10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2018

OR

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

For the transition period from               to

Commission file number: 001-36336

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., Suite 1300
Dallas, Texas	75201
(Address of principal executive offices)	(Zip Code)

(214) 953-9500

(Registrant’s telephone number, including area code)

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 every Interactive Data File required to be submitted 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” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	ý	Accelerated filer	¨
Non-accelerated filer	¨	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 November 1, 2018, the Registrant had 181,294,967 common units outstanding.

TABLE OF CONTENTS

Item	Description	Page
	PART I—FINANCIAL INFORMATION
1.	Financial Statements	5
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	39
3.	Quantitative and Qualitative Disclosures About Market Risk	57
4.	Controls and Procedures	60
	PART II—OTHER INFORMATION
1.	Legal Proceedings	61
1A.	Risk Factors	61
2.	Unregistered Sales of Equity Securities and Use of Proceeds	62
6.	Exhibits	63

2

DEFINITIONS

The following terms as defined are used in this document:

Defined Term	Definition
/d	Per day.
2017 EDA	Equity Distribution Agreement entered into by ENLK in August 2017 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 to sell up to $600.0 million in aggregate gross sales of our common units from time to time through an “at the market” equity offering program.
AMZ	Alerian MLP Index for Master Limited Partnerships.
ASC	The FASB Accounting Standards Codification.
ASC 606	ASC 606, Revenue from Contracts with Customers.
ASU	The FASB Accounting Standards Update.
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.
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.
Devon	Devon Energy Corporation.
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.
ENLC	EnLink Midstream, LLC.
ENLC Credit Facility	A $250.0 million revolving credit facility entered into by ENLC that matures on March 7, 2019, which includes a $125.0 million letter of credit subfacility.
ENLK	EnLink Midstream Partners, LP or 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 matures on March 6, 2020, which includes a $500.0 million letter of credit subfacility.
EOGP	EnLink Oklahoma Gas Processing, LP or EnLink Oklahoma Gas Processing, LP together with, when applicable, its consolidated subsidiaries. EOGP is a partnership in which ENLK and ENLC hold an 83.9% and 16.1% interest, respectively.
FASB	Financial Accounting Standards Board.
FERC	Federal Energy Regulatory Commission.
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 and all of the incentive distribution rights in ENLK.
GIP	Global Infrastructure Management, LLC, an independent infrastructure fund manager, itself, or its affiliates, including GIP III Stetson I, L.P. and GIP III Stetson II, L.P.
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.
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.
HEP	Howard Energy Partners. ENLK sold its 31% ownership interest in HEP in March 2017.

3

ISDAs	International Swaps and Derivatives Association Agreements.
Mcf	Thousand cubic feet.
MMbtu	Million British thermal units.
MMcf	Million cubic feet.
MVC	Minimum volume commitment.
NGL	Natural gas liquid.
NGP	NGP Natural Resources XI, LP
Operating Partnership	EnLink Midstream Operating, LP, a Delaware limited partnership and wholly owned subsidiary of ENLK.
ORV	ENLK’s Ohio River Valley crude oil, condensate stabilization, natural gas compression, and brine disposal assets in the Utica and Marcellus shales.
OTC	Over-the-counter.
Permian Basin	A large sedimentary basin that includes the Midland and Delaware Basins in West Texas.
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.
VEX	ENLK’s Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in South Texas.

4

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENLINK MIDSTREAM, LLC

Consolidated Balance Sheets

(In millions, except unit data)

	September 30, 2018			December 31, 2017
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	64.8		$	31.2
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively	198.0			50.1
Accrued revenue and other	817.2			576.6
Related party	0.7			102.8
Fair value of derivative assets	12.5			6.8
Natural gas and NGLs inventory, prepaid expenses, and other	155.1			41.2
Total current assets	1,248.3			808.7
Property and equipment, net of accumulated depreciation of $2,859.3 and $2,533.0, respectively	6,875.7			6,587.0
Intangible assets, net of accumulated amortization of $391.3 and $298.7, respectively	1,404.5			1,497.1
Goodwill	1,542.2			1,542.2
Investment in unconsolidated affiliates	84.5			89.4
Other assets, net	43.1			13.4
Total assets	$	11,198.3		$	10,537.8
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable and drafts payable	$	130.6		$	66.9
Accounts payable to related party	5.0			16.3
Accrued gas, NGLs, condensate, and crude oil purchases	656.9			476.1
Fair value of derivative liabilities	21.9			8.4
Installment payable, net of discount of $0.5 at December 31, 2017	—			249.5
Current maturities of long-term debt	500.9			—
Other current liabilities	261.4			222.9
Total current liabilities	1,576.7			1,040.1
Long-term debt	3,835.9			3,542.1
Asset retirement obligations	14.6			14.2
Other long-term liabilities	20.7			33.9
Deferred tax liability	361.8			346.2
Fair value of derivative liabilities	7.0			—
Redeemable non-controlling interest	6.2			4.6
Members’ equity:
Members’ equity (181,294,450 and 180,600,728 units issued and outstanding, respectively)	1,838.4			1,924.2
Accumulated other comprehensive loss	(2.0		)	(2.0		)
Non-controlling interest	3,539.0			3,634.5
Total members’ equity	5,375.4			5,556.7
Total liabilities and members’ equity	$	11,198.3		$	10,537.8

See accompanying notes to consolidated financial statements.

5

ENLINK MIDSTREAM, LLC

Consolidated Statements of Operations

(In millions, except per unit data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(Unaudited)
Revenues:
Product sales	$	1,832.2		$	1,056.7		$	4,766.5		$	2,973.9
Product sales—related parties	10.2			35.3			41.0			107.3
Midstream services	241.5			136.4			476.1			395.7
Midstream services—related parties	35.8			175.0			377.2			507.6
Loss on derivative activity	(5.4		)	(5.5		)	(20.1		)	(1.1		)
Total revenues	2,114.3			1,397.9			5,640.7			3,983.4
Operating costs and expenses:
Cost of sales (1)	1,696.6			1,053.2			4,403.7			2,987.9
Operating expenses	114.7			102.1			337.3			308.8
General and administrative	41.9			31.3			99.8			98.5
Loss on disposition of assets	—			1.1			1.3			0.8
Depreciation and amortization	146.7			136.3			430.1			407.1
Impairments	24.6			1.8			24.6			8.8
Gain on litigation settlement	—			—			—			(26.0		)
Total operating costs and expenses	2,024.5			1,325.8			5,296.8			3,785.9
Operating income	89.8			72.1			343.9			197.5
Other income (expense):
Interest expense, net of interest income	(45.2		)	(49.6		)	(134.3		)	(142.2		)
Gain on extinguishment of debt	—			—			—			9.0
Income from unconsolidated affiliates	4.3			4.4			11.7			5.0
Other income	0.1			0.3			0.3			0.5
Total other expense	(40.8		)	(44.9		)	(122.3		)	(127.7		)
Income before non-controlling interest and income taxes	49.0			27.2			221.6			69.8
Income tax provision	(4.0		)	(3.1		)	(17.3		)	(9.3		)
Net income	45.0			24.1			204.3			60.5
Net income attributable to non-controlling interest	37.3			17.9			156.2			50.3
Net income attributable to ENLC	$	7.7		$	6.2		$	48.1		$	10.2
Net income attributable to ENLC per unit:
Basic common unit	$	0.04		$	0.03		$	0.27		$	0.06
Diluted common unit	$	0.04		$	0.03		$	0.26		$	0.06

(1) Includes related party cost of sales of $23.0 million and $47.3 millionfor thethree months endedSeptember 30, 2018and2017, respectively, and $103.8 million and $126.9 millionfor thenine months endedSeptember 30, 2018and2017, respectively.

See accompanying notes to consolidated financial statements.

6

ENLINK MIDSTREAM, LLC

Consolidated Statements of Comprehensive Income

(In millions)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(Unaudited)
Net income	$	45.0	$	24.1	$	204.3	$	60.5
Loss on designated cash flow hedge, net of tax benefit of $0.2 million for the nine months ended September 30, 2017	—		—		—		(2.0		)
Comprehensive income	45.0		24.1		204.3		58.5
Comprehensive income attributable to non-controlling interest	37.3		17.9		156.2		48.7
Comprehensive income attributable to EnLink Midstream, LLC	$	7.7	$	6.2	$	48.1	$	9.8

See accompanying notes to consolidated financial statements.

7

ENLINK MIDSTREAM, LLC

Consolidated Statement of Changes in Members’ Equity

Nine Months Ended September 30, 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	—			—	—			46.1			46.1			—
Conversion of restricted units for common units, net of units withheld for taxes	(5.7		)	0.7	—			—			(5.7		)	—
Non-controlling interest’s impact of conversion of restricted units	—			—	—			(5.6		)	(5.6		)	—
Unit-based compensation	15.9			—	—			16.4			32.3			—
Change in equity due to issuance of units by ENLK	1.2			—	—			(1.4		)	(0.2		)	—
Contributions from non-controlling interests	—			—	—			73.4			73.4			—
Distributions	(145.0		)	—	—			(379.3		)	(524.3		)	—
Fair value adjustment related to redeemable non-controlling interest	(0.3		)	—	—			(1.1		)	(1.4		)	1.4
Net income	48.1			—	—			156.0			204.1			0.2
Balance, September 30, 2018	$	1,838.4		181.3	$	(2.0	)	$	3,539.0		$	5,375.4		$	6.2

See accompanying notes to consolidated financial statements.

8

ENLINK MIDSTREAM, LLC

Consolidated Statements of Cash Flows

(In millions)

	Nine Months Ended September 30,
	2018			2017
	(Unaudited)
Cash flows from operating activities:
Net income	$	204.3		$	60.5
Adjustments to reconcile net income to net cash provided by operating activities:
Impairments	24.6			8.8
Depreciation and amortization	430.1			407.1
Non-cash unit-based compensation	31.8			38.9
Loss on derivatives recognized in net income	20.1			1.1
Gain on extinguishment of debt	—			(9.0		)
Cash settlements on derivatives	(4.3		)	(5.9		)
Amortization of debt issue costs, net discount (premium) of notes and installment payable	3.4			21.8
Distribution of earnings from unconsolidated affiliates	14.0			4.1
Income from unconsolidated affiliates	(11.7		)	(5.0		)
Non-cash revenue from contract restructuring	(45.5		)	—
Other operating activities	15.0			9.3
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue, and other	(292.2		)	(56.7		)
Natural gas and NGLs inventory, prepaid expenses, and other	(93.0		)	(48.4		)
Accounts payable, accrued gas and crude oil purchases, and other accrued liabilities	242.4			101.8
Net cash provided by operating activities	539.0			528.4
Cash flows from investing activities:
Additions to property and equipment	(639.4		)	(662.5		)
Proceeds from sale of unconsolidated affiliate investment	—			189.7
Investment in unconsolidated affiliates	(0.1		)	(11.8		)
Distribution from unconsolidated affiliates in excess of earnings	2.7			7.3
Other investing activities	3.8			2.0
Net cash used in investing activities	(633.0		)	(475.3		)
Cash flows from financing activities:
Proceeds from borrowings	2,011.8			2,213.4
Payments on borrowings	(1,220.0		)	(1,955.6		)
Payment of installment payable for EOGP acquisition	(250.0		)	(250.0		)
Debt financing costs	—			(5.5		)
Conversion of restricted units, net of units withheld for taxes	(5.7		)	(5.0		)
Conversion of ENLK's restricted units, net of units withheld for taxes	(5.6		)	(5.2		)
Proceeds from issuance of ENLK common units	46.1			92.3
Distribution to members	(145.0		)	(139.5		)
Distributions to non-controlling interests	(379.3		)	(306.9		)
Proceeds from issuance of ENLK Series C Preferred Units	—			393.7
Contributions by non-controlling interests	73.4			46.2
Other financing activities	1.9			(0.8		)
Net cash provided by financing activities	127.6			77.1
Net increase in cash and cash equivalents	33.6			130.2
Cash and cash equivalents, beginning of period	31.2			11.7
Cash and cash equivalents, end of period	$	64.8		$	141.9
Supplemental disclosures of cash flow information:
Cash paid for interest	$	108.8		$	94.7
Cash paid for income taxes	$	0.6		$	4.1
Non-cash investing activities:
Non-cash accrual of property and equipment	$	13.3		$	(26.2	)
Discounted secured term loan receivable from contract restructuring	$	47.7		$	—

See accompanying notes to consolidated financial statements.

9

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements

September 30, 2018

(Unaudited)

(1) General

In this report, the terms “Company” or “Registrant,” as well as the terms “ENLC,” “our,” “we,” “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 the Operating Partnership and EOGP.

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

(a) Organization of Business

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 of equity interests in ENLK and EOGP. ENLK is a publicly traded limited partnership formed on July 12, 2002 and is engaged in the gathering, transmission, processing, and marketing of natural gas, NGLs, condensate, and crude oil, as well as providing crude oil, condensate, and brine services to producers. EOGP is a partnership held by us and ENLK and is engaged in the gathering and processing of natural gas. As ofSeptember 30, 2018, our direct and indirect interests in ENLK and EOGP consisted of the following:

• 88,528,451common units representing an aggregate21.4%limited partner interest in ENLK;

• 100%ownership interest in the General Partner of ENLK, which owns a0.4%general partner interest and all of the incentive distribution rights in ENLK; and

• 16.1%limited partner interest in EOGP

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.As a result of the transaction:

• GIP, through GIP Stetson I, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLK and the managing member of ENLC, which amount to100%of the outstanding limited liability company interests in the managing member of ENLC and approximately23.1%of the outstanding limited partner interests in ENLK at the closing date. Through this transaction, GIP acquired control of (i) the managing member of ENLC, (ii) ENLC, and (iii) ENLK, as a result of ENLC’s indirect ownership of ENLK’s general partner; and

• GIP, through GIP Stetson II, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLC, which amount to approximately63.8%of the outstanding limited liability company interests in ENLC at the closing date.

On October 21, 2018, ENLC, ENLK, the General Partner, the managing member of ENLC, and NOLA Merger Sub, LLC, a wholly-owned subsidiary of ENLC (“NOLA Merger Sub”), entered into a definitive agreement and plan of merger (the “Merger Agreement”) pursuant to which, subject to the satisfaction or waiver of certain conditions in the Merger Agreement, NOLA Merger Sub will merge with and into ENLK (the “Merger”), with ENLK continuing as the surviving entity and a subsidiary of ENLC. The Merger and the other transactions contemplated by the Merger Agreement and the preferred restructuring agreement entered into concurrently with the Merger Agreement (the “Merger Transactions”) are expected to close in the first quarter of 2019, subject to obtaining ENLK unitholder approval, customary regulatory approvals, and other customary closing conditions. SeeNote 15—Subsequent Eventfor more information regarding this transaction.

(b) Nature of Business

We primarily focus on providing midstream energy services, including:

• gathering, compressing, treating, processing, transporting, storing, and selling natural gas;

10

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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

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

Our natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems 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 that is transported to the processing plants by our own gathering systems or by 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, marketers, and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from 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.

Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate 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.

(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 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. All significant intercompany balances and transactions have been eliminated in consolidation.

(b) Revenue Recognition

We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. 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. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows:

• Product sales—Product sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above.

11

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

• Midstream services—Midstream services represent all other revenue generated as a result of performing our midstream services as outlined above.

Adoption of ASC 606

Effective January 1, 2018, we adopted ASC 606 using the modified retrospective method. ASC 606 replaces previous revenue recognition requirements in GAAP and requires 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 also requires 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.

Evaluation of Our Contractual Performance Obligations

In adopting ASC 606, we evaluated our contracts with customers that are within the scope of ASC 606. In accordance with the new revenue recognition framework introduced by ASC 606, we identified our performance obligations under our contracts with customers. These performance obligations include:

• promises to perform midstream services for our customers over a specified contractual term and/or for a specified volume of commodities; and

• promises to sell a specified volume of commodities to our customers.

The identification of performance obligations under our contracts requires a contract-by-contract evaluation of when control, including the economic benefit, of commodities transfers to and from us (if at all). This evaluation of control changed the way we account for certain transactions effective January 1, 2018, specifically those contracts in which there is both a commodity purchase and a midstream service. 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 do not consider these revenue-generating contracts for purposes of ASC 606. Based on the control determination, all contractually-stated fees that are deducted from our payments to producers or other suppliers for commodities purchased are reflected as a reduction in the cost of such commodity purchases. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating and recognize the fees received for satisfying them as midstream services revenues over time as 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 recognize these fees as midstream services revenues over time as we satisfy our performance obligations.

We also evaluate our contractual arrangements that contain a purchase and sale of commodities under the principal/agent provisions in ASC 606. For contracts where we possess control of the commodity and act as principal in the purchase and sale, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as an agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract.

12

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Based on our review of our performance obligations in our contracts with customers, we changed the consolidated statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. For thethree and nine months ended September 30, 2018, the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately$179 million and $480 million, respectively, or 8% and 8%, respectively, compared to total revenues based on accounting prior to the adoption of ASC 606, with an equivalent net decrease in cost of sales. The change in total revenues as a result of the adoption of ASC 606 is made up of the following revenue line item changes (in millions):

	Increase (Decrease) in Revenue Due to ASC 606 Adoption
	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
Product sales	$	(71	)	$	(149	)
Product sales—related parties	(7		)	(53		)
Midstream services	(98		)	(251		)
Midstream services—related parties	(3		)	(27		)
Total	$	(179	)	$	(480	)

This change in accounting treatment had no impact on our operating income, net income, results of operations, financial condition, or cash flows.

Changes in Accounting Methodology for Certain Contracts

For NGL contracts in which we purchase raw mix NGLs and subsequently transport, fractionate, and market the NGLs, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which the fees we earned for our services were recorded as midstream services revenue on the consolidated statements of operations. As a result of the adoption of ASC 606, we determined that the control, including the economic benefit, of commodities has passed to us once the raw mix NGLs have been purchased from the customer. Therefore, we now consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the raw mix NGLs, rather than being recorded as midstream services revenue. Upon sale of the NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased.

For our crude oil and condensate service contracts in which we purchase the commodity, we utilize a similar approach under ASC 606 as outlined above for NGL contracts. This treatment is consistent with our accounting for crude oil and condensate service contracts prior to the adoption of ASC 606.

For our natural gas gathering and processing contracts in which we perform midstream services and also purchase the natural gas, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which all contractually-stated fees earned for our gathering and processing services were recorded as midstream services revenue on the statements of operations. As a result of the adoption of ASC 606, we must determine if economic control of the commodities has passed from the producer to us before or after we perform our services (if at all). Control is assessed on a contract-by-contract basis by analyzing each contract’s provisions, which can include provisions for: the customer to take its residue gas and/or NGLs in-kind; fixed or actual NGL or keep-whole recovery; commodity purchase prices at weighted average sales price or market index-based pricing; and various other contract-specific considerations. Based on this control assessment, our gathering and processing contracts fall into two primary categories:

• For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas passes to us when the natural gas is brought into our system, we do not consider these contracts to contain performance obligations for our services. As control of the natural gas passes to us prior to performing our gathering and processing services, we are, in effect, performing our services for our own benefit. Based on this control determination, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the natural gas, rather than being recorded as midstream services revenue. Upon sale of the residue gas and/or NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased.

13

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

• For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas does not pass to us until after the natural gas has been gathered and processed, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenues over time as we satisfy our performance obligations.

For midstream service contracts related to NGL, crude oil, or natural gas gathering and processing in which there is no commodity purchase or control of the commodity never passes to us and we simply earn a fee for our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenue over time as we satisfy our performance obligations. This treatment is consistent with our accounting for these contracts prior to the adoption of ASC 606.

For our natural gas transmission contracts, we determined that control of the natural gas never transfers to us and we simply earn a fee for our services. Therefore, we recognize these fees as midstream services revenue over time as we satisfy our performance obligations. This treatment is consistent with our accounting for natural gas transmission contracts prior to the adoption of ASC 606.

We also evaluate our commodity marketing contracts, under which we purchase and sell commodities in connection with our gas, NGL, and crude and condensate midstream services, pursuant to ASC 606, including the principal/agent provisions. For contracts in which we possess control of the commodity and act as principal in the purchase and sale of commodities, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. This treatment is consistent with our accounting for our commodity marketing contracts prior to the adoption of ASC 606.

Satisfaction of Performance Obligations and Recognition of Revenue

While ASC 606 alters the line item on which certain amounts are recorded on the consolidated statements of operations, ASC 606 did not significantly affect the timing of income and expense recognition on the consolidated statements of operations. Specifically, for our commodity sales contracts, we satisfy our performance obligations at the point in time at which the commodity transfers from us to the customer. This transfer pattern aligns with our billing methodology. Therefore, we recognize product sales revenue at the time the commodity is delivered and in the amount to which we have the right to invoice the customer, which is consistent with our accounting prior to the adoption of ASC 606. For our midstream service contracts that contain revenue-generating performance obligations, we satisfy our performance obligations over time as we perform the midstream service and as the customer receives the benefit of these services over the term of the contract. As permitted by ASC 606, we are utilizing the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice, since we have a right to consideration from our customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Accordingly, we continue to recognize revenue over time as our midstream services are performed. Therefore, ASC 606 does not significantly affect the timing of revenue and expense recognition on our consolidated statements of operations, and no cumulative effect adjustment was made to the balance of equity upon our adoption of ASC 606.

We generally accrue one month of sales and the related natural gas, NGL, condensate, and crude oil purchases and reverse these accruals when the sales and purchases are invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. We typically receive payment for invoiced amounts within one month, depending on the terms of the contract. We account for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

14

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Minimum Volume Commitments and Firm Transportation Contracts

Certain gathering and processing agreements in our Texas, Oklahoma, and Crude and Condensate segments provide for quarterly or annual MVCs, including MVCs from Devon from certain of our Barnett Shale assets in North Texas and our Cana gathering and processing assets in Oklahoma. Under these agreements, our customers or suppliers (as “customers” and “suppliers” are determined per application of ASC 606) 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 customer is obligated to pay a contractually-determined fee based upon the shortfall between actual product volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer or supplier 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 MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, 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 expected impact to our consolidated statements of operations, resulting from either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below reflect 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. In addition, amounts in the table below 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.

2018 (remaining)	$	190.9
2019	237.1
2020	225.7
2021	82.3
2022	71.9
Thereafter	231.2
Total	$	1,039.1

In May 2018, we restructured one of our natural gas gathering and processing contracts that included MVCs that were in effect through 2023. Prior to the contract restructuring, we expected$135.1 million in guaranteed future gross operating margin under the contract, generated from either revenue or reductions to cost of sales resulting from both gathering and processing fees as well as shortfall revenue under the MVCs. As a result of the contract restructuring, all MVC provisions were removed from the contract, and we and the counterparty entered into additional agreements pursuant to which: (i) the counterparty made a$19.7 million payment to us on the date of the contract restructuring to satisfy MVC revenue earned up to the date of the contract restructuring; (ii) the counterparty entered into a second lien secured term loan under which the counterparty will pay us$58.0 millionin principal payments in various installments ending in May 2023, with interest accruing on the loan balance at8.0%per annum beginning in 2020; and (iii) the counterparty granted to us a1.0%term overriding royalty interest through June 2034 in each well located on leasehold interests of the counterparty and connected to the gas gathering system that we operate. As a result of the contract restructuring and in accordance with ASC 606, we recognized$45.5 millionof midstream services revenue, which primarily represents the discounted present value of the second lien secured term loan receivable, in the Oklahoma segment in the second quarter of 2018. Pursuant to the contract restructuring, the terms of the restructured contract, other than the MVCs, are the same as the original contract, and we expect to continue recognizing gathering and processing fees on volumes delivered by the customer.

15

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

Contributions in Aid of Construction

The adoption of ASC 606 also alters how we account for contributions in aid of construction (“CIAC”). CIAC payments are lump sum payments from third parties to reimburse us for capital expenditures related to the construction of our operating assets and, in most cases, the connection of these operating assets to the third party’s assets. CIAC payments can be paid to us prior to the commencement of construction activities, during construction, or after construction has been completed. Prior to adoption of ASC 606 and in accordance with ASC 980, Regulated Operations (“ASC 980”), and the FERC Uniform System of Accounts, we reduced the balance of the related property and equipment by the amount of CIAC payments received. In doing so, CIAC payments previously affected the consolidated statements of operations through reduced depreciation expense over the useful lives of the related property and equipment. Upon adoption of ASC 606, we initially recognize CIAC payments received from customers as deferred revenue, which will be subsequently amortized into revenue over the term of the underlying operational contract. For CIAC payments from noncustomers and for payments related to the construction of regulated operating assets, we continue to reduce the balance of the related property and equipment in accordance with ASC 980 and the FERC Uniform System of Accounts. This change in our CIAC accounting policy was not material to our financial statements for thethree and nine months ended September 30, 2018.

Disaggregation of Revenue and Presentation of Prior Periods

Based on the disclosure requirements of ASC 606, we are presenting revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. SeeNote 13—Segment Informationfor the revenue disaggregation information included in the segment information table for thethree and nine months ended September 30, 2018. As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for thethree and nine months ended September 30, 2018are presented to conform to ASC 606 accounting and disclosure requirements. Prior periods presented in the consolidated financial statements and accompanying notes were not restated in accordance with ASC 606.

(c) Accounting Standards to be Adopted in Future Periods

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842)—Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”), which establishes ASC Topic 842, Leases (“ASC 842”). Under ASC 842, lessees will need to recognize virtually all of their leases on the balance sheet by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASC 842 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those annual periods. We will adopt ASC 842 effective January 1, 2019. We are currently assessing the impact of adopting ASC 842 and are in the process of implementing a lease accounting software tool. This assessment includes the evaluation of our current lease contracts and the analysis of contracts that may contain lease components. We are electing to apply certain practical expedients that are 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. While we are still evaluating the complete population of lease contracts, we believe the adoption of ASC 842 will increase our asset and liability balances on the consolidated balance sheets by less than$100 milliondue 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 January 2018, the FASB issued ASU 2018-01, Leases (Topic 842)—Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 amends ASC 842 and provides an optional practical expedient to not evaluate under ASC 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in ASC 840, Leases. Under ASU 2018-01, an entity that elects this practical expedient should evaluate new or modified land easements under ASC 842 beginning at the date that the entity adopts ASC 842. We plan to utilize the practical expedient provided in ASU 2018-01 in conjunction with our adoption of ASC 842.

In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842)—Targeted Improvements (“ASU 2018-11”). ASU 2018-11 amends ASC 842 and allows entities to adopt the new leases standard using a modified retrospective approach. Under this new transition method, entities initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Additionally, an entity’s reporting for

16

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with current GAAP. We plan to utilize the optional transition method provided in ASU 2018-11 in conjunction with our adoption of ASC 842 in January 2019.

(d)    Property & Equipment

Impairment Review. In accordance with ASC 360, Property, Plant and Equipment, we evaluate long-lived assets of identifiable business activities 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 three and nine months ended September 30, 2018, we recognized impairments of property and equipment of $24.6 million related to certain non-core pipeline assets, because the carrying values were no longer recoverable.For thethree and nine months ended September 30, 2017, we recognized impairments of property and equipment of$1.8 million and $8.8 million, respectively, which related to the carrying values of rights-of-way that we are no longer using and an abandoned brine disposal well.

(3) 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 from5 to 20 years.

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

	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Nine Months Ended September 30, 2018
Customer relationships, beginning of period	$	1,795.8	$	(298.7	)	$	1,497.1
Amortization expense	—		(92.6		)	(92.6		)
Customer relationships, end of period	$	1,795.8	$	(391.3	)	$	1,404.5

The weighted average amortization period is15.0 years. Amortization expense was $30.9 millionand$31.2 millionfor the three months endedSeptember 30, 2018and2017, respectively, and$92.6 millionand$96.2 millionfor theninemonths endedSeptember 30, 2018and2017, respectively.

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

2018 (remaining)	$	30.9
2019	123.7
2020	123.7
2021	123.7
2022	123.7
Thereafter	878.8
Total	$	1,404.5

17

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(4) Related Party Transactions

On July 18, 2018, subsidiaries of Devon sold all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP. 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. SeeNote 1—Generalfor additional information regarding the GIP Transaction.Prior to July 18, 2018, revenues from transactions with Devon are included in “Product sales—related 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.

From July 1, 2018 to July 18, 2018 and January 1, 2018 to July 18, 2018, Devon accounted for 2.0% and 7.3%of our revenues, respectively, and for thethree and ninemonths endedSeptember 30, 2017, Devon accounted for15.0%and15.4%of our revenues, respectively. We had an accounts receivable balance related to transactions with Devon of $102.7 million at December 31, 2017. Additionally, we had an accounts payable balance related to transactions with Devon of $16.3 million at December 31, 2017.

For thethree and ninemonths endedSeptember 30, 2018, we recorded cost of sales of$11.3 millionand$33.8 million, respectively, and for thethree and ninemonths endedSeptember 30, 2017, we recorded cost of sales of$9.5 millionand$15.0 million, respectively, related to our 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 related to transactions with the Cedar Cove JV of$0.7 million at September 30, 2018. Additionally, we had an accounts payable balance related to transactions with the Cedar Cove JV of$5.0 million at September 30, 2018. The accounts receivable and payable balances related to transactions with the Cedar Cove JV were immaterial atDecember 31, 2017.

Management believes these transactions are executed on terms that are fair and reasonable to us. The amounts related to related party transactions are specified in the accompanying consolidated financial statements.

18

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(5) Long-Term Debt

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

	September 30, 2018								December 31, 2017
	Outstanding Principal		Premium (Discount)			Long-Term Debt			Outstanding Principal		Premium (Discount)			Long-Term Debt
ENLK credit facility due 2020 (1)	$	765.0	$	—		$	765.0		$	—	$	—		$	—
ENLC credit facility due 2019 (2)	101.4		—			101.4			74.6		—			74.6
ENLK’s 2.70% Senior unsecured notes due 2019	400.0		(0.1		)	399.9			400.0		(0.1		)	399.9
ENLK’s 4.40% Senior unsecured notes due 2024	550.0		1.9			551.9			550.0		2.2			552.2
ENLK’s 4.15% Senior unsecured notes due 2025	750.0		(0.9		)	749.1			750.0		(1.0		)	749.0
ENLK’s 4.85% Senior unsecured notes due 2026	500.0		(0.5		)	499.5			500.0		(0.6		)	499.4
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		(6.2		)	443.8			450.0		(6.5		)	443.5
ENLK's 5.45% Senior unsecured notes due 2047	500.0		(0.1		)	499.9			500.0		(0.1		)	499.9
Debt classified as long-term, including current maturities of long-term debt	$	4,366.4	$	(6.1	)	4,360.3			$	3,574.6	$	(6.3	)	3,568.3
Debt issuance cost (3)						(23.5		)						(26.2		)
Less: Current maturities of long-term debt (4)						(500.9		)						—
Long-term debt, net of unamortized issuance cost						$	3,835.9							$	3,542.1

(1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was4.1%atSeptember 30, 2018.

(2) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 4.1% and 3.2% at September 30, 2018 and December 31, 2017, respectively.

(3) Net of amortization of $15.7 million and $12.9 million at September 30, 2018 and December 31, 2017, respectively.

(4) The outstanding balance, net of debt issuance costs, of the ENLC Credit Facility and ENLK’s2.70%senior unsecured notes as ofSeptember 30, 2018are classified as “Current maturities of long-term debt” on the consolidated balance sheet as the ENLC Credit Facility matures on March 7, 2019, and ENLK’s 2.70% senior unsecured notes mature on April 1, 2019.

ENLC Credit Facility

The ENLC Credit Facility is a $250.0 million revolving credit facility that matures on March 7, 2019 and includes a $125.0 million letter of credit subfacility. Our obligations under the ENLC Credit Facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 88,528,451 ENLK common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us, and (iii) any additional equity interests subsequently pledged as collateral under the ENLC Credit Facility.

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

Borrowings under the ENLC Credit Facility bear interest at our option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.75% to 2.50%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, 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.

19

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

On June 20, 2018, we amended the change of control provisions of the ENLC Credit Facility to, among other things, designate GIP as Qualifying Owners (as defined in the ENLC Credit Facility). At September 30, 2018, ENLC was in compliance and expects to be in compliance with the covenants in the ENLC Credit Facility through its maturity date.

As of September 30, 2018, there were no outstanding letters of credit and $101.4 million in outstanding borrowings under the ENLC Credit Facility, leaving approximately $148.6 million available for future borrowing.

ENLK Credit Facility

The ENLK Credit Facility is a $1.5 billion unsecured revolving credit facility that matures on March 6, 2020 and includes a $500.0 millionletter 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 millionand (2) subject to certain conditions and the consent of the requisite lenders, ontwo separate occasions, extend the maturity date of the ENLK Credit Facility by one yearon 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 to5.5 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 plus1.0%or the administrative agent’s prime rate) plus an applicable margin (ranging from0.0% to 0.75%). The applicable margins vary depending on ENLK’s credit rating. If ENLK breaches certain covenants governing the ENLK Credit Facility, amounts outstanding under the ENLK Credit Facility, if any, may become due and payable immediately.

On June 20, 2018, ENLK amended the change of control provisions of the ENLK Credit Facility to, among other things, designate GIP as Qualifying Owners (as defined in the ENLK Credit Facility). At September 30, 2018, ENLK was in compliance and expects to be in compliance with the covenants in the ENLK Credit Facility for at least the next twelve months.

As of September 30, 2018, there were $9.3 millionin outstanding letters of credit and $765.0 million outstanding borrowings under the ENLK Credit Facility, leaving approximately $725.7 million available for future borrowing.

All other material terms and conditions of the ENLC Credit Facility, the ENLK Credit Facility, and outstanding senior unsecured notes 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, 2017.

(6) 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,
	2018		2017		2018		2017
Current income tax provision	$	1.0	$	0.9	$	1.9	$	1.3
Deferred income tax provision	3.0		2.2		$	15.4	$	8.0
Total income tax provision	$	4.0	$	3.1	$	17.3	$	9.3

20

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The following schedule reconciles total income tax expense 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,
	2018			2017			2018			2017
Expected income tax provision based on federal statutory rate (1)	$	2.4		$	3.3		$	13.7		$	6.8
State income taxes expense, net of federal tax benefit	0.3			0.2			1.6			0.5
Income tax expense (benefit) from ENLK	0.9			0.5			(0.2		)	0.7
Unit-based compensation	(0.9		)	—			0.6			2.3
Other	1.3			(0.9		)	1.6			(1.0		)
Total income tax provision	$	4.0		$	3.1		$	17.3		$	9.3

(1) The statutory federal tax rate for corporations was 21% at September 30, 2018 and 35% at September 30, 2017.

(7) Certain Provisions of the Partnership Agreement

(a) Issuance of ENLK Common Units

In August 2017, ENLK entered into 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 of the common units under the 2017 EDA and may at any time suspend solicitation and offers under the 2017 EDA.

For thenine months ended September 30, 2018, ENLK sold an aggregate of approximately2.6 millioncommon units under the 2017 EDA, generating proceeds of approximately$46.1 million(net of approximately$0.5 millionof commissions paid to the Sales Agents). ENLK used the net proceeds for general partnership purposes. As of September 30, 2018, approximately $518.8 millionin aggregate gross proceeds remains available to be issued under the 2017 EDA.

(b) ENLK Series B Preferred Units

Beginning with the quarter ended September 30, 2017, Series B Preferred Unit distributions are payable quarterlyin cash at an amount equal to$0.28125 per Series B Preferred Unit (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A)0.0025Series B Preferred Units per Series B Preferred Unit and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Series B Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the issue price of $15.00.

21

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

A summary of the distribution activity relating to the Series B Preferred Units during the nine months ended September 30, 2018 and 2017 is provided below:

Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2018
Fourth Quarter of 2017	413,658	$	16.0	February 13, 2018
First Quarter of 2018	416,657	$	16.2	May 14, 2018
Second Quarter of 2018	419,678	$	16.3	August 13, 2018
Third Quarter of 2018	422,720	$	16.4	November 13, 2018
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

(c) ENLK Series C Preferred Units

Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15^th day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15^th day of March, June, September, and December of each year, in each case, if and when declared by the General Partner out of legally available funds for such purpose. The distribution rate for the Series C Preferred Units is6.0%per annum, and ENLK distributed $12.0 million to holders of Series C Preferred Units during thenine months ended September 30, 2018.

(d) ENLK Common Unit Distributions

Unless restricted by the terms of the ENLK Credit Facility and/or the indentures governing ENLK’s senior unsecured notes, ENLK must make distributions of100%of available cash, as defined in its partnership agreement, within 45 daysfollowing the end of each quarter. Distributions of available cash 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 distributions with respect to (i) distributions on theSeries 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 incentive distribution rights in ENLK. 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 to13.0% 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.

22

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

A summary of ENLK’s distribution activity relating to the common units during theninemonths endedSeptember 30, 2018 and 2017 is provided below:

Declaration period	Distribution/unit		Date paid/payable
2018
Fourth Quarter of 2017	$	0.39	February 13, 2018
First Quarter of 2018	$	0.39	May 14, 2018
Second Quarter of 2018	$	0.39	August 13, 2018
Third Quarter of 2018	$	0.39	November 13, 2018
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

(e) Allocation of ENLK Income

Net income is allocated to the General Partner in an amount equal to its incentive distribution rights as described in section “(d) ENLK Common Unit Distributions” above. The General Partner’s share of net income consists of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units, and the percentage interest of ENLK’s net incomeadjusted 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,
	2018			2017			2018			2017
Income allocation for incentive distributions	$	15.0		$	14.8		$	44.6		$	44.1
Unit-based compensation attributable to ENLC’s restricted and performance units	(7.3		)	(4.2		)	(15.7		)	(16.9		)
General Partner share of net income	—			—			0.6			0.1
General Partner interest in net income	$	7.7		$	10.6		$	29.5		$	27.3

23

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(8) Members' Equity

(a)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 unit for the periods presented (in millions, except per unit amounts):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
ENLC interest in net income	$	7.7		$	6.2		$	48.1		$	10.2
Distributed earnings allocated to:
Common units (1) (2)	$	49.1		$	46.0		$	145.0		$	138.0
Unvested restricted units (1) (2)	0.9			0.7			2.2			1.9
Total distributed earnings	$	50.0		$	46.7		$	147.2		$	139.9
Undistributed loss allocated to:
Common units	$	(41.5	)	$	(39.9	)	$	(97.6	)	$	(128.0	)
Unvested restricted units	(0.8		)	(0.6		)	(1.5		)	(1.7		)
Total undistributed loss	$	(42.3	)	$	(40.5	)	$	(99.1	)	$	(129.7	)
Net income allocated to:
Common units	$	7.6		$	6.1		$	47.4		$	10.0
Unvested restricted units	0.1			0.1			0.7			0.2
Total net income	$	7.7		$	6.2		$	48.1		$	10.2
Basic and diluted net income per unit:
Basic	$	0.04		$	0.03		$	0.27		$	0.06
Diluted	$	0.04		$	0.03		$	0.26		$	0.06

(1) For the three months ended September 30, 2018 and 2017, distributed earnings represent a declared distribution of $0.271 per unit payable on November 14, 2018 and a distribution of $0.255 per unit paid on November 14, 2017, respectively.

(2) For the nine months ended September 30, 2018, distributed earnings included a declared distribution of $0.271 per unit payable on November 14, 2018, $0.267 per unit paid on August 14, 2018, and $0.263 per unit paid on May 15, 2018. For the nine months ended September 30, 2017, distributed earnings included distributions of $0.255 per unit paid on November 14, 2017, $0.255 per unit paid on August 14, 2017, and $0.255 per unit paid on May 15, 2017.

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,
	2018	2017	2018	2017
Basic weighted average units outstanding:
Weighted average common units outstanding	181.2	180.6	181.1	180.4
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	181.2	180.6	181.1	180.4
Dilutive effect of non-vested restricted units	1.3	1.2	1.1	1.3
Total weighted average diluted common units outstanding	182.5	181.8	182.2	181.7

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.

24

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(b) Distributions

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

Declaration period	Distribution/unit		Date paid/payable
2018
Fourth Quarter of 2017	$	0.259	February 14, 2018
First Quarter of 2018	$	0.263	May 15, 2018
Second Quarter 2018	$	0.267	August 14, 2018
Third Quarter 2018	$	0.271	November 14, 2018
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

25

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(9) Investment in Unconsolidated Affiliates

As of September 30, 2018, our unconsolidated investments consisted of a 38.75%ownership in GCF and an approximate30% ownership in the Cedar Cove 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,
	2018			2017			2018			2017
GCF
Distributions	$	5.3		$	3.5		$	16.4		$	10.6
Equity in income	$	4.6		$	4.5		$	14.0		$	8.5
HEP
Equity in loss (1)	$	—		$	—		$	—		$	(3.4	)
Cedar Cove JV
Contributions	$	—		$	1.5		$	0.1		$	11.8
Distributions	$	—		$	0.5		$	0.3		$	0.8
Equity in loss	$	(0.3	)	$	(0.1	)	$	(2.3	)	$	(0.1	)
Total
Contributions	$	—		$	1.5		$	0.1		$	11.8
Distributions	$	5.3		$	4.0		$	16.7		$	11.4
Equity in income (1)	$	4.3		$	4.4		$	11.7		$	5.0

(1) We sold our ownership interest in HEP during the first quarter of 2017, resulting in a loss of$3.4 million for the ninemonths ended September 30, 2017.

The following table shows the balances related to our investment in unconsolidated affiliates as ofSeptember 30, 2018 and December 31, 2017 (in millions):

	September 30, 2018		December 31, 2017
GCF	$	46.0	$	48.4
Cedar Cove JV	38.5		41.0
Total investment in unconsolidated affiliates	$	84.5	$	89.4

(10) Employee Incentive Plans

(a) Long-Term Incentive Plans

ENLC and ENLK each have similar unit-based compensation payment plans for officers and employees. ENLC grants unit-based awards under the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “2014 Plan”), and ENLK grants unit-based awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP 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 in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of 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

26

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

plan awarded to ENLC’s officers and employees is recorded by us since ENLC has no substantial or managed operating activities other than its interests in ENLK and EOGP.

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,
	2018		2017		2018		2017
Cost of unit-based compensation charged to operating expense	$	5.2	$	2.8	$	9.5	$	10.4
Cost of unit-based compensation charged to general and administrative expense	11.9		7.4		22.3		28.5
Total unit-based compensation expense	$	17.1	$	10.2	$	31.8	$	38.9
Non-controlling interest in unit-based compensation	$	6.6	$	3.9	$	12.1	$	14.6
Amount of related income tax benefit recognized in net income (1)	$	2.2	$	2.4	$	4.1	$	9.1

(1) For the three and nine months ended September 30, 2018, the amount of related income tax benefit recognized in net income excluded $0.9 million of income tax benefit and $0.6 million of income tax expense, respectively, related to tax deficiencies recorded upon vesting of restricted units. For the nine months ended September 30, 2017, the amount of related income tax benefit recognized in net income excluded $2.3 million of income tax expense related to tax deficiencies recorded upon vesting of restricted units. There was no income tax expense or benefit related to tax deficiencies recorded upon vesting of restricted units for the three months ended September 30, 2017.

(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 ENLK common units on such date.A summary of the restricted incentive unit activity for thenine months ended September 30, 2018is provided below:

	Nine Months Ended September 30, 2018
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,980,224			$	15.81
Granted (1)	1,586,750			15.27
Vested (1)(2)	(813,290		)	19.78
Forfeited	(157,057		)	12.42
Non-vested, end of period	2,596,627			$	14.44
Aggregate intrinsic value, end of period (in millions)	$	48.4

(1) Restricted incentive units typically vest at the end of three years. In March 2018, ENLK granted 200,753restricted incentive units with a fair value of$3.0 millionto officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.

(2) Vested units included255,653units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for thethree and nine months ended September 30, 2018 and 2017 is provided below (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
EnLink Midstream Partners, LP Restricted Incentive Units:	2018		2017		2018		2017
Aggregate intrinsic value of units vested	$	3.7	$	0.6	$	12.8	$	16.3
Fair value of units vested	$	2.8	$	1.1	$	16.1	$	22.1

27

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

As of September 30, 2018, there was $22.2 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 2.0 years.

(c) EnLink Midstream Partners, LP Performance Units

The General Partner grants performance awards under the GP 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 total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the AMZ, excluding ENLC and ENLK, on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of ENLC’s and ENLK’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units ranges fromzero to 200% of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLK’s common units and the designated Peer Companies’ securities; (iii) an estimated ranking of ENLK among the designated 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 of performance units granted and the related assumptions by performance unit grant date:

EnLink Midstream Partners, LP Performance Units:	March 2018
Beginning TSR price	$	15.44
Risk-free interest rate	2.38		%
Volatility factor	43.85		%
Distribution yield	10.5		%

The following table presents a summary of the performance units:

	Nine Months Ended September 30, 2018
EnLink Midstream Partners, LP Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	585,285			$	20.52
Granted	256,345			19.24
Vested (1)	(313,610		)	24.43
Forfeited	(76,351		)	16.62
Non-vested, end of period	451,669			$	17.74
Aggregate intrinsic value, end of period (in millions)	$	8.4

(1) Vested units included112,101units withheld for payroll taxes paid on behalf of employees and 120,250units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes.

28

ENLINK MIDSTREAM, LLC

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 theninemonths endedSeptember 30, 2018 is provided below (in millions). No performance units vested for the three and nine months ended September 30, 2017.

EnLink Midstream Partners, LP Performance Units:	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Aggregate intrinsic value of units vested	$	3.0	$	5.0
Fair value of units vested	$	3.6	$	7.7

As ofSeptember 30, 2018, there was$6.2 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 1.8 years.

In connection with the GIP Transaction, certain outstanding performance unit agreements were modified to increase the minimum vesting of units fromzeroto100% as described in our Current Report on Form 8-K filed with the Securities and Exchange Commission (the “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$2.3 million compensation cost over the life of these ENLK performance units.

(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 ENLC common units on such date.A summary of the restricted incentive unit activity for theninemonths endedSeptember 30, 2018is provided below:

	Nine Months Ended September 30, 2018
EnLink Midstream, LLC Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,889,310			$	16.33
Granted (1)	1,469,452			15.76
Vested (1)(2)	(749,164		)	21.53
Forfeited	(146,045		)	12.38
Non-vested, end of period	2,463,553			$	14.64
Aggregate intrinsic value, end of period (in millions)	$	40.5

(1) Restricted incentive units typically vest at the end of three years. In March 2018, ENLC granted194,185restricted incentive units with a fair value of$3.0 million to officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.

(2) Vested units included238,970units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for thethree and nine months ended September 30, 2018 and 2017is provided below (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
EnLink Midstream, LLC Restricted Incentive Units:	2018		2017		2018		2017
Aggregate intrinsic value of units vested	$	3.3	$	0.6	$	12.6	$	15.2
Fair value of units vested	$	2.6	$	1.1	$	16.1	$	21.9

As of September 30, 2018, there was $21.5 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 2.0 years.

29

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(e) EnLink Midstream, LLC’s Performance Units

ENLC grants performance awards under the 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 TSR performance goals relative to the TSR achievement of the Peer Companies 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 ranges fromzero to 200%of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC’s common units and the designated Peer Companies’ securities; (iii) an estimated ranking of ENLC among the designated 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 approximatelythree years. The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:

EnLink Midstream, LLC Performance Units:	March 2018
Beginning TSR price	$	16.55
Risk-free interest rate	2.38		%
Volatility factor	51.36		%
Distribution yield	6.7		%

The following table presents a summary of the performance units:

	Nine Months Ended September 30, 2018
EnLink Midstream, LLC Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	548,839			$	22.14
Granted	223,865			21.63
Vested (1)	(283,637		)	27.25
Forfeited	(70,918		)	17.75
Non-vested, end of period	418,149			$	19.15
Aggregate intrinsic value, end of period (in millions)	$	6.9

(1) Vested units included100,109units withheld for payroll taxes paid on behalf of employees and 109,819units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes.

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 theninemonths endedSeptember 30, 2018is provided below (in millions). No performance units vested for the three and nine months ended September 30, 2017.

EnLink Midstream, LLC Performance Units:	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Aggregate intrinsic value of units vested	$	2.8	$	4.7
Fair value of units vested	$	3.5	$	7.7

As of September 30, 2018, 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 1.8 years.

In connection with the GIP Transaction, certain outstanding performance unit agreements were modified to increase the minimum vesting of units fromzero to 100%as described in our Current Report on Form 8-K filed with the 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.

30

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(11) 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 ENLK’s 5.45% senior unsecured notes due 2047 (the “2047 Notes”). In accordance with ASC 815, we designated this swap as a cash flow hedge. Upon settlement of the interest rate swap in May 2017, we recorded the associated $2.2 million settlement loss in accumulated 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. For the three and nine months ended September 30, 2018, we amortized an immaterial amount of the settlement loss into interest expense from accumulated other comprehensive income (loss). We expect to recognize$0.1 millionof interest expense out of accumulated other comprehensive income (loss) over the next twelve months. We have no open interest rate swap position as of September 30, 2018.

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 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 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 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.

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Change in fair value of derivatives	$	(0.8	)	$	(3.3	)	$	(14.8	)	$	3.8
Realized loss on derivatives	(4.6		)	(2.2		)	(5.3		)	(4.9		)
Loss on derivative activity	$	(5.4	)	$	(5.5	)	$	(20.1	)	$	(1.1	)

31

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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

	September 30, 2018			December 31, 2017
Fair value of derivative assets—current	$	12.5		$	6.8
Fair value of derivative liabilities—current	(21.9		)	(8.4		)
Fair value of derivative liabilities—long-term	(7.0		)	—
Net fair value of derivatives	$	(16.4	)	$	(1.6	)

As of September 30, 2018 and December 31, 2017, there were no derivative assets classified as long-term on the consolidated balance sheets.

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

		September 30, 2018
Commodity	Instruments	Unit	Volume		Fair Value
NGL (short contracts)	Swaps	Gallons	(58.4	)	$	(12.0	)
NGL (long contracts)	Swaps	Gallons	18.9		3.1
Natural Gas (short contracts)	Swaps	MMBtu	(9.0	)	0.4
Natural Gas (long contracts)	Swaps	MMBtu	10.9		(1.4		)
Crude and condensate (short contracts)	Swaps	MMbbls	(13.3	)	(13.2		)
Crude and condensate (long contracts)	Swaps	MMbbls	1.3		6.7
Total fair value of derivatives					$	(16.4	)

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 financial institutions when entering into financial derivatives on commodities. We have entered into Master 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, the maximum loss on our gross receivable position of$12.5 million as of September 30, 2018 would be reduced to$0.1 milliondue to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

(12) 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

32

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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, 2018			December 31, 2017
Commodity Swaps (1)	$	(16.4	)	$	(1.6	)

(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.

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, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current maturities of long-term debt (1)	$	4,336.8	$	4,119.0	$	3,542.1	$	3,650.2
Installment Payables	$	—	$	—	$	249.5	$	249.6
Obligations under capital lease	$	2.9	$	2.5	$	4.1	$	3.4
Secured term loan receivable	$	49.9	$	49.9	$	—	$	—

(1) The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance costs of$23.5 million and $26.2 million at September 30, 2018 and December 31, 2017, 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 $765.0 million of outstanding borrowings under the ENLK Credit Facility as of September 30, 2018 and no outstanding borrowings under the ENLK Credit Facility as of December 31, 2017. ENLC had $101.4 million and $74.6 million in outstanding borrowings under the ENLC Credit Facility as of September 30, 2018 and December 31, 2017, respectively. As borrowings under the ENLK Credit Facility and ENLC Credit Facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the ENLK Credit Facility and the ENLC Credit Facility. As of September 30, 2018 and December 31, 2017, ENLK had total borrowings under senior unsecured notes of$3.5 billion maturing between 2019 and 2047 with fixed interest rates ranging from2.7% to 5.6%. The fair values of all senior unsecured notes and installment payables as ofSeptember 30, 2018 and December 31, 2017were based on Level 2 inputs from third-party market quotations. The fair values of obligations under capital leases and the secured term loan receivable were calculated using Level 2 inputs from third-party banks.

(13) Segment Information

Identification of the majority of our operating segments is based principally upon geographic regions served and the nature of operating activity. Our reportable segments consist of the following: natural gas gathering, processing, transmission, and fractionation operations located in North Texas and the Permian Basin primarily in West Texas (“Texas”), natural gas pipelines, processing plants, storage facilities, NGL pipelines, and fractionation assets in Louisiana (“Louisiana”), natural gas gathering and processing operations located throughout Oklahoma (“Oklahoma”), and crude rail, truck, pipeline, and barge facilities in West Texas, South Texas, Louisiana, Oklahoma, 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 segment profits.

33

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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.

Based on the disclosure requirements of ASC 606, we are presenting revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for thethree and nine months ended September 30, 2018are presented to conform to ASC 606 accounting and disclosure requirements. Prior periods presented in the consolidated financial statements and accompanying notes were not restated in accordance with ASC 606.

34

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

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

	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals
Three Months Ended September 30, 2018
Natural gas sales	$	69.1		$	129.5		$	41.9		$	—		$	—		$	240.5
NGL sales	16.8			839.6			12.8			0.1			—			869.3
Crude oil and condensate sales	—			0.1			0.3			722.0			—			722.4
Product sales	85.9			969.2			55.0			722.1			—			1,832.2
Natural gas sales—related parties	—			—			0.1			—			—			0.1
NGL sales—related parties	153.8			10.9			192.5			—			(347.2		)	10.0
Crude oil and condensate sales—related parties	13.4			0.1			18.0			1.5			(32.9		)	0.1
Product sales—related parties	167.2			11.0			210.6			1.5			(380.1		)	10.2
Gathering and transportation	71.7			17.5			50.2			0.8			—			140.2
Processing	39.4			0.8			31.5			—			—			71.7
NGL services	—			11.9			—			—			—			11.9
Crude services	—			—			0.2			14.9			—			15.1
Other services	2.4			0.1			—			0.1			—			2.6
Midstream services	113.5			30.3			81.9			15.8			—			241.5
Gathering and transportation—related parties	8.7			—			7.2			—			—			15.9
Processing—related parties	10.2			—			3.2			—			—			13.4
Crude services—related parties	—			—			0.1			6.3			—			6.4
Other services—related parties	0.1			—			—			—			—			0.1
Midstream services—related parties	19.0			—			10.5			6.3			—			35.8
Revenue from contracts with customers	385.6			1,010.5			358.0			745.7			(380.1		)	2,119.7
Cost of sales	(222.0		)	(923.6		)	(228.5		)	(702.6		)	380.1			(1,696.6		)
Operating expenses	(44.7		)	(28.7		)	(22.5		)	(18.8		)	—			(114.7		)
Loss on derivative activity	—			—			—			—			(5.4		)	(5.4		)
Segment profit (loss)	$	118.9		$	58.2		$	107.0		$	24.3		$	(5.4	)	$	303.0
Depreciation and amortization	$	(54.0	)	$	(32.7	)	$	(44.7	)	$	(12.9	)	$	(2.4	)	$	(146.7	)
Impairments	$	—		$	(24.6	)	$	—		$	—		$	—		$	(24.6	)
Goodwill	$	232.0		$	—		$	190.3		$	—		$	1,119.9		$	1,542.2
Capital expenditures	$	90.0		$	13.0		$	109.3		$	39.9		$	1.1		$	253.3
Three Months Ended September 30, 2017
Product sales	$	80.8		$	642.3		$	42.5		$	291.1		$	—		$	1,056.7
Product sales—related parties	130.6			10.0			94.6			—			(199.9		)	35.3
Midstream services	29.1			50.3			44.3			12.7			—			136.4
Midstream services—related parties	106.7			35.9			63.0			4.8			(35.4		)	175.0
Cost of sales	(198.5		)	(662.7		)	(148.2		)	(279.1		)	235.3			(1,053.2		)
Operating expenses	(41.1		)	(24.8		)	(17.1		)	(19.1		)	—			(102.1		)
Loss on derivative activity	—			—			—			—			(5.5		)	(5.5		)
Segment profit (loss)	$	107.6		$	51.0		$	79.1		$	10.4		$	(5.5	)	$	242.6
Depreciation and amortization	$	(52.5	)	$	(29.3	)	$	(40.2	)	$	(11.7	)	$	(2.6	)	$	(136.3	)
Impairments	$	—		$	—		$	—		$	(1.8	)	$	—		$	(1.8	)
Goodwill	$	232.0		$	—		$	190.3		$	—		$	1,119.9		$	1,542.2
Capital expenditures	$	39.1		$	7.5		$	107.7		$	13.3		$	2.1		$	169.7

35

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals
Nine Months Ended September 30, 2018
Natural gas sales	$	208.9		$	377.2		$	127.9		$	—		$	—		$	714.0
NGL sales	16.8			2,075.9			18.3			0.9			—			2,111.9
Crude oil and condensate sales	—			0.2			0.3			1,940.1			—			1,940.6
Product sales	225.7			2,453.3			146.5			1,941.0			—			4,766.5
Natural gas sales—related parties	—			—			2.5			—			—			2.5
NGL sales—related parties	381.1			45.4			433.0			—			(822.1		)	37.4
Crude oil and condensate sales—related parties	39.4			0.3			63.9			3.3			(105.8		)	1.1
Product sales—related parties	420.5			45.7			499.4			3.3			(927.9		)	41.0
Gathering and transportation	98.4			51.8			91.4			2.5			—			244.1
Processing	52.7			2.5			87.9			—			—			143.1
NGL services	—			38.8			—			—			—			38.8
Crude services	—			—			0.2			42.8			—			43.0
Other services	6.4			0.5			—			0.2			—			7.1
Midstream services	157.5			93.6			179.5			45.5			—			476.1
Gathering and transportation—related parties	122.7			—			80.6			—			—			203.3
Processing—related parties	108.6			—			48.4			—			—			157.0
Crude services—related parties	—			—			1.5			14.9			—			16.4
Other services—related parties	0.5			—			—			—			—			0.5
Midstream services—related parties	231.8			—			130.5			14.9			—			377.2
Revenue from contracts with customers	1,035.5			2,592.6			955.9			2,004.7			(927.9		)	5,660.8
Cost of sales	(562.2		)	(2,333.3		)	(537.8		)	(1,898.3		)	927.9			(4,403.7		)
Operating expenses	(134.7		)	(82.3		)	(64.0		)	(56.3		)	—			(337.3		)
Loss on derivative activity	—			—			—			—			(20.1		)	(20.1		)
Segment profit (loss)	$	338.6		$	177.0		$	354.1		$	50.1		$	(20.1	)	$	899.7
Depreciation and amortization	$	(159.9	)	$	(92.4	)	$	(133.2	)	$	(38.0	)	$	(6.6	)	$	(430.1	)
Impairments	$	—		$	(24.6	)	$	—		$	—		$	—		$	(24.6	)
Goodwill	$	232.0		$	—		$	190.3		$	—		$	1,119.9		$	1,542.2
Capital expenditures	$	200.0		$	36.4		$	328.8		$	84.1		$	3.4		$	652.7
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

36

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

The table below represents information about segment assets as ofSeptember 30, 2018 and December 31, 2017 (in millions):

Segment Identifiable Assets:	September 30, 2018		December 31, 2017
Texas	$	3,161.9	$	3,094.8
Louisiana	2,583.8		2,408.5
Oklahoma	3,074.1		2,836.7
Crude and Condensate	1,069.9		929.5
Corporate	1,308.6		1,268.3
Total identifiable assets	$	11,198.3	$	10,537.8

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Segment profit	$	303.0		$	242.6		$	899.7		$	686.7
General and administrative expenses	(41.9		)	(31.3		)	(99.8		)	(98.5		)
Loss on disposition of assets	—			(1.1		)	(1.3		)	(0.8		)
Depreciation and amortization	(146.7		)	(136.3		)	(430.1		)	(407.1		)
Impairments	(24.6		)	(1.8		)	(24.6		)	(8.8		)
Gain on litigation settlement	—			—			—			26.0
Operating income	$	89.8		$	72.1		$	343.9		$	197.5

(14) Other Information

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

Other Current Assets:	September 30, 2018		December 31, 2017
Natural gas and NGLs inventory	$	119.4	$	30.1
Secured term loan receivable from contract restructuring, net of discount of $1.1	18.4		—
Prepaid expenses and other	17.3		11.1
Natural gas and NGLs inventory, prepaid expenses, and other	$	155.1	$	41.2

Other Current Liabilities:	September 30, 2018		December 31, 2017
Accrued interest	$	64.8	$	35.6
Accrued wages and benefits, including taxes	24.8		30.4
Accrued ad valorem taxes	33.4		27.8
Capital expenditure accruals	57.9		48.8
Onerous performance obligations	13.5		15.2
Other	67.0		65.1
Other current liabilities	$	261.4	$	222.9

37

ENLINK MIDSTREAM, LLC

Notes to Consolidated Financial Statements (Continued)

(Unaudited)

(15) Subsequent Event

On October 21, 2018, we and ENLK entered into the Merger Agreement and the related preferred restructuring agreement, pursuant to which, subject to the satisfaction or waiver of certain conditions:

• Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) will be converted into the right to receive1.15ENLC common units;

• The General Partner’s incentive distribution rights in ENLK will be eliminated;

• The Series B Preferred Units will continue to be issued and outstanding following the Merger, except that certain terms of the Series B Preferred Units will be modified pursuant to an amended partnership agreement of ENLK, including exchangeability of the Series B Preferred Units, under certain circumstances, into ENLC common units instead of ENLK common units, subject to the election of ENLK to instead redeem for cash any such exchanged Series B Preferred Units;

• ENLC will issue to Enfield Holdings, L.P. (“Enfield”), the current holder of the Series B Preferred Units, for no additional consideration, a new class of non-economic ENLC 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;

• The Series C Preferred Units will continue to be issued and outstanding following the Merger; and

• All unit-based awards issued and outstanding immediately prior to the effective time of the Merger under the GP Plan will be converted into an award with respect to ENLC common units with substantially similar terms as were in effect immediately prior to the effective time, with certain adjustments to the performance-based vesting of terms of applicable awards related to the performance of ENLC.

The Merger Transactions are expected to close in the first quarter of 2019, subject to obtaining approval of ENLK’s unitholders, customary regulatory approvals, and other customary closing conditions.

38

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

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,” “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 the Operating Partnership and EOGP.

Overview

We are a Delaware limited liability company formed in October 2013. Our assets consist of equity interests in ENLK and EOGP. ENLK is a publicly traded limited partnership engaged in the gathering, transmission, processing, and marketing of natural gas, NGLs, condensate, and crude oil, as well as providing crude oil, condensate, and brine services to producers. EOGP is a partnership held by us and ENLK and is engaged in the gathering and processing of natural gas. As ofSeptember 30, 2018, our direct and indirect interests in ENLK and EOGP consisted of the following:

• 88,528,451common units representing an aggregate21.4%limited partner interest in ENLK;

• 100.0%ownership interest in the General Partner of ENLK, which owns a0.4%general partner interest and all of the incentive distribution rights in ENLK; and

• 16.1%limited partner interest in EOGP

Each of ENLK and EOGP is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by their respective general partners in their sole discretion to provide for the proper conduct of ENLK’s or EOGP’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 interest in ENLK, we reflect our ownership interest in ENLK on a consolidated basis, which means that our financial results are combined with ENLK’s financial results and the results of our other subsidiaries. Our consolidated results of operations are derived from the results of operations of ENLK and also include our deferred taxes, interest of non-controlling partners in ENLK’s net income, interest income (expense), and general and administrative expenses 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.

We primarily focus on providing midstream energy services, including:

• gathering, compressing, treating, processing, transporting, storing, and selling natural gas;

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

• gathering, transporting, stabilizing, storing, trans-loading, and selling crude oil and 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 4.8 Bcf/d of processing capacity, seven fractionators with approximately 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:

• Texas Segment. The Texas segment includes our natural gas gathering, processing, and transmission operations in North Texas and the Permian Basin primarily in West Texas;

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• Oklahoma Segment. The Oklahoma segment includes our natural gas gathering, processing, and transmission activities in the Cana-Woodford, Arkoma-Woodford, Northern Oklahoma Woodford, STACK, and CNOW 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 and Condensate Segment. The Crude and Condensate segment includes our 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, Delaware Basin, and Central Oklahoma, and our crude oil activities associated with VEX located in the Eagle Ford Shale; and

• 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, and our general corporate property, goodwill, and expenses.

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 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 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. 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 90% of our gross operating margin was derived from fee-based contractual arrangements with minimal direct commodity price exposure for the nine months ended September 30, 2018. 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 and nine months ended September 30, 2018, approximately 38.5% and 38.3% of our gross operating margin, respectively, was attributable to commercial contracts with Devon.

We generate revenues from eight primary sources:

• gathering and transporting natural gas, NGLs, and 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 or transported through our pipeline systems;

• crude oil and condensate handled at our crude terminals;

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

• condensate stabilized;

• brine disposed; and

• natural gas, crude oil, and NGLs stored.

We gather, transport, or store gas owned by others under fee-only contract arrangements based either on the volume of gas gathered, transported, or 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 or shippers at a market index less a fee-based deduction subtracted from the purchase price of the natural gas. We then gather or transport the natural gas and sell the natural gas at a market index, thereby earning a margin through the 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. We are also party to certain long-term gas sales commitments that

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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 ending June 2019 that requires us 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, 2018, the balance sheet reflects a liability of $13.5 million related to this performance obligation. Unfavorable 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 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 gather or transport crude oil and condensate owned by others by rail, truck, pipeline, and barge facilities under fee-only contract arrangements based on volumes gathered or transported. We also buy crude oil and condensate from producers at a market index less a stated deduction, then transport and resell the crude oil and condensate at the same market index. We execute substantially all purchases and sales concurrently, thereby establishing the 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 margin (“margin”) contracts, POL contracts, POP contracts, fixed-fee component contracts, or a combination of these contractual arrangements. “See Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” for a detailed description of these contractual arrangements. Under any of these gathering and processing arrangements, we may earn a fee for the services performed, or 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.

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

Recent Developments

Simplification of Corporate Structure. On October 21, 2018, we, ENLK, the General Partner, the managing member of ENLC, and NOLA Merger Sub, LLC, a wholly-owned subsidiary of ENLC (“NOLA Merger Sub”), entered into a definitive agreement and plan of merger (the “Merger Agreement”) pursuant to which, subject to the satisfaction or waiver of certain conditions in the Merger Agreement, NOLA Merger Sub will merge with and into ENLK (the “Merger”), with ENLK continuing as the surviving entity and a subsidiary of ENLC. The Merger and the other transactions contemplated by the Merger Agreement and the preferred restructuring agreement entered into concurrently with the Merger Agreement (the “Merger Transactions”) are expected to close in the first quarter of 2019, subject to obtaining ENLK unitholder approval,

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customary regulatory approvals, and other customary closing conditions. See“Item 1. Financial Statements—Note 15—Subsequent Event” for more information regarding this transaction.

Strategic Partner Update.On July 18, 2018, subsidiaries of Devon closed a transaction to sell all of their equity interests in ENLK, ENLC, and ENLC’s managing member to GIP. See “Item 1. Financial Statements—Note 1—General” for more information regarding the GIP Transaction.

Cajun-Sibon Pipeline. We commenced an 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 will increase throughput capacity from 130,000 bbls/d to 185,000 bbls/d. We expect Cajun-Sibon III to be operational during the second quarter of 2019.

Avenger Crude Oil Gathering System. We are constructing a new crude oil gathering system in the northern Delaware Basin called the Avenger crude oil gathering system (“Avenger”). Avenger is wholly owned by ENLK and 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 first half of 2019.

Central Oklahoma Plants. In December 2017, we commenced construction on an additional 200 MMcf/d gas processing plant, referred to as the “Thunderbird plant” to expand our Central Oklahoma processing capacity. We expect to begin operations on the Thunderbird plant during the first quarter of 2019.

Central Oklahoma Crude Oil Gathering Systems. In late March 2018, we completed construction of the first phase of a new crude oil gathering system that we refer to as “Black Coyote.” Black Coyote expands our operations in the core of the STACK play in Central Oklahoma and was built primarily on acreage dedicated from Devon, which is the main shipper on the system. In addition, we are further expanding our crude oil gathering operations in the STACK through the construction of the Redbud Crude Oil Gathering System (“Redbud”), which is supported by a contract with an existing large and active customer in the STACK. We commenced initial operations on Redbud during the third quarter of 2018. Both Black Coyote and Redbud are jointly owned by ENLK and ENLC through their respective ownership in EOGP.

Lobo Natural Gas Gathering and Processing Facilities. During the second quarter of 2018, we completed construction of an expansion to our Lobo II cryogenic gas processing plant, bringing total operational processing capacity at our Lobo facilities to 175 MMcf/d. We are further expanding our gas processing capacity at our Lobo facilities through the construction of the Lobo III cryogenic gas processing plant. We expect 100 MMcf/d of operational capacity at Lobo III to be completed during the fourth quarter of 2018 and an additional 100 MMcf/d of operational capacity to be completed during the first quarter of 2019.

Non-GAAP Financial Measures

We include the following non-GAAP financial measures: cash available for distribution and gross operating margin.

Cash Available for Distribution

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

We also calculate cash available for distribution as net income (loss) of ENLC less the net income (loss) attributable to ENLK, which is consolidated into ENLC’s net income (loss), plus ENLC's (i) share of distributions from ENLK, (ii) share of EOGP’s non-cash expenses, (iii) deferred income tax (benefit) expense, (iv) corporate goodwill impairment, if any, and (v) successful transaction costs, if any, less ENLC’s interest in maintenance capital expenditures of EOGP and less third-party non-controlling interest share of net income (loss) from consolidated affiliates.

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

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ENLC’s profitability and serves as an indicator of ENLC’s success in providing a cash return on its investments to its unitholders.

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, to maintain pipeline and equipment reliability, integrity, and safety, and to address environmental laws and regulations.

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

The following is a calculation of our cash available for distribution (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Distribution declared by ENLK associated with (1):
General partner interest	$	0.7		$	0.6		$	1.9		$	1.9
Incentive distribution rights	15.0			14.8			44.6			44.1
ENLK common units owned	34.5			34.5			103.6			103.6
Total share of ENLK distributions declared	50.2			49.9			150.1			149.6
Adjusted EBITDA of EOGP (2)	10.6			6.9			29.8			14.6
Transaction costs (3)	1.3			—			1.3			—
Total cash available	62.1			56.8			181.2			164.2
Uses of cash:
General and administrative expenses	(2.6		)	(1.1		)	(5.1		)	(3.7		)
Current income taxes (4)	(0.1		)	(0.1		)	(0.3		)	(0.3		)
Interest expense	(1.1		)	(0.7		)	(2.8		)	(1.7		)
Maintenance capital expenditures (5)	(0.2		)	(0.1		)	(0.4		)	(0.1		)
Total cash used	(4.0		)	(2.0		)	(8.6		)	(5.8		)
ENLC cash available for distribution	$	58.1		$	54.8		$	172.6		$	158.4

(1) Represents distributions declared by ENLK and to be paid to ENLC onNovember 13, 2018and distributions paid by ENLK to ENLC onAugust 13, 2018, May 14, 2018, November 13, 2017, August 11, 2017, and May 12, 2017.

(2) Represents ENLC’s interest in EOGP adjusted EBITDA, which is disbursed to ENLC by EOGP on a monthly basis. EOGP adjusted EBITDA is defined as earnings before depreciation and amortization and provision for income taxes and includes allocated expenses from ENLK.

(3) Represents transaction costs, primarily associated with costs incurred by ENLC related to the GIP Transaction.

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

(5) Represents ENLC’s interest in EOGP’s maintenance capital expenditures which is netted against the monthly disbursement of EOGP’s adjusted EBITDA per (2) above.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net income of ENLC	$	45.0		$	24.1		$	204.3		$	60.5
Less: Net income attributable to ENLK	43.2			25.5			202.2			73.2
Net income (loss) of ENLC excluding ENLK	1.8			(1.4		)	2.1			(12.7		)
ENLC's share of distributions from ENLK (1)	50.2			49.9			150.1			149.6
ENLC's interest in EOGP's non-cash expenses (2)	5.1			4.6			7.5			12.8
ENLC deferred income tax expense (3)	3.0			2.5			17.2			8.3
Non-controlling interest share of ENLK's net (income) loss (4)	(3.1		)	(0.9		)	(5.2		)	0.3
Other items (5)	1.1			0.1			0.9			0.1
ENLC cash available for distribution	$	58.1		$	54.8		$	172.6		$	158.4

(1) Represents distributions declared by ENLK and to be paid to ENLC onNovember 13, 2018and distributions paid by ENLK to ENLC on August 13, 2018, May 14, 2018, November 13, 2017, August 11, 2017, and May 12, 2017.

(2) Includes depreciation and amortization, unit-based compensation expense allocated to EOGP, gains and losses on sale of property, and non-cash revenue recognized upon receipt of secured term loan receivable related to contract restructuring (as discussed in “Item 1. Financial Statements—Note 2”).

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

(4) Represents NGP’s49.9%share of the Delaware Basin JV, Marathon Petroleum Corporation’s 50% share of the Ascension JV, and other minor non-controlling interests.

(5) Represents ENLC’s interest in EOGP’s maintenance capital expenditures (which is netted against the monthly disbursement of EOGP’s adjusted EBITDA), transaction costs, primarily associated with costs incurred by ENLC related to the GIP Transaction,and other non-cash items not included in cash available for distribution.

Gross Operating Margin

We define gross operating margin as revenues less cost of sales. 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 gather, process, transport, or market natural gas, NGLs, condensate, and crude oil for a 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.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Operating income	$	89.8	$	72.1	343.9		$	197.5
Add (deduct):
Operating expenses	114.7		102.1		337.3		308.8
General and administrative expenses	41.9		31.3		99.8		98.5
Loss on disposition of assets	—		1.1		1.3		0.8
Depreciation and amortization	146.7		136.3		430.1		407.1
Impairments	24.6		1.8		24.6		8.8
Gain on litigation settlement	—		—		—		(26.0		)
Gross operating margin	$	417.7	$	344.7	$	1,237.0	$	995.5

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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,
	2018			2017			2018			2017
Texas Segment
Revenues	$	385.6		$	347.2		$	1,035.5		$	997.2
Cost of sales	(222.0		)	(198.5		)	(562.2		)	(554.7		)
Total gross operating margin	$	163.6		$	148.7		$	473.3		$	442.5
Louisiana Segment
Revenues	$	1,010.5		$	738.5		$	2,592.6		$	2,021.0
Cost of sales	(923.6		)	(662.7		)	(2,333.3		)	(1,803.1		)
Total gross operating margin	$	86.9		$	75.8		$	259.3		$	217.9
Oklahoma Segment
Revenues	$	358.0		$	244.4		$	955.9		$	583.1
Cost of sales	(228.5		)	(148.2		)	(537.8		)	(335.9		)
Total gross operating margin	$	129.5		$	96.2		$	418.1		$	247.2
Crude and Condensate Segment
Revenues	$	745.7		$	308.6		$	2,004.7		$	973.1
Cost of sales	(702.6		)	(279.1		)	(1,898.3		)	(884.1		)
Total gross operating margin	$	43.1		$	29.5		$	106.4		$	89.0
Corporate Segment
Revenues	$	(385.5	)	$	(240.8	)	$	(948.0	)	$	(591.0	)
Cost of sales	380.1			235.3			927.9			589.9
Total gross operating margin	$	(5.4	)	$	(5.5	)	$	(20.1	)	$	(1.1	)
Total
Revenues	$	2,114.3		$	1,397.9		$	5,640.7		$	3,983.4
Cost of sales	(1,696.6		)	(1,053.2		)	(4,403.7		)	(2,987.9		)
Total gross operating margin	$	417.7		$	344.7		$	1,237.0		$	995.5
Midstream Volumes:
Texas Segment
Gathering and Transportation (MMBtu/d)	2,267,300			2,251,700			2,237,900			2,265,900
Processing (MMBtu/d)	1,310,800			1,194,300			1,263,100			1,178,800
Louisiana Segment
Gathering and Transportation (MMBtu/d)	2,273,700			2,009,300			2,197,100			1,960,300
Processing (MMBtu/d)	429,200			443,400			422,200			452,500
NGL Fractionation (Gals/d)	6,545,100			5,814,800			6,457,000			5,630,600
Oklahoma Segment
Gathering and Transportation (MMBtu/d)	1,259,700			889,200			1,181,800			787,400
Processing (MMBtu/d)	1,239,000			872,200			1,170,300			753,500
Crude and Condensate Segment
Crude Oil Handling (Bbls/d)	166,400			95,700			147,700			104,500
Brine Disposal (Bbls/d)	3,300			4,800			3,200			4,700

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Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

Gross Operating Margin. Gross operating margin was $417.7 million for the three months ended September 30, 2018 compared to $344.7 million for the three months ended September 30, 2017, an increase of $73.0 million, or 21.2%, due to the following:

• Texas Segment. Gross operating margin in the Texas segment increased$14.9 million, which was due to a $10.9 million increase from our Permian Basin processing assets as a result of higher volumes from continued development by our customers and a $4.0 million increase associated with our Bridgeport gathering and processing volumes due to rate increases and volumes from new Devon wells not included under Devon’s MVC. Gross operating margin for the remainder of our North Texas assets was flat quarter over quarter despite volume declines because the corresponding revenue decline was offset by an increase in revenue earned from MVCs (as discussed in more detail below). For the three months ended September 30, 2018, the shortfall revenue from Devon-related MVCs was $22.1 million compared to $15.9 million for the three months ended September 30, 2017.

• Louisiana Segment. Gross operating margin in the Louisiana segment increased$11.1 million, which was due to an increase from our NGL transmission and fractionation assets as a result of higher volumes received from our Permian Basin and Oklahoma assets.

• Oklahoma Segment. Gross operating margin in the Oklahoma segment increased$33.3 million, which was primarily due to higher volumes from continued development by our customers. For the three months ended September 30, 2018, there was no shortfall revenue from Devon-related MVCs compared to $4.0 million for the three months ended September 30, 2017.

• Crude and Condensate Segment. Gross operating margin in the Crude and Condensate segment increased$13.6 million, which was partially due to a $5.8 million increase from our ORV assets due to higher condensate stabilization volumes and improved margins from contract renegotiations. In addition, there was a $5.8 million increase from our Midland Basin crude business as a result of increased trucked volumes, higher trucking fees, and higher volumes due to continued expansion of our customer base on the Greater Chickadee gathering system.

• Corporate Segment. Gross operating margin in the Corporate segmentincreased$0.1 million, which was due to the changes in fair value of our commodity swaps between the periods.For the three months endedSeptember 30, 2018, there were realized losses of $4.6 million in addition to unrealized losses of $0.8 million.For the three months endedSeptember 30, 2017, there were realized losses of $2.2 million in addition to unrealized losses of $3.3 million.

Certain gathering and processing agreements in our Texas, Oklahoma, and Crude and Condensate segments provide for quarterly or annual MVCs, including MVCs from Devon from certain of our Barnett Shale assets in North Texas and our Cana gathering and processing assets in Oklahoma. Under these agreements, our customers agree to ship and/or process a minimum volume of 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 MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods.

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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, 2018
Midstream services	$	17.7	$	—	$	2.1	$	19.8
Midstream services—related parties	4.4		—		0.6		5.0
Total	$	22.1	$	—	$	2.7	$	24.8
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

On January 1, 2019, certain MVCs related to gathering and processing agreements with Devon for operations in the Texas and Oklahoma segments will expire. These MVCs generated$22.1 million and $19.6 millionin shortfall revenue for the three months endedSeptember 30, 2018 and 2017, respectively. Additionally, on July 31, 2019, an MVC related to a transportation services agreement with Devon for operations in the Crude and Condensate segment will expire. This MVC generated$2.7 millionand$3.1 millionin shortfall revenue for the three months endedSeptember 30, 2018and2017, respectively.

Operating Expenses. Operating expenses were $114.7 million for the three months ended September 30, 2018 compared to $102.1 million for the three months ended September 30, 2017, an increase of $12.6 million, or 12.3%. The primary contributors to the total increase by segment were as follows (in millions):

	Three Months Ended September 30,				Change
	2018		2017		$			%
Texas Segment	$	44.7	$	41.1	$	3.6		8.8	%
Louisiana Segment	28.7		24.8		3.9			15.7	%
Oklahoma Segment	22.5		17.1		5.4			31.6	%
Crude and Condensate Segment	18.8		19.1		(0.3		)	(1.6	)%
Total	$	114.7	$	102.1	$	12.6		12.3	%

• Texas Segment. Operating expenses in the Texas segmentincreased$3.6 millionprimarily due to expanded operations and higher utilities expense in the Permian Basin.

• Louisiana Segment. Operating expenses in the Louisiana segmentincreased$3.9 millionprimarily due to increased utilities, operational fees and services, and materials and supplies expenses as a result of higher volumes across our Louisiana assets.

• Oklahoma Segment. Operating expenses in the Oklahoma segment increased$5.4 million primarily due to increased labor and benefits expenses due to increased headcount, as well as increases in materials and supplies, utilities, operational fees and services, treater rentals, and compression expenses as a result of expanded operations on our Oklahoma assets.

• Crude and Condensate Segment. Operating expenses in the Crude and Condensate segmentdecreased$0.3 millionprimarily due to decreases in third-party transportation charges.

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General and Administrative Expenses. General and administrative expenses were$41.9 millionfor the three months endedSeptember 30, 2018compared to$31.3 millionfor the three months endedSeptember 30, 2017,an increaseof$10.6 million, or33.9%. The primary contributors to the increase were as follows:

• Unit-based compensation expense increased $4.5 million due to accelerated vestings related to the GIP Transaction and an organizational realignment in the third quarter of 2018.

• Salaries and wages expense increased $2.7 million due to severance expense related to an organizational realignment in the third quarter of 2018.

• Transaction costs increased $2.8 million due to costs we incurred related to the GIP Transaction.

Depreciation and Amortization. Depreciation and amortization expenses were $146.7 million for the three months endedSeptember 30, 2018 compared to$136.3 million for the three months ended September 30, 2017, an increase of $10.4 million, or7.6%. This increase was primarily due to increased depreciation expense of $4.5 million and $1.5 million from completed projects in Central Oklahoma and the Permian Basin, respectively, and accelerated depreciation expense due to a change in the useful lives of certain underutilized assets in our Louisiana segment of $3.3 million.

Impairments. For the three months endedSeptember 30, 2018, we recognized impairments of property and equipment of$24.6 million related to certain non-core pipeline assets, because the carrying values were no longer recoverable.We recognized impairment expense for the three months endedSeptember 30, 2017 of $1.8 millionrelated to the carrying values of rights-of-way that we are no longer using and a brine disposal well that was abandoned.

Interest Expense. Interest expense was $45.2 million for the three months ended September 30, 2018 compared to $49.6 millionfor the three months ended September 30, 2017, a decrease of $4.4 million, or 8.9%. Interest expense consisted of the following (in millions):

	Three Months Ended September 30,
	2018			2017
ENLK senior notes	$	40.0		$	40.0
ENLK Credit Facility	6.9			2.5
ENLC Credit Facility	1.0			0.6
Capitalized interest	(2.3		)	(1.1		)
Amortization of debt issue costs and net discounts	0.9			7.5
Other	(1.3		)	0.1
Total	$	45.2		$	49.6

Net Income (Loss) Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $37.3 million for the three months ended September 30, 2018 compared to net income of $17.9 million for the three months ended September 30, 2017, an increase of $19.4 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, 2018 Compared to Nine Months Ended September 30, 2017

Gross Operating Margin. Gross operating margin was$1,237.0 million for the nine months ended September 30, 2018 compared to $995.5 million for the nine months ended September 30, 2017, an increase of $241.5 million, or 24.3%, due to the following:

• Texas Segment. Gross operating margin in the Texas segmentincreased$30.8 million, which was primarily due to a $29.9 million increase from our Permian Basin processing assets as a result of higher volumes due to continued development by our customers. Gross operating margin for our North Texas assets was relatively flat quarter over quarter despite volume declines because of increased revenue earned from MVCs (as discussed in more detail below). For the nine months ended September 30, 2018, the shortfall revenue from Devon-related MVCs was $61.1 million compared to $42.1 million for the nine months ended September 30, 2017.

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• Louisiana Segment. Gross operating margin in the Louisiana segmentincreased $41.4 million, which was primarily due to a $38.4 million increase in our NGL transmission and fractionation gross operating margin due to additional NGL volumes received from our Oklahoma and Permian Basin assets and fees earned from the start-up of our Ascension JV assets in April 2017, as well as a $3.0 million increase from our Louisiana gas business as a result of higher volumes.

• Oklahoma Segment. Gross operating margin in the Oklahoma segmentincreased$170.9 million, which was primarily due to a $125.4 million increase from higher volumes as a result of continued development by our customers. In addition, during the nine months ended September 30, 2018, we restructured a contract with a customer, which resulted in the recognition of $45.5 million in revenue for the nine months ended September 30, 2018 (as discussed in “Item 1. Financial Statements—Note 2”). For the nine months ended September 30, 2018, the shortfall revenue from Devon-related MVCs was $1.2 million compared to $12.0 million for the nine months ended September 30, 2017.

• Crude and Condensate Segment. Gross operating margin in the Crude and Condensate segmentincreased$17.4 million, which was partially due to a $7.3 million increase from our ORV assets due to higher condensate stabilization volumes and improved margins from contract renegotiations. In addition, there was an $8.6 million increase from our Midland Basin crude business as a result of increased trucking volumes, higher trucking fees, and higher volumes due to continued expansion of our customer base on the Greater Chickadee gathering system.

• Corporate Segment. Gross operating margin in the Corporate segmentdecreased$19.0 milliondue to the changes in fair value of our commodity swaps between the periods. For the nine months ended September 30, 2018, there were realized losses of $5.3 million in addition to unrealized losses of $14.8 million. For the nine months ended September 30, 2017, there were realized losses of $4.9 millionwere partially offset byunrealized gains of $3.8 million.

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

	Texas		Oklahoma		Crude and Condensate		Total
Nine Months Ended
September 30, 2018
Midstream services (1)	$	17.8	$	52.7	$	2.1	$	72.6
Midstream services—related parties	43.3		1.2		6.3		50.8
Total	$	61.1	$	53.9	$	8.4	$	123.4
September 30, 2017
Midstream services	$	0.8	$	11.1	$	—	$	11.9
Midstream services—related parties	42.1		12.0		5.9		60.0
Total	$	42.9	$	23.1	$	5.9	$	71.9

(1) We restructured a natural gas gathering and processing contract that contained MVCs. As a result, we recognized$45.5 millionof midstream services revenue in the Oklahoma segment for theninemonths endedSeptember 30, 2018. For more information, see “Item 1. Financial Statements—Note 2.”

On January 1, 2019, certain MVCs related to gathering and processing agreements with Devon for operations in the Texas and Oklahoma segments will expire. These MVCs generated$62.3 million and $53.7 millionin shortfall revenue for thenine months ended September 30, 2018 and 2017, respectively. Additionally, on July 31, 2019, an MVC related to a transportation services agreement with Devon for operations in the Crude and Condensate segment will expire. This MVC generated$8.4 millionand$5.9 millionin shortfall revenue for theninemonths endedSeptember 30, 2018 and 2017, respectively.

In May 2018, we restructured one of our natural gas gathering and processing contracts that included MVCs that were in effect through 2023. Prior to the contract restructuring, we expected$135.1 million in guaranteed future gross operating margin under the contract, generated from either revenue or reductions to cost of sales resulting from both gathering and processing fees as well as shortfall revenue under the MVCs. As a result of the contract restructuring, all MVC provisions were removed from the contract, and we and the counterparty entered into additional agreements pursuant to which: (i) the counterparty made a$19.7 million payment to us on the date of the contract restructuring to satisfy MVC revenue earned up to the date of the contract restructuring; (ii) the counterparty entered into a second lien secured term loan under which the counterparty will pay

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us$58.0 millionin principal payments in various installments ending in May 2023, with interest accruing on the loan balance at8.0%per annum beginning in 2020; and (iii) the counterparty granted to us a1.0%term overriding royalty interest through June 2034 in each well located on leasehold interests of the counterparty and connected to the gas gathering system that we operate. As a result of the contract restructuring and in accordance with ASC 606, we recognized$45.5 millionof midstream services revenue, which primarily represents the discounted present value of the second lien secured term loan receivable, in the Oklahoma segment in the second quarter of 2018. Pursuant to the contract restructuring, the terms of the restructured contract, other than the MVCs, are the same as the original contract, and we expect to continue recognizing gathering and processing fees on volumes delivered by the customer.

Operating Expenses. Operating expenses were $337.3 million for the nine months ended September 30, 2018 compared to $308.8 million for the nine months ended September 30, 2017, an increase of $28.5 million, or 9.2%. The primary contributors to the increase by segment were as follows (in millions):

	Nine Months Ended September 30,				Change
	2018		2017		$			%
Texas Segment	$	134.7	$	127.9	$	6.8		5.3	%
Louisiana Segment	82.3		74.8		7.5			10.0	%
Oklahoma Segment	64.0		45.9		18.1			39.4	%
Crude and Condensate Segment	56.3		60.2		(3.9		)	(6.5	)%
Total	$	337.3	$	308.8	$	28.5		9.2	%

• Texas Segment. Operating expenses in the Texas segmentincreased$6.8 millionprimarily due to expanded operations and higher utilities expense in the Permian Basin.

• Louisiana Segment. Operating expenses in the Louisiana segmentincreased$7.5 millionprimarily due to increased utilities, operational fees and services, labor and benefits charges, and materials and supplies expenses as a result of the start-up of the Ascension JV in April 2017 and higher volumes across our Louisiana assets.

• Oklahoma Segment. Operating expenses in the Oklahoma segmentincreased$18.1 million primarily due to increased labor and benefits expenses due to increased headcount, as well as an increase in materials and supplies, operational fees and services, treater rentals, ad valorem tax, and compression expenses as a result of expanded operations.

• Crude and Condensate Segment. Operating expenses in the Crude and Condensate segmentdecreased$3.9 millionprimarily due to decreases in third-party transportation charges.

Depreciation and Amortization. Depreciation and amortization expenses were $430.1 million for the nine months ended September 30, 2018 compared to $407.1 million for the nine months ended September 30, 2017, an increase of $23.0 million, or 5.6%. Thisincreasewas primarily due to increased depreciation expense of $17.7 million and $3.7 million from completed projects in Central Oklahoma and the Permian Basin, respectively, and accelerated depreciation expense due to a change in the useful lives of certain underutilized assets in our Louisiana segment of $3.3 million.

Impairments. For the nine months ended September 30, 2018, we recognized impairments of property and equipment of $24.6 million related to certain non-core pipeline assets, because the carrying values were no longer recoverable.We recognized impairment expense for theninemonths endedSeptember 30, 2017 of $8.8 millionrelated to the carrying values of rights-of-way that we are no longer using and a brine disposal well that was abandoned.

Gain on Litigation Settlement. We settled a lawsuit in 2017 and recognized a gain on litigation settlement of$26.0 millionfor theninemonths endedSeptember 30, 2017.

Gain on Extinguishment of Debt. We recognized a gain on extinguishment of debt of $9.0 million for theninemonths endedSeptember 30, 2017 due to the redemption of $162.5 million in aggregate principal amount of ENLK’s 7.125% senior unsecured notes due 2022.

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Interest Expense. Interest expense was $134.3 million for the nine months ended September 30, 2018 compared to $142.2 million for the nine months ended September 30, 2017, a decrease of $7.9 million, or 5.6%. Interest expense consisted of the following (in millions):

	Nine Months Ended September 30,
	2018			2017
ENLK senior notes	$	120.0		$	115.0
ENLK Credit Facility	15.2			8.4
ENLC Credit Facility	2.6			1.5
Capitalized interest	(5.2		)	(5.1		)
Amortization of debt issue cost and net discounts	3.4			21.9
Other	(1.7		)	0.5
Total	$	134.3		$	142.2

Income (Loss) from Unconsolidated Affiliate Investments. Income from unconsolidated affiliate investments was $11.7 millionfor theninemonths endedSeptember 30, 2018compared to $5.0 millionfor theninemonths endedSeptember 30, 2017, an increase of $6.7 million. The increasewas primarily due to additional income of $5.5 million from our GCF investment as a result of higher fractionation revenues and lower operating expenses and a $3.4 million loss on the sale of our HEP investment for the nine months ended September 30, 2017. These increases were offset by a$2.2 milliondecrease in income from our Cedar Cove JV for the nine months ended September 30, 2018.

Income Tax Benefit (Provision). Income tax expense was $17.3 million for the nine months ended September 30, 2018 compared to $9.3 million for the nine months ended September 30, 2017, an increase of $8.0 million. The increase in income tax expense was primarily attributable to higher taxable income between periods, partially offset by a decrease in our statutory federal tax rate. See “Item 1. Financial Statements—Note 6” for additional information.

Net Income (Loss) Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $156.2 million for the nine months ended September 30, 2018 compared to net income of $50.3 million for the nine months ended September 30, 2017, an increase of $105.9 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.

Critical Accounting Policies

Information regarding our critical accounting policies is included in Item 7 of our Annual Report on Form 10-K for the year endedDecember 31, 2017, except for our critical accounting policy on revenue recognition, which changed as a result of the adoption of ASC 606 on January 1, 2018. See “Item 1. Financial Statements—Note 2” for information on our revenue recognition accounting policy.

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Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $539.0 million for the nine months ended September 30, 2018 compared to $528.4 million for the nine months ended September 30, 2017. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):

	Nine Months Ended September 30,
	2018			2017
Operating cash flows before working capital	$	681.8		$	531.7
Changes in working capital	(142.8		)	(3.3		)

Operating cash flows before changes in working capitalincreased$150.1 millionfor the nine months ended September 30, 2018compared to the nine months endedSeptember 30, 2017primarily due to a$214.3 millionincrease in gross operating margin, excluding gains and losses on derivative activity and excluding non-cash revenue recognized from the restructuring of a contract (as discussed in “Item 1. Financial Statements—Note 2”). The increase in operating cash flows was partially offset by a$10.6 millionincrease in interest expense, excluding amortization of debt issue costs and net discounts, as well as a$26.0 milliongain on litigation settlement recognized for the nine months ended September 30, 2017. The remaining difference is due to higher cash paid for operating expenses and general and administrative expenses for the nine months ended September 30, 2018. The changes in working capital for theninemonths endedSeptember 30, 2018compared to theninemonths endedSeptember 30, 2017were 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 $633.0 million for the nine months endedSeptember 30, 2018, compared to $475.3 million for the nine months ended September 30, 2017. Our primary investing cash flows were as follows (in millions):

	Nine Months Ended September 30,
	2018			2017
Growth capital expenditures	$	(608.8	)	$	(641.1	)
Maintenance capital expenditures	(30.6		)	(21.4		)
Proceeds from sale of unconsolidated affiliate investment	—			189.7

Growth capital expenditures decreased$32.3 million for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017. The decreasewas primarily due to completion of capital expenditures in 2017 related to the Greater Chickadee crude oil gathering system in the Permian Basin and the Ascension JV assets in Louisiana, in addition to lower capital expenditure levels for our expansion projects in the Central Oklahoma assets compared to 2017. Increased capital expenditures related to our Avenger crude gathering system and the Lobo III gas processing plant in the Delaware Basin during 2018 partially offset the decreases in the Permian Basin, Louisiana, and Central Oklahoma.

We completed the sale of our ownership interest in HEP in March 2017 and received net proceeds of $189.7 million.

Cash Flows from Financing Activities. Net cash provided by financing activities$127.6 million for the nine months ended September 30, 2018 and $77.1 million for the nine months ended September 30, 2017. Our primary financing activities consisted of the following (in millions):

	Nine Months Ended September 30,
	2018			2017
Net borrowings (repayments) on the ENLK Credit Facility	$	765.0		$	(120.0	)
Net borrowings on the ENLC Credit Facility	26.8			46.2
ENLK unsecured senior notes borrowings, net of notes extinguished	—			331.6
Proceeds from issuance of ENLK common units	46.1			92.3
Proceeds from issuance of ENLK Series C Preferred Units	—			393.7
Contributions by non-controlling interests	73.4			46.2
Payment of installment payable for EOGP acquisition	(250.0		)	(250.0		)

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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 at a price to the public of 99.981% of their face value. The net proceeds of approximately $495.2 million were used to repay outstanding borrowings under the ENLK Credit Facility and for general partnership purposes. For the six months ended June 30, 2017, ENLK redeemed $162.5 million in aggregate principal amount of ENLK’s 7.125% senior unsecured notes due June 1, 2022 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 thenine months ended September 30, 2018, ENLK sold an aggregate of approximately2.6 millioncommon units under the 2017 EDA, generating proceeds of approximately$46.1 million. For thenine months ended September 30, 2017, ENLK sold an aggregate of approximately 5.3 millioncommon units under an equity distribution agreement entered into prior to the 2017 EDA, generating proceeds of$92.3 million.

In September 2017, ENLK issued 400,000 Series C Preferred Units for net proceeds of $393.7 million.

For the nine months ended September 30, 2018, contributions by non-controlling interests included $73.6 million from NGP to the Delaware Basin JV. For the nine months ended September 30, 2017, contributions by non-controlling interests included$43.9 million from NGP to the Delaware Basin JV, and $2.3 million from Marathon Petroleum Corporation to the Ascension JV. 

For theninemonths endedSeptember 30, 2018and2017, we made the final two $250.0 million payments under the installment payable obligation related to the EOGP acquisition.

Distributions to unitholders and non-controlling interests also represent a primary use of cash in financing activities. Total cash distributions made for the nine months ended September 30, 2018 and 2017 were as follows (in millions):

	Nine Months Ended September 30,
	2018		2017
Distributions to members	$	145.0	$	139.5
Distributions to non-controlling interests	379.3		306.9

Distributions to non-controlling interests included distributions paid to public unitholders of ENLK common units, Series B Preferred Units, and Series C Preferred Units, as well as distributions to NGP for its ownership in the Delaware Basin JV, and distributions to Marathon Petroleum Corporation for its ownership in the Ascension JV.

Beginning with the quarter ended September 30, 2017, Series B Preferred Unit distributions were payable quarterly in cash in 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) 0.0025 Series B Preferred Units per Series B Preferred Unit and (b) an amount equal to (i) the excess, if any, of the distributions that would have been payable had the Series B Preferred Units converted into common units for that quarter over the Cash Distribution Component, divided by (ii) the issue price of $15.00. The Series B Preferred Unit distributions paid in-kind in the form of additional Series B Preferred Units are non-cash distributions, and they are not reflected in our financing cash flows for the nine months ended September 30, 2018 and 2017.

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 the General Partner out of legally available funds for such purpose. The 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 of4.11%.

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.

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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 2018 capital expenditures, including capital contributions to our unconsolidated affiliate investments, to be as follows (in millions):

	Remainder of
	2018
Growth Capital Expenditures
Texas segment	$	38 - 58
Louisiana segment		10 - 30
Oklahoma segment (1)		105 - 145
Crude and Condensate segment		33 - 68
Corporate segment		2 - 2
Total growth capital expenditures	$	188 - 303
Less: Growth capital expenditures funded by joint venture partners (2)		(9 - 24)
Growth capital expenditures, attributable to ENLC	$	179 - 279
Maintenance Capital Expenditures	$	14 - 19

(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 Corporation to the Ascension JV.

Our primary capital projects for the remainder of 2018and for 2019 include the construction of the Thunderbird gas processing plant and the Redbud crude oil gathering system in Central Oklahoma and the Avenger crude oil gathering system and the Lobo III processing plant in the Delaware Basin. See “Recent Developments” for further details.

We expect to fund growth capital expenditures from the proceeds of borrowings under the ENLK Credit Facility, the ENLC Credit Facility, 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 2018, it is possible that not all of 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, 2018.

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Total Contractual Cash Obligations. A summary of contractual cash obligations as of September 30, 2018 is as follows (in millions):

	Payments Due by Period
	Total		Remainder 2018		2019		2020		2021		2022		Thereafter
Long-term debt obligations (1)	$	3,500.0	$	—	$	400.0	$	—	$	—	$	—	$	3,100.0
ENLK Credit Facility	765.0		—		—		765.0		—		—		—
ENLC Credit Facility	101.4		—		101.4		—		—		—		—
Interest payable on fixed long-term debt obligations	2,481.3		67.8		154.5		149.2		149.2		149.2		1,811.4
Capital lease obligations	3.1		0.4		1.5		1.2		—		—		—
Operating lease obligations	102.9		3.9		13.3		9.8		8.7		8.6		58.6
Purchase obligations	41.3		16.8		24.5		—		—		—		—
Delivery contract obligation	13.5		4.5		9.0		—		—		—		—
Pipeline capacity and deficiency agreements (2)	180.6		5.7		26.2		27.2		27.2		26.8		67.5
Inactive easement commitment (3)	10.0		—		—		—		—		10.0		—
Total contractual obligations	$	7,199.1	$	99.1	$	730.4	$	952.4	$	185.1	$	194.6	$	5,037.5

(1) $400.0 million in aggregate principal amount of ENLK’s 2.7% senior unsecured notes mature on April 1, 2019.

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

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

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 the ENLK Credit Facility and the ENLC Credit Facility is not reflected in the above table because such amounts depend on the outstanding balances and interest rates, which vary from time to time.

Our contractual cash obligations for the next twelve months are expected to be funded from cash flows generated from our operations, proceeds from ENLK common unit issuances under the 2017 EDA, asset sales, and borrowings under the ENLC Credit Facility and ENLK Credit Facility.

Indebtedness

The ENLK Credit Facility is a $1.5 billion unsecured revolving credit facility that matures on March 6, 2020 and includes a $500.0 million letter of credit subfacility. As of September 30, 2018, there were $9.3 millionin outstanding letters of credit and $765.0 million outstanding borrowings under the ENLK Credit Facility, leaving approximately $725.7 million available for future borrowing.

The ENLC Credit Facility is a $250.0 million revolving credit facility that matures on March 7, 2019 and includes a $125.0 million letter of credit subfacility. As of September 30, 2018, there were no outstanding letters of credit and $101.4 million in outstanding borrowings under the ENLC Credit Facility, leaving approximately $148.6 million available for future borrowing.

In addition, as of September 30, 2018, ENLK has $3.5 billion in aggregate principal amount of outstanding unsecured senior notes with $400.0 millionmaturing in April 2019 and the remaining amount maturing from 2024 to 2047.

See “Item 1. Financial Statements—Note 5” for more information on our outstanding debt instruments.

Recent Accounting Pronouncements

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

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Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements that are based on information currently available to management as well as management’s assumptions and beliefs. All statements, other than statements of historical fact, included in this Quarterly Report constitute forward-looking statements, including, but not limited to, statements identified by the words “forecast,” “may,” “believe,” “will,” “should,” “plan,” “predict,” “anticipate,” “intend,” “estimate,” “expect,” “continue,” and similar 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, Part II, “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, and in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year endedDecember 31, 2017may 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 CFTC to regulate certain markets for derivative products, including OTC derivatives. The CFTC has issued several new relevant regulations that mandate that certain derivatives products be subject to margin requirements, cleared at a clearinghouse, or executed on an exchange. While some of these rules have been finalized, some have not and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.

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

The legislation and 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 risks due to fluctuations in commodity prices. Approximately 90% of our gross operating margin for thenine months ended September 30, 2018was generated from arrangements with fee-based structures with minimal direct commodity price exposure.Our exposure to these 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.

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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.

2. 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 thenine months ended September 30, 2018, less than 2%of our contracts, based on gross operating margin, were under processing margin contracts.

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

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

For theninemonths ended September 30, 2018, approximately9%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 OTC derivative financial instruments with only certain well-capitalized counterparties which have been approved in accordance with our commodity risk management policy.

We have hedged our exposure to fluctuations in prices for natural gas, NGLs, crude oil, and 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.

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The following table sets forth certain information related to derivative instruments outstanding at September 30, 2018mitigating 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 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 2018 - June 2019	Ethane	559 (MBbls)	$0.5198/gal	Index	$	2.2
October 2018 - September 2019	Propane	776 (MBbls)	Index	$1.0464/gal	(7.0		)
October 2018 - September 2019	Normal Butane	343 (MBbls)	Index	$1.2588/gal	(2.9		)
October 2018 - September 2019	Natural Gasoline	162 (MBbls)	Index	$1.6408/gal	(1.2		)
October 2018 - October 2019	Natural Gas	54,468 (MMBtu/d)	Index	$2.2107/MMBtu	(1.0		)
October 2018 - December 2022	Crude and condensate	14,618 (MBbls)	Index	$68.69/bbl	(6.5		)
					$	(16.4	)

(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, 2018, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements, and other derivative instruments were a net fair value liability of $16.4 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 $10.4 million in the net fair value of these contracts as of September 30, 2018. 

Interest Rate Risk

We are exposed to interest rate risk from the ENLC Credit Facility and the ENLK Credit Facility. At September 30, 2018, the ENLC Credit Facility had $101.4 million in outstanding borrowings, and the ENLK Credit Facility had $765.0 million in outstanding borrowings. A 1% increase or decrease in interest rates would change the annualized interest expense for the ENLC Credit Facility and the ENLK Credit Facility by approximately $1.0 million and $7.7 million for the year, respectively.

We are not exposed to changes in interest rates with respect to ENLK’s senior unsecured notes due in 2019, 2024, 2025, 2026, 2044, 2045 or 2047 as these are fixed-rate obligations. The estimated fair value of ENLK’s senior unsecured notes was approximately$3,252.6 millionas ofSeptember 30, 2018, based on market prices of similar debt at September 30, 2018. Market risk is estimated as the potential decrease in fair value of our long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in an approximate $230.6 milliondecrease in fair value of ENLK’s senior unsecured notes at September 30, 2018.

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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, 2018), 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

Effective January 1, 2018, we adopted ASC 606. The adoption of this accounting standard had no impact on our operating income, results of operations, financial condition, or cash flows. While the adoption of ASC 606 did not materially affect our internal control over financial reporting, we did implement certain changes to our related revenue recognition control activities, including changes to our policies related to the revenue recognition model, training, ongoing 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 endedSeptember 30, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Except as set forth below, information about risk factors does not differ materially from that set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2017and in Part II, “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018.

Risks Related to the Merger Transactions

The Merger Transactions are subject to conditions and may not be consummated even if the required unitholder approvals are obtained, which may cause the market price of the ENLC common units to decline.

The Merger Transactions are subject to the satisfaction or waiver of certain conditions, including the approval of the Merger Agreement by the holders of a majority of the ENLK common units and the ENLK Series B Preferred Units, voting together as a single class (the “ENLK Voting Unitholders”). The Merger Agreement contains other conditions that, if not satisfied or waived, would result in the Merger Transactions not occurring, even though the ENLK Voting Unitholders may have approved the Merger Agreement. Satisfaction of some of these other conditions to the Merger Transactions is not entirely in the control of ENLK and ENLC. The closing conditions to the Merger Transactions may not be satisfied, and ENLK and ENLC may choose not to, or may be unable to, waive an unsatisfied condition, which may cause the Merger Transactions not to occur.

The Merger Agreement contains certain termination rights for both ENLK and ENLC, including, among others, (i) by the mutual written agreement of ENLK (duly authorized by the conflicts committee of the Board of Directors of the General Partner (the “ENLK Conflicts Committee”)) and ENLC (duly authorized by the Board of Directors of the managing member of ENLC); (ii) by either ENLK or ENLC, if (A) the Merger has not been consummated on or before June 30, 2019; or (B) the requisite approval of the ENLK Voting Unitholders of the Merger Agreement is not obtained; (iii) by ENLC, if (A) the Board of Directors of ENLK’s general partner (upon the recommendation of the ENLK Conflicts Committee) or the ENLK Conflicts Committee makes a Recommendation Change (as defined in the Merger Agreement) prior to the meeting of the ENLK Voting Unitholders to consider and vote on the approval of the Merger Agreement or (B) if under certain conditions, there has been a material breach by ENLK of any of its representations, warranties, or covenants set forth in the Merger Agreement that is not cured within 30 days of notice of such breach; and (iv) by ENLK, if (A) subject to certain conditions, ENLK has received a Superior Proposal (as defined in the Merger Agreement) and the Board of Directors of the General Partner (upon the recommendation of the ENLK Conflicts Committee) or the ENLK Conflicts Committee has determined in good faith that the failure to terminate the Merger Agreement would be inconsistent with its fiduciary duties, or (B) under certain conditions, there has been a material breach by ENLC of any of its representations, warranties, or covenants set forth in the Merger Agreement that is not cured within 30 days of notice of such breach. The Merger Agreement further provides that, upon termination of the Merger Agreement under certain circumstances, ENLK or ENLC, as applicable, may be required to reimburse the other party’s expenses up to $5 million, and, in certain circumstances, ENLK may be required to pay ENLC a termination fee equal to $55 million.

If the Merger Transactions do not occur for any reason or if there are significant delays in completing the Merger Transactions, ENLC’s business and financial results could be negatively affected and the market price of ENLC common units may decline.

ENLK and ENLC may incur substantial transaction-related costs in connection with the Merger Transactions.

ENLK and ENLC expect to incur nonrecurring transaction-related costs associated with completing the Merger Transactions. Nonrecurring transaction costs include, but are not limited to, fees paid to legal, financial, and accounting advisors, registration and regulatory filing fees, proxy solicitation costs, and printing costs.

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Failure to complete, or significant delays in completing, the Merger Transactions could negatively affect the trading price of ENLC’s common units and our future business and financial results.

Completion of the Merger Transactions is not assured and is subject to risks, including the risks that approval of the Merger Transactions by the ENLK Voting Unitholders or by any applicable governmental agencies or third parties is not obtained or that other closing conditions are not satisfied. If the Merger Transactions are not completed, or if there are significant delays in completing the Merger Transactions, the trading price of ENLC’s common units and our future business and financial results could be negatively affected, and we will be subject to several risks, including the following:

• ENLK and ENLC may be liable for damages to one another under the terms and conditions of the Merger Agreement;

• negative reactions from the financial markets, including declines in the price of ENLC’s common units due to the fact that the current price may reflect a market assumption that the Merger Transactions will be completed;

• having to pay certain significant costs relating to the Merger Transactions; and

• the attention of management may have been diverted to the Merger Transactions rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

We may not realize the benefits we expect from the Merger Transactions.

We believe that the Merger Transactions will, among other things, provide increased financial flexibility for execution of our strategic growth plan. However, our assessments and expectations regarding the anticipated benefits of the Merger Transactions may prove to be incorrect. Accordingly, there can be no assurance we will realize the anticipated benefits of the Merger Transactions.

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

During the three months ended September 30, 2018, we re-acquired ENLC common units from certain employees in order to 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
July 1, 2018 to July 31, 2018	72,553	$	15.32	—	—
August 1, 2018 to August 31, 2018	56,422	17.27		—	—
September 1, 2018 to September 30, 2018	2,434	16.75		—	—
Total	131,409	$	16.18	—	—

_________________

(1) The common units were not re-acquired pursuant to any repurchase plan or program.

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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, 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 our Registration Statement on Form S-4, file No. 333-192419).
3.3	—	First Amended and Restated Operating Agreement of EnLink Midstream, LLC, dated as of March 7, 2014 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated March 7, 2014, filed with the Commission on March 11, 2014, 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, 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, filed with the Commission on August 6, 2014, file No. 001-36336).
3.6	—	Second Amended and Restated Limited Liability Company Agreement of EnLink Midstream Manager, LLC, dated as of July 18, 2018 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated July 17, 2018, filed with the 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, 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, file No. 333-97779).
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).
3.12	—	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, file No. 001-36340).
3.13	—	Third Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to 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).
3.14	—	Ninth Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of September 21, 2017 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated September 21, 2017, filed with the Commission on September 21, 2017, file No. 001-36340).
3.15	—	Amendment No. 1 to Ninth Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of December 12, 2017 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated December 12, 2017, filed with the Commission on December 14, 2017, file No. 001-36340).
10.1	—	Second Amendment to Credit Agreement and Limited Consent, dated as of June 20, 2018, by and among EnLink Midstream, LLC, Bank of America, N.A., as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated June 20, 2018, filed with the Commission on June 25, 2018, file No. 001-36336).
10.2	—	Second Amendment to Credit Agreement and Limited Consent, dated as of June 20, 2018, by and among EnLink Midstream Partners, LP, Bank of America, N.A., as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated June 20, 2018, filed with the Commission on June 25, 2018, file No. 001-36336).
10.3	—	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated July 17, 2018, filed with the Commission on July 23, 2018, file No. 003-36336).
10.4	—	Support Agreement, dated as of October 21, 2018, by and among GIP III Stetson I, L.P., EnLink Midstream, LLC, Acacia Natural Gas Corp I., Inc., EnLink Midstream, Inc., and EnLink Midstream Partners, LP (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated October 21, 2018, filed with the Commission on October 22, 2018, file No. 001-36336).
10.5	—	Preferred Restructuring Agreement, dated as of October 21, 2018, by and among Enfield Holdings, L.P., TPG VII Management, LLC, WSEP Egypt Holdings, LP, WSIP Egypt Holdings, LP, EnLink Midstream, LLC, EnLink Midstream Manager, LLC, EnLink Midstream Partners, LP, and EnLink Midstream GP, LLC (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated October 21, 2018, filed with the Commission on October 22, 2018, file No. 001-36336).
31.1 *	—	Certification of the Principal Executive Officer.
31.2 *	—	Certification of the Principal Financial Officer.

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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, 2018, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, (ii) Consolidated Statements of Operations for the three and nine months ended September 30, 2018 and 2017, (iii) Consolidated Statements of Changes in Members’ Equity for the nine months ended September 30, 2018, (iv) Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and 2017, and (v) the Notes to Consolidated Financial Statements.

* Filed herewith.

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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/ ERIC D. BATCHELDER
		Eric D. Batchelder
		Executive Vice President and Chief Financial Officer
November 7, 2018

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EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Michael J. Garberding, certify that:

1. I have reviewed this quarterly report on Form 10-Q of EnLink Midstream, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 7, 2018	/s/ MICHAEL J. GARBERDING
	Michael J. Garberding
	President and Chief Executive Officer
	(principal executive officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Eric D. Batchelder, certify that:

1. I have reviewed this quarterly report on Form 10-Q of EnLink Midstream, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 7, 2018	/s/ ERIC D. BATCHELDER
	Eric D. Batchelder
	Chief Financial Officer
	(principal financial and accounting officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of EnLink Midstream, LLC (the “Registrant”) on Form 10-Q of EnLink Midstream, LLC for the quarter ended September 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned, Michael J. Garberding, Chief Executive Officer of EnLink Midstream Manager, LLC, and Eric D. Batchelder, Chief Financial Officer of EnLink Midstream Manager, LLC, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: November 7, 2018	/s/ MICHAEL J. GARBERDING
	Michael J. Garberding
	Chief Executive Officer
Date: November 7, 2018	/s/ ERIC D. BATCHELDER
	Eric D. Batchelder
	Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to the Registrant and will be retained by the Registrant and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report.

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 01, 2018
Entity Information [Abstract]
Document Type	10-Q
Document Fiscal Period Focus	Q3
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Amendment Flag	false
Entity Registrant Name	Enlink Midstream, LLC
Entity Central Index Key	0001592000
Entity Current Reporting Status	Yes
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		181,294,967

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Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 64.8	$ 31.2
Accounts receivable:
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively	198.0	50.1
Accrued revenue and other	817.2	576.6
Related party	0.7	102.8
Fair value of derivative assets	12.5	6.8
Natural gas and NGLs inventory, prepaid expenses, and other	155.1	41.2
Total current assets	1,248.3	808.7
Property and equipment, net of accumulated depreciation of $2,859.3 and $2,533.0, respectively	6,875.7	6,587.0
Intangible assets, net of accumulated amortization of $391.3 and $298.7, respectively	1,404.5	1,497.1
Goodwill	1,542.2	1,542.2
Investment in unconsolidated affiliates	84.5	89.4
Other assets, net	43.1	13.4
Total assets	11,198.3	10,537.8
Current liabilities:
Accounts payable and drafts payable	130.6	66.9
Accounts payable to related party	5.0	16.3
Accrued gas, NGLs, condensate, and crude oil purchases	656.9	476.1
Fair value of derivative liabilities	21.9	8.4
Installment payable, net of discount of $0.5 at December 31, 2017	0.0	249.5
Current maturities of long-term debt	500.9	0.0
Other current liabilities	261.4	222.9
Total current liabilities	1,576.7	1,040.1
Long-term debt	3,835.9	3,542.1
Asset retirement obligations	14.6	14.2
Other long-term liabilities	20.7	33.9
Deferred tax liability	361.8	346.2
Fair value of derivative liabilities	7.0	0.0
Redeemable non-controlling interest	6.2	4.6
Members’ equity:
Members’ equity (181,294,450 and 180,600,728 units issued and outstanding, respectively)	1,838.4	1,924.2
Accumulated other comprehensive loss	(2.0)	(2.0)
Non-controlling interest	3,539.0	3,634.5
Total members’ equity	5,375.4	5,556.7
Total liabilities and members’ equity	$ 11,198.3	$ 10,537.8

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
ASSETS
Allowance for bad debt	$ 0.3	$ 0.3
Property and equipment, accumulated depreciation	2,859.3	2,533.0
Intangible assets, accumulated amortization	391.3	298.7
Liabilities:
Current installment payable discount	$ 0.0	$ 0.5
Members’ equity:
Common units issued (in shares)	181,294,450	180,600,728
Common units outstanding (in shares)	181,294,450	180,600,728

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Consolidated Statements of Operations - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues:
Revenue from contracts with customers		$ 2,119.7		$ 5,660.8
Loss on derivative activity		(5.4)	$ (5.5)	(20.1)	$ (1.1)
Total revenues		2,114.3	1,397.9	5,640.7	3,983.4
Operating costs and expenses:
Cost of sales	[1]	1,696.6	1,053.2	4,403.7	2,987.9
Operating expenses		114.7	102.1	337.3	308.8
General and administrative		41.9	31.3	99.8	98.5
Loss on disposition of assets		0.0	1.1	1.3	0.8
Depreciation and amortization		146.7	136.3	430.1	407.1
Impairments		24.6	1.8	24.6	8.8
Gain on litigation settlement		0.0	0.0	0.0	(26.0)
Total operating costs and expenses		2,024.5	1,325.8	5,296.8	3,785.9
Operating income		89.8	72.1	343.9	197.5
Other income (expense):
Interest expense, net of interest income		(45.2)	(49.6)	(134.3)	(142.2)
Gain on extinguishment of debt		0.0	0.0	0.0	9.0
Income from unconsolidated affiliates		4.3	4.4	11.7	5.0
Other income		0.1	0.3	0.3	0.5
Total other expense		(40.8)	(44.9)	(122.3)	(127.7)
Income before non-controlling interest and income taxes		49.0	27.2	221.6	69.8
Income tax provision		(4.0)	(3.1)	(17.3)	(9.3)
Net income		45.0	24.1	204.3	60.5
Net income attributable to non-controlling interest		37.3	17.9	156.2	50.3
Net income attributable to ENLC		$ 7.7	$ 6.2	$ 48.1	$ 10.2
Net income attributable to ENLC per unit:
Basic common unit (in dollars per share)		$ 0.04	$ 0.03	$ 0.27	$ 0.06
Diluted common unit (in dollars per share)		$ 0.04	$ 0.03	$ 0.26	$ 0.06
Product sales
Revenues:
Revenue from contracts with customers		$ 1,832.2	$ 1,056.7	$ 4,766.5	$ 2,973.9
Product sales—related parties
Revenues:
Revenue from contracts with customers		10.2	35.3	41.0	107.3
Midstream services
Revenues:
Revenue from contracts with customers		241.5	136.4	476.1	395.7
Midstream services-related parties
Revenues:
Revenue from contracts with customers		$ 35.8	$ 175.0	$ 377.2	$ 507.6

[1] Includes related party cost of sales of $23.0 million and $47.3 million for the three months ended September 30, 2018 and 2017, respectively, and $103.8 million and $126.9 million for the nine months ended September 30, 2018 and 2017, respectively.

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Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Statement [Abstract]
Related party cost of sales	$ 23.0	$ 47.3	$ 103.8	$ 126.9

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Consolidated Statements of Comprehensive Income Statement - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income	$ 45.0	$ 24.1	$ 204.3	$ 60.5
Loss on designated cash flow hedge, net of tax benefit of $0.2 million for the nine months ended September 30, 2017	0.0	0.0	0.0	(2.0)
Comprehensive income	45.0	24.1	204.3	58.5
Comprehensive income attributable to non-controlling interest	37.3	17.9	156.2	48.7
Comprehensive income attributable to EnLink Midstream, LLC	$ 7.7	$ 6.2	$ 48.1	$ 9.8

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Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Loss on designated cash flow hedge, tax benefit	$ 0.0	$ 0.0	$ 0.0	$ 0.2

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Consolidated Statement of Changes in Members' Equity - 9 months ended Sep. 30, 2018 - USD ($) $ in Millions	Total	Common Units	Accumulated Other Comprehensive Loss	Non-Controlling Interest	Redeemable Non-Controlling Interest (Temporary Equity)
Member equity, beginning balance at Dec. 31, 2017	$ 5,556.7	$ 1,924.2	$ (2.0)	$ 3,634.5
Units outstanding, beginning balance (in shares) at Dec. 31, 2017	180,600,728	180,600,000
Increase (Decrease) in Members' Equity
Issuance of common units by ENLK	$ 46.1			46.1
Conversion of restricted units for common units, net of units withheld for taxes	(5.7)	$ (5.7)
Conversion of restricted units for common units, net of units withheld for taxes (in shares)		700,000
Non-controlling interest’s impact of conversion of restricted units	(5.6)			(5.6)
Unit-based compensation	32.3	$ 15.9		16.4
Change in equity due to issuance of units by ENLK	(0.2)	1.2		(1.4)
Contributions from non-controlling interests	73.4			73.4
Distributions	(524.3)	(145.0)		(379.3)
Fair value adjustment related to redeemable non-controlling interest	(1.4)	(0.3)		(1.1)	$ 1.4
Net income	204.1	48.1		156.0	0.2
Member equity, end balance at Sep. 30, 2018	$ 5,375.4	$ 1,838.4	$ (2.0)	3,539.0
Units outstanding, end balance (in shares) at Sep. 30, 2018	181,294,450	181,300,000
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2017					4.6
Increase (Decrease) in Temporary Equity
Fair value adjustment related to redeemable non-controlling interest	$ (1.4)	$ (0.3)		(1.1)	1.4
Net income	$ 204.1	$ 48.1		$ 156.0	0.2
Redeemable noncontrolling interest, ending balance at Sep. 30, 2018					$ 6.2

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities:
Net income	$ 204.3	$ 60.5
Adjustments to reconcile net income to net cash provided by operating activities:
Impairments	24.6	8.8
Depreciation and amortization	430.1	407.1
Non-cash unit-based compensation	31.8	38.9
Loss on derivatives recognized in net income	20.1	1.1
Gain on extinguishment of debt	0.0	(9.0)
Cash settlements on derivatives	(4.3)	(5.9)
Amortization of debt issue costs, net discount (premium) of notes and installment payable	3.4	21.8
Distribution of earnings from unconsolidated affiliates	14.0	4.1
Income from unconsolidated affiliates	(11.7)	(5.0)
Non-cash revenue from contract restructuring	(45.5)	0.0
Other operating activities	15.0	9.3
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
Accounts receivable, accrued revenue, and other	(292.2)	(56.7)
Natural gas and NGLs inventory, prepaid expenses, and other	(93.0)	(48.4)
Accounts payable, accrued gas and crude oil purchases, and other accrued liabilities	242.4	101.8
Net cash provided by operating activities	539.0	528.4
Cash flows from investing activities:
Additions to property and equipment	(639.4)	(662.5)
Proceeds from sale of unconsolidated affiliate investment	0.0	189.7
Investment in unconsolidated affiliates	(0.1)	(11.8)
Distribution from unconsolidated affiliates in excess of earnings	2.7	7.3
Other investing activities	3.8	2.0
Net cash used in investing activities	(633.0)	(475.3)
Cash flows from financing activities:
Proceeds from borrowings	2,011.8	2,213.4
Payments on borrowings	(1,220.0)	(1,955.6)
Payment of installment payable for EOGP acquisition	(250.0)	(250.0)
Debt financing costs	0.0	(5.5)
Conversion of restricted units, net of units withheld for taxes	(5.7)	(5.0)
Conversion of ENLK's restricted units, net of units withheld for taxes	(5.6)	(5.2)
Proceeds from issuance of ENLK common units	46.1	92.3
Distribution to members	(145.0)	(139.5)
Distributions to non-controlling interests	(379.3)	(306.9)
Proceeds from issuance of ENLK Series C Preferred Units	0.0	393.7
Contributions by non-controlling interests	73.4	46.2
Other financing activities	1.9	(0.8)
Net cash provided by financing activities	127.6	77.1
Net increase in cash and cash equivalents	33.6	130.2
Cash and cash equivalents, beginning of period	31.2	11.7
Cash and cash equivalents, end of period	64.8	141.9
Supplemental disclosures of cash flow information:
Cash paid for interest	108.8	94.7
Cash paid for income taxes	0.6	4.1
Non-cash investing activities:
Non-cash accrual of property and equipment	13.3	(26.2)
Discounted secured term loan receivable from contract restructuring	$ 47.7	$ 0.0

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General

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General

(1) General

In this report, the terms “Company” or “Registrant,” as well as the terms “ENLC,” “our,” “we,” “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 the Operating Partnership and EOGP.

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

(a) Organization of Business

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 of equity interests in ENLK and EOGP. ENLK is a publicly traded limited partnership formed on July 12, 2002 and is engaged in the gathering, transmission, processing, and marketing of natural gas, NGLs, condensate, and crude oil, as well as providing crude oil, condensate, and brine services to producers. EOGP is a partnership held by us and ENLK and is engaged in the gathering and processing of natural gas. As ofSeptember 30, 2018, our direct and indirect interests in ENLK and EOGP consisted of the following:

• 88,528,451common units representing an aggregate21.4%limited partner interest in ENLK;

• 100%ownership interest in the General Partner of ENLK, which owns a0.4%general partner interest and all of the incentive distribution rights in ENLK; and

• 16.1%limited partner interest in EOGP

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.As a result of the transaction:

• GIP, through GIP Stetson I, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLK and the managing member of ENLC, which amount to100%of the outstanding limited liability company interests in the managing member of ENLC and approximately23.1%of the outstanding limited partner interests in ENLK at the closing date. Through this transaction, GIP acquired control of (i) the managing member of ENLC, (ii) ENLC, and (iii) ENLK, as a result of ENLC’s indirect ownership of ENLK’s general partner; and

• GIP, through GIP Stetson II, L.P., acquired all of the equity interests held by subsidiaries of Devon in ENLC, which amount to approximately63.8%of the outstanding limited liability company interests in ENLC at the closing date.

On October 21, 2018, ENLC, ENLK, the General Partner, the managing member of ENLC, and NOLA Merger Sub, LLC, a wholly-owned subsidiary of ENLC (“NOLA Merger Sub”), entered into a definitive agreement and plan of merger (the “Merger Agreement”) pursuant to which, subject to the satisfaction or waiver of certain conditions in the Merger Agreement, NOLA Merger Sub will merge with and into ENLK (the “Merger”), with ENLK continuing as the surviving entity and a subsidiary of ENLC. The Merger and the other transactions contemplated by the Merger Agreement and the preferred restructuring agreement entered into concurrently with the Merger Agreement (the “Merger Transactions”) are expected to close in the first quarter of 2019, subject to obtaining ENLK unitholder approval, customary regulatory approvals, and other customary closing conditions. SeeNote 15—Subsequent Eventfor more information regarding this transaction.

(b) Nature of Business

We primarily focus on providing midstream energy services, including:

• gathering, compressing, treating, processing, transporting, storing, and selling natural gas;

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

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

Our natural gas business includes connecting the wells of producers in our market areas to our gathering systems. Our gathering systems 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 that is transported to the processing plants by our own gathering systems or by 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, marketers, and pipelines. Our transmission pipelines receive natural gas from our gathering systems and from 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.

Our crude oil and condensate business includes the gathering and transmission of crude oil and condensate via pipelines, barges, rail, and trucks, in addition to condensate stabilization and brine disposal. We also purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate 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.

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Significant Accounting Policies

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Significant Accounting Policies

(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 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. All significant intercompany balances and transactions have been eliminated in consolidation.

(b) Revenue Recognition

We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. 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. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows:

• Product sales—Product sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above.

• Midstream services—Midstream services represent all other revenue generated as a result of performing our midstream services as outlined above.

Adoption of ASC 606

Effective January 1, 2018, we adopted ASC 606 using the modified retrospective method. ASC 606 replaces previous revenue recognition requirements in GAAP and requires 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 also requires 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.

Evaluation of Our Contractual Performance Obligations

In adopting ASC 606, we evaluated our contracts with customers that are within the scope of ASC 606. In accordance with the new revenue recognition framework introduced by ASC 606, we identified our performance obligations under our contracts with customers. These performance obligations include:

• promises to perform midstream services for our customers over a specified contractual term and/or for a specified volume of commodities; and

• promises to sell a specified volume of commodities to our customers.

The identification of performance obligations under our contracts requires a contract-by-contract evaluation of when control, including the economic benefit, of commodities transfers to and from us (if at all). This evaluation of control changed the way we account for certain transactions effective January 1, 2018, specifically those contracts in which there is both a commodity purchase and a midstream service. 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 do not consider these revenue-generating contracts for purposes of ASC 606. Based on the control determination, all contractually-stated fees that are deducted from our payments to producers or other suppliers for commodities purchased are reflected as a reduction in the cost of such commodity purchases. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating and recognize the fees received for satisfying them as midstream services revenues over time as 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 recognize these fees as midstream services revenues over time as we satisfy our performance obligations.

We also evaluate our contractual arrangements that contain a purchase and sale of commodities under the principal/agent provisions in ASC 606. For contracts where we possess control of the commodity and act as principal in the purchase and sale, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as an agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract.

Based on our review of our performance obligations in our contracts with customers, we changed the consolidated statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. For thethree and nine months ended September 30, 2018, the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately$179 million and $480 million, respectively, or 8% and 8%, respectively, compared to total revenues based on accounting prior to the adoption of ASC 606, with an equivalent net decrease in cost of sales. The change in total revenues as a result of the adoption of ASC 606 is made up of the following revenue line item changes (in millions):

	Increase (Decrease) in Revenue Due to ASC 606 Adoption
	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
Product sales	$	(71	)	$	(149	)
Product sales—related parties	(7		)	(53		)
Midstream services	(98		)	(251		)
Midstream services—related parties	(3		)	(27		)
Total	$	(179	)	$	(480	)

This change in accounting treatment had no impact on our operating income, net income, results of operations, financial condition, or cash flows.

Changes in Accounting Methodology for Certain Contracts

For NGL contracts in which we purchase raw mix NGLs and subsequently transport, fractionate, and market the NGLs, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which the fees we earned for our services were recorded as midstream services revenue on the consolidated statements of operations. As a result of the adoption of ASC 606, we determined that the control, including the economic benefit, of commodities has passed to us once the raw mix NGLs have been purchased from the customer. Therefore, we now consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the raw mix NGLs, rather than being recorded as midstream services revenue. Upon sale of the NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased.

For our crude oil and condensate service contracts in which we purchase the commodity, we utilize a similar approach under ASC 606 as outlined above for NGL contracts. This treatment is consistent with our accounting for crude oil and condensate service contracts prior to the adoption of ASC 606.

For our natural gas gathering and processing contracts in which we perform midstream services and also purchase the natural gas, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which all contractually-stated fees earned for our gathering and processing services were recorded as midstream services revenue on the statements of operations. As a result of the adoption of ASC 606, we must determine if economic control of the commodities has passed from the producer to us before or after we perform our services (if at all). Control is assessed on a contract-by-contract basis by analyzing each contract’s provisions, which can include provisions for: the customer to take its residue gas and/or NGLs in-kind; fixed or actual NGL or keep-whole recovery; commodity purchase prices at weighted average sales price or market index-based pricing; and various other contract-specific considerations. Based on this control assessment, our gathering and processing contracts fall into two primary categories:

• For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas passes to us when the natural gas is brought into our system, we do not consider these contracts to contain performance obligations for our services. As control of the natural gas passes to us prior to performing our gathering and processing services, we are, in effect, performing our services for our own benefit. Based on this control determination, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the natural gas, rather than being recorded as midstream services revenue. Upon sale of the residue gas and/or NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased.

• For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas does not pass to us until after the natural gas has been gathered and processed, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenues over time as we satisfy our performance obligations.

For midstream service contracts related to NGL, crude oil, or natural gas gathering and processing in which there is no commodity purchase or control of the commodity never passes to us and we simply earn a fee for our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenue over time as we satisfy our performance obligations. This treatment is consistent with our accounting for these contracts prior to the adoption of ASC 606.

For our natural gas transmission contracts, we determined that control of the natural gas never transfers to us and we simply earn a fee for our services. Therefore, we recognize these fees as midstream services revenue over time as we satisfy our performance obligations. This treatment is consistent with our accounting for natural gas transmission contracts prior to the adoption of ASC 606.

We also evaluate our commodity marketing contracts, under which we purchase and sell commodities in connection with our gas, NGL, and crude and condensate midstream services, pursuant to ASC 606, including the principal/agent provisions. For contracts in which we possess control of the commodity and act as principal in the purchase and sale of commodities, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. This treatment is consistent with our accounting for our commodity marketing contracts prior to the adoption of ASC 606.

Satisfaction of Performance Obligations and Recognition of Revenue

While ASC 606 alters the line item on which certain amounts are recorded on the consolidated statements of operations, ASC 606 did not significantly affect the timing of income and expense recognition on the consolidated statements of operations. Specifically, for our commodity sales contracts, we satisfy our performance obligations at the point in time at which the commodity transfers from us to the customer. This transfer pattern aligns with our billing methodology. Therefore, we recognize product sales revenue at the time the commodity is delivered and in the amount to which we have the right to invoice the customer, which is consistent with our accounting prior to the adoption of ASC 606. For our midstream service contracts that contain revenue-generating performance obligations, we satisfy our performance obligations over time as we perform the midstream service and as the customer receives the benefit of these services over the term of the contract. As permitted by ASC 606, we are utilizing the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice, since we have a right to consideration from our customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Accordingly, we continue to recognize revenue over time as our midstream services are performed. Therefore, ASC 606 does not significantly affect the timing of revenue and expense recognition on our consolidated statements of operations, and no cumulative effect adjustment was made to the balance of equity upon our adoption of ASC 606.

We generally accrue one month of sales and the related natural gas, NGL, condensate, and crude oil purchases and reverse these accruals when the sales and purchases are invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. We typically receive payment for invoiced amounts within one month, depending on the terms of the contract. We account for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

Minimum Volume Commitments and Firm Transportation Contracts

Certain gathering and processing agreements in our Texas, Oklahoma, and Crude and Condensate segments provide for quarterly or annual MVCs, including MVCs from Devon from certain of our Barnett Shale assets in North Texas and our Cana gathering and processing assets in Oklahoma. Under these agreements, our customers or suppliers (as “customers” and “suppliers” are determined per application of ASC 606) 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 customer is obligated to pay a contractually-determined fee based upon the shortfall between actual product volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer or supplier 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 MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, 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 expected impact to our consolidated statements of operations, resulting from either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below reflect 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. In addition, amounts in the table below 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.

2018 (remaining)	$	190.9
2019	237.1
2020	225.7
2021	82.3
2022	71.9
Thereafter	231.2
Total	$	1,039.1

In May 2018, we restructured one of our natural gas gathering and processing contracts that included MVCs that were in effect through 2023. Prior to the contract restructuring, we expected$135.1 million in guaranteed future gross operating margin under the contract, generated from either revenue or reductions to cost of sales resulting from both gathering and processing fees as well as shortfall revenue under the MVCs. As a result of the contract restructuring, all MVC provisions were removed from the contract, and we and the counterparty entered into additional agreements pursuant to which: (i) the counterparty made a$19.7 million payment to us on the date of the contract restructuring to satisfy MVC revenue earned up to the date of the contract restructuring; (ii) the counterparty entered into a second lien secured term loan under which the counterparty will pay us$58.0 millionin principal payments in various installments ending in May 2023, with interest accruing on the loan balance at8.0%per annum beginning in 2020; and (iii) the counterparty granted to us a1.0%term overriding royalty interest through June 2034 in each well located on leasehold interests of the counterparty and connected to the gas gathering system that we operate. As a result of the contract restructuring and in accordance with ASC 606, we recognized$45.5 millionof midstream services revenue, which primarily represents the discounted present value of the second lien secured term loan receivable, in the Oklahoma segment in the second quarter of 2018. Pursuant to the contract restructuring, the terms of the restructured contract, other than the MVCs, are the same as the original contract, and we expect to continue recognizing gathering and processing fees on volumes delivered by the customer.

Contributions in Aid of Construction

The adoption of ASC 606 also alters how we account for contributions in aid of construction (“CIAC”). CIAC payments are lump sum payments from third parties to reimburse us for capital expenditures related to the construction of our operating assets and, in most cases, the connection of these operating assets to the third party’s assets. CIAC payments can be paid to us prior to the commencement of construction activities, during construction, or after construction has been completed. Prior to adoption of ASC 606 and in accordance with ASC 980, Regulated Operations (“ASC 980”), and the FERC Uniform System of Accounts, we reduced the balance of the related property and equipment by the amount of CIAC payments received. In doing so, CIAC payments previously affected the consolidated statements of operations through reduced depreciation expense over the useful lives of the related property and equipment. Upon adoption of ASC 606, we initially recognize CIAC payments received from customers as deferred revenue, which will be subsequently amortized into revenue over the term of the underlying operational contract. For CIAC payments from noncustomers and for payments related to the construction of regulated operating assets, we continue to reduce the balance of the related property and equipment in accordance with ASC 980 and the FERC Uniform System of Accounts. This change in our CIAC accounting policy was not material to our financial statements for thethree and nine months ended September 30, 2018.

Disaggregation of Revenue and Presentation of Prior Periods

Based on the disclosure requirements of ASC 606, we are presenting revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. SeeNote 13—Segment Informationfor the revenue disaggregation information included in the segment information table for thethree and nine months ended September 30, 2018. As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for thethree and nine months ended September 30, 2018are presented to conform to ASC 606 accounting and disclosure requirements. Prior periods presented in the consolidated financial statements and accompanying notes were not restated in accordance with ASC 606.

(c) Accounting Standards to be Adopted in Future Periods

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842)—Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”), which establishes ASC Topic 842, Leases (“ASC 842”). Under ASC 842, lessees will need to recognize virtually all of their leases on the balance sheet by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASC 842 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those annual periods. We will adopt ASC 842 effective January 1, 2019. We are currently assessing the impact of adopting ASC 842 and are in the process of implementing a lease accounting software tool. This assessment includes the evaluation of our current lease contracts and the analysis of contracts that may contain lease components. We are electing to apply certain practical expedients that are 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. While we are still evaluating the complete population of lease contracts, we believe the adoption of ASC 842 will increase our asset and liability balances on the consolidated balance sheets by less than$100 milliondue 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 January 2018, the FASB issued ASU 2018-01, Leases (Topic 842)—Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 amends ASC 842 and provides an optional practical expedient to not evaluate under ASC 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in ASC 840, Leases. Under ASU 2018-01, an entity that elects this practical expedient should evaluate new or modified land easements under ASC 842 beginning at the date that the entity adopts ASC 842. We plan to utilize the practical expedient provided in ASU 2018-01 in conjunction with our adoption of ASC 842.

In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842)—Targeted Improvements (“ASU 2018-11”). ASU 2018-11 amends ASC 842 and allows entities to adopt the new leases standard using a modified retrospective approach. Under this new transition method, entities initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Additionally, an entity’s reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with current GAAP. We plan to utilize the optional transition method provided in ASU 2018-11 in conjunction with our adoption of ASC 842 in January 2019.

(d)    Property & Equipment

Impairment Review. In accordance with ASC 360, Property, Plant and Equipment, we evaluate long-lived assets of identifiable business activities 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 three and nine months ended September 30, 2018, we recognized impairments of property and equipment of $24.6 million related to certain non-core pipeline assets, because the carrying values were no longer recoverable.For thethree and nine months ended September 30, 2017, we recognized impairments of property and equipment of$1.8 million and $8.8 million, respectively, which related to the carrying values of rights-of-way that we are no longer using and an abandoned brine disposal well.

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Intangible Assets

9 Months Ended

Sep. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

(3) 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 from5 to 20 years.

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

	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Nine Months Ended September 30, 2018
Customer relationships, beginning of period	$	1,795.8	$	(298.7	)	$	1,497.1
Amortization expense	—		(92.6		)	(92.6		)
Customer relationships, end of period	$	1,795.8	$	(391.3	)	$	1,404.5

The weighted average amortization period is15.0 years. Amortization expense was $30.9 millionand$31.2 millionfor the three months endedSeptember 30, 2018and2017, respectively, and$92.6 millionand$96.2 millionfor theninemonths endedSeptember 30, 2018and2017, respectively.

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

2018 (remaining)	$	30.9
2019	123.7
2020	123.7
2021	123.7
2022	123.7
Thereafter	878.8
Total	$	1,404.5

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Related Party Transactions

9 Months Ended

Sep. 30, 2018

Related Party Transactions [Abstract]

Related Party Transactions

(4) Related Party Transactions

On July 18, 2018, subsidiaries of Devon sold all of their equity interests in ENLK, ENLC, and the managing member of ENLC to GIP. 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. SeeNote 1—Generalfor additional information regarding the GIP Transaction.Prior to July 18, 2018, revenues from transactions with Devon are included in “Product sales—related 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.

From July 1, 2018 to July 18, 2018 and January 1, 2018 to July 18, 2018, Devon accounted for 2.0% and 7.3%of our revenues, respectively, and for thethree and ninemonths endedSeptember 30, 2017, Devon accounted for15.0%and15.4%of our revenues, respectively. We had an accounts receivable balance related to transactions with Devon of $102.7 million at December 31, 2017. Additionally, we had an accounts payable balance related to transactions with Devon of $16.3 million at December 31, 2017.

For thethree and ninemonths endedSeptember 30, 2018, we recorded cost of sales of$11.3 millionand$33.8 million, respectively, and for thethree and ninemonths endedSeptember 30, 2017, we recorded cost of sales of$9.5 millionand$15.0 million, respectively, related to our 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 related to transactions with the Cedar Cove JV of$0.7 million at September 30, 2018. Additionally, we had an accounts payable balance related to transactions with the Cedar Cove JV of$5.0 million at September 30, 2018. The accounts receivable and payable balances related to transactions with the Cedar Cove JV were immaterial atDecember 31, 2017.

Management believes these transactions are executed on terms that are fair and reasonable to us. The amounts related to related party transactions are specified in the accompanying consolidated financial statements.

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Long-Term Debt

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Long-Term Debt

(5) Long-Term Debt

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

	September 30, 2018								December 31, 2017
	Outstanding Principal		Premium (Discount)			Long-Term Debt			Outstanding Principal		Premium (Discount)			Long-Term Debt
ENLK credit facility due 2020 (1)	$	765.0	$	—		$	765.0		$	—	$	—		$	—
ENLC credit facility due 2019 (2)	101.4		—			101.4			74.6		—			74.6
ENLK’s 2.70% Senior unsecured notes due 2019	400.0		(0.1		)	399.9			400.0		(0.1		)	399.9
ENLK’s 4.40% Senior unsecured notes due 2024	550.0		1.9			551.9			550.0		2.2			552.2
ENLK’s 4.15% Senior unsecured notes due 2025	750.0		(0.9		)	749.1			750.0		(1.0		)	749.0
ENLK’s 4.85% Senior unsecured notes due 2026	500.0		(0.5		)	499.5			500.0		(0.6		)	499.4
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		(6.2		)	443.8			450.0		(6.5		)	443.5
ENLK's 5.45% Senior unsecured notes due 2047	500.0		(0.1		)	499.9			500.0		(0.1		)	499.9
Debt classified as long-term, including current maturities of long-term debt	$	4,366.4	$	(6.1	)	4,360.3			$	3,574.6	$	(6.3	)	3,568.3
Debt issuance cost (3)						(23.5		)						(26.2		)
Less: Current maturities of long-term debt (4)						(500.9		)						—
Long-term debt, net of unamortized issuance cost						$	3,835.9							$	3,542.1

(1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was4.1%atSeptember 30, 2018.

(2) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 4.1% and 3.2% at September 30, 2018 and December 31, 2017, respectively.

(3) Net of amortization of $15.7 million and $12.9 million at September 30, 2018 and December 31, 2017, respectively.

(4) The outstanding balance, net of debt issuance costs, of the ENLC Credit Facility and ENLK’s2.70%senior unsecured notes as ofSeptember 30, 2018are classified as “Current maturities of long-term debt” on the consolidated balance sheet as the ENLC Credit Facility matures on March 7, 2019, and ENLK’s 2.70% senior unsecured notes mature on April 1, 2019.

ENLC Credit Facility

The ENLC Credit Facility is a $250.0 million revolving credit facility that matures on March 7, 2019 and includes a $125.0 million letter of credit subfacility. Our obligations under the ENLC Credit Facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 88,528,451 ENLK common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us, and (iii) any additional equity interests subsequently pledged as collateral under the ENLC Credit Facility.

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

Borrowings under the ENLC Credit Facility bear interest at our option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.75% to 2.50%) or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, 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.

On June 20, 2018, we amended the change of control provisions of the ENLC Credit Facility to, among other things, designate GIP as Qualifying Owners (as defined in the ENLC Credit Facility). At September 30, 2018, ENLC was in compliance and expects to be in compliance with the covenants in the ENLC Credit Facility through its maturity date.

As of September 30, 2018, there were no outstanding letters of credit and $101.4 million in outstanding borrowings under the ENLC Credit Facility, leaving approximately $148.6 million available for future borrowing.

ENLK Credit Facility

The ENLK Credit Facility is a $1.5 billion unsecured revolving credit facility that matures on March 6, 2020 and includes a $500.0 millionletter 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 millionand (2) subject to certain conditions and the consent of the requisite lenders, ontwo separate occasions, extend the maturity date of the ENLK Credit Facility by one yearon 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 to5.5 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 plus1.0%or the administrative agent’s prime rate) plus an applicable margin (ranging from0.0% to 0.75%). The applicable margins vary depending on ENLK’s credit rating. If ENLK breaches certain covenants governing the ENLK Credit Facility, amounts outstanding under the ENLK Credit Facility, if any, may become due and payable immediately.

On June 20, 2018, ENLK amended the change of control provisions of the ENLK Credit Facility to, among other things, designate GIP as Qualifying Owners (as defined in the ENLK Credit Facility). At September 30, 2018, ENLK was in compliance and expects to be in compliance with the covenants in the ENLK Credit Facility for at least the next twelve months.

As of September 30, 2018, there were $9.3 millionin outstanding letters of credit and $765.0 million outstanding borrowings under the ENLK Credit Facility, leaving approximately $725.7 million available for future borrowing.

All other material terms and conditions of the ENLC Credit Facility, the ENLK Credit Facility, and outstanding senior unsecured notes 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, 2017.

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Income Taxes

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

(6) 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,
	2018		2017		2018		2017
Current income tax provision	$	1.0	$	0.9	$	1.9	$	1.3
Deferred income tax provision	3.0		2.2		$	15.4	$	8.0
Total income tax provision	$	4.0	$	3.1	$	17.3	$	9.3

The following schedule reconciles total income tax expense 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,
	2018			2017			2018			2017
Expected income tax provision based on federal statutory rate (1)	$	2.4		$	3.3		$	13.7		$	6.8
State income taxes expense, net of federal tax benefit	0.3			0.2			1.6			0.5
Income tax expense (benefit) from ENLK	0.9			0.5			(0.2		)	0.7
Unit-based compensation	(0.9		)	—			0.6			2.3
Other	1.3			(0.9		)	1.6			(1.0		)
Total income tax provision	$	4.0		$	3.1		$	17.3		$	9.3

(1) The statutory federal tax rate for corporations was 21% at September 30, 2018 and 35% at September 30, 2017.

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Certain Provisions of the Partnership Agreement

9 Months Ended

Sep. 30, 2018

Partners' Capital [Abstract]

Certain Provisions of the Partnership Agreement

(7) Certain Provisions of the Partnership Agreement

(a) Issuance of ENLK Common Units

In August 2017, ENLK entered into 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 of the common units under the 2017 EDA and may at any time suspend solicitation and offers under the 2017 EDA.

For thenine months ended September 30, 2018, ENLK sold an aggregate of approximately2.6 millioncommon units under the 2017 EDA, generating proceeds of approximately$46.1 million(net of approximately$0.5 millionof commissions paid to the Sales Agents). ENLK used the net proceeds for general partnership purposes. As of September 30, 2018, approximately $518.8 millionin aggregate gross proceeds remains available to be issued under the 2017 EDA.

(b) ENLK Series B Preferred Units

Beginning with the quarter ended September 30, 2017, Series B Preferred Unit distributions are payable quarterlyin cash at an amount equal to$0.28125 per Series B Preferred Unit (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A)0.0025Series B Preferred Units per Series B Preferred Unit and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Series B Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the issue price of $15.00.

A summary of the distribution activity relating to the Series B Preferred Units during the nine months ended September 30, 2018 and 2017 is provided below:

Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2018
Fourth Quarter of 2017	413,658	$	16.0	February 13, 2018
First Quarter of 2018	416,657	$	16.2	May 14, 2018
Second Quarter of 2018	419,678	$	16.3	August 13, 2018
Third Quarter of 2018	422,720	$	16.4	November 13, 2018
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

(c) ENLK Series C Preferred Units

Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15^th day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15^th day of March, June, September, and December of each year, in each case, if and when declared by the General Partner out of legally available funds for such purpose. The distribution rate for the Series C Preferred Units is6.0%per annum, and ENLK distributed $12.0 million to holders of Series C Preferred Units during thenine months ended September 30, 2018.

(d) ENLK Common Unit Distributions

Unless restricted by the terms of the ENLK Credit Facility and/or the indentures governing ENLK’s senior unsecured notes, ENLK must make distributions of100%of available cash, as defined in its partnership agreement, within 45 daysfollowing the end of each quarter. Distributions of available cash 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 distributions with respect to (i) distributions on theSeries 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 incentive distribution rights in ENLK. 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 to13.0% of amounts ENLK distributes in excess of $0.25 per unit, 23.0% of the amounts ENLK distributes in excess of $0.3125 per unit, and 48.0% of amounts ENLK distributes in excess of $0.375 per unit.

A summary of ENLK’s distribution activity relating to the common units during theninemonths endedSeptember 30, 2018 and 2017 is provided below:

Declaration period	Distribution/unit		Date paid/payable
2018
Fourth Quarter of 2017	$	0.39	February 13, 2018
First Quarter of 2018	$	0.39	May 14, 2018
Second Quarter of 2018	$	0.39	August 13, 2018
Third Quarter of 2018	$	0.39	November 13, 2018
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

(e) Allocation of ENLK Income

Net income is allocated to the General Partner in an amount equal to its incentive distribution rights as described in section “(d) ENLK Common Unit Distributions” above. The General Partner’s share of net income consists of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units, and the percentage interest of ENLK’s net incomeadjusted 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,
	2018			2017			2018			2017
Income allocation for incentive distributions	$	15.0		$	14.8		$	44.6		$	44.1
Unit-based compensation attributable to ENLC’s restricted and performance units	(7.3		)	(4.2		)	(15.7		)	(16.9		)
General Partner share of net income	—			—			0.6			0.1
General Partner interest in net income	$	7.7		$	10.6		$	29.5		$	27.3

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Members' Equity

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Members' Equity

(8) Members' Equity

(a)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 unit for the periods presented (in millions, except per unit amounts):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
ENLC interest in net income	$	7.7		$	6.2		$	48.1		$	10.2
Distributed earnings allocated to:
Common units (1) (2)	$	49.1		$	46.0		$	145.0		$	138.0
Unvested restricted units (1) (2)	0.9			0.7			2.2			1.9
Total distributed earnings	$	50.0		$	46.7		$	147.2		$	139.9
Undistributed loss allocated to:
Common units	$	(41.5	)	$	(39.9	)	$	(97.6	)	$	(128.0	)
Unvested restricted units	(0.8		)	(0.6		)	(1.5		)	(1.7		)
Total undistributed loss	$	(42.3	)	$	(40.5	)	$	(99.1	)	$	(129.7	)
Net income allocated to:
Common units	$	7.6		$	6.1		$	47.4		$	10.0
Unvested restricted units	0.1			0.1			0.7			0.2
Total net income	$	7.7		$	6.2		$	48.1		$	10.2
Basic and diluted net income per unit:
Basic	$	0.04		$	0.03		$	0.27		$	0.06
Diluted	$	0.04		$	0.03		$	0.26		$	0.06

(1) For the three months ended September 30, 2018 and 2017, distributed earnings represent a declared distribution of $0.271 per unit payable on November 14, 2018 and a distribution of $0.255 per unit paid on November 14, 2017, respectively.

(2) For the nine months ended September 30, 2018, distributed earnings included a declared distribution of $0.271 per unit payable on November 14, 2018, $0.267 per unit paid on August 14, 2018, and $0.263 per unit paid on May 15, 2018. For the nine months ended September 30, 2017, distributed earnings included distributions of $0.255 per unit paid on November 14, 2017, $0.255 per unit paid on August 14, 2017, and $0.255 per unit paid on May 15, 2017.

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,
	2018	2017	2018	2017
Basic weighted average units outstanding:
Weighted average common units outstanding	181.2	180.6	181.1	180.4
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	181.2	180.6	181.1	180.4
Dilutive effect of non-vested restricted units	1.3	1.2	1.1	1.3
Total weighted average diluted common units outstanding	182.5	181.8	182.2	181.7

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) Distributions

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

Declaration period	Distribution/unit		Date paid/payable
2018
Fourth Quarter of 2017	$	0.259	February 14, 2018
First Quarter of 2018	$	0.263	May 15, 2018
Second Quarter 2018	$	0.267	August 14, 2018
Third Quarter 2018	$	0.271	November 14, 2018
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

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Investment in Unconsolidated Affiliates

9 Months Ended

Sep. 30, 2018

Equity Method Investments and Joint Ventures [Abstract]

Investment in Unconsolidated Affiliates

(9) Investment in Unconsolidated Affiliates

As of September 30, 2018, our unconsolidated investments consisted of a 38.75%ownership in GCF and an approximate30% ownership in the Cedar Cove 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,
	2018			2017			2018			2017
GCF
Distributions	$	5.3		$	3.5		$	16.4		$	10.6
Equity in income	$	4.6		$	4.5		$	14.0		$	8.5
HEP
Equity in loss (1)	$	—		$	—		$	—		$	(3.4	)
Cedar Cove JV
Contributions	$	—		$	1.5		$	0.1		$	11.8
Distributions	$	—		$	0.5		$	0.3		$	0.8
Equity in loss	$	(0.3	)	$	(0.1	)	$	(2.3	)	$	(0.1	)
Total
Contributions	$	—		$	1.5		$	0.1		$	11.8
Distributions	$	5.3		$	4.0		$	16.7		$	11.4
Equity in income (1)	$	4.3		$	4.4		$	11.7		$	5.0

(1) We sold our ownership interest in HEP during the first quarter of 2017, resulting in a loss of$3.4 million for the ninemonths ended September 30, 2017.

The following table shows the balances related to our investment in unconsolidated affiliates as ofSeptember 30, 2018 and December 31, 2017 (in millions):

	September 30, 2018		December 31, 2017
GCF	$	46.0	$	48.4
Cedar Cove JV	38.5		41.0
Total investment in unconsolidated affiliates	$	84.5	$	89.4

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Employee Incentive Plans

9 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Employee Incentive Plans

(10) Employee Incentive Plans

(a) Long-Term Incentive Plans

ENLC and ENLK each have similar unit-based compensation payment plans for officers and employees. ENLC grants unit-based awards under the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “2014 Plan”), and ENLK grants unit-based awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP 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 in the consolidated financial statements. Unit-based compensation cost is valued at fair value at the date of 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 ENLC’s officers and employees is recorded by us since ENLC has no substantial or managed operating activities other than its interests in ENLK and EOGP.

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,
	2018		2017		2018		2017
Cost of unit-based compensation charged to operating expense	$	5.2	$	2.8	$	9.5	$	10.4
Cost of unit-based compensation charged to general and administrative expense	11.9		7.4		22.3		28.5
Total unit-based compensation expense	$	17.1	$	10.2	$	31.8	$	38.9
Non-controlling interest in unit-based compensation	$	6.6	$	3.9	$	12.1	$	14.6
Amount of related income tax benefit recognized in net income (1)	$	2.2	$	2.4	$	4.1	$	9.1

(1) For the three and nine months ended September 30, 2018, the amount of related income tax benefit recognized in net income excluded $0.9 million of income tax benefit and $0.6 million of income tax expense, respectively, related to tax deficiencies recorded upon vesting of restricted units. For the nine months ended September 30, 2017, the amount of related income tax benefit recognized in net income excluded $2.3 million of income tax expense related to tax deficiencies recorded upon vesting of restricted units. There was no income tax expense or benefit related to tax deficiencies recorded upon vesting of restricted units for the three months ended September 30, 2017.

(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 ENLK common units on such date.A summary of the restricted incentive unit activity for thenine months ended September 30, 2018is provided below:

	Nine Months Ended September 30, 2018
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,980,224			$	15.81
Granted (1)	1,586,750			15.27
Vested (1)(2)	(813,290		)	19.78
Forfeited	(157,057		)	12.42
Non-vested, end of period	2,596,627			$	14.44
Aggregate intrinsic value, end of period (in millions)	$	48.4

(1) Restricted incentive units typically vest at the end of three years. In March 2018, ENLK granted 200,753restricted incentive units with a fair value of$3.0 millionto officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.

(2) Vested units included255,653units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for thethree and nine months ended September 30, 2018 and 2017 is provided below (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
EnLink Midstream Partners, LP Restricted Incentive Units:	2018		2017		2018		2017
Aggregate intrinsic value of units vested	$	3.7	$	0.6	$	12.8	$	16.3
Fair value of units vested	$	2.8	$	1.1	$	16.1	$	22.1

As of September 30, 2018, there was $22.2 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 2.0 years.

(c) EnLink Midstream Partners, LP Performance Units

The General Partner grants performance awards under the GP 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 total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the AMZ, excluding ENLC and ENLK, on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of ENLC’s and ENLK’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units ranges fromzero to 200% of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLK’s common units and the designated Peer Companies’ securities; (iii) an estimated ranking of ENLK among the designated 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 of performance units granted and the related assumptions by performance unit grant date:

EnLink Midstream Partners, LP Performance Units:	March 2018
Beginning TSR price	$	15.44
Risk-free interest rate	2.38		%
Volatility factor	43.85		%
Distribution yield	10.5		%

The following table presents a summary of the performance units:

	Nine Months Ended September 30, 2018
EnLink Midstream Partners, LP Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	585,285			$	20.52
Granted	256,345			19.24
Vested (1)	(313,610		)	24.43
Forfeited	(76,351		)	16.62
Non-vested, end of period	451,669			$	17.74
Aggregate intrinsic value, end of period (in millions)	$	8.4

(1) Vested units included112,101units withheld for payroll taxes paid on behalf of employees and 120,250units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes.

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 theninemonths endedSeptember 30, 2018 is provided below (in millions). No performance units vested for the three and nine months ended September 30, 2017.

EnLink Midstream Partners, LP Performance Units:	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Aggregate intrinsic value of units vested	$	3.0	$	5.0
Fair value of units vested	$	3.6	$	7.7

As ofSeptember 30, 2018, there was$6.2 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 1.8 years.

In connection with the GIP Transaction, certain outstanding performance unit agreements were modified to increase the minimum vesting of units fromzeroto100% as described in our Current Report on Form 8-K filed with the Securities and Exchange Commission (the “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$2.3 million compensation cost over the life of these ENLK performance units.

(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 ENLC common units on such date.A summary of the restricted incentive unit activity for theninemonths endedSeptember 30, 2018is provided below:

	Nine Months Ended September 30, 2018
EnLink Midstream, LLC Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,889,310			$	16.33
Granted (1)	1,469,452			15.76
Vested (1)(2)	(749,164		)	21.53
Forfeited	(146,045		)	12.38
Non-vested, end of period	2,463,553			$	14.64
Aggregate intrinsic value, end of period (in millions)	$	40.5

(1) Restricted incentive units typically vest at the end of three years. In March 2018, ENLC granted194,185restricted incentive units with a fair value of$3.0 million to officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.

(2) Vested units included238,970units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for thethree and nine months ended September 30, 2018 and 2017is provided below (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
EnLink Midstream, LLC Restricted Incentive Units:	2018		2017		2018		2017
Aggregate intrinsic value of units vested	$	3.3	$	0.6	$	12.6	$	15.2
Fair value of units vested	$	2.6	$	1.1	$	16.1	$	21.9

As of September 30, 2018, there was $21.5 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 2.0 years.

(e) EnLink Midstream, LLC’s Performance Units

ENLC grants performance awards under the 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 TSR performance goals relative to the TSR achievement of the Peer Companies 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 ranges fromzero to 200%of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC’s common units and the designated Peer Companies’ securities; (iii) an estimated ranking of ENLC among the designated 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 approximatelythree years. The following table presents a summary of the grant-date fair value assumptions by performance unit grant date:

EnLink Midstream, LLC Performance Units:	March 2018
Beginning TSR price	$	16.55
Risk-free interest rate	2.38		%
Volatility factor	51.36		%
Distribution yield	6.7		%

The following table presents a summary of the performance units:

	Nine Months Ended September 30, 2018
EnLink Midstream, LLC Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	548,839			$	22.14
Granted	223,865			21.63
Vested (1)	(283,637		)	27.25
Forfeited	(70,918		)	17.75
Non-vested, end of period	418,149			$	19.15
Aggregate intrinsic value, end of period (in millions)	$	6.9

(1) Vested units included100,109units withheld for payroll taxes paid on behalf of employees and 109,819units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes.

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 theninemonths endedSeptember 30, 2018is provided below (in millions). No performance units vested for the three and nine months ended September 30, 2017.

EnLink Midstream, LLC Performance Units:	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Aggregate intrinsic value of units vested	$	2.8	$	4.7
Fair value of units vested	$	3.5	$	7.7

As of September 30, 2018, 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 1.8 years.

In connection with the GIP Transaction, certain outstanding performance unit agreements were modified to increase the minimum vesting of units fromzero to 100%as described in our Current Report on Form 8-K filed with the 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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Derivatives

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

(11) 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 ENLK’s 5.45% senior unsecured notes due 2047 (the “2047 Notes”). In accordance with ASC 815, we designated this swap as a cash flow hedge. Upon settlement of the interest rate swap in May 2017, we recorded the associated $2.2 million settlement loss in accumulated 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. For the three and nine months ended September 30, 2018, we amortized an immaterial amount of the settlement loss into interest expense from accumulated other comprehensive income (loss). We expect to recognize$0.1 millionof interest expense out of accumulated other comprehensive income (loss) over the next twelve months. We have no open interest rate swap position as of September 30, 2018.

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 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 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 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.

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Change in fair value of derivatives	$	(0.8	)	$	(3.3	)	$	(14.8	)	$	3.8
Realized loss on derivatives	(4.6		)	(2.2		)	(5.3		)	(4.9		)
Loss on derivative activity	$	(5.4	)	$	(5.5	)	$	(20.1	)	$	(1.1	)

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

	September 30, 2018			December 31, 2017
Fair value of derivative assets—current	$	12.5		$	6.8
Fair value of derivative liabilities—current	(21.9		)	(8.4		)
Fair value of derivative liabilities—long-term	(7.0		)	—
Net fair value of derivatives	$	(16.4	)	$	(1.6	)

As of September 30, 2018 and December 31, 2017, there were no derivative assets classified as long-term on the consolidated balance sheets.

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

		September 30, 2018
Commodity	Instruments	Unit	Volume		Fair Value
NGL (short contracts)	Swaps	Gallons	(58.4	)	$	(12.0	)
NGL (long contracts)	Swaps	Gallons	18.9		3.1
Natural Gas (short contracts)	Swaps	MMBtu	(9.0	)	0.4
Natural Gas (long contracts)	Swaps	MMBtu	10.9		(1.4		)
Crude and condensate (short contracts)	Swaps	MMbbls	(13.3	)	(13.2		)
Crude and condensate (long contracts)	Swaps	MMbbls	1.3		6.7
Total fair value of derivatives					$	(16.4	)

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 financial institutions when entering into financial derivatives on commodities. We have entered into Master 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, the maximum loss on our gross receivable position of$12.5 million as of September 30, 2018 would be reduced to$0.1 milliondue to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

(12) 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, 2018			December 31, 2017
Commodity Swaps (1)	$	(16.4	)	$	(1.6	)

(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.

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, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current maturities of long-term debt (1)	$	4,336.8	$	4,119.0	$	3,542.1	$	3,650.2
Installment Payables	$	—	$	—	$	249.5	$	249.6
Obligations under capital lease	$	2.9	$	2.5	$	4.1	$	3.4
Secured term loan receivable	$	49.9	$	49.9	$	—	$	—

(1) The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance costs of$23.5 million and $26.2 million at September 30, 2018 and December 31, 2017, 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 $765.0 million of outstanding borrowings under the ENLK Credit Facility as of September 30, 2018 and no outstanding borrowings under the ENLK Credit Facility as of December 31, 2017. ENLC had $101.4 million and $74.6 million in outstanding borrowings under the ENLC Credit Facility as of September 30, 2018 and December 31, 2017, respectively. As borrowings under the ENLK Credit Facility and ENLC Credit Facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the ENLK Credit Facility and the ENLC Credit Facility. As of September 30, 2018 and December 31, 2017, ENLK had total borrowings under senior unsecured notes of$3.5 billion maturing between 2019 and 2047 with fixed interest rates ranging from2.7% to 5.6%. The fair values of all senior unsecured notes and installment payables as ofSeptember 30, 2018 and December 31, 2017were based on Level 2 inputs from third-party market quotations. The fair values of obligations under capital leases and the secured term loan receivable were calculated using Level 2 inputs from third-party banks.

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Segment Information

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Segment Information

(13) Segment Information

Identification of the majority of our operating segments is based principally upon geographic regions served and the nature of operating activity. Our reportable segments consist of the following: natural gas gathering, processing, transmission, and fractionation operations located in North Texas and the Permian Basin primarily in West Texas (“Texas”), natural gas pipelines, processing plants, storage facilities, NGL pipelines, and fractionation assets in Louisiana (“Louisiana”), natural gas gathering and processing operations located throughout Oklahoma (“Oklahoma”), and crude rail, truck, pipeline, and barge facilities in West Texas, South Texas, Louisiana, Oklahoma, 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 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.

Based on the disclosure requirements of ASC 606, we are presenting revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for thethree and nine months ended September 30, 2018are presented to conform to ASC 606 accounting and disclosure requirements. Prior periods presented in the consolidated financial statements and accompanying notes were not restated in accordance with ASC 606.

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

	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals
Three Months Ended September 30, 2018
Natural gas sales	$	69.1		$	129.5		$	41.9		$	—		$	—		$	240.5
NGL sales	16.8			839.6			12.8			0.1			—			869.3
Crude oil and condensate sales	—			0.1			0.3			722.0			—			722.4
Product sales	85.9			969.2			55.0			722.1			—			1,832.2
Natural gas sales—related parties	—			—			0.1			—			—			0.1
NGL sales—related parties	153.8			10.9			192.5			—			(347.2		)	10.0
Crude oil and condensate sales—related parties	13.4			0.1			18.0			1.5			(32.9		)	0.1
Product sales—related parties	167.2			11.0			210.6			1.5			(380.1		)	10.2
Gathering and transportation	71.7			17.5			50.2			0.8			—			140.2
Processing	39.4			0.8			31.5			—			—			71.7
NGL services	—			11.9			—			—			—			11.9
Crude services	—			—			0.2			14.9			—			15.1
Other services	2.4			0.1			—			0.1			—			2.6
Midstream services	113.5			30.3			81.9			15.8			—			241.5
Gathering and transportation—related parties	8.7			—			7.2			—			—			15.9
Processing—related parties	10.2			—			3.2			—			—			13.4
Crude services—related parties	—			—			0.1			6.3			—			6.4
Other services—related parties	0.1			—			—			—			—			0.1
Midstream services—related parties	19.0			—			10.5			6.3			—			35.8
Revenue from contracts with customers	385.6			1,010.5			358.0			745.7			(380.1		)	2,119.7
Cost of sales	(222.0		)	(923.6		)	(228.5		)	(702.6		)	380.1			(1,696.6		)
Operating expenses	(44.7		)	(28.7		)	(22.5		)	(18.8		)	—			(114.7		)
Loss on derivative activity	—			—			—			—			(5.4		)	(5.4		)
Segment profit (loss)	$	118.9		$	58.2		$	107.0		$	24.3		$	(5.4	)	$	303.0
Depreciation and amortization	$	(54.0	)	$	(32.7	)	$	(44.7	)	$	(12.9	)	$	(2.4	)	$	(146.7	)
Impairments	$	—		$	(24.6	)	$	—		$	—		$	—		$	(24.6	)
Goodwill	$	232.0		$	—		$	190.3		$	—		$	1,119.9		$	1,542.2
Capital expenditures	$	90.0		$	13.0		$	109.3		$	39.9		$	1.1		$	253.3
Three Months Ended September 30, 2017
Product sales	$	80.8		$	642.3		$	42.5		$	291.1		$	—		$	1,056.7
Product sales—related parties	130.6			10.0			94.6			—			(199.9		)	35.3
Midstream services	29.1			50.3			44.3			12.7			—			136.4
Midstream services—related parties	106.7			35.9			63.0			4.8			(35.4		)	175.0
Cost of sales	(198.5		)	(662.7		)	(148.2		)	(279.1		)	235.3			(1,053.2		)
Operating expenses	(41.1		)	(24.8		)	(17.1		)	(19.1		)	—			(102.1		)
Loss on derivative activity	—			—			—			—			(5.5		)	(5.5		)
Segment profit (loss)	$	107.6		$	51.0		$	79.1		$	10.4		$	(5.5	)	$	242.6
Depreciation and amortization	$	(52.5	)	$	(29.3	)	$	(40.2	)	$	(11.7	)	$	(2.6	)	$	(136.3	)
Impairments	$	—		$	—		$	—		$	(1.8	)	$	—		$	(1.8	)
Goodwill	$	232.0		$	—		$	190.3		$	—		$	1,119.9		$	1,542.2
Capital expenditures	$	39.1		$	7.5		$	107.7		$	13.3		$	2.1		$	169.7

	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals
Nine Months Ended September 30, 2018
Natural gas sales	$	208.9		$	377.2		$	127.9		$	—		$	—		$	714.0
NGL sales	16.8			2,075.9			18.3			0.9			—			2,111.9
Crude oil and condensate sales	—			0.2			0.3			1,940.1			—			1,940.6
Product sales	225.7			2,453.3			146.5			1,941.0			—			4,766.5
Natural gas sales—related parties	—			—			2.5			—			—			2.5
NGL sales—related parties	381.1			45.4			433.0			—			(822.1		)	37.4
Crude oil and condensate sales—related parties	39.4			0.3			63.9			3.3			(105.8		)	1.1
Product sales—related parties	420.5			45.7			499.4			3.3			(927.9		)	41.0
Gathering and transportation	98.4			51.8			91.4			2.5			—			244.1
Processing	52.7			2.5			87.9			—			—			143.1
NGL services	—			38.8			—			—			—			38.8
Crude services	—			—			0.2			42.8			—			43.0
Other services	6.4			0.5			—			0.2			—			7.1
Midstream services	157.5			93.6			179.5			45.5			—			476.1
Gathering and transportation—related parties	122.7			—			80.6			—			—			203.3
Processing—related parties	108.6			—			48.4			—			—			157.0
Crude services—related parties	—			—			1.5			14.9			—			16.4
Other services—related parties	0.5			—			—			—			—			0.5
Midstream services—related parties	231.8			—			130.5			14.9			—			377.2
Revenue from contracts with customers	1,035.5			2,592.6			955.9			2,004.7			(927.9		)	5,660.8
Cost of sales	(562.2		)	(2,333.3		)	(537.8		)	(1,898.3		)	927.9			(4,403.7		)
Operating expenses	(134.7		)	(82.3		)	(64.0		)	(56.3		)	—			(337.3		)
Loss on derivative activity	—			—			—			—			(20.1		)	(20.1		)
Segment profit (loss)	$	338.6		$	177.0		$	354.1		$	50.1		$	(20.1	)	$	899.7
Depreciation and amortization	$	(159.9	)	$	(92.4	)	$	(133.2	)	$	(38.0	)	$	(6.6	)	$	(430.1	)
Impairments	$	—		$	(24.6	)	$	—		$	—		$	—		$	(24.6	)
Goodwill	$	232.0		$	—		$	190.3		$	—		$	1,119.9		$	1,542.2
Capital expenditures	$	200.0		$	36.4		$	328.8		$	84.1		$	3.4		$	652.7
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

The table below represents information about segment assets as ofSeptember 30, 2018 and December 31, 2017 (in millions):

Segment Identifiable Assets:	September 30, 2018		December 31, 2017
Texas	$	3,161.9	$	3,094.8
Louisiana	2,583.8		2,408.5
Oklahoma	3,074.1		2,836.7
Crude and Condensate	1,069.9		929.5
Corporate	1,308.6		1,268.3
Total identifiable assets	$	11,198.3	$	10,537.8

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Segment profit	$	303.0		$	242.6		$	899.7		$	686.7
General and administrative expenses	(41.9		)	(31.3		)	(99.8		)	(98.5		)
Loss on disposition of assets	—			(1.1		)	(1.3		)	(0.8		)
Depreciation and amortization	(146.7		)	(136.3		)	(430.1		)	(407.1		)
Impairments	(24.6		)	(1.8		)	(24.6		)	(8.8		)
Gain on litigation settlement	—			—			—			26.0
Operating income	$	89.8		$	72.1		$	343.9		$	197.5

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Other Information

9 Months Ended

Sep. 30, 2018

Other Liabilities Disclosure [Abstract]

Other Information

(14) Other Information

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

Other Current Assets:	September 30, 2018		December 31, 2017
Natural gas and NGLs inventory	$	119.4	$	30.1
Secured term loan receivable from contract restructuring, net of discount of $1.1	18.4		—
Prepaid expenses and other	17.3		11.1
Natural gas and NGLs inventory, prepaid expenses, and other	$	155.1	$	41.2

Other Current Liabilities:	September 30, 2018		December 31, 2017
Accrued interest	$	64.8	$	35.6
Accrued wages and benefits, including taxes	24.8		30.4
Accrued ad valorem taxes	33.4		27.8
Capital expenditure accruals	57.9		48.8
Onerous performance obligations	13.5		15.2
Other	67.0		65.1
Other current liabilities	$	261.4	$	222.9

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Subsequent Event

9 Months Ended

Sep. 30, 2018

Subsequent Events [Abstract]

Subsequent Event

(15) Subsequent Event

On October 21, 2018, we and ENLK entered into the Merger Agreement and the related preferred restructuring agreement, pursuant to which, subject to the satisfaction or waiver of certain conditions:

• Each issued and outstanding ENLK common unit (except for ENLK common units held by ENLC and its subsidiaries) will be converted into the right to receive1.15ENLC common units;

• The General Partner’s incentive distribution rights in ENLK will be eliminated;

• The Series B Preferred Units will continue to be issued and outstanding following the Merger, except that certain terms of the Series B Preferred Units will be modified pursuant to an amended partnership agreement of ENLK, including exchangeability of the Series B Preferred Units, under certain circumstances, into ENLC common units instead of ENLK common units, subject to the election of ENLK to instead redeem for cash any such exchanged Series B Preferred Units;

• ENLC will issue to Enfield Holdings, L.P. (“Enfield”), the current holder of the Series B Preferred Units, for no additional consideration, a new class of non-economic ENLC 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;

• The Series C Preferred Units will continue to be issued and outstanding following the Merger; and

• All unit-based awards issued and outstanding immediately prior to the effective time of the Merger under the GP Plan will be converted into an award with respect to ENLC common units with substantially similar terms as were in effect immediately prior to the effective time, with certain adjustments to the performance-based vesting of terms of applicable awards related to the performance of ENLC.

The Merger Transactions are expected to close in the first quarter of 2019, subject to obtaining approval of ENLK’s unitholders, customary regulatory approvals, and other customary closing conditions.

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Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Basis of Presentation

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 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. All significant intercompany balances and transactions have been eliminated in consolidation.

Revenue Recognition

Revenue Recognition

We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services, and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. 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. Revenues from both “Product sales” and “Midstream services” represent revenues from contracts with customers and are reflected on the consolidated statements of operations as follows:

• Product sales—Product sales represent the sale of natural gas, NGLs, crude oil, and condensate where the product is purchased and resold in connection with providing our midstream services as outlined above.

• Midstream services—Midstream services represent all other revenue generated as a result of performing our midstream services as outlined above.

Adoption of ASC 606

Effective January 1, 2018, we adopted ASC 606 using the modified retrospective method. ASC 606 replaces previous revenue recognition requirements in GAAP and requires 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 also requires 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.

Evaluation of Our Contractual Performance Obligations

In adopting ASC 606, we evaluated our contracts with customers that are within the scope of ASC 606. In accordance with the new revenue recognition framework introduced by ASC 606, we identified our performance obligations under our contracts with customers. These performance obligations include:

• promises to perform midstream services for our customers over a specified contractual term and/or for a specified volume of commodities; and

• promises to sell a specified volume of commodities to our customers.

The identification of performance obligations under our contracts requires a contract-by-contract evaluation of when control, including the economic benefit, of commodities transfers to and from us (if at all). This evaluation of control changed the way we account for certain transactions effective January 1, 2018, specifically those contracts in which there is both a commodity purchase and a midstream service. 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 do not consider these revenue-generating contracts for purposes of ASC 606. Based on the control determination, all contractually-stated fees that are deducted from our payments to producers or other suppliers for commodities purchased are reflected as a reduction in the cost of such commodity purchases. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating and recognize the fees received for satisfying them as midstream services revenues over time as 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 recognize these fees as midstream services revenues over time as we satisfy our performance obligations.

We also evaluate our contractual arrangements that contain a purchase and sale of commodities under the principal/agent provisions in ASC 606. For contracts where we possess control of the commodity and act as principal in the purchase and sale, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as an agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract.

Based on our review of our performance obligations in our contracts with customers, we changed the consolidated statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. For thethree and nine months ended September 30, 2018, the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately$179 million and $480 million, respectively, or 8% and 8%, respectively, compared to total revenues based on accounting prior to the adoption of ASC 606, with an equivalent net decrease in cost of sales. The change in total revenues as a result of the adoption of ASC 606 is made up of the following revenue line item changes (in millions):

	Increase (Decrease) in Revenue Due to ASC 606 Adoption
	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
Product sales	$	(71	)	$	(149	)
Product sales—related parties	(7		)	(53		)
Midstream services	(98		)	(251		)
Midstream services—related parties	(3		)	(27		)
Total	$	(179	)	$	(480	)

This change in accounting treatment had no impact on our operating income, net income, results of operations, financial condition, or cash flows.

Changes in Accounting Methodology for Certain Contracts

For NGL contracts in which we purchase raw mix NGLs and subsequently transport, fractionate, and market the NGLs, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which the fees we earned for our services were recorded as midstream services revenue on the consolidated statements of operations. As a result of the adoption of ASC 606, we determined that the control, including the economic benefit, of commodities has passed to us once the raw mix NGLs have been purchased from the customer. Therefore, we now consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the raw mix NGLs, rather than being recorded as midstream services revenue. Upon sale of the NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased.

For our crude oil and condensate service contracts in which we purchase the commodity, we utilize a similar approach under ASC 606 as outlined above for NGL contracts. This treatment is consistent with our accounting for crude oil and condensate service contracts prior to the adoption of ASC 606.

For our natural gas gathering and processing contracts in which we perform midstream services and also purchase the natural gas, we accounted for these contracts prior to the adoption of ASC 606 as revenue-generating contracts in which all contractually-stated fees earned for our gathering and processing services were recorded as midstream services revenue on the statements of operations. As a result of the adoption of ASC 606, we must determine if economic control of the commodities has passed from the producer to us before or after we perform our services (if at all). Control is assessed on a contract-by-contract basis by analyzing each contract’s provisions, which can include provisions for: the customer to take its residue gas and/or NGLs in-kind; fixed or actual NGL or keep-whole recovery; commodity purchase prices at weighted average sales price or market index-based pricing; and various other contract-specific considerations. Based on this control assessment, our gathering and processing contracts fall into two primary categories:

• For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas passes to us when the natural gas is brought into our system, we do not consider these contracts to contain performance obligations for our services. As control of the natural gas passes to us prior to performing our gathering and processing services, we are, in effect, performing our services for our own benefit. Based on this control determination, we consider the contractually-stated fees to serve as pricing mechanisms that reduce the cost of such commodity purchased upon receipt of the natural gas, rather than being recorded as midstream services revenue. Upon sale of the residue gas and/or NGLs to a third-party customer, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities purchased.

• For gathering and processing contracts in which there is a commodity purchase and analysis of the contract provisions indicates that control, including the economic benefit, of the natural gas does not pass to us until after the natural gas has been gathered and processed, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenues over time as we satisfy our performance obligations.

For midstream service contracts related to NGL, crude oil, or natural gas gathering and processing in which there is no commodity purchase or control of the commodity never passes to us and we simply earn a fee for our services, we consider these contracts to contain performance obligations for our services. Accordingly, we consider the satisfaction of these performance obligations as revenue-generating, and we recognize the fees received for satisfying these performance obligations as midstream services revenue over time as we satisfy our performance obligations. This treatment is consistent with our accounting for these contracts prior to the adoption of ASC 606.

For our natural gas transmission contracts, we determined that control of the natural gas never transfers to us and we simply earn a fee for our services. Therefore, we recognize these fees as midstream services revenue over time as we satisfy our performance obligations. This treatment is consistent with our accounting for natural gas transmission contracts prior to the adoption of ASC 606.

We also evaluate our commodity marketing contracts, under which we purchase and sell commodities in connection with our gas, NGL, and crude and condensate midstream services, pursuant to ASC 606, including the principal/agent provisions. For contracts in which we possess control of the commodity and act as principal in the purchase and sale of commodities, we record product sales revenue at the price at which the commodities are sold, with a corresponding cost of sales equal to the cost of the commodities when purchased. For contracts in which we do not possess control of the commodity and are acting as agent, our consolidated statements of operations only reflect midstream services revenues that we earn based on the fees contained in the applicable contract. This treatment is consistent with our accounting for our commodity marketing contracts prior to the adoption of ASC 606.

Satisfaction of Performance Obligations and Recognition of Revenue

While ASC 606 alters the line item on which certain amounts are recorded on the consolidated statements of operations, ASC 606 did not significantly affect the timing of income and expense recognition on the consolidated statements of operations. Specifically, for our commodity sales contracts, we satisfy our performance obligations at the point in time at which the commodity transfers from us to the customer. This transfer pattern aligns with our billing methodology. Therefore, we recognize product sales revenue at the time the commodity is delivered and in the amount to which we have the right to invoice the customer, which is consistent with our accounting prior to the adoption of ASC 606. For our midstream service contracts that contain revenue-generating performance obligations, we satisfy our performance obligations over time as we perform the midstream service and as the customer receives the benefit of these services over the term of the contract. As permitted by ASC 606, we are utilizing the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice, since we have a right to consideration from our customer in an amount that corresponds directly with the value to the customer of our performance completed to date. Accordingly, we continue to recognize revenue over time as our midstream services are performed. Therefore, ASC 606 does not significantly affect the timing of revenue and expense recognition on our consolidated statements of operations, and no cumulative effect adjustment was made to the balance of equity upon our adoption of ASC 606.

We generally accrue one month of sales and the related natural gas, NGL, condensate, and crude oil purchases and reverse these accruals when the sales and purchases are invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. We typically receive payment for invoiced amounts within one month, depending on the terms of the contract. We account for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

Minimum Volume Commitments and Firm Transportation Contracts

Certain gathering and processing agreements in our Texas, Oklahoma, and Crude and Condensate segments provide for quarterly or annual MVCs, including MVCs from Devon from certain of our Barnett Shale assets in North Texas and our Cana gathering and processing assets in Oklahoma. Under these agreements, our customers or suppliers (as “customers” and “suppliers” are determined per application of ASC 606) 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 customer is obligated to pay a contractually-determined fee based upon the shortfall between actual product volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer or supplier 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 MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, 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 expected impact to our consolidated statements of operations, resulting from either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below reflect 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. In addition, amounts in the table below 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.

2018 (remaining)	$	190.9
2019	237.1
2020	225.7
2021	82.3
2022	71.9
Thereafter	231.2
Total	$	1,039.1

In May 2018, we restructured one of our natural gas gathering and processing contracts that included MVCs that were in effect through 2023. Prior to the contract restructuring, we expected$135.1 million in guaranteed future gross operating margin under the contract, generated from either revenue or reductions to cost of sales resulting from both gathering and processing fees as well as shortfall revenue under the MVCs. As a result of the contract restructuring, all MVC provisions were removed from the contract, and we and the counterparty entered into additional agreements pursuant to which: (i) the counterparty made a$19.7 million payment to us on the date of the contract restructuring to satisfy MVC revenue earned up to the date of the contract restructuring; (ii) the counterparty entered into a second lien secured term loan under which the counterparty will pay us$58.0 millionin principal payments in various installments ending in May 2023, with interest accruing on the loan balance at8.0%per annum beginning in 2020; and (iii) the counterparty granted to us a1.0%term overriding royalty interest through June 2034 in each well located on leasehold interests of the counterparty and connected to the gas gathering system that we operate. As a result of the contract restructuring and in accordance with ASC 606, we recognized$45.5 millionof midstream services revenue, which primarily represents the discounted present value of the second lien secured term loan receivable, in the Oklahoma segment in the second quarter of 2018. Pursuant to the contract restructuring, the terms of the restructured contract, other than the MVCs, are the same as the original contract, and we expect to continue recognizing gathering and processing fees on volumes delivered by the customer.

Contributions in Aid of Construction

The adoption of ASC 606 also alters how we account for contributions in aid of construction (“CIAC”). CIAC payments are lump sum payments from third parties to reimburse us for capital expenditures related to the construction of our operating assets and, in most cases, the connection of these operating assets to the third party’s assets. CIAC payments can be paid to us prior to the commencement of construction activities, during construction, or after construction has been completed. Prior to adoption of ASC 606 and in accordance with ASC 980, Regulated Operations (“ASC 980”), and the FERC Uniform System of Accounts, we reduced the balance of the related property and equipment by the amount of CIAC payments received. In doing so, CIAC payments previously affected the consolidated statements of operations through reduced depreciation expense over the useful lives of the related property and equipment. Upon adoption of ASC 606, we initially recognize CIAC payments received from customers as deferred revenue, which will be subsequently amortized into revenue over the term of the underlying operational contract. For CIAC payments from noncustomers and for payments related to the construction of regulated operating assets, we continue to reduce the balance of the related property and equipment in accordance with ASC 980 and the FERC Uniform System of Accounts. This change in our CIAC accounting policy was not material to our financial statements for thethree and nine months ended September 30, 2018.

Disaggregation of Revenue and Presentation of Prior Periods

Based on the disclosure requirements of ASC 606, we are presenting revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues. SeeNote 13—Segment Informationfor the revenue disaggregation information included in the segment information table for thethree and nine months ended September 30, 2018. As we adopted ASC 606 using the modified retrospective method, only the consolidated statement of operations and revenue disaggregation information for thethree and nine months ended September 30, 2018are presented to conform to ASC 606 accounting and disclosure requirements. Prior periods presented in the consolidated financial statements and accompanying notes were not restated in accordance with ASC 606.

Accounting Standards to be Adopted in Future Periods

Accounting Standards to be Adopted in Future Periods

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842)—Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”), which establishes ASC Topic 842, Leases (“ASC 842”). Under ASC 842, lessees will need to recognize virtually all of their leases on the balance sheet by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASC 842 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within those annual periods. We will adopt ASC 842 effective January 1, 2019. We are currently assessing the impact of adopting ASC 842 and are in the process of implementing a lease accounting software tool. This assessment includes the evaluation of our current lease contracts and the analysis of contracts that may contain lease components. We are electing to apply certain practical expedients that are 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. While we are still evaluating the complete population of lease contracts, we believe the adoption of ASC 842 will increase our asset and liability balances on the consolidated balance sheets by less than$100 milliondue 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 January 2018, the FASB issued ASU 2018-01, Leases (Topic 842)—Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 amends ASC 842 and provides an optional practical expedient to not evaluate under ASC 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in ASC 840, Leases. Under ASU 2018-01, an entity that elects this practical expedient should evaluate new or modified land easements under ASC 842 beginning at the date that the entity adopts ASC 842. We plan to utilize the practical expedient provided in ASU 2018-01 in conjunction with our adoption of ASC 842.

In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842)—Targeted Improvements (“ASU 2018-11”). ASU 2018-11 amends ASC 842 and allows entities to adopt the new leases standard using a modified retrospective approach. Under this new transition method, entities initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Additionally, an entity’s reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with current GAAP. We plan to utilize the optional transition method provided in ASU 2018-11 in conjunction with our adoption of ASC 842 in January 2019.

Property and Equipment

Property & Equipment

Impairment Review. In accordance with ASC 360, Property, Plant and Equipment, we evaluate long-lived assets of identifiable business activities 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.

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Significant Accounting Polices (Tables)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

Based on our review of our performance obligations in our contracts with customers, we changed the consolidated statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. For thethree and nine months ended September 30, 2018, the reclassification of revenues and cost of sales resulted in a net decrease in revenue of approximately$179 million and $480 million, respectively, or 8% and 8%, respectively, compared to total revenues based on accounting prior to the adoption of ASC 606, with an equivalent net decrease in cost of sales. The change in total revenues as a result of the adoption of ASC 606 is made up of the following revenue line item changes (in millions):

	Increase (Decrease) in Revenue Due to ASC 606 Adoption
	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
Product sales	$	(71	)	$	(149	)
Product sales—related parties	(7		)	(53		)
Midstream services	(98		)	(251		)
Midstream services—related parties	(3		)	(27		)
Total	$	(179	)	$	(480	)

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

The following table summarizes the expected impact to our consolidated statements of operations, resulting from either revenue or reductions to cost of sales, from MVC and firm transportation contractual provisions. All amounts in the table below reflect 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. In addition, amounts in the table below 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.

2018 (remaining)	$	190.9
2019	237.1
2020	225.7
2021	82.3
2022	71.9
Thereafter	231.2
Total	$	1,039.1

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Intangible Assets (Tables)

9 Months Ended

Sep. 30, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Summary of Changes in Carrying Value

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

	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Nine Months Ended September 30, 2018
Customer relationships, beginning of period	$	1,795.8	$	(298.7	)	$	1,497.1
Amortization expense	—		(92.6		)	(92.6		)
Customer relationships, end of period	$	1,795.8	$	(391.3	)	$	1,404.5

Schedule of Amortization Expense

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

2018 (remaining)	$	30.9
2019	123.7
2020	123.7
2021	123.7
2022	123.7
Thereafter	878.8
Total	$	1,404.5

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Summary of Debt

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

	September 30, 2018								December 31, 2017
	Outstanding Principal		Premium (Discount)			Long-Term Debt			Outstanding Principal		Premium (Discount)			Long-Term Debt
ENLK credit facility due 2020 (1)	$	765.0	$	—		$	765.0		$	—	$	—		$	—
ENLC credit facility due 2019 (2)	101.4		—			101.4			74.6		—			74.6
ENLK’s 2.70% Senior unsecured notes due 2019	400.0		(0.1		)	399.9			400.0		(0.1		)	399.9
ENLK’s 4.40% Senior unsecured notes due 2024	550.0		1.9			551.9			550.0		2.2			552.2
ENLK’s 4.15% Senior unsecured notes due 2025	750.0		(0.9		)	749.1			750.0		(1.0		)	749.0
ENLK’s 4.85% Senior unsecured notes due 2026	500.0		(0.5		)	499.5			500.0		(0.6		)	499.4
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		(6.2		)	443.8			450.0		(6.5		)	443.5
ENLK's 5.45% Senior unsecured notes due 2047	500.0		(0.1		)	499.9			500.0		(0.1		)	499.9
Debt classified as long-term, including current maturities of long-term debt	$	4,366.4	$	(6.1	)	4,360.3			$	3,574.6	$	(6.3	)	3,568.3
Debt issuance cost (3)						(23.5		)						(26.2		)
Less: Current maturities of long-term debt (4)						(500.9		)						—
Long-term debt, net of unamortized issuance cost						$	3,835.9							$	3,542.1

(1) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was4.1%atSeptember 30, 2018.

(2) Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 4.1% and 3.2% at September 30, 2018 and December 31, 2017, respectively.

(3) Net of amortization of $15.7 million and $12.9 million at September 30, 2018 and December 31, 2017, respectively.

(4) The outstanding balance, net of debt issuance costs, of the ENLC Credit Facility and ENLK’s2.70%senior unsecured notes as ofSeptember 30, 2018are classified as “Current maturities of long-term debt” on the consolidated balance sheet as the ENLC Credit Facility matures on March 7, 2019, and ENLK’s 2.70% senior unsecured notes mature on April 1, 2019.

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

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,
	2018		2017		2018		2017
Current income tax provision	$	1.0	$	0.9	$	1.9	$	1.3
Deferred income tax provision	3.0		2.2		$	15.4	$	8.0
Total income tax provision	$	4.0	$	3.1	$	17.3	$	9.3

Reconciliation of Total Income Tax Expense to Income before Income Taxes

The following schedule reconciles total income tax expense 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,
	2018			2017			2018			2017
Expected income tax provision based on federal statutory rate (1)	$	2.4		$	3.3		$	13.7		$	6.8
State income taxes expense, net of federal tax benefit	0.3			0.2			1.6			0.5
Income tax expense (benefit) from ENLK	0.9			0.5			(0.2		)	0.7
Unit-based compensation	(0.9		)	—			0.6			2.3
Other	1.3			(0.9		)	1.6			(1.0		)
Total income tax provision	$	4.0		$	3.1		$	17.3		$	9.3

(1) The statutory federal tax rate for corporations was 21% at September 30, 2018 and 35% at September 30, 2017.

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Certain Provisions of the Partnership Agreement (Tables)

9 Months Ended

Sep. 30, 2018

Partners' Capital [Abstract]

Summary of Distribution Activity

A summary of the distribution activity relating to the Series B Preferred Units during the nine months ended September 30, 2018 and 2017 is provided below:

Declaration period	Distribution paid as additional Series B Preferred Units	Cash Distribution (in millions)		Date paid/payable
2018
Fourth Quarter of 2017	413,658	$	16.0	February 13, 2018
First Quarter of 2018	416,657	$	16.2	May 14, 2018
Second Quarter of 2018	419,678	$	16.3	August 13, 2018
Third Quarter of 2018	422,720	$	16.4	November 13, 2018
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

A summary of ENLK’s distribution activity relating to the common units during theninemonths endedSeptember 30, 2018 and 2017 is provided below:

Declaration period	Distribution/unit		Date paid/payable
2018
Fourth Quarter of 2017	$	0.39	February 13, 2018
First Quarter of 2018	$	0.39	May 14, 2018
Second Quarter of 2018	$	0.39	August 13, 2018
Third Quarter of 2018	$	0.39	November 13, 2018
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

Incentive Distributions

Net income is allocated to the General Partner in an amount equal to its incentive distribution rights as described in section “(d) ENLK Common Unit Distributions” above. The General Partner’s share of net income consists of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units, and the percentage interest of ENLK’s net incomeadjusted 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,
	2018			2017			2018			2017
Income allocation for incentive distributions	$	15.0		$	14.8		$	44.6		$	44.1
Unit-based compensation attributable to ENLC’s restricted and performance units	(7.3		)	(4.2		)	(15.7		)	(16.9		)
General Partner share of net income	—			—			0.6			0.1
General Partner interest in net income	$	7.7		$	10.6		$	29.5		$	27.3

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Members' Equity (Tables)

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings per Limited Partner Unit

The following table reflects the computation of basic and diluted earnings per unit for the periods presented (in millions, except per unit amounts):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
ENLC interest in net income	$	7.7		$	6.2		$	48.1		$	10.2
Distributed earnings allocated to:
Common units (1) (2)	$	49.1		$	46.0		$	145.0		$	138.0
Unvested restricted units (1) (2)	0.9			0.7			2.2			1.9
Total distributed earnings	$	50.0		$	46.7		$	147.2		$	139.9
Undistributed loss allocated to:
Common units	$	(41.5	)	$	(39.9	)	$	(97.6	)	$	(128.0	)
Unvested restricted units	(0.8		)	(0.6		)	(1.5		)	(1.7		)
Total undistributed loss	$	(42.3	)	$	(40.5	)	$	(99.1	)	$	(129.7	)
Net income allocated to:
Common units	$	7.6		$	6.1		$	47.4		$	10.0
Unvested restricted units	0.1			0.1			0.7			0.2
Total net income	$	7.7		$	6.2		$	48.1		$	10.2
Basic and diluted net income per unit:
Basic	$	0.04		$	0.03		$	0.27		$	0.06
Diluted	$	0.04		$	0.03		$	0.26		$	0.06

(1) For the three months ended September 30, 2018 and 2017, distributed earnings represent a declared distribution of $0.271 per unit payable on November 14, 2018 and a distribution of $0.255 per unit paid on November 14, 2017, respectively.

(2) For the nine months ended September 30, 2018, distributed earnings included a declared distribution of $0.271 per unit payable on November 14, 2018, $0.267 per unit paid on August 14, 2018, and $0.263 per unit paid on May 15, 2018. For the nine months ended September 30, 2017, distributed earnings included distributions of $0.255 per unit paid on November 14, 2017, $0.255 per unit paid on August 14, 2017, and $0.255 per unit paid on May 15, 2017.

Schedule of Unit Amounts Used to Computer Earnings per Unit

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,
	2018	2017	2018	2017
Basic weighted average units outstanding:
Weighted average common units outstanding	181.2	180.6	181.1	180.4
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	181.2	180.6	181.1	180.4
Dilutive effect of non-vested restricted units	1.3	1.2	1.1	1.3
Total weighted average diluted common units outstanding	182.5	181.8	182.2	181.7

Summary of Distribution Activity

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

Declaration period	Distribution/unit		Date paid/payable
2018
Fourth Quarter of 2017	$	0.259	February 14, 2018
First Quarter of 2018	$	0.263	May 15, 2018
Second Quarter 2018	$	0.267	August 14, 2018
Third Quarter 2018	$	0.271	November 14, 2018
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

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Investment in Unconsolidated Affiliates (Tables)

9 Months Ended

Sep. 30, 2018

Equity Method Investments and Joint Ventures [Abstract]

Activity Related to Investment in Unconsolidated Affiliates

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,
	2018			2017			2018			2017
GCF
Distributions	$	5.3		$	3.5		$	16.4		$	10.6
Equity in income	$	4.6		$	4.5		$	14.0		$	8.5
HEP
Equity in loss (1)	$	—		$	—		$	—		$	(3.4	)
Cedar Cove JV
Contributions	$	—		$	1.5		$	0.1		$	11.8
Distributions	$	—		$	0.5		$	0.3		$	0.8
Equity in loss	$	(0.3	)	$	(0.1	)	$	(2.3	)	$	(0.1	)
Total
Contributions	$	—		$	1.5		$	0.1		$	11.8
Distributions	$	5.3		$	4.0		$	16.7		$	11.4
Equity in income (1)	$	4.3		$	4.4		$	11.7		$	5.0

(1) We sold our ownership interest in HEP during the first quarter of 2017, resulting in a loss of$3.4 million for the ninemonths ended September 30, 2017.

The following table shows the balances related to our investment in unconsolidated affiliates as ofSeptember 30, 2018 and December 31, 2017 (in millions):

	September 30, 2018		December 31, 2017
GCF	$	46.0	$	48.4
Cedar Cove JV	38.5		41.0
Total investment in unconsolidated affiliates	$	84.5	$	89.4

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Employee Incentive Plans (Tables)

9 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Amounts Recognized in Consolidated Financial Statements

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,
	2018		2017		2018		2017
Cost of unit-based compensation charged to operating expense	$	5.2	$	2.8	$	9.5	$	10.4
Cost of unit-based compensation charged to general and administrative expense	11.9		7.4		22.3		28.5
Total unit-based compensation expense	$	17.1	$	10.2	$	31.8	$	38.9
Non-controlling interest in unit-based compensation	$	6.6	$	3.9	$	12.1	$	14.6
Amount of related income tax benefit recognized in net income (1)	$	2.2	$	2.4	$	4.1	$	9.1

(1) For the three and nine months ended September 30, 2018, the amount of related income tax benefit recognized in net income excluded $0.9 million of income tax benefit and $0.6 million of income tax expense, respectively, related to tax deficiencies recorded upon vesting of restricted units. For the nine months ended September 30, 2017, the amount of related income tax benefit recognized in net income excluded $2.3 million of income tax expense related to tax deficiencies recorded upon vesting of restricted units. There was no income tax expense or benefit related to tax deficiencies recorded upon vesting of restricted units for the three months ended September 30, 2017.

Summary of Restricted Incentive Unit Activity

A summary of the restricted incentive unit activity for thenine months ended September 30, 2018is provided below:

	Nine Months Ended September 30, 2018
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,980,224			$	15.81
Granted (1)	1,586,750			15.27
Vested (1)(2)	(813,290		)	19.78
Forfeited	(157,057		)	12.42
Non-vested, end of period	2,596,627			$	14.44
Aggregate intrinsic value, end of period (in millions)	$	48.4

(1) Restricted incentive units typically vest at the end of three years. In March 2018, ENLK granted 200,753restricted incentive units with a fair value of$3.0 millionto officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.

(2) Vested units included255,653units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive unit activity for theninemonths endedSeptember 30, 2018is provided below:

	Nine Months Ended September 30, 2018
EnLink Midstream, LLC Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	1,889,310			$	16.33
Granted (1)	1,469,452			15.76
Vested (1)(2)	(749,164		)	21.53
Forfeited	(146,045		)	12.38
Non-vested, end of period	2,463,553			$	14.64
Aggregate intrinsic value, end of period (in millions)	$	40.5

(1) Restricted incentive units typically vest at the end of three years. In March 2018, ENLC granted194,185restricted incentive units with a fair value of$3.0 million to officers and certain employees as bonus payments for 2017, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.

(2) Vested units included238,970units withheld for payroll taxes paid on behalf of employees

Summary of Restricted Units' Aggregate Intrinsic Value

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 thethree and nine months ended September 30, 2018 and 2017is provided below (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
EnLink Midstream, LLC Restricted Incentive Units:	2018		2017		2018		2017
Aggregate intrinsic value of units vested	$	3.3	$	0.6	$	12.6	$	15.2
Fair value of units vested	$	2.6	$	1.1	$	16.1	$	21.9

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 thethree and nine months ended September 30, 2018 and 2017 is provided below (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
EnLink Midstream Partners, LP Restricted Incentive Units:	2018		2017		2018		2017
Aggregate intrinsic value of units vested	$	3.7	$	0.6	$	12.8	$	16.3
Fair value of units vested	$	2.8	$	1.1	$	16.1	$	22.1

Summary of Grant-Date Fair Values

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

EnLink Midstream Partners, LP Performance Units:	March 2018
Beginning TSR price	$	15.44
Risk-free interest rate	2.38		%
Volatility factor	43.85		%
Distribution yield	10.5		%

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

EnLink Midstream, LLC Performance Units:	March 2018
Beginning TSR price	$	16.55
Risk-free interest rate	2.38		%
Volatility factor	51.36		%
Distribution yield	6.7		%

Summary of Performance Units

The following table presents a summary of the performance units:

	Nine Months Ended September 30, 2018
EnLink Midstream Partners, LP Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	585,285			$	20.52
Granted	256,345			19.24
Vested (1)	(313,610		)	24.43
Forfeited	(76,351		)	16.62
Non-vested, end of period	451,669			$	17.74
Aggregate intrinsic value, end of period (in millions)	$	8.4

(1) Vested units included112,101units withheld for payroll taxes paid on behalf of employees and 120,250units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes.

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 theninemonths endedSeptember 30, 2018 is provided below (in millions). No performance units vested for the three and nine months ended September 30, 2017.

EnLink Midstream Partners, LP Performance Units:	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Aggregate intrinsic value of units vested	$	3.0	$	5.0
Fair value of units vested	$	3.6	$	7.7

The following table presents a summary of the performance units:

	Nine Months Ended September 30, 2018
EnLink Midstream, LLC Performance Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	548,839			$	22.14
Granted	223,865			21.63
Vested (1)	(283,637		)	27.25
Forfeited	(70,918		)	17.75
Non-vested, end of period	418,149			$	19.15
Aggregate intrinsic value, end of period (in millions)	$	6.9

(1) Vested units included100,109units withheld for payroll taxes paid on behalf of employees and 109,819units that vested as a result of the GIP Transaction, net of units withheld for payroll taxes.

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 theninemonths endedSeptember 30, 2018is provided below (in millions). No performance units vested for the three and nine months ended September 30, 2017.

EnLink Midstream, LLC Performance Units:	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Aggregate intrinsic value of units vested	$	2.8	$	4.7
Fair value of units vested	$	3.5	$	7.7

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Derivatives (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Components of Gain (Loss) on Derivative Activity

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Change in fair value of derivatives	$	(0.8	)	$	(3.3	)	$	(14.8	)	$	3.8
Realized loss on derivatives	(4.6		)	(2.2		)	(5.3		)	(4.9		)
Loss on derivative activity	$	(5.4	)	$	(5.5	)	$	(20.1	)	$	(1.1	)

Fair Value of Derivative Assets and Liabilities Related to Commodity Swaps

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

	September 30, 2018			December 31, 2017
Fair value of derivative assets—current	$	12.5		$	6.8
Fair value of derivative liabilities—current	(21.9		)	(8.4		)
Fair value of derivative liabilities—long-term	(7.0		)	—
Net fair value of derivatives	$	(16.4	)	$	(1.6	)

Notional Amount and Fair Value of Derivative Instruments

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

		September 30, 2018
Commodity	Instruments	Unit	Volume		Fair Value
NGL (short contracts)	Swaps	Gallons	(58.4	)	$	(12.0	)
NGL (long contracts)	Swaps	Gallons	18.9		3.1
Natural Gas (short contracts)	Swaps	MMBtu	(9.0	)	0.4
Natural Gas (long contracts)	Swaps	MMBtu	10.9		(1.4		)
Crude and condensate (short contracts)	Swaps	MMbbls	(13.3	)	(13.2		)
Crude and condensate (long contracts)	Swaps	MMbbls	1.3		6.7
Total fair value of derivatives					$	(16.4	)

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Schedule of Net Assets (Liabilities) Measured on a Recurring Basis

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

	Level 2
	September 30, 2018			December 31, 2017
Commodity Swaps (1)	$	(16.4	)	$	(1.6	)

(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.

Schedule of the Estimated Fair Value of Financial Instruments

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, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt, including current maturities of long-term debt (1)	$	4,336.8	$	4,119.0	$	3,542.1	$	3,650.2
Installment Payables	$	—	$	—	$	249.5	$	249.6
Obligations under capital lease	$	2.9	$	2.5	$	4.1	$	3.4
Secured term loan receivable	$	49.9	$	49.9	$	—	$	—

(1) The carrying value of long-term debt, including current maturities of long-term debt, is reduced by debt issuance costs of$23.5 million and $26.2 million at September 30, 2018 and December 31, 2017, respectively. The respective fair values do not factor in debt issuance costs.

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Summary of Financial Information

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

	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals
Three Months Ended September 30, 2018
Natural gas sales	$	69.1		$	129.5		$	41.9		$	—		$	—		$	240.5
NGL sales	16.8			839.6			12.8			0.1			—			869.3
Crude oil and condensate sales	—			0.1			0.3			722.0			—			722.4
Product sales	85.9			969.2			55.0			722.1			—			1,832.2
Natural gas sales—related parties	—			—			0.1			—			—			0.1
NGL sales—related parties	153.8			10.9			192.5			—			(347.2		)	10.0
Crude oil and condensate sales—related parties	13.4			0.1			18.0			1.5			(32.9		)	0.1
Product sales—related parties	167.2			11.0			210.6			1.5			(380.1		)	10.2
Gathering and transportation	71.7			17.5			50.2			0.8			—			140.2
Processing	39.4			0.8			31.5			—			—			71.7
NGL services	—			11.9			—			—			—			11.9
Crude services	—			—			0.2			14.9			—			15.1
Other services	2.4			0.1			—			0.1			—			2.6
Midstream services	113.5			30.3			81.9			15.8			—			241.5
Gathering and transportation—related parties	8.7			—			7.2			—			—			15.9
Processing—related parties	10.2			—			3.2			—			—			13.4
Crude services—related parties	—			—			0.1			6.3			—			6.4
Other services—related parties	0.1			—			—			—			—			0.1
Midstream services—related parties	19.0			—			10.5			6.3			—			35.8
Revenue from contracts with customers	385.6			1,010.5			358.0			745.7			(380.1		)	2,119.7
Cost of sales	(222.0		)	(923.6		)	(228.5		)	(702.6		)	380.1			(1,696.6		)
Operating expenses	(44.7		)	(28.7		)	(22.5		)	(18.8		)	—			(114.7		)
Loss on derivative activity	—			—			—			—			(5.4		)	(5.4		)
Segment profit (loss)	$	118.9		$	58.2		$	107.0		$	24.3		$	(5.4	)	$	303.0
Depreciation and amortization	$	(54.0	)	$	(32.7	)	$	(44.7	)	$	(12.9	)	$	(2.4	)	$	(146.7	)
Impairments	$	—		$	(24.6	)	$	—		$	—		$	—		$	(24.6	)
Goodwill	$	232.0		$	—		$	190.3		$	—		$	1,119.9		$	1,542.2
Capital expenditures	$	90.0		$	13.0		$	109.3		$	39.9		$	1.1		$	253.3
Three Months Ended September 30, 2017
Product sales	$	80.8		$	642.3		$	42.5		$	291.1		$	—		$	1,056.7
Product sales—related parties	130.6			10.0			94.6			—			(199.9		)	35.3
Midstream services	29.1			50.3			44.3			12.7			—			136.4
Midstream services—related parties	106.7			35.9			63.0			4.8			(35.4		)	175.0
Cost of sales	(198.5		)	(662.7		)	(148.2		)	(279.1		)	235.3			(1,053.2		)
Operating expenses	(41.1		)	(24.8		)	(17.1		)	(19.1		)	—			(102.1		)
Loss on derivative activity	—			—			—			—			(5.5		)	(5.5		)
Segment profit (loss)	$	107.6		$	51.0		$	79.1		$	10.4		$	(5.5	)	$	242.6
Depreciation and amortization	$	(52.5	)	$	(29.3	)	$	(40.2	)	$	(11.7	)	$	(2.6	)	$	(136.3	)
Impairments	$	—		$	—		$	—		$	(1.8	)	$	—		$	(1.8	)
Goodwill	$	232.0		$	—		$	190.3		$	—		$	1,119.9		$	1,542.2
Capital expenditures	$	39.1		$	7.5		$	107.7		$	13.3		$	2.1		$	169.7

	Texas			Louisiana			Oklahoma			Crude and Condensate			Corporate			Totals
Nine Months Ended September 30, 2018
Natural gas sales	$	208.9		$	377.2		$	127.9		$	—		$	—		$	714.0
NGL sales	16.8			2,075.9			18.3			0.9			—			2,111.9
Crude oil and condensate sales	—			0.2			0.3			1,940.1			—			1,940.6
Product sales	225.7			2,453.3			146.5			1,941.0			—			4,766.5
Natural gas sales—related parties	—			—			2.5			—			—			2.5
NGL sales—related parties	381.1			45.4			433.0			—			(822.1		)	37.4
Crude oil and condensate sales—related parties	39.4			0.3			63.9			3.3			(105.8		)	1.1
Product sales—related parties	420.5			45.7			499.4			3.3			(927.9		)	41.0
Gathering and transportation	98.4			51.8			91.4			2.5			—			244.1
Processing	52.7			2.5			87.9			—			—			143.1
NGL services	—			38.8			—			—			—			38.8
Crude services	—			—			0.2			42.8			—			43.0
Other services	6.4			0.5			—			0.2			—			7.1
Midstream services	157.5			93.6			179.5			45.5			—			476.1
Gathering and transportation—related parties	122.7			—			80.6			—			—			203.3
Processing—related parties	108.6			—			48.4			—			—			157.0
Crude services—related parties	—			—			1.5			14.9			—			16.4
Other services—related parties	0.5			—			—			—			—			0.5
Midstream services—related parties	231.8			—			130.5			14.9			—			377.2
Revenue from contracts with customers	1,035.5			2,592.6			955.9			2,004.7			(927.9		)	5,660.8
Cost of sales	(562.2		)	(2,333.3		)	(537.8		)	(1,898.3		)	927.9			(4,403.7		)
Operating expenses	(134.7		)	(82.3		)	(64.0		)	(56.3		)	—			(337.3		)
Loss on derivative activity	—			—			—			—			(20.1		)	(20.1		)
Segment profit (loss)	$	338.6		$	177.0		$	354.1		$	50.1		$	(20.1	)	$	899.7
Depreciation and amortization	$	(159.9	)	$	(92.4	)	$	(133.2	)	$	(38.0	)	$	(6.6	)	$	(430.1	)
Impairments	$	—		$	(24.6	)	$	—		$	—		$	—		$	(24.6	)
Goodwill	$	232.0		$	—		$	190.3		$	—		$	1,119.9		$	1,542.2
Capital expenditures	$	200.0		$	36.4		$	328.8		$	84.1		$	3.4		$	652.7
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

Schedule of Segment Assets

The table below represents information about segment assets as ofSeptember 30, 2018 and December 31, 2017 (in millions):

Segment Identifiable Assets:	September 30, 2018		December 31, 2017
Texas	$	3,161.9	$	3,094.8
Louisiana	2,583.8		2,408.5
Oklahoma	3,074.1		2,836.7
Crude and Condensate	1,069.9		929.5
Corporate	1,308.6		1,268.3
Total identifiable assets	$	11,198.3	$	10,537.8

Reconciliation of Profits to Operating Income (Loss)

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Segment profit	$	303.0		$	242.6		$	899.7		$	686.7
General and administrative expenses	(41.9		)	(31.3		)	(99.8		)	(98.5		)
Loss on disposition of assets	—			(1.1		)	(1.3		)	(0.8		)
Depreciation and amortization	(146.7		)	(136.3		)	(430.1		)	(407.1		)
Impairments	(24.6		)	(1.8		)	(24.6		)	(8.8		)
Gain on litigation settlement	—			—			—			26.0
Operating income	$	89.8		$	72.1		$	343.9		$	197.5

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Other Information (Tables)

9 Months Ended

Sep. 30, 2018

Other Liabilities Disclosure [Abstract]

Schedule of Other Current Liabilities

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

Other Current Assets:	September 30, 2018		December 31, 2017
Natural gas and NGLs inventory	$	119.4	$	30.1
Secured term loan receivable from contract restructuring, net of discount of $1.1	18.4		—
Prepaid expenses and other	17.3		11.1
Natural gas and NGLs inventory, prepaid expenses, and other	$	155.1	$	41.2

Other Current Liabilities:	September 30, 2018		December 31, 2017
Accrued interest	$	64.8	$	35.6
Accrued wages and benefits, including taxes	24.8		30.4
Accrued ad valorem taxes	33.4		27.8
Capital expenditure accruals	57.9		48.8
Onerous performance obligations	13.5		15.2
Other	67.0		65.1
Other current liabilities	$	261.4	$	222.9

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General (Details) - shares		9 Months Ended
	Jul. 18, 2018	Sep. 30, 2018
EnLink Midstream Partners, LP
Related Party Transaction [Line Items]
Units owned, limited partner interest (in shares)		88,528,451
Ownership interest		21.40%
Membership interest in the General Partner		0.40%
EnLink Midstream Partners GP, LLC
Related Party Transaction [Line Items]
Ownership interest		100.00%
EnLink Oklahoma T.O.
Related Party Transaction [Line Items]
Ownership interest		16.10%
GIP Stetson I | EnLink Midstream Partners, LP
Related Party Transaction [Line Items]
Membership interest in the General Partner	23.10%
GIP Stetson I | EnLink Midstream Partners GP, LLC
Related Party Transaction [Line Items]
Membership interest in the General Partner	100.00%
GIP Stetson II | ENLC
Related Party Transaction [Line Items]
Membership interest in the General Partner	63.80%

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Significant Accounting Policies - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended			9 Months Ended
	May 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Jan. 01, 2019
Property, Plant and Equipment [Line Items]
Revenues		$ (2,114.3)		$ (1,397.9)	$ (5,640.7)	$ (3,983.4)
Expected gross operating margin from long-term purchase commitment	$ 135.1
Amount due from counterparty due to deficiency on MVC	19.7
Total principal payments to be received	$ 58.0
Financing receivable, interest rate	8.00%
Overriding royalty interest percentage	1.00%
Consideration received due to restructuring of contract			$ 45.5
Expired rights-of-ways and abandoned brine disposal well
Property, Plant and Equipment [Line Items]
Impairment of long-lived assets		24.6		$ 1.8	24.6	$ 8.8
Difference between Revenue Guidance in Effect before and after Topic 606 | Accounting Standards Update 2014-09
Property, Plant and Equipment [Line Items]
Revenues		$ (179.0)			$ (480.0)
Percentage decrease in revenue from contracts with customers		8.00%			8.00%
Scenario, Forecast | Accounting Standards Update 2016-02
Property, Plant and Equipment [Line Items]
Right-of-use asset (less than)							$ 100.0
Lease liability (less than)							$ 100.0

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Significant Accounting Policies - Summary of Changes in Revenue (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	$ 2,119.7		$ 5,660.8
Product sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	1,832.2	$ 1,056.7	4,766.5	$ 2,973.9
Product sales—related parties
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	10.2	35.3	41.0	107.3
Midstream services
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	241.5	136.4	476.1	395.7
Midstream services—related parties
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	35.8	$ 175.0	377.2	$ 507.6
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	(179.0)		(480.0)
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606 | Product sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	(71.0)		(149.0)
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606 | Product sales—related parties
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	(7.0)		(53.0)
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606 | Midstream services
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	(98.0)		(251.0)
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606 | Midstream services—related parties
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contracts with customers	$ (3.0)		$ (27.0)

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Significant Accounting Policies - Summary of Future Performance Obligations (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
Accounting Policies [Abstract]
Expected gross operating margin expected to be recognized in future periods	$ 1,039.1
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Accounting Policies [Abstract]
Expected gross operating margin expected to be recognized in future periods	$ 190.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin expected to be recognized, period	3 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Accounting Policies [Abstract]
Expected gross operating margin expected to be recognized in future periods	$ 237.1
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Accounting Policies [Abstract]
Expected gross operating margin expected to be recognized in future periods	$ 225.7
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Accounting Policies [Abstract]
Expected gross operating margin expected to be recognized in future periods	$ 82.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Accounting Policies [Abstract]
Expected gross operating margin expected to be recognized in future periods	$ 71.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin expected to be recognized, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Accounting Policies [Abstract]
Expected gross operating margin expected to be recognized in future periods	$ 231.2
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Expected gross operating margin expected to be recognized, period

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Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 30.9	$ 31.2	$ 92.6	$ 96.2
Minimum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets			5 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets			20 years
Weighted average
Finite-Lived Intangible Assets [Line Items]
Estimated useful life of intangible assets			15 years

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Intangible Assets - Changes in Carrying Value (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Finite-lived Intangible Assets [Roll Forward]
Accumulated Amortization, Beginning Balance			$ (298.7)
Accumulated Amortization, Amortization expense	$ (30.9)	$ (31.2)	(92.6)	$ (96.2)
Accumulated Amortization, Ending Balance	(391.3)		(391.3)
EnLink Midstream Partners, LP
Finite-lived Intangible Assets [Roll Forward]
Net Carrying Amount, Ending Balance	1,404.5		1,404.5
Customer relationships | EnLink Midstream Partners, LP
Finite-lived Intangible Assets [Roll Forward]
Gross Carrying Amount, Beginning Balance			1,795.8
Accumulated Amortization, Beginning Balance			(298.7)
Net Carrying Amount, Beginning Balance			1,497.1
Accumulated Amortization, Amortization expense			(92.6)
Gross Carrying Amount, Ending Balance	1,795.8		1,795.8
Accumulated Amortization, Ending Balance	(391.3)		(391.3)
Net Carrying Amount, Ending Balance	$ 1,404.5		$ 1,404.5

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Intangible Assets - Amortization Expense (Details) - EnLink Midstream Partners, LP $ in Millions	Sep. 30, 2018 USD ($)
Finite-Lived Intangible Assets [Line Items]
2018 (remaining)	$ 30.9
2019	123.7
2020	123.7
2021	123.7
2022	123.7
Thereafter	878.8
Total	$ 1,404.5

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Related Party Transactions (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended		7 Months Ended	9 Months Ended
		Jul. 18, 2018	Sep. 30, 2018	Sep. 30, 2017	Jul. 18, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Related Party Transaction [Line Items]
Accounts payable to related party			$ 5.0			$ 5.0		$ 16.3
Cost of sales	[1]		1,696.6	$ 1,053.2		4,403.7	$ 2,987.9
Devon Energy Corporation
Related Party Transaction [Line Items]
Accounts receivable balance								102.7
Accounts payable to related party								$ 16.3
Devon Energy Corporation | Customer Concentration Risk | Sales Revenue, Net
Related Party Transaction [Line Items]
Concentration risk		2.00%		15.00%	7.30%		15.40%
Cedar Cove Joint Venture
Related Party Transaction [Line Items]
Accounts receivable balance			0.7			0.7
Accounts payable to related party			5.0			5.0
Cost of sales			$ 11.3	$ 9.5		$ 33.8	$ 15.0

[1] Includes related party cost of sales of $23.0 million and $47.3 million for the three months ended September 30, 2018 and 2017, respectively, and $103.8 million and $126.9 million for the nine months ended September 30, 2018 and 2017, respectively.

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Long-Term Debt - Summary (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	May 31, 2017
Debt Instrument
Outstanding Principal	$ 4,366.4	$ 3,574.6
Premium (Discount)	(6.1)	(6.3)
Long-Term Debt	4,360.3	3,568.3
Debt issuance costs	(23.5)	(26.2)
Less: Current maturities of long-term debt	(500.9)	0.0
Long-term debt, net of unamortized issuance cost	3,835.9	3,542.1
Debt issuance cost accumulated amortization	$ 15.7	12.9
ENLK credit facility due 2020
Debt Instrument
Effective interest rate	4.10%
ENLK credit facility due 2020 | EnLink Midstream Partners, LP
Debt Instrument
Outstanding Principal	$ 765.0	0.0
Premium (Discount)	0.0	0.0
Long-Term Debt	765.0	0.0
ENLC credit facility due 2019
Debt Instrument
Outstanding Principal	101.4	74.6
Premium (Discount)	0.0	0.0
Long-Term Debt	$ 101.4	$ 74.6
Effective interest rate	4.10%	3.20%
ENLK’s 2.70% Senior unsecured notes due 2019
Debt Instrument
Stated interest rate	2.70%
Outstanding Principal	$ 400.0	$ 400.0
Premium (Discount)	(0.1)	(0.1)
Long-Term Debt	$ 399.9	399.9
ENLK’s 4.40% Senior unsecured notes due 2024
Debt Instrument
Stated interest rate	4.40%
Outstanding Principal	$ 550.0	550.0
Premium (Discount)	1.9	2.2
Long-Term Debt	$ 551.9	552.2
ENLK’s 4.15% Senior unsecured notes due 2025
Debt Instrument
Stated interest rate	4.15%
Outstanding Principal	$ 750.0	750.0
Premium (Discount)	(0.9)	(1.0)
Long-Term Debt	$ 749.1	749.0
ENLK’s 4.85% Senior unsecured notes due 2026
Debt Instrument
Stated interest rate	4.85%
Outstanding Principal	$ 500.0	500.0
Premium (Discount)	(0.5)	(0.6)
Long-Term Debt	$ 499.5	499.4
ENLK’s 5.60% Senior unsecured notes due 2044
Debt Instrument
Stated interest rate	5.60%
Outstanding Principal	$ 350.0	350.0
Premium (Discount)	(0.2)	(0.2)
Long-Term Debt	$ 349.8	349.8
ENLK’s 5.05% Senior unsecured notes due 2045
Debt Instrument
Stated interest rate	5.05%
Outstanding Principal	$ 450.0	450.0
Premium (Discount)	(6.2)	(6.5)
Long-Term Debt	$ 443.8	443.5
ENLK's 5.45% Senior unsecured notes due 2047
Debt Instrument
Stated interest rate	5.45%		5.45%
Outstanding Principal	$ 500.0	500.0
Premium (Discount)	(0.1)	(0.1)
Long-Term Debt	$ 499.9	$ 499.9

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Long-Term Debt - Narrative (Details)	9 Months Ended
	Sep. 30, 2018 USD ($) extension subsidiary shares	Dec. 31, 2017 USD ($)
ENLC credit facility due 2019
Debt Instrument
Maximum borrowing capacity	$ 250,000,000.0
Units owned, limited partner interest (in shares) | shares	88,528,451
Membership interest in the General Partner	100.00%
Ownership interest	100.00%
Maximum consolidated leverage ratio	0.0450
Outstanding borrowings	$ 101,400,000	$ 74,600,000
Amount available for future borrowings	148,600,000
ENLC credit facility due 2019 | Letters of credit
Debt Instrument
Outstanding letters of credit	$ 0
ENLC credit facility due 2019 | Maximum
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA	0.0400
ENLC credit facility due 2019 | Minimum
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA	0.0250
ENLC credit facility due 2019 | Letter of Credit
Debt Instrument
Maximum borrowing capacity	$ 125,000,000.0
Number of wholly-owned subsidiaries that are used as the guarantee | subsidiary	2
ENLC credit facility due 2019 | LIBOR | Maximum
Debt Instrument
Variable rate	2.50%
ENLC credit facility due 2019 | LIBOR | Minimum
Debt Instrument
Variable rate	1.75%
ENLC credit facility due 2019 | Federal Funds
Debt Instrument
Variable rate	0.50%
ENLC credit facility due 2019 | Eurodollar
Debt Instrument
Variable rate	1.00%
ENLC credit facility due 2019 | Eurodollar | Maximum
Debt Instrument
Variable rate	1.50%
ENLC credit facility due 2019 | Eurodollar | Minimum
Debt Instrument
Variable rate	0.75%
ENLK credit facility due 2020 | EnLink Midstream Partners, LP
Debt Instrument
Maximum borrowing capacity	$ 1,500,000,000
Ratio of consolidated indebtedness to consolidated EBITDA	0.050
Outstanding borrowings	$ 765,000,000	$ 0
Amount available for future borrowings	725,700,000
Additional amount available (not to exceed)	$ 500,000,000
Number of allowed extensions | extension	2
Extension period	1 year
Conditional acquisition purchase price (or more)	$ 50,000,000.0
ENLK credit facility due 2020 | EnLink Midstream Partners, LP | Letters of credit
Debt Instrument
Maximum borrowing capacity	500,000,000.0
Outstanding letters of credit	$ 9,300,000
ENLK credit facility due 2020 | Maximum | EnLink Midstream Partners, LP
Debt Instrument
Ratio of consolidated indebtedness to consolidated EBITDA	0.055
ENLK credit facility due 2020 | LIBOR | Maximum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate	1.75%
ENLK credit facility due 2020 | LIBOR | Minimum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate	1.00%
ENLK credit facility due 2020 | Federal Funds | EnLink Midstream Partners, LP
Debt Instrument
Variable rate	0.50%
ENLK credit facility due 2020 | Eurodollar | EnLink Midstream Partners, LP
Debt Instrument
Variable rate	1.00%
ENLK credit facility due 2020 | Eurodollar | Maximum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate	0.75%
ENLK credit facility due 2020 | Eurodollar | Minimum | EnLink Midstream Partners, LP
Debt Instrument
Variable rate	0.00%

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Current income tax provision	$ 1.0	$ 0.9	$ 1.9	$ 1.3
Deferred income tax provision	3.0	2.2	15.4	8.0
Total income tax provision	4.0	3.1	17.3	9.3
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Expected income tax provision based on federal statutory rate	2.4	3.3	13.7	6.8
State income taxes expense, net of federal tax benefit	0.3	0.2	1.6	0.5
Income tax expense (benefit) from ENLK	0.9	0.5	(0.2)	0.7
Unit-based compensation	(0.9)	0.0	0.6	2.3
Other	1.3	(0.9)	1.6	(1.0)
Total income tax provision	$ 4.0	$ 3.1	$ 17.3	$ 9.3

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Certain Provisions of the Partnership Agreement - Narrative and Distributions (Details) - USD ($)	3 Months Ended								9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Aug. 31, 2017
Partnership agreement
Proceeds from sale of common units									$ 46,100,000	$ 92,300,000
Distribution declared/unit (in dollars per share)	$ 0.271000000	$ 0.267	$ 0.263	$ 0.259	$ 0.255	$ 0.255	$ 0.255	$ 0.255	$ 0.271000000
Proceeds from issuance of ENLK Series C Preferred Units									$ 0	$ 393,700,000
EnLink Midstream Partners, LP
Partnership agreement
Percentage of available cash to distribute									100.00%
Period after quarter for distribution									45 days
EnLink Midstream Partners, LP | General Partner | Incentive Distribution Level 1
Partnership agreement
Incentive distribution for general partner									13.00%
Incentive distribution, conditional distribution per unit (in dollars per share)									$ 0.25
EnLink Midstream Partners, LP | General Partner | Incentive Distribution Level 2
Partnership agreement
Incentive distribution for general partner									23.00%
Incentive distribution, conditional distribution per unit (in dollars per share)									$ 0.3125
EnLink Midstream Partners, LP | General Partner | Incentive Distribution Level 3
Partnership agreement
Incentive distribution for general partner									48.00%
Incentive distribution, conditional distribution per unit (in dollars per share)									$ 0.375
EnLink Midstream Partners, LP | 2017 EDA
Partnership agreement
Commission fees									$ 500,000
Common units | EnLink Midstream Partners, LP
Partnership agreement
Shelf registration for issuance of common units (up to)											$ 600,000,000.0
Distribution declared/unit (in dollars per share)	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.39
Common units | EnLink Midstream Partners, LP | 2017 EDA
Partnership agreement
Common units sold									2,600,000
Proceeds from sale of common units									$ 46,100,000
Series B Preferred Unitholders
Partnership agreement
Distribution declared/unit (in dollars per share)									$ 0.28125
Distribution paid-in kind (in shares)	422,720.00000	419,678	416,657	413,658	410,681	1,178,672	1,154,147	1,130,131
Proceeds from issuance of ENLK Series C Preferred Units	$ 16,400,000	$ 16,300,000	$ 16,200,000	$ 16,000,000	$ 15,900,000	$ 0	$ 0	$ 0
Series C Preferred Unitholders
Partnership agreement
Distributions to preferred unitholders									$ 12,000,000
Limited Partner | Common units | EnLink Midstream Partners, LP | 2017 EDA
Partnership agreement
Amount of equity security remaining under equity distribution agreement	$ 518,800,000								$ 518,800,000
Limited Partner | Series B Preferred Unitholders
Partnership agreement
Shares issued, price per share (in dollars per share)	$ 15.00								$ 15.00
Limited Partner | Series B Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Annual rate on issue price payable in kind									0.25%
Limited Partner | Series C Preferred Unitholders | EnLink Midstream Partners, LP
Partnership agreement
Partners' capital account, dividend rate, percentage									6.00%

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Certain Provisions of the Partnership Agreement - Allocation of Income (Details) - General Partner - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Incentive distribution
Income allocation for incentive distributions	$ 15.0	$ 14.8	$ 44.6	$ 44.1
Unit-based compensation attributable to ENLC’s restricted and performance units	(7.3)	(4.2)	(15.7)	(16.9)
General Partner share of net income	0.0	0.0	0.6	0.1
General Partner interest in net income	$ 7.7	$ 10.6	$ 29.5	$ 27.3

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Members' Equity - Computation and Distribution Activity (Details) - USD ($) $ / shares in Units, $ in Millions						3 Months Ended								9 Months Ended
	Aug. 14, 2018	May 15, 2018	Nov. 14, 2017	Aug. 14, 2017	May 15, 2017	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
ENLC interest in net income						$ 7.7				$ 6.2				$ 48.1	$ 10.2
Distributed earnings allocated to:
Total distributed earnings						50.0				46.7				147.2	139.9
Undistributed loss allocated to:
Total undistributed loss						(42.3)				(40.5)				(99.1)	(129.7)
Net income allocated to:
Total net income						$ 7.7				$ 6.2				$ 48.1	$ 10.2
Basic and diluted net income per unit:
Basic (in dollars per share)						$ 0.04				$ 0.03				$ 0.27	$ 0.06
Diluted (in dollars per share)						0.04				0.03				0.26	$ 0.06
Distribution declared/unit (in dollars per share)						$ 0.271000000	$ 0.267	$ 0.263	$ 0.259	$ 0.255	$ 0.255	$ 0.255	$ 0.255	$ 0.271000000
Distribution paid per unit (in dollars per share)	$ 0.267000000	$ 0.263000000	$ 0.255000000	$ 0.255000000	$ 0.255000000
Unvested restricted units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
ENLC interest in net income						$ 0.1				$ 0.1				$ 0.7	$ 0.2
Distributed earnings allocated to:
Total distributed earnings						0.9				0.7				2.2	1.9
Undistributed loss allocated to:
Total undistributed loss						(0.8)				(0.6)				(1.5)	(1.7)
Net income allocated to:
Total net income						0.1				0.1				0.7	0.2
Common units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
ENLC interest in net income						7.6				6.1				47.4	10.0
Distributed earnings allocated to:
Total distributed earnings						49.1				46.0				145.0	138.0
Undistributed loss allocated to:
Total undistributed loss						(41.5)				(39.9)				(97.6)	(128.0)
Net income allocated to:
Total net income						$ 7.6				$ 6.1				$ 47.4	$ 10.0

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Members' Equity - Components to Compute Basic and Diluted Earnings per Unit (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Basic weighted average units outstanding:
Weighted average common units outstanding (in shares)	181.2	180.6	181.1	180.4
Diluted weighted average units outstanding:
Weighted average basic common units outstanding (in shares)	181.2	180.6	181.1	180.4
Dilutive effect of non-vested restricted incentive units (in shares)	1.3	1.2	1.1	1.3
Total weighted average diluted common units outstanding (in shares)	182.5	181.8	182.2	181.7

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Investment in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Equity method investments
Distributions	$ 5.3	$ 4.0	$ 16.7	$ 11.4
Equity in income (loss)	4.3	4.4	11.7	5.0
Contributions	0.0	1.5	0.1	11.8
Total investment in unconsolidated affiliates	$ 84.5		$ 84.5		$ 89.4
GCF
Equity method investments
Ownership interest	38.75%		38.75%
Distributions	$ 5.3	3.5	$ 16.4	10.6
Equity in income (loss)	4.6	4.5	14.0	8.5
HEP
Equity method investments
Equity in income (loss)	$ 0.0	0.0	$ 0.0	(3.4)
Cedar Cove JV
Equity method investments
Ownership interest	30.00%		30.00%
Distributions	$ 0.0	0.5	$ 0.3	0.8
Equity in income (loss)	(0.3)	(0.1)	(2.3)	(0.1)
Contributions	0.0	$ 1.5	0.1	$ 11.8
EnLink Midstream Partners, LP
Equity method investments
Total investment in unconsolidated affiliates	84.5		84.5		89.4
EnLink Midstream Partners, LP | GCF
Equity method investments
Total investment in unconsolidated affiliates	46.0		46.0		48.4
EnLink Midstream Partners, LP | Cedar Cove JV
Equity method investments
Total investment in unconsolidated affiliates	$ 38.5		$ 38.5		$ 41.0

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Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Allocation
Compensation expense	$ 17.1	$ 10.2	$ 31.8	$ 38.9
Amount of related income tax benefit recognized in net income	2.2	2.4	4.1	9.1
Tax expense excluded from income tax benefit	(0.9)	0.0	0.6	2.3
Cost of unit-based compensation charged to operating expense
Allocation
Compensation expense	5.2	2.8	9.5	10.4
Cost of unit-based compensation charged to general and administrative expense
Allocation
Compensation expense	11.9	7.4	22.3	28.5
Non-controlling interest in unit-based compensation
Allocation
Compensation expense	$ 6.6	$ 3.9	$ 12.1	$ 14.6

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Employee Incentive Plans - Restricted and Performance Awards (Details) - USD ($) $ / shares in Units, $ in Millions			1 Months Ended	3 Months Ended		9 Months Ended
	Jul. 23, 2018	Jul. 18, 2018	Mar. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Restricted incentive units
Number of Units
Non-vested, beginning of period (in shares)						1,889,310
Granted (in shares)			194,185			1,469,452
Vested (in shares)						(749,164)
Forfeited (in shares)						(146,045)
Non-vested, end of period (in shares)				2,463,553		2,463,553
Aggregate intrinsic value, end of period				$ 40.5		$ 40.5
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)						$ 16.33
Granted (in dollars per share)						15.76
Vested (in dollars per share)						21.53
Forfeited (in dollars per share)						12.38
Non-vested, end of period (in dollars per share)				$ 14.64		$ 14.64
Vesting period						3 years
Fair value of units vested			$ 3.0	$ 2.6	$ 1.1	$ 16.1	$ 21.9
Units withheld for payroll taxes (in shares)						238,970
Aggregate intrinsic value of units vested				3.3	0.6	$ 12.6	15.2
Unrecognized compensation cost related to non-vested restricted incentive units				$ 21.5		$ 21.5
Unrecognized compensation costs, weighted average period for recognition						2 years
Restricted incentive units | EnLink Midstream Partners, LP
Number of Units
Non-vested, beginning of period (in shares)						1,980,224
Granted (in shares)			200,753			1,586,750
Vested (in shares)						(813,290)
Forfeited (in shares)						(157,057)
Non-vested, end of period (in shares)				2,596,627		2,596,627
Aggregate intrinsic value, end of period				$ 48.4		$ 48.4
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)						$ 15.81
Granted (in dollars per share)						15.27
Vested (in dollars per share)						19.78
Forfeited (in dollars per share)						12.42
Non-vested, end of period (in dollars per share)				$ 14.44		$ 14.44
Vesting period						3 years
Fair value of units vested			$ 3.0	$ 2.8	1.1	$ 16.1	22.1
Units withheld for payroll taxes (in shares)						255,653
Aggregate intrinsic value of units vested				3.7	$ 0.6	$ 12.8	$ 16.3
Unrecognized compensation cost related to non-vested restricted incentive units				$ 22.2		$ 22.2
Unrecognized compensation costs, weighted average period for recognition						2 years
Performance units
Number of Units
Non-vested, beginning of period (in shares)						548,839
Granted (in shares)						223,865
Vested (in shares)		(109,819)			0	(283,637)	0
Forfeited (in shares)						(70,918)
Non-vested, end of period (in shares)				418,149		418,149
Aggregate intrinsic value, end of period				$ 6.9		$ 6.9
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)						$ 22.14
Granted (in dollars per share)						21.63
Vested (in dollars per share)						27.25
Forfeited (in dollars per share)						17.75
Non-vested, end of period (in dollars per share)				$ 19.15		$ 19.15
Vesting period						3 years
Fair value of units vested				$ 3.5		$ 7.7
Units withheld for payroll taxes (in shares)						100,109
Aggregate intrinsic value of units vested				2.8		$ 4.7
Unrecognized compensation cost related to non-vested restricted incentive units				6.0		$ 6.0
Unrecognized compensation costs, weighted average period for recognition						1 year 10 months
Compensation expense not yet recognized				$ 2.3		$ 2.3
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Beginning TSR Price (in dollars per share)			$ 16.55
Risk-free interest rate			2.38%
Volatility factor			51.36%
Distribution yield			6.70%
Performance units | Minimum
Weighted Average Grant-Date Fair Value
Percent of units vesting	0.00%					0.00%
Performance units | Maximum
Weighted Average Grant-Date Fair Value
Percent of units vesting	100.00%					200.00%
Performance units | EnLink Midstream Partners, LP
Number of Units
Non-vested, beginning of period (in shares)						585,285
Granted (in shares)						256,345
Vested (in shares)		(120,250)			0	(313,610)	0
Forfeited (in shares)						(76,351)
Non-vested, end of period (in shares)				451,669		451,669
Aggregate intrinsic value, end of period				$ 8.4		$ 8.4
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period (in dollars per share)						$ 20.52
Granted (in dollars per share)						19.24
Vested (in dollars per share)						24.43
Forfeited (in dollars per share)						16.62
Non-vested, end of period (in dollars per share)				$ 17.74		$ 17.74
Vesting period						3 years
Fair value of units vested				$ 3.6		$ 7.7
Units withheld for payroll taxes (in shares)						112,101
Aggregate intrinsic value of units vested				3.0		$ 5.0
Unrecognized compensation cost related to non-vested restricted incentive units				6.2		$ 6.2
Unrecognized compensation costs, weighted average period for recognition						1 year 10 months
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Beginning TSR Price (in dollars per share)			$ 15.44
Risk-free interest rate			2.38%
Volatility factor			43.85%
Distribution yield			10.50%
Performance units | EnLink Midstream Partners, LP | Minimum
Weighted Average Grant-Date Fair Value
Percent of units vesting						0.00%
Performance units | EnLink Midstream Partners, LP | Maximum
Weighted Average Grant-Date Fair Value
Percent of units vesting						200.00%
Performance units | ENLC
Weighted Average Grant-Date Fair Value
Compensation expense not yet recognized				$ 2.1		$ 2.1
Performance units | ENLC | Minimum
Weighted Average Grant-Date Fair Value
Percent of units vesting						0.00%
Performance units | ENLC | Maximum
Weighted Average Grant-Date Fair Value
Percent of units vesting	100.00%

XML

Derivatives - Interest Rate Swaps (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	May 31, 2017
Derivatives
Accumulated other comprehensive loss	$ 2.0	$ 2.0	$ 2.2
Interest income (expense) expected to be reclassified out of accumulated other comprehensive income (loss) over the next twelve months	$ (0.1)
ENLK's 5.45% Senior unsecured notes due 2047
Derivatives
Stated interest rate	5.45%		5.45%

XML

Derivatives - Components of Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivatives
Loss on derivative activity	$ (5.4)	$ (5.5)	$ (20.1)	$ (1.1)
EnLink Midstream Partners, LP | Commodity Swaps
Derivatives
Change in fair value of derivatives	(0.8)	(3.3)	(14.8)	3.8
Realized loss on derivatives	(4.6)	(2.2)	(5.3)	(4.9)
Loss on derivative activity	$ (5.4)	$ (5.5)	$ (20.1)	$ (1.1)

XML

Derivatives - Fair Value of Assets and Liabilities (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Derivatives
Fair value of derivative assets—current	$ 12,500,000	$ 6,800,000
Fair value of derivative liabilities—current	(21,900,000)	(8,400,000)
Fair value of derivative liabilities—long-term	(7,000,000)	0
EnLink Midstream Partners, LP
Derivatives
Fair value of derivative assets—current	12,500,000	6,800,000
Fair value of derivative liabilities—current	(21,900,000)	(8,400,000)
Fair value of derivative liabilities—long-term	(7,000,000)	0
Net fair value of derivatives	(16,400,000)	(1,600,000)
Fair value of derivative assets — long-term	$ 0	$ 0

XML

Derivatives - Commodities (Details) - EnLink Midstream Partners, LP gal in Millions, MMBbls in Millions, MMBTU in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($) MMBTU gal MMBbls	Dec. 31, 2017 USD ($)
Derivatives
Fair Value	$ (16.4)	$ (1.6)
Commodity
Derivatives
Fair Value	(16.4)
Maximum loss if counterparties fail to perform	12.5
Possible reduction in maximum loss if counterparties fail to perform	$ 0.1
Commodity | NGL | Short
Derivatives
Notional amount (in gallons and mmbls) | gal	58.4
Fair Value	$ (12.0)
Commodity | NGL | Long
Derivatives
Notional amount (in gallons and mmbls) | gal	18.9
Fair Value	$ 3.1
Commodity | Natural Gas | Short
Derivatives
Notional amount (in mmbtu) | MMBTU	9.0
Fair Value	$ 0.4
Commodity | Natural Gas | Long
Derivatives
Notional amount (in mmbtu) | MMBTU	10.9
Fair Value	$ (1.4)
Commodity | Crude and condensate | Short
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	13.3
Fair Value	$ (13.2)
Commodity | Crude and condensate | Long
Derivatives
Notional amount (in gallons and mmbls) | MMBbls	1.3
Fair Value	$ 6.7

XML

Fair Value Measurements - Recurring (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Level 2 | Commodity Swaps | Recurring
Fair Value
Fair Value	$ (16.4)	$ (1.6)

XML

Fair Value Measurements - Financial Instruments (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Fair Value
Debt issuance costs, noncurrent	$ 23,500,000	$ 26,200,000
ENLC credit facility due 2019
Fair Value
Outstanding borrowings	101,400,000	74,600,000
EnLink Midstream Partners, LP
Fair Value
Senior unsecured debt	$ 3,500,000,000	$ 3,500,000,000
EnLink Midstream Partners, LP | Minimum
Fair Value
Stated interest rate	2.70%	2.70%
EnLink Midstream Partners, LP | Maximum
Fair Value
Stated interest rate	5.60%	5.60%
EnLink Midstream Partners, LP | ENLK credit facility due 2020
Fair Value
Outstanding borrowings	$ 765,000,000	$ 0
EnLink Midstream Partners, LP | Carrying Value
Fair Value
Long-term debt, including current maturities of long-term debt	4,336,800,000	3,542,100,000
Installment Payables	0	249,500,000
Obligations under capital lease	2,900,000	4,100,000
Secured term loan receivable	49,900,000	0
EnLink Midstream Partners, LP | Fair Value
Fair Value
Long-term debt, including current maturities of long-term debt	4,119,000,000	3,650,200,000
Installment Payables	0	249,600,000
Obligations under capital lease	2,500,000	3,400,000
Secured term loan receivable	$ 49,900,000	$ 0

XML

Segment Information - Financial Information and Assets (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Segment Reporting
Revenue from contracts with customers		$ 2,119.7		$ 5,660.8
Cost of sales	[1]	(1,696.6)	$ (1,053.2)	(4,403.7)	$ (2,987.9)
Operating expenses		(114.7)	(102.1)	(337.3)	(308.8)
Loss on derivative activity		(5.4)	(5.5)	(20.1)	(1.1)
Segment profit (loss)		303.0	242.6	899.7	686.7
Depreciation and amortization		(146.7)	(136.3)	(430.1)	(407.1)
Impairments		(24.6)	(1.8)	(24.6)	(8.8)
Goodwill		1,542.2	1,542.2	1,542.2	1,542.2	$ 1,542.2
Capital expenditures		253.3	169.7	652.7	636.3
Total identifiable assets		11,198.3		11,198.3		10,537.8
Corporate
Segment Reporting
Revenue from contracts with customers		(380.1)		(927.9)
Cost of sales		380.1	235.3	927.9	589.9
Operating expenses		0.0	0.0	0.0	0.0
Loss on derivative activity		(5.4)	(5.5)	(20.1)	(1.1)
Segment profit (loss)		(5.4)	(5.5)	(20.1)	(1.1)
Depreciation and amortization		(2.4)	(2.6)	(6.6)	(7.3)
Impairments		0.0	0.0	0.0	0.0
Goodwill		1,119.9	1,119.9	1,119.9	1,119.9
Capital expenditures		1.1	2.1	3.4	25.6
Total identifiable assets		1,308.6		1,308.6		1,268.3
Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		385.6		1,035.5
Cost of sales		(222.0)	(198.5)	(562.2)	(554.7)
Operating expenses		(44.7)	(41.1)	(134.7)	(127.9)
Loss on derivative activity		0.0	0.0	0.0	0.0
Segment profit (loss)		118.9	107.6	338.6	314.6
Depreciation and amortization		(54.0)	(52.5)	(159.9)	(161.9)
Impairments		0.0	0.0	0.0	0.0
Goodwill		232.0	232.0	232.0	232.0
Capital expenditures		90.0	39.1	200.0	107.1
Total identifiable assets		3,161.9		3,161.9		3,094.8
Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		1,010.5		2,592.6
Cost of sales		(923.6)	(662.7)	(2,333.3)	(1,803.1)
Operating expenses		(28.7)	(24.8)	(82.3)	(74.8)
Loss on derivative activity		0.0	0.0	0.0	0.0
Segment profit (loss)		58.2	51.0	177.0	143.1
Depreciation and amortization		(32.7)	(29.3)	(92.4)	(86.8)
Impairments		(24.6)	0.0	(24.6)	0.0
Goodwill		0.0	0.0	0.0	0.0
Capital expenditures		13.0	7.5	36.4	55.8
Total identifiable assets		2,583.8		2,583.8		2,408.5
Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		358.0		955.9
Cost of sales		(228.5)	(148.2)	(537.8)	(335.9)
Operating expenses		(22.5)	(17.1)	(64.0)	(45.9)
Loss on derivative activity		0.0	0.0	0.0	0.0
Segment profit (loss)		107.0	79.1	354.1	201.3
Depreciation and amortization		(44.7)	(40.2)	(133.2)	(115.3)
Impairments		0.0	0.0	0.0	0.0
Goodwill		190.3	190.3	190.3	190.3
Capital expenditures		109.3	107.7	328.8	383.4
Total identifiable assets		3,074.1		3,074.1		2,836.7
Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		745.7		2,004.7
Cost of sales		(702.6)	(279.1)	(1,898.3)	(884.1)
Operating expenses		(18.8)	(19.1)	(56.3)	(60.2)
Loss on derivative activity		0.0	0.0	0.0	0.0
Segment profit (loss)		24.3	10.4	50.1	28.8
Depreciation and amortization		(12.9)	(11.7)	(38.0)	(35.8)
Impairments		0.0	(1.8)	0.0	(8.8)
Goodwill		0.0	0.0	0.0	0.0
Capital expenditures		39.9	13.3	84.1	64.4
Total identifiable assets		1,069.9		1,069.9		$ 929.5
Product sales
Segment Reporting
Revenue from contracts with customers		1,832.2	1,056.7	4,766.5	2,973.9
Product sales | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0	0.0	0.0
Product sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		85.9	80.8	225.7	240.5
Product sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		969.2	642.3	2,453.3	1,735.5
Product sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		55.0	42.5	146.5	84.7
Product sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		722.1	291.1	1,941.0	913.2
Product sales, Natural gas sales
Segment Reporting
Revenue from contracts with customers		240.5		714.0
Product sales, Natural gas sales | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, Natural gas sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		69.1		208.9
Product sales, Natural gas sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		129.5		377.2
Product sales, Natural gas sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		41.9		127.9
Product sales, Natural gas sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, NGL sales
Segment Reporting
Revenue from contracts with customers		869.3		2,111.9
Product sales, NGL sales | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, NGL sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		16.8		16.8
Product sales, NGL sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		839.6		2,075.9
Product sales, NGL sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		12.8		18.3
Product sales, NGL sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.9
Product sales, Crude oil and condensate sales
Segment Reporting
Revenue from contracts with customers		722.4		1,940.6
Product sales, Crude oil and condensate sales | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, Crude oil and condensate sales | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, Crude oil and condensate sales | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.2
Product sales, Crude oil and condensate sales | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.3		0.3
Product sales, Crude oil and condensate sales | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		722.0		1,940.1
Product sales—related parties
Segment Reporting
Revenue from contracts with customers		10.2	35.3	41.0	107.3
Product sales—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		(380.1)	(199.9)	(927.9)	(493.1)
Product sales—related parties | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		167.2	130.6	420.5	352.6
Product sales—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		11.0	10.0	45.7	25.6
Product sales—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		210.6	94.6	499.4	221.4
Product sales—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		1.5	0.0	3.3	0.8
Product sales, Natural gas sales, related party
Segment Reporting
Revenue from contracts with customers		0.1		2.5
Product sales, Natural gas sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, Natural gas sales, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, Natural gas sales, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, Natural gas sales, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		2.5
Product sales, Natural gas sales, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, NGL sales, related party
Segment Reporting
Revenue from contracts with customers		10.0		37.4
Product sales, NGL sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		(347.2)		(822.1)
Product sales, NGL sales, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		153.8		381.1
Product sales, NGL sales, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		10.9		45.4
Product sales, NGL sales, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		192.5		433.0
Product sales, NGL sales, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Product sales, Crude oil and condensate sales, related party
Segment Reporting
Revenue from contracts with customers		0.1		1.1
Product sales, Crude oil and condensate sales, related party | Corporate
Segment Reporting
Revenue from contracts with customers		(32.9)		(105.8)
Product sales, Crude oil and condensate sales, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		13.4		39.4
Product sales, Crude oil and condensate sales, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.3
Product sales, Crude oil and condensate sales, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		18.0		63.9
Product sales, Crude oil and condensate sales, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		1.5		3.3
Midstream services
Segment Reporting
Revenue from contracts with customers		241.5	136.4	476.1	395.7
Midstream services | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	0.0	0.0	0.0
Midstream services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		113.5	29.1	157.5	85.1
Midstream services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		30.3	50.3	93.6	159.7
Midstream services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		81.9	44.3	179.5	105.2
Midstream services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		15.8	12.7	45.5	45.7
Midstream services, Gathering and transportation
Segment Reporting
Revenue from contracts with customers		140.2		244.1
Midstream services, Gathering and transportation | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Gathering and transportation | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		71.7		98.4
Midstream services, Gathering and transportation | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		17.5		51.8
Midstream services, Gathering and transportation | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		50.2		91.4
Midstream services, Gathering and transportation | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.8		2.5
Midstream services, Processing
Segment Reporting
Revenue from contracts with customers		71.7		143.1
Midstream services, Processing | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Processing | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		39.4		52.7
Midstream services, Processing | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.8		2.5
Midstream services, Processing | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		31.5		87.9
Midstream services, Processing | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, NGL services
Segment Reporting
Revenue from contracts with customers		11.9		38.8
Midstream services, NGL services | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, NGL services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, NGL services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		11.9		38.8
Midstream services, NGL services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, NGL services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Crude services
Segment Reporting
Revenue from contracts with customers		15.1		43.0
Midstream services, Crude services | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Crude services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Crude services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Crude services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.2		0.2
Midstream services, Crude services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		14.9		42.8
Midstream services, Other services
Segment Reporting
Revenue from contracts with customers		2.6		7.1
Midstream services, Other services | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Other services | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		2.4		6.4
Midstream services, Other services | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.5
Midstream services, Other services | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Other services | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.2
Midstream services—related parties
Segment Reporting
Revenue from contracts with customers		35.8	175.0	377.2	507.6
Midstream services—related parties | Corporate
Segment Reporting
Revenue from contracts with customers		0.0	(35.4)	0.0	(96.8)
Midstream services—related parties | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		19.0	106.7	231.8	319.0
Midstream services—related parties | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0	35.9	0.0	100.2
Midstream services—related parties | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		10.5	63.0	130.5	171.8
Midstream services—related parties | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		6.3	$ 4.8	14.9	$ 13.4
Midstream services, Gathering and transportation, related party
Segment Reporting
Revenue from contracts with customers		15.9		203.3
Midstream services, Gathering and transportation, related party | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Gathering and transportation, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		8.7		122.7
Midstream services, Gathering and transportation, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Gathering and transportation, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		7.2		80.6
Midstream services, Gathering and transportation, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Processing, related party
Segment Reporting
Revenue from contracts with customers		13.4		157.0
Midstream services, Processing, related party | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Processing, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		10.2		108.6
Midstream services, Processing, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Processing, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		3.2		48.4
Midstream services, Processing, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Crude services, related party
Segment Reporting
Revenue from contracts with customers		6.4		16.4
Midstream services, Crude services, related party | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Crude services, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Crude services, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Crude services, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		1.5
Midstream services, Crude services, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		6.3		14.9
Midstream services, Other services, related party
Segment Reporting
Revenue from contracts with customers		0.1		0.5
Midstream services, Other services, related party | Corporate
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Other services, related party | Texas | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.1		0.5
Midstream services, Other services, related party | Louisiana | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Other services, related party | Oklahoma | Operating Segments
Segment Reporting
Revenue from contracts with customers		0.0		0.0
Midstream services, Other services, related party | Crude and Condensate | Operating Segments
Segment Reporting
Revenue from contracts with customers		$ 0.0		$ 0.0

[1] Includes related party cost of sales of $23.0 million and $47.3 million for the three months ended September 30, 2018 and 2017, respectively, and $103.8 million and $126.9 million for the nine months ended September 30, 2018 and 2017, respectively.

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Segment Information - Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting [Abstract]
Segment profit	$ 303.0	$ 242.6	$ 899.7	$ 686.7
General and administrative expenses	(41.9)	(31.3)	(99.8)	(98.5)
Loss on disposition of assets	0.0	(1.1)	(1.3)	(0.8)
Depreciation and amortization	(146.7)	(136.3)	(430.1)	(407.1)
Impairments	(24.6)	(1.8)	(24.6)	(8.8)
Gain on litigation settlement	0.0	0.0	0.0	26.0
Operating income	$ 89.8	$ 72.1	$ 343.9	$ 197.5

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Other Information (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Other Current Assets:
Natural gas and NGLs inventory	$ 119,400,000	$ 30,100,000
Secured term loan receivable from contract restructuring, net of discount of $1.1	18,400,000	0
Secured term loan receivable, discount	1,100,000	0
Prepaid expenses and other	17,300,000	11,100,000
Natural gas and NGLs inventory, prepaid expenses, and other	155,100,000	41,200,000
Other Current Liabilities:
Accrued interest	64,800,000	35,600,000
Accrued wages and benefits, including taxes	24,800,000	30,400,000
Accrued ad valorem taxes	33,400,000	27,800,000
Capital expenditure accruals	57,900,000	48,800,000
Onerous performance obligations	13,500,000	15,200,000
Other	67,000,000	65,100,000
Other current liabilities	$ 261,400,000	$ 222,900,000

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Subsequent Event (Details)	Oct. 21, 2018
Subsequent Event
Subsequent Event [Line Items]
Common units conversion ratio	1.15