UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

ý Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended ~~September 30, 2017~~March 31, 2019

¨ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission file number: 001-36336

ENLINK MIDSTREAM, LLC

(Exact name of registrant as specified in its charter)



Delaware	46-4108528
(State of organization)	(I.R.S. Employer Identification No.)

1722 ~~ROUTH ST.~~Routh St., ~~SUITE~~Suite 1300
~~DALLAS, TEXAS~~Dallas, Texas	75201
(Address of principal executive offices)	(Zip Code)

(214) 953-9500

(Registrant’s telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE SECURITIES EXCHANGE ACT OF 1934:



Title of Each Class	Name of Exchange on which Registered	Symbol
Common Units Representing Limited	The New York Stock Exchange	ENLC
Liability Company Interests

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate website, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting ~~company”~~company,” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act. (Check one):



Large accelerated filer	ý	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	¨

~~(Do not check if a smaller reporting company)~~		Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No ý

As of ~~October 26, 2017,~~April 25, 2019, the Registrant had ~~180,589,927~~487,170,379 common units outstanding.

TABLE OF CONTENTS

DEFINITIONS

The following terms as defined are used in ~~the energy industry and in~~ this document:

~~/d = per day~~

~~Bbls = barrels~~

~~Bcf = billion cubic feet~~

~~Gal = gallon~~

~~Mcf = thousand cubic feet~~

~~MMBtu = million British thermal units~~

~~MMcf = million cubic feet~~

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



Defined Term		Definition
/d		Per day.
2014 Plan		EnLink Midstream, LLC’s 2014 Long-Term Incentive Plan.
AMZ		Alerian MLP Index for Master Limited Partnerships.
ASC		The FASB Accounting Standards Codification.
ASC 842		ASC 842, Leases, a new accounting standard effective January 1, 2019 related to the accounting for lease agreements.
Ascension JV		Ascension Pipeline Company, LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Marathon Petroleum Corporation in which ENLK owns a 50% interest and Marathon Petroleum Corporation owns a 50% interest. The Ascension JV, which began operations in April 2017, owns an NGL pipeline that connects ENLK’s Riverside fractionator to Marathon Petroleum Corporation’s Garyville refinery.
ASU		The FASB Accounting Standards Update.
Avenger		Avenger crude oil gathering system, a crude oil gathering system in the northern Delaware Basin.
Bbls		Barrels.
Bcf		Billion cubic feet.
Cedar Cove JV		Cedar Cove Midstream LLC, a joint venture between a subsidiary of ENLK and a subsidiary of Kinder Morgan, Inc. in which ENLK owns a 30% interest and Kinder Morgan, Inc. owns a 70% interest. The Cedar Cove JV, which was formed in November 2016, owns gathering and compression assets in Blaine County, Oklahoma, located in the STACK play.
CFTC		U.S. Commodity Futures Trading Commission.
CNOW		Central Northern Oklahoma Woodford Shale.
Consolidated Credit Facility		A $1.75 billion unsecured revolving credit facility entered into by ENLC that matures on January 25, 2024, which includes a $500.0 million letter of credit subfacility. The Consolidated Credit Facility was available upon closing of the Merger and is guaranteed by ENLK.
Delaware Basin JV		Delaware G&P LLC, a joint venture between a subsidiary of ENLK and an affiliate of NGP in which ENLK owns a 50.1% interest and NGP owns a 49.9% interest. The Delaware Basin JV, which was formed in August 2016, owns the Lobo processing facilities located in the Delaware Basin in Texas.
Devon		Devon Energy Corporation.
Enfield		Enfield Holdings, L.P.
ENLC		EnLink Midstream, LLC.
ENLC Class C common Units		A class of non-economic ENLC common units issued to Enfield immediately prior to the Merger equal to the number of Series B Preferred Units of ENLK held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC.
ENLC Credit Facility		A $250.0 million secured revolving credit facility entered into by ENLC that would have matured on March 7, 2019, which included a $125.0 million letter of credit subfacility. The ENLC Credit Facility was terminated on January 25, 2019 in connection with the consummation of the Merger.
ENLC EDA		Equity Distribution Agreement entered into by ENLC in February 2019 with RBC Capital Markets, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., BMO Capital Markets Corp., Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, J.P. Morgan Securities LLC, Jefferies LLC, Mizuho Securities USA LLC, MUFG Securities Americas Inc., SunTrust Robinson Humphrey, Inc., and Wells Fargo Securities, LLC (collectively, the “Sales Agents”) to sell up to $400.0 million in aggregate gross sales of ENLC common units from time to time through an “at the market” equity offering program.
ENLK		EnLink Midstream Partners, LP or, when applicable, EnLink Midstream Partners, LP together with its consolidated subsidiaries. Also referred to as the “Partnership.”
ENLK Credit Facility		A $1.5 billion unsecured revolving credit facility entered into by ENLK that would have matured on March 6, 2020, which included a $500.0 million letter of credit subfacility. The ENLK Credit Facility was terminated on January 25, 2019 in connection with the consummation of the Merger.
EOGP		EnLink Oklahoma Gas Processing, LP or EnLink Oklahoma Gas Processing, LP together with, when applicable, its consolidated subsidiaries. As of January 31, 2019, EOGP is wholly-owned by the Operating Partnership.
FASB		Financial Accounting Standards Board.
GAAP		Generally accepted accounting principles in the United States of America.
Gal		Gallons.
GCF		Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas. ENLK owns 38.75% of GCF.



General Partner		EnLink Midstream GP, LLC, the general partner of ENLK, which owns a 0.4% general partner interest in ENLK. Prior to the effective time of the Merger, the General Partner also owned all of the incentive distribution rights in 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.
GIP Transaction		On July 18, 2018, subsidiaries of Devon closed a transaction to sell all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP.
GP Plan		EnLink Midstream GP, LLC’s Long-Term Incentive Plan.
Greater Chickadee		Crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin.
Gross Operating Margin		A non-GAAP financial measure. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures” for the definition and other information.
ISDAs		International Swaps and Derivatives Association Agreements.
Mcf		Thousand cubic feet.
Merger		On January 25, 2019, NOLA Merger Sub merged with and into ENLK with ENLK continuing as the surviving entity and a subsidiary of ENLC.
Merger Agreement		The Agreement and Plan of Merger, dated as of October 21, 2018, by and among ENLK, the General Partner, ENLC, the managing member of ENLC, and NOLA Merger Sub related to the Merger.
MMbbls		One million barrels.
MMbtu		Million British thermal units.
MMcf		Million cubic feet.
MVC		Minimum volume commitment.
NGL		Natural gas liquid.
NGP		NGP Natural Resources XI, LP.
NOLA Merger Sub		NOLA Merger Sub, LLC, previously a wholly-owned subsidiary of ENLC prior to the Merger.
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 in west Texas and New Mexico.
POL contracts		Percentage-of-liquids contracts.
POP contracts		Percentage-of-proceeds contracts.
Series B Preferred Units		ENLK’s Series B Cumulative Convertible Preferred Units.
Series C Preferred Units		ENLK’s Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units.
STACK		Sooner Trend Anadarko Basin Canadian and Kingfisher Counties in Oklahoma.
Term Loan		An $850.0 million term loan 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 guarantees.
Thunderbird Plant		A gas processing plant in central Oklahoma.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(In millions, except unit data)


	September 30, 2017			December 31, 2016		March 31, 2019			December 31, 2018
	(Unaudited)					(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	141.9		$	11.7	$	0.7		$	100.4
Accounts receivable:
Trade, net of allowance for bad debt of $0.1 and $0.1, respectively	42.5			63.9
Trade, net of allowance for bad debt of $0.5 and $0.3, respectively						104.2			126.3
Accrued revenue and other	432.4			369.6		634.2			705.9
Related party	121.5			100.2		0.4			0.7
Fair value of derivative assets	4.6			1.3		8.7			28.6
Natural gas and NGLs inventory, prepaid expenses and other	73.4			33.5
Investment in unconsolidated affiliates—current	—			193.1
Natural gas and NGLs inventory, prepaid expenses, and other						73.4			74.2
Total current assets	816.3			773.3		821.6			1,036.1
Property and equipment, net of accumulated depreciation of $2,428.5 and $2,124.1, respectively	6,568.8			6,256.7
Property and equipment, net of accumulated depreciation of $3,080.1 and $2,967.4, respectively						6,975.4			6,846.7
Intangible assets, net of accumulated amortization of $453.1 and $422.2, respectively						1,342.7			1,373.6
Goodwill						1,123.7			1,310.2
Investment in unconsolidated affiliates						82.9			80.1
Fair value of derivative assets	0.1			—		4.6			4.1
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		155.9			43.3
Total assets	$	10,548.3		$	10,275.9	$	10,506.8		$	10,694.1
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	65.2		$	69.2	$	103.4		$	105.5
Accounts payable to related party	36.8			10.4		2.6			4.3
Accrued gas, NGLs, condensate and crude oil purchases	376.6			333.3
Accrued gas, NGLs, condensate, and crude oil purchases						492.6			500.4
Fair value of derivative liabilities	7.2			7.6		6.6			21.8
Installment payable, net of discount of $7.0 and $0.5, respectively	243.0			249.5
Current maturities of long-term debt						—			399.8
Other current liabilities	235.2			217.5		230.6			248.2
Total current liabilities	964.0			887.5		835.8			1,280.0
Long-term debt	3,540.5			3,295.3		4,475.6			4,031.0
Asset retirement obligations	14.0			13.5		15.0			14.8
Installment payable, net of discount of $26.3 at December 31, 2016	—			223.7
Other long-term liabilities	38.7			42.5		89.5			20.0
Deferred tax liability	550.2			542.6		—			362.4
Fair value of derivative liabilities						0.2			2.4

Redeemable non-controlling interest	4.6			5.2		7.2			9.3

Members’ equity:
Members’ equity (180,586,977 and 180,049,316 units issued and outstanding, respectively)	1,763.5			1,880.9
Members’ equity (487,160,080 and 181,309,981 units issued and outstanding, respectively)						3,471.1			1,730.9
Accumulated other comprehensive loss	(2.0		)	—		(2.0		)	(2.0		)
Non-controlling interest	3,674.8			3,384.7		1,614.4			3,245.3
Total members’ equity	5,436.3			5,265.6		5,083.5			4,974.2
Commitments and contingencies (Note 15)
Total liabilities and members’ equity	$	10,548.3		$	10,275.9	$	10,506.8		$	10,694.1

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,						Three Months Ended March 31,
	2017			2016			2017			2016			2019			2018
	(Unaudited)												(Unaudited)
Revenues:
Product sales	$	1,056.7		$	771.0		$	2,973.9		$	2,097.8		$	1,530.9		$	1,499.2
Product sales—related parties	35.3			43.1			107.3			99.3			—			3.6
Midstream services	136.4			125.7			395.7			348.5			246.5			92.2
Midstream services—related parties	175.0			165.3			507.6			488.5			—			166.2
Loss on derivative activity	(5.5		)	(0.5		)	(1.1		)	(6.6		)
Gain on derivative activity													1.8			0.5
Total revenues	1,397.9			1,104.6			3,983.4			3,027.5			1,779.2			1,761.7
Operating costs and expenses:
Cost of sales (1)	1,053.2			788.2			2,987.9			2,106.8			1,363.4			1,381.5
Operating expenses	102.1			98.0			308.8			296.3			114.5			109.2
General and administrative	31.3			29.3			98.5			94.7			51.4			27.5
(Gain) loss on disposition of assets	1.1			(3.0		)	0.8			(2.9		)
Loss on disposition of assets													—			0.1
Depreciation and amortization	136.3			126.2			407.1			373.0			152.1			138.1
Impairments	1.8			—			8.8			873.3			186.5			—
Gain on litigation settlement	—			—			(26.0		)	—
Total operating costs and expenses	1,325.8			1,038.7			3,785.9			3,741.2			1,867.9			1,656.4
Operating income (loss)	72.1			65.9			197.5			(713.7		)	(88.7		)	105.3
Other income (expense):
Interest expense, net of interest income	(49.6		)	(48.4		)	(142.2		)	(138.9		)	(49.6		)	(44.5		)
Gain on extinguishment of debt	—			—			9.0			—
Income (loss) from unconsolidated affiliates	4.4			1.1			5.0			(0.5		)
Income from unconsolidated affiliates													5.3			3.0
Other income	0.3			0.1			0.5			0.1			—			0.3
Total other expense	(44.9		)	(47.2		)	(127.7		)	(139.3		)	(44.3		)	(41.2		)
Income (loss) before non-controlling interest and income taxes	27.2			18.7			69.8			(853.0		)	(133.0		)	64.1
Income tax provision	(3.1		)	(7.6		)	(9.3		)	(6.0		)	(1.8		)	(7.0		)
Net income (loss)	24.1			11.1			60.5			(859.0		)	(134.8		)	57.1
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:
Net income attributable to non-controlling interest													41.5			44.7
Net income (loss) attributable to ENLC													$	(176.3	)	$	12.4
Net income (loss) attributable to ENLC per unit:
Basic common unit	$	0.03		$	—		$	0.06		$	(2.54	)	$	(0.45	)	$	0.07
Diluted common unit	$	0.03		$	—		$	0.06		$	(2.54	)	$	(0.45	)	$	0.07

____________________________


(1)	Includes related party cost of sales of $~~47.3~~8.1 million and $~~33.7 million~~ ~~for the three months ended~~ ~~September 30, 2017~~ ~~and~~ ~~2016, respectively, and~~ ~~$126.9 million~~ ~~and~~ ~~$126.0~~34.1 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 and ~~and2016~~2018, ~~respectively.~~respectively.

See accompanying notes to consolidated financial statements.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of ~~Comprehensive Income (Loss)~~Changes in Members’ Equity

Three Months Ended March 31, 2019

(In millions)

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 )



	Common Units				Accumulated Other Comprehensive Loss			Non-Controlling Interest			Total			Redeemable Non-Controlling Interest (Temporary Equity)
	$			Units	$			$			$			$
	(Unaudited)
Balance, December 31, 2018	$	1,730.9		181.3	$	(2.0	)	$	3,245.3		$	4,974.2		$	9.3
Adoption of ASC 842	0.3			—	—			—			0.3			—
Balance, January 1, 2019	1,731.2			181.3	(2.0		)	3,245.3			4,974.5			9.3
Conversion of restricted units for common units, net of units withheld for taxes	(5.6		)	1.0	—			(2.8		)	(8.4		)	—
Unit-based compensation	12.2			—	—			1.4			13.6			—
Contributions from non-controlling interests	—			—	—			15.7			15.7			—
Distributions	(51.0		)	—	—			(127.6		)	(178.6		)	—
Fair value adjustment related to redeemable non-controlling interest	2.5			—	—			—			2.5			(2.1		)
Net income (loss)	(176.3		)	—	—			41.5			(134.8		)	—
Issuance of common units for ENLK public common units related to the Merger	1,958.1			304.9	—			(1,559.1		)	399.0			—
Balance, March 31, 2019	$	3,471.1		487.2	(2.0		)	$	1,614.4		$	5,083.5		$	7.2

See accompanying notes to consolidated financial statements.

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity (Continued)

Three Months Ended March 31, 2018

(In millions)



	Common Units				Accumulated Other Comprehensive Loss			Non-Controlling Interest			Total			Redeemable Non-Controlling Interest (Temporary Equity)
	$			Units	$			$			$			$
	(Unaudited)
Balance, December 31, 2017	$	1,924.2		180.6	$	(2.0	)	$	3,634.5		$	5,556.7		$	4.6
Issuance of common units by ENLK	—			—	—			0.9			0.9			—
Conversion of restricted units for common units, net of units withheld for taxes	(2.9		)	0.4	—			—			(2.9		)	—
Non-controlling interest’s impact of conversion of restricted units	—			—	—			(2.7		)	(2.7		)	—
Unit-based compensation	4.4			—	—			4.4			8.8			—
Change in equity due to issuance of units by ENLK	(1.3		)	—	—			1.7			0.4			—
Contributions from non-controlling interests	—			—	—			22.7			22.7			—
Distributions	(47.5		)	—	—			(121.2		)	(168.7		)	—
Net income	12.4			—	—			44.7			57.1			—
Balance, March 31, 2018	$	1,889.3		181.0	$	(2.0	)	$	3,585.0		$	5,472.3		$	4.6

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~~Cash Flows

(In millions)



	Three Months Ended March 31,
	2019			2018
	(Unaudited)
Cash flows from operating activities:
Net income (loss)	$	(134.8	)	$	57.1
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments	186.5			—
Depreciation and amortization	152.1			138.1
Non-cash unit-based compensation	11.1			5.1
Gain on derivatives recognized in net income (loss)	(1.8		)	(0.5		)
Cash settlements on derivatives	4.6			3.1
Amortization of debt issue costs, net discount (premium) of notes	1.8			1.6
Non-cash lease expense	1.6			—
Distribution of earnings from unconsolidated affiliates	2.2			4.6
Income from unconsolidated affiliates	(5.3		)	(3.0		)
Other operating activities	(1.2		)	6.1
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue, and other	93.8			(64.2		)
Natural gas and NGLs inventory, prepaid expenses, and other	3.6			9.2
Accounts payable, accrued product purchases, and other accrued liabilities	(50.2		)	36.5
Net cash provided by operating activities	264.0			193.7
Cash flows from investing activities:
Additions to property and equipment	(241.5		)	(181.5		)
Other investing activities	0.5			2.2
Net cash used in investing activities	(241.0		)	(179.3		)
Cash flows from financing activities:
Proceeds from borrowings	630.0			800.5
Payments on borrowings	(581.4		)	(428.6		)
Payment of installment payable for EOGP acquisition	—			(250.0		)
Debt financing costs	(5.6		)	—
Proceeds from issuance of ENLK common units	—			0.9
Distribution to members	(51.0		)	(47.5		)
Distributions to non-controlling interests	(127.6		)	(121.2		)
Contributions by non-controlling interests	15.7			22.7
Other financing activities	(2.8		)	(5.2		)
Net cash used in financing activities	(122.7		)	(28.4		)
Net decrease in cash and cash equivalents	(99.7		)	(14.0		)
Cash and cash equivalents, beginning of period	100.4			31.2
Cash and cash equivalents, end of period	$	0.7		$	17.2

Supplemental disclosures of cash flow information:
Cash paid for interest	$	23.8		$	15.5
Non-cash investing activities:
Non-cash accrual of property and equipment	$	9.5		$	(0.3	)

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

~~Consolidated Statements of Cash Flows~~

~~(In millions)~~

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 )

~~See accompanying notes to consolidated financial statements.~~

~~ENLINK MIDSTREAM, LLC~~ AND SUBSIDIARIES

Notes to Consolidated Financial Statements

~~September 30, 2017~~March 31, 2019

(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 LPPartnership and ~~EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”). EnLink Oklahoma T.O. is sometimes used~~EOGP.

Please read the notes to ~~refer~~the consolidated financial statements in conjunction with the Definitions page set forth in this report prior to ~~EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP together with its consolidated subsidiaries.~~Part I—Financial Information.


(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~~Transfer 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:EOGP Interest

~~88,528,451 common units representing an aggregate 21.8%~~On January 31, 2019, ENLC transferred its 16.1% limited partner interest in ~~ENLK;~~EOGP to the Operating Partnership in exchange for 55,827,221 ENLK common units, resulting in the Operating Partnership owning 100% of the limited partner interests in EOGP.

~~100.0% ownership interest~~Simplification of the Corporate Structure

On October 21, 2018, ENLK, ENLC, the General Partner, the managing member of ENLC, and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the surviving entity and as a subsidiary of ENLC. As a result of the Merger:

Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) was converted into 1.15 ENLC common units, which resulted in ~~EnLink Midstream Partners GP, LLC,~~ the ~~general partner~~issuance of 304,822,035 ENLC common units.

The General Partner’s incentive distribution rights in ENLK ~~(the “General Partner”), which owns a 0.4% general partner interest~~were eliminated.

The Series B Preferred Units continue to be issued and outstanding, except that certain terms of the Series B Preferred Units have been modified pursuant to an amended partnership agreement of ENLK. See “Note 8—Certain Provisions of the Partnership Agreement” for additional information regarding the modified terms of the Series B Preferred Units.

ENLC issued to Enfield, the current holder of the Series B Preferred Units, for no additional consideration, ENLC Class C Common Units equal to the number of Series B Preferred Units held by Enfield immediately prior to the effective time of the Merger, in order to provide Enfield with certain voting rights with respect to ENLC. For each additional Series B Preferred Unit issued by ENLK in quarterly in-kind distributions, ENLC will issue an additional ENLC Class C Common Unit to the applicable holder of such Series B Preferred Unit. In addition, for each Series B Preferred Unit that is exchanged into an ENLC common unit, an ENLC Class C Common Unit will be canceled.

The Series C Preferred Units and all of ENLK’s then-existing senior notes continue to be issued and outstanding following the Merger.

Each unit-based award issued and outstanding immediately prior to the effective time of the Merger under the GP Plan and the 2014 Plan has been converted into an award with respect to ENLC common units with substantially similar terms as were in effect immediately prior to the effective time.

Each unit-based award with performance-based vesting conditions issued and outstanding immediately prior to the effective time of the Merger under the GP Plan has been modified such that the performance metric for such award relates (on a weighted average basis) to (i) the combined performance of ENLC and ENLK for periods preceding the

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

effective time of the Merger and (ii) the performance of ENLC for periods on and after the effective time of the Merger.

ENLC assumed the outstanding debt under the Term Loan and ENLK became a guarantor thereof. See “Note 6—Long-Term Debt” for additional information regarding the Term Loan.

We refinanced our existing revolving credit facilities at ENLK and ENLC. In connection with the Merger, we entered into the Consolidated Credit Facility, with respect to which ENLK is a guarantor. See “Note 6—Long-Term Debt” for additional information regarding the Consolidated Credit Facility.

We were required to allocate the goodwill in our Corporate reporting unit previously associated with the incentive distribution rights in ~~ENLK;~~ENLK granted to the General Partner which were created at the formation of ENLC in 2014, to the Permian, North Texas, Oklahoma, and Louisiana reporting units, which resulted in the recognition of a goodwill impairment of $186.5 million. See “Note 3—Goodwill and Intangible Assets” for more information on this transaction.

~~16% limited partner interest~~We reduced our deferred tax liability (“DTL”) by $399.0 million related to ENLC’s step-up in ~~EnLink Oklahoma T.O.~~basis of ENLK’s underlying assets with the offsetting credit in members’ equity. See “Note 7—Income Taxes” for more information on the DTA.


(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~~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 Texas and from our 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 Texas and 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.

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. While our transactions vary in form, the essential element of 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, truck, or rail terminal.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(2) Significant Accounting Policies


(a)	Basis of Presentation

The accompanying consolidated financial statements are 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, 2018. All significant intercompany balances and transactions have been eliminated in consolidation.


(b)	~~Adopted Accounting Standards~~Revenue Recognition

~~In March 2016,~~Minimum Volume Commitments and Firm Transportation Contracts

Certain of our gathering and processing agreements provide for quarterly or annual MVCs. Under these agreements, our customers or suppliers agree to ship and/or process a minimum volume of product on our systems over an agreed time period. If a customer or supplier under such an agreement fails to meet its MVC for a specified period, the ~~Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-09,~~ ~~Compensation~~—~~Stock Compensation (Topic 718): Improvements~~customer is obligated to ~~Employee Share-Based Payment Accounting~~ ~~(“ASU 2016-09”), which simplifies several aspects related to~~pay a contractually-determined fee based upon 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 activityshortfall between actual product volumes and the ~~presentation~~MVC for that period. Some of ~~cash paid by an employer when directly withholding shares for tax-withholding purposes as~~these agreements also contain make-up right provisions that allow a ~~financing activity, and this treatment is consistent with our historical accounting treatment. Finally, we elected~~customer or supplier to ~~estimate the number of awards that are expected to vest, which is consistent with our historical accounting treatment. The adoption~~utilize gathering or processing fees in excess of the ~~new guidance did~~MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, ~~materially affect~~make up the deficiency in subsequent periods. Deficiency fee revenue is included in midstream services revenue.

For our firm transportation contracts, we transport commodities owned by others for a stated monthly fee for a specified monthly quantity with an additional fee based on actual volumes. We include transportation fees from firm transportation contracts in our midstream services revenue.

The following table summarizes the contractually committed fees that we expect to recognize in our consolidated statements of operations, in either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below are determined using the contractually-stated MVC or firm transportation volumes specified for each period multiplied by the relevant deficiency or reservation fee. Actual amounts could differ due to the timing of revenue recognition or reductions to cost of sales resulting from make-up right provisions included in our agreements, as well as due to nonpayment or nonperformance by our customers. These fees do not represent the shortfall amounts we expect to collect under our MVC contracts, as we generally do not expect volume shortfalls to equal the full amount of the contractual MVCs during these periods. For example, for the three ~~and nine~~ months ended ~~September 30, 2017.~~March 31, 2019, we had contractual commitments of $38.5 million under our MVC contracts and recorded $3.8 million of revenue due to volume shortfalls.



MVC and Firm Transportation Commitments (1)
2019 (remaining)	$	196.7
2020	252.7
2021	104.7
2022	94.3
2023	91.6
Thereafter	279.7
Total	$	1,019.7

____________________________


(1)	Amounts do not represent expected shortfall under these commitments.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~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.


(c)	Accounting Standards to be Adopted in Future Periods

~~In February 2016,~~On August 29, 2018, the FASB issued ASU ~~2016-02,~~2018-15, ~~Leases (Topic 842)~~—~~Amendments to the FASB~~Customer’s Accounting ~~Standards Codification~~for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU ~~2016-02”~~2018-15”)~~. Lessees~~, which amends ASC 350-40, Internal-Use Software (“ASC 350-40”) to address a customer’s accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the accounting for costs incurred to implement a cloud computing arrangement that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Specifically, the ASU amends ASC 350-40 to include in its scope implementation costs of a cloud computing arrangement that is a service contract and clarifies that a customer should apply ASC 350-40 to determine which implementation costs should be capitalized in a cloud computing arrangement that is considered a service contract. To the extent costs incurred in a cloud computing arrangement are capitalizable, the corresponding amortization will ~~need to recognize virtually all~~be included in “Operating expenses” or “General and administrative” in the consolidated statement of ~~their~~operations, rather than “Depreciation and amortization.” We are currently evaluating the impact of ASU 2018-15 on our consolidated financial statements and will adopt ASU 2018-15 effective January 1, 2020.

(d) Adopted Accounting Standards

Effective January 1, 2019, we adopted ASC 842, Leases, using the modified retrospective approach whereby we recognized leases on ~~the~~our consolidated balance sheet by recording a right-of-use asset and lease liability. ~~Lessor accounting is similar~~We applied certain practical expedients that were allowed in the adoption of ASC 842, including not reassessing existing contracts for lease arrangements, not reassessing existing lease classification, not recording a right-of-use asset or lease liability for leases of twelve months or less, and not separating lease and non-lease components of a lease arrangement. In connection with the adoption of ASC 842 in January 2019, we recorded a lease liability of $97.6 million, a right-of-use asset of $75.3 million, and a reduction of $22.6 million in other liabilities previously recorded related to lease incentives. For additional information about our adoption of ASC 842, refer to “Note 5—Leases.”

(3) Goodwill and Intangible Assets

Goodwill

In March 2014, at the time of our transactions with Devon that led us to become publicly held, we recorded goodwill in our corporate reporting unit at ENLC that was associated with the General Partner’s incentive distribution rights in ENLK. Prior to the ~~current model, but updated~~completion of the Merger in January 2019, ENLC’s aggregate fair value of its reporting units was in excess of the consolidated book value of its assets, including all goodwill, which would not have resulted in a goodwill impairment on a consolidated basis. Upon the completion of the Merger, in accordance with ASC 350, Intangibles-Goodwill and other (“ASC 350”), the portion of goodwill on our corporate reporting unit that was previously associated with the General Partner’s incentive distribution rights in ENLK was required to ~~align with certain~~be reallocated to the four remaining reporting units based on the relative fair value of each of the reporting units. Due to the application of ASC 350, we were required to allocate goodwill to reporting units at which goodwill had previously been impaired due to book value in excess of fair value. As a result of the allocated goodwill, we recognized a $186.5 million impairment related to our Louisiana segment in the consolidated statement of operations for the three months ended March 31, 2019.

The table below provides a summary of our change in carrying amount of goodwill (in millions) for the three months ended March 31, 2019, by segment. For the three months ended March 31, 2018, there were no 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 impactcarrying amounts 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 sheets due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that are currently classified as operating leases. In addition, there are industry-specific concerns with the implementation of ASU 2016-02, including the application of ASU 2016-02 to 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.

goodwill.



	Permian		North Texas		Oklahoma		Louisiana			Corporate			Totals
Three Months Ended March 31, 2019
Balance, beginning of period	$	—	$	—	$	190.3	$	—		$	1,119.9		$	1,310.2
Goodwill allocation	184.6		125.7		623.1		186.5			(1,119.9		)	—
Impairment	—		—		—		(186.5		)	—			(186.5		)
Balance, end of period	$	184.6	$	125.7	$	813.4	$	—		$	—		$	1,123.7

Table of Contents

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.

~~Table of Contents~~

~~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 and ENLK acquired a 16% and 84% voting interest, respectively, 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, 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 the total purchase price.

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 $ 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

The fair value of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. We recognized intangible assets related to customer relationships and determined their fair value using the income approach. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 15 years.

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

For the three and nine months ended September 30, 2016, we recognized $77.3 million and $149.5 million of revenues, respectively, and $4.4 million and $27.9 million of net loss, respectively, related to the assets acquired.

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC~~

~~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 from ~~ten~~5 to ~~twenty~~20 years.

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


	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount			Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Nine Months Ended September 30, 2017
Three Months Ended March 31, 2019
Customer relationships, beginning of period	$	1,795.8	$	(171.6	)	$	1,624.2		$	1,795.8	$	(422.2	)	$	1,373.6
Amortization expense	—		(96.2		)	(96.2		)	—		(30.9		)	(30.9		)
Customer relationships, end of period	$	1,795.8	$	(267.8	)	$	1,528.0		$	1,795.8	$	(453.1	)	$	1,342.7

The weighted average amortization period is 15.0 years. Amortization expense was ~~approximately $31.2~~$30.9 million and ~~$29.9~~$30.8 million for the three months ended ~~September 30, 2017~~March 31, 2019 and ~~2016, respectively, and $96.2 million and $87.4 million for the nine months ended September 30, 2017 and 2016,~~2018, respectively.

~~Table of Contents~~

~~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):


2017 (remaining)	$	30.8
2018	123.4
2019	123.4
2019 (remaining)			$	92.8
2020	123.4		123.7
2021	123.4		123.7
2022			123.7
2023			123.6
Thereafter	1,003.6		755.2
Total	$	1,528.0	$	1,342.7

~~(5)~~(4) Related Party Transactions

~~We engage~~(a) Transactions with ENLK

Simplification of the Corporate Structure. On October 21, 2018, ENLK, ENLC, the General Partner, the managing member of ENLC, and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the surviving entity and as a subsidiary of ENLC. See “Note 1—General” for more information on this transaction.

Transfer of EOGP Interest. On January 31, 2019, ENLC transferred its 16.1% limited partner interest in ~~various~~EOGP to the Operating Partnership in exchange for 55,827,221 ENLK common units, resulting in the Operating Partnership owning 100% of the limited partner interests in EOGP.

(b) Transactions with Devon

On July 18, 2018, subsidiaries of Devon sold all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP for aggregate consideration of $3.125 billion. Accordingly, Devon is no longer an affiliate of ENLK or ENLC. The sale did not affect our commercial arrangements with Devon, except that Devon agreed to extend through 2029 certain existing fixed-fee gathering and processing contracts related to the Bridgeport plant in north Texas and the Cana plant in Oklahoma. Prior to July 18, 2018, revenues from transactions with Devon ~~Energy Corporation (“Devon”) and other~~ are included in “Product sales—related ~~parties.~~ parties” or “Midstream services—related parties” in the consolidated statement of operations. Revenues from transactions with Devon after July 18, 2018 are included in “Product sales” or “Midstream services” in the consolidated statement of operations.

For the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2018, Devon accounted for ~~15.0% and 15.4%~~9.8% of our ~~revenues, respectively, and for~~revenues.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

For the three ~~and nine~~ months ended ~~September 30, 2016, Devon accounted for 18.9%~~March 31, 2019 and ~~19.4%~~2018, we recorded cost of sales of $8.1 million and $13.0 million, respectively, related to our ~~revenues, respectively.~~purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at our central Oklahoma processing facilities. We had an accounts receivable ~~balance~~balances related to transactions with ~~Devon~~the Cedar Cove JV of ~~$121.5~~$0.4 million and $0.7 million at ~~September 30, 2017~~March 31, 2019 and ~~$100.2 million at~~ December 31, ~~2016.~~2018, respectively. Additionally, we had an accounts payable ~~balance~~balances related to transactions with ~~Devon~~the Cedar Cove JV of ~~$36.8~~$2.6 million and $4.3 million at ~~September 30, 2017~~March 31, 2019 and ~~$10.4 million at~~ December 31, ~~2016.~~ 2018, respectively.

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.

(5) Leases

Effective with the adoption of ASC 842 in January 2019, we evaluate new contracts at inception to determine if the contract conveys the right to control the use of an identified asset for a period of time in exchange for periodic payments. A lease exists if we obtain substantially all of the economic benefits of an asset, and we have the right to direct the use of that asset. When a lease exists, we record a right-of-use asset that represents our right to use the asset over the lease term and a lease liability that represents our obligation to make payments over the lease term. Lease liabilities are recorded at the sum of future lease payments discounted by the collateralized rate we could obtain to lease a similar asset over a similar period, and right-of-use assets are recorded equal to the corresponding lease liability, plus any prepaid or direct costs incurred to enter the lease, less the cost of any incentives received from the lessor. The majority of our leases are for the following types of assets:

Office space- Our primary offices are in Dallas, Houston, and Midland, with smaller offices in other locations near our assets. Our office leases are long-term in nature and represent $64.1 million of our lease liability and $42.8 million of our right-of-use asset as of March 31, 2019. These office leases typically include variable lease costs related to utility expenses, which are determined based on our pro-rata share of the building expenses each month and expensed as incurred.

Compression and other field equipment- We pay third parties to provide compressors or other field equipment for our assets. Under these agreements, a third party installs and operates compressor units based on specifications set by us to meet our compression needs at specific locations. While the third party determines which compressors to install and operates and maintains the units, we have the right to control the use of the compressors and are the sole economic beneficiary of the identified assets. These agreements are typically for an initial term of one to three years but will automatically renew from month to month until canceled by us or the lessor. Compression and other field equipment rentals represent $19.2 million of our lease liability and $23.0 million of our right-of-use asset as of March 31, 2019. Under certain agreements, we may incur variable lease costs related to incidental services provided by the equipment lessor, which are expensed as incurred.

Office equipment- We rent office equipment for a monthly fee. These leases are typically for several years and represent $0.8 million of our lease liability and $0.8 million of our right-of-use asset as of March 31, 2019.

Land and land easements- We make periodic payments to lease land or to have access to our assets. Land leases and easements are typically long-term to match the expected useful life of the corresponding asset and represent $14.9 million of our lease liability and $13.2 million of our right-of-use asset as of March 31, 2019.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Lease balances are recorded on the consolidated balance sheets as follows (in millions):



	March 31, 2019
Finance leases:
Property and equipment	$	5.2
Accumulated depreciation	(0.7		)
Property and equipment, net of accumulated depreciation	$	4.5
Other current liabilities	$	0.8

Operating leases:
Other assets, net	$	75.3
Other current liabilities	$	17.3
Other long-term liabilities	$	80.9

Certain of our lease agreements have options to extend the lease for a certain period after the expiration of the initial term. We recognize the cost of a lease over the expected total term of the lease, including optional renewal periods that we can reasonably expect to exercise. We do not have material obligations whereby we guarantee a residual value on assets we lease, nor do our lease agreements impose restrictions or covenants that could affect our ability to make distributions.

Lease expense is recognized on the consolidated statements of operations as “Operating expenses” and “General and administrative” depending on the nature of the leased asset. The components of total lease expense are as follows (in millions):



	Three Months Ended March 31,
	2019
Finance lease expense:
Amortization of right-of-use asset	$	0.7
Interest on lease liability	—
Operating lease expense:
Long-term operating lease expense	6.3
Short-term lease expense	6.9
Variable lease expense	1.6
Total lease expense	$	15.5

Other information about our leases are as follows (dollar amounts in millions, lease terms in years):



	Three Months Ended March 31,
	2019
Supplemental cash flow information:
Cash payments for finance leases included in cash flows from financing activities	$	0.4
Cash payments for operating leases included in cash flows from operating activities	$	7.0
Right-of-use assets obtained in exchange for operating lease liabilities	$	80.6

Other lease information
Weighted-average remaining lease term - Finance leases	0.5 years
Weighted-average remaining lease term - Operating leases	11.6 years
Weighted-average discount rate - Finance leases	9.3		%
Weighted-average discount rate - Operating leases	5.2		%

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The following table summarizes the maturity of our lease liability as of March 31, 2019 (in millions):



	Total			2019 (remaining)			2020			2021			2022			2023			Thereafter
Undiscounted finance lease liability	$	0.8		$	0.8		$	—		$	—		$	—		$	—		$	—
Reduction due to present value	—			—			—			—			—			—			—
Finance lease liability	0.8			0.8			—			—			—			—			—

Undiscounted operating lease liability	139.2			16.5			16.0			12.9			9.1			8.9			75.8
Reduction due to present value	(41.0		)	(3.6		)	(4.2		)	(3.7		)	(3.4		)	(3.0		)	(23.1		)
Operating lease liability	98.2			12.9			11.8			9.2			5.7			5.9			52.7
Total lease liability	$	99.0		$	13.7		$	11.8		$	9.2		$	5.7		$	5.9		$	52.7

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(6) Long-Term Debt

As of ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016,~~2018, long-term debt consisted of the following (in millions):

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



	March 31, 2019								December 31, 2018
	Outstanding Principal		Premium (Discount)			Long-Term Debt			Outstanding Principal		Premium (Discount)			Long-Term Debt
ENLC Credit Facility, due 2019 (1)	$	—	$	—		$	—		$	111.4	$	—		$	111.4
Consolidated Credit Facility due 2024 (2)	160.0		—			160.0			—		—			—
Term Loan due 2021 (3)	850.0		—			850.0			850.0		—			850.0
ENLK’s 2.70% Senior unsecured notes due 2019 (4)	400.0		—			400.0			400.0		—			400.0
ENLK’s 4.40% Senior unsecured notes due 2024	550.0		1.7			551.7			550.0		1.8			551.8
ENLK’s 4.15% Senior unsecured notes due 2025	750.0		(0.8		)	749.2			750.0		(0.9		)	749.1
ENLK’s 4.85% Senior unsecured notes due 2026	500.0		(0.5		)	499.5			500.0		(0.5		)	499.5
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		(6.1		)	443.9			450.0		(6.2		)	443.8
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, including current maturities of long-term debt	$	4,510.0	$	(6.0	)	4,504.0			$	4,461.4	$	(6.1	)	4,455.3
Debt issuance cost (5)						(28.4		)						(24.5		)
Less: Current maturities of long-term debt (4)						—								(399.8		)
Long-term debt, net of unamortized issuance cost						$	4,475.6							$	4,031.0

____________________________

(1)

~~Bears~~Bore interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was~~2.3%~~ 4.4% atDecember 31, ~~2016~~.

2018. In connection with the closing of the Merger, the ENLC Credit Facility was canceled, and all outstanding borrowings were refinanced through borrowings on the Consolidated Credit Facility. Since the borrowings under the ENLC Credit Facility were refinanced with long-term debt, they are classified as “Long-term debt” on the consolidated balance sheet as of December 31, 2018.


(2)	Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was~~3.2% and 3.4%~~ 4.6%at ~~September 30, 2017 and December~~March 31, ~~2016, respectively.~~2019.


(3)	Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 4.0% and 3.9% at March 31, 2019 and December 31, 2018, respectively.


(4)	ENLK’s 2.70% senior unsecured notes matured on April 1, 2019 and were refinanced through borrowings on the Consolidated Credit Facility.Therefore, the outstanding principal balance, net of discount and debt issuance costs, is classified as “Long-term debt” on the consolidated balance sheet as of March 31, 2019 and “Current maturities of long-term debt” as of December 31, 2018.


(5)	Net of amortization of ~~$11.9~~$10.9 million and ~~$9.0~~$16.5 million at ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016~~,2018, respectively.

~~ENLC~~Consolidated Credit Facility

~~We have~~On December 11, 2018, ENLC entered into the Consolidated Credit Facility, which permits ENLC to borrow up to $1.75 billion on a ~~$250.0 million~~ revolving credit ~~facility that matures on March 7, 2019~~basis and includes a ~~$125.0~~$500.0 million letter of credit ~~subfacility (the “ENLC~~subfacility. The Consolidated Credit ~~Facility”). Our~~Facility became available for borrowings and letters of credit upon closing of the Merger. In addition, ENLK became a guarantor under the Consolidated Credit Facility upon the closing of the Merger. In the event that ENLC defaults on the Consolidated Credit Facility, ENLK will be liable for the entire outstanding balance ($160.0 million as of March 31, 2019), and 105% of the outstanding letters of credit under the Consolidated Credit Facility. The obligations under the ~~ENLC~~Consolidated Credit Facility are ~~guaranteed by two~~unsecured.

The Consolidated Credit Facility includes procedures for additional financial institutions to become lenders, or for any existing lender to increase its revolving commitment thereunder, subject to an aggregate maximum of ~~our wholly-owned subsidiaries and secured by first priority liens~~$2.25 billion for all commitments under the Consolidated Credit Facility.

The Consolidated Credit Facility will mature on ~~(i) 88,528,451 ENLK common units~~January 25, 2024, unless ENLC requests, and the ~~100% membership~~

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC~~

~~Notes~~requisite lenders agree, 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.

extend it pursuant to its terms. The ~~ENLC~~Consolidated 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~~quarter. The financial covenants include (i) maintaining a ~~maximum~~ratio of consolidated ~~leverage ratio~~EBITDA (as defined in the ~~ENLC~~Consolidated Credit Facility, ~~but generally computed as the ratio of consolidated funded indebtedness~~which term includes projected EBITDA from certain capital expansion projects) to consolidated ~~earnings before~~ interest ~~taxes, depreciation, amortization and certain other non-cash charges)~~charges of ~~4.00~~no less than 2.5 to ~~1.00, provided that~~1.0 at all times prior to the ~~maximum consolidated leverage ratio is 4.50~~occurrence of an investment

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to ~~1.00 during an acquisition period~~Consolidated Financial Statements (Continued)

(Unaudited)

grade event (as defined in the ~~ENLC~~Consolidated 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~~indebtedness to consolidated ~~interest charges)~~EBITDA of ~~2.50~~no more than 5.0 to ~~1.00 unless an investment grade event (as defined~~1.0. If ENLC consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLC ~~Credit Facility) occurs.~~can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters.

Borrowings under the ~~ENLC~~Consolidated Credit Facility bear interest at ~~our~~ENLC’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from ~~1.75%~~1.125% to ~~2.50%~~2.00%) 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 0.125% to 1.00%). The applicable margins vary depending on ENLC’s debt rating. Upon breach by ENLC of certain covenants governing the Consolidated Credit Facility, amounts outstanding under the Consolidated Credit Facility, if any, may become due and payable immediately.

At March 31, 2019, we were in compliance with and expect to be in compliance with the covenants of the Consolidated Credit Facility for at least the next twelve months.

Term Loan

On December 11, 2018, ENLK entered into the Term Loan 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. On December 11, 2018, ENLK borrowed $850.0 million under the Term Loan and used the net proceeds to repay obligations outstanding under the ENLK Credit Facility. Upon the closing of the Merger, ENLC assumed ENLK’s obligations under the Term Loan, and ENLK became a guarantor of the Term Loan. In the event that ENLC defaults on the Term Loan, the outstanding balance immediately becomes due, and ENLK will be liable for any amount owed on the Term Loan not paid by ENLC. The outstanding balance of the Term Loan was $850.0 million as of March 31, 2019. The obligations under the Term Loan are unsecured.

The Term Loan will mature on December 10, 2021. The Term Loan 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. The financial covenants include (i) maintaining a ratio of consolidated EBITDA (as defined in the Term Loan, which term includes projected EBITDA from certain capital expansion projects) to consolidated interest charges of no less than 2.5 to 1.0 at all times prior to the occurrence of an investment grade event (as defined in the Term Loan) and (ii) maintaining a ratio of consolidated indebtedness to consolidated EBITDA of no more than 5.0 to 1.0. If ENLC consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLC can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter in which the acquisition occurs and the three subsequent quarters.

Borrowings under the Term Loan bear interest at ENLC’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.0% to 1.75%) 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 in compliance and expects to be in compliance with the covenants in the ENLC Credit Facility for at least the next twelve months.

As of September 30, 2017, there were no outstanding letters of credit and $74.0 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.

~~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 percent0.0% to 0.75%). The applicable margins vary depending on ~~ENLK’s credit~~ENLC’s debt rating. ~~If ENLK breaches~~Upon breach by ENLC of certain covenants ~~governing~~included in the ~~ENLK Credit Facility,~~Term Loan, amounts outstanding under the ~~ENLK Credit Facility, if any,~~Term Loan may become due and payable immediately.

At ~~September 30, 2017, ENLK was~~March 31, 2019, we were in compliance with and ~~expects~~expect to be in compliance with the covenants inof the ~~ENLK Credit Facility~~Term Loan for at least the next twelve months.

As of 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.

(7) Income Taxes

~~All other material terms and conditions~~The components of ~~the ENLK Credit Facility~~our income tax provision are ~~described in Part II, “Item 8. Financial Statements and Supplementary Data—Note 6” in our Annual Report on Form 10-K for the year ended December 31, 2016.~~

as follows (in millions):



	Three Months Ended March 31,
	2019		2018
Current income tax provision	$	1.0	$	1.2
Deferred income tax provision	0.8		5.8
Income tax provision	$	1.8	$	7.0

Table of Contents

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 as follows for the periods presented (in millions):~~

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)~~provision and the amount calculated by applying the statutory U.S. federal tax rate to income before income taxes (in millions):

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



	Three Months Ended March 31,
	2019			2018
Expected income tax provision (benefit) based on federal statutory rate	$	(36.7	)	$	4.1
State income tax provision (benefit), net of federal benefit	(4.4		)	0.5
Income tax provision from ENLK	0.9			1.0
Unit-based compensation (1)	0.1			1.6
Non-deductible expense related to asset impairment	43.8			—
Other	(1.9		)	(0.2		)
Income tax provision	$	1.8		$	7.0

____________________________


(1)	Related to tax deficiencies recorded upon the vesting of restricted incentive units.

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. Our deferred income tax assets and liabilities as of March 31, 2019 and December 31, 2018 are as follows (in millions):



	March 31, 2019			December 31, 2018
Deferred income tax assets:
Federal net operating loss carryforward	$	77.4		$	67.9
State net operating loss carryforward	13.1			11.7
Total deferred tax assets	90.5			79.6
Deferred tax liabilities:
Property, equipment, and intangible assets (1)	(54.0		)	(440.6		)
Other	(0.3		)	(1.4		)
Total deferred tax liabilities	(54.3		)	(442.0		)
Deferred tax asset (liability), net	$	36.2		$	(362.4	)

____________________________


(1)	~~Related~~ Includes our investment in ENLK and primarily relates to differences between the book and tax bases of property and equipment~~to tax deficiencies recorded on vested units, which were recognized in accordance with the adoption of ASU 2016-09.~~.

~~(8) Certain Provisions~~As a result of the ~~Partnership Agreement~~


~~(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.Merger, we acquired all issued and ~~RBC Capital Markets, LLC to sell up to $350.0 million in aggregate gross sales of~~outstanding ENLK common units ~~from time~~that were not already held by us or our subsidiaries in exchange for the issuance of ENLC common units. See “Note 1—General” for more information regarding this transaction. This was a taxable exchange to ~~time through an “at~~our unitholders, and we received a step-up in tax basis of the ~~market” equity offering program.~~underlying assets acquired. In accordance with ASC 810, Consolidation, the step-up in our basis reduced our DTL by $399.0 million, and the resulting DTA will be realized over the tax-basis depreciable life of the underlying assets.

As of March 31, 2019, we had federal net operating loss carryforwards of $368.5 million that represent a net deferred tax asset of $77.4 million. As of December 31, 2018, we had federal net operating loss carryforwards of $323.6 million that represent a net deferred tax asset of $67.9 million. These carryforwards will begin expiring in 2028 through 2038. Management believes that it is more likely than not that the future results of operations will generate sufficient taxable income to utilize these net operating loss carryforwards before they expire.

Table of Contents

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

~~(b)~~(a) ENLK Series B Preferred Units

~~In January 2016, ENLK issued an aggregate~~Prior to the closing of ~~50,000,000~~the Merger, Series B Preferred ~~Units representing ENLK limited partner interests~~Unit distributions were payable quarterly in cash at an amount equal to ~~Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00~~$0.28125 per 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 connection 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, all of the Series B Preferred Units will automatically convert into 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 through the 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 ENLK common units over the Cash Distribution Component, divided by (ii) the ~~Issue Price.~~issue price of $15.00 (the “Issue Price”).

~~Table~~Following the closing of ~~Contents~~

~~ENLINK MIDSTREAM, LLC~~

~~Notes~~the Merger, and beginning with the quarter ended March 31, 2019, the holder of the Series B Preferred Units will be entitled to ~~Consolidated Financial Statements (Continued)~~

~~(Unaudited)~~

quarterly cash distributions and distributions in-kind of additional Series B Preferred Units as described below. The quarterly in-kind distribution (the “Series B PIK Distribution”) will equal the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) the number of Series B Preferred Units equal to the quotient of (x) the excess (if any) of (1) the distribution that would have been payable by ENLC had the Series B Preferred Units been exchanged for ENLC common units but applying a one-to-one exchange ratio (subject to certain adjustments) instead of the exchange ratio of 1.15 ENLC common units for each Series B Preferred Unit, subject to certain adjustments (the “Series B Exchange Ratio”), over (2) the Cash Distribution Component, divided by (y) the Issue Price. The quarterly cash distribution will consist of the Cash Distribution Component plus an amount in cash that will be determined based on a comparison of the value (applying the Issue Price) of (i) the Series B PIK Distribution and (ii) the Series B Preferred Units that would have been distributed in the Series B PIK Distribution if such calculation applied the Series B Exchange Ratio instead of the one-to-one ratio (subject to certain adjustments).

A summary of the distribution activity relating to the Series B Preferred Units ~~for~~during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 and ~~2016~~2018 is provided below:

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



Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2019
Fourth Quarter of 2018	425,785	$	16.5	February 13, 2019
First Quarter of 2019	147,887	$	16.7	May 14, 2019

2018
Fourth Quarter of 2017	413,658	$	16.0	February 13, 2018
First Quarter of 2018	416,657	$	16.2	May 14, 2018


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


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

In September 2017, ENLK issued 400,000 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 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 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, the Series C Preferred Units rank senior to ENLK’s common units 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 allocated to the Series C Preferred Units in an amount equal to 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, 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~~the 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%.


~~(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

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~distributions with respect to (i) distributions on the ENLK Series B Preferred Units until such units convert into common units or (ii) the Series C Preferred Units.~~

The General Partner owns the general partner interest in ENLK 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.


(c)	ENLK Common Unit Distributions

A summary of ENLK’s distribution activity relating to the common units for periods prior to the ~~nine months ended September 30, 2017 and 2016~~Merger is provided below:

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



Declaration period	Distribution/unit		Date paid/payable
2019
Fourth Quarter of 2018	$	0.39	February 13, 2019

2018
Fourth Quarter of 2017	$	0.39	February 13, 2018
First Quarter of 2018	$	0.39	May 14, 2018


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

~~Net~~Prior to the closing of the Merger and for the three months ended March 31, 2018, net income iswas allocated to the General Partner in an amount equal to its incentive distribution rights. Prior to the closing of the Merger, ENLK was required to pay the General Partner incentive distributions in the amount of 13.0% of ENLK distributions in excess of $0.25 per unit, 23.0% of ENLK distributions in excess of $0.3125 per unit, and 48.0% of ENLK distributions in excess of $0.375 per unit. The General Partner was not entitled to incentive distributions with respect to (i) distributions on the Series B Preferred Units until such units converted into common units or (ii) the Series C Preferred Units. At the closing of the Merger, the General Partner’s incentive distribution rights ~~as described~~ in ~~(d) above. The~~ENLK were eliminated.

For the three months ended March 31, 2018, the General Partner’s share of net income ~~consists~~consisted 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):

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



	Three Months Ended March 31,
	2019			2018
Income allocation for incentive distributions	$	—		$	14.8
Unit-based compensation attributable to ENLC’s restricted and performance units	(12.1		)	(4.4		)
General Partner share of net income	0.4			0.2
General Partner interest in EOGP acquisition	2.4			4.2
General Partner interest in net income (loss)	$	(9.3	)	$	14.8

(9) Members' Equity

(a)Issuance of ENLC Common Units related to the Merger

In connection with the consummation of the Merger, we issued 304,822,035 ENLC common units in exchange for all of the outstanding ENLK common units not previously owned by us.

(b)ENLC Equity Distribution Agreement

On February 22, 2019, ENLC entered into the ENLC EDA with the Sales Agents to sell up to $400.0 million in aggregate gross sales of ENLC common units from time to time through an “at the market” equity offering program. Under the ENLC EDA, ENLC 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. ENLC has no obligation to sell any ENLC common units under the ENLC EDA and may at any time suspend solicitation and offers under the ENLC EDA. As of May 1, 2019, ENLC has not sold any common units under the ENLC EDA.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(9) Members' Equity~~

~~(a)~~(c) 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,						Three Months Ended March 31,
	2017			2016			2017			2016			2019			2018
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
Common units (1)													$	109.4		$	47.6
Unvested restricted units (1)													1.2			0.5
Total distributed earnings	$	46.7		$	46.5		$	139.9		$	139.0		$	110.6		$	48.1
Undistributed loss allocated to:
Common units	$	(39.9	)	$	(45.1	)	$	(128.0	)	$	(588.3	)	$	(283.8	)	$	(35.3	)
Unvested restricted units	(0.6		)	(0.7		)	(1.7		)	(6.8		)	(3.1		)	(0.4		)
Total undistributed loss	$	(40.5	)	$	(45.8	)	$	(129.7	)	$	(595.1	)	$	(286.9	)	$	(35.7	)
Net income (loss) allocated to:
Common units	$	6.1		$	0.8		$	10.0		$	(450.9	)	$	(174.4	)	$	12.3
Unvested restricted units	0.1			(0.1		)	0.2			(5.2		)	(1.9		)	0.1
Total net income (loss)	$	6.2		$	0.7		$	10.2		$	(456.1	)	$	(176.3	)	$	12.4
Basic and diluted net income (loss) per unit:
Basic	$	0.03		$	—		$	0.06		$	(2.54	)	$	(0.45	)	$	0.07
Diluted	$	0.03		$	—		$	0.06		$	(2.54	)	$	(0.45	)	$	0.07

____________________________


(1)	For the three months ended ~~September 30, 2017~~March 31, 2019 and ~~2016,~~2018, distributed earnings ~~included~~represent a declared distribution of ~~$0.255~~$0.279 per unit payable on ~~November~~May 14, ~~2017~~2019 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~~$0.263 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, 2016.2018.

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,		Three Months Ended March 31,
	2017	2016	2017	2016	2019	2018
Basic and diluted earnings per unit:
Basic weighted average units outstanding:
Weighted average common units outstanding	180.6	180.0	180.4	179.6	392.0	180.9

Diluted weighted average units outstanding:
Weighted average basic common units outstanding	180.6	180.0	180.4	179.6	392.0	180.9
Dilutive effect of non-vested restricted incentive units (1)	1.2	1.1	1.3	—
Dilutive effect of non-vested restricted units (1)					—	0.9
Total weighted average diluted common units outstanding	181.8	181.1	181.7	179.6	392.0	181.8

___________________________


(1)	~~For the nine months ended September 30, 2016, all~~All common unit equivalents were antidilutive for the three months ended March 31, 2019 since a net loss existed for that period.

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

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 presented.~~

~~(b)~~(d) Distributions

A summary of our distribution activity relating to the ENLC common units for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 and ~~2016,~~2018, respectively, is provided below:

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



Declaration period	Distribution/unit		Date paid/payable
2019
Fourth Quarter of 2018	$	0.275	February 14, 2019
First Quarter of 2019	$	0.279	May 14, 2019

2018
Fourth Quarter of 2017	$	0.259	February 14, 2018
First Quarter of 2018	$	0.263	May 15, 2018

(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~~As of March 31, 2019, our unconsolidated investments consisted ~~of:~~

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~~GCF 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.~~

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC~~

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

~~(Unaudited)~~

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,
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 )



	Three Months Ended March 31,
	2019			2018
GCF
Distributions	$	2.2		$	5.7
Equity in income	$	5.7		$	4.6

Cedar Cove JV
Distributions	$	0.3		$	0.3
Equity in loss	$	(0.4	)	$	(1.6	)

Total
Distributions	$	2.5		$	6.0
Equity in income	$	5.3		$	3.0


~~(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~~March 31, 2019 and December 31, ~~2016~~2018 (in millions):


	September 30, 2017		December 31, 2016		March 31, 2019		December 31, 2018
Gulf Coast Fractionators	$	46.4	$	48.5
Howard Energy Partners	—		193.1
GCF					$	45.4	$	41.9
Cedar Cove JV	39.7		28.8		37.5		38.2
Total investment in unconsolidated affiliates	$	86.1	$	270.4	$	82.9	$	80.1

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

~~(12)~~(11) Employee Incentive Plans


(a)	Long-Term Incentive Plans

Prior to the Merger, ENLC and ENLK each ~~have~~had similar unit-based compensation payment plans for officers and employees. ENLC grants unit-based awards under the ~~EnLink Midstream, LLC~~ 2014 ~~Long-Term Incentive~~ Plan, ~~(the “LLC Plan”),~~ and ENLK ~~grants~~granted unit-based awards under the ~~amended~~GP Plan. As of the closing of the Merger, (i) ENLC assumed all obligations in respect of the GP Plan and ~~restated EnLink Midstream~~the outstanding awards granted thereunder (the “Legacy ENLK Awards”) and (ii) the Legacy ENLK Awards converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate. In addition, as of the closing of the Merger, the performance metric of each Legacy ENLK Award and each then outstanding award under the 2014 Plan with performance-based vesting conditions was modified as discussed in (c) and (e) below.Following the consummation of the Merger, no additional awards will be granted under the GP ~~LLC Long-Term Incentive Plan (the “GP Plan”).~~Plan.

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,				Three Months Ended March 31,
	2017		2016		2017		2016		2019		2018
Cost of unit-based compensation charged to operating expense									$	0.3	$	2.0
Cost of unit-based compensation charged to general and administrative expense	$	7.4	$	5.8	$	28.5	$	17.7	10.8		3.1
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	$	11.1	$	5.1
Non-controlling interest in unit-based compensation	$	3.9	$	2.7	$	14.6	$	8.3	$	0.5	$	1.9
Amount of related income tax benefit recognized in net income (1)	$	2.4	$	1.7	$	9.1	$	5.4	$	2.5	$	0.7

____________________________


(1)	For the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2019 and 2018, the amount of related income tax benefit recognized in net income excluded ~~$2.3~~$0.1 million and $1.6 million, respectively, of income tax expense related to tax deficiencies recorded on vested ~~units, which were recognized in accordance with the adoption of ASU 2016-09.~~ units.


(b)	EnLink Midstream Partners, LP Restricted Incentive Units

ENLK restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of ~~the~~ENLK common units on such date. A summary of the restricted incentive unit activity for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 is provided below:


	Nine Months Ended September 30, 2017					Three Months Ended March 31, 2019
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value		Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	2,024,820			$	19.05	2,556,270		$	14.43
Granted (1)	859,595			18.41
Vested (1)(2)	(851,753		)	25.90
Vested (1)						(722,853	)	10.02
Forfeited	(32,225		)	16.28		(4,490	)	11.93
Converted to ENLC (2)						(1,828,927	)	16.11
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~~249,201 units withheld for payroll taxes paid on behalf of employees.


(2)	As a result of the Merger, the Legacy ENLK Awards converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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~~March 31, 2019 and ~~2016~~2018 is provided below (in millions):

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

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC~~

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

~~(Unaudited)~~

As of September 30, 2017, there was $14.6 million of unrecognized compensation cost related to non-vested ENLK restricted incentive units. That cost is expected to be recognized over a weighted-average period of 1.7 years.



	Three Months Ended March 31,
EnLink Midstream Partners, LP Restricted Incentive Units:	2019		2018
Aggregate intrinsic value of units vested	$	8.0	$	8.7
Fair value of units vested	$	7.2	$	12.8


(c)	EnLink Midstream Partners, LP Performance Units

~~For~~Prior to the ~~nine months ended September 30, 2017,~~Merger, the General Partner ~~and EnLink Midstream Manager, LLC, our managing member,~~ granted performance awards under the GP ~~Plan and the LLC Plan, respectively.~~Plan. The performance award agreements ~~provide~~provided that the vesting of performance units (i.e., performance-based restricted incentive ~~units~~units) granted thereunder iswas 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~~contemplated that the Peer Companies for an individual performance award (the “Subject Award”) ~~are~~were the companies comprising the ~~Alerian MLP Index for Master Limited Partnerships (“AMZ”),~~AMZ, excluding ~~ENLC~~ENLK and ~~ENLK (collectively, “EnLink”),~~ENLC, on the grant date for the Subject Award. The performance units ~~will~~would vest based on the percentile ranking of the average of ~~ENLC’s~~ENLK’s and ~~ENLK’s~~ENLC’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

As of the closing of the Merger, these performance-based Legacy ENLK Awards were modified, such that, the performance goal will, on a weighted average basis, (i) continue to relate to the EnLink TSR relative to the TSR performance of the Peer Companies in respect of periods preceding the effective time of the Merger; and (ii) relate solely to the TSR performance of ENLC relative to the TSR performance of such Peer Companies in respect of periods on and after the effective time of the Merger. 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~~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.~~ relevant performance period.

The fair value of each performance unit iswas 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~~Peer Companies’ securities; (iii) an estimated ranking of ENLK among the designated ~~peer group;~~Peer Companies; 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:~~

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, 2017				Three Months Ended March 31, 2019
EnLink Midstream Partners, LP Performance Units:	Number of Units		Weighted Average Grant-Date Fair Value		Number of Units		Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	408,637		$	18.27	451,669		$	17.74
Granted	176,648		25.73
Forfeited	—		—
Vested (1)					(161,410	)	10.54
Converted to ENLC (2)					(290,259	)	28.31
Non-vested, end of period	585,285		$	20.52	—		$	—
Aggregate intrinsic value, end of period (in millions)	$	9.8

____________________________


(1)	Vested units included 62,403 units withheld for payroll taxes paid on behalf of employees.


(2)	As a result of the Merger, the performance-based Legacy ENLK Awards converted into ENLC performance-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.

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.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

A summary of the 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 months ended March 31, 2019 and 2018 is provided below (in millions).



	Three Months Ended March 31,
EnLink Midstream Partners, LP Performance Units:	2019		2018
Aggregate intrinsic value of units vested	$	2.1	$	2.0
Fair value of units vested	$	1.7	$	4.1


(d)	EnLink Midstream, LLC Restricted Incentive Units

ENLC restricted incentive units are 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~~three months ended ~~September 30, 2017~~March 31, 2019 is provided below:


	Nine Months Ended September 30, 2017					Three Months Ended March 31, 2019
EnLink Midstream, LLC Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value		Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,897,298			$	19.96	2,425,867			$	14.62
Granted (1)	817,201			19.24		1,770,170			11.45
Vested (1)(2)	(775,973		)	28.28		(1,214,354		)	10.35
Forfeited	(31,636		)	16.53		(54,090		)	11.71
Converted from ENLK (3)						2,103,266			14.01
Non-vested, end of period	1,906,890			$	16.32	5,030,859			$	14.31
Aggregate intrinsic value, end of period (in millions)	$	32.9				$	64.3

____________________________

(1)

Restricted incentive units typically vest at the end of three years. In March ~~2017,~~2019, ENLC granted ~~258,606~~420,842 restricted incentive units with a fair value of ~~$5.0~~$4.8 million to officers and certain employees as bonus payments for ~~2016,~~2018, 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~~409,384 units withheld for payroll taxes paid on behalf of employees.


(3)	Represents Legacy ENLK Awards that were converted into ENLC unit-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
EnLink Midstream, LLC Restricted Incentive Units:	2017		2016		2017		2016		2019		2018
Aggregate intrinsic value of units vested	$	0.6	$	0.3	$	15.2	$	4.1	$	12.4	$	8.9
Fair value of units vested	$	1.1	$	0.6	$	21.9	$	12.4	$	12.6	$	13.1

As of ~~September 30, 2017,~~March 31, 2019, there was ~~$14.2~~$44.6 million of unrecognized compensation cost related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted-average period of ~~1.8~~2.0 years.

For all restricted incentive unit awards granted after March 8, 2019 to certain officers and employees (the “grantee”), such awards (the “Subject Grants”) generally provide that, subject to the satisfaction of the conditions set forth in the agreement, the Subject Grants will vest on the third anniversary of the vesting commencement date (the “Regular Vesting Date”). The Subject Grants will be forfeited if the grantee’s employment or service with ENLC and its affiliates terminates prior to the Regular Vesting Date except that the Subject Grants will vest in full or on a pro-rated basis for certain terminations of employment or service prior to the Regular Vesting Date. For instance, the Subject Grants will vest on a pro-rated basis for any terminations of the grantee’s employment: (i) due to retirement, (ii) by ENLC or its affiliates without cause, or (iii) by the grantee for good reason (each, a “Covered Termination” and more particularly defined in the Subject Grants agreement) except that the Subject Grants will vest in full if the applicable Covered Termination is a “normal retirement” (as defined in the Subject Grants

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

agreement) or the applicable Covered Termination occurs after a change of control (if any). The Subject Grants will vest in full if death or a qualifying disability occurs prior to the Regular Vesting Date.


(e)	EnLink Midstream, LLC’s Performance Units

~~For the nine months ended September 30, 2017,~~ ENLC ~~granted~~grants performance awards under the ~~LLC~~2014 Plan. The performance award agreements provide that the vesting of performance units (i.e., performance-based restricted incentive units) granted thereunder is dependent on the achievement of certain performance goals over the applicable performance period. 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~~ranges from zero to 200% of the units granted depending on the ~~EnLink~~extent to which the related performance goals are achieved over the relevant performance period.

Performance awards granted prior to March 8, 2019 provided that the vesting of performance units granted was dependent on the achievement of certain TSR ~~as compared~~performance goals relative to the TSR achievement of the Peer Companies over the applicable performance period. Prior to the Merger, vesting of the performance units was based on the percentile ranking of the EnLink TSR for the applicable performance period relative to the TSR achievement of the Peer Companies. As of the effective time of the Merger, these performance-based awards were modified, such that, the performance goal will, on a weighted average basis, (i) continue to relate to the EnLink TSR relative to the TSR performance of the Peer Companies in respect of periods preceding the effective time of the Merger; and (ii) relate solely to the TSR performance of ENLC relative to the TSR performance of such Peer Companies in respect of periods on and after the effective time of the Merger.

The following table presents a summary of the performance units:



	Three Months Ended March 31, 2019
EnLink Midstream, LLC Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	418,149			$	19.15
Granted	907,337			13.53
Vested (1)	(161,286		)	11.71
Converted from ENLK (2)	333,798			25.84
Non-vested, end of period	1,497,998			$	18.04
Aggregate intrinsic value, end of period (in millions)	$	19.1

____________________________


(1)	Vested units included 62,219 units withheld for payroll taxes paid on behalf of employees.


(2)	As a result of the Merger, the performance-based Legacy ENLK Awards converted into ENLC performance-based awards using the 1.15 exchange ratio (as defined in the Merger Agreement) as the conversion rate.

A summary of the performance units’ aggregate intrinsic value (market value at vesting ~~date.~~ date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2019 and 2018 is provided below (in millions):



	Three Months Ended March 31,
EnLink Midstream, LLC Performance Units:	2019		2018
Aggregate intrinsic value of units vested	$	1.8	$	1.9
Fair value of units vested	$	1.9	$	4.2

As of March 31, 2019, there was $16.6 million of unrecognized compensation cost that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 2.2 years.

In connection with the GIP Transaction, certain outstanding performance unit agreements were modified to, among other things: (i) provide that the awards granted thereunder did not vest due to the closing of the GIP Transaction, and (ii) increase the minimum vesting of units from zero to 100% as described in our Current Report on Form 8-K filed with the Securities and Exchange Commission on July 23, 2018. The modified performance units retained the original vesting schedules. As a result of the modifications, we will recognize an additional $2.1 million compensation cost over the life of these ENLC performance units.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

In connection with the Merger, Legacy ENLK Awards with “performance-based” vesting and payment conditions were modified to reflect the Performance Metric Adjustment (as defined in the Merger Agreement) as described in our Current Report on Form 8-K filed with the Commission on January 29, 2019. The modified performance units retained the original vesting schedules. As a result of the modifications, we will recognize an additional $0.7 million in compensation costs over the life of the Legacy ENLK Awards.

2019 Performance Unit Awards

For all performance awards granted after March 8, 2019 to the grantee, the vesting of performance units is dependent on (a) the grantee’s continued employment or service with ENLC or its affiliates for all relevant periods and (b) EnLink TSR and a performance goal based on cash flow (“Cash Flow”). At the time of grant, the Board of Directors of the managing member of ENLC (the “Board”) will determine the relative weighting of the two performance goals by including in the award agreement the number of units that will be eligible for vesting depending on the achievement of the TSR performance goals (the “Total TSR Units”) versus the achievement of the Cash Flow performance goals (the “Total CF Units”). These performance awards have four separate performance periods: (i) three performance periods are each of the first, second, and third calendar years that occur following the vesting commencement date of the performance awards and (ii) the fourth performance period is the cumulative three-year period from the vesting commencement date through the third anniversary thereof (the “Cumulative Performance Period”).

One-fourth of the Total TSR Units (the “Tranche TSR Units”) relates to each of the four performance periods described above. Following the end date of a given performance period, the Governance and Compensation Committee (the “Committee”) of the Board will measure and determine the TSR performance of ENLC (the “ENLC TSR”) relative to the TSR performance of a designated group of peer companies (the “Designated Peer Companies”) to determine the Tranche TSR Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end date of the Cumulative Performance Period. In short, the TSR for a given performance period is defined as (i)(A) the average closing price of a common equity security at the end of the relevant performance period minus (B) the average closing price of a common equity security at the beginning of the relevant performance period plus (C) reinvested dividends divided by (ii) the average closing price of a common equity security at the beginning of the relevant performance period.

The following table sets out the levels at which the Tranche TSR Units may vest (using linear interpolation) based on the ENLC TSR percentile ranking for the applicable performance period relative to the TSR achievement of the Designated Peer Companies:



Performance Level	Achieved ENLC TSR Position Relative to Designated Peer Companies	Vesting percentage of the Tranche TSR Units
Below Threshold	Less than 25%	0%
Threshold	Equal to 25%	50%
Target	Equal to 50%	100%
Maximum	Greater than or Equal to 75%	200%

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Approximately one-third of the Total CF Units (the “Tranche CF Units”) relates to each of the first three performance periods described above (i.e., the Cash Flow performance goal does not relate to the Cumulative Performance Period). The Board will establish the Cash Flow performance targets for purposes of the column in the table below titled “ENLC’s Achieved Cash Flow” for each performance period no later than March 31 of the year in which the relevant performance period begins. Following the end date of a given performance period, the Committee will measure and determine the Cash Flow performance of ENLC to determine the Tranche CF Units that are eligible to vest, subject to the grantee’s continued employment or service with ENLC or its affiliates through the end of the Cumulative Performance Period. In short, the Performance-Based Award Agreement defines Cash Flow for a given performance period as (A)(i) ENLC’s adjusted EBITDA minus (ii) interest expense, current taxes and other, maintenance capital expenditures, and preferred unit accrued distributions divided by (B) the time-weighted average number of ENLC’s common units outstanding during the relevant performance period. The following table sets out the levels at which the Tranche CF Units will be eligible to vest (using linear interpolation) based on the Cash Flow performance of ENLC for the performance period ending December 31, 2019:



Performance Level	ENLC’s Achieved Cash Flow	Vesting percentage of the Tranche CF Units
Below Threshold	Less than $1.43	0%
Threshold	Equal to $1.43	50%
Target	Equal to $1.55	100%
Maximum	Greater than or Equal to $1.72	200%

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;~~Designated Peer Companies’ or Peer Companies’ securities as applicable; (iii) an estimated ranking of ENLC among the ~~designated peer group~~Designated Peer Companies or Peer Companies, 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.

~~Table of Contents~~

~~ENLINK MIDSTREAM, LLC~~

~~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:

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 ENLC performance units. That cost is expected to be recognized over a weighted-average period of 2.0 years.



EnLink Midstream, LLC Performance Units:	March 2019
Beginning TSR price	$	10.92
Risk-free interest rate	2.42		%
Volatility factor	33.86		%
Distribution yield	9.7		%

~~(13)~~(12) Derivatives

Interest Rate Swaps

We periodically enter into 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 swaps as hedges and, therefore, included the associated settlement gains and losses as interest expense, net of interest income, on the consolidated statements of operations.

In May 2017, we entered into an interest rate swap in connection with the issuance of ~~the~~ENLK’s 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 in accumulated ~~other~~ comprehensive loss on the consolidated balance sheets. We will amortize the settlement loss into interest expense on the 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 as of September 30, 2017. In addition, the settlement loss is included as an operating cash outflow on the consolidated statements of cash flows.~~

For the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2019, we amortized an immaterial amount of the settlement loss into interest expense from accumulated other comprehensive income (loss). We expect to recognize $0.1 million of interest expense out of accumulated other comprehensive income (loss) over the next twelve months.

~~In July 2016, we entered into an~~ We have no open interest rate swap ~~in connection with ENLK’s issuance~~positions as 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.March 31, 2019.

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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 both to manage and hedge price and location risk related to these market ~~exposures. Commodity swaps are also used~~exposures and 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~~swaps 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 commodity 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~~For condensate, crude oil, and natural gas, index swaps 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 oil, 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 on the consolidated statements of operations related to commodity swaps are (in millions):~~

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, 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 in “Gain on derivative activity” in 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.

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



	Three Months Ended March 31,
	2019			2018
Change in fair value of derivatives	$	(2.0	)	$	(3.5	)
Realized gain on derivatives	3.8			4.0
Gain on derivative activity	$	1.8		$	0.5

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



	March 31, 2019			December 31, 2018
Fair value of derivative assets—current	$	8.7		$	28.6
Fair value of derivative assets—long-term	4.6			4.1
Fair value of derivative liabilities—current	(6.6		)	(21.8		)
Fair value of derivative liabilities—long-term	(0.2		)	(2.4		)
Net fair value of derivatives	$	6.5		$	8.5

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Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Set forth below are the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at ~~September 30, 2017~~March 31, 2019 (in millions). The remaining term of the contracts extend no later than ~~October 2018.~~December 2022.

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 )

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~~ENLINK MIDSTREAM, LLC~~

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

~~(Unaudited)~~



		March 31, 2019
Commodity	Instruments	Unit	Volume		Fair Value
NGL (short contracts)	Swaps	Gallons	(13.8	)	$	1.2
NGL (long contracts)	Swaps	Gallons	2.6		(0.1		)
Natural Gas (short contracts)	Swaps	MMBtu	(3.0	)	—
Natural Gas (long contracts)	Swaps	MMBtu	4.6		(1.1		)
Crude and condensate (short contracts)	Swaps	MMbbls	(12.7	)	9.7
Crude and condensate (long contracts)	Swaps	MMbbls	1.5		(3.2		)
Total fair value of derivatives					$	6.5

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 swap contracts, ~~our~~the maximum loss on our gross receivable position of ~~$4.7~~$13.3 million as of ~~September 30, 2017~~March 31, 2019 would be reduced to ~~$1.7~~$7.5 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

~~(14)~~(13) Fair Value Measurements

ASC 820, Fair Value Measurements 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)~~ measured at fair value on a recurring basis are summarized below (in millions):

Level 2
September 30, 2017 December 31, 2016
Commodity Swaps (1) $ (2.5 ) $ (6.3 )
Total $ (2.5 ) $ (6.3 )



	Level 2
	March 31, 2019		December 31, 2018
Commodity Swaps (1)	$	6.5	$	8.5

____________________________


(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.

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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, 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



	March 31, 2019				December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current maturities of long-term debt (1)	$	4,475.6	$	4,321.6	$	4,430.8	$	4,065.0
Secured term loan receivable	$	52.5	$	52.5	$	51.1	$	51.1

____________________________


(1)	The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance costs of ~~$27.2~~$28.4 million and ~~$24.6~~$24.5 million at ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016,~~2018, 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~~As of ~~September 30, 2017 and $120.0 million of outstanding borrowings under the ENLK Credit Facility as of December~~March 31, ~~2016. ENLC had $74.0 million and $27.8 million in outstanding borrowings under the ENLC Credit Facility as of September 30, 2017~~2019 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, 2016,2018, 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~~March 31, 2019 and December 31, ~~2016~~2018 were based on Level 2 inputs from third-party market quotations. The fair values of ~~obligations under capital leases~~the secured term loan receivable 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

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~~ENLINK MIDSTREAM, LLC~~

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

~~(Unaudited)~~

information, compliance with these laws 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 time and, thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation.(14) Segment Information

InEffective January 1, 2019, we changed our reportable operating segments to reflect how we currently make financial decisions and allocate resources. As of December 31, 2018, our reportable operating segments consisted of the second quarter of 2017, we reached a settlement agreement with the Ohio Environmental Protection Agency with respect to the previously disclosed notices of violation (“NOVs”) relating to certain of our ORVfollowing: (i) natural gas gathering, processing, transmission, and fractionation operations ~~that were previously operated by a joint venture partner. The settlement payment 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 one of our~~located in north Texas and the Permian Basin primarily in west Texas, (ii) natural gas pipelines, processing plants, storage facilities, NGL pipelines, and self-reported these matters to the Texas Commission on Environment Quality (“TCEQ”). On October 4, 2017, we received and accepted an Agreed Order from the TCEQ related to these instances of non-compliance. The final penalty assessed was not material to the results of our operations, financial condition or cash flows.

Finally, 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 to historic industry operations in those areas. The suit was filedfractionation assets 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 pipelines in the area. On February 13, 2015, the court granted defendants’ joint motion to dismiss(iii) natural gas gathering 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~~processing operations located throughout Oklahoma, and ~~operate a high-pressure~~(iv) crude rail, truck, pipeline, and ~~underground~~barge facilities in west Texas, south Texas, Louisiana, Oklahoma, and ORV. Effective January 1, 2019, we are reporting financial performance in five segments: Permian, North Texas, Oklahoma, Louisiana, and Corporate. Crude and condensate operations are combined regionally with natural gas and NGL ~~storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed~~operations in the ~~vicinity of this pipeline~~Oklahoma and ~~underground storage reservoirs, resulting in damage to certain of our facilities. In order to recover our losses from responsible parties, we sued the operator of a failed cavern~~Permian segments, and ORV operations are included in the ~~area, and its insurers, seeking recovery~~Louisiana segment. We have recast the segment information for ~~these losses, as well as other parties we alleged contributed~~the three months ended March 31, 2018 to conform 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.

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~~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~~current period presentation.

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:~~served:

Permian Segment. The Permian segment includes our natural gas gathering, processing, and transmission activities and ~~fractionation~~our crude oil operations ~~located~~ in ~~north Texas and~~ the Midland and Delaware ~~basins~~Basins in west Texas ~~(“Texas”),~~and eastern New Mexico and our crude operations in south Texas;

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

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;

Louisiana Segment. The Louisiana segment includes our natural gas pipelines, natural gas processing plants, storage facilities, fractionation facilities, and NGL assets located in Louisiana ~~(“Louisiana”), natural gas gathering~~ and ~~processing~~our crude oil operations ~~located throughout Oklahoma (“Oklahoma”)~~in ORV; 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.

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, our ownership interest in GCF in south Texas, our derivative activity, and our general corporate assets and expenses.

We evaluate the performance of our operating segments based on segment profits. Summarized financial information for our reportable segments is shown in the following tables (in millions):


	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals			Permian			North Texas			Oklahoma			Louisiana			Corporate			Totals
Three Months Ended September 30, 2017
Three Months Ended March 31, 2019
Natural gas sales																			$	36.1		$	50.6		$	61.6		$	122.2		$	—		$	270.5
NGL sales																			(0.2		)	9.3			8.9			573.1			—			591.1
Crude oil and condensate sales																			580.8			—			29.6			58.8			—			669.2
Other																			—			—			0.1			—			—			0.1
Product sales	$	80.8		$	642.3		$	42.5		$	291.1		$	—		$	1,056.7		616.7			59.9			100.2			754.1			—			1,530.9
NGL sales—related parties																			97.2			28.5			126.1			3.2			(255.0		)	—
Crude oil and condensate sales—related parties																			4.0			1.0			—			—			(5.0		)	—
Product sales—related parties	130.6			10.0			94.6			—			(199.9		)	35.3			101.2			29.5			126.1			3.2			(260.0		)	—
Gathering and transportation																			10.3			63.6			55.3			17.2			—			146.4
Processing																			7.7			21.1			34.1			0.9			—			63.8
NGL services																			—			—			—			11.7			—			11.7
Crude services																			5.2			—			4.0			13.8			—			23.0
Other services																			1.5			0.2			(0.3		)	0.2			—			1.6
Midstream services	29.1			50.3			44.3			12.7			—			136.4			24.7			84.9			93.1			43.8			—			246.5
NGL services—related parties																			—			—			—			(3.0		)	3.0			—
Crude services—related parties																			—			—			0.3			—			(0.3		)	—
Midstream services—related parties	106.7			35.9			63.0			4.8			(35.4		)	175.0			—			—			0.3			(3.0		)	2.7			—
Revenue from contracts with customers																			742.6			174.3			319.7			798.1			(257.3		)	1,777.4
Cost of sales	(198.5		)	(662.7		)	(148.2		)	(279.1		)	235.3			(1,053.2		)	(676.2		)	(73.7		)	(184.2		)	(686.6		)	257.3			(1,363.4		)
Operating expenses	(41.1		)	(24.8		)	(17.1		)	(19.1		)	—			(102.1		)	(27.8		)	(25.7		)	(25.4		)	(35.6		)	—			(114.5		)
Loss on derivative activity	—			—			—			—			(5.5		)	(5.5		)
Segment profit (loss)	$	107.6		$	51.0		$	79.1		$	10.4		$	(5.5	)	$	242.6
Gain on derivative activity																			—			—			—			—			1.8			1.8
Segment profit																			$	38.6		$	74.9		$	110.1		$	75.9		$	1.8		$	301.3
Depreciation and amortization	$	(52.5	)	$	(29.3	)	$	(40.2	)	$	(11.7	)	$	(2.6	)	$	(136.3	)	$	(27.9	)	$	(34.3	)	$	(46.1	)	$	(41.8	)	$	(2.0	)	$	(152.1	)
Impairments	$	—		$	—		$	—		$	(1.8	)	$	—		$	(1.8	)	$	—		$	—		$	—		$	(186.5	)	$	—		$	(186.5	)
Goodwill	$	232.0		$	—		$	190.3		$	—		$	1,119.9		$	1,542.2		$	184.6		$	125.7		$	813.4		$	—		$	—		$	1,123.7
Capital expenditures	$	39.1		$	7.5		$	107.7		$	13.3		$	2.1		$	169.7		$	95.9		$	4.3		$	108.2		$	41.0		$	1.6		$	251.0

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

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ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

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



	Permian			North Texas			Oklahoma			Louisiana			Corporate			Totals
Three Months Ended March 31, 2018
Natural gas sales	$	37.7		$	45.3		$	48.1		$	125.0		$	—		$	256.1
NGL sales	0.5			—			1.9			608.4			—			610.8
Crude oil and condensate sales	577.2			—			21.9			33.2			—			632.3
Product sales	615.4			45.3			71.9			766.6			—			1,499.2
Natural gas sales—related parties	—			—			0.5			—			—			0.5
NGL sales—related parties	83.9			9.0			100.1			5.6			(196.2		)	2.4
Crude oil and condensate sales—related parties	1.5			0.4			0.4			0.1			(1.7		)	0.7
Product sales—related parties	85.4			9.4			101.0			5.7			(197.9		)	3.6
Gathering and transportation	6.2			7.8			15.6			17.6			—			47.2
Processing	3.8			—			9.0			0.6			—			13.4
NGL services	—			—			—			16.6			—			16.6
Crude services	—			—			0.1			12.8			—			12.9
Other services	1.7			0.3			0.1			—			—			2.1
Midstream services	11.7			8.1			24.8			47.6			—			92.2
Gathering and transportation—related parties	—			52.6			34.7			—			—			87.3
Processing—related parties	—			51.6			22.1			—			—			73.7
Crude services—related parties	4.3			—			0.7			—			—			5.0
Other services—related parties	—			—			0.2			—			—			0.2
Midstream services—related parties	4.3			104.2			57.7			—			—			166.2
Revenue from contracts with customers	716.8			167.0			255.4			819.9			(197.9		)	1,761.2
Cost of sales	(674.1		)	(49.9		)	(139.3		)	(716.1		)	197.9			(1,381.5		)
Operating expenses	(23.8		)	(28.4		)	(20.7		)	(36.3		)	—			(109.2		)
Gain on derivative activity	—			—			—			—			0.5			0.5
Segment profit	$	18.9		$	88.7		$	95.4		$	67.5		$	0.5		$	271.0
Depreciation and amortization	$	(26.8	)	$	(31.3	)	$	(42.1	)	$	(35.9	)	$	(2.0	)	$	(138.1	)
Goodwill	$	29.3		$	202.7		$	190.3		$	—		$	1,119.9		$	1,542.2
Capital expenditures	$	63.6		$	2.5		$	103.9		$	10.0		$	1.2		$	181.2

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

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~~



	Three Months Ended March 31,
	2019			2018
Segment profit	$	301.3		$	271.0
General and administrative expenses	(51.4		)	(27.5		)
Loss on disposition of assets	—			(0.1		)
Depreciation and amortization	(152.1		)	(138.1		)
Impairments	(186.5		)	—
Operating income (loss)	$	(88.7	)	$	105.3

The ~~following schedule summarizes non-cash financing activities for the periods presented~~table below represents information about segment assets as of March 31, 2019 and December 31, 2018 (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



Segment Identifiable Assets:	March 31, 2019		December 31, 2018
Permian	$	2,382.6	$	2,096.8
North Texas	1,365.2		1,308.2
Oklahoma	3,906.6		3,209.5
Louisiana	2,626.8		2,734.5
Corporate	225.6		1,345.1
Total identifiable assets	$	10,506.8	$	10,694.1


~~(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)~~(15) 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
Other Current Assets:					March 31, 2019		December 31, 2018
Natural gas and NGLs inventory	$	59.1	$	17.4	$	39.4	$	41.3
Secured term loan receivable from contract restructuring, net of discount of $0.8 and $1.1					23.2		19.4
Prepaid expenses and other	14.3		16.1		10.8		13.5
Natural gas and NGLs inventory, prepaid expenses and other	$	73.4	$	33.5
Natural gas and NGLs inventory, prepaid expenses, and other					$	73.4	$	74.2


	September 30, 2017		December 31, 2016
Other Current Liabilities:					March 31, 2019		December 31, 2018
Accrued interest	$	64.8	$	34.2	$	65.3	$	37.5
Accrued wages and benefits, including taxes	23.2		19.0		16.9		37.2
Accrued ad valorem taxes	33.5		23.5		13.1		28.1
Capital expenditure accruals	43.6		64.6		59.9		50.6
Onerous performance obligations	15.4		15.9		4.5		9.0
Short-term lease liability					18.1		1.5
Suspense producer payments					18.4		34.6
Other	54.7		60.3		34.4		49.7
Other current liabilities	$	235.2	$	217.5	$	230.6	$	248.2

Table of Contents

ENLINK MIDSTREAM, LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(16) Subsequent Event

Senior Unsecured Notes due 2029. On April 9, 2019, ENLC issued $500.0 million in aggregate principal amount of ENLC’s 5.375% senior unsecured notes due June 1, 2029 (the “2029 Notes”) at a price to the public of 100% of their face value. Interest payments on the 2029 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2019. The 2029 Notes are fully and unconditionally guaranteed by ENLK. Net proceeds of approximately $496.5 million were used to repay outstanding borrowings under the Consolidated Credit Facility, including borrowings incurred on April 1, 2019 to repay at maturity all of the $400.0 million outstanding aggregate principal amount of ENLK’s 2.70% senior unsecured notes due 2019, and for general limited liability company purposes.

Secured Term Loan Receivable. In April 2019, we became aware that the counterparty to our $58.0 million second lien secured term loan receivable, which was recorded at its discounted present value of $52.5 million on the consolidated balance sheet as of March 31, 2019, as described in “Note 13—Fair Value Measurements,” will not be able to make its contractual installment payment in May 2019 of $9.75 million for principal due on the outstanding balance. The counterparty has notified us that it is evaluating financial and strategic alternatives in order to satisfy its obligations, including obligations to its first lien secured lenders and our second lien secured term loan. There can be no assurance that any of these alternatives will occur or that we will collect all of the outstanding amounts under the second lien secured term loan.

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” 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 LPPartnership 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.EOGP.

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~~ENLK and, ~~EnLink Oklahoma T.O. EnLink Midstream Partners, LP is~~effective January 25, 2019, ENLC owns all of the outstanding common units of ENLK as a ~~publicly traded limited partnership engaged~~result of the closing of the Merger described in ~~the gathering, transmission, processing~~“Item 1. Financial Statements—Note 1—General.” All of our midstream energy assets are owned 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~~operated 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. consisted of the following as of September 30, 2017:~~

~~88,528,451 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; and

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

~~Each of 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.~~ condensate, in addition to brine disposal services.

Our midstream energy asset network includes approximately 11,000 miles of pipelines, 20 natural gas processing plants with approximately ~~4.5 billion cubic feet per day~~5.0 Bcf/d of processing capacity, 7seven fractionators with approximately ~~260,000 barrels per day~~280,000 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:

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 and our crude operations in south Texas;

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

Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and ~~processing~~transmission activities, and our crude oil operations in the Cana-Woodford, Arkoma-Woodford, ~~Northern~~northern Oklahoma Woodford, ~~Sooner Trend Anadarko Basin Canadian~~STACK, and CNOW shale areas;

~~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, fractionation facilities, and NGL assets located in ~~Louisiana;~~

~~Crude~~Louisiana 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;~~ORV; and

Corporate Segment. The Corporate segment includes our unconsolidated affiliate investments in the Cedar Cove JV in Oklahoma, our ~~contractual right to the economic burdens and benefits associated with Devon’s~~ ownership interest in ~~Gulf Coast Fractionators (“GCF”)~~GCF in south Texas, our derivative activity, 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 operations by focusing on 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.~~rail terminal. We define 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%~~91% of our gross operating margin was derived from fee-based ~~services~~

contractual arrangements with nominimal direct commodity price exposure for the ~~nine~~three months ended ~~September 30, 2017.~~March 31, 2019. We reflect revenue as “Product sales” and “Midstream services” on the consolidated statements of operations.

Devon is one of our primary customers. For the three months ended March 31, 2019 and 2018, approximately 30.0% and 39.0%, respectively, of our gross operating margin was attributable to commercial contracts with Devon.

~~We generate~~Our revenues and gross operating 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 natural gas, crude oil, 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 our crude terminals;~~

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

~~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 gross operating margins from product upgrades during periods with higher NGL prices.

~~We typically~~We 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 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 component 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 gross operating margins are higher during periods of high NGL prices relative to natural gas prices. Gross operating 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 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 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 ~~the asset.~~our assets.

Recent Developments

~~Organic Growth~~

~~Black Coyote Crude Oil Gathering System.~~ We are expanding in the core of the STACK play in Central Oklahoma with the construction of a new crude oil gathering system that we refer to as “Black Coyote.” Black Coyote will primarily be built on dedicated acreage from Devon, who will be the main shipper on the system. The system is expected to be operational in the first quarter of 2018.

~~Chisholm Plants.~~ In April 2017, we completed construction of a new cryogenic gas processing plant, referred to as Chisholm II, which provides 200 MMcf/d of processing capacity and is tied to new and existing pipelines in the STACK and SCOOP plays in Oklahoma. The new capacity is supported by new and existing long-term contracts.

In addition, we commenced construction 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 in the STACK and SCOOP plays. Construction is scheduled to be completed during the fourth quarter of 2017.

~~Greater Chickadee Crude Oil Gathering System~~.In March 2017, we completed construction and began operations of a crude oil gathering system in Upton and Midland counties, Texas in the Permian Basin that we refer to as “Greater Chickadee.” Greater Chickadee includes over 185 miles of high- and low-pressure pipelines that transport crude oil volumes to several major market outlets and other key hub centers in the Midland, Texas area. Greater Chickadee also includes multiple central tank batteries, together with pump, truck injection and storage stations to maximize shipping 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”), is a bolt-on project to 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 Mexico 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, we recorded an impairment loss of $20.1 million to reduce the carrying value of our investment to the expected sales price. Upon the final sale of HEP in March 2017, we recorded an additional loss of $3.4 million for the nine months ended September 30, 2017.

Senior Unsecured Notes due ~~2047~~2029.

On ~~May 11, 2017, ENLK~~April 9, 2019, ENLC issued $500.0 million in aggregate principal amount of ~~ENLK’s 5.450%~~ENLC’s 5.375% senior unsecured notes due June 1, ~~2047~~2029 (the ~~“2047~~“2029 Notes”) at a price to the public of ~~99.981%~~100% of their face value. Interest payments on the ~~2047~~2029 Notes are payable on June 1 and December 1 of each year, beginning December 1, ~~2017.~~2019. The 2029 Notes are fully and unconditionally guaranteed by ENLK. Net proceeds of approximately ~~$495.2~~$496.5 million were used to repay outstanding borrowings under the ~~ENLK~~Consolidated Credit Facility, ~~and for general partnership purposes.~~

~~Redemption~~including borrowings incurred on April 1, 2019 to repay at maturity all of ~~Senior Unsecured Notes due 2022~~

~~On June 1, 2017, ENLK redeemed $162.5~~the $400.0 million inoutstanding aggregate principal amount of ENLK’s ~~7.125%~~2.70% senior unsecured notes ~~(the “2022 Notes”) at 103.6% of the principal amount, plus accrued unpaid interest,~~due 2019, and 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.~~

~~Issuance of ENLK Common Units~~

In November 2014, ENLK entered into an Equity Distribution Agreement (the “2014 EDA”) with BMO Capital Markets Corp. and other sales agents to sell up to $350.0 million in aggregate gross sales of ENLK’s common units from time to time through an “at 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 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 of the common units under the 2017 EDA and may at any time suspend solicitation and offers under the 2017 EDA.general limited liability company purposes.

~~Issuance of ENLK Series C Preferred Units~~

In September 2017, ENLK issued 400,000 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 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, the Series C Preferred Units rank senior to ENLK’s common units and to each other class of limited partner interests or other equity securities established after the issue dateSimplification of the ~~Series C Preferred Units that is not expressly made senior or~~Corporate Structure. On October 21, 2018, ENLK, ENLC, the General Partner, the managing member of ENLC, and NOLA Merger Sub entered into the Merger Agreement pursuant to which, on ~~parity~~January 25, 2019, NOLA Merger Sub merged with and into ENLK, with ENLK continuing as the ~~Series C Preferred Units. The Series C Preferred Units will rank junior to the Series B Preferred Units with respect to the payment~~surviving entity and as a subsidiary 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.ENLC.

~~At any time on or after December 15, 2022, ENLK may redeem, at ENLK’s option,~~Reporting Segments. Effective January 1, 2019, we are reporting financial performance in ~~whole or~~five segments: Permian, North Texas, Oklahoma, Louisiana, and Corporate. Crude and condensate operations are combined regionally with natural gas and NGL operations in ~~part,~~ the ~~Series C Preferred Units at a redemption price~~Oklahoma and Permian segments, and ORV operations are included 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.Louisiana segment. See “Item 1. Financial Statements—Note 14—Segment Information” for more information regarding reporting segments.

~~Distributions~~Transfer of EOGP Interest. On January 31, 2019, ENLC transferred its 16.1% limited partner interest in EOGP to the Operating Partnership. See “Item 1. Financial Statements—Note 1—General” for more information regarding this transaction.

Lobo Natural Gas Gathering and Processing Facilities. In early April 2019, we completed construction of a 100 MMcf/d expansion to our Lobo III cryogenic gas processing plant, bringing the total operational processing capacity at our Lobo facilities to 375 MMcf/d.

Cajun-Sibon Pipeline. In April 2019, we completed the expansion of our Cajun-Sibon NGL pipeline capacity, which connects the Mont Belvieu NGL hub to our fractionation facilities in Louisiana. This is the third phase of our Cajun-Sibon system referred to as Cajun Sibon III, which increases throughput capacity from 130,000 bbls/d to 185,000 bbls/d.

Avenger Crude Oil Gathering System. We commenced construction on a new crude oil gathering system in the northern Delaware Basin called Avenger. Avenger is supported by a long-term contract with Devon on dedicated acreage in their Todd and Potato Basin development areas in Eddy and Lea counties in New Mexico. We commenced initial operations on Avenger during the third quarter of 2018 and expect to begin full-service operations during the second quarter of 2019.

Central Oklahoma Plants. In December 2017, we commenced construction on our Thunderbird Plant to expand our central Oklahoma processing capacity by an additional 200 MMcf/d gas processing plant. We expect to begin operations on the ~~Series C Preferred Units accrue and are cumulative from~~Thunderbird Plant during the ~~date~~second quarter of ~~original issue and payable semi-annually~~2019.

Riptide Processing Plant. We commenced an expansion of our Riptide processing plant. We expect an additional 65MMcf/d of operational capacity to be completed during the fourth quarter of 2019.

Delaware Basin processing plant. We plan to construct a 200 MMcf/d gas processing plant in ~~arrears on~~ the 15^th ~~day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly~~Delaware Basin. We expect the plant to be operational 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%.2020.

Non-GAAP Financial Measures

We include the following non-GAAP financial measures: ~~Cash~~Adjusted earnings before interest, taxes, and depreciation and amortization (“adjusted EBITDA”), distributable cash flow available ~~for distribution~~to common unitholders (“distributable cash flow”), and gross operating margin.

~~Cash Available for Distribution~~Adjusted EBITDA

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),~~as net income (loss) plus interest expense, provision (benefit) for income taxes, depreciation and amortization expense, impairments, unit-based compensation, (gain) loss on non-cash derivatives, (gain) loss on disposition of assets, (gain) loss on extinguishment of debt, successful transaction costs, accretion expense associated with asset retirement obligations, non-cash rent, and distributions from unconsolidated affiliate investments, less payments under onerous performance obligations, non-controlling interest, income (loss) from unconsolidated affiliate investments, and non-cash revenue from contract restructuring. Adjusted EBITDA is a primary metric used in our ~~share of maintenance capital attributable to our interest in EnLink Oklahoma T.O., our specific general and administrative costs~~short-term incentive program for compensating employees. In addition, adjusted EBITDA is used as a ~~separate public reporting entity, the interest costs associated with our debt~~supplemental liquidity 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 usour management and by external users of our financial statements, such as investors, commercial banks, research analysts, and ~~others. As ENLC~~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 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, income taxes, or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a ~~holding company without~~necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any ~~direct operations,~~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 activities as determined under GAAP, as well as adjusted EBITDA, to evaluate our overall performance.

The following tables reconcile adjusted EBITDA to the most directly comparable GAAP measure for the periods indicated (in millions):

Reconciliation of net income (loss) to adjusted EBITDA



	Three Months Ended March 31,
	2019			2018
Net income (loss)	$	(134.8	)	$	57.1
Interest expense, net of interest income	49.6			44.5
Depreciation and amortization	152.1			138.1
Impairments	186.5			—
Income from unconsolidated affiliates	(5.3		)	(3.0		)
Distributions from unconsolidated affiliates	2.5			6.0
Loss on disposition of assets	—			0.1
Unit-based compensation	11.1			5.1
Income tax provision	1.8			7.0
Loss on non-cash derivatives	2.0			3.5
Payments under onerous performance obligation offset to other current and long-term liabilities	(4.5		)	(4.5		)
Transaction costs (1)	13.5			—
Other (2)	0.3			1.0
Adjusted EBITDA before non-controlling interest	274.8			254.9
Non-controlling interest share of adjusted EBITDA from joint ventures (3)	(6.6		)	(3.6		)
Adjusted EBITDA, net to ENLC	$	268.2		$	251.3

____________________________


(1)	Represents transaction costs attributable to costs incurred related to the Merger.


(2)	Includes accretion expense associated with 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, Marathon Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV, and other minor non-controlling interests.

Distributable Cash Flow

We define distributable cash flow as adjusted EBITDA, net to ENLC, ~~primarily generates value for its unitholders~~less interest expense, interest rate swaps, current income taxes and other non-distributable cash flows, accrued cash distributions on ENLK Series B Preferred Units and ENLK Series C Preferred Units paid or expected to be paid, and maintenance capital expenditures, excluding maintenance capital expenditures that were contributed by ~~generating returns on its investments in~~ other entities and ~~subsequently distributing these returns in~~relate to the non-controlling interest share of our consolidated entities. Distributable cash flow is used as a supplemental liquidity measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts, and others, to ~~its unitholders. Therefore,~~assess the ability of our assets to generate cash ~~available for distribution serves as an important measure of ENLC’s profitability~~sufficient to pay interest costs, support our indebtedness, and ~~serves as an indicator of ENLC’s success in providing a~~make cash ~~return on its investments to its unitholders.~~distributions.

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 distributable cash ~~available for distribution~~flow is net ~~income (loss). Cash available for distribution~~cash provided by operating activities. Distributable cash flow should not be considered as an alternative to, ~~GAAP~~or more meaningful than, net income (loss)~~. Cash available for distribution is not a presentation made~~, operating income (loss), net cash provided by operating activities, or any other measure of liquidity presented in accordance with ~~GAAP and~~GAAP. Distributable cash flow 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 distributionbecause it excludes some items that affect net income (loss), operating income (loss), and ~~is defined differently~~net cash provided by ~~different companies in our industry, our definition of~~operating activities. Distributable cash ~~available for distribution~~flow may not be comparable to similarly-titled measures of other companies ~~thereby diminishing its utility.~~because other companies may not calculate distributable cash flow 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 distributable cash flow, to evaluate our overall liquidity.

~~The following is a calculation~~Reconciliation of ~~ENLC’s~~net cash ~~available for distribution~~provided by operating activities to adjusted EBITDA and Distributable Cash Flow (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



	Three Months Ended March 31,
	2019
Net cash provided by operating activities	$	264.0
Interest expense (1)	49.5
Current income tax expense	1.0
Transaction costs (2)	13.5
Other (3)	(1.5		)
Changes in operating assets and liabilities which (provided) used cash:
Accounts receivable, accrued revenues, inventories and other	(97.4		)
Accounts payable, accrued product purchases, and other accrued liabilities (4)	45.7
Adjusted EBITDA before non-controlling interest	274.8
Non-controlling interest share of adjusted EBITDA from joint ventures (5)	(6.6		)
Adjusted EBITDA, net to ENLC	268.2
Interest expense, net of interest income	(49.6		)
Current taxes and other	(2.5		)
Maintenance capital expenditures, net to ENLC (6)	(8.5		)
ENLK preferred unit accrued cash distributions (7)	(22.7		)
Distributable cash flow	$	184.9

____________________________

(1)

~~Represents distributions to be paid to ENLC on~~ ~~November 13, 2017~~ Net of amortization of debt issuance costs and ~~distributions paid on~~ ~~August 11, 2017~~, ~~May 12, 2017, November 11, 2016~~, ~~August 11, 2016~~discount and ~~May 12, 2016.~~premium, 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)	Represents ~~ENLC’s interest in EnLink Oklahoma T.O. adjusted EBITDA, which is disbursed~~transaction costs incurred related 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.the Merger.


(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.~~Includes accruals for settled commodity swap transactions.


(4)	~~Represents ENLC’s stand-alone~~Net of payments under onerous performance obligation offset to other current ~~tax expense.~~ and long-term liabilities.


(5)	~~Represents ENLC’s~~Non-controlling interest ~~in EnLink Oklahoma T.O.s’ maintenance capital expenditures which is netted against the monthly disbursement~~share 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~~from joint ventures includes NGP’s 49.9% share of adjusted EBITDA from the Delaware Basin JV, ~~which was formed in August 2016,~~ Marathon ~~Petroleum’s~~Petroleum Corporation’s 50% share of adjusted EBITDA from the Ascension JV, ~~which began operations in April 2017,~~ and other minor non-controlling interests.


~~(5)~~(6)	Excludes maintenance capital expenditures that were contributed by other entities and relate to the non-controlling interest share of our consolidated entities.

(7)

Represents ~~transaction costs attributable to ENLC’s share~~the cash distributions earned by the ENLK Series B Preferred Units and ENLK Series C Preferred Units of ~~the acquisition of EnLink Oklahoma T.O.~~ $16.7 million and $6.0 million, respectively, 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~~ March 31, 2019. Cash distributions to be paid to holders of the ENLK Series B Preferred Units and ~~other non-cash items~~ENLK Series C Preferred Units are not ~~included in cash~~ available ~~for distribution.~~to common unitholders.

Distributable cash flow is not presented for the three months ended March 31, 2018 because distributable cash flow was not used as a supplemental liquidity measure by ENLC during 2018. ENLC began using distributable cash flow as a supplemental liquidity measure in 2019 as a result of the simplification of our corporate structure in the Merger.

Gross Operating Margin

We define gross operating margin as revenues less cost of sales. We present gross operating margin by segment in “Results of Operations.” We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe 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 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 operating expenses from total revenue in calculating 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 gross operating margin is operating income (loss). Gross operating margin should not be considered an alternative to, or more meaningful than, operating income (loss) as determined in accordance with GAAP. Gross operating margin has important limitations because it excludes all operating costs that affect operating income (loss) except cost of sales. Our gross operating margin may not be comparable to similarly-titled measures of other companies because other entities may not calculate these amounts in the same manner.

The following table provides a reconciliation of operating income ~~(loss)~~ to gross operating margin (in millions):


	Three Months Ended September 30,					Nine Months Ended September 30,						Three Months Ended March 31,
	2017		2016			2017			2016			2019			2018
Operating income (loss)	$	72.1	$	65.9		197.5			$	(713.7	)
Operating income												$	(88.7	)	$	105.3

Add (deduct):
Add:
Operating expenses	102.1		98.0			308.8			296.3			114.5			109.2
General and administrative expenses	31.3		29.3			98.5			94.7			51.4			27.5
(Gain) loss on disposition of assets	1.1		(3.0		)	0.8			(2.9		)
Loss on disposition of assets												—			0.1
Depreciation and amortization	136.3		126.2			407.1			373.0			152.1			138.1
Impairments	1.8		—			8.8			873.3			186.5			—
Gain on litigation settlement	—		—			(26.0		)	—
Gross operating margin	$	344.7	$	316.4		$	995.5		$	920.7		$	415.8		$	380.2

Results of Operations

The table below sets forth certain financial and operating data for the periods indicated. We manage our 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,						Three Months Ended March 31,
	2017			2016			2017			2016			2019			2018
Texas Segment
Permian Segment
Revenues													$	742.6		$	716.8
Cost of sales													(676.2		)	(674.1		)
Total gross operating margin													$	66.4		$	42.7
North Texas Segment
Revenues													$	174.3		$	167.0
Cost of sales													(73.7		)	(49.9		)
Total gross operating margin													$	100.6		$	117.1
Oklahoma Segment
Revenues	$	347.2		$	280.2		$	997.2		$	767.4		$	319.7		$	255.4
Cost of sales	(198.5		)	(134.1		)	(554.7		)	(329.0		)	(184.2		)	(139.3		)
Total gross operating margin	$	148.7		$	146.1		$	442.5		$	438.4		$	135.5		$	116.1
Louisiana Segment
Revenues	$	738.5		$	542.4		$	2,021.0		$	1,398.3		$	798.1		$	819.9
Cost of sales	(662.7		)	(471.5		)	(1,803.1		)	(1,199.1		)	(686.6		)	(716.1		)
Total gross operating margin	$	75.8		$	70.9		$	217.9		$	199.2		$	111.5		$	103.8
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
Corporate Segment
Revenues	$	(240.8	)	$	(126.7	)	$	(591.0	)	$	(276.5	)	$	(255.5	)	$	(197.4	)
Cost of sales	235.3			126.2			589.9			269.9			257.3			197.9
Total gross operating margin	$	(5.5	)	$	(0.5	)	$	(1.1	)	$	(6.6	)	$	1.8		$	0.5
Total
Revenues	$	1,397.9		$	1,104.6		$	3,983.4		$	3,027.5		$	1,779.2		$	1,761.7
Cost of sales	(1,053.2		)	(788.2		)	(2,987.9		)	(2,106.8		)	(1,363.4		)	(1,381.5		)
Total gross operating margin	$	344.7		$	316.4		$	995.5		$	920.7		$	415.8		$	380.2

Midstream Volumes:
Texas
Permian Segment
Gathering and Transportation (MMBtu/d)	2,251,700			2,579,500			2,265,900			2,657,600			657,500			424,000
Processing (MMBtu/d)	1,194,300			1,172,200			1,178,800			1,188,100			712,000			442,000
Louisiana
Crude Oil Handling (Bbls/d)													147,400			107,900
North Texas Segment
Gathering and Transportation (MMBtu/d)	2,009,300			1,754,400			1,960,300			1,602,400			1,683,100			1,766,800
Processing (MMBtu/d)	443,400			487,900			452,500			496,400			729,800			752,100
NGL Fractionation (Gals/d)	5,814,800			5,259,400			5,630,600			5,194,700
Oklahoma
Oklahoma Segment
Gathering and Transportation (MMBtu/d)	889,200			624,500			787,400			620,300			1,244,400			1,047,900
Processing (MMBtu/d)	872,200			570,100			753,500			571,800			1,231,600			1,069,400
Crude and Condensate
Crude Oil Handling (Bbls/d)	95,700			72,800			104,500			98,300			29,200			8,200
Louisiana Segment
Gathering and Transportation (MMBtu/d)													2,070,500			2,222,900
Processing (MMBtu/d)													468,000			441,900
Crude Oil Handling (Bbls/d)													15,000			11,500
NGL Fractionation (Gals/d)													6,973,800			6,343,500
Brine Disposal (Bbls/d)	4,800			3,700			4,700			3,500			3,500			2,800

Three Months Ended ~~September 30, 2017~~March 31, 2019 Compared to Three Months Ended ~~September 30, 2016~~March 31, 2018

Gross Operating Margin. Gross operating margin was ~~$344.7~~$415.8 million for the three months ended ~~September 30, 2017~~March 31, 2019 compared to ~~$316.4~~$380.2 million for the three months ended ~~September 30, 2016,~~March 31, 2018, an increase of ~~$28.3~~$35.6 million, or ~~8.9%~~9.4%, due to the following:

~~Texas~~Permian Segment. Gross operating margin in the ~~Texas~~Permian segment increased ~~$2.6~~$23.7 million, which was primarily due to a ~~$7.3~~$16.8 million increase in gross operating margin due to higher volumes on our Permian gas assets from continued producer development in the region, including $8.9 million from our Delaware Basin assets and $7.9 million from our Midland Basin assets. The remaining increase of $6.9 million was contributed by our Permian Basin ~~processing~~crude assets, ~~as a result~~including the Avenger system, which commenced operations in the third quarter of ~~higher volumes. This increase~~2018.

North Texas Segment. Gross operating margin in the North Texas segment decreased $16.5 million primarily due to the January 1, 2019 expiration of Devon’s obligations related to MVCs on our North Texas assets. Shortfall revenue from the Devon-related MVCs was $18.1 million for the three months ended March 31, 2018, which was partially offset by ~~a $2.4~~an increase of $1.6 million ~~decrease~~from other gathering and transportation agreements for the three months ended March 31, 2019.

Oklahoma Segment. Gross operating margin in the Oklahoma segment increased $19.4 million, which was primarily due to ~~volume declines across our north Texas~~higher volumes from continued producer development in the region. Our Oklahoma gas assets ~~and a $2.0~~contributed $15.4 million ~~decrease due to the sale~~ of the ~~North Texas Pipeline (the “NTPL”)~~increase, and our Oklahoma crude assets ~~in December 2016.~~contributed the remaining increase of $4.0 million.

Louisiana Segment. Gross operating margin in the Louisiana segment increased ~~$4.9~~$7.7 million, ~~which was primarily due to~~including a ~~$3.2~~$4.1 million increase from our gas 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 in the Oklahoma segment~~ ~~increased $30.4 million, which was primarily~~ due to higher volumes on our ~~central Oklahoma assets.~~

~~Crude and Condensate Segment.~~ ~~Gross operating margin in the Crude and Condensate segment~~ ~~decreased $4.6 million, which was primarily due to a $3.8 million decrease as a result of condensate stabilization volume declines and transportation rate decreases on our~~ ORV crude 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 operational induring the first quarter of ~~2017.~~2019 and a $3.6 million increase from our Louisiana gas and NGL operations. The increase from our Louisiana gas and NGL operations is primarily due to the negative effect of seasonal gas price fluctuations during the first quarter of 2018, which was offset by realized gains from our hedging activities recorded in our Corporate segment.

Corporate Segment. Gross operating margin in the Corporate segment ~~decreased $5.0~~increased $1.3 million, ~~as a result~~which was primarily due to the changes in fair value of ~~losses on derivative activity.~~our commodity swaps between the periods. For the three months ended ~~September 30, 2017, there~~March 31, 2019, realized gains of $3.8 million were partially offset by unrealized losses of ~~$3.3 million and realized losses of $2.2~~$2.0 million. For the three months ended ~~September 30, 2016, there~~March 31, 2018, realized gains of $4.0 million were partially offset by unrealized losses of ~~$1.6 million, partially offset by realized gains of $1.1~~$3.5 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”).~~MVCs, including MVCs from Devon. Under these agreements, our customers agree to ship and/or process a minimum volume of ~~production~~commodity 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 commodity 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~~MVC contracts 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 compensation expense associated with awards granted in 2017.

~~Depreciation and Amortization~~. Depreciation 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 attributable to the expansion of our central Oklahoma assets; $4.3 million was attributable to the plant expansion 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 on Disposition of Assets.~~ Loss 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 to Nine Months Ended September 30, 2016~~

~~Gross Operating Margin.~~ Gross operating margin was $995.5 million for the nine months ended September 30, 2017 compared to $920.7 million for the nine months ended September 30, 2016, an increase of $74.8 million, or 8.1%, due 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 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 the NTPL assets in December 2016.

~~Louisiana Segment.~~ Gross operating margin in the Louisiana segment increased $18.7 million, which was primarily due to a $10.0 million increase in our Louisiana gathering 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-up of our Ascension JV assets during 2017.

~~Oklahoma Segment.~~ Gross operating margin in 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		Permian		North Texas		Oklahoma		Total
Nine Months Ended
September 30, 2017
Three Months Ended
March 31, 2019
Midstream services									$	3.8	$	—	$	—	$	3.8
Total									$	3.8	$	—	$	—	$	3.8

March 31, 2018
Midstream services	$	0.8	$	11.1	$	—	$	11.9	$	—	$	—	$	5.0	$	5.0
Midstream services—related parties	42.1		12.0		5.9		60.0		3.4		18.1		1.2		22.7
Total	$	42.9	$	23.1	$	5.9	$	71.9	$	3.4	$	18.1	$	6.2	$	27.7

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

On January 1, 2019, certain MVCs related to gathering and processing agreements with Devon for operations in the North Texas and Oklahoma segments expired. These MVCs generated $19.3 million in shortfall revenue for the three months ended March 31, 2018. Additionally, an MVC related to a transportation services agreement with Devon for operations in the Permian segment will expire on July 31, 2019. This MVC generated $3.8 million and $3.4 million in shortfall revenue for the three months ended March 31, 2019 and 2018, respectively.

Operating ~~Expenses.~~Expenses. Operating expenses were ~~$308.8~~$114.5 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 compared to ~~$296.3~~$109.2 million for the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2018, an increase of ~~$12.5~~$5.3 million, or ~~4.2%~~4.9%. The primary contributors to the total increase by segment were as follows ~~(dollars in~~(in millions):


	Nine Months Ended September 30,				Change					Three Months Ended March 31,				Change
	2017		2016		$			%		2019		2018		$			%
Texas Segment	$	127.9	$	125.2	$	2.7		2.2	%
Permian Segment										$	27.8	$	23.8	$	4.0		16.8	%
North Texas Segment										25.7		28.4		(2.7		)	(9.5	)%
Oklahoma Segment										25.4		20.7		4.7			22.7	%
Louisiana Segment	74.8		72.2		2.6			3.6	%	35.6		36.3		(0.7		)	(1.9	)%
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	%	$	114.5	$	109.2	$	5.3		4.9	%

~~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~~Permian Segment. Operating expenses in the ~~Louisiana~~Permian segment increased ~~$2.6~~$4.0 million primarily due to ~~increased regulatory,~~expanded operations with increases in utilities, materials and supplies expenses, and construction fees and services.

North Texas Segment. Operating expenses in the North Texas segment decreased $2.7 million primarily due to decreased rents, compressor overhauls, labor and benefits costs, and materials and supplies ~~expenses as a result of the start-up of the Ascension JV.~~expenses.

Oklahoma Segment.Operating expenses in the Oklahoma segment increased ~~$8.7~~$4.7 million primarily due to ~~increased labor~~expanded operations with increases in compressor rentals and ~~benefits charges attributable to higher headcount~~compression operations and ~~increased materials and supplies expense as a result of expanded operations.~~maintenance.

General and Administrative Expenses. General and administrative expenses were ~~$98.5~~$51.4 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 compared to ~~$94.7~~$27.5 million for the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2018, an increase of ~~$3.8~~$23.9 million, or ~~4.0%~~86.9%. The primary contributors to the increase were as follows:

~~Unit-based compensation expense~~Transaction costs increased ~~$10.8~~$13.5 million, which was primarily due to ~~bonuses paid in~~costs that we incurred related to the ~~form~~Merger that closed during the first quarter of ~~units that immediately vested in March 2017, as well as the accrual of annual bonuses for 2017.~~2019.

~~We incurred $3.8~~Unit-based compensation expense increased $7.6 million, which was primarily due to higher bonus expense and lower forfeiture 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.units in 2019.

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

Depreciation and ~~Amortization.~~Amortization. Depreciation and amortization expenses were ~~$407.1~~$152.1 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 compared to ~~$373.0~~$138.1 million for the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2018, an increase of ~~$34.1~~$14.0 million, or ~~9.1%~~10.1%. ~~Of this increase, $18.0~~Depreciation expense on the Louisiana segment increased $5.8 million ~~was~~primarily due to retirements and reductions in our estimated useful lives of certain assets. Depreciation expense on the Oklahoma segment increased $4.1 million primarily attributable to the plant expansion of our Permian Basin processing assets; $10.9 million was attributable to the expansion of 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 othernew assets placed ~~in service. These increases were partially~~in-service. Depreciation expense on the Permian segment increased $3.3 million due to new assets placed in-service, offset by a ~~$3.5~~$2.2 million decrease due to an impairment of the carrying value of certain non-core crude pipeline assets during 2018. Depreciation expense on the North Texas segment increased $3.0 million primarily due to accelerated depreciation on certain assets based on changes in ~~depreciation expense~~their estimated useful lives.

Impairments. As a result of the Merger, we recognized a $186.5 million impairment related to our Louisiana segment in the ~~sale~~consolidated statement of ~~NTPL in December 2016.~~

~~(Gain) Loss on Disposition of Assets.~~ ~~Loss on disposition of assets was $0.8 million~~operations for the ~~nine~~three 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.~~March 31, 2019. See “Item 1. Financial Statements—Note ~~15”~~3—Goodwill and Intangible Assets” for additional information.

~~Gain on Extinguishment of Debt.~~ Interest Expense~~We recognized a gain on extinguishment of debt of $9.0~~. Interest expense was $49.6 million for the ~~nine~~three months ended ~~September 30, 2017 due~~March 31, 2019 compared to ~~the redemption of the 2022 Notes. See “Item 1. Financial Statements—Note 6” for additional information.~~

~~Impairments.~~ ~~Impairment expense was $8.8~~$44.5 million for the ~~nine~~three 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,~~March 31, 2018, an increase of ~~$3.3~~$5.1 million, or ~~2.4%~~11.5%. ~~Net interest~~Interest expense consisted of the following (in millions):


	Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2019			2018
ENLK senior notes	$	115.0		$	95.1
ENLK Senior Notes							$	40.0		$	40.0
ENLK Credit Facility	8.4			9.6			0.3			3.4
ENLC Credit Facility	1.5			0.7			0.2			0.7
Term Loan							8.6			—
Consolidated Credit Facility							2.4			—
Capitalized interest	(5.1		)	(5.5		)	(2.0		)	(1.3		)
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
Amortization of debt issue costs and net discounts							1.8			1.6
Secured term loan receivable adjustment							(1.7		)	—
Other	0.5			(0.7		)	—			0.1
Total	$	142.2		$	138.9		$	49.6		$	44.5

Income ~~(Loss)~~ from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was ~~$5.0~~$5.3 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 compared to ~~a loss~~income of ~~$0.5~~$3.0 million for the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2018, an increase of ~~$5.5~~$2.3 million. The increase was ~~primarily~~partially due to additional income of ~~$7.4~~$1.1 million from our GCF investment ~~for the nine months ended September 30, 2017~~ as a result of ~~higher~~increased volumes and fractionation ~~revenues and lower operating expenses.Partially offsetting this increase, income from~~fee margin. Additionally, our ~~HEP~~ investment ~~decreased $1.8~~in the Cedar Cove JV contributed $1.2 million ~~due to a $1.6 million loss for~~of the ~~nine months ended September 30, 2016 and a $3.4 million loss on sale for the nine months ended September 30, 2017.~~increase.

Income Tax Benefit (Provision). Income tax expense was ~~$9.3~~$1.8 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 compared to ~~income tax expense of $6.0~~$7.0 million for the ~~nine~~three months ended ~~September 30, 2016, an increase~~March 31, 2018, a decrease of ~~$3.3~~$5.2 million. The ~~increase~~decrease in income tax expense was primarily attributable to ~~an increase in~~lower 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”7—Income Taxes” for additional information.

Net Income (Loss) Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was ~~$50.3~~$41.5 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 compared to a net ~~loss~~income of ~~$402.9~~$44.7 million for the ~~nine~~three months ended ~~September 30, 2016, an increase~~March 31, 2018, a decrease of ~~$453.2~~$3.2 million. This ~~increase~~decrease was primarily due to ~~higher impairment expense at~~the conversion of ENLK ~~for~~common units as a result of the ~~nine months ended September 30, 2016.~~Merger. Subsequent to the Merger, ENLC’s non-controlling interest is comprised of ENLK’s Series B Preferred Units, ENLK’s Series C Preferred Units, NGP’s 49.9% share of the Delaware Basin JV, Marathon Petroleum Corporation’s 50% share of the Ascension JV, and other minor non-controlling interests.

Critical Accounting Policies

Information regarding our ~~Critical Accounting Policies~~critical accounting policies is included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, ~~2016,~~2018, except for our critical accounting policy on leases, which changed as ~~described below.~~

~~Impairment of Goodwill. Goodwill is the cost of an acquisition less the fair value~~a result of the ~~net identifiable assets~~adoption of ~~the acquired business. We evaluate goodwill~~ASC 842 on January 1, 2019. See “Item 1. Financial Statements—Note 5—Leases” 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.information on our leases accounting policy.

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.Goodwill Impairment

~~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~~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 ~~that described~~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 ~~Item 7~~the period in which the carrying value exceeds fair value. The estimated fair value of our ~~Annual Report~~reporting units may be impacted in the future by a prolonged decline in our unit price or a prolonged period of lower commodity prices which may adversely affect our estimate of future cash flows, both of which could result in future goodwill impairment charges for our reporting units.

In March 2014, at the time of our transactions with Devon that led us to become publicly held, we recorded goodwill in our corporate reporting unit at ENLC that was associated with the General Partner’s incentive distribution rights in ENLK. Prior to the completion of the Merger in January 2019, ENLC’s aggregate fair value of its reporting units was in excess of the consolidated book value of its assets, including all goodwill, which would not have resulted in a goodwill impairment on ~~Form 10-K~~a consolidated basis. Upon the completion of the Merger, in accordance with ASC 350, Intangibles-Goodwill and other (“ASC 350”), the portion of goodwill on our corporate reporting unit that was previously associated with the General Partner’s incentive distribution rights in ENLK was required to be reallocated to the four remaining reporting units based on the relative fair value of each of the reporting units, with $184.6 million allocated to our Permian segment, $125.7 million allocated to our North Texas segment, $623.1 million allocated to our Oklahoma segment, and $186.5 million allocated to our Louisiana segment. As a result of the allocated goodwill, we recognized a $186.5 million impairment related to our Louisiana segment in the consolidated statement of operations for the ~~year~~three months ended ~~December~~March 31, ~~2016.~~2019. As of March 31, 2019, the fair values of our Permian and North Texas segment assets exceed their respective carrying values by 3% and 5%, respectively.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was ~~$528.4~~$264.0 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 compared to ~~$512.5~~$193.7 million for the ~~nine~~three months ended ~~September 30, 2016.~~March 31, 2018. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):


	Nine Months Ended September 30,					Three Months Ended March 31,
	2017			2016		2019		2018
Operating cash flows before working capital	$	531.7		$	469.1	$	216.8	$	212.2
Changes in working capital	(3.3		)	43.4		47.2		(18.5		)

Operating cash flows before changes in working capital increased ~~$62.6~~$4.6 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 compared to the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2018 primarily due to a ~~$69.3~~$35.8 million increase in gross operating margin, excluding gains and losses on derivative ~~activity, and a $26.0 million gain on litigation settlement,~~activity. The increase in operating cash flows was partially offset by a ~~$21.2~~$6.6 million increase in interest expense, excluding amortization of debt issue costs and net discounts, and ~~a $15.4 million decrease in~~higher cash ~~received on derivative settlements.~~paid for operating expenses and general and administrative expenses for the three months ended March 31, 2019. The changes in working capital for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 compared to the ~~nine~~three months ended ~~September 30, 2016~~March 31, 2018 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~~$241.0 million for the ~~nine~~three months ended ~~September 30, 2017 and $1,203.6~~March 31, 2019, compared to $179.3 million for the ~~nine~~three months ended ~~September 30, 2016.~~March 31, 2018. 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



	Three Months Ended March 31,
	2019			2018
Growth capital expenditures	$	(233.0	)	$	(175.3	)
Maintenance capital expenditures	(8.5		)	(6.2		)

Growth capital expenditures increased ~~$236.7~~$57.7 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 compared to the ~~nine~~three months ended ~~September 30, 2016.~~March 31, 2018. The increase was primarily due to the capital expenditures ~~related to~~on the Lobo III plant expansion, the Thunderbird Plant, and 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.~~our Cajun-Sibon NGL pipeline.

~~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~~used in financing activities was ~~$77.1~~$122.7 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2019 and ~~$733.2~~$28.4 million for the ~~nine~~three months ended ~~September 30, 2016.~~March 31, 2018. 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 ) —



	Three Months Ended March 31,
	2019			2018
Net borrowings on the ENLK Credit Facility	$	—		$	370.0
Net repayments (borrowings) on the ENLC Credit Facility	(111.4		)	1.9
Net borrowings on the Consolidated Credit Facility	160.0			—
Contributions by non-controlling interests	15.7			22.7
Payment of installment payable for EOGP acquisition	—			(250.0		)
Distributions to members	(51.0		)	(47.5		)
Distributions to ENLK common units and Series B Preferred Units	(121.3		)	(111.2		)
Distributions to joint venture partners	(6.3		)	(10.0		)

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~~three 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,~~March 31, 2019, contributions by non-controlling interests included ~~$43.9~~$15.7 million from NGP to the Delaware Basin ~~JV and $2.3 million from Marathon Petroleum to the Ascension~~ JV. For the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2018, contributions by non-controlling interests included ~~$137.7~~$22.7 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~~included distributions paid to public unitholders of ~~cash~~ENLK common units, Series B Preferred Units, and Series C Preferred Units, as well as distributions to NGP for its ownership in ~~financing activities. Total cash~~the Delaware Basin JV and distributions ~~made~~to Marathon Petroleum Corporation for its ownership in 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
Ascension JV. Subsequent to the closing of the Merger, ENLK no longer has publicly held common units.

Prior to the closing of the Merger, 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 quarterly in cash ~~(the “Cash Distribution Component”)~~ at an amount ~~per quarter~~ equal to $0.28125 per Series B Preferred Unit (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of ~~(a)~~(A) 0.0025 Series B Preferred Units per Series B Preferred Unit and ~~(b)~~(B) an amount equal to (i) the excess, if any, of the ~~distributions~~distribution that would have been payable had the Series B Preferred Units converted into ENLK common units ~~for that quarter~~ over the Cash Distribution Component, divided by (ii) the issue price of ~~$15.00.~~$15.00 (“the Issue Price”).

Following the closing of the Merger, and beginning with the quarter ended March 31, 2019, the holder of the Series B Preferred Units will be entitled to quarterly cash distributions and distributions in-kind of additional Series B Preferred Units as described below. The quarterly in-kind distribution (the “Series B PIK Distribution”) will equal the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) the number of Series B Preferred Units equal to the quotient of (x) the excess (if any) of (1) the distribution that would have been payable by ENLC had the Series B Preferred Units been exchanged for ENLC common units but applying a one-to-one exchange ratio (subject to certain adjustments) instead of the exchange ratio of 1.15 ENLC common units for each Series B Preferred Unit, subject to certain adjustments (the “Series B Exchange Ratio”), over (2) the Cash Distribution Component, divided by (y) the Issue Price. The quarterly cash distribution will consist of the Cash Distribution Component plus an amount in cash that will be determined based on a comparison of the value (applying the Issue Price) of (i) the Series B PIK Distribution and (ii) the Series B Preferred Units that would have been distributed in the Series B PIK Distribution if such calculation applied the Series B Exchange Ratio instead of the one-to-one ratio (subject to certain adjustments).

For the three months ended March 31, 2019 and March 31, 2018, distributions to non-controlling interests included $16.5 million and $16.0 million, respectively, from the issuance of Series B Preferred Units.

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 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 our remaining ~~2017~~2019 growth 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 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.

approximately $346 million to $506 million, net of $77 million to $87 million which we expect to come from our joint venture partners. We expect our remaining 2019 maintenance capital expenditures to be approximately $32 million to $52 million. Our primary capital projects for ~~the remainder of 2017 and 2018~~2019 include the completion of construction of ~~our Chisholm~~the Thunderbird Plant, Avenger, the Lobo III processing plant in the Delaware Basin, the expansion of Cajun Sibon III, commencement of construction a new gas processing plant in the Delaware Basin, and ~~the~~continued development of ~~additional gathering and compression assets in Oklahoma and the Permian Basin.~~our existing systems. See “Recent Developments” for further details.

We expect to fund growth capital expenditures from the proceeds of borrowings under the ~~ENLK~~Consolidated Credit Facility, ~~discussed below~~operating cash flows, 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. We expect to fund our maintenance capital expenditures from operating cash flows. In ~~2017 and 2018,~~2019, 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 off-balance sheet arrangements existed as of ~~September 30, 2017.~~March 31, 2019.

Total Contractual Cash Obligations. A summary of contractual cash obligations as of ~~September 30, 2017~~March 31, 2019 is as follows (in millions):


	Payments Due by Period														Payments Due by Period
	Total		Remainder 2017		2018		2019		2020		2021		Thereafter		Total		Remainder 2019		2020		2021		2022		2023		Thereafter
Long-term debt obligations(1)	$	3,500.0	$	—	$	—	$	400.0	$	—	$	—	$	3,100.0	$	3,500.0	$	400.0	$	—	$	—	$	—	$	—	$	3,100.0
ENLK Credit Facility	—		—		—		—		—		—		—
ENLC Credit Facility	74.0		—		—		74.0		—		—		—
Term Loan															850.0		—		—		850.0		—		—		—
Consolidated Credit Facility															160.0		—		—		—		—		—		160.0
Interest payable on fixed long-term debt obligations	2,642.8		69.4		159.9		154.5		149.2		149.2		1,960.6		2,401.4		142.4		149.2		149.2		149.2		149.2		1,662.2
Capital lease obligations	4.9		0.4		1.5		1.5		1.5		—		—		0.8		0.8		—		—		—		—		—
Operating lease obligations	113.3		3.8		14.3		10.9		8.6		8.6		67.1		139.2		16.5		16.0		12.9		9.1		8.9		75.8
Purchase obligations	3.7		3.7		—		—		—		—		—		27.6		27.6		—		—		—		—		—
Delivery contract obligation	31.4		4.5		17.9		9.0		—		—		—		4.5		4.5		—		—		—		—		—
Pipeline capacity and deficiency agreements ~~(1)~~(2)	95.7		4.8		19.0		13.8		8.9		8.8		40.4		215.1		31.1		35.5		35.4		30.8		28.1		54.2
Inactive easement commitment ~~(2)~~(3)	10.0		—		—		—		—		—		10.0		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	$	7,308.6	$	622.9	$	200.7	$	1,047.5	$	199.1	$	186.2	$	5,052.2

____________________________


(1)	ENLK’s 2.70%senior unsecured notes matured on April 1, 2019 and were refinanced through borrowings on the Consolidated Credit Facility.


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


~~(2)~~(3)	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.~~

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.

The interest payable ~~under~~related to the ~~ENLK~~Consolidated Credit Facility and ~~ENLC credit facilities~~the Term Loan are not reflected in the above table because such amounts depend on the outstanding balances and interest rates of the Consolidated Credit Facility and the Term Loan, 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~~2019 are expected to be funded from cash flows generated from our operations, with the exception of ENLK’s $250.0 million installment payable obligation due January 7, 2018 related to the acquisition of the EnLink Oklahoma T.O. assets. We expect to fund payment of this installment obligation from the proceeds of borrowings under ENLK’s credit facility, proceeds from the issuance ofpotential non-core asset sales, and other debt and equity ~~or both of these alternatives.~~sources.

Indebtedness

In December 2018, we entered into the Consolidated Credit Facility, which permits us to borrow up to $1.75 billion on a revolving credit basis and includes a $500.00 million letter of credit subfacility. At the closing of the Merger, the ENLC Credit Facility was canceled, the Consolidated Credit Facility became available for borrowings and letters of credit, and ENLK became a guarantor under the Consolidated Credit Facility.

In December 2018, ENLK entered into the Term Loan and used the net proceeds to repay borrowings under the ENLK Credit Facility. At the closing of the Merger, the Term Loan was assumed by us, and ENLK became a guarantor of the Term Loan.

In addition, as of March 31, 2019, ENLK had $3.5 billion in aggregate principal amount of outstanding unsecured senior notes maturing from 2024 to 2047. In April 2019, we issued $500.0 million in aggregate principal amount of unsecured senior notes that mature in 2029. See “Item 1. Financial Statements—Note 6”16—Subsequent Event” for more information on this transaction.

See “Item 1. Financial Statements—Note 6—Long-Term Debt” for more information on our outstanding debt instruments.

Recent Accounting Pronouncements

See “Item 1. Financial Statements—Note 2”2—Significant Accounting Policies” for more information on recently issued and adopted accounting pronouncements.

Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q ~~includes~~contains forward-looking statements ~~within the meaning~~that are based on information currently available to management as well as management’s assumptions and beliefs. All statements, other than statements of ~~federal securities laws. Statements~~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” or other~~“expect,” “continue,” and similar ~~words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information.~~expressions. Such statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to the specific uncertainties discussed elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth in Part II, “Item 1A. Risk Factors” of this report and in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2018 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 position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. 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,~~proposed and revised new rules in November 2013 ~~the CFTC proposed new rules~~and December 2016, respectively, 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~~rules as reproposed and revised, but ~~these~~the new ~~position limit~~ rules ~~are~~have not yet been issued in final form, and the impact of ~~those~~any final provisions on us is uncertain at this time.

The legislation and new regulations may also require counterparties to our derivative instruments to spin off some of their derivatives 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 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 subject to ~~significant~~ risks due to fluctuations in commodity prices. Approximately 91% of our gross operating margin for the three months ended March 31, 2019 was generated from arrangements with fee-based structures with minimal 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 under four main types of contractual arrangements (or a combination of these types of contractual arrangements) as summarized below. ~~Approximately 86% of our processing margins were from fixed-fee based contracts for the nine months ended September 30, 2017.~~


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 volume processed or (2) arrangements where we purchase and resell commodities in connection with providing the related processing service and earn a net margin through a fee-like deduction subtracted from the purchase price of the commodities.

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 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 three months ended March 31, 2019, less than 1% of our contracts, based on gross operating margin, were under processing margin contracts.

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.

2.3.

~~Percent of liquids~~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 ~~percent of liquids~~POL contracts, but they do decline during periods of low liquids prices.

3.4.

~~Percent of proceeds contracts:~~POP contracts: Under these contracts, we receive a fee asin 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 ~~percent of proceeds~~POP 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.~~

For the three months ended March 31, 2019, approximately 7% of our contracts, based on gross operating margin, were under 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, crude oil, and ~~NGL~~condensate 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.

The following table sets forth certain information related to derivative instruments outstanding at ~~September 30, 2017~~March 31, 2019 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.~~Oil Price Information Service. 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 )

Period

Underlying

Notional Volume

We Pay

We Receive (1)

Fair Value
Asset/(Liability)
(In millions)

April 2019 - June 2019

Ethane

63 (MBbls)

$0.2359/gal

Index

(0.1

)

April 2019 - September 2019

Propane

184 (MBbls)

Index

$0.6490/gal

0.7

April 2019 - September 2019

Normal Butane

91 (MBbls)

Index

$0.7602/gal

0.2

April 2019 - September 2019

Natural Gasoline

53 (MBbls)

Index

$1.2439/gal

0.3

April 2019 - October 2019

Natural Gas

20,876 (MMBtu/d)

Index

$2.2818/MMBtu

(1.1

)

April 2019 - December 2022

Crude and condensate

14,166 (MBbls)

Index

$59.57/bbl

6.5

____________________________


(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,~~March 31, 2019, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments were a net fair value ~~liability~~asset of ~~$2.5~~$6.5 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~~$3.8 million in the net fair value of these contracts as of ~~September 30, 2017.~~ March 31, 2019.

Interest Rate Risk

We are exposed to interest rate risk ~~from~~on the ~~ENLC~~Consolidated Credit Facility and the ~~ENLK Credit Facility.~~Term Loan. At ~~September 30, 2017, the ENLC Credit Facility~~March 31, 2019, we had ~~$74.0~~$160.0 million and $850.0 million in outstanding borrowings under the Consolidated Credit Facility and the ~~ENLK Credit Facility had no outstanding borrowings.~~Term Loan, respectively. 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~~$1.6 million and $8.5 million, respectively, for the year.

In April 2019, we entered into $850.0 million of interest rate swaps to reduce the variability of cash outflows associated with interest payments related to our long-term debt with variable interest rates. These swaps have been designated as cash flow hedges.

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 as these are fixed-rate obligations. The estimated fair value of ENLK’s senior unsecured notes was approximately ~~$3,564.7~~$3,311.6 million as of ~~September 30, 2017,~~March 31, 2019, based on market prices of similar debt at ~~September 30, 2017.~~March 31, 2019. 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~~$227.7 million decrease in fair value of ENLK’s senior unsecured notes at ~~September 30, 2017.~~March 31, 2019. See “Item 1. Financial Statements—Note 6—Long-Term Debt” for more information on our outstanding indebtedness.

Item 4. Controls and Procedures


(a)	Evaluation of Disclosure Controls and Procedures

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, 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)~~(March 31, 2019), 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 Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.


(b)	Changes in Internal Control Over Financial Reporting

~~There~~Effective January 1, 2019, we adopted ASC 842. The adoption of this accounting standard had no material impact on our operating income, results of operations, financial condition, or cash flows. While the adoption of ASC 842 did not materially affect our internal control over financial reporting, we did implement certain changes to our related lease control activities, including changes to our policies related to leases, training, ongoing lease contract review requirements, and gathering of information to comply with disclosure requirements. Furthermore, there has been no change in our internal control over financial reporting that occurred in the three months ended ~~September 30, 2017~~March 31, 2019 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

~~For a discussion of certain litigation and similar proceedings, see “Item 1. Financial Statements—Note 15.”~~

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 the new risk factor set forth below.~~2018.

~~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 March 31, 2019, 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 our assets~~satisfy the employees’ tax liability in connection with the vesting of restricted incentive units.



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	Maximum Number of Units that May Yet Be Purchased under the Plans or Programs
January 1, 2019 to January 31, 2019	259,713	$	9.52	—	—
February 1, 2019 to February 28, 2019	64,135	10.87		—	—
March 1, 2019 to March 31, 2019	147,755	11.32		—	—
Total	471,603	$	10.27	—	—

____________________________

(1) The common units were not re-acquired pursuant to any repurchase plan or ~~complete planned growth projects.~~program.

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
2.1	—	Agreement and Plan of Merger, dated as of October 21, 2018, by and among EnLink Midstream, LLC, EnLink Midstream Manager, LLC, NOLA Merger Sub, LLC, EnLink Midstream Partners, LP, and EnLink Midstream GP, LLC (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated October 21, 2018, filed with the Commission on October 22, 2018, file No. 001-36336).
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~~April 9, 2019, by and among EnLink Midstream, ~~GP,~~ LLC, any subsidiary guarantors that may become party thereto, and Wells Fargo Bank, National Association, 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,~~April 4, 2019, filed with the Commission on ~~July 7, 2014,~~April 9, 2019, file No. ~~001-36340)~~001-36336).
~~3.15~~4.2	—	~~Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC,~~First Supplemental Indenture, dated as of ~~January 7, 2016~~April 9, 2019, by and among EnLink Midstream, LLC, EnLink Midstream Partners, LP, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit ~~3.2~~4.2 to our Current Report on Form 8-K dated April 4, 2019, filed with the Commission on April 9, 2019, file No. 001-36336).
10.1	† —	EnLink Midstream GP, LLC Long-Term Incentive Plan, as amended and restated January 25, 2019 (the “GP Plan”) (incorporated by reference to Exhibit 4.2 to our Registration Statement on Form S-8 dated January 28, 2019, filed with the Commission on January 28, 2019, file No. 333-229393).
10.2	† —	EnLink Midstream, LLC 2014 Long-Term Incentive Plan, as amended and restated January 25, 2019 (the “2014 Plan”) (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-8 dated January 28, 2019, filed with the Commission on January 28, 2019, file No. 333-229393).
10.3	† —	Form of Amended Performance Conditions for Certain Performance Unit Agreements made under the GP Plan and 2014 Plan, effective as of January 25, 2019 (incorporated by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the Commission on February 20, 2019, file No. 001-36336).
10.4	—	Revolving Credit Agreement, dated as of December 11, 2018, by and among EnLink Midstream, LLC, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, 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 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated December 11, 2018, filed with the Commission on December 12, 2018, file No. 001-36336).



10.5	—	Term Loan Agreement, dated as of December 11, 2018, by and among EnLink Midstream Partners, ~~LP’s~~LP, 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 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated December 11, 2018, filed with the Commission on December 12, 2018, file No. 001-36336).
10.6	—	Guaranty Agreement, dated as of January 25, 2019, by EnLink Midstream Partners, LP in favor of Bank of America, N.A., as Administrative Agent, for the ratable benefit of the lenders from time to time party to the Revolving Credit Agreement, dated as of December 11, 2018 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated January ~~12, 2016,~~25, 2019, filed with the Commission on January ~~12, 2016,~~29, 2019, file No. ~~001-36340)~~001-36336).
10.7	—	New Borrower Joinder and Assumption Agreement, dated January 25, 2019, by EnLink Midstream, LLC and EnLink Midstream Partners, LP in favor of Bank of America, N.A., as Administrative Agent, and the lenders from time to time party to the Term Loan Agreement, dated as of December 11, 2018 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K dated January 25, 2019, filed with the Commission on January 29, 2019, file No. 001-36336).
10.8	—	Guaranty Agreement, dated as of January 25, 2019, by EnLink Midstream Partners, LP in favor of Bank of America, as Administrative Agent, for the ratable benefit of the lenders from time to time party to the Term Loan Agreement, dated as of December 11, 2018 (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K dated January 25, 2019, filed with the Commission on January 29, 2019, file No. 001-36336).
10.9	—	Amended and Restated Board Representation Agreement, dated as of January 25, 2019, by and among EnLink Midstream, LLC, EnLink Midstream Manager, LLC, GIP III Stetson I, L.P., and TPG VII Management, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated January 25, 2019, filed with the Commission on January 25, 2019, file No. 001-36336).
10.10	—	Contribution Agreement, dated as of January 31, 2019, by and between EnLink Midstream, LLC and EnLink Midstream Partners, LP (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated January 31, 2019, filed with the Commission on February 4, 2019, file No. 001-36336).
10.11	† —	Form of Performance Unit Agreement made under the 2014 Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated March 8, 2019, filed with the Commission on March 14, 2019, file No. 001-36336).
10.12	† —	Form of Restricted Incentive Unit Agreement made under the 2014 Plan (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated March 8, 2019, filed with the Commission on March 14, 2019, file No. 001-36336).
31.1 *	—	Certification of the Principal Executive Officer.
31.2 *	—	Certification 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,~~March 31, 2019, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016,~~2018, (ii) Consolidated Statements of Operations for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2019 and ~~2016,~~2018, (iii) Consolidated Statements of Changes in Members’ Equity for the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2019 and 2018, (iv) Consolidated Statements of Cash Flows for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2019 and ~~2016,~~2018, and (v) the ~~notes~~Notes to Consolidated Financial Statements.

____________________________


*	Filed herewith.

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

SIGNATURES

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



	EnLink Midstream, LLC

	By:	EnLink Midstream Manager, LLC,
		its managing member

	By:	/s/ ~~MICHAEL J. GARBERDING~~ERIC D. BATCHELDER
		~~Michael J. Garberding~~Eric D. Batchelder
		Executive Vice President and Chief Financial Officer

~~November~~May 1, ~~2017~~2019

5859


Item	Description	Page	Description	Page

	PART I—FINANCIAL INFORMATION		PART I—FINANCIAL INFORMATION

1.	Financial Statements	4	Financial Statements	5

2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	35	Management's Discussion and Analysis of Financial Condition and Results of Operations	38

3.	Quantitative and Qualitative Disclosures About Market Risk	53	Quantitative and Qualitative Disclosures About Market Risk	52

4.	Controls and Procedures	55	Controls and Procedures	55

	PART II—OTHER INFORMATION		PART II—OTHER INFORMATION

1.	Legal Proceedings	56	Legal Proceedings	56

1A.	Risk Factors	56	Risk Factors	56

2.			Unregistered Sales of Equity Securities and Use of Proceeds	56

6.	Exhibits	57	Exhibits	57



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



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



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		%



	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	)