EnLink Midstream, LLC - Quarter Report: 2014 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

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

for the quarterly period ended September 30, 2014

o 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.)

2501 CEDAR SPRINGS
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 x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-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 x No o

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



Large accelerated filer x		Accelerated filer o

Non-accelerated filer o		Smaller reporting company o
(Do not check if a smaller reporting company)

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

As of October 24, 2014, the Registrant had 164,045,868 common units outstanding.

TABLE OF CONTENTS



Item	Description	Page

	PART I—FINANCIAL INFORMATION

1.	Financial Statements	3

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

3.	Quantitative and Qualitative Disclosures About Market Risk	56

4.	Controls and Procedures	58

	PART II—OTHER INFORMATION

1.	Legal Proceedings	59

1A.	Risk Factors	59

6.	Exhibits	60

ENLINK MIDSTREAM, LLC

Condensed Consolidated Balance Sheets



	September 30, 2014		December 31, 2013
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	39.5	$	—
Accounts receivable:
Trade, net of allowance for bad debt	49.0		0.4
Accrued revenue and other	220.6		—
Related party	113.3		—
Fair value of derivative assets	1.1		—
Natural gas and natural gas liquids inventory, prepaid expenses and other	57.3		5.8
Assets held for disposition	—		72.7
Total current assets	480.8		78.9
Property and equipment, net of accumulated depreciation of $1,349.8 and $1,169.8, respectively	4,523.4		1,768.1
Fair value of derivative assets	0.2		—
Intangible assets, net of accumulated amortization of $24.4	522.7		—
Goodwill	3,694.6		401.7
Investments in unconsolidated affiliates	276.1		61.1
Other assets, net	30.0		—
Total assets	$	9,527.8	$	2,309.8

LIABILITIES AND MEMBERS' EQUITY
Current liabilities:
Accounts payable, drafts payable and other	$	37.3	$	1.7
Related party payables	3.8		—
Accrued gas and crude oil purchases	198.4		—
Fair value of derivative liabilities	0.9		—
Accrued capital expenditures	35.6		—
Contract liability	21.2		—
Other current liabilities	91.4		38.7
Accrued interest	30.9		—
Liabilities held for disposition	—		37.0
Total current liabilities	419.5		77.4
Long-term debt	1,853.9		—
Fair value of derivative liabilities	0.6		—
Asset retirement obligation	10.8		7.7
Other long-term liabilities	88.1		—
Deferred tax liability	497.0		440.9
Members’ equity	6,657.9		1,783.8
Total liabilities and members’ equity	$	9,527.8	$	2,309.8

See accompanying notes to condensed consolidated financial statements.

ENLINK MIDSTREAM, LLC

Condensed Consolidated Statements of Operations



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(Unaudited) (In millions, except per unit amounts)
Revenues:
Revenues	$	647.7		$	46.8		$	1,635.2		$	136.1
Revenues - affiliates	206.3			531.4			872.0			1,557.0
Gain (loss) on derivative activity	1.0			—			(1.9		)	—
Total revenues	855.0			578.2			2,505.3			1,693.1
Operating costs and expenses:
Purchased gas, NGLs, condensate and crude oil (1)	597.2			435.5			1,798.0			1,279.6
Operating expenses (2)	76.7			35.8			195.5			116.0
General and administrative (3)	24.5			10.8			66.9			32.3
Depreciation and amortization	73.4			48.0			195.8			138.6
Gain on litigation settlement	(6.1		)	—			(6.1		)	—
Total operating costs and expenses	765.7			530.1			2,250.1			1,566.5
Operating income	89.3			48.1			255.2			126.6
Other income (expense):
Interest expense, net of interest income	(13.6		)	—			(33.1		)	—
Income from equity investments	5.6			5.8			14.3			10.2
Gain on extinguishment of debt	2.4			—			3.2			—
Other income (expense)	0.1			—			(0.7		)	—
Total other income (expense)	(5.5		)	5.8			(16.3		)	10.2
Income from continuing operations before non-controlling interest and income taxes	83.8			53.9			238.9			136.8
Income tax provision	(17.3		)	(19.3		)	(59.5		)	(49.2		)
Net income from continuing operations	66.5			34.6			179.4			87.6
Discontinued operations:
Income (loss) from discontinued operations, net of tax	—			(4.0		)	1.0			6.3
Income from discontinued operations attributable to non-controlling interest, net of tax	—			0.3			—			1.4
Discontinued operations, net of tax	—			(4.3		)	1.0			4.9
Net income	66.5			30.3			180.4			92.5
Net income attributable to the non-controlling interest	37.7			—			80.5			—
Net income attributable to EnLink Midstream, LLC	$	28.8		$	30.3		$	99.9		$	92.5
Predecessor interest in net income (4)	$	—		$	30.3		$	35.5		$	92.5
EnLink Midstream, LLC interest in net income	$	28.8		$	—		$	64.4		$	—
Net income attributable to EnLink Midstream, LLC per unit:
Basic per common unit	$	0.18		$	—		$	0.39		$	—
Diluted per common unit	$	0.17		$	—		$	0.39		$	—

(1) Includes $24.1 million and $397.8 million for the three months ended September 30, 2014 and 2013, respectively, and $349.9 million and $1,170.4 million for the nine months ended September 30, 2014 and 2013, respectively, of affiliate purchased gas, NGLs, condensate and crude oil.

(2) Includes $8.9 million for the three months ended September 30, 2013 and $5.9 million and $26.9 million for the nine months ended September 30, 2014 and 2013, respectively, of affiliate operating expenses.

(3) Includes $1.0 million and $10.8 million for the three months ended September 30, 2014 and 2013, respectively, and $10.6 million and $32.3 million for the nine months ended September 30, 2014 and 2013, respectively, of affiliate general and administrative expenses.

(4) Represents net income attributable to the Predecessor for the periods prior to March 7, 2014.

See accompanying notes to condensed consolidated financial statements.

ENLINK MIDSTREAM, LLC

Consolidated Statement of Changes in Members’ Equity

Nine Months Ended September 30, 2014



	Common Units				Predecessor Equity			Non-Controlling Interest
	$			Units	$			$			Total
	(Unaudited)
	(In millions)
Balance, December 31, 2013	$	—		—	$	1,783.8		$	—		$	1,783.8
Distributions to the Predecessor	—			—	(95.0		)	—			(95.0		)
Issuance of units for reorganization of predecessor equity	929.3			115.5	(1,724.3		)	795.0			—
Issuance of common units for acquisition of Company	1,822.5			48.5	—			2,841.1			4,663.6
Elimination of deferred taxes attributable to non-controlling interest in predecessor equity	—			—	—			215.5			215.5
Change in equity due to issuance of units by the Partnership	—			—	—			71.9			71.9
Conversion of restricted stock for common, net of shares withheld for taxes	(1.0		)	—	—			—			(1.0		)
Non-controlling partner's impact of conversion of restricted units and option exercises	—			—	—			(0.1		)	(0.1		)
Unit-based compensation	6.9			—	—			5.9			12.8
Distributions to members	(51.0		)	—	—			—			(51.0		)
Distributions to non-controlling interest	—			—	—			(124.2		)	(124.2		)
Contribution by non-controlling interest	—			—	—			1.2			1.2
Net income	64.4			—	35.5			80.5			180.4
Balance, September 30, 2014	$	2,771.1		164.0	$	—		$	3,886.8		$	6,657.9

See accompanying notes to condensed consolidated financial statements.

ENLINK MIDSTREAM, LLC

Consolidated Statements of Cash Flows



	Nine Months Ended September 30,
	2014			2013
	(Unaudited) (In millions)
Cash flows from operating activities:
Net income from continuing operations	$	179.4		$	87.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	195.8			138.6
Accretion expense	0.4			0.3
Gain on extinguishment of debt	(3.2		)	—
Deferred tax expense (benefit)	53.7			10.8
Non-cash stock-based compensation	12.8			—
Loss on derivatives recognized in net income	1.9			—
Cash paid on derivatives	(1.7		)	—
Amortization of debt issue costs	0.8			—
Amortization of premium on notes	(1.7		)	—
Distribution of earnings from equity investment	6.3			10.9
Income from equity investment	(14.3		)	(10.2		)
Changes in assets and liabilities:
Accounts receivable, accrued revenue and other	26.2			—
Natural gas and natural gas liquids, prepaid expenses and other	(27.0		)	(1.1		)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities	(67.4		)	8.1
Net cash provided by operating activities	362.0			245.0
Cash flows from investing activities:
Additions to property and equipment	(511.8		)	(201.3		)
Acquisition of business	(51.9		)	—
Deposit for acquisition	(23.5		)	—
Investment in equity investment company	(5.7		)	—
Distribution from equity investment company in excess of earnings	7.6			1.1
Net cash used in investing activities	(585.3		)	(200.2		)
Cash flows from financing activities:
Proceeds from borrowings	2,170.3			—
Payments on borrowings	(1,765.2		)	—
Payments on capital lease obligations	(1.8		)	—
Increase in drafts payable	(2.6		)	—
Debt refinancing costs	(7.5		)	—
Proceeds from issuance of Partnership units	71.9			—
Proceeds from exercise of Partnership unit options	0.4			—
Conversion of restricted stock for common, net of shares withheld for taxes	(1.0		)	—
Conversion of Partnerships restricted units for common, net of shares withheld for taxes	(0.5		)	—
Distributions to members	(51.0		)	—
Distributions to Predecessor	(27.2		)	(117.7		)
Distributions to non-controlling interest	(124.2		)	—
Contribution by non-controlling interest	1.2			—
Net cash provided by (used in) financing activities	262.8			(117.7		)
Cash flow from discontinued operations:
Net cash provided by operating activities	5.0			11.2
Net cash used in investing activities	(0.6		)	143.7
Net cash used in financing activities – net distributions to Devon and non-controlling interests	(4.4		)	(97.6		)
Net cash provided by discontinued operations	—			57.3
Net increase (decrease) in cash and cash equivalents	39.5			(15.6		)
Cash and cash equivalents, beginning of period	—			15.6
Cash and cash equivalents, end of period	$	39.5		$	—
Cash paid for interest	$	19.9		$	—
Cash paid for income taxes	$	7.4		$	—

See accompanying notes to condensed consolidated financial statements.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements

September 30, 2014

(Unaudited)

(1) General

In this report, the terms “Company” or “Registrant” as well as the terms “ENLC,” “our,” “we,” and “us,” or like terms, are sometimes used as references to EnLink Midstream, LLC and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including EnLink Midstream Operating, LP and Midstream Holdings, together with their consolidated subsidiaries. “Midstream Holdings” is sometimes used to refer to EnLink Midstream Holdings, LP itself or to EnLink Midstream Holdings, LP together with EnLink Midstream Holdings GP, LLC and their subsidiaries.

(a)Organization of Business

EnLink Midstream, LLC is a Delaware limited liability company formed in October 2013. Effective as of March 7, 2014, EnLink Midstream, Inc. (formerly known as Crosstex Energy, Inc.) (“EMI”) merged with and into a wholly-owned subsidiary of the Company and Acacia Natural Gas Corp I, Inc. (“New Acacia”), formerly a wholly-owned subsidiary of Devon Energy Corporation (“Devon”), merged with and into a wholly-owned subsidiary of the Company (collectively, the “mergers”). Pursuant to the mergers, each of EMI and New Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. EMI owns common units representing an approximate 7% limited partner interest in the Partnership as of September 30, 2014 and also owns EnLink Midstream Partners GP, LLC (formerly known as Crosstex Energy GP, LLC) (the “General Partner”). New Acacia directly owns a 50% limited partner interest in Midstream Holdings. Midstream Holdings formerly was a wholly-owned subsidiary of Devon. Upon closing of the business combination (as defined below), ENLC issued 115,495,669 Class B Units ("Class B Units") to a wholly-owned subsidiary of Devon, which represents approximately 70% of the outstanding limited liability company interests in ENLC. The Class B units converted to common units on May 6, 2014.

Concurrently with the consummation of the mergers, a wholly-owned subsidiary of the Partnership acquired the remaining 50% of the outstanding limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the mergers, the “business combination”). The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.”

Our assets consist of equity interests in the Partnership, Midstream Holdings, E2 Energy Services, LLC and E2 Appalachian Compression, LLC (collectively, “E2”). The Partnership is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. Midstream Holdings is a partnership held by us and the Partnership and is engaged in the gathering, transmission and processing of natural gas. E2 is a services company focused on the Utica Shale play in the Ohio River Valley. As of September 30, 2014, our interests in the Partnership, Midstream Holdings and E2 consist of the following:


•	16,414,830 common units representing an aggregate 7% limited partner interest in the Partnership;


•	100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership, which owns a 0.7% general partner interest and all of the incentive distribution rights in the Partnership;


•	50.0% limited partner interest in Midstream Holdings; and


•	89.8% interest in E2 Energy Services, LLC and a 90.6% interest in E2 Appalachian Compression, LLC, with the remainder owned by E2 management.

(b) Nature of Business

The Company primarily focuses on providing midstream energy services, including gathering, transmission, processing, fractionation and marketing, to producers of natural gas, NGLs, crude oil and condensate. The Company also provides crude oil, condensate and brine services to producers. The Company connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. The Company purchases

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines. The Company operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of fee arrangements. The Company provides a variety of crude oil and condensate services throughout the Ohio River Valley (“ORV”), which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks and brine disposal. The Company also has crude oil and condensate terminal facilities in south Louisiana that provide access for crude oil and condensate producers to the premium markets in this area. The Company's gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. The Company's transmission pipelines primarily receive natural gas from its gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. The Company also has transmission lines that transport NGLs from east Texas and its south Louisiana processing plants to its fractionators in south Louisiana. The Company's crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a fee, transport oil from a producer site to an end user. The Company's processing plants remove NGLs and CO₂ from a natural gas stream and its fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline.

(2) Significant Accounting Policies


(a)	Basis of Presentation

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles in the United States of America ("US 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.

Further, the unaudited consolidated financial statements give effect to the business combination and related transactions discussed above under the acquisition method of accounting and are treated as a reverse acquisition. Under the acquisition method of accounting, Midstream Holdings was the accounting acquirer in the transactions because its parent company, Devon, obtained control of ENLC after the business combination. Consequently, Midstream Holdings’ assets and liabilities retained their carrying values and are reflected in the balance sheet as of December 31, 2013 as the Predecessor. All financial results prior to March 7, 2014 reflect the historical operations of Midstream Holdings and are reflected as Predecessor income in the statement of operations. Additionally, EMI’s assets acquired and liabilities assumed by ENLC, as well as ENLC's non-controlling interests in the Partnership, were recorded at their fair values measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of EMI’s net assets acquired was recorded as goodwill. Financial results on and subsequent to March 7, 2014 reflect the combined operations of Midstream Holdings and EMI, which give effect to new contracts entered into with Devon and include the legacy Partnership assets. Certain assets were not contributed to Midstream Holdings from the Predecessor and the operations of such non-contributed assets have been presented as discontinued operations.


(b)	Management's Use of Estimates

The preparation of financial statements in accordance with US GAAP requires management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.


(c)	Revenue Recognition

The Company recognizes revenue for sales or services at the time the natural gas, NGLs, condensate or crude oil are delivered or at the time the service is performed at a fixed or determinable price. The Company generally accrues one month of sales and the related gas, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. The Company's purchase and sale arrangements are generally reported in revenues and costs on a gross basis in the consolidated statement of operations in accordance with the Financial Accounting Standards Board Accounting Standards Codification

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

("FASB ASC") 605-45-45-1. Except for fee based arrangements, the Company acts as the principal in these purchase and sale transactions, has the risk and reward of ownership as evidenced by title transfer, schedules the transportation and assumes credit risk.

The Company accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).


(d)	Gas Imbalance Accounting

Quantities of natural gas and NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas or NGLs. The Company had imbalance payables of $1.1 million at September 30, 2014 which approximate the fair value of these imbalances. The Company had imbalance receivables of $1.3 million at September 30, 2014, which are carried at the lower of cost or market value. There were no imbalance payables or receivables at December 31, 2013.


(e)	Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.


(f)	Natural Gas, Natural Gas Liquids, Crude Oil and Condensate Inventory

The Company's inventories of products consist of natural gas, NGLs, crude oil and condensate. The Company reports these assets at the lower of cost or market value which is determined by using the first-in, first-out method.


(g)	Property, Plant, and Equipment

Property, plant and equipment are stated at historical cost less accumulated depreciation. Assets acquired in a business combination are recorded at fair value, including the Partnership's assets acquired by the Predecessor in the business combination. Repairs and maintenance are charged against income when incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. Subsequent to the business combination, interest costs for material projects are capitalized to property, plant and equipment during the period the assets are undergoing preparation for intended use.

Change in Depreciation Method. Historically, Midstream Holdings depreciated certain property, plant, and equipment using the units-of-production method. As a result of the business combination, the Company is operated as an independent midstream company and thus no longer has access to Devon’s proprietary reserve and production data historically used to compute depreciation under the units-of-production method. Additionally, the existing contracts with Devon were revised to a fee-based arrangement with minimum volume commitments. Effective March 7, 2014, the Company changed its method of computing depreciation for these assets to the straight-line method, consistent with the depreciation method applied to the Company’s legacy assets. In accordance with FASB ASC 250, the Company determined that the change in depreciation method is a change in accounting estimate effected by a change in accounting principle, and accordingly, the straight-line method will be applied on a prospective basis. This change is considered preferable because the straight-line method will more accurately reflect the pattern of usage and the expected benefits of such assets. The effect of this change in estimate resulted in a decrease in depreciation expense for the three and nine months ended September 30, 2014 by approximately $9.3 million and $21.0 million, or $0.06 and $0.13 per unit, respectively.

Gain or Loss on Disposition. Upon the disposition or retirement of property, plant and equipment related to continuing operations, any gain or loss is recognized in operating income in the statement of operations. When a disposition or retirement occurs which qualifies as discontinued operations, any gain or loss is recognized as income or loss from discontinued operations in the statement of operations.

Impairment Review. The Company evaluates its property, plant and equipment for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment loss is recognized equal to the excess of the asset’s carrying value over its fair value. The fair

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

values of long-lived assets are generally determined from estimated discounted future net cash flows. The Company's estimate of cash flows is based on assumptions which include (1) the amount of fee based services and the purchase and resale margins on natural gas, together with the volume of gas, NGL, condensate and crude oil available to the asset, (2) markets available to the asset, (3) operating expenses, and (4) future natural gas prices, crude prices, condensate prices and NGL product prices. The volume of available gas, condensate, NGLs and crude oil to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, condensate and crude oil prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of the above assumptions or factors could materially affect the Company's cash flows, which could require it to record an impairment of an asset.


(h)	Equity Method of Accounting

The Company accounts for investments it does not control but over which the Company has the ability to exercise significant influence using the equity method of accounting. Under this method, equity investments are carried originally at the acquisition cost, increased by the Company’s proportionate share of the investee’s net income and by contributions made, and decreased by the Predecessor’s proportionate share of the investee’s net losses and by distributions received.

The Company evaluates its equity investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable.


(i)	Investment in E2

The Company owns a majority interest in E2, which are companies that provide compression and stabilization services for producers in the liquids-rich window of the Utica Shale play. The Company owns approximately 89.8% of E2 Energy Services, LLC and a 90.6% interest in E2 Appalachian Compression, LLC and has pre-determined rights to purchase the management ownership interests of E2 in the future. The Company consolidates its investment in E2 pursuant to FASB ASC 810-10-05-08.


(j)	Goodwill

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Company will evaluate goodwill for impairment annually as of October 31^st or whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Company first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Company may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step process goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss.

The Company has approximately $3.7 billion of goodwill at September 30, 2014 primarily related to the legacy Company operations as a result of the business combination.


(k)	Intangible Assets

Intangible assets consist of customer relationships which are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from ten to twenty years.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

The following table represents the Partnership's total intangible assets as of September 30, 2014 (in millions):



	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount

Customer relationships	$	547.1	$	(24.4	)	$	522.7

The weighted average amortization period for intangible assets is 13.7 years. Amortization expense for intangibles was approximately $12.4 million and $24.4 million for the three and nine months ended September 30, 2014, respectively.

The following table summarizes the Company's estimated aggregate amortization expense for the identified periods (in millions):



2014 (remaining)	$	10.7
2015	43.0
2016	43.0
2017	43.0
2018	42.6
Thereafter	340.4
Total	$	522.7

(l) Asset Retirement Obligations

The Company recognizes liabilities for retirement obligations associated with its pipelines and processing and fractionation facilities. Such liabilities are recognized when there is a legal obligation associated with the retirement of the assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property, plant and equipment. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The Company’s retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of the long-lived assets. The asset retirement cost is depreciated using a straight line depreciation method similar to that used for the associated property, plant and equipment.

(m) Other Long-Term Liabilities

Included in other current and long-term liabilities is an $85.2 million total liability related to an onerous performance obligation assumed in the business combination. The Partnership has one delivery contract which requires it to deliver a specified volume of gas each month at an indexed base price with a term to 2019. The Partnership realizes a loss on the delivery of gas under this contract each month based on current prices. The fair value of this onerous performance obligation was recorded as a result of the business combination and was based on forecasted discounted cash obligations in excess of market under this gas delivery contract. The liability is reduced each month as delivery is made over the remaining life of the contract with an offsetting reduction in purchase gas costs.

(n) Derivatives

The Company uses derivative instruments to hedge against changes in cash flows related to product price, as opposed to their use for trading purposes. We generally determine the fair value of swap contracts based on the difference between the derivative's fixed contract price and the underlying market price at the determination date. The asset or liability related to the derivative instruments is recorded on the balance sheet as fair value of derivative assets or liabilities in accordance with FASB ASC 815. Changes in fair value of derivative instruments are recorded in gain (loss) on derivative activity in the period of change.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

Realized gains and losses on commodity related derivatives are recorded as gain or loss on derivative activity within revenues in the consolidated statement of operations in the period incurred. Settlements of derivatives are included in cash flows from operating activities.

(o) Concentrations of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of trade accounts receivable and derivative financial instruments. Management believes the risk is limited, other than the Company's exposure to Devon discussed below, since the Company's customers represent a broad and diverse group of energy marketers and end users. In addition, the Company continually monitors and reviews credit exposure to its marketing counter-parties and letters of credit or other appropriate security are obtained as considered necessary to limit the risk of loss. The Company records reserves for uncollectible accounts on a specific identification basis since there is not a large volume of late paying customers. The Company had no reserve for uncollectible receivables as of September 30, 2014.

During the three and nine months ended September 30, 2014, and 2013, the Partnership had no third party customer that individually represented greater than 10.0% of its midstream revenues other than affiliate transactions with Devon which represented 24.1% and 34.8% of the consolidated midstream revenues for the three and nine months ended September 30, 2014, respectively, and 91.9% and 92.0% for the three and nine months ended September 30, 2013, respectively. As the Company continues to grow and expand, the relationship between individual customer sales and consolidated total sales is expected to continue to change. Devon represents a significant percentage of revenues and the loss of Devon as a customer would have a material adverse impact on the Company's results of operations because the gross operating margin received from transactions with this customer is material to the Company.

(p) Environmental Costs

Environmental expenditures are expensed or capitalized as appropriate, depending on the nature of the expenditures and their future economic benefit. Expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or a discounted basis when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. For the three and nine months ended September 30, 2014, such expenditures were not material.

(q) Unit-Based Awards

Prior to the business combination, Devon granted certain share-based awards to members of its board of directors and selected employees. The Predecessor did not grant share-based awards because it previously participated in Devon’s share-based award plans since the Predecessor comprised Devon's U.S. midstream assets. The awards granted under Devon’s plans were measured at fair value on the date of grant and were recognized as expense over the applicable requisite service periods.

The Company recognizes compensation cost related to all unit-based awards in its consolidated financial statements in accordance with FASB ASC 718. The Company and the Partnership each have similar unit-based payment plans for employees. Unit-based compensation associated with ENLC's unit-based compensation plans awarded to directors, officers and employees of the general partner of the Partnership are recorded by the Partnership since the Company has no substantial or managed operating activities other than its interests in the Partnership and Midstream Holdings.

(r) Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

(s) Discontinued Operations

The Company classifies as discontinued operations its assets or asset groups that have clearly distinguishable cash flows and are in the process of being sold or have been sold. The Company also includes as discontinued operations Predecessor assets that were not contributed in the business combination.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(t) Debt Issue Costs

Costs incurred in connection with the issuance of long-term debt are deferred and recorded as interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs.

(u) Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"). ASU 2014-09 will replace existing revenue recognition requirements in US GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Company expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires significantly expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period and is to be applied retrospectively, with early application not permitted. We are currently evaluating the impact the pronouncement will have on our consolidated financial statements and related disclosures. Subject to this evaluation, we have reviewed all recently issued accounting pronouncements that became effective during the nine months ended September 30, 2014, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.

(3) Acquisition

On March 7, 2014, EMI merged with and into a wholly-owned subsidiary of the Company, and New Acacia, formerly a wholly-owned subsidiary of Devon, merged with and into another wholly-owned subsidiary of the Company (collectively, the “mergers”). Upon consummation of the mergers, EMI and New Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. As of September 30, 2014, the Company, through its ownership of EMI, owned approximately 7% of the outstanding limited partner interests in the Partnership and owned 100.0% of the General Partner. The Company, through its ownership of New Acacia, indirectly owns a 50% limited partner interest in Midstream Holdings. Midstream Holdings owns midstream assets previously held by Devon in the Barnett Shale in North Texas, the Cana-Woodford Shale and Arkoma-Woodford Shale in Oklahoma and a contractual right to the burdens and benefits associated with Devon’s 38.75% interest in Gulf Coast Fractionators ("GCF") in Mt. Belvieu, Texas.

Also effective as of March 7, 2014, a wholly-owned subsidiary of the Partnership acquired the remaining 50% limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the mergers, the “business combination”).

Under the acquisition method of accounting, Midstream Holdings is the acquirer in the business combination because its parent company, Devon, obtained control of ENLC. Consequently, Midstream Holdings’ assets and liabilities retained their carrying values. Additionally, EMI’s assets acquired and liabilities assumed by ENLC, as well as ENLC’s non-controlling interest in the Partnership, are recorded at their fair values measured as of the acquisition date. The excess of the purchase price over the estimated fair values of EMI’s net assets acquired is recorded as goodwill.

Since equity consideration was issued for this business combination, the purchase of these assets and liabilities has been excluded from our statement of cash flows, except for transaction related costs totaling $51.4 million assumed by ENLC at closing and subsequently paid by ENLC.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

The following table summarizes the purchase price (in millions, except per unit price):



EMI outstanding common shares:
Held by public shareholders	48.0
Restricted shares	0.4
Total subject to exchange	48.4
Exchange ratio	1.0		x
Exchanged shares	48.4
EMI common share price(1)	$	37.6
EMI consideration	$	1,822.6
Fair value of non-controlling interests in E2	12.1
Total consideration and fair value of non-controlling interests	$	1,834.7
Partnership outstanding units:
Common units held by public unitholders	75.1
Preferred units held by third party (2)	17.1
Restricted units	0.4
Total	92.6
Partnership common unit price(3)	$	30.51
Partnership common units value	$	2,825.2
Partnership outstanding unit options value	$	3.9
Total fair value of non-controlling interests in the Partnership(3)	$	2,828.8
Total consideration and fair value of non-controlling interests	$	4,663.5

(1) The final purchase price is based on the fair value of the Company's common shares as of the closing date, March 7, 2014.

(2) The Partnership converted the preferred units to common units in February 2014.

(3) The final purchase price is based on the fair value of the Partnership's common units as of the closing date, March 7, 2014.

The following table is a summary of the preliminary fair value of the assets acquired and liabilities assumed from EMI in the business combination as of March 7, 2014 (in millions):



Assets acquired:
Current assets	$	437.4
Property, plant and equipment	2,437.9
Intangibles assets	546.9
Equity investment	221.5
Goodwill	3,291.9
Other long term assets	1.3
Liabilities assumed:
Current liabilities	(515.9		)
Long-term debt	(1,453.7		)
Deferred taxes	(202.6		)
Other long term liabilities	(101.2		)
Total purchase price	$	4,663.5

Goodwill recognized from the business combination primarily relates to the value created from additional growth opportunities and greater operating leverage in core areas. The goodwill is allocated among our Texas, Louisiana, Oklahoma,

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

and ORV segments. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. All of the goodwill is non-deductible for tax purposes.

For the period from March 7, 2014 to September 30, 2014, the Company recognized $1,669.0 million of revenues and $1,646.5 million of operating expenses related to the assets acquired in the business combination.

Pro Forma Information

The following unaudited pro forma condensed financial data for the nine months ended September 30, 2014 and three and nine months ended September 30, 2013 gives effect to the business combination as if it had occurred on January 1, 2013. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results. As of March 7, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 4. Pro forma financial information associated with the business combination and with these agreements with Devon is reflected below.



	Three Months Ended			Nine Months Ended
	September 30, 2013			September 30, 2014		September 30, 2013
	(in millions, except for per unit data)
Pro forma total revenues	$	622.0		$	2,676.6	$	1,818.9
Pro forma net income	$	(6.4	)	$	165.8	$	76.5
Pro forma net income attributable to EnLink Midstream, LLC.	$	18.2		$	75.3	$	53.2
Pro forma net income per common unit:
Basic	$	0.10		$	0.46	$	0.33
Diluted	$	0.10		$	0.45	$	0.33

(4) Affiliate Transactions

The Partnership engages in various transactions with Devon and other affiliated entities. Prior to March 7, 2014, these transactions relate to EnLink Midstream Holdings, LP Predecessor (the "Predecessor") transactions consisting of sales to and from affiliates, services provided by affiliates, cost allocations from affiliates and centralized cash management activities performed by affiliates. Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with nonaffiliated third parties. The amounts related to affiliate transactions are specified in the accompanying financial statements.

The Predecessor’s historical assets comprised all of Devon’s U.S. midstream assets and operations. However, only its assets serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as contractual rights to the burdens and benefits of Devon's 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the business combination. Assets that were not contributed from the Predecessor are reflected as discontinued operations prior to March 7, 2014 and reflected as a reduction in equity as of March 7, 2014.

Midstream Holdings, in which the Company holds a 50% economic interest as of March 7, 2014, conducts business with Devon pursuant to the gathering and processing agreements described below. The legacy Partnership also historically has maintained a relationship with Devon as a customer, as described in more detail below.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

Gathering and Processing Agreements

As described in Note 1, Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon. In connection with the consummation of the business combination, EnLink Midstream Services, LLC, a wholly-owned subsidiary of Midstream Holdings ("EnLink Midstream Services"), entered into 10-year gathering and processing agreements with Devon pursuant to which EnLink Midstream Services provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon Gas Services, L.P., a subsidiary of Devon ("Gas Services") to Midstream Holdings’ gathering and processing systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. SWG Pipeline, L.L.C. (“SWG Pipeline”), another wholly-owned subsidiary of Midstream Holdings, entered into a 10-year gathering agreement with Devon pursuant to which SWG Pipeline provides gathering, treating, compression, dehydration and redelivery services, as applicable, for natural gas delivered by Gas Services to another of the Partnership's gathering system in the Barnett Shale.

These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. Pursuant to the gathering and processing agreements, Devon has committed to deliver specified average minimum daily volumes of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter for a five-year period following execution. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

The gathering and processing agreements are fee-based, and Midstream Holdings is paid a specified fee per MMBtu for natural gas gathered on Midstream Holdings’ gathering systems and a specified fee per MMBtu for natural gas processed. The particular fees, all of which are subject to an automatic annual inflation escalator at the beginning of each year, differ from one system to another and do not contain a fee redetermination clause.

On August 29, 2014, Gas Services assigned its 10-year gathering and processing agreement to Linn Exchange Properties, LLC (“Linn Energy”), which is a subsidiary of Linn Energy, LLC, in connection with Gas Services’ divestiture of certain of its southeastern Oklahoma assets. Such assignment will be effective as of December 1, 2014. Accordingly, beginning on December 1, 2014, Linn Energy will perform Gas Services’ obligations under the agreement, which remains in full force and effect. The assignment of this agreement relates to production dedicated to our Northridge assets in southeastern Oklahoma. Gross operating margin related to our Northridge assets totaled $6.5 million and $22.3 million for the three and nine months ended September 30, 2014, respectively.

Historical Customer Relationship with Devon

As noted above, the Partnership maintained a customer relationship with Devon prior to the business combination pursuant to which certain of the Partnership's subsidiaries provide gathering, transportation, processing and gas lift services to Devon subsidiaries in exchange for fee-based compensation under several agreements with Devon. The terms of these agreements vary, but the agreements expire between March 2015 and July 2021 and they automatically renew for month-to-month or year-to-year periods unless canceled by Devon prior to expiration. In addition, one of the Partnership's subsidiaries has agreements with a subsidiary of Devon pursuant to which the Partnership's subsidiary purchases and sells NGLs and pays or receives, as applicable, a margin-based fee. These NGL purchase and sale agreements have month-to-month terms.

Transition Services Agreement

In connection with the consummation of the business combination, the Partnership entered into a transition services agreement with Devon pursuant to which Devon provides certain services to the Partnership with respect to the business and operations of Midstream Holdings, including IT, accounting, pipeline integrity, compliance management and procurement services, and the Partnership provides certain services to Devon and its subsidiaries, including IT, human resources and other commercial and operational services. The Partnership expects most services under the transition services agreement to end by December 31, 2014.

GCF Agreement

In connection with the closing of the business combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Devon agreed, from and after the closing of the business combination, to hold for

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

the benefit of Midstream Holdings the economic benefits and burdens of Devon’s 38.75% interest in GCF, which owns a fractionation facility in Mont Belvieu, Texas.

Lone Camp Gas Storage Agreement

In connection with the closing of the business combination, Midstream Holdings entered into an agreement with Gas Services under which Midstream Holdings provides gas storage services at its Lone Camp storage facility. Under this agreement, Gas Services reimburses Midstream Holdings for the expenses it incurs in providing the storage services. This agreement has minimal to no impact on Midstream Holdings' annual revenue.

Acacia Transportation Agreement

In connection with the closing of the business combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Midstream Holdings provides transportation services to Devon on its Acacia pipeline.

Office Leases

In connection with the closing of the business combination, EnLink Midstream Operating, LP (formerly known as Crosstex Energy Services, L.P.) entered into three office lease agreements with a wholly-owned subsidiary of Devon pursuant to which EnLink Midstream Operating, LP leases office space from Devon at its Bridgeport, Oklahoma City and Cresson office buildings. Rent payable to Devon under these lease agreements is $174,000, $31,000 and $66,000, respectively, on an annual basis.

Tax Sharing Agreement

In connection with the closing of the business combination, ENLC, the Partnership and Devon entered into a tax sharing agreement providing for the allocation of responsibilities, liabilities and benefits relating to any tax for which a combined tax return is due.

The following presents financial information for the Predecessor's affiliate transactions and other transactions with Devon, all of which are settled through an adjustment to equity prior to March 7, 2014 (in millions):

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)



	Three Months Ended September 30,			Nine Months Ended September 30,
	2013			2014			2013
Continuing Operations:
Operating revenues - affiliates	$	(531.4	)	$	(436.4	)	$	(1,557.0	)
Operating expenses - affiliates	417.5			340.0			1,229.6
Net affiliate transactions	(113.9		)	(96.4		)	(327.4		)
Capital expenditures	44.7			16.2			201.3
Other third-party transactions, net	(50.8		)	53.0			8.4
Net third-party transactions	(6.1		)	69.2			209.7
Net cash distributions to Devon - continuing operations	(120.0		)	(27.2		)	(117.7		)
Non-cash distribution of net assets to Devon	—			(23.5		)	—
Total net distributions per equity	$	(120.0	)	$	(50.7	)	$	(117.7	)

Discontinued operations:
Operating revenues - affiliates	$	(20.8	)	$	(10.4	)	$	(68.1	)
Operating expenses - affiliates	7.8			5.0			25.4
Cash used in financing activities - affiliates	(0.4		)	—			(5.6		)
Net affiliate transactions	(13.4		)	(5.4		)	(48.3		)
Capital expenditures	(0.1		)	0.6			5.3
Other third-party transactions, net	(73.5		)	0.4			(54.6		)
Net third-party transactions	(73.6		)	1.0			(49.3		)
Net distributions to Devon and non-controlling interests - discontinued operations	(87.0		)	(4.4		)	(97.6		)
Non-cash distribution of net assets to Devon	—			(39.9		)	—
Total net distributions per equity	$	(87.0	)	$	(44.3	)	$	(97.6	)
Total distributions - continuing and discontinued operations	$	(207.0	)	$	(95.0	)	$	(215.3	)

For the three and nine months ended September 30, 2014 and 2013, Devon was a significant customer to the Company. Devon accounted for 24.1% and 34.8% of the Company's revenues for the three and nine months ended September 30, 2014, respectively, and 91.9% and 92.0% of the Company’s revenues for the three and nine months ended September 30, 2013, respectively. The affiliate revenues from March 7, 2014 through September 30, 2014 were $435.6 million. Additionally, the Partnership had an accounts receivable balance related to transactions with Devon of $113.2 million as of September 30, 2014. The Company had an accounts payable balance related to transactions with Devon of $3.8 million as of September 30, 2014.

Share-based compensation costs included in the management services fee charged to Midstream Holdings by Devon were approximately $2.8 million for the nine months ended September 30, 2014 and $3.5 million and $10.1 million for the three and nine months ended September 30, 2013, respectively. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Company by Devon were approximately $1.6 million for the nine months ended September 30, 2014 and $2.2 million and $6.1 million for the three and nine months ended September 30, 2013, respectively. These amounts are included in general and administrative expenses in the accompanying statements of operations.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(5) Long-Term Debt

As of September 30, 2014, long-term debt consisted of the following (in millions):



	September 30, 2014
Partnership bank credit facility (due 2019), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at September 30, 2014 was 1.9%	$	371.0
Company bank credit facility (due 2019), interest based on LIBOR plus an applicable margin, interest rate at September 30, 2014 was 1.9%	80.5
Senior unsecured notes (due 2019), net of discount of $2.7 million, which bear interest at the rate of 2.70%	397.3
Senior unsecured notes (due 2022), including a premium of $22.6 million, which bear interest at the rate of 7.125%	185.1
Senior unsecured notes (due 2024), net of discount of $3.5 million, which bear interest at the rate of 4.40%	446.5
Senior unsecured notes (due 2044), net of discount of $3.3 million, which bear interest at the rate of 5.60%	346.8
Other debt	26.7
Debt classified as long-term	$	1,853.9

Company Credit Facility. On March 7, 2014, the Company entered into a new $250.0 million revolving credit facility, which includes a $125.0 million letter of credit subfacility (the “credit facility”). The Company used borrowings under the credit facility to repay outstanding borrowings under the margin loan facility of XTXI Capital, LLC (a former wholly-owned subsidiary of EnLink Midstream, Inc.), which was paid in full and terminated on March 7, 2014. Our obligations under the credit facility are guaranteed by our two wholly-owned subsidiaries and secured by first priority liens on (i) 16,414,830 Partnership 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, (iii) the 50% limited partner interest in Midstream Holdings held by us and (iv) any additional equity interests subsequently pledged as collateral under the credit facility.

The credit facility will mature on March 7, 2019. The credit facility contains certain financial, operational and legal covenants. The financial covenants will be 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 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 credit facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the 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 at all times prior to the occurrence of an investment grade event (as defined in the credit facility).

Borrowings under the credit facility bear interest, at our option, at either the Eurodollar Rate (the LIBOR Rate) plus an applicable margin 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. The applicable margins vary depending on our leverage ratio. Upon breach by us of certain covenants governing the credit facility, amounts outstanding under the credit facility, if any, may become due and payable immediately and the liens securing credit facility could be foreclosed upon.

As of September 30, 2014, there was $80.5 million borrowed under the credit facility, leaving approximately $169.5 million available for future borrowing based on the borrowing capacity of $250.0 million.

Other Company Borrowings. On September 4, 2013, E2 Energy Services LLC ("E2 Services"), one of the Ohio services companies in which the Company invests, entered into a credit agreement with JPMorgan Chase Bank ("JPMorgan"). The maturity date of E2 Services' credit agreement is September 4, 2016. As of September 30, 2014, there was $26.3 million borrowed under E2 Services' credit agreement, leaving approximately $2.5 million available for future borrowing based on borrowing capacity of $30.0 million. The interest rate under the credit agreement is based on Prime plus an applicable margin. The effective interest rate as of September 30, 2014 was approximately 4.0%. Additionally, as of September 30, 2014, E2 Services had certain promissory notes outstanding related to its vehicle fleet in the amount of $0.4 million due in increments

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

through July 2017. The notes bear interest at fixed rates ranging 3.9% to 7.0%. The Company does not guarantee E2 Services' debt obligations.

Partnership Credit Facility. On February 20, 2014, the Partnership entered into a new $1.0 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”). The Partnership credit facility will mature on the fifth anniversary of the initial funding date, which was March 7, 2014, unless the Partnership requests, and the requisite lenders agree, to extend it pursuant to its terms. The Partnership credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the Partnership credit facility, which definition includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If the Partnership consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA will increase to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

Borrowings under the Partnership credit facility bear interest at the Partnership’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin 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. The applicable margins vary depending on the Partnership’s credit rating. Upon breach by the Partnership of certain covenants governing the Partnership credit facility, amounts outstanding under the Partnership credit facility, if any, may become due and payable immediately.

As of September 30, 2014, there were $14.0 million in outstanding letters of credit and $371.0 million in outstanding borrowings under the Partnership’s bank credit facility, leaving approximately $615.0 million available for future borrowing based on the borrowing capacity of $1.0 billion.

The percentages per annum, based upon the debt rating are as set forth below:



Pricing Level	Debt Ratings	Applicable Rate Commitment Fee	EuroDollar Rate/Letter of Credit	Base Rate +
Pricing Level	Debt Ratings	Applicable Rate Commitment Fee	EuroDollar Rate/Letter of Credit	Base Rate +
1	A-/A3 or better	0.100%	1.000%	—
2	BBB+/Baa1	0.125%	1.125%	0.125%
3	BBB/Baa2	0.175%	1.250%	0.250%
4	BBB-/Baa3	0.225%	1.500%	0.500%
5	BB+/Ba1	0.275%	1.625%	0.625%
6	BB/Ba2 or worse	0.350%	1.750%	0.750%

Senior Unsecured Notes. On March 7, 2014, the Partnership recorded $725.0 million in aggregate principal amount of 8.875% senior unsecured notes (the “2018 Notes”) due on February 15, 2018 in the business combination. As a result of the business combination, the 2018 Notes were recorded at fair value in accordance with acquisition accounting at an amount of $761.3 million, including a premium of $36.3 million, as of March 7, 2014.

On March 7, 2014, the Partnership recorded $196.5 million in aggregate principal amount of 7.125% senior unsecured notes (the “2022 Notes”) due on June 1, 2022 in the business combination. The interest payments on the 2022 Notes are due semi-annually in arrears in June and December. As a result of the business combination, the 2022 Notes were recorded at fair value in accordance with acquisition accounting at an amount of $226.0 million, including a premium of $29.5 million. On July 20, 2014, the Partnership redeemed $18.5 million aggregate principal amount of the 2022 Notes for $20.0 million, including accrued interest. On September 20, 2014, the Partnership redeemed an additional $15.5 million aggregate principal amount of the 2022 Notes for $17.0 million, including accrued interest. The Partnership recorded a gain on extinguishment of debt related to the redemption of the 2022 Notes of $2.4 million and $3.2 million for the three and nine months ended September 30, 2014, respectively.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

On March 12, 2014, the Partnership commenced a tender offer to purchase any and all of the outstanding 2018 Notes. Approximately $536.1 million, or approximately 74%, of the 2018 Notes were validly tendered and on March 19, 2014, the Partnership made a payment of approximately $567.4 million for all such tendered 2018 Notes. Also on March 19, 2014, the Partnership delivered a notice of redemption for any and all outstanding 2018 Notes. All remaining outstanding 2018 Notes were redeemed on April 18, 2014 for $200.2 million, including accrued interest.

On March 19, 2014, the Partnership issued $1.2 billion aggregate principal amount of unsecured senior notes, consisting of $400.0 million aggregate principal amount of its 2.700% senior notes due 2019 (the “2019 Notes”), $450.0 million aggregate principal amount of its 4.400% senior notes due 2024 (the “2024 Notes”) and $350.0 million aggregate principal amount of its 5.600% senior notes due 2044 (the “2044 Notes” and, together with the 2018 Notes, 2019 Notes, 2022 Notes and 2024 Notes, the “Senior Notes”), at prices to the public of 99.850%, 99.830% and 99.925%, respectively, of their face value. The 2019 Notes mature on April 1, 2019, the 2024 Notes mature on April 1, 2024 and the 2044 Notes mature on April 1, 2044. The interest payments on the 2019 Notes, 2024 Notes and 2044 Notes are due semi-annually in arrears in April and October.

Prior to June 1, 2017, the Partnership may redeem all or part of the remaining 2022 Notes at the redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest to the redemption date. On or after June 1, 2017, the Partnership may redeem all or a part of the remaining 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.563% for the twelve-month period beginning on June 1, 2017, 102.375% for the twelve-month period beginning on June 1, 2018, 101.188% for the twelve-month period beginning on June 1, 2019 and 100.000% for the twelve-month period beginning on June 1, 2020 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022 Notes.

Prior to March 1, 2019, the Partnership may redeem all or a part of the 2019 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2019 Notes to be redeemed; or (ii) the sum of the remaining scheduled payments of principal and interest on the 2019 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 20 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after March 1, 2019, the Partnership may redeem all or a part of the 2019 Notes at a redemption price equal to 100% of the principal amount of the 2019 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to January 1, 2024, the Partnership may redeem all or a part of the 2024 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2024 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2024 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 25 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after January 1, 2024, the Partnership may redeem all or a part of the 2024 Notes at a redemption price equal to 100% of the principal amount of the 2024 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to October 1, 2043, the Partnership may redeem all or a part of the 2044 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2044 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2044 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after October 1, 2043, the Partnership may redeem all or a part of the 2044 Notes at a redemption price equal to 100% of the principal amount of the 2044 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

The indentures governing the Senior Notes contain covenants that, among other things, limit the Partnership's ability to create or incur certain liens or consolidate, merge or transfer all or substantially all of its assets.

Each of the following is an event of default under the indentures:


•	failure to pay any principal or interest when due;

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)


•	failure to observe any other agreement, obligation or other covenant in the indenture, subject to the cure periods for certain failures;


•	default by the Partnership under other indebtedness that exceeds a certain threshold amount;


•	failure by the Partnership to pay final judgments that exceed a certain threshold amount; and


•	bankruptcy or other insolvency events involving the Partnership.

If an event of default relating to bankruptcy or other insolvency events occurs, the Senior Notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the Senior Notes may accelerate the maturity of the Senior Notes and exercise other rights and remedies.

(6) Income Taxes

The Predecessor’s historical combined financial statements include U.S. federal and state income tax expense and related deferred tax liabilities. As a result of the business combination, the Predecessor was reorganized and Midstream Holdings is treated as a partnership and no longer subject to federal and certain state income taxes on or subsequent to March 7, 2014, the transaction date.

As of the transaction date, ENLC owned a 50% direct partnership interest in Midstream Holdings and indirectly owned an additional interest of approximately 3% through its ownership in the Partnership which owns the other 50% interest in Midstream Holdings. ENLC assumed a carryover basis in Midstream Holdings' assets and, therefore, assumed $252.0 million of deferred tax liability in the business combination. This amount represents approximately 53% of Midstream Holdings' deferred tax liability at closing related to the difference between the book basis and the tax basis of Midstream Holdings' assets. The deferred tax liability of $215.5 million related to the 47% of Midstream Holdings not owned by ENLC was reflected as a reduction in the deferred tax liability and an increase in non-controlling interest through equity at closing.

The Company provides for income taxes using the liability method. Accordingly, deferred taxes are recorded for the differences between the tax and book basis that will reverse in future periods (in millions).



	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014

Predecessor tax provision	$	—	$	19.4
ENLC tax provision	17.3		40.1
Tax provision	$	17.3	$	59.5

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

The principal component of the Company's net deferred tax liability is as follows (in millions):



	September 30, 2014
Deferred income tax assets:
Inventory	$	0.2
Accrued expenses	0.3
Asset retirement obligations	2.2
Net operating loss carryforward-non current	23.9
Total deferred tax assets	26.6
Deferred income tax liabilities:
Property, plant, equipment, and intangibles assets-long term	(515.1		)
Other assets	(8.1		)
Total deferred tax liabilities	(523.2		)
Net deferred tax liability	$	(496.6	)

At September 30, 2014, the Company had a net operating loss carryforward of approximately $61.9 million that expires from 2027 through 2034. The Company also has various state net operating loss carryforwards of approximately $75.4 million which will begin expiring in 2027. Management believes that it is more likely than not that the future results of operations will generate sufficient taxable income to utilize these net operating loss carryforwards before they expire.

Deferred tax liabilities relating to property, plant, equipment and intangible assets represent, primarily, the Company's share of the book basis in excess of tax basis for assets inside of the Partnership and Midstream Holdings.

(7) Certain Provisions of the Partnership Agreement

(a) Issuance of Common Units

In May 2014, the Partnership entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (“BMOCM”). Pursuant to the terms of the EDA, the Partnership may from time to time through BMOCM, as its sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75.0 million.

Through September 30, 2014, the Partnership sold an aggregate of 2.4 million common units under the EDA, generating proceeds of approximately $71.9 million (net of approximately $0.7 million of commissions to BMOCM). The Partnership used the net proceeds for general partnership purposes, including working capital, capital expenditures and repayments of indebtedness.

(b) Cash Distributions

Unless restricted by the terms of the Partnership credit facility and/or the indentures governing the Partnership’s unsecured senior notes, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions are made to the General Partner in accordance with its current percentage interest with the remainder to the common unitholders, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. The Partnership's first quarter 2014 distribution on its common units and Class B Units of $0.36 per unit and $0.10 per unit, respectively, were paid on May 14, 2014. Distributions declared for the Partnership's Class B Units represent a pro rata distribution for the number of days its Class B Units were issued and outstanding during the quarter. The Partnership's Class B Units automatically converted into common units on a one-for-one basis on May 6, 2014. The Partnership paid second quarter 2014 distribution on its common units of 0.365 on August 13, 2014. Also, the Partnership declared a third quarter 2014 distribution on its common units of $0.37 per unit to be paid on November 13, 2014.

Under the quarterly incentive distribution provisions, generally the Partnership's General Partner is entitled to 13.0% of amounts the Partnership distributes in excess of $0.25 per unit, 23% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48.0% of amounts the Partnership distributes in excess of $0.375 per unit.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

Net income is allocated to the General Partner in an amount equal to its incentive distributions as described in Note 7(b). The General Partner's share of net income consists of incentive distributions to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of the Partnership’s net income adjusted for ENLC's unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows for the three and nine months ended September 30, 2014 (in millions):



	Three Months Ended September 30, 2014			Nine Months Ended September 30, 2014*
Income allocation for incentive distributions	$	6.3		$	13.6
Unit-based compensation attributable to ENLC's restricted units	(3.1		)	(6.8		)
General Partner interest in net income	0.3			0.7
General Partner share of net income	$	3.5		$	7.5

* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.

(8) Earnings per Unit and Dilution Computations

As required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations. Net income earned by the Predecessor prior to March 7, 2014 is not included for purposes of calculating earnings per unit as the Predecessor did not have any unitholders. Additionally, distributions declared for the Class B Units represent a pro rata distribution for the number of days the Class B Units were issued and outstanding during the quarter. The Class B Units automatically converted into common units on a one-for-one basis on May 6, 2014.

The following table reflects the computation of basic and diluted earnings per limited partner unit for the three and nine months ended September 30, 2014 (in millions, except per unit amounts):



	Three Months Ended September 2014			Nine Months Ended September 30, 2014*
Net income attributable to Enlink Midstream, LLC	$	28.8		$	64.4
Distributed earnings allocated to:
Common units and Class B Units (1)(2)	$	37.7		$	88.3
Unvested restricted units (1)	0.2			0.6
Total distributed earnings	$	37.9		$	88.9
Undistributed loss allocated to:
Common units and Class B Units	$	(9.1	)	$	(24.3	)
Unvested restricted units	(0.1		)	(0.2		)
Total undistributed loss	$	(9.2	)	$	(24.5	)
Net income allocated to:
Common units and Class B Units	$	28.6		$	64.0
Unvested restricted units	0.2			0.4
Total net income	$	28.8		$	64.4
Basic and diluted net income per unit:
Basic common unit	$	0.18		$	0.39
Diluted common unit	$	0.17		$	0.39

__________________________________________________

* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(1) Three months ended September 30, 2014 represents a declared distribution of $0.23 per unit for common units payable on November 14, 2014 and nine months ended September 30, 2014 represents distributions of $0.18 per unit paid on May 15, 2014, distributions of $0.22 per unit paid on August 14, 2014 and distributions declared of $0.23 per unit payable on November 14, 2014.

(2) Nine months ended September 30, 2014 includes distributions of $0.05 per unit for ENLC's Class B Units paid on May 15, 2014. The Class B Units converted into common units on a one-for-one basis on May 6, 2014.

The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the three and nine months ended September 30, 2014 (in millions):



	Three Months Ended September 30, 2014	Nine Months Ended September 30, 2014*
Basic weighted average units outstanding:
Weighted average limited partner basic common units outstanding	164.0	164.0
Diluted weighted average units outstanding:
Weighted average basic common units outstanding	164.0	164.0
Dilutive effect of restricted units issued	0.4	0.3
Total weighted average diluted common units outstanding	164.4	164.3

* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.

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 period presented.

(9) Asset Retirement Obligations

The schedule below summarizes the changes in the Company’s asset retirement obligations:



	September 30, 2014		September 30, 2013
	(in millions)
Beginning asset retirement obligations	$	7.7	$	9.1
Revisions to existing liabilities	2.2		0.4
Liabilities acquired	0.5		—
Accretion	0.4		0.3
Ending asset retirement obligations	$	10.8	$	9.8

(10) Investment in Unconsolidated Affiliates

The Company’s unconsolidated investments consisted of a contractual right to the benefits and burdens associated with Devon's 38.75% ownership interest in GCF at September 30, 2014 and December 31, 2013 and a 30.6% ownership interest in Howard Energy Partners ("HEP") at September 30, 2014.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for periods indicated (in millions



	Gulf Coast Fractionators		Howard Energy Partners		Total
Three months ended
September 30, 2014
Distributions	$	5.2	$	3.0	$	8.2
Equity in income	$	5.2	$	0.4	$	5.6

September 30, 2013
Distributions	$	12.0	$	—	$	12.0
Equity in income	$	5.8	$	—	$	5.8

Nine months ended
September 30, 2014 (1)
Distributions	$	5.2	$	8.7	$	13.9
Equity in income	$	13.2	$	1.1	$	14.3

September 30, 2013
Distributions	$	12.0	$	—	$	12.0
Equity in income	$	10.2	$	—	$	10.2

(1) Includes income and distributions for the period March 7, 2014 through September 30, 2014 for Howard Energy Partners.

The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):



	September 30, 2014		December 31, 2013
Gulf Coast Fractionators (1)	$	56.0	$	61.1
Howard Energy Partners	220.1		—
Total investments in unconsolidated affiliates	$	276.1	$	61.1

(1) Devon retained $13.1 million of the undistributed earnings due from GCF, as of March 7, 2014 when the GCF contractual right allocating the benefits and burdens of the 38.75% ownership interest in GCF to the Partnership became effective. The $13.1 million of the undistributed earnings was reflected as a reduction in the GCF investment on March 7, 2014.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(11) Employee Incentive Plans

(a) Long-Term Incentive Plans

The Partnership and ENLC each have similar unit or unit-based payment plans for employees, which are described below. Unit-based compensation associated with ENLC's unit-based compensation plan awarded to officers and employees of the Partnership are recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership and Midstream Holdings. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Cost of unit-based compensation allocated to Predecessor general and administrative expense (1)	$	—	$	3.5	$	2.8	$	10.1
Cost of unit-based compensation charged to general and administrative expense	5.0		—		11.0		—
Cost of unit-based compensation charged to operating expense	0.8		—		1.8		—
Total amount charged to income	$	5.8	$	3.5	$	15.6	$	10.1
Interest of non-controlling partners in unit-based compensation	$	2.5	$	—	$	5.4	$	—
Amount of related income tax expense recognized in income	$	1.3	$	1.3	$	3.9	$	3.8

(1) Unit-based compensation expense was treated as a contribution by the Predecessor in the Consolidated Statement of Changes in Members' Equity.

The Partnership accounts for unit-based compensation in accordance with FASB ASC 718, which requires that compensation related to all unit-based awards, including unit options, be recognized in the consolidated financial statements. On March 7, 2014, the General Partner amended and restated the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “Plan”) (formerly the Crosstex Energy GP, LLC Long-Term Incentive Plan). Amendments to the Plan included a change in name and other technical amendments. The Plan provides for the issuance of up to 9,070,000 awards.

(b) Restricted Partnership's Incentive Units

The restricted incentive units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, 2014 is provided below:



	Nine Months Ended September 30, 2014
EnLink Midstream Partners, LP Restricted Incentive Units:	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	—			$	—
Assumed in business combination	371,225			30.51
Granted	701,119			31.65
Vested*	(39,833		)	30.63
Forfeited	(13,196		)	31.83
Non-vested, end of period	1,019,315			$	31.27
Aggregate intrinsic value, end of period (in millions)	$	31.0

* Vested units include 16,471 units withheld for payroll taxes paid on behalf of employees.

Restricted incentive units assumed in the business combination were valued as of March 7, 2014, will vest at the end of two years and are included in the restricted incentive units outstanding and the current unit-based compensation cost calculations at September 30, 2014. The Partnership issued restricted incentive units in 2014 to officers and other employees. These restricted incentive units typically vest at the end of three years.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and nine months ended September 30, 2014 are provided below (in millions):



	Three Months Ended September 30,		Nine Months Ended September 30,
EnLink Midstream Partners, LP Restricted Incentive Units:	2014		2014
Aggregate intrinsic value of units vested	$	1.2	$	1.2
Fair value of units vested	$	1.2	$	1.2

As of September 30, 2014, there was $21.3 million of unrecognized compensation cost related to non-vested restricted incentive units. That cost is expected to be recognized over a weighted-average period of 2.1 years.

During the nine months ended September 30, 2014, 31,382 unit options of the Partnership were exercised with an intrinsic value of $0.6 million. As of September 30, 2014, all unit options were fully vested and fully expensed.

(d) EnLink Midstream, LLC's Restricted Incentive Units

On February 5, 2014, ENLC's sole unitholder at the time, EnLink Midstream Manager, LLC, approved the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “Company Plan”). The Company Plan provides for the issuance of 11.0 million awards.

On March 7, 2014, effective as of the closing of the business combination, ENLC (i) assumed the Crosstex Energy, Inc. 2009 Long-Term Incentive Plan (the “2009 Plan”) and all awards thereunder outstanding following the business combination and (ii) amended and restated the 2009 Plan to reflect the conversion of the awards under the 2009 Plan relating to EMI’s common stock to awards in respect of common units of ENLC.

ENLC’s restricted incentive units are valued at their fair value at the date of grant which is equal to the market value of the common units on such date. A summary of the restricted incentive units activities for the nine months ended September 30, 2014 is provided below:



	Nine Months Ended September 30, 2014
EnLink Midstream, LLC Restricted Incentive Units	Number of Units			Weighted Average Grant-Date Fair Value
Non-vested, beginning of period	—			$	—
Assumed in business combination	435,674			37.60
Granted	626,341			36.59
Vested*	(59,553		)	37.56
Forfeited	(11,859		)	36.54
Non-vested, end of period	990,603			$	36.97
Aggregate intrinsic value, end of period (in millions)	$	40.9

* Vested units include 24,727 units withheld for payroll taxes paid on behalf of employees.

Restricted incentive units assumed in the business combination were valued as of March 7, 2014, will vest at the end of two years and are included in restricted incentive units outstanding and the current unit-based compensation cost calculations at September 30, 2014. ENLC issued restricted incentive units in 2014 to officers and other employees. These restricted incentive units typically vest at the end of three years and are included in restricted incentive units outstanding.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)



	Three Months Ended September 30,		Nine Months Ended September 30,
EnLink Midstream, LLC Restricted Incentive Units:	2014		2014
Aggregate intrinsic value of units vested	$	2.4	$	2.4
Fair value of units vested	$	2.2	$	2.2

As of September 30, 2014, there was $23.2 million of unrecognized compensation costs related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted average period of 2.1 years.

(12) Derivatives

Commodity Swaps

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

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

The components of gain (loss) on derivative activity in the consolidated statements of operations relating to commodity swaps are as follows for the three and nine months ended September 30, 2014 (in millions



	Three Months Ended September 30, 2014			Nine Months Ended September 30, 2014*
Change in fair value of derivatives	$	1.8		$	(0.2	)
Realized losses on derivatives	(0.8		)	(1.7		)
Loss on derivative activity	$	1.0		$	(1.9	)

* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.

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



	September 30, 2014
Fair value of derivative assets — current	$	1.1
Fair value of derivative assets — long term	0.2
Fair value of derivative liabilities — current	(0.9		)
Fair value of derivative liabilities— long term	(0.6		)
Net fair value of derivatives	$	(0.2	)

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets at September 30, 2014. The remaining term of the contracts extend no later than December 2016.



			September 30, 2014
Commodity	Instruments	Unit	Volume		Fair Value
			(In millions)
NGL (short contracts)	Swaps	Gallons	(61.3	)	$	0.7
NGL (long contracts)	Swaps	Gallons	47.9		(0.9		)
Natural Gas (short contracts)	Swaps	MMBtu	(2.2	)	0.1
Natural Gas (long contracts)	Swaps	MMBtu	0.4		(0.1		)
Total fair value of derivatives					$	(0.2	)

On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty's financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis. The Partnership primarily deals with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. The Partnership has entered into Master International Swaps and Derivatives Association Agreements ("ISDAs") that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership's counterparties failed to perform under existing swap contracts, the Partnership's maximum loss as of September 30, 2014 of $1.3 million would be reduced to $0.2 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.

Fair Value of Derivative Instruments

Assets and liabilities related to the Partnership's derivative contracts are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as a loss on derivatives in the consolidated statement of operations. The Partnership estimates the fair value of all of its derivative contracts using actively quoted prices. The estimated fair value of derivative contracts by maturity date was as follows (in millions):



	Maturity Periods
	Less than one year		One to two years			More than two years			Total fair value
September 30, 2014	$	0.2	$	(0.3	)	$	(0.1	)	$	(0.2	)

(13) Fair Value Measurements

FASB ASC 820 sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under FASB 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.

FASB ASC 820 establishes 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.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

The Partnership’s 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 liabilities measured at fair value on a recurring basis are summarized below (in millions):



	September 30, 2014 Level 2
Commodity Swaps*	$	(0.2	)
Total	$	(0.2	)

_________________________________________________

* The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.

Fair Value of Financial Instruments

The estimated fair value of the Company’s financial instruments has been determined by the Company 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 the Company could realize upon the sale or refinancing of such financial instruments (in millions):



	September 30, 2014
	Carrying Value		Fair Value
Long-term debt	$	1,853.9	$	1,916.4
Obligations under capital leases	$	21.1	$	20.7

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

The Partnership had $371.0 million in outstanding borrowings under its revolving credit facility as of September 30, 2014. The Company had $80.5 million in borrowings under its revolving credit facility included in long-term debt as of September 30, 2014. As borrowings under the Company's credit facility and other borrowings related to E2 of $26.3 million accrued interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding. As of September 30, 2014, the Partnership had borrowings totaling $397.3 million, $446.5 million and $346.8 million, net of discount, under the 2019 Notes, 2024 Notes and 2044 Notes, with a fixed rate of 2.70%, 4.40% and 5.60%, respectively. Additionally, the Partnership had borrowings of $185.1 million, including premium, under the 2022 Notes with a fixed rate of 7.125% as of September 30, 2014. The fair value of all senior unsecured notes as of September 30, 2014 was based on Level 2 inputs from third-party market quotations. The fair value of obligations under capital leases was calculated using Level 2 inputs from third-party banks.

(14) Commitments and Contingencies

(a) Employment and Severance Agreements

Certain members of management of the Partnership are parties to employment and/or severance agreements with the General Partner. The employment and severance agreements provide those managers with severance payments in certain circumstances and, in the case of employment agreements, prohibit each such person from competing with the General Partner or its affiliates for a certain period of time following the termination of such person’s employment.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(b) Environmental Issues

The operation of pipelines, plants and other facilities for the gathering, processing, transmitting or disposing of natural gas, NGLs, brine and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's results of operations, financial condition or cash flows.

The Partnership is 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 its financial position or results of operations.

At times, the Partnership’s subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations or financial condition.

The Partnership (or its subsidiaries) is defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas.

In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans, but was removed to the United States District Court for the Eastern District of Louisiana. The amount of damages is unspecified. The Partnership's subsidiary, Crosstex LIG, LLC, is one of the named defendants as the owner of pipelines in the area. The validity of the causes of action, as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case.

In June 2014, a group of landowners in Assumption Parish, Louisiana added a subsidiary of the Partnership, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine Company, LLC, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the August 2012 sinkhole that formed in the Bayou Corne area of Assumption Parish, Louisiana. The suit is pending in the 23^rdJudicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants have been pending since October 2012, plaintiffs are now alleging that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

The Partnership owns and operates a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of these pipelines and underground storage reservoirs. The Partnership is assessing the potential for recovering its losses from responsible parties. The Partnership has sued Texas Brine, LLC, the operator of a failed cavern in the area, and its insurers seeking recovery for this

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

damage. The Partnership also filed a claim with its insurers. The Partnership's insurers denied its claim. The Partnership disputes the denial but has agreed to stay the matter pending resolution of its claims against Texas Brine and its insurers. In August 2014, the Partnership received a partial settlement in the amount of $6.1 million. Additional claims related to this matter remain outstanding. The Partnership cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties.

In October 2014, Williams Olefins, L.L.C. filed a lawsuit against a subsidiary of the Partnership, EnLink NGL Marketing, LP, in the District Court of Tulsa County, Oklahoma. The plaintiff alleges breach of contract and negligent misrepresentation relating to an ethane output contract between the parties and the subsidiary’s termination of ethane production from one of its fractionation plants. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership’s costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case.

(15) Segment Information

Identification of the Company's operating segments is based principally upon geographic regions served. The Company’s reportable segments consist of the following: natural gas gathering, processing, transmission and fractionation operations located in north Texas, south Texas and the Permian Basin in west Texas ("Texas"), the pipelines and processing plants located in Louisiana and NGL assets located in south Louisiana ("Louisiana"), natural gas gathering and processing operations located throughout Oklahoma ("Oklahoma") and crude rail, truck, pipeline, and barge facilities in the Ohio River Valley ("ORV"), which includes the Company's consolidated E2 operations. Operating activity for intersegment eliminations is shown in the corporate segment. The Company’s sales are derived from external domestic customers.

Corporate expenses include general partnership expenses associated with managing all reportable operating segments. Corporate assets consist primarily of cash, property and equipment, including software, for general corporate support, debt financing costs and its investments in HEP and GCF. The Company evaluates the performance of its operating segments based on operating revenues and segment profits.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

Summarized financial information concerning the Company’s reportable segments is shown in the following tables:



	Texas			Louisiana			Oklahoma			Ohio River Valley			Corporate			Totals
	(In millions)
Three Months Ended September 30, 2014
Sales to external customers	$	77.3		$	491.3		$	—		$	79.1		$	—		$	647.7
Sales to affiliates	148.9			39.5			45.9			—			(28.0		)	206.3
Purchased gas, NGLs, condensate and crude oil	(76.8		)	(486.9		)	—			(61.5		)	28.0			(597.2		)
Operating expenses	(36.2		)	(23.7		)	(7.0		)	(9.8		)	—			(76.7		)
Gain on litigation settlement	—			6.1			—			—			—			6.1
Gain on derivative activity	—			—			—			—			1.0			1.0
Segment profit	$	113.2		$	26.3		$	38.9		$	7.8		$	1.0		$	187.2
Depreciation and amortization	$	(31.6	)	$	(19.1	)	$	(11.8	)	$	(10.0	)	$	(0.9	)	$	(73.4	)
Goodwill	$	1,168.2		$	786.8		$	190.3		$	112.5		$	1,436.8		$	3,694.6
Capital expenditures	$	79.7		$	79.1		$	2.5		$	42.2		$	3.9		$	207.4
Three Months Ended September 30, 2013
Sales to external customers	$	32.9		$	—		$	13.9		$	—		$	—		$	46.8
Sales to affiliates	359.4			—			172.0			—			—			531.4
Purchased gas, NGLs, condensate and crude oil	(286.2		)	—			(149.3		)	—			—			(435.5		)
Operating expenses	(26.9		)	—			(8.9		)	—			—			(35.8		)
Segment profit	$	79.2		$	—		$	27.7		$	—		$	—		$	106.9
Depreciation and amortization	$	(29.0	)	$	—		$	(19.0	)	$	—		$	—		$	(48.0	)
Goodwill	$	325.4		$	—		$	76.3		$	—		$	—		$	401.7
Capital expenditures	$	27.1		$	—		$	10.0		$	—		$	—		$	37.1
Nine Months Ended September 30, 2014
Sales to external customers	$	214.3		$	1,221.9		$	11.5		$	187.5		$	—		$	1,635.2
Sales to affiliates	637.7			41.7			256.0			—			(63.4		)	872.0
Purchased gas, NGLs, condensate and crude oil	(423.0		)	(1,158.2		)	(133.8		)	(146.4		)	63.4			(1,798.0		)
Operating expenses	(106.5		)	(45.5		)	(20.9		)	(22.6		)	—			(195.5		)
Gain on litigation settlement	—			6.1			—			—			—			6.1
Loss on derivative activity	—			—			—			—			(1.9		)	(1.9		)
Segment profit (loss)	$	322.5		$	66.0		$	112.8		$	18.5		$	(1.9	)	$	517.9
Depreciation and amortization	$	(91.7	)	$	(43.4	)	$	(37.6	)	$	(21.6	)	$	(1.5	)	$	(195.8	)
Goodwill	$	1,168.2		$	786.8		$	190.3		$	112.5		$	1,436.8		$	3,694.6
Capital expenditures	$	180.2		$	222.4		$	10.5		$	67.8		$	12.6		$	493.5
Nine Months Ended September 30, 2013
Sales to external customers	$	96.6		$	—		$	39.5		$	—		$	—		$	136.1
Sales to affiliates	1,052.3			—			504.7			—			—			1,557.0
Purchased gas, NGLs, condensate and crude oil	(838.7		)	—			(440.9		)	—			—			(1,279.6		)
Operating expenses	(92.0		)	—			(24.0		)	—			—			(116.0		)
Segment profit	$	218.2		$	—		$	79.3		$	—		$	—		$	297.5
Depreciation and amortization	$	(82.4	)	$	—		$	(56.2	)	$	—		$	—		$	(138.6	)
Goodwill	$	325.4		$	—		$	76.3		$	—		$	—		$	401.7
Capital expenditures	$	113.9		$	—		$	58.7		$	—		$	—		$	172.6

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

The table below presents information about segment assets as of September 30, 2014 and December 31, 2013:



	September 30, 2014		December 31, 2013
Segment Identifiable Assets:	(In millions)
Texas	$	3,236.9	$	1,460.0
Louisiana	2,925.3		—
Oklahoma	894.5		777.1
Ohio River Valley	677.0		—
Corporate	1,794.1		72.7
Total identifiable assets	$	9,527.8	$	2,309.8

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Segment profits	$	187.2		$	106.9		$	517.9		$	297.5
General and administrative expenses	(24.5		)	(10.8		)	(66.9		)	(32.3		)
Depreciation and amortization	(73.4		)	(48.0		)	(195.8		)	(138.6		)
Operating income	$	89.3		$	48.1		$	255.2		$	126.6

(16) Discontinued Operations

The Predecessor’s historical assets comprised all of Devon’s U.S. midstream assets and operations. However, only its assets serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as contractual rights to the benefits and burdens associated with Devon's 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the business combination on March 7, 2014. Therefore, the Predecessor's non-contributed historical assets and liabilities are presented as held for sale as of December 31, 2013. All operations activity related to the non-contributed assets prior to March 7, 2014 are classified as discontinued operations.

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

The following schedule summarizes net income from discontinued operations (in millions):



	Three Months Ended September 30,			Nine Months Ended September 30,
	2013			2014		2013

Operating revenues:
Operating revenues	$	10.9		$	6.8	$	33.5
Operating revenues - affiliates	20.8			10.5		68.1
Total operating revenues	31.7			17.3		101.6

Operating expenses:
Operating expenses	37.9			15.7		91.7
Total operating expenses	37.9			15.7		91.7

Income (loss) before income taxes	(6.2		)	1.6		9.9
Income tax expense (benefit)	(2.2		)	0.6		3.6
Net income (loss)	(4.0		)	1.0		6.3
Net income attributable to non-controlling interest	(0.3		)	—		(1.4		)
Net income (loss) including non-controlling interest	$	(4.3	)	$	1.0	$	4.9

The following table presents the main classes of assets and liabilities associated with the Partnership's discontinued operations at December 31, 2013. There were no assets and liabilities associated with discontinued operations at September 30, 2014:



	December 31, 2013
	(in millions)
Inventories	$	0.2
Other current assets	0.2
Total current assets	0.4
Property, plant & equipment	72.3
Total assets	$	72.7

Accounts payable	$	3.2
Other current liabilities	1.1
Total current liabilities	4.3
Asset retirement obligations	7.1
Deferred income taxes	25.3
Other long-term liabilities	0.3
Total liabilities	$	37.0

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements-(Continued)

(17) Subsequent Events

E2 Drop Down. On October 22, 2014, EnLink Midstream, Inc. (“EMI”), a wholly-owned subsidiary of ENLC, sold 100% of the Class A Units and 50% of the Class B Units (collectively, the “E2 Appalachian Units”) in E2 Appalachian Compression, LLC (“E2 Appalachian”), and 93.7% of the Class A Units (the “Energy Services Units” and, together with the E2 Appalachian Units, the “Purchased Units”) in E2 Energy Services, LLC (“Energy Services”), to the Partnership. The total consideration paid by the Partnership to EMI for the Purchased Units included (i) $13.0 million in cash for the Energy Services Units and (ii) $150.0 million in cash and 1,016,322 common units representing limited partner interests in the Partnership for the E2 Appalachian Units. The remaining 50% of the Class B Units in E2 Appalachian are owned by members of the E2 Appalachian management team and are designed to provide such management team members with equity incentives. Pursuant to the limited liability company agreement of E2 Appalachian, such management owners will be required to sell their Class B Units to ENLK on either December 31, 2015 or March 31, 2016.

E2 Non-Controlling Interest Purchase. On October 10, 2014, the Company purchased 100% of Class A units and 50% of Class B Units owned by E2 management in E2 Appalachian Compression, LLC for $7.0 million and $5.5 million, respectively.

Acquisition of Natural Gas Pipeline Assets. Effective November 1, 2014, the Partnership acquired, through one of its wholly owned subsidiaries, Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana for $235.0 million, subject to certain adjustments. The natural gas assets include natural gas pipelines spanning from Beaumont, Texas to the Mississippi River corridor and working natural gas storage capacity in southern Louisiana.

In September 2014, the Partnership paid the sellers, Chevron Pipe Line Company and Chevron Midstream Pipelines LLC, $23.5 million deposit, which is included in "Other assets, net" on the condensed consolidated balance sheet.

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

You should 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.

The historical financial statements included in this report reflect (1) for periods prior to March 7, 2014, the assets, liabilities and operations of EnLink Midstream Holdings, LP Predecessor (the “Predecessor”), the predecessor to EnLink Midstream Holdings, LP (“Midstream Holdings”), which is the historical predecessor of EnLink Midstream, LLC and (2) for periods on or after March 7, 2014, the results of operations of EnLink Midstream, LLC, after giving effect to the business combination discussed under “Devon Energy Transaction” below. The Predecessor was comprised of all of the U.S. midstream assets and operations of Devon Energy Corporation (“Devon”) prior to the business combination, including its 38.75% economic interest in Gulf Coast Fractionators ("GCF"). However, in connection with the business combination, only the Predecessor’s systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales in Texas and Oklahoma, as well as the economic burdens and benefits of the 38.75% economic interest in GCF, were contributed to Midstream Holdings, effective as of March 7, 2014.

You should read this discussion in conjunction with the historical financial statements and accompanying notes included in this report. All references in this section to the "Company", as well as the terms “our,” “we,” “us” and “its” (1) for periods prior to March 7, 2014 refer to the Predecessor and (2) for periods on or after March 7, 2014 refer to EnLink Midstream, LLC, together with its consolidated subsidiaries including the Partnership and Midstream Holdings. All references in this section to the "Partnership" (1) for periods prior to March 7, 2014 refer to the Predecessor and (2) for periods on or after March 7, 2014 refer to EnLink Midstream Partners, LP, together with its consolidated subsidiaries including EnLink Midstream Operating, LP (formerly known as Crosstex Energy Services, L.P.) (the "Operating Partnership"), Midstream Holdings and their consolidated subsidiaries.

Overview

We are a Delaware limited liability company formed in October 2013. Our assets consist of equity interests in EnLink Midstream Partners, LP, EnLink Midstream Holdings, LP, E2 Energy Services, LLC and E2 Appalachian Compression, LLC (collectively, “E2”). EnLink Midstream Partners, LP is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. EnLink Midstream Holdings, LP, a partnership owned by the Partnership and us, is engaged in the gathering, transmission and processing of natural gas. E2 is a services company focused on the Utica Shale play in the Ohio River Valley. Our interests in EnLink Midstream Partners, LP, EnLink Midstream Holdings, LP and E2 consist of the following as of September 30, 2014:


•	16,414,830 common units representing an aggregate 7% limited partner interest in the Partnership;


•	100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership, which owns a 0.7% general partner interest and all of the incentive distribution rights in the Partnership;


•	50.0% limited partner interest in Midstream Holdings; and


•	89.8% interest in E2 Energy Services, LLC and a 90.6% interest in E2 Appalachian Compression, LLC, with the remainder owned by E2 management.

Each of the Partnership and Midstream Holdings is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership’s or Midstream Holdings’ business, as applicable, or to provide for future distributions. Other than with respect to distributions to cover tax liabilities allocated to the members, the limited liability company agreements of each of E2 Energy Services, LLC and E2 Appalachian Compression, LLC provide that distributions will be made to the members at such time and in such amounts as determined by the board of directors of the applicable entity.

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

Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries. Since the Partnership controls Midstream Holdings through the ownership of its general partner, the financial results of the Partnership consolidate all of Midstream Holdings' financial results. Our condensed consolidated results

of operations are derived from the results of operations of the Partnership and also include our deferred taxes, interest of non-controlling partners in the Partnership’s net income, interest income (expense) and general and administrative expenses not reflected in the Partnership’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 the Partnership and Midstream Holdings.

The Partnership primarily focuses on providing midstream energy services, including gathering, processing, transmission and marketing, to producers of natural gas, natural gas liquids ("NGLs") and crude oil. The Partnership also provides crude oil, condensate and brine disposal services to producers. The Partnership's midstream energy asset network includes approximately 8,800 miles of pipelines, thirteen natural gas processing plants, seven fractionators, 3.1 million barrels of NGL cavern storage, rail terminals, barge terminals, truck terminals and a fleet of approximately 100 trucks. E2 builds, owns and operates natural gas compression and condensate stabilization facilities. The Partnership manages and reports its activities primarily according to geography. The Partnership has five reportable segments: (1) Texas, which includes the Partnership's activities in north Texas and the Permian Basin in west Texas; (2) Oklahoma, which includes the Partnership's activities in Cana-Woodford and Arkoma-Woodford Shale areas; (3) Louisiana, which includes the Partnership's pipelines, processing plants and NGL assets located in Louisiana; (4) ORV, which includes the Partnership's activities in the Utica and Marcellus Shales and our consolidated E2 operations; and (5) Corporate Segment, or Corporate, which includes the Partnership's equity investments in Howard Energy Partners, or HEP, in the Eagle Ford Shale, its contractual right to the burdens and benefits associated with Devon's ownership interest in GCF in south Texas and our general partnership property and expenses.

The Partnership manages its operations by focusing on gross operating margin because the Partnership's business is generally to purchase and resell natural gas, NGLs and crude oil for a margin or to gather, process, transport or market natural gas, NGLs and crude oil for a fee. In addition, the Partnership earns a volume based fee for providing crude oil transportation and brine disposal services. The Partnership defines gross operating margin as operating revenue minus cost of purchased gas, NGLs, condensate and crude oil. Gross operating margin is a non-generally accepted accounting principle, or non-GAAP, financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below.

The Partnership's gross operating margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities, the volumes of NGLs handled at its fractionation facilities, the volumes of crude oil handled at its crude terminals, the volumes of crude oil gathered, transported, purchased and sold and the volume of brine disposed. The Partnership generates revenues from seven primary sources:

•purchasing and reselling or transporting natural gas and NGLs on the pipeline systems it owns;

•processing natural gas at its processing plants;

•fractionating and marketing the recovered NGLs;

•providing compression services;

•purchasing and reselling crude oil and condensate;

•providing crude oil and condensate transportation and terminal services; and

•providing brine transportation and disposal services.

The Partnership generally gathers or transports gas owned by others through its facilities for a fee, or it buys natural gas from a producer, plant or shipper at either a fixed discount to a market index or a percentage of the market index, then transports and resells the natural gas at the market index. The Partnership attempts to execute all purchases and sales substantially concurrently, or it enters into a future delivery obligation, thereby establishing the basis for the margin it will receive for each natural gas transaction. The Partnership’s gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. The Partnership is also party to certain long-term gas sales commitments that it satisfies through supplies purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time the supplies that it has under contract may decline due to reduced drilling or other causes and the Partnership 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 the Partnership’s purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. However, on occasion the Partnership has 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 it captures the

difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as margin. Changes in the basis spread can increase or decrease margins.

The Partnership has made commitments to purchase natural gas in production areas based on production-area indices and to sell the natural gas into market areas based on market-area indices, pay the costs to transport the natural gas between the two points and capture the difference between the indices as margin. Changes in the index prices relative to each other (also referred to as basis spread) can significantly affect the Partnership's margins or even result in losses. For example, the Partnership is a party to one contract with a term to 2019 to supply approximately 150,000 MMBtu/d of gas. The Partnership buys gas for this contract on several different production-area indices on its North Texas Pipeline and sells the gas into a different market area index. The Partnership realizes a loss on the delivery of gas under this contract each month based on current prices. The balance sheet as of September 30, 2014 reflects a liability of $85.2 million related to this onerous performance obligation based on forecasted discounted cash obligations in excess of market under this gas delivery contract. Reduced supplies and narrower basis spreads in recent periods have increased the losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse.

The Partnership generally gathers or transports crude oil and condensate owned by others by rail, truck, pipeline and barge facilities for a fee, or it buys crude oil and condensate from a producer at a fixed discount to a market index, then transports and resells the crude oil and condensate at the market index. The Partnership executes all purchases and sales substantially concurrently, thereby establishing the basis for the margin it will receive for each crude oil and condensate transaction. Additionally, it provides crude oil, condensate and brine services on a volume basis.

The Partnership also realizes gross operating margins from its processing services primarily through three different contract arrangements: processing margins ("margin"), percentage of liquids ("POL") or fixed-fee based. Under margin contract arrangements the Partnership’s gross operating margins are higher during periods of high liquid 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. Under fixed-fee based contracts the Partnership’s gross operating margins are driven by throughput volume. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

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

Devon Energy Transaction

On March 7, 2014, ENLC consummated the transactions contemplated by the Agreement and Plan of Merger, dated as of October 21, 2013 (the “Merger Agreement”), among EnLink Midstream, Inc., or EMI, Devon, Acacia Natural Gas Corp I, Inc., formerly a wholly-owned subsidiary of Devon ("New Acacia"), and certain other wholly-owned subsidiaries of Devon pursuant to which EMI and New Acacia each became wholly-owned subsidiaries of ENLC (collectively, the “Mergers”). Upon the closing of the Mergers (the “Closing”), each issued and outstanding share of EMI’s common stock was converted into the right to receive (i) one Common Unit and (ii) an amount in cash equal to approximately $2.06. In addition, ENLC issued 115,495,669 Class B Units to a wholly-owned subsidiary of Devon, which units represent approximately 70% of the outstanding limited liability company interests in ENLC, with the remaining 30% held by the former stockholders of EMI in exchange for a 50% interest in Midstream Holdings. The Class B Units were substantially similar in all respects to the Common Units, except that they were only entitled to a pro rata distribution for the fiscal quarter ended March 31, 2014. The Class B Units automatically converted into Common Units on a one-for-one basis on May 6, 2014.

Midstream Holdings owns midstream assets previously held by Devon in the Barnett Shale in North Texas, the Cana- Woodford and Arkoma-Woodford Shales in Oklahoma and a contractual right to the benefits and burdens associated with Devon’s 38.75% interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. These assets consist of natural gas gathering and transportation systems, natural gas processing facilities and NGL fractionation facilities located in Texas and Oklahoma. Midstream Holdings' primary assets consist of three processing facilities with 1.3 Bcf/d of natural gas processing capacity, approximately 3,685 miles of pipelines with aggregate capacity of 2.9 Bcf/d and fractionation facilities with up to 160 MBbls/d of aggregate NGL fractionation capacity.

Also, on March 7, 2014, the Partnership consummated the transactions contemplated by the Contribution Agreement, dated as of October 21, 2013 (the “Contribution Agreement”), among the Partnership, EnLink Midstream Operating, LP

(formerly known as Crosstex Energy Services, L.P.), a wholly-owned subsidiary of the Partnership (“EnLink Midstream Operating”), Devon and certain of Devon’s wholly-owned subsidiaries.

Recent Developments

Our E2 Investment. As of September 30, 2014, we had invested approximately $105.4 million in E2. On October 10, 2014, we purchased 100% of Class A units and 50% of Class B Units of E2 Appalachian Compression, LLC owned by E2 management for $7.0 million and $5.5 million, respectively. E2 constructed three natural gas compressor stations and condensate stabilization facilities located in Noble and Monroe counties in the southern portion of the Utica Shale play in Ohio. Commercial operations of two of the facilities, Upper Hill and Reusser, commenced during January 2014 and April 2014, respectively, which are owned and operated by E2. Additionally, the Batesville station became operational in June 2014.

Acquisition of Natural Gas Pipeline Assets. On November 1, 2014, the Partnership acquired Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana, for $235.0 million, subject to certain adjustments. These natural gas pipeline assets include the following:


◦	Bridgeline System: approximately 985 miles of natural gas pipelines in southern Louisiana with a total system capacity of approximately 920 MMcf/d;


◦	Sabine Pipeline: approximately 150 miles of natural gas pipelines in Texas and southern Louisiana with a total capacity of approximately 235 MMcf/d;


◦	Chandeleur System: approximately 215 miles of offshore Mississippi and Alabama pipelines with a total capacity of approximately 330 MMcf/d;


◦	Storage Assets: three caverns located in southern Louisiana with a combined working capacity of approximately 11 Bcf, including two near Sorrento, LA with a capacity of approximately 4 Bcf and one inactive cavern near Napoleonville, LA with approximately 7 Bcf of capacity; and


◦	Henry Hub: ownership and management of the title tracking services offered at the Henry Hub, the delivery location for NYMEX natural gas futures contracts. Henry Hub is connected to 13 major interstate and intrastate natural gas pipeline and storage systems.

Ohio River Valley Condensate Pipeline and Condensate Stabilization Facilities. In August 2014, the Partnership announced plans to construct a new 45-mile, eight inch condensate pipeline and six natural gas compression and condensate stabilization facilities that will service major producer customers in the Utica Shale, including Eclipse Resources. As a component of the project, the Partnership has entered into a long-term, fee-based agreement under which Eclipse Resources will receive compression and stabilization services and has agreed to sell stabilized condensate to the Partnership.

The new-build stabilized condensate pipeline will connect to the Partnership's existing 200-mile pipeline in eastern Ohio, providing producer customers in the region access to premium market outlets through our barge facility on the Ohio river and rail terminal in Ohio. The pipeline, which is expected to be complete in the second half of 2015, will have an initial capacity of approximately 50,000 bpd.

The Partnership will also build and operate six natural gas compression and condensate stabilization facilities in Noble, Belmont, and Guernsey counties in Ohio. Upon completion, the facilities will have a combined capacity of approximately 560 MMcf/d of natural gas compression and approximately 41,500 bpd of condensate stabilization. The Partnership expects the first two compression and condensate stabilization facilities to be operational in the second half of 2014 and the remaining four facilities to be operational by the end of 2015.

In support of the project, the Partnership plans to leverage and expand its existing midstream assets in the region, including increasing condensate storage capacity and handling capabilities at its barge terminal on the Ohio River. The Partnership will add approximately 130,000 barrels of above ground storage, bringing its total storage capacity at the barge facility to over 360,000 barrels.

West Texas Expansion. The Partnership will expand its natural gas gathering and processing system in the Permian Basin by constructing a new natural gas processing plant and expanding the Partnership's rich gas gathering system. The new 120 MMcf/d gas processing plant will be strategically located on the north end of the Partnership's existing midstream assets and will offer additional gas processing capabilities to producer customers in the region, including Devon Energy. The processing plant is expected to be operational in the second half of 2015. Upon completion, the Partnership's total operated processing capacity in the region will be approximately 240 MMcf/d.

As a part of the expansion, the Partnership has signed a long-term, fee-based agreement with Devon Energy to provide gathering and processing services for over 18,000 acres under development in Martin County. The Partnership will construct multiple low pressure gathering pipelines and a new 23-mile, 12-inch high pressure gathering pipeline that will tie into the previously announced Bearkat natural gas gathering system. The new pipelines are expected to be operational in the first quarter of 2015.

Marathon Petroleum Joint Venture. The Partnership has entered into a series of agreements with MPL Investment LLC, a subsidiary of Marathon Petroleum Corporation, to create a 50/50 joint venture named Ascension Pipeline Company, LLC. This joint venture will build a new 30-mile NGL pipeline connecting the Partnership’s existing Riverside fractionation and terminal complex to Marathon Petroleum’s Garyville refinery located on the Mississippi River. The bolt-on project to the Partnership’s Cajun-Sibon NGL system is supported by long-term, fee-based contracts with Marathon Petroleum. Under the arrangement, the Partnership will serve as the construction manager and operator of the pipeline project, which is expected to be operational in the first half of 2017.

Cajun-Sibon Phases I and II. In Louisiana, the Partnership is transforming its business that historically has been focused on processing offshore natural gas to a business that is focused on NGLs with additional opportunities for growth from new onshore supplies of NGLs. The Louisiana petrochemical market historically has relied on liquids from offshore production; however, the decrease in offshore production and increase in onshore rich gas production have changed the market structure. Cajun-Sibon Phases I and II will work to bridge the gap between supply, which aggregates in the Mont Belvieu area, and demand, located in the Mississippi River corridor of Louisiana, thereby building a strategic NGL position in this region.

The pipeline expansion and the Eunice fractionation expansion under Phase I were completed and commenced operation in November 2013. Cajun-Sibon Phase II will further enhance the Partnership's Louisiana NGL business with significant additions to the Cajun-Sibon Phase I NGL pipeline extension and Eunice expansion. The expansion of the Partnership's Cajun-Sibon pipeline capacity and new Plaquemine fractionator were completed and commenced operation in September 2014. Phase II of the Cajun-Sibon project increased the Cajun-Sibon pipeline capacity by an additional 50,000 Bbls/d to a total of 120,000 Bbls/d and includes a new 100,000 Bbl/d fractionator at the Partnership's Plaquemine gas processing complex. The throughput through the pipeline averaged 50,000 Bbls/d during the third quarter of 2014 due to downtime related to the start-up of Phase II. The Eunice fractionator in south Louisiana averaged approximately 43,000 Bbls/d during the third quarter of 2014. Additionally, the Partnership's Riverside fractionator resumed service in September 2014 as a heavy end fractionator after being shut-down in July 2014 for planned maintenance related to Phase II.

The Partnership believes the Cajun-Sibon project not only represents a tremendous growth step by leveraging its Louisiana assets, but that it also creates a significant platform for continued growth of the Partnership's NGL business. The project, along with existing assets, will provide a number of additional opportunities to grow this business, including expanding market optionality and connectivity, upgrading products, expanding rail imports, exporting NGLs and expanding fractionation and product storage capacity.

Bearkat Natural Gas Gathering and Processing System. In September 2014, the Partnership completed construction of a new natural gas processing complex and rich gas gathering pipeline system in the Permian Basin called Bearkat. The natural gas processing complex includes treating, processing and gas takeaway solutions for regional producers. The project, which is fully owned by the Partnership, is supported by a 10-year, fee-based contract.

Bearkat is strategically located near the Partnership's existing Deadwood joint venture assets in Glasscock County, Texas. The processing plant has an initial capacity of 60 MMcf/d, increasing the Partnership’s total operated processing capacity in the Permian to approximately 115 MMcf/d. The Partnership also completed construction on a 30-mile high-pressure gathering system upstream of the Bearkat complex to provide additional gathering capacity for producers in Glasscock and Reagan counties.

Additionally, in February 2014, the Partnership entered into an agreement to construct a new 35-mile, 12-inch diameter high-pressure pipeline that will provide critical gathering capacity for the Bearkat natural gas processing complex. The pipeline will have an initial capacity of approximately 100 MMcf/d and will provide gas takeaway solutions for constrained producer customers in Howard, Martin and Glasscock counties. The pipeline is expected to be operational in the fourth quarter of 2014.

Issuance of Common Units. In May 2014, the Partnership entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (“BMOCM”). Pursuant to the terms of the EDA, the Partnership may from time to time through BMOCM, as its sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75.0 million.

Senior Unsecured Notes. On March 12, 2014, the Partnership commenced a tender offer to purchase any and all of its outstanding 8.875% Senior Notes due 2018 (the "2018 Notes"). Approximately $536.1 million, or approximately 74%, of the 2018 Notes were validly tendered, and on March 19, 2014, the Partnership made a payment of approximately $567.4 million for all such tendered 2018 Notes. Also on March 19, 2014, the Partnership delivered a notice of redemption for any and all outstanding 2018 Notes. The redemption for the remaining $198.2 million of outstanding 2018 Notes was completed on April 18, 2014 for $200.2 million, including accrued interest.

On July 22, 2014, the Partnership redeemed $18.5 million in aggregate principal amount of 7.125% senior unsecured notes (the “2022 Notes”) due on June 1, 2022 for $20.0 million, including accrued interest. On September 20, 2014, the Partnership redeemed an additional $15.5 million aggregate principal amount of the 2022 Notes for $17.0 million, including accrued interest.

Non-GAAP Financial Measures

Cash Available for Distribution

We define cash available for distribution as distributions due to us from the Partnership and from our 50% interest in Midstream Holdings, less our specific general and administrative costs as a separate public reporting entity, the interest costs associated with our debt and taxes attributable to our earnings. Cash available for distribution is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Cash available for distribution is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment.

The GAAP measure most directly comparable to cash available for distribution is net income. Cash available for distribution should not be considered as an alternative to GAAP net income. 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, but not all, items that affect net income 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 the Company's cash available for distribution (in millions):



	Three Months Ended September 30, 2014
	(Unaudited)
Distribution declared by ENLK associated with (1):
General partner interest	$	0.6
Incentive distribution rights	6.3
ENLK common units owned	6.4
Total share of ENLK distributions declared	$	13.3
Adjusted EBITDA of Midstream Holdings (2)	59.2
Total cash available	$	72.5
Uses of cash:
General and administrative expenses	(0.9		)
Current income taxes (3)	(5.9		)
Interest expense	(0.7		)
Maintenance capital expenditures (4)	(2.8		)
Total cash used	$	(10.3	)
ENLC cash available for distribution	$	62.2


(1)	Represents distributions declared by ENLK and to be paid to ENLC on November 13, 2014.

(2)

Represents ENLC's 50% interest in Midstream Holdings' adjusted EBITDA , which is disbursed on a monthly basis to ENLC by Midstream Holdings. Midstream Holdings' adjusted EBITDA is defined as earnings plus depreciation, provision for income taxes and distributions from equity investment less income from equity investment. ENLC's share of Midstream Holdings' adjusted EBITDA is comprised of its 50% share in Midstream Holdings' net income of $41.7 million plus its 50% share in Midstream Holdings' depreciation of $17.2 million, taxes of $0.3 million and distributions from equity investment of $2.6 million, less its 50% share of income from equity investment of $2.6 million.


(3)	Represents ENLC's stand-alone current income tax estimate. Based on current forecasted taxable income estimates for 2014, ENLC's taxable income is expected to exceed its federal net operating loss carryforward during 2014.


(4)	Represents ENLC's interest in Midstream Holdings' maintenance capital expenditures which is netted against the monthly disbursement of Midstream Holdings' adjusted EBITDA per (2) above.

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



	Three Months Ended September 30, 2014
	(Unaudited)

Net income of ENLC	$	66.5
Less: Net income attributable to ENLK	(44.0		)
Net Income of ENLC excluding ENLK	$	22.5
ENLC's share of distributions from ENLK (1)	13.3
ENLC's interest in Midstream Holdings' depreciation (2)	17.2
ENLC's interest in distributions from Midstream Holding's equity investment	2.6
ENLC's interest in income from Midstream Holding's equity investment	(2.6		)
ENLC's interest in Midstream Holdings' taxes	0.3
ENLC deferred income tax expense (3)	11.8
Depreciation attributable to E2	1.8
Maintenance capital expenditures (4)	(2.8		)
Other items (5)	(1.9		)
ENLC cash available for distribution	$	62.2


(1)	Represents distributions declared by ENLK and to be paid to ENLC on November 13, 2014.


(2)	Represents ENLC's interest in Midstream Holdings' depreciation, which is reflected as a non-cash deduction in the net income of ENLC excluding ENLK.


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


(4)	Represents ENLC's interest in Midstream Holdings' maintenance capital expenditures, which is netted against the monthly disbursement of Midstream Holdings' adjusted EBITDA.


(5)	Represents E2's adjusted EBITDA and other non-cash items not included in cash available for distributions.

ENLC cash available for distributions is not presented for the nine months ended September 30, 2014 or the comparative periods in 2013 because the historical results of operations for periods prior to March 7, 2014 reflect the operations of the Predecessor which would not be considered in this non-GAAP financial measure.

Gross Operating Margin. We include gross operating margin as a non-GAAP financial measure. We define gross operating margin, generally, as revenues less cost of purchased gas, NGLs, condensate and crude oil. 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 our business is generally to purchase and resell natural gas and crude oil for a margin or to gather, process, transport or market natural gas, NGLs and crude oil for a fee. Operating expense is a separate measure used by 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. As an indicator of our operating performance, gross operating margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our gross operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.

The following table provides a reconciliation of gross operating margin to operating income:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Total gross operating margin	$	257.8		$	142.7		$	707.3		$	413.5

Deduct:
Operating expenses	(76.7		)	(35.8		)	(195.5		)	(116.0		)
General and administrative expenses	(24.5		)	(10.8		)	(66.9		)	(32.3		)
Gain on litigation settlement	6.1			—			6.1			—
Depreciation and amortization	(73.4		)	(48.0		)	(195.8		)	(138.6		)
Operating income	$	89.3		$	48.1		$	255.2		$	126.6

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 operating revenue less cost of purchased gas, NGLs, condensate and crude oil as reflected in the table below.

Items Affecting Comparability of Our Financial Results

Our historical financial results discussed below may not be comparable to our future financial results, and our financial results for the three and nine months ended September 30, 2013 may not be comparable to our financial results for the three and nine months ended September 30, 2014, for the following reasons:

•

In connection with the business combination, Midstream Holdings entered into new agreements with Devon that were effective on March 1, 2014 pursuant to which Midstream Holdings provides services to Devon under fixed-fee arrangements in which Midstream Holdings does not take title to the natural gas gathered or processed or the NGLs it fractionates. Prior to the effectiveness of these agreements, the Predecessor provided services to Devon under a percent-of-proceeds arrangement in which it took title to the natural gas it gathered and processed and the NGLs it fractionated.


•	Prior to March 7, 2014, our financial results only included the assets, liabilities and operations of our Predecessor. Beginning on March 7, 2014, our financial results also consolidate the assets, liabilities and operations of the legacy business of the Partnership prior to giving effect to the business combination.

•

Subsequent to March 7, 2014, we own a 50% direct ownership interest in Midstream Holdings and indirectly own an additional interest of approximately 3% of Midstream Holdings through our ownership in the Partnership which owns the remaining 50% interest in Midstream Holdings rather than the 100% ownership reflected as part of our Predecessor’s historical financial results. Our financial statements after March 7, 2014 consolidate all of Midstream Holdings’ financial results with ours in accordance with GAAP and ENLK’s 47% interest not owned by us in Midstream Holdings is reflected as a non-controlling interest.


•	Our financial statements for the three and nine months ended September 30, 2014 report financial results according to operating segments based principally upon geographic regions served. The Predecessor had no operations for certain of those reporting segments.

•

The Predecessor’s historical assets comprised all of Devon’s U.S.-midstream assets and operations. However, only its assets serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as a contractual right to the burdens and benefits of its 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the consummation of the business combination. Assets that were not contributed to Midstream Holdings are included in discontinued operations.

•

All historical affiliated transactions prior to March 7, 2014 related to our continuing operations were net settled within our combined financial statements because these transactions related to Devon and were funded by Devon’s working capital. Beginning on March 7, 2014, all our transactions are funded by our working capital. This will impact the comparability of our cash flow statements, working capital analysis and liquidity discussion.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions, except volumes)
Texas Segment
Revenues	$	226.2		$	392.3		$	852.0		$	1,148.9
Purchased gas and NGLs	(76.8		)	(286.2		)	(423.0		)	(838.7		)
Total gross operating margin	$	149.4		$	106.1		$	429.0		$	310.2
Louisiana Segment
Revenues	$	530.8		$	—		$	1,263.6		$	—
Purchased gas, NGLs and crude oil	(486.9		)	—			(1,158.2		)	—
Total gross operating margin	$	43.9		$	—		$	105.4		$	—
Oklahoma Segment
Revenues	$	45.9		$	185.9		$	267.5		$	544.2
Purchased gas and NGLs	—			(149.3		)	(133.8		)	(440.9		)
Total gross operating margin	$	45.9		$	36.6		$	133.7		$	103.3
ORV Segment
Revenues	$	79.1		$	—		$	187.5		$	—
Purchased crude oil and condensate	(61.5		)	—			(146.4		)	—
Total gross operating margin	$	17.6		$	—		$	41.1		$	—
Corporate
Revenues	$	(27.0	)	$	—		$	(65.3	)	$	—
Purchased gas and NGLs	28.0			—			63.4			—
Total gross operating margin	$	1.0		$	—		$	(1.9	)	$	—
Total
Revenues	$	855.0		$	578.2		$	2,505.3		$	1,693.1
Purchased gas, NGLs, condensate and crude oil	(597.2		)	(435.5		)	(1,798.0		)	(1,279.6		)
Total gross operating margin	$	257.8		$	142.7		$	707.3		$	413.5

Midstream Volumes:
Texas (1)
Gathering and Transportation (MMBtu/d)	2,975,600			2,086,000			2,979,000			2,112,000
Processing (MMBtu/d)	1,152,400			831,000			1,149,100			807,000
Louisiana (2)
Gathering and Transportation (MMBtu/d)	500,200			—			459,300			—
Processing (MMBtu/d)	499,100			—			557,000			—
NGL Fractionation (Gals/d)	4,073,500			—			4,112,500			—
Oklahoma (3)
Gathering and Transportation (MMBtu/d)	494,200			387,000			472,000			384,000
Processing (MMBtu/d)	447,300			407,000			447,300			393,000
ORV (2)
Crude Oil Handling (Bbls/d)	15,200			—			15,400			—
Brine Disposal (Bbls/d)	5,000			—			5,300			—

__________________________________________________

(1)

Volumes include volumes per day based on 92 days and 273 day periods for the three and nine months ended September 30, 2014, for Midstream Holdings operations. Volumes include volumes per day based on 92 days for the three months ended September 30, 2014 and volumes based on the 208 day period from March 7 to September 30, 2014 for the nine months ended September 30, 2014 for the Partnership’s legacy operations in Texas.


(2)	Volumes include volumes per day based on 92 days for the three months ended September 30, 2014 and based on the 208 day period from March 7 to September 30, 2014 for the nine months ended September 30, 2014 for the Partnership’s legacy operations. Midstream Holdings does not have any operations in Louisiana or Ohio.


(3)	Volumes include volumes per day based on 92 and 273 day periods for the three and nine months ended September 30, 2014, respectively, for Midstream Holdings operations. The Partnership did not have any legacy operations in Oklahoma.

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

Gross Operating Margin. Gross operating margin was $257.8 million for the three months ended September 30, 2014 compared to $142.7 million for the three months ended September 30, 2013, an increase of $115.1 million, or 80.7%. Of this increase in gross operating margin, $103.0 million is attributable to the legacy Company assets associated with the business combination effective on March 7, 2014. Approximately $12.1 million of the increase in gross operating margin is related to Midstream Holdings, which is the result of the new fixed-fee arrangements with Devon entered into in connection with the business combination.

Operating Expenses. Operating expenses were $76.7 million for the three months ended September 30, 2014 compared to $35.8 million for the three months ended September 30, 2013, an increase of $40.9 million, or 114.2%. Of this increase in operating expenses, $44.1 million is attributable to the legacy Company assets, partially offset by a decrease in Midstream Holdings’ operating expenses of $3.1 million due to both lower personnel and contract labor and a decrease in compressor maintenance expense.

General and Administrative Expenses. General and administrative expenses were $24.5 million for the three months ended September 30, 2014 compared to $10.8 million for the three months ended September 30, 2013, an increase of $13.7 million, or 126.9%. General and administrative expenses for the three months ended September 30, 2014 reflect expenses associated with the new combined operations of the legacy Company and Midstream Holdings, including $1.0 million for transition service costs from Devon. General and administrative expenses for the three months ended September 30, 2013 reflect expenses for Midstream Holdings which primarily consisted of costs allocated by Devon for shared general and administrative services.

Depreciation and Amortization. Depreciation and amortization expenses were $73.4 million for the three months ended September 30, 2014 compared to $48.0 million for the three months ended September 30, 2013, an increase of $25.4 million, or 52.9%. The increase in depreciation and amortization expenses result from an increase in depreciation expense of $38.9 million related to the legacy Company assets acquired in March 2014. This increase was partially offset by a decrease of $13.5 million in depreciation and amortization expenses related to Midstream Holdings, with the primary driver being the change in depreciation methodology from the units-of-production method to the straight-line method of $9.3 million.

Gain on Litigation Settlement. We recognized a gain on the settlement of a lawsuit of $6.1 million for the three months ended September 30, 2014 due to a partial settlement of our claims against Texas Brine and its insurers. Additional claims related to this matter remain outstanding.

Interest Expense. Interest expense was $13.6 million for the three months ended September 30, 2014. There was no interest expense for the three months ended September 30, 2013 as Midstream Holdings did not have any debt. Net interest expense consists of the following (in millions):



	Three Months Ended September 30,
	2014
Senior notes	$	15.8
Bank credit facility	2.3
Capitalized interest	(4.6		)
Amortization of debt issue costs and net discount (premium)	(0.2		)
Other	0.3
Total	$	13.6

Income from Equity Investments. Income from equity investments was $5.6 million for the three months ended September 30, 2014 as compared to $5.8 million for the three months ended September 30, 2013, an decrease of $0.2 million. The decrease primarily relates to our investment in GCF due to a decease in volumes.

Income Tax Expense. Income tax expense was $17.3 million for the three months ended September 30, 2014 as compared to $19.3 million for the three months ended September 30, 2013, a decrease of $2.0 million or 10.4%. This decrease primarily relates to a decrease in taxable income between periods.

Net Income from Discontinued Operations. The Company had no net income from discontinued operations for the three months ended September 30, 2014 as compared to a net loss of $4.3 million for the three months ended September 30, 2013. Discontinued operations for the period ended September 30, 2013 included assets that were not contributed to Midstream Holdings, while Midstream Holdings had no discontinued operations during the period ended September 30, 2014.

Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $37.7 million for the three months ended September 30, 2014. Income attributable to non-controlling interests represents the combined limited partner interests in the Partnership owned by Devon and public unitholders, and the interest in E2 not owned by us.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Gross Operating Margin. Gross operating margin was $707.3 million for the nine months ended September 30, 2014 compared to $413.5 million for the nine months ended September 30, 2013, an increase of $293.8 million, or 71.1%. Of this increase in gross operating margin, $238.0 million is attributable to the legacy Company assets associated with the business combination effective on March 7, 2014. Approximately $55.8 million of the increase in gross operating margin is related to

Midstream Holdings, which is the result of the new fixed-fee arrangements with Devon entered into in connection with the

business combination.

Operating Expenses. Operating expenses were $195.5 million for the nine months ended September 30, 2014 compared to $116.0 million for the nine months ended September 30, 2013, an increase of $79.5 million, or 68.5%. Of this increase in operating expenses, $96.2 million is attributable to the legacy Company assets, partially offset by a decrease in Midstream Holdings’ operating expenses of $16.7 million due to both lower personnel and contract labor and a decrease in compressor maintenance expense.

General and Administrative Expenses. General and administrative expenses were $66.9 million for the nine months ended September 30, 2014 compared to $32.3 million for the nine months ended September 30, 2013, an increase of $34.6 million, or 107.1%. General and administrative expenses for the nine months ended September 30, 2014 reflect expenses associated with the new combined operations of the legacy Company and Midstream Holdings since March 7, 2014, including $2.3 million for transition service costs from Devon, together with general and administrative expenses of Midstream Holdings prior to March 7, 2014. General and administrative expenses for the nine months ended September 30, 2013 reflect expenses for Midstream Holdings which primarily consisted of costs allocated by Devon for shared general and administrative services.

Depreciation and Amortization. Depreciation and amortization expenses were $195.8 million for the nine months ended September 30, 2014 compared to $138.6 million for the nine months ended September 30, 2013, an increase of $57.2 million, or 41.3%. The increase in depreciation and amortization expenses results from an increase in depreciation expense of $88.1 million related to the legacy Company assets acquired in March 2014. The increase was partially offset by a decrease of $30.9 million in depreciation and amortization expenses related to Midstream Holdings with the primary driver being the change in depreciation methodology from the units-of-production method to the straight-line method of $21.0 million. The remaining decrease related to a $5.6 million decrease due to a change in the annual units of production rate partially offset by a $1.7 million increase related to assets placed in service during 2013.

Gain on Litigation Settlement. We recognized a gain on the settlement of a lawsuit of $6.1 million for the nine months

ended September 30, 2014 due to a partial settlement of our claims against Texas Brine and its insurers. Additional claims related to this matter remain outstanding.

Interest Expense. Interest expense was $33.1 million for the nine months ended September 30, 2014. There was no interest expense for the nine months ended September 30, 2013 as Midstream Holdings did not have any debt. Net interest expense consists of the following (in millions):



	Nine Months Ended September 30,
	2014
Senior notes	$	37.5
Bank credit facility	5.0
Capitalized interest	(9.9		)
Amortization of debt issue costs and net discount (premium)	(0.8		)
Other	1.3
Total	$	33.1

Income from Equity Investments. Income from equity investments was $14.3 million for the nine months ended September 30, 2014 as compared to $10.2 million for the nine months ended September 30, 2013, an increase of $4.1 million. The increase primarily relates to our investment in GCF due to downtime experienced during the 2013 period.

Income Tax Expense. Income tax expense was $59.5 million for the nine months ended September 30, 2014 as compared to $49.2 million for the nine months ended September 30, 2013, an increase of $10.3 million or 20.9%. This increase primarily relates to an increase in taxable income between periods.

Net Income from Discontinued Operations. Net income from discontinued operations was $1.0 million for the nine months ended September 30, 2014 as compared to $4.9 million for the nine months ended September 30, 2013, a decrease of $3.9 million. The decrease is due to Midstream Holdings’ discontinued operations for the period ended September 30, 2013 which included assets that were sold during 2013, while the nine month period ended September 30, 2014 includes Predecessor assets that were not contributed to Midstream Holdings as part of the business combination.

Net Income Attributable to Non-Controlling Interest. Net income attributable to non-controlling interest was $80.5 million for the nine months ended September 30, 2014. Income attributable to non-controlling interests represents the combined limited partner interests in the Partnership owned by Devon and public unitholders, and the interest in E2 not owned by us.

Critical Accounting Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment to the specific set of circumstances existing in our business. Compliance with the rules necessarily involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policies are discussed below. See Note 2 of the Notes to Consolidated Financial Statements for further details on our accounting policies.

Revenue Recognition and Commodity Risk Management. We recognize revenue for sales or services at the time the natural gas, NGLs or crude oil is delivered or at the time the service is performed. We generally accrue one month of sales and the related gas, NGL or crude oil purchases and reverse these accruals when the sales and purchases are actually invoiced and recorded in the subsequent months. Actual results could differ from the accrual estimates.

We utilize extensive estimation procedures to determine the sales and cost of gas, NGL or crude oil purchase accruals for each accounting cycle. Accruals are based on estimates of volumes flowing each month from a variety of sources. We use actual measurement data, if it is available, and will use such data as producer/shipper nominations, prior month average daily flows, estimated flow for new production and estimated end-user requirements (all adjusted for the estimated impact of weather patterns) when actual measurement data is not available. Throughout the month or two following production, actual measured sales and transportation volumes are received and invoiced and used in a process referred to as "actualization". Through the actualization process, any estimation differences recorded through the accrual are reflected in the subsequent month's accounting cycle when the accrual is reversed and actual amounts are recorded. Actual volumes purchased, processed or sold may differ from the estimates due to a variety of factors including, but not limited to: actual wellhead production or customer requirements being higher or lower than the amount nominated at the beginning of the month; liquids recoveries being higher or lower than estimated because gas processed through the plants was richer or leaner than estimated; the estimated impact of weather patterns being different from the actual impact on sales and purchases; and pipeline maintenance or allocation causing actual deliveries of gas to be different than estimated. We believe that our accrual process for sales and purchases provides a reasonable estimate of such sales and purchases.

We engage in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas, NGLs, crude oil and condensate. We also manage our price risk related to future physical purchase or sale commitments by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in natural gas and NGL prices.

We use derivatives to hedge against changes in cash flows related to product prices, as opposed to their use for trading purposes. FASB ASC 815 requires that all derivatives and hedging instruments are recognized as assets or liabilities at fair value. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

We manage our price risk related to future physical purchase or sale commitments for energy trading activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance future commitments and significantly reduce risk related to the movement in natural gas prices. However, we are subject to counter-party risk for both the physical and financial contracts. Our energy trading contracts qualify as derivatives and we use mark-to-market accounting for both physical and financial contracts of the energy trading business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to energy trading activities are recognized currently in earnings as gain or loss on derivatives.

Impairment of Long-Lived Assets. In accordance with FASB ASC 360-10-05, we evaluate the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value.

When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding the purchase and resale margins on natural gas, volume of gas available to the asset, markets available to the asset, operating expenses, and future natural gas prices and NGL product prices. The amount of availability of gas and crude oil to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas and crude oil prices. Projections of gas and crude oil volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:


•	changes in general economic conditions in regions in which our markets are located;


•	the availability and prices of natural gas, crude oil and condensate supply;


•	our ability to negotiate favorable sales agreements;


•	the risks that natural gas, crude oil and condensate exploration and production activities will not occur or be successful;


•	our dependence on certain significant customers, producers and transporters of natural gas, crude oil, and condensate; and


•	competition from other midstream companies, including major energy producers.

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

Impairment of Goodwill. Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We will evaluate goodwill for impairment annually as of October 31^st and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step process goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting

unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss.

Depreciation Expense and Cost Capitalization. Our assets consist primarily of natural gas, NGL, condensate and crude oil gathering pipelines, processing plants, transmission pipelines and trucks. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the costs of funds used in construction. Capitalized interest represents the cost of funds used to finance the construction of new facilities and is expensed over the life of the constructed assets through the recording of depreciation expense. We capitalize the costs of renewals and betterments that extend the useful life, while we expense the costs of repairs, replacements and maintenance projects as incurred.

Historically, Midstream Holdings depreciated certain property, plant, and equipment using the units-of-production method. As a result of the business combination, Midstream Holdings is operated as an independent midstream company and thus no longer has access to Devon’s proprietary reserve and production data historically used to compute depreciation under the units-of-production method. Additionally, the existing contracts with Devon were revised to a fee-based arrangement with minimum volume commitments. Effective March 7, 2014, the Partnership changed its method of computing depreciation for these assets to the straight-line method, consistent with the depreciation method applied to the Partnership’s legacy assets. In accordance with FASB ASC 250, the Partnership determined that the change in depreciation method is a change in accounting estimate and accordingly, the straight-line method will be applied on a prospective basis. This change is considered preferable because the straight-line method more accurately reflects the pattern of usage and the expected benefits of such assets.

Certain assets such as land, NGL line pack, natural gas line pack and crude oil line pack are non-depreciable. The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, we may review depreciation estimates to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values, which would impact future depreciation expense.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $362.0 million for the nine months ended September 30, 2014 compared to $245.0 million for the nine months ended September 30, 2013. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):



	Nine Months Ended September 30,
	2014			2013
Operating cash flows before working capital	$	430.2		$	238.0
Changes in working capital	$	(68.2	)	$	7.0

The primary reason for the increase in operating cash flows before working capital of $192.2 million from 2013 to 2014 relates to an increase in gross operating margin from the acquired legacy Company assets and Midstream Holdings assets. The decrease in working capital for 2014 related to fluctuations in trade receivable and payable balances due to timing of collection and payments and changes in inventory balances due to normal operating fluctuations. Further, prior to March 7, 2014, all cash receipts for the Predecessor were deposited into Devon’s bank accounts, and all cash disbursements were made from these accounts. Cash transactions handled by Devon were reflected in intercompany advances between Devon and the Predecessor, all of which were settled through an adjustment to equity and reflected in cash flows from financing activities. Subsequent to March 7, 2014, the Company and Midstream Holdings handle all of their cash transactions and the changes in working capital are reflected in our cash flows from operating activities.

Cash Flows from Investing Activities. Net cash used in investing activities was $585.3 million for the nine months ended September 30, 2014 and $200.2 million for the nine months ended September 30, 2013. Our primary investing cash flows were acquisition costs and capital expenditures, net of accrued amounts, as follows (in millions):



	Nine Months Ended September 30,
	2014			2013
Growth capital expenditures	$	488.4		$	149.0
Maintenance capital expenditures	23.4			52.3
Acquisition of business	51.9			—
Deposit for acquisition	23.5			—
Investment in equity investment company	5.7			—
Distribution from equity investment company in excess of earnings	(7.6		)	(1.1		)
Total	$	585.3		$	200.2

Cash Flows from Financing Activities. Net cash provided by financing activities was $262.8 million for the nine months ended September 30, 2014 and net cash used of $117.7 million for nine months ended September 30, 2013. All Predecessor financing activities from January 1, 2014 through March 6, 2014 and for the nine months ended September 30, 2013 totaling $27.2 million and $117.7 million, respectively, are reflected in distributions to the Predecessor on the statement of cash flows. Our primary financing activities subsequent to March 7, 2014 consist of the following (in millions):



	Nine Months Ended September 30, 2014
Net repayments on Partnership's bank credit facility	$	(6.0	)
Net borrowings on Company's credit facility	5.3
Net borrowings on E2's credit facility	12.5
Senior unsecured notes borrowings	1,190.0
Redemption of 2018 Notes	(760.3		)
Partial Redemption of 2022 notes	(36.4		)
Net repayments under capital lease obligations	(1.8		)
Debt refinancing costs	(7.5		)
Proceeds from issuance of Partnership units	71.9

Distributions to unitholders and non-controlling partners in the Partnership are also primary uses of cash in financing activity. Total cash distributions made during the nine months ended September 30, 2014 were as follows (in millions):



	Nine Months Ended September 30, 2014
Distributions to unitholders	$	51.0
Non-controlling partner distributions	124.2
Total	$	175.2

In order to reduce our interest costs, we do not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our credit facility. We borrow money under our credit facility to fund checks as they are presented. Change in drafts payable for the nine months ended September 30, 2014 was as follows (in millions):



	Nine Months Ended September 30, 2014
Decrease in drafts payable	$	(2.6	)

Uncertainties. The Partnership owns and operates a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of these pipelines and underground storage reservoirs. This sinkhole is situated west of the Partnership's underground natural gas and NGL storage facility. The cause of the sinkhole is currently under investigation by Louisiana state and local officials. The Partnership took a section of its 36-inch-diameter natural gas pipeline located near the sinkhole out of service. Service to

certain markets, primarily in the Mississippi River area, has been curtailed or interrupted, and the Partnership has worked with its customers to secure alternative natural gas supplies so that disruptions are minimized. The replacement pipeline was completed and services resumed in May 2014.

The Partnership is assessing the potential for recovering its losses from responsible parties. The Partnership has sued Texas Brine, LLC, the operator of a failed cavern in the area, and its insurers seeking recovery for this damage. The Partnership also filed a claim with its insurers. The Partnership's insurers denied its claim. The Partnership disputes the denial but has agreed to stay the matter pending resolution of its claims against Texas Brine and its insurers. In August 2014, the Partnership received a partial settlement in the amount of $6.1 million. We cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties.

Capital Requirements. During the nine months ended September 30, 2014, capital investments were $488.4 million, which were funded by internally generated cash flow, borrowings under the Partnership's credit facility and borrowings under our credit facility. Our remaining current growth capital spending projection for 2014 is approximately $550.0 million to $590.0 million related to identified growth projects. Our 2015 projected capital spend for growth capital is approximately $300.0 million to $400.0 million. We expect to fund the growth capital expenditures from the proceeds of borrowing under the Partnership's and ENLC's respective bank credit facilities and from other debt and equity sources.

Off-Balance Sheet Arrangements. No off-balance sheet arrangements existed as of September 30, 2014.

Total Contractual Cash Obligations. A summary of contractual cash obligations as of September 30, 2014 is as follows (in millions):



	Payments Due by Period
	Total		Remainder 2014		2015		2016		2017		2018		Thereafter
Long-term debt obligations	$	1,362.5	$	—	$	—	$	—	$	—	$	—	$	1,362.5
Partnership credit facility	371.0		—		—		—		—		—		371.0
Bank credit facility	80.5		—		—		—		—		—		80.5
Other long term debt obligation	26.7		—		—		26.3		0.4		—		—
Interest payable on fixed long-term debt obligations	934.3		32.5		61.8		61.8		61.8		61.8		654.6
Capital lease obligations	23.2		1.1		4.6		4.6		6.7		2.9		3.3
Operating lease obligations	50.9		3.4		11.4		8.8		5.6		6.0		15.7
Purchase obligations	15.8		15.8		—		—		—		—		—
Delivery contract obligation	85.2		4.5		17.9		17.9		17.9		17.9		9.1
Inactive easement commitment*	8.0		—		1.0		1.0		1.0		1.0		4.0
Uncertain tax position obligations	2.6		2.6		—		—		—		—		—
Total contractual obligations	$	2,960.7	$	59.9	$	96.7	$	120.4	$	93.4	$	89.6	$	2,500.7

__________________________________________________

* Amounts related to inactive easements paid as utilized by the Partnership with balance due at end of 10 years if not utilized.

The above table does not include any physical or financial contract purchase commitments for natural gas 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 Partnership's credit facility, the Company’s credit facility and other debt is not reflected in the above table because such amounts depend on the outstanding balances and interest rates, which vary from time to time. However, given the same borrowing amount and rates in effect at September 30, 2014 the cash obligation for interest expense on the Partnership's credit facility, the Company’s credit facility and other debt would be approximately $7.0 million, $1.5 million and $1.1 million per year, respectively, or approximately $1.8 million, $0.4 million and $0.3 million, respectively, for the remainder of 2014.

Indebtedness

As of September 30, 2014, long-term debt consisted of the following (in millions):



	September 30, 2014
Partnership bank credit facility (due 2019), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at September 30, 2014 was 1.9%	$	371.0
Company bank credit facility (due 2019), interest based on LIBOR plus an applicable margin, interest rate at September 30, 2014 was 1.9%	80.5
Senior unsecured notes (due 2019), net of discount of $2.7 million, which bear interest at the rate of 2.70%	397.3
Senior unsecured notes (due 2022), including a premium of $22.6 million, which bear interest at the rate of 7.125%	185.1
Senior unsecured notes (due 2024), net of discount of $3.5 million, which bear interest at the rate of 4.40%	446.5
Senior unsecured notes (due 2044), net of discount of $3.3 million, which bear interest at the rate of 5.60%	346.8
Other debt	26.7
Debt classified as long-term	$	1,853.9

Company Credit Facility. On March 7, 2014, we entered into a new $250.0 million revolving credit facility, which includes a $125.0 million letter of credit subfacility (the “credit facility”). We used borrowings under the credit facility to repay outstanding borrowings under the margin loan facility of XTXI Capital, LLC (a former wholly-owned subsidiary of EnLink Midstream, Inc.), which was paid in full and terminated on March 7, 2014. Borrowings under the credit facility bear interest, at our option, at either the Eurodollar Rate (the LIBOR Rate) plus an applicable margin 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. The applicable margins vary depending on our leverage ratio. Upon breach by us of certain covenants governing the credit facility, amounts outstanding under the credit facility, if any, may become due and payable immediately and the liens securing credit facility could be foreclosed upon.

Other Company Borrowings. On September 4, 2013, E2 Energy Services LLC ("E2 Services"), one of the Ohio services companies in which the Company invests, entered into a credit agreement with JPMorgan Chase Bank ("JPMorgan"). The maturity date of E2 Services' credit agreement is September 4, 2016. As of September 30, 2014, there was $26.3 million borrowed under E2 Services' credit agreement, leaving approximately $2.5 million available for future borrowing based on borrowing capacity of $30.0 million. On April 9, 2014, the credit agreement was amended to increase the borrowing capacity to $30.0 million. The interest rate under E2 Services' credit agreement is based on Prime plus an applicable margin. The effective interest rate as of September 30, 2014 was approximately 4.0%. Additionally, as of September 30, 2014, E2 Services had certain promissory notes outstanding related to its vehicle fleet in the amount of $0.4 million due in increments through July 2017. The notes bear interest at fixed rates ranging 3.9% to 7.0%. EMI and ENLC do not guarantee E2 Services' debt obligations.

acquisitions in which the aggregate purchase price is $50.0 million or more, the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA will increase to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

As of September 30, 2014, there were $14.0 million in outstanding letters of credit and $371.0 million of outstanding borrowings under the Partnership’s bank credit facility, leaving approximately $615.0 million available for future borrowing based on the borrowing capacity of $1.0 billion. The Partnership credit facility will mature on the fifth anniversary of the initial funding date, which was March 7, 2014, unless the Partnership requests, and the requisite lenders agree, to extend it pursuant to its terms.

See Note 5 to the condensed consolidated financial statements titled “Long-Term Debt” for further details.

Recent Accounting Pronouncements

We have reviewed all recently issued accounting pronouncements that became effective during the nine months ended September 30, 2014 and have determined that none would have a material impact to our Unaudited Condensed Consolidated Financial Statements.

Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of federal securities laws. Statements included in this report which are not historical facts are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. 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 specific uncertainties discussed elsewhere in this Form 10-Q, the risk factors set forth in Part II, “Item 1A. Risk Factors” of this report may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Our primary market risk is the risk related to changes in the prices of natural gas, NGLs 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 Commodities Futures Trading Commission ("CFTC") to regulate certain markets for derivative products, including over-the-counter (“OTC”) derivatives. The CFTC has issued several new relevant regulations and other rulemakings are pending at the CFTC, the product of which would be rules that implement mandates in new legislation to cause significant portions of derivatives markets to clear through clearinghouses. The legislation and new regulations may also require counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any future new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition and our results of operations.

Commodity Price Risk

We are subject to significant risks due to fluctuations in commodity prices. Our exposure to these risks is primarily in the gas processing component of our business. We currently process gas under three main types of contractual arrangements as summarized below. Approximately 89% of our processing margins are from fixed fee based contracts.

Processing margin contracts: Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and makes 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 ("shrink") and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction or "PTR". The Partnership's 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, the Partnership mitigates its risk of processing natural gas when margins are negative primarily through its ability to bypass processing when it is not profitable for the Partnership, or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications.

2. Percent of liquids (“POL”) contracts: Under these contracts, the Partnership receives 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, its margins from these contracts are greater during periods of high liquids prices. The Partnership's margins from processing cannot become negative under percent of liquids contracts, but do decline during periods of low NGL prices.

3. Fee based contracts: Under these contracts we have no commodity price exposure and are paid a fixed fee per unit of volume that is processed.

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 and NGLs using over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our risk management committee.

We have hedged our exposure to fluctuations in prices for natural gas and NGL 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.

The following table sets forth certain information related to derivative instruments outstanding at September 30, 2014 mitigating the risks associated with the gas processing and fractionation components of our business. The relevant payment index price for liquids is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price Information Service ("OPIS"). The relevant index price for Natural Gas is Henry Hub Gas Daily is as defined by the pricing dates in the swap contracts.

Period

Underlying

Notional Volume

We Pay

We Receive *

Fair Value Asset/(Liability)

(In millions)

October 2014 - December 2016

Ethane

1,033

(MBbls)

Index

$0.2757/gal

(0.7

)

October 2014 - December 2016

Propane

1,240

(MBbls)

Index

$1.0211/gal

0.3

October 2014 - May 2015

Normal Butane

(MBbls)

Index

$1.1994/gal

0.1

October 2014 - May 2015

Natural Gasoline

(MBbls)

Index

$1.9255/gal

0.1

October 2014 - May 2015

Natural Gas

(MMBtu/d)

$4.0963/MMBtu*

Index

—

(0.2

)

__________________________________________________

*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, 2014, 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 $0.2 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas and NGL prices would result in a change of approximately $5.2 million in the net fair value of these contracts as of September 30, 2014.

Interest Rate Risk

The Company is exposed to interest rate risk on its variable rate bank credit facility. At September 30, 2014, we had $80.5 million in outstanding borrowings under this facility. A 1% increase or decrease in interest rates would change our annual interest expense by approximately $0.8 million for the year.

The Partnership is exposed to interest rate risk on its variable rate bank credit facility. At September 30, 2014, the Partnership had $371.0 million outstanding borrowings under this facility. A 1% increase or decrease in interest rates would change its annual interest by approximately $3.7 million per year. The Partnership is not exposed to changes in interest rates with respect to our senior unsecured notes due in 2019, 2022, 2024 or 2044, as these obligations are fixed rates. The estimated fair value of the Partnership's senior unsecured notes was approximately $1,438.2 million as of September 30, 2014, based on market prices of similar debt at September 30, 2014. Market risk is estimated as the potential decrease in fair value of the Partnership's long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in approximately a $116.2 million decrease in fair value of the Partnership's senior unsecured notes at September 30, 2014.

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, 2014), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting that occurred in the three months ended September 30, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

For a discussion of certain litigation and similar proceedings, please refer to Note 14, “Commitments and Contingencies,” of the Notes to Condensed Consolidated Financial Statements, which is incorporated by reference herein.

Item 1A. Risk Factors

Information about risk factors does not differ materially from that set forth in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2013 other than as supplemented by our Form 10-Q for the quarterly period ended June 30, 2014 in response to Part II, Item 1A. of such Form 10-Q. Such risk factors are incorporated herein by reference.

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, 2013, by and among Devon Energy Corporation, Devon Gas Services, L.P., Acacia Natural Gas Corp I, Inc., EnLink Midstream, Inc. (formerly known as Crosstex Energy, Inc.), EnLink Midstream, LLC (formerly known as New Public Rangers, L.L.C.), Boomer Merger Sub, Inc. and Rangers Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to EnLink Midstream, Inc.’s Current Report on Form 8-K, dated October 21, 2013, filed with the Commission on October 22, 2013).
2.2**	—	Contribution Agreement, dated as of October 21, 2013, by and among Devon Energy Corporation, Devon Gas Corporation, Devon Gas Services, L.P., Southwestern Gas Pipeline, Inc., EnLink Midstream Partners, LP (formerly known as Crosstex Energy, L.P.) and EnLink Midstream Operating, LP (formerly known as Crosstex Energy Services, L.P.) (incorporated by reference to Exhibit 2.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated October 21, 2013, filed with the Commission on October 22, 2013).
2.3**	—	Contribution and Transfer Agreement, dated as of October 22, 2014, by and between EnLink Midstream Partners, LP and EnLink Midstream, Inc. (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated October 22, 2014, filed with the Commission on October 22, 2014).
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 (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).
3.4	—	Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).
3.5	—	Certificate of Amendment to the Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012).
3.6	—	Second Amendment to the Certificate of Limited Partnership of Crosstex Energy, L.P. (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).
3.7	—	Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP dated July 7, 2014 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated July 7, 2014, filed with the Commission on July 7, 2014).
3.8	—	Certificate of Formation of Crosstex Energy 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).
3.9	—	Amendment to Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K, dated March 6, 2014, filed with the Commission on March 11, 2014).
3.10	—	Second Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of March 7, 2014 (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K, dated March 6, 2014, filed with the Commission on March 11, 2014).
3.11	—	Third Amended and Restated Limited Liability Company Agreement of EnLink Midstream GP, LLC, dated as of July 7, 2014 (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP's Current Report on Form 8-K dated July 7, 2014, filed with the Commission on July 7, 2014).
3.12	—	Certificate of Formation of New Public Rangers Manager, L.L.C. (incorporated by reference to Exhibit 3.12 to EnLink Midstream, LLC’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
3.13	—	Certificate of Amendment to the Certificate of Formation of New Public Rangers Manager, L.L.C. (incorporated by reference to Exhibit 3.13 to EnLink Midstream, LLC’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
3.14	—	First Amended and Restated Limited Liability Company Agreement of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.14 to EnLink Midstream, LLC’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).



10.1†	—	Second Amendment to Employment Agreement, dated August 26, 2014, by and between EnLink Midstream GP, LLC and Michael J. Garberding (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated August 26, 2014, filed with the Commission on August 26, 2014).
10.2†	—	Form of Severance Agreement (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated September 17, 2014, filed with the Commission on September 23, 2014).
10.3†	—	Form of Change in Control Agreement (incorporated by reference to Exhibit 10.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated September 17, 2014, filed with the Commission on September 23, 2014).
31.1*	—	Certification of the Principal Executive Officer.
31.2*	—	Certification of the Principal Financial Officer.
32.1*	—	Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350.
101*	—	The following financial information from EnLink Midstream, LLC’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013, (ii) Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013, (iii) Consolidated Statements of Changes in Members’ Equity for the nine months ended September 30, 2014, (iv) Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013, and (v) the Notes to Condensed Consolidated Financial Statements.

__________________________________________________

* Filed herewith.

** Pursuant to Item 601(b)(2) of Regulation S-K, the Registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

† This Exhibit is identified as a management contract or compensatory benefit plan or arrangement.

SIGNATURES

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



	EnLink Midstream, LLC

	By:	EnLink Midstream Manager, LLC,
		its managing member

	By:	/s/ MICHAEL J. GARBERDING
		Michael J. Garberding
		Executive Vice President and Chief Financial Officer

November 5, 2014