3.4 million loss on sale for the nine months ended September 30, 2017.

~~Income Tax Benefit (Provision).~~ Income tax expense was $9.3 million for the nine months ended September 30, 2017 compared to income tax expense of $6.0 million for the nine months ended September 30, 2016, an increase of $3.3 million. The increase in income tax expense was primarily attributable to an increase in taxable income between periods. Additionally, $2.3 million was attributable to tax deficiencies on restricted incentive units that vested in March 2017. See “Item 1. Financial Statements—Note 7” for additional information.

~~Net Income (Loss) Attributable to Non-Controlling Interest.~~ Net income attributable to non-controlling interest was $50.3 million for the nine months ended September 30, 2017 compared to a net loss of $402.9 million for the nine months ended September 30, 2016, an increase of $453.2 million. This increase was primarily due to higher impairment expense at ENLK for the nine months ended September 30, 2016.

~~Critical Accounting Policies~~

~~Information regarding our Critical Accounting Policies is included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2016, except as described below.~~

~~Impairment of Goodwill~~. Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform a goodwill impairment test. We may elect to perform a goodwill impairment test without completing a qualitative assessment.

Prior to January 2017, if a goodwill impairment test was elected or required, we performed a two-step goodwill impairment test. The first step involved comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeded its fair value, the second step of the process involved comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeded the implied fair value of that goodwill, the excess of the carrying value over the implied fair value was recognized as an impairment loss.

~~In January 2017, the FASB issued ASU 2017-04,~~ ~~Intangibles~~—~~Goodwill and Other (Topic 350)~~—~~Simplifying the Test for Goodwill Impairment~~ (“ASU 2017-04”). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in Accounting Standards Codification (“ASC”) 350, ~~Intangibles~~—~~Goodwill and Other~~ (“ASC 350”). As a result, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. In January 2017, we elected to early adopt ASU 2017-04, and the adoption had no impact on our consolidated financial statements. We will perform future goodwill impairment tests according to ASU 2017-04.

Except for the items discussed above, the methodology and assumptions used to perform our goodwill assessments remains consistent with that described in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2016.

~~Liquidity and Capital Resources~~

~~Cash Flows from Operating Activities~~. Net cash provided by operating activities was $528.4 million for the nine months ended September 30, 2017 compared to $512.5 million for the nine months ended September 30, 2016. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):

Nine Months Ended September 30,
2017 2016
Operating cash flows before working capital $ 531.7
$ 469.1
Changes in working capital (3.3 ) 43.4

Operating cash flows before changes in working capital increased $62.6 million for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 primarily due to a $69.3 million increase in gross operating margin, excluding gains and losses on derivative activity, and a $26.0 million gain on litigation settlement, partially offset by a $21.2 million increase in interest expense, excluding amortization of debt issue costs and net discounts, and a $15.4 million decrease in cash received on derivative settlements. The changes in working capital for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 were primarily due to fluctuations in trade receivable and

~~payable balances due to timing of collection and payments and changes in inventory balances attributable to normal operating fluctuations.~~

~~Cash Flows from Investing Activities~~. Net cash used in investing activities was $475.3 million for the nine months ended September 30, 2017 and $1,203.6 million for the nine months ended September 30, 2016. Our primary investing cash flows were as follows (in millions):

Nine Months Ended September 30,
2017 2016
Growth capital expenditures $ (641.1 ) $ (404.4 )
Maintenance capital expenditures (21.4 ) (19.3 )
Acquisition of business, net of cash acquired —
(791.5 )
Investment in unconsolidated affiliates (11.8 ) (45.0 )
Proceeds from sale of unconsolidated affiliate investment 189.7
—
Distribution from unconsolidated affiliate investments in excess of earnings 7.3
51.6

Growth capital expenditures increased $236.7 million for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016. The increase was primarily due to capital expenditures related to the expansion of the central Oklahoma assets as well as expenditures for the Greater Chickadee crude oil gathering system in the Permian Basin and the Ascension JV assets in Louisiana.

~~Acquisition expenditures of $791.5 million for the nine months ended September 30, 2016 were for the EnLink Oklahoma T.O. acquisition.~~

Investment in unconsolidated affiliates decreased $33.2 million for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016. The decrease was primarily due to contributions of $45.0 million made to our HEP investment in 2016, including $32.7 million of contributions to HEP for preferred units. This decrease was partially offset by contributions to our Cedar Cove JV of $11.8 million in 2017.

Distributions from unconsolidated affiliates in excess of earnings decreased $44.3 million for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016. The decrease was primarily due to the redemption of our preferred units interest in our HEP investment for $32.7 million during the nine months ended September 30, 2016. The remaining difference was primarily due to decreased distributions following the sale of our HEP interest in March 2017.

~~In December 2016, we entered into an agreement to sell our ownership interest in HEP. We finalized the sale in March 2017 and received net proceeds of $189.7 million.~~

~~Cash Flows from Financing Activities~~. Net cash provided by financing activities was $77.1 million for the nine months ended September 30, 2017 and $733.2 million for the nine months ended September 30, 2016. Our primary financing activities consisted of the following (in millions):

Nine Months Ended September 30,
2017 2016
Net repayments on the ENLK Credit Facility $ (120.0 ) $ (339.2 )
Net borrowings on the ENLC Credit Facility 46.2
23.1
ENLK unsecured senior notes borrowings, net of notes extinguished 331.6
499.3
Proceeds from issuance of ENLK common units 92.3
110.6
Proceeds from issuance of ENLK Series B Preferred Units —
724.1
Proceeds from issuance of ENLK Series C Preferred Units 393.7
—
Contributions by non-controlling interest 46.2
151.5
Payment of installment payable for EnLink Oklahoma T.O. acquisition (250.0 ) —

On May 11, 2017, ENLK issued $500.0 million in aggregate principal amount of ENLK’s 5.450% senior unsecured notes due 2047 at a price to the public of 99.981% of their face value. Interest payments on the 2047 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2017. Net proceeds of approximately $495.2 million were used to repay outstanding borrowings under ENLK’s credit facility and for general partnership purposes. For the nine months ended September 30, 2017, ENLK redeemed $162.5 million in aggregate principal amount of the 2022 Notes at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174.1 million, which included payments for accrued interest of $5.8 million.

For the nine months ended September 30, 2017, ENLK sold an aggregate of 5.3 million common units under the 2014 EDA and 2017 EDA, generating proceeds of $92.3 million. For the nine months ended September 30, 2016, ENLK sold an aggregate of 6.7 million common units under the 2014 EDA, generating proceeds of $110.6 million.

~~In January 2016, ENLK issued an aggregate of 50,000,000 Series B Preferred Units for net proceeds of $724.1 million. See “Item 1. Financial Statements—Note 8” for additional information.~~

~~In September 2017, ENLK issued 400,000 Series C Preferred Units for net proceeds of $393.7 million. See “Item 1. Financial Statements—Note 8” for additional information.~~

For the nine months ended September 30, 2017, contributions by non-controlling interests included $43.9 million from NGP to the Delaware Basin JV and $2.3 million from Marathon Petroleum to the Ascension JV. For the nine months ended September 30, 2016, contributions by non-controlling interests included $137.7 million from NGP to the Delaware Basin JV and $13.7 million from Marathon Petroleum to the Ascension JV.

~~For the nine months ended September 30, 2017, ENLK paid $250.0 million for the second installment payable obligation related to the EnLink Oklahoma T.O. acquisition.~~

~~Distributions to unitholders and non-controlling interests represent a primary use of cash in financing activities. Total~~indebtedness, make cash distributions, ~~made for the nine months ended September 30, 2017~~ and ~~2016 were as follows (in millions):~~

Nine Months Ended September 30,
2017 2016
Distributions to members $ 139.5
$ 139.0
Distributions to non-controlling interests 306.9
284.3

Series B Preferred Unit distributions for 2016 and for the first two quarters for 2017 were paid in-kind by ENLK in the form of additional Series B Preferred Units. As these were non-cash distributions, they were not reflected in our financing cash flows for the nine months ended September 30, 2017 and 2016. Beginning with the quarter ended September 30, 2017, Series B Preferred Unit distributions are payable in cash (the “Cash Distribution Component”) at an amount per quarter equal to $0.28125 per Series B Preferred Unit plus an in-kind distribution equal to the greater of (a) 0.0025 Series B Preferred Units per Series B Preferred Unit and (b) an amount equal to (i) the excess, if any, of the distributions that would have been payable had the Series B Preferred Units converted into common units for that quarter over the Cash Distribution Component, divided by (ii) the issue price of $15.00.

~~Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15~~^th ~~day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15~~^th day of March, June, September and December of each year, in each case, if and when declared by ENLK’s general partner out of legally available funds for such purpose. The initial distribution rate for the Series C Preferred Units from and including the date of original issue to, but not including, December 15, 2022 is 6.0% per annum. On and after December 15, 2022, distributions on the Series C Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to an annual floating rate of the three-month LIBOR plus a spread of 4.11%.

If distributions are declared by ENLK’s Board of Directors, cash distributions for the Series B Preferred Units and the Series C Preferred Units will decrease our cash flows from financing activities beginning in the fourth quarter of 2017.

~~Capital Requirements. We consider a number of factors in determining whether our capital expenditures are growth capital expenditures or maintenance~~make capital expenditures.

Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that we expect will increase our asset base, operating income, or operating capacity over

the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, well connections, gathering, or processing assets, in each case, to the extent such capital expenditures are expected to expand our asset base, operating capacity, or our operating income.

Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines, gathering assets, well connections, compression assets, and processing assets up to their original operating capacity, or to maintain pipeline and equipment reliability, integrity, and safety, and to address environmental laws and regulations.

~~We expect~~The GAAP measure most directly comparable to free cash flow after distributions is net cash provided by operating activities. Free cash flow after distributions should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), net cash provided by operating activities, or any other measure of liquidity presented in accordance with GAAP. Free cash flow after distributions has important limitations because it excludes some items that affect net income (loss), operating income (loss), and net cash provided by operating activities. Free cash flow after distributions may not be comparable to similarly titled measures of other companies because other companies may not calculate this non-GAAP metric in the same manner. To compensate for these limitations, we believe that it is important to consider net cash provided by operating activities determined under GAAP, as well as free cash flow after distributions, to evaluate our ~~remaining 2017~~overall liquidity.

The following table reconciles net cash provided by operating activities to adjusted EBITDA and free cash flow after distributions (in millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Net cash provided by operating activities	$	343.3	$	197.0	$	825.9	$	599.2
Interest expense (1)	59.3		55.1		167.2		166.6
Utility credits (redeemed) earned (2)	(16.3)		(5.6)		(27.9)		38.2
Payments to terminate interest rate swaps (3)	—		0.5		—		1.8
Accruals for settled commodity swap transactions	(0.3)		(2.1)		(1.9)		(4.6)
Distributions from unconsolidated affiliate investment in excess of earnings	0.2		0.1		0.6		3.8
Costs associated with the relocation of processing facilities (4)	9.7		8.8		32.1		26.6
Other (5)	(0.1)		(0.2)		3.3		2.4
Changes in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories, and other	(54.3)		167.6		255.6		276.8
Accounts payable, accrued product purchases, and other accrued liabilities	19.9		(153.2)		(256.1)		(316.5)
Adjusted EBITDA before non-controlling interest	361.4		268.0		998.8		794.3
Non-controlling interest share of adjusted EBITDA from joint ventures (6)	(18.0)		(11.6)		(51.4)		(31.0)
Adjusted EBITDA, net to ENLC	343.4		256.4		947.4		763.3
Growth capital expenditures, net to ENLC (7)	(82.7)		(33.2)		(173.1)		(89.1)
Maintenance capital expenditures, net to ENLC (7)	(8.7)		(6.9)		(33.7)		(19.1)
Interest expense, net of interest income	(60.4)		(60.1)		(171.0)		(180.1)
Distributions declared on common units	(54.8)		(46.6)		(164.9)		(140.0)
ENLK preferred unit accrued cash distributions (8)	(23.3)		(23.0)		(70.1)		(69.0)
Costs associated with the relocation of processing facilities (4)	(9.7)		(8.8)		(32.1)		(26.6)
Contribution to investment in unconsolidated affiliates	(19.7)		—		(46.3)		—
Payments to terminate interest rate swaps	—		(0.5)		—		(1.8)
Non-cash interest expense	—		2.7		—		7.3
Other (9)	0.8		0.5		1.1		1.3
Free cash flow after distributions	$	84.9	$	80.5	$	257.3	$	246.2

____________________________

(1)Net of amortization of debt issuance costs, net discount of senior unsecured notes, and designated cash flow hedge, which are included in interest expense but not included in net cash provided by operating activities, and non-cash interest income, which is netted against interest expense but not included in adjusted EBITDA.

(2)Under our utility agreements, we are entitled to a base load of electricity and pay or receive credits, based on market pricing, when we exceed or do not use the base load amounts. Due to Winter Storm Uri, we received credits from our utility providers based on market rates for our unused electricity. These utility credits are recorded as “Other current assets” or “Other assets, net” on our consolidated balance sheets depending on the timing of their expected usage, and amortized as we incur utility expenses.

(3)Represents cash paid for the early termination of our interest rate swaps due to the partial repayment of the Term Loan in May 2021 and September 2021.

(4)Represents cost incurred that are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant and Battle Ridge processing plant in the Oklahoma segment to the Permian segment. The relocation of equipment and facilities from the Battle Ridge processing plant was completed in the third quarter of 2021 and we completed the relocation of equipment and facilities from the Thunderbird processing plant in October 2022.

(5)Includes transaction costs, current income tax expense, and non-cash rent, which relates to lease incentives pro-rated over the lease term.

(6)Non-controlling interest share of adjusted EBITDA from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV and Marathon Petroleum Corporation’s50% share of adjusted EBITDA from the Ascension JV.

(7)Excludes capital expenditures ~~including capital contributions to our unconsolidated affiliate investments, to be as follows (in millions):~~



	~~Remainder of~~
	~~2017~~
~~Growth Capital Expenditures~~
~~Texas segment~~	$	~~15 - 40~~
~~Louisiana segment~~		~~10 - 20~~
~~Oklahoma segment (1)~~		~~50 - 110~~
~~Crude and Condensate segment~~		~~0 - 0~~
~~Corporate segment~~		~~0 - 0~~
~~Total growth capital expenditures~~	$	~~75 - 170~~
~~Less: Growth capital expenditures funded by joint venture partners (2)~~		~~(6 - 12)~~
~~Growth capital expenditures, attributable to ENLC~~	$	~~69 - 158~~

~~Maintenance Capital Expenditures~~	$	~~17 - 27~~


~~(1)~~	~~Includes projected growth capital contributions related to our non-controlling interest share of the Cedar Cove JV.~~


~~(2)~~	~~Includes growth capital expenditures that will be~~that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities. These contributions include contributions by NGP to the Delaware Basin JV and contributions by Marathon Petroleum to the Ascension JV.

Our primary capital projects for the remainder of 2017 and 2018 include the construction of our Chisholm III plant expansion and the development of additional gathering and compression assets in Oklahoma and the Permian Basin. See “Recent Developments” for further details.

We expect to fund growth capital expenditures from the proceeds of borrowings under the ENLK Credit Facility discussed below and proceeds from other debt and equity sources, including capital contributions by joint venture partners that relate to the non-controlling interest share of our consolidated entities.

(8)Represents the cash distributions earned by the Series B Preferred Units and Series C Preferred Units. See “Item 1. Financial Statements—Note 8” for information on the cash distributions earned by holders of the Series B Preferred Units and Series C Preferred Units. Cash distributions to be paid to holders of the Series B Preferred Units and Series C Preferred Units are not available to common unitholders.

(9)Includes current income tax expense and proceeds from the sale of surplus or unused equipment and land, which occurred in the normal operation of our business.

Results of Operations

The tables below set forth certain financial and operating data for the periods indicated. We evaluate the performance of our consolidated operations by focusing on adjusted gross margin, while we evaluate the performance of our operating segments based on segment profit and adjusted gross margin, as reflected in the tables below (in millions, except volumes):


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Three Months Ended September 30, 2022
Gross margin	$	74.6	$	57.3	$	53.0	$	49.3	$	(1.2)	$	233.0
Depreciation and amortization	36.8		39.7		51.5		33.4		1.2		162.6
Segment profit	111.4		97.0		104.5		82.7		—		395.6
Operating expenses	49.7		37.6		23.5		26.0		—		136.8
Adjusted gross margin	$	161.1	$	134.6	$	128.0	$	108.7	$	—	$	532.4

Three Months Ended September 30, 2021
Gross margin	$	33.7	$	29.1	$	34.8	$	31.5	$	(2.2)	$	126.9
Depreciation and amortization	35.4		34.6		52.3		28.5		2.2		153.0
Segment profit	69.1		63.7		87.1		60.0		—		279.9
Operating expenses	37.3		30.5		19.8		19.3		—		106.9
Adjusted gross margin	$	106.4	$	94.2	$	106.9	$	79.3	$	—	$	386.8


	Permian		Louisiana		Oklahoma		North Texas		Corporate		Totals
Nine Months Ended September 30, 2022
Gross margin	$	185.9	$	161.9	$	134.2	$	122.1	$	(4.1)	$	600.0
Depreciation and amortization	110.6		114.6		154.7		90.5		4.1		474.5
Segment profit	296.5		276.5		288.9		212.6		—		1,074.5
Operating expenses	145.3		105.4		67.6		68.3		—		386.6
Adjusted gross margin	$	441.8	$	381.9	$	356.5	$	280.9	$	—	$	1,461.1

Nine Months Ended September 30, 2021
Gross margin	$	52.4	$	106.4	$	74.6	$	108.8	$	(6.0)	$	336.2
Depreciation and amortization	103.5		106.8		153.6		86.0		6.0		455.9
Segment profit	155.9		213.2		228.2		194.8		—		792.1
Operating expenses	52.9		91.4		57.3		58.4		—		260.0
Adjusted gross margin	$	208.8	$	304.6	$	285.5	$	253.2	$	—	$	1,052.1


	Three Months Ended September 30,		Nine Months Ended September 30,
	2022	2021	2022	2021
Midstream Volumes:
Permian Segment
Gathering and Transportation (MMbtu/d)	1,596,400	1,111,800	1,480,200	1,021,800
Processing (MMbtu/d)	1,520,800	1,062,800	1,404,100	966,500
Crude Oil Handling (Bbls/d)	157,700	157,500	161,200	129,400
Louisiana Segment
Gathering and Transportation (MMbtu/d)	2,996,100	2,013,900	2,731,900	2,101,000

Crude Oil Handling (Bbls/d)	18,500	17,600	17,400	16,000
NGL Fractionation (Gals/d)	7,930,200	7,050,500	7,953,300	7,295,100
Brine Disposal (Bbls/d)	3,000	3,300	3,100	2,500
Oklahoma Segment
Gathering and Transportation (MMbtu/d)	1,036,400	996,900	1,017,600	983,700
Processing (MMbtu/d)	1,067,600	1,004,400	1,048,400	999,900
Crude Oil Handling (Bbls/d)	21,500	20,000	22,200	20,400
North Texas Segment
Gathering and Transportation (MMbtu/d)	1,687,100	1,377,600	1,494,800	1,370,700
Processing (MMbtu/d)	776,700	627,900	684,900	626,700

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021

Gross Margin. Gross margin was $233.0 million for the three months ended September 30, 2022 compared to $126.9 million for the three months ended September 30, 2021, an increase of $106.1 million. The primary contributors to the increase were as follows:

•Permian Segment. Gross margin was $74.6 million for the three months ended September 30, 2022 compared to $33.7 million for the three months ended September 30, 2021, an increase of $40.9 million primarily due to the following:

◦Adjusted gross margin in the Permian segment increased $54.7 million, which was primarily driven by:

•A $50.9 million increase to adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased $50.8 million, which was primarily due to higher volumes from increased producer activity and higher commodity prices. Derivative activity associated with our Permian gas assets increased margin by $0.1 million, which included $7.7 million from decreased realized losses and $7.6 million from decreased unrealized gains.

•A $3.8 million increase to adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, increased $1.7 million, which was primarily due to higher commodity prices. Derivative activity associated with our Permian crude assets increased margin by $2.1 million, which included $2.3 million from increased realized gains and $0.2 million from increased unrealized losses.

◦Operating expenses in the Permian segment increased $12.4 million due to higher construction fees and services, labor and benefits costs, materials and supplies expense, utility costs, and compressor rentals due to an increase in operating activity and the transfer of equipment to the Phantom processing facilities in 2022.

◦Depreciation and amortization in the Permian segment increased $1.4 million primarily due to new assets placed into service.

•Louisiana Segment. Gross margin was $57.3 million for the three months ended September 30, 2022 compared to $29.1 million for the three months ended September 30, 2021, an increase of $28.2 million primarily due to the following:

◦Adjusted gross margin in the Louisiana segment increased $40.4 million, resulting from:

•An $15.1 million increase to adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, decreased $7.3 million, which was primarily due to fluctuations in market prices. Derivative activity associated with our Louisiana NGL transmission and fractionation assets increased margin by $22.4 million, which included $18.0 million from increased realized gains and $4.4 million from increased unrealized gains.

•A $25.8 million increase to adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased $18.0 million, which was primarily due to higher volumes from existing customers and higher commodity prices. Derivative activity associated with our Louisiana gas assets increased margin by $7.8 million, which included $0.6 million from increased realized losses and $8.4 million from decreased unrealized losses.

•A $0.5 million decrease to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, decreased $1.3 million, which was primarily due to fluctuation in market prices. Derivative activity associated with our ORV crude assets increased margin by $0.8 million from increased realized gains.

◦Operating expenses in the Louisiana segment increased $7.1 million primarily due to increases in materials and supplies expense, utility costs, construction fees and services, vehicle expenses, and ad valorem taxes due to an increase in operating activity.

◦Depreciation and amortization in the Louisiana segment increased $5.1 million primarily due to changes in estimated useful lives of certain non-core assets.

•Oklahoma Segment. Gross margin was $53.0 million for the three months ended September 30, 2022 compared to $34.8 million for the three months ended September 30, 2021, an increase of $18.2 million primarily due to the following:

◦Adjusted gross margin in the Oklahoma segment increased $21.1 million, resulting from:

•A $21.7 million increase to adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, increased $2.8 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Oklahoma gas assets increased margin by $18.9 million, which included $7.1 million from increased realized gains and $11.8 million from increased unrealized gains.

•A $0.6 million decrease to adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, decreased $0.9 million, which was primarily due to fluctuation in market prices. Derivative activity associated with our Oklahoma crude assets increased margin by $0.3 million from increased realized gains.

◦Operating expenses in the Oklahoma segment increased $3.7 million primarily due to increases in materials and supplies expense and construction fees and services due to an increase in operating activity. Operating expenses also increased due to the transfer of equipment related to the Phantom processing facility.

◦Depreciation and amortization in the Oklahoma segment decreased $0.8 million due to the transfer of equipment to the Phantom and Warhorse processing facilities, which was partially offset by additional assets placed into service.

•North Texas Segment. Gross margin was $49.3 million for the three months ended September 30, 2022 compared to $31.5 million for the three months ended September 30, 2021, an increase of $17.8 million primarily due to the following:

◦Adjusted gross margin in the North Texas segment increased $29.4 million. Adjusted gross margin, excluding derivative activity, increased $27.7 million, which was primarily due to the acquisition of Barnett Shale gathering and processing assets on July 1, 2022 and higher volumes from existing customers. Derivative activity associated with our North Texas segment increased margin by $1.7 million, which included $0.9 million from increased realized losses and $2.6 million from increased unrealized gains.

◦Operating expenses in the North Texas segment increased $6.7 million primarily due to increases in materials and supplies expense and ad valorem taxes due to an increase in operating activity and the acquisition of Barnett Shale gathering and processing assets on July 1, 2022.

◦Depreciation and amortization in the North Texas segment increased $4.9 million primarily due to the acquisition of Barnett Shale gathering and processing assets on July 1, 2022.

•Corporate Segment. Gross margin was negative $1.2 million for the three months ended September 30, 2022 compared to negative $2.2 million for the three months ended September 30, 2021. Corporate gross margin consists of depreciation and amortization of corporate assets.

General and Administrative Expenses. General and administrative expenses were $34.5 million for the three months ended September 30, 2022 compared to $28.2 million for the three months ended September 30, 2021, an increase of $6.3 million. The increase was primarily due to an increase in unit-based compensation and consulting fees and services. The increase was partially offset by a gain related to a decrease in the estimated fair value of the Amarillo Rattler Acquisition contingent consideration.

Interest Expense. Interest expense was $60.4 million for the three months ended September 30, 2022 compared to $60.1 million for the three months ended September 30, 2021, an increase of $0.3 million. Interest expense consisted of the following (in millions):


	Three Months Ended September 30,
	2022		2021
ENLK and ENLC Senior Notes	$	51.5	$	50.3
Term Loan	—		1.0
Revolving Credit Facility	4.4		1.3
AR Facility	3.6		1.0

Amortization of debt issuance costs and net discount of senior unsecured notes	1.1		1.4
Interest rate swaps - realized	—		5.0
Other	(0.2)		0.1
Total	$	60.4	$	60.1

Loss from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $1.7 million for the three months ended September 30, 2022 compared to a loss of $2.3 million for the three months ended September 30, 2021, a reduction in loss of $0.6 million. The reduction in loss was primarily attributable to a reduction in loss of $0.9 million from our GCF investment and was partially offset by an increase in loss of $0.3 million from the Matterhorn JV.

Income Tax Expense. Income tax expense was $15.2 million for the three months ended September 30, 2022 compared to an income tax expense of $4.4 million for the three months ended September 30, 2021. The increase in income tax expense was primarily attributable to the increase in income between periods. See “Item 1. Financial Statements—Note 7” for additional information.

Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $35.8 million for the three months ended September 30, 2022 compared to net income of $30.4 million for the three months ended September 30, 2021, an increase of $5.4 million. ENLC’s non-controlling interest is comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50% share of the Ascension JV. The increase in income was primarily due to a $6.8 million increase attributable to NGP’s 49.9% share of the Delaware Basin JV and was partially offset by a $0.6 million decrease attributable to Marathon Petroleum Corporation’s 50%

share of the Ascension JV and a $0.8 million decrease in income attributable to the Series B Preferred Units following the partial redemptions of the Series B Units in December 2021 and January 2022.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

Gross Margin. Gross margin was $600.0 million for the nine months ended September 30, 2022 compared to $336.2 million for the nine months ended September 30, 2021, an increase of $263.8 million. The primary contributors to the increase were as follows:

•Permian Segment. Gross margin was $185.9 million for the nine months ended September 30, 2022 compared to $52.4 million for the nine months ended September 30, 2021, an increase of $133.5 million primarily due to the following:

◦Adjusted gross margin in the Permian segment increased $233.0 million, which was primarily driven by:

•A $218.3 million increase to adjusted gross margin associated with our Permian gas assets. Adjusted gross margin, excluding derivative activity, increased $146.5 million, which was primarily due to higher volumes from increased producer activity and higher commodity prices. Derivative activity associated with our Permian gas assets increased margin by $71.8 million, which included $60.5 million from decreased realized losses and $11.3 million from increased unrealized gains.

•A $14.7 million increase to adjusted gross margin associated with our Permian crude assets. Adjusted gross margin, excluding derivative activity, increased $16.0 million, which was primarily due to higher volumes from increased producer activity. Derivative activity associated with our Permian crude assets decreased margin by $1.3 million, which included $2.0 million from decreased realized gains and $0.7 million from increased unrealized gains.

◦Operating expenses in the Permian segment increased $92.4 million. During the nine months ended September 30, 2021, our Permian operating expenses were reduced by $48.1 million due to electricity credits earned during Winter Storm Uri in February 2021 that were not available during the same period of 2022. Operating expenses also increased due to higher construction fees and services, labor and benefits costs, materials and supplies expense, compressor rentals, and ad valorem and sales and use taxes due to an increase in operating activity and the transfer of equipment to the Warhorse and Phantom processing facilities in 2022.

◦Depreciation and amortization in the Permian segment increased $7.1 million primarily due to new assets placed into service, including gathering and processing assets associated with the Amarillo Rattler Acquisition in April 2021.

•Louisiana Segment. Gross margin was $161.9 million for the nine months ended September 30, 2022 compared to $106.4 million for the nine months ended September 30, 2021, an increase of $55.5 million primarily due to the following:

◦Adjusted gross margin in the Louisiana segment increased $77.3 million, resulting from:

•A $43.6 million increase to adjusted gross margin associated with our Louisiana NGL transmission and fractionation assets. Adjusted gross margin, excluding derivative activity, increased $1.6 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Louisiana NGL transmission and fractionation assets increased margin by $42.0 million, which included $30.2 million from increased realized gains and $11.8 million from increased unrealized gains.

•An $34.3 million increase to adjusted gross margin associated with our Louisiana gas assets. Adjusted gross margin, excluding derivative activity, increased $20.2 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Louisiana gas assets increased margin by $14.1 million, which included $4.0 million from increased realized losses and $18.1 million from increased unrealized gains.

•A $0.6 million decrease to adjusted gross margin associated with our ORV crude assets. Adjusted gross margin, excluding derivative activity, increased $0.5 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our ORV crude assets decreased margin by $1.1 million from decreased unrealized gains.

◦Operating expenses in the Louisiana segment increased $14.0 million primarily due to increases in utility costs, construction fees and services, and compressor rentals due to an increase in operating activity. These increases were partially offset by decreases in consulting fees and services.

◦Depreciation and amortization in the Louisiana segment increased $7.8 million primarily due to changes in estimated useful lives of certain non-core assets.

•Oklahoma Segment. Gross margin was $134.2 million for the nine months ended September 30, 2022 compared to $74.6 million for the nine months ended September 30, 2021, an increase of $59.6 million primarily due to the following:

◦Adjusted gross margin in the Oklahoma segment increased $71.0 million, resulting from:

•A $73.6 million increase to adjusted gross margin associated with our Oklahoma gas assets. Adjusted gross margin, excluding derivative activity, increased $53.6 million, which was primarily due to higher volumes from existing customers, higher commodity prices, and the negative effect in 2021 of weather disruptions from Winter Storm Uri. Derivative activity associated with our Oklahoma gas assets increased margin by $20.0 million, which included $2.5 million from increased realized losses and $22.5 million from increased unrealized gains.

•A $2.6 million decrease to adjusted gross margin associated with our Oklahoma crude assets. Adjusted gross margin, excluding derivative activity, increased $0.6 million, which was primarily due to higher volumes from existing customers. Derivative activity associated with our Oklahoma crude assets decreased margin by $3.2 million, which included $0.7 million from increased realized losses and $2.5 million from decreased unrealized gains.

◦Operating expenses in the Oklahoma segment increased $10.3 million primarily due to increases in materials and supplies expense and construction fees and services due to an increase in operating activity. Operating expenses also increased due to the transfer of equipment to the Phantom processing facility.

◦Depreciation and amortization in the Oklahoma segment increased $1.1 million due to additional assets placed in service, partially offset by the transfer of equipment related to the Phantom and Warhorse processing facilities.

•North Texas Segment. Gross margin was $122.1 million for the nine months ended September 30, 2022 compared to $108.8 million for the nine months ended September 30, 2021, an increase of $13.3 million primarily due to the following:

◦Adjusted gross margin in the North Texas segment increased $27.7 million. Adjusted gross margin, excluding derivative activity, increased $21.0 million, which was primarily due to the acquisition of Barnett Shale gathering and processing assets on July 1, 2022. Derivative activity associated with our North Texas segment increased margin by $6.7 million, which included $3.8 million from increased realized losses and $10.5 million from increased unrealized gains.

◦Operating expenses in the North Texas segment increased $9.9 million primarily due to increases in materials and supplies expense, ad valorem taxes, and utility costs due to an increase in operating activity and the acquisition of Barnett Shale gathering and processing assets on July 1, 2022.

◦Depreciation and amortization in the North Texas segment increased $4.5 million primarily due to the acquisition of Barnett Shale gathering and processing assets on July 1, 2022, which was partially offset by assets reaching the end of their depreciable lives.

•Corporate Segment. Gross margin was negative $4.1 million for the nine months ended September 30, 2022 compared to negative $6.0 million for the nine months ended September 30, 2021. Corporate gross margin consists of depreciation and amortization of corporate assets.

General and Administrative Expenses. General and administrative expenses were $91.9 million for the nine months ended September 30, 2022 compared to $80.3 million for the nine months ended September 30, 2021, an increase of $11.6 million. The increase was primarily due to an increase in unit-based compensation, labor costs, and consulting fees and services. The increase was partially offset by a gain related to a decrease in the estimated fair value of the Amarillo Rattler Acquisition contingent consideration.

Interest Expense. Interest expense was $171.0 million for the nine months ended September 30, 2022 compared to $180.1 million for the nine months ended September 30, 2021, a decrease of $9.1 million. Interest expense consisted of the following (in millions):


	Nine Months Ended September 30,
	2022		2021
ENLK and ENLC Senior Notes	$	152.1	$	150.9
Term Loan	—		3.7
Revolving Credit Facility	8.9		4.0
AR Facility	6.4		3.0

Amortization of debt issuance costs and net discount of senior unsecured notes	3.7		3.9
Interest rate swaps - realized	0.1		14.6
Other	(0.2)		—
Total	$	171.0	$	180.1

Loss from Unconsolidated Affiliate Investments. Loss from unconsolidated affiliate investments was $4.0 million for the nine months ended September 30, 2022 compared to a loss of $9.9 million for the nine months ended September 30, 2021, a reduction in loss of $5.9 million. The reduction in loss was primarily attributable to a reduction in loss of $5.7 million from our GCF investment, as a result of the GCF assets being idled beginning in January 2021, and a reduction of loss of $0.5 million from the Cedar Cove JV. The reduction in loss was partially offset by an increase in loss of $0.3 million from the Matterhorn JV.

Income Tax Expense. Income tax expense was $17.1 million for the nine months ended September 30, 2022 compared to an income tax expense of $12.4 million for the nine months ended September 30, 2021. The increase in income tax expense was primarily attributable to the increase in income between periods and was partially offset by the changes in the valuation allowance. See “Item 1. Financial Statements—Note 7” for additional information.

Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $105.2 million for the nine months ended September 30, 2022 compared to net income of $86.7 million for the nine months ended September 30, 2021, an increase of $18.5 million. ENLC’s non-controlling interest is comprised of Series B Preferred Units, Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, and Marathon Petroleum Corporation’s 50% share of the Ascension JV. The increase in income was primarily due to a $20.2 million increase attributable to NGP’s 49.9% share of the Delaware Basin JV and was partially offset by a $0.1 million decrease attributable to Marathon Petroleum Corporation’s 50% share of the Ascension JV and a $1.6 million decrease in income attributable to the Series B Preferred Units following the partial redemptions of the Series B Units in December 2021 and January 2022.

Critical Accounting Policies

Information regarding our critical accounting policies is included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the Commission on February 16, 2022.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $825.9 million for the nine months ended September 30, 2022 compared to $599.2 million for the nine months ended September 30, 2021. Operating cash flows before working capital and changes in working capital for the comparative periods were as follows (in millions):


	Nine Months Ended September 30,
	2022		2021
Operating cash flows before working capital	$	825.4	$	559.5
Changes in working capital	0.5		39.7

Operating cash flows before changes in working capital increased $265.9 million for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021. The primary contributor to the increase in operating cash flows was as follows:

•Gross margin, excluding depreciation and amortization, non-cash commodity swap activity, utility credits redeemed or earned, and unit-based compensation, increased $273.7 million. The increase in gross margin is due to a $335.0 million increase in adjusted gross margin, excluding non-cash commodity swap activity, which was partially offset by a $61.3 million increase in operating expenses, excluding utility credits redeemed or earned and unit-based compensation. For more information regarding the changes in gross margin for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021, see “Results of Operations.”

The changes in working capital for the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021 were primarily due to fluctuations in trade receivable and payable balances due to timing of collection and payments, changes in inventory balances attributable to normal operating fluctuations, and fluctuations in accrued revenue and accrued cost of sales.

Cash Flows from Investing Activities. Net cash used in investing activities was $547.0 million for the nine months ended September 30, 2022 compared to $155.4 million for the nine months ended September 30, 2021. Our primary investing activities consisted of the following (in millions):


	Nine Months Ended September 30,
	2022		2021
Additions to property and equipment (1)	$	(213.2)	$	(104.7)
Contributions to unconsolidated affiliate investments (2)	(46.3)		—
Acquisitions, net of cash acquired (3)	(289.5)		(56.7)

____________________________

(1)The increase in capital expenditures was due to expansion projects to accommodate increased volumes on our systems.

(2)Represents contributions to the Matterhorn JV and GCF. See “Item 1. Financial Statements—Note 10” for more information regarding the contributions to unconsolidated affiliate investments.

(3)Represents cash paid for the acquisition of Barnett Shale assets in July 2022 and the Amarillo Rattler Acquisition in April 2021.

Cash Flows from Financing Activities. Net cash used in financing activities was $305.1 million for the nine months ended September 30, 2022 compared to $447.3 million for the nine months ended September 30, 2021. Our primary financing activities consisted of the following (in millions):


	Nine Months Ended September 30,
	2022		2021
Net repayments on the Term Loan	$	—	$	(200.0)
Net borrowings (repayments) on the AR Facility (1)	150.0		(5.0)
Net borrowings on the Revolving Credit Facility (1)	55.0		—
Net borrowings on ENLC’s senior unsecured notes (1)	700.0		—
Net repurchases of ENLK’s senior unsecured notes (1)	(738.5)		—
Payment of installment payable for Amarillo Rattler Acquisition (2)	(10.0)		—
Payment of inactive easement commitment (3)	(10.0)		—
Contributions from non-controlling interests (4)	14.2		2.4
Distributions to members	(167.4)		(140.4)
Redemption of Series B Preferred Units (5)	(50.5)		—
Distributions to Series B Preferred Unitholders (5)	(53.1)		(50.9)
Distributions to Series C Preferred Unitholders (5)	(12.0)		(12.0)
Distributions to joint venture partners (6)	(50.3)		(25.3)
Common unit repurchases (7)	(113.2)		(14.5)

____________________________

(1)See “Item 1. Financial Statements—Note 6” for more information regarding the AR Facility, the Revolving Credit Facility, and the issuance of new senior unsecured notes by us and repurchases of ENLK’s senior unsecured notes.

(2)Consideration for the Amarillo Rattler Acquisition included an installment payable, which was paid on April 30, 2022.

(3)Amount related to an inactive easement commitment, which was paid in August 2022.

(4)Represents contributions from NGP to the Delaware Basin JV.

(5)See “Item 1. Financial Statements—Note 8” for information on distributions to holders of the Series B Preferred Units and Series C Preferred Units and information on the partial redemption of the Series B Preferred Units.

(6)Represents distributions to NGP for its ownership in the Delaware Basin JV and distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV.

(7)See “Item 1. Financial Statements—Note 9” for more information regarding the ENLC common unit repurchase program.

Capital Requirements

As of September 30, 2022, the following table summarizes our expected remaining capital requirements for 2022 (in millions):


Capital expenditures, net to ENLC (1)	$	108
Operating expenses associated with the relocation of processing facilities (2)	13
Contributions to unconsolidated affiliate investments (3)	24
Total	$	145

____________________________

(1)Excludes capital expenditures that are contributed by other entities and relate to the non-controlling interest share of our consolidated entities.

(2)Represents cost incurred that are not part of our ongoing operations related to the relocation of equipment and facilities from the Thunderbird processing plant in the Oklahoma segment to the Permian segment. We completed the relocation of equipment and facilities from the Thunderbird processing plant in October 2022.

(3)Includes contributions made to our GCF investment and the Matterhorn JV.

Our primary remaining capital projects for 2022 include the relocation of the Phantom processing plant, which was completed in October 2022, CCS-related initiatives, contributions to unconsolidated affiliate investments, continued development of our existing systems through well connects, and other low-cost development projects. We expect to fund our ~~maintenance~~remaining 2022 capital ~~expenditures~~requirements from operating cash flows. ~~In 2017 and 2018, it~~

It is possible that not all of ~~the~~our planned projects will be commenced or completed. Our ability to pay distributions to our unitholders, to fund planned capital expenditures, and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in the industry, financial, business, and other factors, some of which are beyond our control.

Off-Balance Sheet ~~Arrangements. No~~Arrangements. We had no off-balance sheet arrangements ~~existed~~ as of September 30, ~~2017.~~2022.

Total Contractual Cash Obligations.A summary of our total contractual cash obligations as of September 30, ~~2017~~2022 is as follows (in millions):


	Payments Due by Period
	Total		Remainder 2022		2023		2024		2025		2026		Thereafter
ENLC’s & ENLK’s senior unsecured notes	$	4,009.2	$	—	$	—	$	97.9	$	421.6	$	491.0	$	2,998.7
Revolving Credit Facility (1)	70.0		—		—		—		—		—		70.0
AR Facility (2)	500.0		—		—		—		500.0		—		—
Acquisition contingent consideration (3)	4.4		—		—		0.2		0.1		4.1		—
Interest payable on fixed long-term debt obligations	2,498.0		59.1		215.8		213.5		202.6		193.8		1,613.2
Operating lease obligations	115.1		6.7		24.3		13.8		10.8		8.9		50.6
Purchase obligations	8.3		8.3		—		—		—		—		—
Pipeline and trucking capacity and deficiency agreements (4)	283.9		14.6		60.6		47.8		40.5		30.9		89.5
Total contractual obligations	$	7,488.9	$	88.7	$	300.7	$	373.2	$	1,175.6	$	728.7	$	4,822.0

____________________________

Payments Due by Period
Total Remainder 2017 2018 2019 2020 2021 Thereafter
Long-term debt obligations $ 3,500.0
$ —
$ —
$ 400.0
$ —
$ —
$ 3,100.0
ENLK Credit Facility —
—
—
—
—
—
—
ENLC Credit Facility 74.0
—
—
74.0
—
—
—
Interest payable on fixed long-term debt obligations 2,642.8
69.4
159.9
154.5
149.2
149.2
1,960.6
Capital lease obligations 4.9
0.4
1.5
1.5
1.5
—
—
Operating lease obligations 113.3
3.8
14.3
10.9
8.6
8.6
67.1
Purchase obligations 3.7
3.7
—
—
—
—
—
Delivery contract obligation 31.4
4.5
17.9
9.0
—
—
—
Pipeline capacity and deficiency agreements (1) 95.7
4.8
19.0
13.8
8.9
8.8
40.4
Inactive easement commitment (2) 10.0
—
—
—
—
—
10.0
Installment payable obligations (3) 250.0
—
250.0
—
—
—
—
Total contractual obligations $ 6,725.8
$ 86.6
$ 462.6
$ 663.7
$ 168.2
$ 166.6
$ 5,178.1
(1)The Revolving Credit Facility permits us to borrow up to $1.40 billion on a revolving credit basis and will mature on June 3, 2027.


~~(1)~~	~~Consists of pipeline capacity payments for firm transportation and deficiency agreements.~~


~~(2)~~	~~Amounts related to inactive easements paid as utilized by us with balance due in 2022 if not utilized.~~


~~(3)~~	~~Amounts relate to the final installment payable for the acquisition of the EnLink Oklahoma T.O. assets with a balance due on January 7, 2018.~~

(2)The AR Facility will terminate on August 1, 2025, unless extended or earlier terminated in accordance with its terms.

(3)The estimated fair value of the Amarillo Rattler Acquisition contingent consideration was calculated in accordance with the fair value guidance contained in ASC 820. There are a number of assumptions and estimates factored into these fair values and actual contingent consideration payments could differ from these estimated fair values. See “Item 1. Financial Statements—Note 13” for additional information.

(4)Consists of pipeline capacity payments for firm transportation and deficiency agreements.

The above table does not include any physical or financial contract purchase commitments for natural gas and NGLs due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material ~~amount.~~amount that is not already disclosed in the table above.

The interest payable ~~under~~related to the ~~ENLK~~Revolving Credit Facility and ~~ENLC credit facilities~~the AR Facility are not reflected in the above table because such amounts depend on the outstanding balances and interest rates of the Revolving Credit Facility and the AR Facility, which vary from time to time. However, given the same borrowing amount and rates in effect on September 30, 2017, the cash obligation for interest expense on the ENLC credit facility would be approximately $2.4 million per year, respectively, or approximately $0.6 million for the remainder of 2017.

In January 2017, we paid the $250.0 million installment payable obligation related to the EnLink Oklahoma T.O. acquisition, which was due on January 7, 2017. We funded this installment payment using various sources, including $84.6 million in proceeds received from the sale of NTPL, proceeds from equity issuances through the 2014 EDA and borrowings under the ENLK Credit Facility. Our contractual cash obligations for the remainder of ~~2017 and 2018~~2022 are expected to be funded from cash flows generated from our operations.

Indebtedness

As of September 30, 2022, the AR Facility had a borrowing base of $500.0 million and there were $500.0 million in outstanding borrowings under the AR Facility.

In addition, as of September 30, 2022, we have $4.0 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047. There were $70.0 million in outstanding borrowings and $46.6 million in outstanding letters of credit under the Revolving Credit Facility as of September 30, 2022.

Guarantees. The amounts outstanding on our senior unsecured notes and the Revolving Credit Facility are guaranteed in full by our subsidiary ENLK, including 105% of any letters of credit outstanding under the Revolving Credit Facility. ENLK’s guarantees of these amounts are full, irrevocable, unconditional, and absolute, and cover all payment obligations arising under the senior unsecured notes and the Revolving Credit Facility. Liabilities under the guarantees rank equally in right of payment with all existing and future senior unsecured indebtedness of ENLK.

ENLC’s assets consist of all of the outstanding common units of ENLK and all of the membership interests of the General Partner. Other than these equity interests, all of our assets and operations ~~with~~are held by our non-guarantor operating subsidiaries. ENLK, directly and indirectly, owns all of these non-guarantor operating subsidiaries, which in some cases are joint ventures that are partially owned by a third party. As a result, the ~~exception~~assets, liabilities, and results of ~~ENLK’s $250.0 million installment payable obligation due January 7, 2018~~operations of ENLK are not materially different than the corresponding amounts presented in our consolidated financial statements.

As of September 30, 2022, ENLC records, on a stand-alone basis, transactions that do not occur at ENLK, which are primarily related to the ~~acquisition~~taxation of ENLC and the ~~EnLink Oklahoma T.O. assets. We expect to fund payment~~elimination of ~~this installment obligation from the proceeds of borrowings under ENLK’s credit facility, proceeds from the issuance of equity or both of these alternatives.~~intercompany borrowings.

~~Indebtedness~~

See “Item 1. Financial Statements—Note 6” for more information on our outstanding ~~debt instruments.~~debt.

Inflation

The annual U.S. inflation rate has increased significantly in the first three quarters of 2022. The Federal Reserve has already increased its target for the federal funds rate (the benchmark for most interest rates) several times this year. It is widely expected that this trend will continue for the remainder of 2022. Inflation will increase the cost to acquire or replace property and equipment and the cost of labor and supplies. To the extent permitted by competition, regulation, and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees. Additionally, certain of our revenue generating contracts contain clauses that increase our fees based on changes in inflation metrics.

Recent Accounting Pronouncements

~~See “Item 1. Financial Statements—Note 2” for more information on~~We have reviewed recently issued accounting pronouncements that became effective during the three months ended September 30, 2022 and ~~adopted accounting pronouncements.~~have determined that none would have a material impact to our consolidated financial statements.

Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q ~~includes~~contains forward-looking statements within the meaning of the federal securities laws. ~~Statements~~Although these statements reflect the current views, assumptions and expectations of our management, the matters addressed herein involve certain assumptions, risks and uncertainties that could cause actual activities, performance, outcomes and results to differ materially from those indicated herein. Therefore, you should not rely on any of these forward-looking statements. All statements, other than statements of historical fact, included in this ~~report that are~~Quarterly Report constitute forward-looking statements, including, but not ~~historical facts are forward-looking statements. These~~limited to, statements ~~can be~~ identified by the ~~use of forward-looking terminology including~~words “forecast,” “may,” “believe,” “will,” ~~“expect,~~“should,” “plan,” “predict,” “anticipate,” “intend,” “estimate,” ~~“continue”~~“expect,” “continue,” and similar expressions. Such forward-looking statements include, but are not limited to, statements about future results and growth of our CCS business, when additional capacity will be operational, timing for completion of construction or expansion projects, results in certain basins, profitability, financial or leverage metrics, future cost savings or operational, environmental and climate change initiatives, our future capital structure and credit ratings, objectives, strategies, expectations, and intentions, the impact of the COVID-19 pandemic, the impact of weather related events on us and our financial results and operations, and other ~~similar words. These~~ statements ~~discuss future expectations, contain projections of~~that are not historical facts. Factors that could result in such differences or otherwise materially affect our financial condition, results of operations, or cash flows, include, without limitation, (a) the impact of the ongoing coronavirus (COVID-19) pandemic (including the impact of any new variants of the virus) on our business, financial condition, and results of operations, (b) potential conflicts of interest of GIP with us and the potential for GIP to favor GIP’s own interests to the detriment of our unitholders, (c) GIP’s ability to compete with us and the fact that it is not required to offer us the opportunity to acquire additional assets or ~~state~~businesses, (d) a default under GIP’s credit facility could result in a change in control of us, could adversely affect the price of our common units, and could result in a default or prepayment event under our credit facility and certain of our other ~~“forward-looking” information. Such statements reflect~~debt, (e) the dependence on our ~~current views~~significant customers for a substantial portion of the natural gas and crude that we gather, process, and transport, (f) developments that materially and adversely affect our significant customers or other customers, (g) adverse developments in the midstream business that may reduce our ability to make distributions, (h) competition for crude oil, condensate, natural gas, and NGL supplies and any decrease in the availability of such commodities, (i) decreases in the volumes that we gather, process, fractionate, or transport, (j) increasing scrutiny and changing expectations from stakeholders with respect to our environment, social, and governance practices, (k) our ability to receive or renew required permits and other approvals, (l) increased federal, state, and local legislation, and regulatory initiatives, as well as government reviews relating to hydraulic fracturing resulting in increased costs and reductions or delays in natural gas production by our customers, (m) climate change legislation and regulatory initiatives resulting in increased operating costs and reduced demand for the natural gas and NGL services we provide, (n) changes in the availability and cost of capital, including as a result of a change in our credit rating, (o) volatile prices and market demand for crude oil, condensate, natural gas, and NGLs that are beyond our control, (p) our debt levels could limit our flexibility and adversely affect our financial health or limit our flexibility to obtain financing and to pursue other business opportunities, (q) operating hazards, natural disasters, weather-related issues or delays, casualty losses, and other matters beyond our control, (r) reductions in demand for NGL products by the petrochemical, refining, or other industries or by the fuel markets, (s) impairments to goodwill, long-lived assets and equity method investments, (t) construction risks in our major development projects, (u) challenges we may face in connection with our strategy to enter into new lines of business related to the energy transition, and (v) the effects of existing and future ~~events based on what we believe are reasonable assumptions; however, such statements are subject to certain risks~~laws and governmental regulations, including environmental and climate change requirements and other uncertainties. In addition to the specific uncertainties, factors, and risks discussed above and elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth in Part ~~II,~~I, “Item 1A. Risk Factors” of ~~this report and in~~ our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2021 filed with the Commission on February 16, 2022 may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events, or otherwise.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Our primary market risk is the risk related to changes in the prices of natural gas, NGLs, condensate, and crude oil. In addition, we are also exposed to the risk of changes in interest rates on floating rate debt.

Comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the ~~U.S. Commodity Futures Trading Commission (“CFTC”)~~CFTC to regulate certain markets for derivative products, including ~~over-the-counter (“OTC”)~~OTC derivatives. The CFTC has issued several ~~new~~ relevant regulations, and other rulemakings are pending at the CFTC, the product of which would be rules that ~~mandate that certain~~implement the mandates in the legislation to cause significant portions of derivatives ~~products be subject~~markets to ~~margin requirements, cleared at a clearinghouse or executed on an exchange.~~clear through clearinghouses. While some of these rules have been finalized, some have not, and, as a result, the final form and timing of the implementation of the ~~new~~ regulatory regime affecting commodity derivatives remains uncertain.

In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The CFTC’s original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. The CFTC has withdrawn its appeal of the court order vacating the original position limits rule. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In December 2016, the CFTC modified and reproposed its positions limits rules. The CFTC has sought comment on the position limits rule as reproposed, but these new position limit rules are not yet final and the impact of those provisions on us is uncertain at this time.

The legislation and potential new regulations may also require counterparties to our derivative instruments to spin off or result in such counterparties spinning off some of their ~~derivatives~~derivative activities to separate entities, which may not be as creditworthy as the current counterparties. The ~~new~~ legislation and any ~~future~~ new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

Commodity Price Risk

We are also subject to ~~significant~~direct risks due to fluctuations in commodity prices. While approximately 90% of our adjusted gross margin for the nine months ended September 30, 2022 was generated from arrangements with fee-based structures with minimal direct commodity price exposure, the remainder is subject to more direct commodity price exposure. Our exposure to these ~~risks~~commodity price fluctuations is primarily in the gas processing component of our business. We currently ~~process gas~~earn adjusted gross margin under four main types of contractual arrangements (or a combination of these types of contractual arrangements) as summarized below. ~~Approximately 86%~~

1.Fee-based contracts. Under fee-based contracts, we earn our fees through (1) stated fixed-fee arrangements in which we are paid a fixed fee per unit of ~~our processing margins were~~volume or (2) arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin through a fee-like deduction subtracted from ~~fixed-fee based~~the purchase price of the commodities.

2.Processing margin contracts. Under these contracts, we pay the producer for the ~~nine months ended September 30, 2017.~~


1.	~~Processing margin contracts:~~ ~~Under these contracts, we pay the producer for the~~ full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas ~~to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas~~

as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction, or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when margins are negative primarily through our ability to bypass processing when it is not profitable for us or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications. For the nine months ended September 30, 2022, less than 1% of our adjusted gross margin was generated from processing margin contracts.

~~Percent of liquids contracts:~~ Under these contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, our margins from these contracts are greater during periods of high liquids prices. Our margins from processing cannot become negative under percent of liquids contracts, but they do decline during periods of low liquids prices.

~~Percent of proceeds contracts:~~ Under these contracts, we receive a fee as a portion of the proceeds of the sale of natural gas and liquids. Therefore, our margins from these contracts are greater during periods of high natural gas and liquids prices. Our margins from processing cannot become negative under percent of proceeds contracts, but they do decline during periods of low natural gas and liquids prices.


4.	~~Fixed-fee based contracts:~~ ~~Under these contracts, we have no direct commodity price exposure and are paid a fixed fee per unit of volume that is processed.~~

3.POL contracts. Under these contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, our margins from these contracts are greater during periods of high liquids prices. Our margins from processing cannot become negative under POL contracts, but they do decline during periods of low liquids prices.

4.POP contracts. Under these contracts, we receive a fee in the form of a portion of the proceeds of the sale of natural gas and liquids. Therefore, our margins from these contracts are greater during periods of high natural gas and liquids prices. Our margins from processing cannot become negative under POP contracts, but they do decline during periods of low natural gas and liquids prices.

For the nine months ended September 30, 2022, approximately 10% of our adjusted gross margin was generated from POL or POP contracts.

Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a risk management committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas, crude and condensate, and NGLs using ~~over-the-counter~~OTC derivative financial instruments with only certain well-capitalized counterparties ~~that~~which have been approved byin accordance with our commodity risk management ~~committee.~~policy.

We have hedged our exposure to fluctuations in prices for natural gas, NGLs, and ~~NGL~~crude oil volumes produced for our account. We hedge our exposure based on volumes we consider hedgeable (volumes committed under contracts that are long term in nature) versus total volumes that include volumes that may fluctuate due to contractual terms, such as contracts with month-to-month processing options. Further, we have tailored our hedges to generally match the ~~NGL~~ product composition and the ~~NGL and natural gas~~ delivery points to those of our physical equity volumes. The ~~NGL~~ hedges cover specific ~~NGL~~ products based upon our expected equity ~~NGL~~ composition.

We manage our exposure to changes in commodity prices by hedging the impact of market fluctuations. Commodity swaps are used both to manage and hedge price and location risk related to these market exposures and to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of NGLs, natural gas, and crude and condensate. The following table presents the relevant pricing index for each commodity:


Commodity						Index
NGLs						Oil Price Information Service
Natural gas						Henry Hub Gas Daily
Crude and condensate						New York Mercantile Exchange

The following table sets forth certain information related to derivative instruments outstanding at September 30, 2017 mitigating the risks associated with the gas processing and fractionation components of our business. The relevant payment index price for liquids is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by OPIS. The relevant index price for natural gas is Henry Hub Gas Daily, as defined by the pricing dates in the swap contracts.

Period Underlying Notional Volume We Pay We Receive (1) Fair Value
Asset/(Liability)
(In millions)
October 2017 - September 2018 Ethane 341 (MBbls) $0.2857/gal Index $ (0.1 )
October 2017 - September 2018 Propane 537 (MBbls) Index $0.6583/gal (4.0 )
October 2017 - September 2018 Normal Butane 344 (MBbls) Index $0.7749/gal 1.3
October 2017 - September 2018 Natural Gasoline 79 (MBbls) Index $1.1270/gal (0.3 )
October 2017 - October 2018 Natural Gas 85,392 (MMBtu/d) Index $3.0561/MMBtu 0.7
December 2017 Condensate 90 (Mbbls) Index $50.90/bbl (0.1 )
$ (2.5 )

2022.

~~(1)~~Period

~~Weighted average.~~

Underlying

Notional Volume

We Pay

We Receive (1)

Net Fair Value
Asset/(Liability)
(In millions)

October 2022 - September 2023

Ethane

720 (Mbbls)

Index

$0.3930/Gal

3.9

October 2022 - September 2023

Propane

1,680 (Mbbls)

Index

$0.8613/Gal

16.6

October 2022 - June 2023

Normal butane

355 (Mbbls)

Index

$0.9710/Gal

3.6

October 2022 - October 2022

Natural gasoline

120 (Mbbls)

Index

$1.6891/Gal

0.3

October 2022 - September 2023

Natural gas

126,379 (MMbtu/d)

Index

$6.4518/MMbtu

(5.0)

October 2022 - January 2024

Crude and condensate

4,650 (Mbbls)

Index

$76.61/Bbl

4.5

23.9

____________________________

(1)Weighted average.

Another price risk we face is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. We enter each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves us with short or long positions that must be covered. We use financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against unfavorable changes in such prices.

As of September 30, ~~2017,~~2022, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments ~~were~~had a net fair value ~~liability~~asset of ~~$2.5~~$23.9 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas, crude and condensate, and NGL prices would result in a change of approximately ~~$1.7~~$15.0 million in the net fair value of these contracts as of September 30, ~~2017.~~2022.

Interest Rate Risk

We are exposed to interest rate risk ~~from~~on the ~~ENLC~~Revolving Credit Facility and the ~~ENLK~~AR Facility. Amounts drawn on the Revolving Credit ~~Facility.~~Facility and the AR Facility bear interest at rates based on SOFR. At September 30, ~~2017, the ENLC Credit Facility~~2022, we had ~~$74.0~~$70.0 million in outstanding borrowings ~~and~~under the ~~ENLK~~Revolving Credit Facility ~~had no~~and $500.0 million in outstanding ~~borrowings.~~borrowings under the AR Facility. A 1%1.0% increase or decrease in interest rates would change ~~the annual~~our annualized interest expense ~~for the ENLC Credit Facility~~ by approximately $0.7 million and $5.0 million for the ~~year.~~Revolving Credit Facility and AR Facility, respectively.

We are not exposed to changes in interest rates with respect to ENLK’s senior unsecured notes due in ~~2019,~~ 2024, 2025, 2026, 2044, 2045, or 2047 or our senior unsecured notes due in 2028, 2029, and 2030 as these are fixed-rate obligations. ~~The~~As of September 30, 2022, the estimated fair value of ~~ENLK’s~~the senior unsecured notes was approximately ~~$3,564.7~~$3,502.5 million, ~~as of September 30, 2017,~~ based on the market prices of ~~similar~~ENLK’s and our publicly traded debt at September 30, ~~2017.~~2022. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1%1.0% in interest rates. Such an increase in interest rates would result in an approximate ~~$291.7~~$209.8 million decrease in fair value of ~~ENLK’s~~the senior unsecured notes at September 30, ~~2017.~~2022. See “Item 1. Financial Statements—Note 6” for more information on our outstanding indebtedness.

Beginning on December 15, 2022, distributions on ENLK's Series C Preferred Units will be based on a floating rate tied to LIBOR (or an alternative rate to be established) plus 4.11% rather than a fixed rate and, therefore, the amount paid by ENLK as a distribution will be more sensitive to changes in interest rates.

Item 4. Controls and Procedures


~~(a)~~	~~Evaluation of Disclosure Controls and Procedures~~

a.Evaluation of Disclosure Controls and Procedures

Management of the Managing Member is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for us. We carried out an evaluation, under the supervision and with the participation of ~~our~~ management, including the Chief Executive Officer and Chief Financial Officer of ~~EnLink Midstream Manager, LLC,~~the Managing Member, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report (September 30, ~~2017)~~2022), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the ~~Securities~~ Exchange Act ~~of 1934~~ is recorded, processed, summarized, and reported within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including ~~the~~our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding ~~required~~ disclosure.


~~(b)~~	~~Changes in Internal Control Over Financial Reporting~~

b.Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting that occurred in the three months ended September 30, ~~2017~~2022 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.

For a discussion of certain litigation and similar proceedings, ~~see “Item 1.~~please refer to Note 16, “Commitments and Contingencies,” of the Notes to Consolidated Financial ~~Statements—Note 15.”~~Statements contained in Part I of this Quarterly Report on Form 10-Q, which is incorporated by reference herein.

Item 1A. Risk Factors

Information about risk factors does not differ materially from that set forth in Part I, ~~Item 1A~~“Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, ~~2016, except for~~2021 filed with the ~~new risk factor set forth below.~~Commission on February 16, 2022.

~~Our business is subject to a number~~

Item 2. Unregistered Sales of ~~weather-related risks. These weather conditions can cause significant damage~~Equity Securities and ~~disruption to our operations and adversely impact our financial condition, results~~Use of ~~operations or cash flows~~.Proceeds

~~Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods, fires and earthquakes. In particular, south Louisiana and~~During the Gulf of Mexico experience hurricanes and other extreme weather conditions on a frequent basis. The location of our significant assets and concentration of activity in these regions make us particularly vulnerable to weather risks in these areas.

High winds, storm surge, flooding and other natural disasters can cause significant damage and curtail our operations for extended periods during and after such weather conditions, which may result in decreased revenues and otherwise adversely impact our financial condition, results of operations or cash flow. These interruptions could involve significant damage to people, property or the environment, and repair time and costs could be extensive. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our members and, accordingly, adversely affect our financial condition and the market price of our securities.

~~In addition,~~three months ended September 30, 2022, we ~~rely on the volumes of natural gas, crude oil, condensate and NGLs gathered, processed, fractionated and transported on our assets. These volumes are influenced by the production~~re-acquired ENLC common units from the regions that supply our systems. Adverse weather conditions can cause direct or indirect disruptions to the operations of, and otherwise negatively affect, producers, suppliers, customers and other third parties to which our assets are connected, even if our assets are not damaged. As a result, our financial condition, results of operations and cash flows could be adversely affected.

We may also suffer reputational damage as a result of a natural disaster or other similar event. The occurrence of such an event, or a series of such events, especially if one or more of them occurs in a highly populated or sensitive area, could negatively impact public perception of our operations and/or make it more difficult for us to obtain the approvals, permits, licenses or real property interests we needcertain employees in order to ~~operate~~satisfy the employees’ tax liability in connection with the vesting of restricted incentive units and we repurchased common units in open market transactions and from GIP in connection with our ~~assets~~common unit repurchase program.


Period	Total Number of Units Purchased (1)	Average Price Paid Per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs (2)	Maximum Dollar Value of Units that May Yet Be Purchased under the Plans or Programs (in millions) (2)
July 1, 2022 to July 31, 2022	904,782	$	8.60	901,800	$	141.5
August 1, 2022 to August 31, 2022	3,742,405	9.64		3,533,555	$	107.4
September 1, 2022 to September 30, 2022	2,750,481	9.69		2,146,778	$	86.8
Total	7,397,668	$	9.53	6,582,133

____________________________

(1)The total number of units purchased shown in the table includes 815,535 ENLC common units received by us from employees for the payment of personal income tax withholding on vesting transactions.

(2)Effective January 1, 2022, the Board reauthorized our common unit repurchase program and reset the amount available for repurchases of outstanding common units at up to $100.0 million. In July 2022, the Board increased the amount available for repurchase to $200.0 million. Future repurchases under the program may be made from time to time in open market or ~~complete planned growth projects.~~private transactions and may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act. The repurchases will depend on market conditions and may be discontinued at any time. For more information regarding common units repurchased from public unitholders and our repurchase of common units held by GIP, see “Item 1. Financial Statements—Note 9.”

Item 6. Exhibits

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):


Number						Description

~~Number~~				~~Description~~
3.1					—	Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-4, filed with the Commission on November 20, 2013, file No. 333-192419).
3.2					—	Certificate of Amendment to Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.2 to Amendment No. 2 to our Registration Statement on Form S-4, filed with the Commission on January 21, 2014, file No. 333-192419).
3.3					—	~~First~~Second Amended and Restated Operating Agreement of EnLink Midstream, LLC, dated as of ~~March 7, 2014~~January 25, 2019 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated ~~March 7, 2014,~~January 25, 2019, filed with the Commission on ~~March 11, 2014,~~January 29, 2019, file No. 001-36336).
3.4					—	Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.12 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, ~~2014)~~2014, filed with the Commission on August 6, 2014, file No. 001-36336).
3.5					—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.13 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, ~~2014)~~2014, filed with the Commission on August 6, 2014, file No. 001-36336).
3.6					—	~~First~~Second Amended and Restated Limited Liability Company Agreement of EnLink Midstream Manager, LLC, dated as of July 18, 2018 (incorporated by reference to Exhibit ~~3.14~~3.1 to our ~~Quarterly~~Current Report on Form ~~10-Q for~~8-K dated July 17, 2018, filed with the ~~quarterly period ended June 30, 2014)~~Commission on July 23, 2018, file No. 001-36336).
3.7					—	Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.7 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).
3.8					—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.12 to EnLink Midstream Partners, LP’s Registration Statement on Form S-3, filed with the Commission on March 10, 2014, file No. 333-194465).
3.9					—	Fourth Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of July 18, 2018 (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K dated July 17, 2018, filed with the Commission on July 23, 2018, file No. 001-36366).
3.10					—	Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, filed with the Commission on August 7, 2012, file No. 333-97779).
~~3.8~~3.11					—	Certificate of Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, filed with the Commission on August 7, 2012, file No. 000-50067).
~~3.9~~3.12					—	Second Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, ~~2014)~~2014, file No. 001-36340).
~~3.10~~3.13					—	Third Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to ~~our~~EnLink Midstream Partners, LP’s Current Report on Form 8-K dated June 16, 2017, filed with the Commission on June 19, 2017, file No. 001-36340).
~~3.11~~3.14					—	~~Ninth~~Tenth Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of ~~September 21, 2017~~January 25, 2019 (incorporated by reference to Exhibit ~~3.1~~3.2 to our Current Report on Form 8-K dated ~~September 21, 2017,~~January 25, 2019, filed with the Commission on ~~September 21, 2017,~~January 29, 2019, file No. ~~001-36340)~~001-36336).
~~3.12~~4.1					—	~~Certificate~~Indenture, dated as of ~~Formation of~~August 31, 2022, by and among EnLink Midstream, ~~GP,~~ LLC, as issuer, EnLink Midstream Partners, LP, as guarantor, and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit ~~3.7~~4.1 to ~~EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).~~
~~3.13~~	—	Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.12 to EnLink Midstream Partners, LP’s Registration Statement on Form S-3, file No. 333-194465).
~~3.14~~	—	~~Third Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of July 7, 2014 (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s~~our Current Report on Form 8-K dated ~~July 7, 2014,~~August 31, 2022, filed with the Commission on ~~July 7, 2014,~~August 31, 2022, file No. ~~001-36340)~~001-36336).
~~3.15~~
















10.1					—	~~Amendment No. 1 to Third~~ Amended and Restated ~~Limited Liability Company~~Revolving Credit Agreement, ~~of EnLink Midstream GP, LLC,~~ dated as of ~~January 7, 2016~~June 3, 2022, by and among EnLink Midstream, LLC, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and each of the Lenders and other L/C Issuers party thereto (incorporated by reference to Exhibit ~~3.2~~10.1 to ~~EnLink Midstream Partners, LP’s~~our Current Report on Form 8-K dated ~~January 12, 2016,~~June 3, 2022, filed with the Commission on ~~January 12, 2016,~~June 6, 2022, file No. ~~001-36340).~~001-36336)
10.2					—	Third Amendment to the Receivables Financing Agreement, dated as of August 1, 2022, by and among EnLink Midstream Funding, LLC, as borrower, EnLink Midstream Operating, LP, as initial servicer, PNC Bank, National Association, as administrative agent and as lender and PNC Capital Markets LLC, as structuring agent and sustainability agent (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2022, filed with the Commission on August 4, 2022, file No. 001-36336).
10.3 *			†		—	EnLink Midstream, LLC 2023 Deferred Compensation Plan.
22.1 *					—	Subsidiary Guarantors.
31.1 *					—	Certification of the Principal Executive Officer.
31.2 *					—	C~~Certification~~ertification of the Principal Financial Officer.
32.1 *					—	Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350.
101 *			—		—	The following financial information from EnLink Midstream, LLC's Quarterly Report on Form 10-Q for the quarter ended September 30, ~~2017,~~2022, formatted in ~~XBRL (eXtensible~~iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of September 30, ~~2017~~2022 and December 31, ~~2016,~~2021, (ii) Consolidated Statements of Operations for the three and nine months ended September 30, ~~2017~~2022 and ~~2016,~~2021, (iii) Consolidated Statements of Changes in Members’ Equity for the three ~~and nine~~ months ended September 30, ~~2017,~~2022 and 2021, June 30, 2022 and 2021, and March 31, 2022 and 2021, (iv) Consolidated Statements of Cash Flows for the ~~three and~~ nine months ended September 30, ~~2017~~2022 and ~~2016,~~2021, and (v) the ~~notes~~Notes to Consolidated Financial Statements.
104 *					—	Cover Page Interactive Data File (formatted as Inline iXBRL and included in Exhibit 101).


*	~~Filed herewith.~~

____________________________

* Filed herewith.

† As required by Item 15(a)(3), this Exhibit is identified as a management contract or compensatory plan or arrangement.