ENLINK MIDSTREAM, LLC, 10-Q filed on 11/5/2014
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2014
Oct. 24, 2014
Document Information [Line Items]
 
 
Document Type
10-Q 
 
Document Fiscal Period Focus
Q3 
 
Document Period End Date
Sep. 30, 2014 
 
Document Fiscal Year Focus
2014 
 
Amendment Flag
false 
 
Entity Registrant Name
Enlink Midstream, LLC 
 
Entity Central Index Key
0001592000 
 
Entity Current Reporting Status
Yes 
 
Entity Voluntary Filers
No 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Well-known Seasoned Issuer
Yes 
 
Entity Common Stock, Shares Outstanding
 
164,045,868 
Condensed Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Current assets:
 
 
Cash and cash equivalents
$ 39.5 
$ 0 
Accounts receivable:
 
 
Trade, net of allowance for bad debt
49.0 
0.4 
Accrued revenue and other
220.6 
0 
Related Party
113.3 
0 
Fair value of derivative assets
1.1 
0 
Natural gas and natural gas liquids, inventory, prepaid expenses and other
57.3 
5.8 
Assets held for disposition
0 
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 
0 
Intangible assets, net of accumulated amortization of $24.4
522.7 
0 
Goodwill
3,694.6 
401.7 
Investment in unconsolidated affiliates
276.1 
61.1 
Other Assets, net
30.0 
0 
Total assets
9,527.8 
2,309.8 
Current liabilities:
 
 
Accounts payable, drafts payable and other
37.3 
1.7 
Related party payables
3.8 
0 
Accrued gas and crude oil purchases
198.4 
0 
Fair value of derivative liabilities
0.9 
0 
Accrued Capital Expenditures
35.6 
0 
Contract liability
21.2 
0 
Other current liabilities
91.4 
38.7 
Accrued interest
30.9 
0 
Liabilities held for disposition
0 
37.0 
Total current liabilities
419.5 
77.4 
Long-term debt
1,853.9 
0 
Fair value of derivative liabilities
0.6 
0 
Asset Retirement Obligation
10.8 
7.7 
Other long-term liabilities
88.1 
0 
Deferred tax liability
497.0 
440.9 
Members' equity
6,657.9 
1,783.8 
Total liabilities & members' equity
$ 9,527.8 
$ 2,309.8 
Condensed Consolidated Statements of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
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 
0 
(1.9)
0 
Total Revenues
855.0 
578.2 
2,505.3 
1,693.1 
Operating costs and expenses:
 
 
 
 
Purchased gas, NGLs, condensate and crude oil
597.2 
435.5 
1,798.0 
1,279.6 
Operating expenses
76.7 
35.8 
195.5 
116.0 
General and administrative
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)
0 
(6.1)
0 
Total operating cost 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)
0 
(33.1)
0 
Income from equity investments
5.6 
5.8 
14.3 
10.2 
Gain on Extinguishment of Debt
2.4 
0 
3.2 
0 
Other income (expense)
0.1 
0 
(0.7)
0 
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
0 
(4.0)
1.0 
6.3 
Income from Discontinued Operations Attributable to Noncontrolling Interest, net of tax
0 
0.3 
0 
1.4 
Discontinued Operations, Net of Tax
0 
(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 
0 
80.5 
0 
Net income attributable to Enlink Midstream, LLC
28.8 
30.3 
99.9 
92.5 
Predecessor interest in net income
0 
30.3 
35.5 
92.5 
Enlink Midstream, LLC interest in net income
$ 28.8 
$ 0 
$ 64.4 
$ 0 
Basic per common unit
$ 0.18 
$ 0.00 
$ 0.39 
$ 0.00 
Diluted per common unit
$ 0.17 
$ 0.00 
$ 0.39 
$ 0.00 
Condensed Consolidated Statements of Operations (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Cost of Purchased Oil and Gas
$ 597.2 
$ 435.5 
$ 1,798.0 
$ 1,279.6 
Operating Costs and Expenses
76.7 
35.8 
195.5 
116.0 
General and Administrative Expense
24.5 
10.8 
66.9 
32.3 
Affiliated Entity [Member]
 
 
 
 
Cost of Purchased Oil and Gas
24.1 
397.8 
349.9 
1,170.4 
Operating Costs and Expenses
0 
8.9 
5.9 
26.9 
General and Administrative Expense
$ 1.0 
$ 10.8 
$ 10.6 
$ 32.3 
Condensed Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Assets, Noncurrent [Abstract]
 
 
Allowance for Doubtful Accounts Receivable, Current
$ 0 
$ 0 
Property plant and equipment accumulated depreciation
1,349.8 
1,169.8 
Intangible assets accumulated amortization
$ 24.4 
$ 0 
Consolidated Statements of Changes in Members' Equity (USD $)
In Millions
Total
Common Stock
Predecessor
Noncontrolling Interest
Balance at Dec. 31, 2013
$ 1,783.8 
$ 0 
$ 1,783.8 
$ 0 
Distributions to predecessor
95.0 
0 
95.0 
0 
Distributions to the predecessor, units
 
0 
 
 
Issuance of units for reorganization of predecessor equity
0 
929.3 
(1,724.3)
795.0 
Issuance of units for reorganization of predecessor equity, units
 
115.5 
 
 
Issuance of common units for acquisition of Company
4,663.6 
1,822.5 
0 
2,841.1 
Issuance of common units for acquisition of Company, units
 
48.5 
 
 
Elimination of deferred taxes attributable to non-controlling interest in predecessor equity
215.5 
0 
0 
215.5 
Change in equity due to issuance of units by the Partnership
71.9 
0 
0 
71.9 
Change in equity due to issuance of units by the Partnership, units
 
0 
 
 
Conversion of restricted stock for common, net of shares withheld for taxes
(1.0)
(1.0)
0 
0 
Stock Issued During Period, Shares, Conversion of Units
 
0 
 
 
Parters Capital Account, option exercised and restricted units converted
(0.1)
0 
0 
(0.1)
Stock Issued During Period, Shares, Conversion of Units
 
0 
 
 
Unit-based Compensation
12.8 
6.9 
0 
5.9 
Unit-based compensation, units
 
0 
 
 
Dividends, Common Stock, Cash
51.0 
51.0 
0 
0 
Distribution to members
(51.0)
 
 
 
Distribution to members, units
 
0 
 
 
Distributions to non-controlling interest
(124.2)
0 
0 
(124.2)
Contribution by Non-Controlling Interest
1.2 
0 
0 
1.2 
Net income
180.4 
64.4 
35.5 
80.5 
Net Income (Loss), units
 
0 
 
 
Common Stock, Units, Outstanding
 
164.0 
 
 
Balance at Sep. 30, 2014
$ 6,657.9 
$ 2,771.1 
$ 0 
$ 3,886.8 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Statement of Cash Flows [Abstract]
 
 
Net income from continuing operations
$ 179.4 
$ 87.6 
Adjustments to reconcile net loss 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)
0 
Deferred tax expense (benefit)
53.7 
10.8 
Non-cash stock-based compensation
12.8 
0 
Loss on derivatives recognized in net income
1.9 
0 
Cash Paid On Derivatives
(1.7)
0 
Amortization of debt issue costs
0.8 
0 
Amortization Of Premium On Notes
(1.7)
0 
Distribution of earnings from equity investment
6.3 
10.9 
Income from equity investments
(14.3)
(10.2)
Changes in assets and liabilities:
 
 
Accounts receivable, accrued revenue and other
26.2 
0 
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)
0 
Deposit for acquisition
(23.5)
0 
Investment in equity investment company
(5.7)
0 
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 
0 
Payments on borrowings
(1,765.2)
0 
Payments on capital lease obligations
(1.8)
0 
Increase in drafts payable
(2.6)
0 
Debt refinancing costs
(7.5)
0 
Proceeds from issuance of Partnership units
71.9 
0 
Proceeds from exercise of Partnership unit options
0.4 
0 
Conversion of restricted stock for common, net of shares withheld for taxes
(1.0)
0 
Conversion of Partnerships restricted units for common, net of shares withheld for taxes
(0.5)
0 
Distribution to members
(51.0)
0 
Distributions to predecessor
(27.2)
(117.7)
Distributions to Non-controlling Interests
(124.2)
0 
Contributions by non-controlling Interests
1.2 
0 
Net cash provided by financing activities
262.8 
(117.7)
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
0 
57.3 
Net increase (decrease) in cash and cash equivalents
39.5 
(15.6)
Cash and cash equivalents, beginning of period
0 
15.6 
Cash and cash equivalents, end of period
39.5 
 
Cash paid for interest
19.9 
0 
Cash paid for income taxes
$ 7.4 
$ 0 
General (Notes)
General
(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 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.
Significant Accounting Policies (Notes)
Significant Accounting Policies
(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 ("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 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 31st 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.

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.
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.
(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.
Acquisition (Notes)
Mergers Acquisitions And Dispositions Disclosures
(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.
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, 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

Affiliate Transactions Affiliate Transactions (Notes)
Affiliate Transactions
(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.
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 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):
 
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.
Long-Term Debt
Long-Term Debt
(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 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 +
 
 
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.

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;

•
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.
Income Taxes (Notes)
Income Taxes
(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


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.
Certain Provisions of the Partnership agreement (Notes)
Certain Provisions of Partnership Agreement
(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.
(c) Allocation of Partnership Income
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.
Earnings Per Share and Dilution Computations
Earnings per Unit and Dilution Computation
(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.
(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.
Asset Retirement Obligation (Notes)
Asset Retirement Obligations
(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

Investment in Unconsolidated Affiliate (Notes)
Investment in Unconsolidated Affiliate
(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.
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.
Employee Incentive Plan
Employee Incentive Plans
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.
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.
(c)  Unit Options
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.

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, 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.
Derivatives
Derivatives
(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
)

 
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
)
Fair Value Measurements
Fair Value Measurements
(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. 
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.
Commitments and Contingencies (Notes)
Commitments and Contingencies
(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.
(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.
(c) Litigation Contingencies
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 23rd Judicial 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 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.
Segment Information
Segment Information
(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.

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



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

Discontinued Operations (Notes)
Disposal Groups, Including Discontinued Operations, Disclosure
(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.
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

Subsequent Events (Notes)
Subsequent Events [Text Block]
(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.
Significant Accounting Policy (Policies)
Basis of Presentation 
(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.
Management's Use of Estimates 
(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.
Revenue Recognition 
(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 ("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)
Gas Imbalance Accounting 
(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.
Cash and Cash Equivalents 
(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.
Natural Gas, Natural Gas Liquids, Crude Oil and Condensate Inventory 
(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.
Property, Plant, and Equipment 
(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 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.
Equity Method of Accounting 
(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.
Investment in E2 
(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.
Goodwill 
(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 31st 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.
Intangible Assets 
(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.

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

Asset Retirement Obligations 
(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.
Other Long-Term Liabilities 
(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.
Derivative 
(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.
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.
Concentrations of Credit Risk 
(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
Environmental Costs 
(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.
Unit-Based Awards 
(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.
Commitments and Contingencies 
(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.
Discontinued Operations 
(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.
Debt Issue Costs 
(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.
Recent Accounting Pronouncements 
(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.
Significant Accounting Policy (Tables)
Schedule of Finite-Lived Intangible Assets 
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.
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense 
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

Acquisition (Table)
Business Combination, Purchase Price Summary 
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.
Schedule of Purchase Price Allocation 
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

Pro Forma 
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

Affiliate Transactions Affiliate Transactions (Tables)
Schedule of Related Party Transactions
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):
 
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
)
Long-Term Debt (Tables)
Indebtedness Table 
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

Credit Facility Interest Levels 
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 +
 
 
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%
Income Taxes Income Taxes (Tables)
Schedule of Components of Income Tax Expense (Benefit) 
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

Schedule of Deferred Tax Assets and Liabilities 
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
)
Certain Provisions of the Partnership agreement (Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution) (Tables)
Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution
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

Earnings Per Share and Dilution Computations (Tables)
Schedule of Earnings Per Share, Basic and Diluted 
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.
(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.
 
Schedule of Weighted Average Number of Shares 
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. 
Asset Retirement Obligation (Table)
Schedule of Change in Asset Retirement Obligation
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

Investment in Unconsolidated Affiliate (Tables)
Equity Method Investments
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.
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.
Employee Incentive Plan (Tables)
ScheduleofShareBasedCompensationRestrictedStockandRestrictedStockUnitsVestedandFairValueVested [Table Text Block] 
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

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, 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

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs 
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

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity 
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

 
 

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

 
 

Derivatives (Tables)
Fair Value of Derivative Assets and Liabilities relating to commodity swaps 
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
)
Notional Amount and Fair Value of Derivative Instruments 
 
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
)
Derivatives Other than Cash Flow Hedges 
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 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
)
Fair Value Measurements (Tables)
Fair Value Derivative Instrument 
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 Financial Instrument 
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

Segement Information (Tables)
Partnership Reportable Segement 
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

Segment Table reconciliation to Condensed Consolidated Financial Statement 
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

Reconciliation of Operating Profit (Loss) from Segments to Consolidated [Table Text Block] 
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

Discontinued Operations (Tables)
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures
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

General (Details)
3 Months Ended 9 Months Ended
Dec. 31, 2013
Sep. 30, 2014
Business Acquisition [Line Items]
 
 
Limited Liability Company or Limited Partnership, Business, Formation State
 
Delaware 
Entity Incorporation, Date of Incorporation
Oct. 21, 2013 
 
Limited Liability Company or Limited Partnership, Business, Formation Date
 
Mar. 07, 2014 
Limited Liability Company or Limited Partnership, Managing Member or General Partner, Name
 
EnLink Midstream Partners GP, LLC 
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares
 
115,495,669 
E2 [Member]
 
 
Business Acquisition [Line Items]
 
 
Noncontrolling Interest, Ownership Percentage by Parent
 
89.80% 
E2 Appalachian Compression, LLC [Member]
 
 
Business Acquisition [Line Items]
 
 
Noncontrolling Interest, Ownership Percentage by Parent
 
90.60% 
Enlink Midstream, Inc. [Member]
 
 
Business Acquisition [Line Items]
 
 
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest
 
7.00% 
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest
 
0.70% 
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest, Shares
 
16,414,830 
Devon Energy Corporation [Member]
 
 
Business Acquisition [Line Items]
 
 
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest
 
70.00% 
EnLink Midstream Partners, LP [Member]
 
 
Business Acquisition [Line Items]
 
 
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest
 
50.00% 
Enlink midstream, LLC
 
 
Business Acquisition [Line Items]
 
 
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest
 
50.00% 
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest
 
100.00% 
Significant Accounting Policies (Other Policies Textuals) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Other Assets, Noncurrent [Abstract]
 
 
Gas Balancing Payable, Current
$ 1.1 
 
Gas Balancing Asset (Liability)
$ 1.3 
$ 0 
Significant Accounting Policies (Property Plant and Equipment Textuals) (Details)
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2014
Property, Plant and Equipment [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Change in Accounting Estimate, Financial Effect
9300000 
21000000 
Depreciation per share [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Change in Accounting Estimate, Financial Effect
.06 
.13 
Significant Accounting Policies (Investment in LLC) (Details)
Sep. 30, 2014
E2 [Member]
 
Schedule of Equity Method Investments [Line Items]
 
Noncontrolling Interest, Ownership Percentage by Parent
89.80% 
E2 Appalachian Compression, LLC [Member]
 
Schedule of Equity Method Investments [Line Items]
 
Noncontrolling Interest, Ownership Percentage by Parent
90.60% 
Significant Accounting Policy (Goodwill) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Mar. 7, 2014
Dec. 31, 2013
Sep. 30, 2013
Goodwill [Line Items]
 
 
 
 
Goodwill
$ 3,694.6 
$ 3,291.9 
$ 401.7 
$ 401.7 
Significant Accounting Policies (Intangible Assets Table) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Finite-Lived Intangible Assets, Net [Abstract]
 
 
Gross Carrying Amount
$ 547.1 
 
Accumulated Amortization
24.4 
0 
Total
$ 522.7 
 
Significant Accounting Policies (Intangible Assets Amortization Expense) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2014
Finite-Lived Intangible Assets, Net [Abstract]
 
 
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life
 
13 years 8 months 
Amortization of Intangible Assets
$ 12.4 
$ 24.4 
Finite-Lived Intangible Assets, Amortization Expense, Maturity Schedule [Abstract]
 
 
2014 (remaining)
10.7 
10.7 
2015
43.0 
43.0 
2016
43.0 
43.0 
2017
43.0 
43.0 
2018
42.6 
42.6 
Thereafter
340.4 
340.4 
Total
$ 522.7 
$ 522.7 
Significant Accounting Policies (Other LTL) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Other Commitments [Line Items]
 
 
Contract liability
$ 21.2 
$ 0 
total contract commitment [Member]
 
 
Other Commitments [Line Items]
 
 
Contract liability
$ 85.2 
 
Significant Accounting Policies (Concentration of Credit Risk Textuals) (Details) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Concentration Risk [Line Items]
 
 
 
 
Allowance for Doubtful Accounts Receivable
$ 0 
 
$ 0 
 
Sales Revenue, Net [Member]
 
 
 
 
Concentration Risk [Line Items]
 
 
 
 
Concentration Risk, Percentage
 
 
10.00% 
 
Sales Revenue, Net [Member] |
Devon Energy Corporation [Member]
 
 
 
 
Concentration Risk [Line Items]
 
 
 
 
Concentration Risk, Percentage
24.10% 
91.90% 
34.80% 
92.00% 
Acquisition (Textuals) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
9 Months Ended 0 Months Ended 0 Months Ended 9 Months Ended
Sep. 30, 2014
Mar. 7, 2014
Mar. 7, 2014
Enlink Midstream, Inc. [Member]
Mar. 7, 2014
Enlink Midstream, Inc. [Member]
Mar. 7, 2014
EnLink Midstream Partners, LP [Member]
Mar. 7, 2014
EnLink Midstream Partners, LP [Member]
Sep. 30, 2014
Gulf Coast Fractionators
Mar. 7, 2014
Gulf Coast Fractionators
Mar. 7, 2014
E2 [Member]
Enlink Midstream, Inc. [Member]
Sep. 30, 2014
Enlink midstream, LLC
Sep. 30, 2014
Enlink Midstream, Inc. [Member]
Sep. 30, 2014
EnLink Midstream Partners GP, LLC [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
Held by public shareholders [Member]
 
 
 
48,000,000 
 
 
 
 
 
 
 
 
Restricted Units
 
 
 
400,000 
 
400,000 
 
 
 
 
 
 
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares
115,495,669 
 
48,400,000 
 
92,600,000 
 
 
 
 
 
 
 
Exchange Ratio
 
1.0 
 
 
 
 
 
 
 
 
 
 
Conversion of Stock, Shares Converted
 
 
48,400,000 
 
 
 
 
 
 
 
 
 
EMI common share price
 
 
 
$ 37.6 
 
$ 0 
 
 
 
 
 
 
Common units held by public unitholders
 
 
 
 
 
75,100,000 
 
 
 
 
 
 
Preferred units held by third party
 
 
 
 
 
17,100,000 
 
 
 
 
 
 
Partnership outstanding unit options value
 
 
 
 
 
$ 3.9 
 
 
 
 
 
 
Total fair value of non-controlling interests
 
 
 
 
 
2,828.8 
 
 
12.1 
 
 
 
Business Acquisition, Transaction Costs
 
51.4 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Date of Acquisition Agreement
 
 
Mar. 07, 2014 
 
 
 
 
 
 
 
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
50.00% 
 
 
 
 
 
 
 
 
 
 
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest
 
 
 
 
 
 
 
 
 
50.00% 
7.00% 
100.00% 
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest
 
 
 
 
 
 
 
 
 
100.00% 
0.70% 
 
Equity Method Investment, Ownership Percentage
 
 
 
 
 
 
38.75% 
38.75% 
 
 
 
 
Business Combination, Consideration Transferred
 
 
1,822.6 
 
2,825.2 
 
 
 
 
 
 
 
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net
 
1,834.7 
 
 
 
 
 
 
 
 
 
 
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest
 
$ 4,663.5 
 
 
 
 
 
 
 
 
 
 
Exchange Ratio
 
1 
 
 
 
 
 
 
 
 
 
 
Acquisition (Details) (USD $)
In Millions, unless otherwise specified
7 Months Ended
Sep. 30, 2014
Mar. 7, 2014
Dec. 31, 2013
Sep. 30, 2013
Business Acquisition [Line Items]
 
 
 
 
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual
$ 1,669.0 
 
 
 
Assets acquired [Abstract]
 
 
 
 
Current assets
 
437.4 
 
 
Property, plant and equipment
 
2,437.9 
 
 
Intangibles
 
546.9 
 
 
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Equity Investment
 
221.5 
 
 
Goodwill
3,694.6 
3,291.9 
401.7 
401.7 
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 
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
50.00% 
 
 
Business Combination, Separately Recognized Transactions, Expenses and Losses Recognized
$ 1,646.5 
 
 
 
Gulf Coast Fractionators
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
Equity Method Investment, Ownership Percentage
38.75% 
38.75% 
 
 
EnLink Midstream Partners, LP [Member]
 
 
 
 
Liabilities assumed:
 
 
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
50.00% 
 
 
Acquisition (Proforma) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Business Acquisition [Line Items]
 
 
 
Business Acquisition, Pro Forma Revenue
$ 622.0 
$ 2,676.6 
$ 1,818.9 
Business Acquisition, Pro Forma Net Income (Loss)
(6.4)
165.8 
76.5 
Business Acquisitions Pro Forma Income Loss Attributable To Parent
$ 18.2 
$ 75.3 
$ 53.2 
Business Acquisition, Pro Forma Earnings Per Share, Basic
$ 0.10 
$ 0.46 
$ 0.33 
Business Acquisition, Pro Forma Earnings Per Share, Diluted
$ 0.10 
$ 0.45 
$ 0.33 
Affiliate Transactions Affiliate Transactions (Details) (USD $)
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 7 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Mar. 7, 2014
Dec. 31, 2013
Sep. 30, 2014
Northridge Assets [Member]
Sep. 30, 2014
Northridge Assets [Member]
Sep. 30, 2013
Devon Energy Corporation [Member]
Sep. 30, 2014
Devon Energy Corporation [Member]
Sep. 30, 2013
Devon Energy Corporation [Member]
Sep. 30, 2014
Affiliated Entity [Member]
Sep. 30, 2014
Sales Revenue, Net [Member]
Sep. 30, 2014
Sales Revenue, Net [Member]
Devon Energy Corporation [Member]
Sep. 30, 2013
Sales Revenue, Net [Member]
Devon Energy Corporation [Member]
Sep. 30, 2014
Sales Revenue, Net [Member]
Devon Energy Corporation [Member]
Sep. 30, 2013
Sales Revenue, Net [Member]
Devon Energy Corporation [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Sep. 30, 2014
Discontinued Operations [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2014
Discontinued Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2014
Discontinued Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2013
Continuing Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2014
Continuing Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2013
Continuing Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2013
Continuing Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2014
Continuing Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2013
Continuing Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2014
Bridgeport [Member]
Sep. 30, 2014
Oklahoma City [Member]
Sep. 30, 2014
Cresson [Member]
Sep. 30, 2014
Gulf Coast Fractionators
Mar. 7, 2014
Gulf Coast Fractionators
Sep. 30, 2014
EnLink Midstream Holdings, LP [Member]
Related Party Transaction [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ (647,700,000)
$ (46,800,000)
$ (1,635,200,000)
$ (136,100,000)
 
 
 
 
 
 
 
$ (435,600,000)
 
 
 
 
 
 
 
 
 
 
 
$ (20,800,000)
$ (10,400,000)
$ (68,100,000)
 
 
 
$ (531,400,000)
$ (436,400,000)
$ (1,557,000,000)
 
 
 
 
 
 
Operating Expenses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7,800,000 
5,000,000 
25,400,000 
 
 
 
417,500,000 
340,000,000 
1,229,600,000 
 
 
 
 
 
 
Net Cash Provided by (Used in) Financing Activities
 
 
262,800,000 
(117,700,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(400,000)
0 
(5,600,000)
 
 
 
 
 
 
 
 
 
 
 
 
Net Related Party transactions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(13,400,000)
(5,400,000)
(48,300,000)
 
 
 
(113,900,000)
(96,400,000)
(327,400,000)
 
 
 
 
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Profit
187,200,000 
106,900,000 
517,900,000 
297,500,000 
 
 
6,500,000 
22,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity Method Investment, Ownership Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
38.75% 
38.75% 
 
Capital Expenditures
207,400,000 
37,100,000 
493,500,000 
172,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(100,000)
600,000 
5,300,000 
 
 
 
44,700,000 
16,200,000 
201,300,000 
 
 
 
 
 
 
Other Expenses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(73,500,000)
400,000 
(54,600,000)
 
 
 
(50,800,000)
53,000,000 
8,400,000 
 
 
 
 
 
 
Total Third-Party Transactions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(73,600,000)
1,000,000 
(49,300,000)
 
 
 
(6,100,000)
69,200,000 
209,700,000 
 
 
 
 
 
 
Net distributions from (to) related party
 
(207,000,000)
(95,000,000)
(215,300,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
(87,000,000)
(4,400,000)
(97,600,000)
 
 
 
(87,000,000)
(44,300,000)
(97,600,000)
(120,000,000)
(27,200,000)
(117,700,000)
(120,000,000)
(50,700,000)
(117,700,000)
 
 
 
 
 
 
Net distributions from (to) related party, non-cash
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
(39,900,000)
0 
 
 
 
 
 
 
0 
(23,500,000)
0 
 
 
 
 
 
 
Business Acquisition, Date of Acquisition Agreement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mar. 07, 2014 
Concentration Risk, Percentage
 
 
 
 
 
 
 
 
 
 
 
 
10.00% 
24.10% 
91.90% 
34.80% 
92.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Due from Affiliate, Current
113,200,000 
 
113,200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related party payables
3,800,000 
 
3,800,000 
 
 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost of Share-based Compensation
5,800,000 
3,500,000 
15,600,000 
10,100,000 
 
 
 
 
3,500,000 
2,800,000 
10,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and Other Postretirement Benefit Expense
 
 
 
 
 
 
 
 
2,200,000 
1,600,000 
6,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Leases, Rent Expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 174,000 
$ 31,000 
$ 66,000 
 
 
 
Long-Term Debt (Indebtedness Table) (Details) (USD $)
3 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Sep. 30, 2014
ENLC Credit Facility [Member]
Sep. 30, 2014
2.7% Senior Notes due 2019 [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Sep. 20, 2014
7.125% Senior Notes due 2022 [Member]
Jul. 20, 2014
7.125% Senior Notes due 2022 [Member]
Sep. 30, 2014
4.4% Senior Notes due 2024 [Member]
Sep. 30, 2014
Unsecured Debt [Member]
Sep. 30, 2014
Other Debt Obligations [Member]
Sep. 30, 2014
September Redemption [Member]
7.125% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchase Date
 
 
 
 
 
 
Mar. 01, 2019 
 
 
 
Jan. 01, 2024 
Oct. 01, 2043 
 
Sep. 20, 2014 
Debt Instrument, Repurchased Face Amount
 
 
 
 
 
 
 
 
$ 15,500,000 
$ 18,500,000 
 
 
 
 
Line of Credit Facility, Amount Outstanding
371,000,000 
 
371,000,000 
 
 
80,500,000 
 
 
 
 
 
 
26,300,000 
 
Senior Notes
 
 
 
 
 
 
397,300,000 
185,100,000 1
 
 
446,500,000 
346,800,000 
 
 
Long-term Debt
1,853,900,000 
 
1,853,900,000 
 
 
 
 
 
 
 
 
 
26,700,000 
 
Long-term Debt, Excluding Current Maturities
1,853,900,000 
 
1,853,900,000 
 
0 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchase Amount
 
 
 
 
 
 
 
 
17,000,000 
20,000,000 
 
 
 
 
Gain on Extinguishment of Debt
$ 2,400,000 
$ 0 
$ 3,200,000 
$ 0 
 
 
 
 
 
 
 
 
 
 
[1] September 30, 2014Partnership 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%$371.0Company bank credit facility (due 2019), interest based on LIBOR plus an applicable margin, interest rate at September 30, 2014 was 1.9%80.5Senior unsecured notes (due 2019), net of discount of $2.7 million, which bear interest at the rate of 2.70%397.3Senior unsecured notes (due 2022), including a premium of $22.6 million, which bear interest at the rate of 7.125% 185.1Senior unsecured notes (due 2024), net of discount of $3.5 million, which bear interest at the rate of 4.40%446.5Senior unsecured notes (due 2044), net of discount of $3.3 million, which bear interest at the rate of 5.60%346.8Other debt26.7Debt classified as long-term$1,853.9
Long-Term Debt (Narrative) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
9 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended 0 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2014
Mar. 7, 2014
Feb. 20, 2014
Sep. 30, 2014
Enlink Midstream, Inc. [Member]
Sep. 30, 2014
EnLink Midstream Partners GP, LLC [Member]
Sep. 30, 2014
5.6% Senior Notes due 2044 [Member]
Sep. 30, 2014
2.7% Senior Notes due 2019 [Member]
Sep. 30, 2014
4.4% Senior Notes due 2024 [Member]
Sep. 30, 2014
8.875% Senior Notes due 2018 [Member]
Mar. 7, 2014
8.875% Senior Notes due 2018 [Member]
Sep. 30, 2014
8.875% Senior Notes due 2018 [Member]
Debt Instrument, Redemption, Period Two [Member]
Apr. 18, 2014
8.875% Senior Notes due 2018 [Member]
Debt Instrument, Redemption, Period Two [Member]
Sep. 30, 2014
8.875% Senior Notes due 2018 [Member]
Debt Instrument, Redemption, Period One [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Sep. 20, 2014
7.125% Senior Notes due 2022 [Member]
Jul. 20, 2014
7.125% Senior Notes due 2022 [Member]
Mar. 7, 2014
7.125% Senior Notes due 2022 [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
2022SeptemberRedemption [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Debt Instrument, Redemption, Period Three [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Debt Instrument, Redemption, Period Two [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Debt Instrument, Redemption, Period One [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Debt Instrument, Redemption, Period Four [Member]
Sep. 30, 2014
Other Debt Obligations [Member]
Mar. 7, 2014
Letter of Credit [Member]
Feb. 20, 2014
Letter of Credit [Member]
Mar. 7, 2014
ENLC Credit Facility [Member]
Sep. 30, 2014
ENLC Credit Facility [Member]
Mar. 7, 2014
ENLC Credit Facility [Member]
Sep. 30, 2014
Unsecured Debt [Member]
Sep. 30, 2014
Maximum [Member]
Sep. 30, 2014
Maximum [Member]
ENLC Credit Facility [Member]
Sep. 30, 2014
Minimum [Member]
Sep. 30, 2014
Base Rate [Member]
Sep. 30, 2014
Base Rate [Member]
ENLC Credit Facility [Member]
Sep. 30, 2014
Eurodollar [Member]
Sep. 30, 2014
Eurodollar [Member]
ENLC Credit Facility [Member]
Sep. 30, 2014
Revolving Credit Facility [Member]
Maximum [Member]
Sep. 30, 2014
Revolving Credit Facility [Member]
Maximum [Member]
ENLC Credit Facility [Member]
Line of Credit Facility [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Face Amount
 
 
 
 
 
$ 350.0 
$ 400.0 
$ 450.0 
 
$ 725.0 
 
 
 
 
 
 
$ 196.5 
 
 
 
 
 
 
 
 
 
 
 
$ 1,200.0 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Initiation Date
Feb. 20, 2014 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sep. 04, 2013 
 
 
Mar. 07, 2014 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Maximum Borrowing Capacity
1,000.0 
 
1,000.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
30.0 
125.0 
500.0 
 
250.0 
250.0 
 
 
 
 
 
 
 
 
 
 
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest, Shares
 
 
 
16,414,830 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest
 
 
 
7.00% 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Expiration Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sep. 04, 2016 
 
 
 
Mar. 07, 2019 
 
 
 
 
 
 
 
 
 
 
 
Leverage ratios
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.0 to 1.0. 
4.50 to 1.00 
 
 
 
 
 
5.5 to 1.0 
4.00 to 1.00 
Conditional acquisition purchase price
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50.0 
 
 
 
 
 
 
 
 
Interest Coverge Ratio
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.50 to 1.00  
 
 
 
 
 
 
Percentage Rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.50% 
 
1.00% 
 
 
Line of Credit Facility, Amount Outstanding
371.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
26.3 
 
 
 
80.5 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Remaining Borrowing Capacity
615.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.5 
 
 
 
169.5 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Interest Rate at Period End
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.977% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes Payable, Noncurrent
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3.90% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Interest Rate During Period
1.90% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1.90% 
 
 
 
 
 
0.50% 
 
1.00% 
 
 
 
Letters of Credit Outstanding, Amount
14.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage
 
 
 
 
 
5.60% 
2.70% 
4.40% 
 
8.875% 
 
 
 
7.125% 
 
 
7.125% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Selling Priceof Debt Instrument
 
 
 
 
 
99.925% 
99.85% 
99.83% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Maturity Date
 
 
 
 
 
Apr. 01, 2044 
Apr. 01, 2019 
Apr. 01, 2024 
Feb. 15, 2018 
 
 
 
 
Jun. 01, 2022 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Redemption Price, Percentage
 
 
 
 
 
100.00% 
100.00% 
100.00% 
 
 
 
 
 
 
 
 
 
 
101.188% 
102.375% 
103.563% 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt, Fair Value
 
 
 
 
 
 
 
 
 
761.3 
 
 
 
 
 
 
226.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Unamortized Discount (Premium), Net
 
 
 
 
 
3.3 
2.7 
3.5 
 
(36.3)
 
 
 
(22.6)
 
 
(29.5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchase Date
 
 
 
 
 
Oct. 01, 2043 
Mar. 01, 2019 
Jan. 01, 2024 
Mar. 12, 2014 
 
Apr. 18, 2014 
 
Mar. 19, 2014 
 
 
 
 
Jul. 20, 2014 
Jun. 01, 2019 
Jun. 01, 2018 
Jun. 01, 2017 
Jun. 01, 2020 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchased Face Amount
 
 
 
 
 
 
 
 
536.1 
 
 
 
 
 
15.5 
18.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed
 
 
 
 
 
 
 
 
74.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Repurchase Amount
 
 
 
 
 
 
 
 
 
 
 
$ 200.2 
$ 567.4 
 
$ 17.0 
$ 20.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Issuance Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mar. 19, 2014 
 
 
 
 
 
 
 
 
 
Long-Term Debt (Percentages Per Annum) (Details)
9 Months Ended
Sep. 30, 2014
Line of Credit Facility [Line Items]
 
EuroDollar Rate/Letter of Credit
1.90% 
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
EuroDollar Rate/Letter of Credit
1.00% 
Level 1 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Ratings
A-/A3 or better 
Applicable Rate Commitment Fee
0.10% 
Base Rate
0.00% 
Level 1 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
EuroDollar Rate/Letter of Credit
1.00% 
Level 2 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Ratings
BBB+/Baa1 
Applicable Rate Commitment Fee
0.125% 
Base Rate
0.125% 
Level 2 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
EuroDollar Rate/Letter of Credit
1.125% 
Level 3 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Ratings
BBB/Baa2 
Applicable Rate Commitment Fee
0.175% 
Base Rate
0.25% 
Level 3 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
EuroDollar Rate/Letter of Credit
1.25% 
Level 4 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Ratings
BBB-/Baa3 
Applicable Rate Commitment Fee
0.225% 
Base Rate
0.50% 
Level 4 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
EuroDollar Rate/Letter of Credit
1.50% 
Level 5 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Ratings
BB+/Ba1 
Applicable Rate Commitment Fee
0.275% 
Base Rate
0.625% 
Level 5 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
EuroDollar Rate/Letter of Credit
1.625% 
Level 6 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Ratings
BB/Ba2 or worse 
Applicable Rate Commitment Fee
0.35% 
Base Rate
0.75% 
Level 6 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
EuroDollar Rate/Letter of Credit
1.75% 
Long-Term Debt (Parenthetical) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2014
ENLC Credit Facility [Member]
Sep. 30, 2014
2.7% Senior Notes due 2019 [Member]
Sep. 30, 2014
4.4% Senior Notes due 2024 [Member]
Sep. 30, 2014
5.6% Senior Notes due 2044 [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Mar. 7, 2014
7.125% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
Line of Credit Facility, Interest Rate During Period
1.90% 
1.90% 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage
 
 
2.70% 
4.40% 
5.60% 
7.125% 
7.125% 
Debt Instrument, Unamortized Discount (Premium), Net
 
 
$ 2.7 
$ 3.5 
$ 3.3 
$ (22.6)
$ (29.5)
Income Taxes (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Mar. 7, 2014
Operating Loss Carryforwards [Line Items]
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
50.00% 
Business acquisition, deferred tax liability, assumed in business acquisition
 
$ 252.0 
Business Acquisition, Deferred tax liability, Percentage of total assumed
 
53.00% 
Operating Loss Carryforwards
61.9 
 
Deferred Tax Assets, Operating Loss Carryforwards, State and Local
75.4 
 
Noncontrolling Interest
 
 
Operating Loss Carryforwards [Line Items]
 
 
Business acquisition, deferred tax liability, assumed in business acquisition
 
$ 215.5 
Business Acquisition, Deferred tax liability, Percentage of total assumed
 
47.00% 
Enlink midstream, LLC
 
 
Operating Loss Carryforwards [Line Items]
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
50.00% 
EnLink Midstream Holdings, LP [Member]
 
 
Operating Loss Carryforwards [Line Items]
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
50.00% 
Business Acquisition, Additional Percentage of Voting Interests Acquired
 
3.00% 
Income Taxes (Income Tax Expense) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Tax Credit Carryforward [Line Items]
 
 
 
 
Income tax provision
$ 17.3 
$ 19.3 
$ 59.5 
$ 49.2 
Enlink midstream, LLC
 
 
 
 
Tax Credit Carryforward [Line Items]
 
 
 
 
Income tax provision
17.3 
 
40.1 
 
Predecessor
 
 
 
 
Tax Credit Carryforward [Line Items]
 
 
 
 
Income tax provision
$ 0 
 
$ 19.4 
 
Income Taxes (Deferred Tax Liability) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 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 
Certain Provisions of the Partnership agreement (Textual) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Sep. 30, 2014
Sep. 30, 2013
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
 
 
 
Approximate Date of Commencement of Proposed Sale to Public
 
 
 
May 29, 2014 
 
Percentage Of Avaliable Cash to Distribute
100.00% 
 
 
100.00% 
 
Number Of Days From End Of Quarter For Distribution
 
 
 
45 days 
 
Distribution Made to Limited Partner, Distribution Date
Nov. 13, 2014 
Aug. 13, 2014 
May 14, 2014 
 
 
Class B units conversion date
 
 
 
May 06, 2014 
 
Distribution Made to Limited Partner, Distributions Declared, Per Unit
$ 0.370 
$ 0.365 
$ 0.36 
 
 
Common Unit, Issuance Value
$ 75.0 
 
 
$ 75.0 
 
Partners' Capital Account, Units, Sold in Public Offering
 
 
 
2,400,000 
 
Proceeds from Issuance of Common Limited Partners Units
 
 
 
71.9 
0 
Sales Commissions and Fees
 
 
 
0.7 
 
Class B units
 
 
 
 
 
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
 
 
 
Distribution Made to Limited Partner, Distributions Declared, Per Unit
 
 
$ 0.10 
 
 
General Partner [Member] |
Incentive Distribution Percentage, Level1 [Member]
 
 
 
 
 
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
 
 
 
Incentive Distribution Percentage Levels
 
 
 
13.00% 
 
Incentive Distribution, Distribution Per Unit
 
 
 
$ 0.25 
 
General Partner [Member] |
Incentive Distribution Percentage, Level2 [Member]
 
 
 
 
 
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
 
 
 
Incentive Distribution Percentage Levels
 
 
 
23.00% 
 
Incentive Distribution, Distribution Per Unit
 
 
 
$ 0.3125 
 
General Partner [Member] |
Incentive Distribution Percentage, Level3 [Member]
 
 
 
 
 
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
 
 
 
Incentive Distribution Percentage Levels
 
 
 
48.00% 
 
Incentive Distribution, Distribution Per Unit
 
 
 
$ 0.375 
 
ATM [Member]
 
 
 
 
 
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
 
 
 
Proceeds from Issuance of Common Limited Partners Units
 
 
 
$ 71.9 
 
Certain Provisions of the Partnership agreement (Partners' Capital) (Allocated Net Income (loss) to the General Partner) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2014
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
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 
Earnings Per Share and Dilution Computations (Details) (USD $)
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Class B units
Sep. 30, 2014
Common Stock
Sep. 30, 2014
Common Stock
Sep. 30, 2014
Unvested restricted shares
Sep. 30, 2014
Unvested restricted shares
Sep. 30, 2014
Enlink midstream, LLC
Jun. 30, 2014
Enlink midstream, LLC
Mar. 31, 2014
Enlink midstream, LLC
Sep. 30, 2014
Enlink midstream, LLC
Class B units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
Enlink Midstream, LLC interest in net income
$ 28,800,000 
$ 0 
$ 64,400,000 
$ 0 
 
 
 
 
 
 
 
 
 
Net income attributable to Enlink Midstream, LLC
28,800,000 
 
64,400,000 
 
 
 
 
 
 
 
 
 
 
Distributed Earnings
37,900,000 
 
88,900,000 
 
 
37,700,000 
88,300,000 
200,000 
600,000 
 
 
 
 
Undistributed Earnings, Basic
(9,200,000)
 
(24,500,000)
 
 
(9,100,000)
(24,300,000)
(100,000)
(200,000)
 
 
 
 
Net income attributable to Enlink Midstream, LLC
28,800,000 
30,300,000 
99,900,000 
92,500,000 
 
28,600,000 
64,000,000 
200,000 
400,000 
 
 
 
 
Distribution Made to Limited Liability Company (LLC) Member, Cash Distributions Declared
 
 
 
 
 
 
 
 
 
$ 0.23 
$ 0.22 
$ 0.18 
$ 0.05 
Distribution Made to Limited Liability Company (LLC) Member, Distribution Date
 
 
 
 
May 15, 2014 
 
 
 
 
Nov. 14, 2014 
Aug. 14, 2014 
May 15, 2014 
 
Basic per common unit
$ 0.18 
$ 0.00 
$ 0.39 
$ 0.00 
 
 
 
 
 
 
 
 
 
Diluted per common unit
$ 0.17 
$ 0.00 
$ 0.39 
$ 0.00 
 
 
 
 
 
 
 
 
 
Class B units conversion date
 
 
May 06, 2014 
 
 
 
 
 
 
 
 
 
 
Earnings Per Share and Dilution Computations (Weighted Average) (Details)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2014
Weighted Average Number of Shares Outstanding, Basic
164.0 
164.0 
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities
0.4 
0.3 
Weighted Average Number Of Diluted Shares Outstanding
164.4 
164.3 
Asset Retirement Obligation (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Dec. 31, 2012
Asset Retirement Obligation, Roll Forward [Roll Forward]
 
 
 
 
Asset Retirement Obligation
$ 10.8 
$ 9.8 
$ 7.7 
$ 9.1 
Asset Retirement Obligation, Revision of Estimate
2.2 
0.4 
 
 
Asset Retirement Obligation, Liabilities Incurred
0.5 
0 
 
 
Accretion expense
$ 0.4 
$ 0.3 
 
 
Investment in Unconsolidated Affiliate (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
Undistributed Earnings, Basic
$ (9.2)
 
$ (24.5)
 
 
Equity Method Investments
276.1 
 
276.1 
 
61.1 
Distribution of earnings from equity investment
 
 
6.3 
10.9 
 
Income from equity investments
5.6 
5.8 
14.3 
10.2 
 
Gulf Coast Fractionators
 
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
Undistributed Earnings, Basic
 
 
13.1 
 
 
Equity Method Investments
56.0 1
 
56.0 1
 
61.1 1
Distribution of earnings from equity investment
5.2 
12.0 
5.2 2
12.0 
 
Equity Method Investment, Ownership Percentage
38.75% 
 
38.75% 
 
 
Income from equity investments
5.2 
5.8 
13.2 2
10.2 
 
Howard Energy Partners
 
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
Equity Method Investments
220.1 
 
220.1 
 
0 
Distribution of earnings from equity investment
3.0 
0 
8.7 2
0 
 
Equity Method Investment, Ownership Percentage
30.60% 
 
30.60% 
 
 
Income from equity investments
0.4 
0 
1.1 2
0 
 
Total
 
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
Distribution of earnings from equity investment
8.2 
12.0 
13.9 2
12.0 
 
Income from equity investments
$ 5.6 
$ 5.8 
$ 14.3 2
$ 10.2 
 
Employee Incentive Plan (Expense Schedule) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Cost of Share-based Compensation
$ 5.8 
$ 3.5 
$ 15.6 
$ 10.1 
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense
1.3 
1.3 
3.9 
3.8 
Operating Expense
 
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Cost of Share-based Compensation
0.8 
0 
1.8 
0 
General and Administrative Expense
 
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Cost of Share-based Compensation
5.0 
0 
11.0 
0 
General and Administrative Expense |
Predecessor
 
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Cost of Share-based Compensation
0 
3.5 
2.8 
10.1 
Noncontrolling Interest
 
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Cost of Share-based Compensation
$ 2.5 
$ 0 
$ 5.4 
$ 0 
Employee Incentive Plan (Compensation Schedule) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
9 Months Ended
Sep. 30, 2014
ENLK Restricted Units |
Restricted Stock Units (RSUs)
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Shares Paid for Tax Withholding for Share Based Compensation
16,471 
Number of Units
 
Non-vested, beginning of period (Units)
0 
Assumed in Business Combination
371,225 
Granted (Units)
701,119 
Vested
(39,833)
Forfeited (Units)
(13,196)
Non-vested, end of period (Units)
1,019,315 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 0.00 
Assumed in Business Combination, price
$ 30.51 
Granted
$ 31.65 
Vested
$ 30.63 
Forfeited
$ 31.83 
Non-vested, end of period
$ 31.27 
Aggregate intrinsic value, end of period (in thousands)
$ 31.0 
ENLC Restricted Units
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Shares Paid for Tax Withholding for Share Based Compensation
24,727 
Number of Units
 
Non-vested, beginning of period (Units)
0 
Assumed in Business Combination
435,674 
Granted (Units)
626,341 
Vested
(59,553)
Forfeited (Units)
(11,859)
Non-vested, end of period (Units)
990,603 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 0.00 
Assumed in Business Combination, price
$ 37.60 
Granted
$ 36.59 
Vested
$ 37.56 
Forfeited
$ 36.54 
Non-vested, end of period
$ 36.97 
Aggregate intrinsic value, end of period (in thousands)
$ 40.9 
Employee Incentive Plan (Textuals) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2014
ENLC Restricted Units
Sep. 30, 2014
ENLC Restricted Units
Sep. 30, 2014
post acquisition [Member]
ENLK Restricted Units
Sep. 30, 2014
post acquisition [Member]
ENLC Restricted Units
Mar. 7, 2014
Common Units [Member]
ENLK Restricted Units
Sep. 30, 2014
Restricted Stock Units (RSUs)
ENLK Restricted Units
Sep. 30, 2014
Restricted Stock Units (RSUs)
ENLK Restricted Units
Sep. 30, 2014
Pre acquisition [Member]
ENLK Restricted Units
Sep. 30, 2014
Pre acquisition [Member]
ENLC Restricted Units
Sep. 30, 2014
Unit Option
Feb. 5, 2014
Common Stock
ENLC Restricted Units
Sep. 30, 2014
Restricted Stock
ENLC Restricted Units
Sep. 30, 2014
EnLink Midstream Partners, LP [Member]
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period
 
 
3 years 
3 years 
 
 
 
2 years 
2 years 
 
 
 
 
ShareBasedCompensationArrangementByShareBasedPaymentAwardEquityInstrumentsOtherThanOptionsVestedInPeriodIntrinsicValue1
$ 2.4 
$ 2.4 
 
 
 
$ 1.2 
$ 1.2 
 
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized
 
 
 
 
9,070,000 
 
 
 
 
 
11,000,000 
 
 
Unrecognized compensation cost related to non-vested restricted incentive units
 
 
 
 
 
 
 
 
 
 
 
23.2 
21.3 
Unrecognized compensation costs, weighted average period for recognition
 
 
 
 
 
 
 
 
 
 
 
2 years 1 month 
2 years 1 month 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period
 
 
 
 
 
 
 
 
 
31,382 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value
 
 
 
 
 
 
 
 
 
0.6 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value
$ 2.2 
$ 2.2 
 
 
 
$ 1.2 
$ 1.2 
 
 
 
 
 
 
Derivatives (Summary of Derivative Income Expense) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Derivative, Gain (loss) on Derivative, Net
 
 
$ 1.9 
$ 0 
Gain (loss) on derivative activity
(1.0)
0 
1.9 
0 
Commodity Swap
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Derivative, Gain (loss) on Derivative, Net
(1.8)
 
0.2 
 
Change in fair value of derivatives
0.8 
 
1.7 
 
Gain (loss) on derivative activity
$ (1.0)
 
$ 1.9 
 
Derivatives (Schedule of Derivative Assets Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative assets, current
$ 1.1 
$ 0 
Derivative Asset, long term
0.2 
0 
Fair value of derivative liabilities, current
(0.9)
0 
Derivative Liability, long term
(0.6)
 
Net fair value of derivatives
$ (0.2)
 
Derivatives (Derivatives Outstanding) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Derivative [Line Items]
 
Total mark to market derivatives
$ (0.2)
Commodity
 
Derivative [Line Items]
 
Total mark to market derivatives
(0.2)
Short [Member] |
Natural Gas Liquids [Member]
 
Derivative [Line Items]
 
Derivative Nonmonetary Notional Amount
61,300,000 
Total mark to market derivatives
0.7 
Short [Member] |
Natural Gas [Member]
 
Derivative [Line Items]
 
Derivative Nonmonetary Notional Amount
2,200,000 
Total mark to market derivatives
0.1 
Long [Member] |
Natural Gas Liquids [Member]
 
Derivative [Line Items]
 
Derivative Nonmonetary Notional Amount
47,900,000 
Total mark to market derivatives
(0.9)
Long [Member] |
Natural Gas [Member]
 
Derivative [Line Items]
 
Derivative Nonmonetary Notional Amount
400,000 
Total mark to market derivatives
$ (0.1)
Derivatives (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
 
Maximum counterparty loss
$ 1.3 
Maximum counterparty loss with netting feature
$ 0.2 
Derivatives (Derivatives Other Than Cash Flow Hedges Table) (Details) (Market Approach Valuation Technique [Member], USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Derivative [Line Items]
 
Less than one year
$ (0.2)
Maturity Less Than One Year [Member]
 
Derivative [Line Items]
 
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value
0.2 
Maturity Within One to Two Years [Member]
 
Derivative [Line Items]
 
Less than one year
(0.3)
Maturity More Than Two Years [Member]
 
Derivative [Line Items]
 
Less than one year
$ (0.1)
Fair Value Measurement (Textual) (Details) (USD $)
Sep. 30, 2014
Mar. 7, 2014
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 1,853,900,000 
 
Line of Credit Facility, Amount Outstanding
371,000,000 
 
7.125% Senior Notes due 2022 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
185,100,000 1
 
Debt Instrument, Interest Rate, Stated Percentage
7.125% 
7.125% 
ENLC Credit Facility [Member]
 
 
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Amount Outstanding
80,500,000 
 
Other Debt Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
26,700,000 
 
Line of Credit Facility, Amount Outstanding
26,300,000 
 
2.7% Senior Notes due 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
397,300,000 
 
Debt Instrument, Interest Rate, Stated Percentage
2.70% 
 
4.4% Senior Notes due 2024 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
446,500,000 
 
Debt Instrument, Interest Rate, Stated Percentage
4.40% 
 
5.6% Senior Notes due 2044 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
$ 346,800,000 
 
Debt Instrument, Interest Rate, Stated Percentage
5.60% 
 
[1] September 30, 2014Partnership 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%$371.0Company bank credit facility (due 2019), interest based on LIBOR plus an applicable margin, interest rate at September 30, 2014 was 1.9%80.5Senior unsecured notes (due 2019), net of discount of $2.7 million, which bear interest at the rate of 2.70%397.3Senior unsecured notes (due 2022), including a premium of $22.6 million, which bear interest at the rate of 7.125% 185.1Senior unsecured notes (due 2024), net of discount of $3.5 million, which bear interest at the rate of 4.40%446.5Senior unsecured notes (due 2044), net of discount of $3.3 million, which bear interest at the rate of 5.60%346.8Other debt26.7Debt classified as long-term$1,853.9
Fair Value Measurement (Fair Measurement on a Recurring Nonrecurring Basis) (Details) (Level 2, Commodity Swap, Fair Value, Measurements, Recurring, USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Level 2 |
Commodity Swap |
Fair Value, Measurements, Recurring
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
Net Fair value of derivatives
$ (0.2)
Fair Value Measurement (Fair Value of Financial Instrument) (Details) (USD $)
Sep. 30, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
Long-term Debt
$ 1,853,900,000 
Line of Credit Facility, Amount Outstanding
371,000,000 
Carrying Value [Member]
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
Obligations under capital lease
21,100,000 
Fair Value [Member]
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
Long-term Debt, Fair Value
1,916,400,000 
Obligations under capital lease
$ 20,700,000 
Commitments and Contingencies Disclosure (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Gain Contingencies [Line Items]
 
 
 
 
Gain on Litigation Settlement
$ 6.1 
$ 0 
$ 6.1 
$ 0 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Mar. 7, 2014
Dec. 31, 2013
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Sales to external customers
$ 647.7 
$ 46.8 
$ 1,635.2 
$ 136.1 
 
 
Sales to affiliates
206.3 
531.4 
872.0 
1,557.0 
 
 
Purchased gas, NGLs and crude oil
(597.2)
(435.5)
(1,798.0)
(1,279.6)
 
 
Operating expenses
(76.7)
(35.8)
(195.5)
(116.0)
 
 
Gain on Litigation Settlement
6.1 
0 
6.1 
0 
 
 
Gain (loss) on derivative activity
1.0 
0 
(1.9)
0 
 
 
Segment profit
187.2 
106.9 
517.9 
297.5 
 
 
Depreciation and Amortization
(73.4)
(48.0)
(195.8)
(138.6)
 
 
Goodwill
3,694.6 
401.7 
3,694.6 
401.7 
3,291.9 
401.7 
Capital Expenditures
207.4 
37.1 
493.5 
172.6 
 
 
Identifiable assets
9,527.8 
 
9,527.8 
 
 
2,309.8 
Texas
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Sales to external customers
77.3 
32.9 
214.3 
96.6 
 
 
Sales to affiliates
148.9 
359.4 
637.7 
1,052.3 
 
 
Purchased gas, NGLs and crude oil
(76.8)
(286.2)
(423.0)
(838.7)
 
 
Operating expenses
(36.2)
(26.9)
(106.5)
(92.0)
 
 
Gain on Litigation Settlement
0 
 
0 
 
 
 
Gain (loss) on derivative activity
0 
 
0 
 
 
 
Segment profit
113.2 
79.2 
322.5 
218.2 
 
 
Depreciation and Amortization
(31.6)
(29.0)
(91.7)
(82.4)
 
 
Goodwill
1,168.2 
325.4 
1,168.2 
325.4 
 
 
Capital Expenditures
79.7 
27.1 
180.2 
113.9 
 
 
Identifiable assets
3,236.9 
 
3,236.9 
 
 
1,460.0 
Louisiana
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Sales to external customers
491.3 
0 
1,221.9 
0 
 
 
Sales to affiliates
39.5 
0 
41.7 
0 
 
 
Purchased gas, NGLs and crude oil
(486.9)
0 
(1,158.2)
0 
 
 
Operating expenses
(23.7)
0 
(45.5)
0 
 
 
Gain on Litigation Settlement
6.1 
 
6.1 
 
 
 
Gain (loss) on derivative activity
0 
 
0 
 
 
 
Segment profit
26.3 
0 
66.0 
0 
 
 
Depreciation and Amortization
(19.1)
0 
(43.4)
0 
 
 
Goodwill
786.8 
0 
786.8 
0 
 
 
Capital Expenditures
79.1 
0 
222.4 
0 
 
 
Identifiable assets
2,925.3 
 
2,925.3 
 
 
0 
Oklahoma
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Sales to external customers
0 
13.9 
11.5 
39.5 
 
 
Sales to affiliates
45.9 
172.0 
256.0 
504.7 
 
 
Purchased gas, NGLs and crude oil
0 
(149.3)
(133.8)
(440.9)
 
 
Operating expenses
(7.0)
(8.9)
(20.9)
(24.0)
 
 
Gain on Litigation Settlement
0 
 
0 
 
 
 
Gain (loss) on derivative activity
0 
 
0 
 
 
 
Segment profit
38.9 
27.7 
112.8 
79.3 
 
 
Depreciation and Amortization
(11.8)
(19.0)
(37.6)
(56.2)
 
 
Goodwill
190.3 
76.3 
190.3 
76.3 
 
 
Capital Expenditures
2.5 
10.0 
10.5 
58.7 
 
 
Identifiable assets
894.5 
 
894.5 
 
 
777.1 
Ohio River Valley
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Sales to external customers
79.1 
0 
187.5 
0 
 
 
Sales to affiliates
0 
0 
0 
0 
 
 
Purchased gas, NGLs and crude oil
(61.5)
0 
(146.4)
0 
 
 
Operating expenses
(9.8)
0 
(22.6)
0 
 
 
Gain on Litigation Settlement
0 
 
0 
 
 
 
Gain (loss) on derivative activity
0 
 
0 
 
 
 
Segment profit
7.8 
0 
18.5 
0 
 
 
Depreciation and Amortization
(10.0)
0 
(21.6)
0 
 
 
Goodwill
112.5 
0 
112.5 
0 
 
 
Capital Expenditures
42.2 
0 
67.8 
0 
 
 
Identifiable assets
677.0 
 
677.0 
 
 
0 
Corporate
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Sales to external customers
0 
0 
0 
0 
 
 
Sales to affiliates
(28.0)
0 
(63.4)
0 
 
 
Purchased gas, NGLs and crude oil
28.0 
0 
63.4 
0 
 
 
Operating expenses
0 
0 
0 
0 
 
 
Gain on Litigation Settlement
0 
 
0 
 
 
 
Gain (loss) on derivative activity
1.0 
 
(1.9)
 
 
 
Segment profit
1.0 
0 
(1.9)
0 
 
 
Depreciation and Amortization
(0.9)
0 
(1.5)
0 
 
 
Goodwill
1,436.8 
0 
1,436.8 
0 
 
 
Capital Expenditures
3.9 
0 
12.6 
0 
 
 
Identifiable assets
$ 1,794.1 
 
$ 1,794.1 
 
 
$ 72.7 
Segment Information (Reconciliation of Segment Profit to Operating Income) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Segment Reporting [Abstract]
 
 
 
 
Gross Profit
$ 187.2 
$ 106.9 
$ 517.9 
$ 297.5 
General and administrative
(24.5)
(10.8)
(66.9)
(32.3)
Depreciation and Amortization
73.4 
48.0 
195.8 
138.6 
Operating Income (Loss)
$ 89.3 
$ 48.1 
$ 255.2 
$ 126.6 
Discontinued Operations (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Sep. 30, 2014
Gulf Coast Fractionators
Mar. 7, 2014
Gulf Coast Fractionators
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
Disposal Group, Including Discontinued Operation, Revenue, External
 
$ 10.9 
$ 6.8 
$ 33.5 
 
 
 
Disposal Group, Including Discontinued Operation, Revenue, Related Party
 
20.8 
10.5 
68.1 
 
 
 
Operating revenues
 
31.7 
17.3 
101.6 
 
 
 
Total operating expenses
 
37.9 
15.7 
91.7 
 
 
 
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax
 
(6.2)
1.6 
9.9 
 
 
 
Income tax expense
 
(2.2)
0.6 
3.6 
 
 
 
Income (loss) from discontinued operations, net of tax
0 
(4.0)
1.0 
6.3 
 
 
 
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Noncontrolling Interest
0 
(0.3)
0 
(1.4)
 
 
 
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent
0 
(4.3)
1.0 
4.9 
 
 
 
Equity Method Investment, Ownership Percentage
 
 
 
 
 
38.75% 
38.75% 
Inventories
 
 
 
 
0.2 
 
 
Other current assets
 
 
 
 
0.2 
 
 
Total current assets
 
 
 
 
0.4 
 
 
Property, plant & equipment
 
 
 
 
72.3 
 
 
Total assets
0 
 
0 
 
72.7 
 
 
Accounts Payable
 
 
 
 
3.2 
 
 
Other current liabilities
 
 
 
 
1.1 
 
 
Liabilities Of Disposal Group Including Discontinued Operations
 
 
 
 
4.3 
 
 
Liabilities held for disposition
0 
 
0 
 
37.0 
 
 
Asset Retirement Obligation
 
 
 
 
7.1 
 
 
Deferred income taxes
 
 
 
 
25.3 
 
 
Other long-term liabilities
 
 
 
 
$ 0.3 
 
 
Subsequent Events (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 0 Months Ended 3 Months Ended 0 Months Ended 3 Months Ended 0 Months Ended
Sep. 30, 2014
Oct. 22, 2014
Subsequent Event [Member]
Dec. 31, 2014
E2 Appalachian [Member]
Subsequent Event [Member]
Dec. 31, 2014
E2 Energy Services [Member]
Subsequent Event [Member]
Sep. 30, 2014
GulfCoast [Member]
Nov. 1, 2014
GulfCoast [Member]
Subsequent Event [Member]
Dec. 31, 2014
GulfCoast [Member]
Subsequent Event [Member]
Dec. 31, 2014
Class A [Member]
E2 Appalachian [Member]
Subsequent Event [Member]
Dec. 31, 2014
Class A [Member]
E2 Energy Services [Member]
Subsequent Event [Member]
Dec. 31, 2014
Class B [Member]
E2 Appalachian [Member]
Subsequent Event [Member]
Oct. 22, 2014
Noncontrolling Interest
E2 Appalachian [Member]
Subsequent Event [Member]
Subsequent Event [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Deposits Assets, Noncurrent
 
 
 
 
$ 23.5 
 
 
 
 
 
 
Payments to Acquire Businesses, Gross
 
 
150.0 
13.0 
 
 
 
 
 
 
 
Business Acquisition, Effective Date of Acquisition
Mar. 07, 2014 
Oct. 22, 2014 
 
 
 
Nov. 01, 2014 
 
 
 
 
Oct. 10, 2014 
Business acquisition additional percentage acquired
 
 
 
 
 
 
 
0 
 
0 
 
Business Combination, Consideration Transferred
 
 
 
 
 
 
0 
 
 
 
 
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable
 
 
1.0 
 
 
 
 
0 
0 
0 
 
Payments to Acquire Additional Interest in Subsidiaries
 
 
 
 
 
 
 
$ 7.0 
 
$ 5.5