ENLINK MIDSTREAM PARTNERS, LP, 10-Q filed on 5/4/2016
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2016
Apr. 22, 2016
Document Information [Line Items]
 
 
Document Type
10-Q 
 
Document Fiscal Period Focus
Q1 
 
Document Period End Date
Mar. 31, 2016 
 
Document Fiscal Year Focus
2016 
 
Amendment Flag
false 
 
Entity Registrant Name
EnLink Midstream Partners, LP 
 
Entity Central Index Key
0001179060 
 
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
 
325,507,250 
Common Class C [Member]
 
 
Document Information [Line Items]
 
 
Entity Common Stock, Shares Outstanding
 
7,284,477 
Condensed Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Current assets:
 
 
Cash and cash equivalents
$ 5.7 
$ 5.9 
Accounts receivable:
 
 
Trade, net of allowance for bad debt of $0.3 and $0.3, respectively
40.0 
37.5 
Accrued revenue and other
261.3 
268.7 
Related party
88.4 
111.1 
Fair value of derivative assets
10.5 
16.8 
Natural gas and NGLs inventory, prepaid expenses and other
32.0 
32.1 
Total current assets
437.9 
472.1 
Property and equipment, net of accumulated depreciation of $1,847.3 and $1,757.6, respectively
6,117.0 
5,666.8 
Intangible assets, net of accumulated amortization of $82.1 and $54.6, respectively
1,696.7 
689.9 
Goodwill
420.7 
987.0 
Investment in unconsolidated affiliates
269.8 
274.3 
Other assets, net
2.4 
2.7 
Total assets
8,944.5 
8,092.8 
Current liabilities:
 
 
Accounts payable and drafts payable
35.7 
33.2 
Accounts payable to related party
22.8 
14.8 
Accrued gas, NGLs, condensate and crude oil purchases
202.9 
206.7 
Fair value of derivative liabilities
3.2 
2.9 
Installment payable, net of discount of $21.0
229.0 
0 
Other current liabilities
187.2 
174.4 
Total current liabilities
680.8 
432.0 
Long-term debt
3,195.6 
3,066.8 
Fair value of derivative liabilities
0 
0.1 
Asset retirement obligation
13.1 
12.9 
Installment payable, net of discount of $45.7
204.3 
0 
Other long-term liabilities
59.5 
65.9 
Deferred tax liability
73.6 
73.6 
Redeemable non-controlling interest
6.8 
7.0 
Common unitholders (325,484,514 units issued and outstanding at March 31, 2016 and 325,090,624 units issued and outstanding at December 31, 2015)
3,367.5 
4,055.8 
Class C unitholders (7,284,477 units issued and outstanding at March 31, 2016 and 7,075,433 units issued and outstanding at December 31, 2015)
137.0 
149.4 
Preferred unitholders (50,000,000 units issued and outstanding at March 31, 2016)
736.3 
0 
General partner interest (1,594,974 equivalent units outstanding at March 31, 2016 and December 31, 2015)
210.4 
213.4 
Non-controlling interest
259.6 
15.9 
Total partners' equity
4,710.8 
4,434.5 
Commitments and Contingencies
   
   
Total liabilities and partners’ equity
$ 8,944.5 
$ 8,092.8 
Condensed Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Assets [Abstract]
 
 
Allowance for bad debt
$ 0.3 
$ 0.3 
Property and equipment, accumulated depreciation
1,847.3 
1,757.6 
Intangible assets, accumulated amortization
82.1 
54.6 
Liabilities [Abstract]
 
 
Installment payable, net of discount of $21.0
21.0 
0 
Installment payable, net of discount of $45.7
$ 45.7 
$ 0 
Partners' Capital [Abstract]
 
 
Common Stock, Shares, Issued
325,484,514 
325,090,624 
Preferred Units, Issued
50,000,000 
0 
General Partners' Capital Account, Units Issued
1,594,974 
1,594,974 
Other Ownership Interests, Units Outstanding
7,284,477 
7,075,433 
Condensed Consolidated Statements of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Revenues:
 
 
Product sales
$ 588.5 
$ 670.7 
Product sales - affiliates
24.5 
16.2 
Midstream services
114.5 
102.4 
Midstream services-affiliates
162.6 
151.0 
Gain (loss) on derivative activity
(0.4)
0.2 
Total revenues
889.7 
940.5 
Operating costs and expenses:
 
 
Cost of sales (1)
586.2 
657.4 
Operating expenses (2)
98.2 
98.4 
General and administrative
33.2 
41.9 
Gain on disposition of assets
(0.2)
0 
Depreciation and amortization
121.9 
91.3 
Impairments
566.3 
0 
Total operating costs and expenses
1,405.6 
889.0 
Operating income (loss)
(515.9)
51.5 
Other income (expense):
 
 
Interest expense, net of interest income
(43.7)
(18.9)
Income (loss) from unconsolidated affiliates
(2.4)
3.7 
Other income
0.1 
0.6 
Total other expense
(46.0)
(14.6)
Income (loss) before non-controlling interest and income taxes
(561.9)
36.9 
Income tax provision
(1.0)
(1.2)
Net income (loss)
(562.9)
35.7 
Net income attributable to non-controlling interest
(2.5)
0.1 
Net income (loss) attributable to EnLink Midstream Partners, LP
(560.4)
35.6 
General partner interest in net income
7.4 
26.5 
Limited partners’ interest in net income (loss) attributable to EnLink Midstream Partners, LP
(567.2)
9.0 
Class C partners’ interest in net income (loss) attributable to EnLink Midstream Partners, LP
(12.4)
0.1 
Preferred interest in net income attributable to EnLink Midstream Partners, LP
$ 11.8 
$ 0 
Basic common unit
$ (1.74)
$ 0.03 
Diluted common unit
$ (1.74)
$ 0.03 
Condensed Consolidated Statements of Operations (parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Affiliate purchased gas, NGLs, condensate and crude
$ 586.2 
$ 657.4 
Affiliate operating expenses
98.2 
98.4 
Affiliated Entity [Member]
 
 
Affiliate purchased gas, NGLs, condensate and crude
42.6 
7.9 
Affiliate operating expenses
$ 0.1 
$ 0 
Consolidated Statements of Changes in Partners' Equity (USD $)
In Millions, unless otherwise specified
Total
Common Units
Preferred Stock [Member]
General Partner Interest
Noncontrolling Interest [Member]
Common Class C [Member]
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount at Dec. 31, 2015
$ 7.0 
 
 
 
 
 
Balance (Shares) at Dec. 31, 2015
 
325.2 
 
1.6 
 
7.1 
Increase (Decrease) in Partners' Capital
 
 
 
 
 
 
Limited Partners' Capital Account
3,367.5 
3,367.5 
 
 
 
 
Other Ownership Interests, Capital Account
137.0 
 
 
 
 
137.0 
Preferred Units, Preferred Partners' Capital Accounts
736.3 
 
736.3 
 
 
 
General Partners' Capital Account
210.4 
 
 
210.4 
 
 
Stockholders' Equity Attributable to Noncontrolling Interest
259.6 
 
 
 
259.6 
 
Partners' Capital, Including Portion Attributable to Noncontrolling Interest
4,710.8 
 
 
 
 
 
Stock Issued During Period, Value, New Issues
 
2.1 
 
 
 
 
Proceeds from Issuance of Preferred Stock and Preference Stock
 
 
724.5 
 
 
 
Stock Issued During Period, Shares, New Issues
 
0.2 
50.0 
 
 
 
Proceeds from Contributions from Parent
237.1 
 
 
 
237.1 
 
Conversion of restricted units for common units, net of units withheld for taxes
(1.1)
(1.1)
 
 
 
 
Restricted Stock, Shares Issued Net of Shares for Tax Withholdings
 
0.1 
 
 
 
 
Unit-based compensation
7.9 
3.9 
 
4.0 
 
 
Contribution from Devon
1.4 
1.4 
 
 
 
 
Distributions
(141.8)
(127.4)
 
(14.4)
 
 
Dividends, Paid-in-kind
 
 
 
 
 
0.2 
Noncontrolling Interest contributions
9.7 
 
 
 
9.7 
 
Distributions to non-controlling interest
(0.6)
 
 
 
(0.6)
 
Net income (loss)
(562.9)
(567.2)
11.8 
7.4 
(2.5)
(12.4)
Increase (Decrease) in Temporary Equity
 
 
 
 
 
 
Redeemable Noncontrolling Interest Reclassifications Between Permanent And Temporary Equity
(0.2)
 
 
 
 
 
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount at Mar. 31, 2016
$ 6.8 
 
 
 
 
 
Balance (Shares) at Mar. 31, 2016
 
325.5 
50.0 
1.6 
 
7.3 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Statement of Cash Flows [Abstract]
 
 
Net income (loss)
$ (562.9)
$ 35.7 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Impairments
566.3 
0 
Depreciation and amortization
121.9 
91.3 
Accretion expense
0.1 
0.1 
Gain on disposition of assets
(0.2)
0 
Non-cash unit-based compensation
7.9 
13.8 
(Gain) loss on derivatives recognized in net income (loss)
0.4 
(0.2)
Cash settlements on derivatives
5.6 
3.9 
Amortization of debt issue costs
0.8 
0.6 
Amortization of net (premium) discount on notes
11.7 
(0.8)
Redeemable non-controlling interest expense
0.2 
(2.6)
Distribution of earnings from unconsolidated affiliates
0 
2.7 
(Income) loss from unconsolidated affiliates
2.4 
(3.7)
Changes in assets and liabilities net of assets acquired and liabilities assumed:
 
 
Accounts receivable, accrued revenue and other
32.0 
118.8 
Natural gas and NGLs inventory, prepaid expenses and other
14.9 
(16.3)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities
(12.0)
(71.6)
Net cash provided by operating activities
189.1 
171.7 
Cash flows from investing activities, net of assets acquired and liabilities assumed:
 
 
Additions to property and equipment
(135.4)
(161.1)
Acquisition of business, net of cash acquired
(774.9)
(312.0)
Proceeds from sale of property
0.2 
0 
Investment in unconsolidated affiliates
(7.1)
0 
Distribution from unconsolidated affiliates in excess of earnings
6.2 
4.1 
Net cash used in investing activities
(911.0)
(469.0)
Cash flows from financing activities:
 
 
Proceeds from borrowings
379.0 
959.1 
Payments on borrowings
(250.0)
(487.1)
Payments on capital lease obligations
(1.1)
(1.0)
Decrease in drafts payable
0 
(12.7)
Debt financing costs
(0.2)
(1.8)
Conversion of restricted units, net of units withheld for taxes
(1.1)
(2.4)
Proceeds from issuance of common units
2.1 
2.2 
Proceeds from issuance of preferred units
724.5 
0 
Distributions to non-controlling partners
(0.8)
(45.2)
Contributions by non-controlling partners
9.7 
2.8 
Distributions to partners
(141.8)
(99.9)
Contributions from Devon
1.4 
7.9 
Net cash provided by financing activities
721.7 
321.9 
Net increase (decrease) in cash and cash equivalents
(0.2)
24.6 
Cash and cash equivalents, beginning of period
5.9 
9.6 
Cash and cash equivalents, end of period
5.7 
34.2 
Cash paid for interest
3.3 
2.1 
Cash paid for income taxes
$ 1.5 
$ 0.1 
General
General
(1) General
In this report, the term “Partnership,” as well as the terms “our,” “we,” “us” and “its,” are sometimes used as abbreviated references to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership (as defined below) and EnLink TOM Holdings, LP and its consolidated subsidiaries (collectively, “TOM”). TOM is sometimes used to refer to EnLink TOM Holdings, LP itself or EnLink TOM Holdings, LP together with its consolidated subsidiaries.
(a)Organization of Business
EnLink Midstream Partners, LP is a publicly traded Delaware limited partnership formed in 2002. Our common units are traded on the New York Stock Exchange under the symbol “ENLK.” Our business activities are conducted through our subsidiary, EnLink Midstream Operating, LP, a Delaware limited partnership (the “Operating Partnership”), and the subsidiaries of the Operating Partnership.
EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities. Our general partner is an indirect wholly-owned subsidiary of EnLink Midstream, LLC (“ENLC”). ENLC’s units are traded on the New York Stock Exchange under the symbol “ENLC.” Devon Energy Corporation (“Devon”) owns ENLC's managing member and common units which represent approximately 64% of the outstanding limited liability company interests in ENLC.
Effective as of January 7, 2016, the Operating Partnership acquired 84% of the outstanding equity interests in TOM, and ENLC acquired the remaining 16% equity interests in TOM. Since we control TOM, we reflect our ownership in TOM on a consolidated basis and ENLC's ownership is reflected as a non-controlling interest in the respective condensed consolidated financial statements and related disclosures.
(b)Nature of Business
We primarily focus on providing midstream energy services, including gathering, transmission, processing, fractionation, brine services and marketing to producers of natural gas, natural gas liquids (“NGLs”), crude oil and condensate. We connect the wells of natural gas producers in our market areas to our gathering systems, process natural gas to remove NGLs, fractionate NGLs into purity products and market those products for a fee, transport natural gas and ultimately provide natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply sources and sell that natural gas to utilities, industrial consumers, other marketers and pipelines. We operate processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee-based arrangements. We provide a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. We also have crude oil and condensate terminal facilities that provide access for crude oil and condensate producers to premium markets. Our 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. Our transmission pipelines primarily receive natural gas from our gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. We also have transmission lines that transport NGLs from east Texas and from our south Louisiana processing plants to our fractionators in south Louisiana. Our 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. Our processing plants remove NGLs and CO2 from a natural gas stream and our fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline.
Significant Accounting Policies
Significant Accounting Policies [Text Block]
(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 (“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.
During the first half of 2015, we acquired assets from ENLC and Devon through drop down transactions. Due to ENLC's control of us through its ownership and control of our general partner and Devon's control of us through its ownership of the managing member of ENLC, each acquisition from ENLC and Devon was considered a transfer of net assets between entities under common control. As such, we were required to recast our historical financial statements to include the activities of such assets from the date that these entities were under common control. The condensed consolidated financial statements for periods prior to our acquisition of the assets from ENLC and Devon have been prepared from ENLC’s and Devon's historical cost-basis accounts for the acquired assets and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from ENLC and Devon for periods prior to our acquisition is allocated to our general partner.
(b) Recent Accounting Pronouncements
In January 2016, we adopted ASU 2015-03, Interest - Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability and requires retrospective application.  The application of this new accounting guidance resulted in the reclassification of $23.0 million of debt issuance costs from “Other Assets, Net” to “Long-term debt” in our accompanying Condensed Consolidated Balance Sheet as of December 31, 2015.
In January 2016, we adopted ASU 2015-17, Balance Sheet Classification of Deferred Taxes on a prospective basis. This new standard required that deferred tax assets and liabilities be classified as noncurrent in our Condensed Consolidated Balance Sheet as of March 31, 2016.
In January 2016, we adopted ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated.
In January 2016, we adopted ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This update has no impact on our condensed consolidated financial statements or related disclosures.
In January 2016, we adopted ASU No. 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a Consensus of the FASB Emerging Issues Task Force) (“ASU 2015-06”), which requires a master limited partnership (MLP) to allocate earnings (losses) of a transferred business entirely to the general partner when computing earnings per unit (EPU) for periods before the dropdown transaction occurred. The EPU that the limited partners previously reported would not change as a result of the dropdown transaction. ASU 2015-06 also requires an MLP to disclose the effects of the dropdown transaction on EPU for the periods before and after the dropdown transaction occurred. ASU 2015-06 is effective for the fiscal years beginning after December 15, 2015, and interim periods within those annual periods. ASU 2015-06 requires retrospective application and early adoption is permitted. The update is effective for us beginning on January 1, 2016 and had no impact on our condensed consolidated financial statements and related disclosures.
In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which amends ASC Topic 718, Compensation – Stock Compensation (“ASU 2016-09”). First, the new standard will require all of the tax effects related to share-based payments at settlement (or expiration) to be recorded through the income statement, and is required to be applied prospectively. Second, the new standard also allows entities to withhold taxes of an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in liability classification of the award, and is required to be adopted using a modified retrospective approach. Third, under the ASU, forfeitures can be estimated, as currently required, or recognized when they occur. If elected, the change to recognize forfeitures when they occur must be adopted using a modified retrospective approach. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016 including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.
In March 2016, the FASB issued ASU 2016-08, Principal versus Agent Considerations (“ASU 2016-08”). The new standard retained the guidance that the principal in an arrangement controls a good or service before it is transferred to a customer, and revised and clarified the indicators to evaluate when making this determination. ASU 2016-08 has the same effective date and transition requirements as the new revenue standard, which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods. Early application is permitted for annual reporting periods beginning after December 15, 2016. The update will have no impact on our condensed consolidated financial statements or related disclosures.
In March 2016, the FASB issued ASU 2016-07, Simplifying the Transition to the Equity Method of Accounting (“ASU 2016-07”). The new standard eliminates the requirement to apply the equity method of accounting retrospectively when a reporting entity obtains significant influence over a previously held investment. Investors should add the cost of acquiring the additional interest in the investee (if any) to the current basis of their previously held interest. ASU 2016-07 is effective for annual reporting periods beginning after December 15, 2016 including interim periods within those annual periods. Early adoption is permitted. We do not expect this standard to impact our condensed consolidated financial statements and related disclosures.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) - Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on the balance sheet, by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018 including interim periods within those annual periods. Early adoption is permitted, and is required to be adopted using a modified retrospective transition. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.
In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). Under this new standard, the FASB issued new guidance related to accounting for unconsolidated affiliate investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. ASU 2016-01 is effective for annual reporting periods beginning after December 15, 2017 including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for transferring goods or services to a customer. The new standard will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Partnership'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, 2017, including interim periods within that reporting period, and is to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the pronouncement will have on our condensed consolidated financial statements and related disclosures.
Acquisition
Mergers Acquisitions And Dispositions Disclosures
(3) Acquisitions
Matador Acquisition
On October 1, 2015, we acquired 100% of the voting equity interests in a subsidiary of Matador Resources Company (“Matador”), which has gathering and processing assets operations in the Delaware Basin, for approximately $141.3 million. The transaction was accounted for using the acquisition method.
The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change.
Purchase Price Allocation (in millions):
 
 
Assets acquired:
 
 
Current assets
 
$
1.1

Property, plant and equipment
 
36.2

Intangibles
 
98.8

Goodwill
 
9.1

Liabilities assumed:
 
 
Current liabilities
 
(3.9
)
Total identifiable net assets
 
$
141.3


We recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to our Texas segment and is non-deductible for tax purposes.
Deadwood Acquisition
Prior to November 2015, we co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). On November 16, 2015, we acquired Apache's 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.1 million, all of which is considered property, plant and equipment. The final working capital settlement was approximately $1.5 million. The transaction was accounted for using the acquisition method.
Tall Oak Acquisition
On January 7, 2016, we and ENLC acquired an 84% and 16% interest, respectively, in TOM for approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The final installment of $500.0 million is due by us no later than the first anniversary of the closing date with the option to defer $250.0 million of the final installment up to 24 months following the closing date. The installment payables are valued net of discount within the total purchase price.
The first installment consisted of approximately $1.02 billion and was funded by (a) approximately $783.9 million in cash paid by us, the majority of which was derived from the proceeds from the issuance of Preferred Units, and (b) 15,564,009 common units representing limited liability company interests in ENLC issued directly by ENLC and approximately $22.0 million in cash paid by ENLC. The transaction was accounted for using the acquisition method.
The following table presents the consideration we paid and the fair value of the identified assets received and liabilities assumed at the acquisition date. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change.
Consideration (in millions):
 
 
Cash
 
$
783.9

Total installment payable, net of discount of $79.1 million assuming payments are made on January 7, 2017 and 2018
 
420.9

Contribution from ENLC
 
237.1

Total consideration
 
$
1,441.9

 
 

Purchase Price Allocation (in millions):
 


Assets acquired:
 
 
Current assets (including $6.8 million in cash)
 
$
20.2

Property, plant and equipment
 
423.2

Intangibles
 
1,034.3

Liabilities assumed:
 
 
Current liabilities
 
(35.8
)
Total identifiable net assets
 
$
1,441.9


We recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer life of approximately 15 years.
We incurred $3.6 million of direct transaction costs for the three months ended March 31, 2016. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.
For the period from January 7, 2016 to March 31, 2016, we recognized $27.3 million of revenues and $14.2 million of net loss related to the assets acquired.
Pro Forma Information
The following unaudited pro forma condensed financial information for the three months ended March 31, 2015 gives effect to the January 2015 LPC acquisition, March 2015 Coronado acquisition, October 2015 Matador acquisition, November 2015 Deadwood acquisition and January 2016 Tall Oak acquisition as if they had occurred on January 1, 2015. 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. Pro forma financial information associated with the acquisitions is reflected below.
 
 
Three Months Ended
March 31,
 
 
2015
 
 
(in millions)

Pro forma total revenues
 
$
1,067.6

Pro forma net income
 
$
10.8

Pro forma net income attributable to EnLink Midstream Partners, LP
 
$
14.0

Pro forma net income (loss) per common unit:
 
 
Basic
 
$
(0.14
)
Diluted
 
$
(0.14
)
Goodwill and Intangible Assets
Goodwill Disclosure
(4) Goodwill and Intangible Assets
Goodwill
Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to 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 of goodwill 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. During February 2016, we determined that continued further weakness in the overall energy sector driven by low commodity prices together with a further decline in our unit price subsequent to year-end caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis on all reporting units.
We perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples and estimated future cash flows including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among other factors.
Using the fair value approaches described above, in step one of the goodwill impairment test, we determined that the estimated fair values of our Texas and Crude and Condensate reporting units were less than their respective carrying amounts, primarily related to increases in our discount rate subsequent to year-end. The second step of the goodwill impairment test measures the amount of impairment loss and involves allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Through the analysis, a goodwill impairment loss for our Texas and Crude and Condensate reporting units in the amount of $566.3 million was recognized for the three months ended March 31, 2016, which is included in impairment expense in the Condensed Consolidated Statements of Operations.
We concluded that the fair value of goodwill of our Oklahoma reporting unit exceeded its carrying value, and the entire amount of goodwill disclosed on the Condensed Consolidated Balance Sheet associated with this remaining reporting unit is recoverable. Therefore, no other goodwill impairment was identified or recorded for this reporting unit as a result of our goodwill impairment analysis.
Our impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. Our estimated fair value of our Texas reporting unit may be impacted in the future by a further decline in our unit price or a continuing prolonged period of lower commodity prices which may adversely affect our estimate of future cash flows, both of which could result in future goodwill impairment charges for our Texas reporting unit.
The table below provides a summary of our change in carrying amount of goodwill, by assigned reporting unit (in millions):
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
Three Months Ended March 31, 2016
 
 
 
 
 
 
 
 
 
 
 
Balance, beginning of period
$
703.5

 
$
—

 
$
190.3

 
$
93.2

 
$
—

 
$
987.0

Impairment
(473.1
)
 
—

 
—

 
(93.2
)
 
—

 
(566.3
)
Balance, end of period
$
230.4

 
$
—


$
190.3


$
—


$
—

 
$
420.7


Intangible Assets
Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from ten to twenty years.
The following table represents our change in carrying value of intangible assets (in millions):
 
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
Carrying
Amount
Three Months Ended March 31, 2016
 
 
 
 
 
 
Customer relationships, beginning of period
 
$
744.5

 
$
(54.6
)
 
$
689.9

Acquisitions
 
1,034.3

 
—

 
1,034.3

Amortization expense
 
—

 
(27.5
)
 
(27.5
)
Customer relationships, end of period
 
$
1,778.8

 
$
(82.1
)
 
$
1,696.7


The weighted average amortization period for intangible assets is 14 years. Amortization expense for intangibles was approximately $27.5 million and $11.5 million for the three months ended March 31, 2016 and 2015, respectively.
The following table summarizes our estimated aggregate amortization expense for the next five years (in millions):
2016 (remaining)
$
86.3

2017
115.1

2018
115.1

2019
115.1

2020
115.1

Thereafter
1,150.0

Total
$
1,696.7

Affiliate Transactions
Related Party Transactions Disclosure
(5) Affiliate Transactions
We engage in various transactions with Devon and other affiliated entities. For the three months ended March 31, 2016 and 2015, Devon was a significant customer to us. Devon accounted for 21.0% and 17.8% of our revenues for the three months ended March 31, 2016 and 2015, respectively. We had an accounts receivable balance related to transactions with Devon of $88.3 million as of March 31, 2016 and $110.8 million as of December 31, 2015. Additionally, we had an accounts payable balance related to transactions with Devon of $22.8 million as of March 31, 2016 and $14.8 million as of December 31, 2015. 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.
TOM Gathering and Processing Agreement with Devon
In January 2016, in connection with the Tall Oak acquisition, we acquired a Gas Gathering and Processing Agreement with Devon Energy Production Company, L.P. (“DEPC”) pursuant to which TOM provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by DEPC. The agreement has a minimum volume commitment that will remain in place during each calendar quarter for the next five years and a remaining overall term of approximately 13 years. Additionally, the agreement provides TOM with dedication of all of the natural gas owned or controlled by DEPC 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 DEPC. DEPC is entitled to firm service, meaning a level of gathering and processing service in which DEPC’s reserved capacity may not be interrupted, except due to force majeure, and may not be displaced by another customer or class of service. TOM will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.
Long-Term Debt
Long-Term Debt
6) Long-Term Debt
As of March 31, 2016 and December 31, 2015, long-term debt consisted of the following (in millions):
 
March 31,
2016
 
December 31,
2015
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at March 31, 2016 and December 31, 2015 was 2.2% and 1.8%, respectively
$
543.0

 
$
414.0

Senior unsecured notes (due 2019), net of discount of $0.4 million at March 31, 2016 and $0.4 million at December 31, 2015, which bear interest at the rate of 2.70%
399.6

 
399.6

Senior unsecured notes (due 2022), including a premium of $18.2 million at March 31, 2016 and $18.9 million at December 31, 2015, which bear interest at the rate of 7.125%
180.7

 
181.4

Senior unsecured notes (due 2024), net of premium of $2.8 million at March 31, 2016 and $2.9 million at December 31, 2015, which bear interest at the rate of 4.40%
552.8

 
552.9

Senior unsecured notes (due 2025), net of discount of $1.2 million at March 31, 2016 and $1.2 million at December 31, 2015, which bear interest at the rate of 4.15%
748.8

 
748.8

Senior unsecured notes (due 2044), net of discount of $0.3 million at March 31, 2016 and $0.2 million at December 31, 2015, which bear interest at the rate of 5.60%
349.7

 
349.8

Senior unsecured notes (due 2045), net of discount of $6.8 million at March 31, 2016 and $6.9 million at December 31, 2015, which bear interest at the rate of 5.05%
443.2

 
443.1

Debt issuance cost, net of amortization of $5.5 million at March 31, 2016 and $4.7 million at December 31, 2015
(22.4
)
 
(23.0
)
Other debt
0.2

 
0.2

Debt classified as long-term
$
3,195.6

 
$
3,066.8


Credit Facility
We have a $1.5 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”) that matures on March 6, 2020. Under our credit facility, we are permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under our credit facility by an additional amount not to exceed $500 million and (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of our credit facility by one year on each occasion. Our 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 our credit facility, which definition includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If we consummate one or more acquisitions in which the aggregate purchase price is $50.0 million or more, we can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.
Borrowings under our credit facility bear interest at our 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 our credit rating. If we breach certain covenants governing our credit facility, amounts outstanding under our credit facility, if any, may become due and payable immediately.
As of March 31, 2016, there were $10.8 million in outstanding letters of credit and $543.0 million in outstanding borrowings under our credit facility, leaving approximately $946.2 million available for future borrowing based on the borrowing capacity of $1.5 billion.
All other material terms and conditions of our credit facility are described in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness” in our Annual Report on Form 10-K for the year ended December 31, 2015. We expect to be in compliance with all credit facility covenants for at least the next twelve months.
Partners' Capital
Partners' Capital Disclosure
(7)      Partners’ Capital
(a) Issuance of Common Units
In November 2014, we entered into an Equity Distribution Agreement (the “BMO EDA”) with BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC (collectively, the “Sales Agents”) to sell up to $350.0 million in aggregate gross sales of our common units from time to time through an “at the market” equity offering program. We may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. We have no obligation to sell any of the common units under the BMO EDA and may at any time suspend solicitation and offers under the BMO EDA. For the three months ended March 31, 2016, we sold an aggregate of 0.2 million common units under the BMO EDA, generating proceeds of approximately $2.1 million (net of approximately $0.1 million of commissions). We used the net proceeds for general partnership purposes. As of March 31, 2016, approximately $314.8 million remains available to be issued under the BMO EDA.
(b) Class C Common Units
In March 2015, we issued 6,704,285 Class C Common Units representing a new class of limited partner interests as partial consideration for the acquisition of Coronado. The Class C Common Units are substantially similar in all respects to our common units, except that distributions paid on the Class C Common Units may be paid in cash or in additional Class C Common Units issued in kind, as determined by our general partner in its sole discretion. The Class C Common Units will automatically convert into common units on a one-for-one basis on May 13, 2016. Distributions on the Class C Common Units for the three months ended December 31, 2015 were paid-in-kind (“PIK”) through the issuance of 209,044 Class C Common Units on February 11, 2016. A distribution on the Class C Common Units of $0.390 per unit was declared for the three months ended March 31, 2016, which will result in the issuance of 233,107 additional Class C Common Units on May 12, 2016.
(c) Preferred Units
In January 2016, we issued an aggregate of 50,000,000 Series B Cumulative Convertible Preferred Units representing our limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00 per Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.5 million after fees and deductions. Proceeds from the Private Placement were used to partially fund our portion of the purchase price payable in connection with the Tall Oak acquisition. Affiliates of the Goldman Sachs Group, Inc. and affiliates of TPG Global, LLC own interests in the general partner of Enfield. The Preferred Units are convertible into our common units on a one-for-one basis, subject to certain adjustments, at any time after the record date for the quarter ending June 30, 2017 (a) in full, at our option, if the volume weighted average price of a common unit over the 30-trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of our general partner or the managing member of ENLC, all of the Preferred Units will automatically convert into a number of common units equal to the greater of (i) the number of common units into which the Preferred Units would then convert and (ii) the number of Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP.
Enfield will receive a quarterly distribution, subject to certain adjustments, equal to (x) during the quarter ending March 31, 2016 through the quarter ending June 30, 2017, an annual rate of 8.5% on the Issue Price payable in-kind in the form of additional Preferred Units and (y) thereafter, at an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) an annual rate of 1.0% of the Issue Price and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the Issue Price. A distribution on the Preferred Units was declared for the three months ended March 31, 2016, which will result in the issuance of 992,445 additional Preferred Units distributable on May 12, 2016. Income was allocated to the preferred units in an amount equal to the quarterly distribution with respect to the period earned. For the three months ended March 31, 2016, $11.8 million of income was allocated to the preferred units.
(d)  Distributions
Unless restricted by the terms of our credit facility and/or the indentures governing our senior unsecured notes, we must make distributions of 100% of available cash, as defined in our agreement, within 45 days following the end of each quarter. Distributions are made to our 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. Our general partner is not entitled to its general partner or incentive distributions with respect to the Class C Common Units and Preferred Units issued in kind.
Our general partner owns the general partner interest in us and all of our incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13.0% of amounts we distribute in excess of $0.25 per unit, 23% of the amounts we distribute in excess of $0.3125 per unit and 48.0% of amounts we distribute in excess of $0.375 per unit.
A summary of the distribution activity relating to the common units for the three months ended March 31, 2016 is provided below:
Declaration period
 
Distribution/unit
 
Date paid/payable
Fourth Quarter of 2015
 
$
0.39

 
February 11, 2016
First Quarter of 2016
 
$
0.39

 
May 12, 2016

(e) 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 (loss) attributable to the EMH Drop Downs and VEX Interests acquired during 2015 from ENLC and Devon, respectively, for periods prior to acquisition is not allocated to the limited partners for purposes of calculating net income (loss) per common unit. The following table reflects the computation of basic and diluted earnings per limited partner unit for the period presented (in millions, except per unit amounts):
 
Three Months Ended
March 31,
 
2016
 
2015
Limited partners’ interest in net income (loss)
$
(567.2
)
 
$
9.0

Distributed earnings allocated to:
 
 
 
Common units (1)
$
126.9

 
$
99.5

Unvested restricted units (1)
0.8

 
0.4

Total distributed earnings
$
127.7

 
$
99.9

Undistributed loss allocated to:
 
 
 
Common units
$
(690.7
)
 
$
(90.5
)
Unvested restricted units
(4.2
)
 
(0.4
)
Total undistributed loss
$
(694.9
)
 
$
(90.9
)
Net income (loss) allocated to:
 
 
 
Common units
$
(563.8
)
 
$
9.0

Unvested restricted units
(3.4
)
 
—

Total limited partners’ interest in net income (loss)
$
(567.2
)
 
$
9.0

Basic and diluted net income (loss) per unit:
 
 
 
Basic
$
(1.74
)
 
$
0.03

Diluted
$
(1.74
)
 
$
0.03


(1)
Three months ended March 31, 2016 and 2015 represents a declared distribution of $0.39 per unit payable on May 12, 2016 and a distribution of $0.38 per unit paid on May 14, 2015, respectively.

 
The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the periods presented (in millions):
 
Three Months Ended
March 31,
 
2016
 
2015
Basic weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
325.2

 
261.8

Weighted average Class C Common Units outstanding
7.2

 
1.1

    Total weighted average limited partner common units outstanding
332.4

 
262.9

Diluted weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
332.4

 
262.9

Dilutive effect of restricted units issued
—

 
0.4

    Total weighted average limited partner diluted common units outstanding
332.4

 
263.3


All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the periods presented.
Net income is allocated to our general partner in an amount equal to its incentive distributions as described in (d) above. Our 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 our net income adjusted for ENLC's unit-based compensation specifically allocated to our general partner. The net income allocated to our general partner is as follows for the periods presented (in millions):
 
Three Months Ended
March 31,
 
2016
 
2015
Income allocation for incentive distributions
$
13.8

 
$
8.8

Unit-based compensation attributable to ENLC’s restricted units
(4.0
)
 
(7.0
)
General partner share of net income (loss)
(2.4
)
 
0.1

General partner interest in drop down transactions
—

 
24.6

General partner interest in net income
$
7.4

 
$
26.5

Asset Retirement Obligation
Asset Retirement Obligation Disclosure
(8) Asset Retirement Obligations
The schedule below summarizes the changes in our asset retirement obligation:
 
Three Months Ended
March 31,
 
2016
 
2015
 
(in millions)
Beginning asset retirement obligations
$
14.0

 
$
20.6

Revisions to existing liabilities
(0.4
)
 
(3.9
)
Accretion
0.1

 
0.1

Liabilities settled
(0.6
)
 
(3.2
)
Ending asset retirement obligations
$
13.1

 
$
13.6


There are no asset retirement obligations included in Other Current Liabilities as of March 31, 2016. Asset retirement obligations of $1.1 million is included in Other Current Liabilities as of March 31, 2015.
Investment in Unconsolidated Affiliate
Investment in unconsolidated affiliate
(9) Investment in Unconsolidated Affiliates
Our unconsolidated investments consisted of a contractual right to the economic benefits and burdens associated with Devon's 38.75% ownership interest in Gulf Coast Fractionators (“GCF”) at March 31, 2016 and 2015 and a 30.6% ownership interest in Howard Energy Partners (“HEP”) at March 31, 2016 and 2015.
The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):
 
Gulf Coast Fractionators
 
Howard Energy Partners
 
Total
Three months ended
 
 
 
 
 
March 31, 2016
 
 
 
 
 
Contributions
$
—

 
$
7.1

 
$
7.1

Distributions
$
3.0

 
$
6.2

 
$
9.2

Equity in net loss
$
(1.7
)
 
$
(0.7
)
 
$
(2.4
)
 
 
 
 
 
 
March 31, 2015
 
 
 
 
 
Distributions
$
2.7

 
$
4.1

 
$
6.8

Equity in net income
$
3.3

 
$
0.4

 
$
3.7


The following table shows the balances related to our investment in unconsolidated affiliates for the periods indicated (in millions):
 
March 31,
2016
 
December 31,
2015
Gulf Coast Fractionators
$
47.9

 
$
52.6

Howard Energy Partners
221.9

 
221.7

Total investment in unconsolidated affiliates
$
269.8

 
$
274.3

Employee Incentive Plans
Employee Incentive Plans
(10) Employee Incentive Plans
(a)         Long-Term Incentive Plans
We account 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 condensed consolidated financial statements. On April 7, 2016, our general partner amended and restated the EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”). Amendments to the GP Plan included an increase to the number of common units of the Partnership authorized for issuance under the GP Plan by 5,000,000 common units to an aggregate of 14,070,000 common units and other technical changes.
We and ENLC each have similar unit-based compensation payment plans for officers and employees, which are described below.  Unit-based compensation associated with ENLC's unit-based compensation plan awarded to our officers and employees is recorded by us since ENLC has no substantial or managed operating activities other than its interests in us and TOM. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions): 
 
Three Months Ended
March 31,
 
2016
 
2015
Cost of unit-based compensation charged to general and administrative expense
$
6.2

 
$
11.9

Cost of unit-based compensation charged to operating expense
1.7

 
1.9

    Total amount charged to income
$
7.9

 
$
13.8


(b)  EnLink Midstream Partners, LP Restricted Incentive Units
Our 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 three months ended March 31, 2016 is provided below:
 
 
Three Months Ended
March 31, 2016
EnLink Midstream Partners, LP Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-vested, beginning of period
 
1,253,729

 
$
29.59

Granted
 
1,041,022

 
10.01

Vested*
 
(294,460
)
 
30.40

Forfeited
 
(27,797
)
 
24.12

Non-vested, end of period
 
1,972,494

 
$
19.21

Aggregate intrinsic value, end of period (in millions)
 
$
23.8

 
 


 * Vested units include 84,429 units withheld for payroll taxes paid on behalf of employees.
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three months ended March 31, 2016 and 2015 are provided below (in millions):

 
Three Months Ended
March 31,
EnLink Midstream Partners, LP Restricted Incentive Units:
 
2016

2015
Aggregate intrinsic value of units vested
 
$
3.7


$
6.8

Fair value of units vested
 
$
9.0


$
7.0


As of March 31, 2016, there was $22.4 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 1.9 years.
(c)  EnLink Midstream Partners, LP Performance Units
During the first quarter of 2016, our general partner and the managing member of ENLC granted performance awards under the GP Plan and the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “LLC Plan”), respectively. The performance award agreements provide that the vesting of restricted incentive units granted thereunder is dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding us and ENLC (collectively, “EnLink”), on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of the Partnership’s and ENLC’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.
At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200 percent of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of our common units and the designated peer group securities; (iii) an estimated ranking of us among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:
EnLink Midstream Partners, LP Performance Units:
 
January 2016
 
February 2016
Beginning TSR Price
 
$
14.82

 
$
14.82

Risk-free interest rate
 
1.10
%
 
0.89
%
Volatility factor
 
39.71
%
 
42.33
%
Distribution yield
 
12.10
%
 
19.20
%

The following table presents a summary of our performance units:
 
 
Three Months Ended 
March 31, 2016
EnLink Midstream Partners, LP Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
118,126

 
$
35.41

Granted
 
258,078

 
9.81

Forfeited
 
(2,798
)
 
36.18

Non-vested, end of period
 
373,406

 
$
17.71

Aggregate intrinsic value, end of period (in millions)
 
$
4.5

 


As of March 31, 2016, there was $4.9 million of unrecognized compensation expense that related to our non-vested performance units. That cost is expected to be recognized over a weighted-average period of 2.2 years.
(d)         EnLink Midstream, LLC Restricted Incentive Units
ENLC restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of the common units on such date. A summary of the restricted incentive unit activity for the three months ended March 31, 2016 is provided below:
 
 
Three Months Ended 
March 31, 2016
EnLink Midstream, LLC Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-vested, beginning of period
 
1,148,893

 
$
34.78

Granted
 
1,032,976

 
9.42

Vested*
 
(317,726
)
 
37.03

Forfeited
 
(24,970
)
 
26.85

Non-vested, end of period
 
1,839,173

 
$
20.26

Aggregate intrinsic value, end of period (in millions)
 
$
20.7

 
 


* Vested units include 90,326 units withheld for payroll taxes paid on behalf of employees.
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three months ended March 31, 2016 and 2015 are provided below (in millions):
 
 
Three Months Ended
March 31,
EnLink Midstream, LLC Restricted Incentive Units:
 
2016
 
2015
Aggregate intrinsic value of units vested
 
$
3.8

 
$
8.3

Fair value of units vested
 
$
11.8

 
$
8.6


As of March 31, 2016, there was $21.9 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 1.9 years.
(e) EnLink Midstream, LLC's Performance Units
In 2016, ENLC granted performance awards under the LLC Plan discussed in Note (c) above. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200 percent of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC's common units and the designated peer group securities; (iii) an estimated ranking of ENLC among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:
EnLink Midstream, LLC Performance Units:
 
January 2016
 
February 2016
Beginning TSR Price
 
$
15.38

 
$
15.38

Risk-free interest rate
 
1.10
%
 
0.89
%
Volatility factor
 
46.02
%
 
52.05
%
Distribution yield
 
8.60
%
 
14.00
%

The following table presents a summary of the ENLC's performance units:
 
 
Three Months Ended 
March 31, 2016
EnLink Midstream, LLC Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
105,080

 
$
40.50

Granted
 
242,646

 
9.59

Forfeited
 
(2,525
)
 
41.31

Non-vested, end of period
 
345,201

 
$
18.76

Aggregate intrinsic value, end of period (in millions)
 
$
3.9

 


As of March 31, 2016, there was $4.7 million of unrecognized compensation expense that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 2.2 years.
Derivatives
Derivatives
(11) Derivatives
Commodity Swaps
We manage our 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. We do 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 our derivatives are recorded in revenue in the period incurred. In addition, our risk management policy does not allow us to take speculative positions with our derivative contracts.
We commonly enter into index (float-for-float) or fixed-for-float swaps in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, NGLs and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. They are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate and crude, fixed-for-float swaps are used to protect cash flows against price fluctuations: (1) where we receive a percentage of liquids as a fee for processing third-party gas or where we receive a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation components of our business and (3) where we are mitigating the price risk for product held in inventory or storage.
The components of gain (loss) on derivative activity in the Condensed Consolidated Statements of Operations relating to commodity swaps are (in millions):
 
Three Months Ended
March 31,
 
2016
 
2015
Change in fair value of derivatives
$
(6.0
)
 
$
(3.7
)
Realized gain on derivatives
5.6

 
3.9

    Gain (loss) on derivative activity
$
(0.4
)
 
$
0.2


The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions):
 
March 31,
2016
 
December 31,
2015
Fair value of derivative assets — current
$
10.5

 
$
16.8

Fair value of derivative liabilities — current
(3.2
)
 
(2.9
)
Fair value of derivative liabilities — long term
—

 
(0.1
)
    Net fair value of derivatives
$
7.3

 
$
13.8


The total estimated fair value of derivative contracts of $7.3 million as of March 31, 2016 has a maturity date of less than one year.
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 March 31, 2016. The remaining term of the contracts extend no later than March 2017.
 
 
 
 
 
 
March 31, 2016
Commodity
 
Instruments
 
Unit
 
Volume
 
Fair Value
 
 
 
 
 
 
(In millions)
NGL (short contracts)
 
Swaps
 
Gallons
 
(42.9
)
 
$
8.8

NGL (long contracts)
 
Swaps
 
Gallons
 
17.1

 
(1.8
)
Natural Gas (short contracts)
 
Swaps
 
MMBtu
 
(6.7
)
 
0.8

Natural Gas (long contracts)
 
Swaps
 
MMBtu
 
2.2

 
(0.3
)
Condensate (short contracts)
 
Swaps
 
MMBbls
 
(0.1
)
 
(0.2
)
Total fair value of derivatives
 
 
 
 
 
 
 
$
7.3


On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. We have entered into Master International Swaps and Derivatives Association Agreements (“ISDAs”) that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing swap contracts, our maximum loss as of March 31, 2016 of $10.5 million would be reduced to $7.3 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.
Fair Value Measurements
Fair Value Measurements
(12)      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, 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.
Our derivative contracts primarily consist of commodity swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument's term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy.
Net liabilities measured at fair value on a recurring basis are summarized below (in millions):
 
March 31, 2016
Level 2
 
December 31, 2015
Level 2
Commodity Swaps*
$
7.3

 
$
13.8

Total
$
7.3

 
$
13.8

 
*               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 our and/or the counterparty credit risk as required under FASB ASC 820.
Fair Value of Financial Instruments
We have determined the estimated fair value of our financial instruments using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):
 
March 31, 2016
 
December 31, 2015
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Long-term debt
$
3,195.6

 
$
2,629.0

 
$
3,066.8

 
$
2,585.5

Obligations under capital leases
$
13.4

 
$
12.7

 
$
16.7

 
$
15.6


The carrying amounts of our cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.
We had $543.0 million and $414.0 million in outstanding borrowings under our revolving credit facility as of March 31, 2016 and December 31, 2015, respectively. As borrowings under the credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of March 31, 2016 and December 31, 2015, we had total borrowings of $2.7 billion under senior unsecured notes maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. The fair value of all senior unsecured notes as of March 31, 2016 and December 31, 2015 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
Commitments and Contingencies Disclosure
(13) Commitments and Contingencies
(a) Severance and Change in Control Agreements
Certain members of our management are parties to severance and change of control agreements with the Operating Partnership. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individual from, among other things, competing with our general partner or its affiliates during his or her employment. In addition, the severance and change of control agreements prohibit subject individuals from, among other things, disclosing confidential information about our general partner or interfering with a client or customer of our general partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment.
(b) Environmental Issues
The operation of pipelines, plants and other facilities for the gathering, processing, transmitting or disposing of natural gas, NGLs, crude oil, condensate, brine and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, 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 our results of operations, financial condition or cash flows. In February 2016, a spill occurred at our Kill Buck Station in our Ohio operations.  State and federal agencies were notified and clean-up response efforts were promptly executed, which significantly lessened the impact of the spill.  On April 7, 2016, the state agency determined that the clean-up recovery efforts were completed and has internally transitioned monitoring to their water quality division.  We do not anticipate a material fine or penalty by either the state or federal agencies.  Additionally, although the spill that previously occurred in our West Virginia operations in the third quarter of 2015 is still pending, we do not believe that any fine or penalty that may be issued will be material to our operations.  Lastly, we continue to work with Pipeline and Hazardous Materials Safety Administration regarding the notice of potential violation discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.
(c) Litigation Contingencies
We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.
At times, our subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, from time to time we (or our subsidiaries) are a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by our 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, we do not expect that awards in these matters will have a material adverse impact on our consolidated results of operations, financial condition or cash flows.
We (or our subsidiaries) are defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed by us as part of our 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. Our subsidiary, EnLink LIG, LLC, is one of the named defendants as the owner of pipelines in the area. On February 13, 2015, the court granted defendants’ joint motion to dismiss and dismissed the plaintiff’s claims with prejudice. Plaintiffs have appealed the matter to the United States Court of Appeals for the Fifth Circuit. We intend to vigorously defend the case. The success of the plaintiffs' appeal as well as our costs and legal exposure, if any, related to the lawsuit are not currently determinable.
We own and operate a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs. We are seeking to recover our losses from responsible parties. We have sued Texas Brine Company, LLC (“Texas Brine”), the operator of a failed cavern in the area and its insurers, seeking recovery for these losses. We have also sued Occidental Chemical Company and Legacy Vulcan Corp. f/k/a Vulcan Materials Company, two Chlor-Alkali plant operators that participated in Texas Brine’s operational decisions regarding the mining of the failed cavern. We also filed a claim with our insurers, which our insurers denied. We disputed the denial and have also sued our insurers. In August 2014, we received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million, but additional claims remain outstanding. We cannot give assurance that we will be able to fully recover our losses through insurance recovery or claims against responsible parties.
In June 2014, a group of landowners in Assumption Parish, Louisiana added our subsidiary, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the Bayou Corne sinkhole. 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 our costs and legal exposure, if any, related to the lawsuit are not currently determinable. We intend to vigorously defend the case. We have also filed a claim for defense and indemnity with its insurers.
Segment Information
Segment Information
(14) Segment Information
Identification of the majority of our operating segments is based principally upon geographic regions served. Our 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 west Texas, south Texas, Louisiana and Ohio River Valley (“Crude and Condensate”). Operating activity for intersegment eliminations is shown in the corporate segment. Our sales are derived from external domestic customers.
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 unconsolidated affiliate investments in HEP and GCF. We evaluate the performance of our operating segments based on operating revenues and segment profits.
Summarized financial information concerning our reportable segments is shown in the following tables:
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
 
(In millions)
Three Months Ended March 31, 2016
 

 
 

 
 

 
 

 
 

 
 

Product sales
$
62.5

 
$
287.7

 
$
7.8

 
$
230.5

 
$
—

 
$
588.5

Product sales-affiliates
37.3

 
7.4

 
10.6

 
0.2

 
(31.0
)
 
24.5

Midstream services
27.4

 
55.2

 
15.1

 
16.8

 
—

 
114.5

Midstream services-affiliates
110.3

 
12.7

 
45.0

 
5.2

 
(10.6
)
 
162.6

Cost of sales
(91.3
)
 
(302.1
)
 
(19.3
)
 
(215.1
)
 
41.6

 
(586.2
)
Operating expenses
(39.3
)
 
(23.3
)
 
(12.8
)
 
(22.8
)
 
—

 
(98.2
)
Loss on derivative activity
—

 
—

 
—

 
—

 
(0.4
)
 
(0.4
)
Segment profit
$
106.9

 
$
37.6

 
$
46.4

 
$
14.8

 
$
(0.4
)
 
$
205.3

Depreciation and amortization
$
(46.2
)
 
$
(29.3
)
 
$
(33.8
)
 
$
(10.4
)
 
$
(2.2
)
 
$
(121.9
)
Impairments
$
(473.1
)
 
$
—

 
$
—

 
$
(93.2
)
 
$
—

 
$
(566.3
)
Goodwill
$
230.4

 
$
—

 
$
190.3

 
$
—

 
$
—

 
$
420.7

Capital expenditures
$
23.3

 
$
22.7

 
$
69.2

 
$
3.3

 
$
1.9

 
$
120.4

 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
49.8

 
$
372.2

 
$
—

 
$
248.7

 
$
—

 
$
670.7

Product sales-affiliates
25.9

 
7.1

 
3.7

 
—

 
(20.5
)
 
16.2

Midstream services
19.6

 
57.9

 
10.7

 
14.2

 
—

 
102.4

Midstream services-affiliates
115.5

 
0.1

 
31.2

 
4.2

 
—

 
151.0

Cost of sales
(67.2
)
 
(370.9
)
 
(5.1
)
 
(234.7
)
 
20.5

 
(657.4
)
Operating expenses
(47.0
)
 
(24.3
)
 
(7.0
)
 
(20.1
)
 
—

 
(98.4
)
Gain on derivative activity
—

 
—

 
—

 
—

 
0.2

 
0.2

Segment profit
$
96.6

 
$
42.1

 
$
33.5

 
$
12.3

 
$
0.2

 
$
184.7

Depreciation and amortization
$
(36.4
)
 
$
(27.5
)
 
$
(13.5
)
 
$
(12.4
)
 
$
(1.5
)
 
$
(91.3
)
Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
137.8

 
$
—

 
$
2,283.1

Capital expenditures
$
73.5

 
$
15.2

 
$
5.2

 
$
77.6

 
$
4.2

 
$
175.7



The table below presents information about segment assets as of March 31, 2016 and December 31, 2015:
 
March 31,
 2016
 
December 31,
2015
Segment Identifiable Assets:
(In millions)
Texas
$
3,175.4

 
$
3,709.5

Louisiana
2,290.6

 
2,309.3

Oklahoma
2,380.7

 
873.4

Crude and Condensate
798.1

 
898.0

Corporate
299.7

 
302.6

Total identifiable assets
$
8,944.5

 
$
8,092.8


The following table reconciles the segment profits reported above to the operating income (loss) as reported in the Condensed Consolidated Statements of Operations (in millions):

Three Months Ended
March 31,
 
2016
 
2015
Segment profits
$
205.3

 
$
184.7

General and administrative expenses
(33.2
)
 
(41.9
)
Gain on disposition of assets
0.2

 
—

Depreciation and amortization
(121.9
)
 
(91.3
)
Impairments
(566.3
)
 
—

Operating income (loss)
$
(515.9
)
 
$
51.5

Supplemental Cash Flow Information (Notes)
Cash Flow, Supplemental Disclosures
(15) Supplemental Cash Flow Information
The following schedule summarizes non-cash financing activities for the period presented:
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
Non-cash financing activities:
 
(In millions)
Installment payable, net of discount of $79.1 million (1)
 
$
420.9

 
$
—

Non-cash issuance of common units (2)
 
—

 
180.0

Non-cash issuance of Class C Common Units (2)
 
—

 
180.0

Contribution from ENLC (3)
 
237.1

 
—

Non-cash adjustment of interest in Midstream Holdings (4)
 
—

 
20.9


(1) We incurred installment purchase obligations, net of discount assuming payments of $250.0 million are made on January 7, 2017 and 2018, payable to the seller in connection with the Tall Oak acquisition. See Note 3 - Acquisitions for further discussion.
(2) Non-cash common units and Class C Common Units were issued as partial consideration for the Coronado acquisition.
(3) Contribution from ENLC in connection with the acquisition of Tall Oak. See Note 3 - Acquisitions for further discussion.
(4) Non-cash adjustment to reflect recast of the interests in EnLink Midstream Holdings, LP (“Midstream Holdings”) acquired on February 17, 2015.
Other Information (Notes)
Other Liabilities Disclosure [Text Block]
(16) Other Information
The following table presents additional detail for certain balance sheet captions.
Other Current Liabilities
Other current liabilities consisted of the following:
 
March 31, 2016
 
December 31, 2015
 
(in millions)
Accrued interest
$
53.3

 
$
23.2

Accrued wages and benefits, including taxes
7.5

 
27.7

Accrued ad valorem taxes
12.5

 
27.0

Capital expenditure accruals
32.0

 
22.3

Onerous performance obligations
16.6

 
17.0

Other
65.3

 
57.2

Other current liabilities
$
187.2

 
$
174.4

Significant Accounting Policy (Policies)
Basis of Accounting, Policy [Policy Text Block] 
(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 (“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.
During the first half of 2015, we acquired assets from ENLC and Devon through drop down transactions. Due to ENLC's control of us through its ownership and control of our general partner and Devon's control of us through its ownership of the managing member of ENLC, each acquisition from ENLC and Devon was considered a transfer of net assets between entities under common control. As such, we were required to recast our historical financial statements to include the activities of such assets from the date that these entities were under common control. The condensed consolidated financial statements for periods prior to our acquisition of the assets from ENLC and Devon have been prepared from ENLC’s and Devon's historical cost-basis accounts for the acquired assets and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from ENLC and Devon for periods prior to our acquisition is allocated to our general partner.
New Accounting Pronouncements, Policy [Policy Text Block] 
(b) Recent Accounting Pronouncements
In January 2016, we adopted ASU 2015-03, Interest - Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability and requires retrospective application.  The application of this new accounting guidance resulted in the reclassification of $23.0 million of debt issuance costs from “Other Assets, Net” to “Long-term debt” in our accompanying Condensed Consolidated Balance Sheet as of December 31, 2015.
In January 2016, we adopted ASU 2015-17, Balance Sheet Classification of Deferred Taxes on a prospective basis. This new standard required that deferred tax assets and liabilities be classified as noncurrent in our Condensed Consolidated Balance Sheet as of March 31, 2016.
In January 2016, we adopted ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated.
In January 2016, we adopted ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This update has no impact on our condensed consolidated financial statements or related disclosures.
In January 2016, we adopted ASU No. 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a Consensus of the FASB Emerging Issues Task Force) (“ASU 2015-06”), which requires a master limited partnership (MLP) to allocate earnings (losses) of a transferred business entirely to the general partner when computing earnings per unit (EPU) for periods before the dropdown transaction occurred. The EPU that the limited partners previously reported would not change as a result of the dropdown transaction. ASU 2015-06 also requires an MLP to disclose the effects of the dropdown transaction on EPU for the periods before and after the dropdown transaction occurred. ASU 2015-06 is effective for the fiscal years beginning after December 15, 2015, and interim periods within those annual periods. ASU 2015-06 requires retrospective application and early adoption is permitted. The update is effective for us beginning on January 1, 2016 and had no impact on our condensed consolidated financial statements and related disclosures.
In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which amends ASC Topic 718, Compensation – Stock Compensation (“ASU 2016-09”). First, the new standard will require all of the tax effects related to share-based payments at settlement (or expiration) to be recorded through the income statement, and is required to be applied prospectively. Second, the new standard also allows entities to withhold taxes of an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in liability classification of the award, and is required to be adopted using a modified retrospective approach. Third, under the ASU, forfeitures can be estimated, as currently required, or recognized when they occur. If elected, the change to recognize forfeitures when they occur must be adopted using a modified retrospective approach. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016 including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.
In March 2016, the FASB issued ASU 2016-08, Principal versus Agent Considerations (“ASU 2016-08”). The new standard retained the guidance that the principal in an arrangement controls a good or service before it is transferred to a customer, and revised and clarified the indicators to evaluate when making this determination. ASU 2016-08 has the same effective date and transition requirements as the new revenue standard, which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods. Early application is permitted for annual reporting periods beginning after December 15, 2016. The update will have no impact on our condensed consolidated financial statements or related disclosures.
In March 2016, the FASB issued ASU 2016-07, Simplifying the Transition to the Equity Method of Accounting (“ASU 2016-07”). The new standard eliminates the requirement to apply the equity method of accounting retrospectively when a reporting entity obtains significant influence over a previously held investment. Investors should add the cost of acquiring the additional interest in the investee (if any) to the current basis of their previously held interest. ASU 2016-07 is effective for annual reporting periods beginning after December 15, 2016 including interim periods within those annual periods. Early adoption is permitted. We do not expect this standard to impact our condensed consolidated financial statements and related disclosures.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) - Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on the balance sheet, by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018 including interim periods within those annual periods. Early adoption is permitted, and is required to be adopted using a modified retrospective transition. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.
In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). Under this new standard, the FASB issued new guidance related to accounting for unconsolidated affiliate investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. ASU 2016-01 is effective for annual reporting periods beginning after December 15, 2017 including interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for transferring goods or services to a customer. The new standard will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Partnership'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, 2017, including interim periods within that reporting period, and is to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the pronouncement will have on our condensed consolidated financial statements and related disclosures.
Acquisition (Table)
BusinessAcquisitionProFormaInformation 
The following unaudited pro forma condensed financial information for the three months ended March 31, 2015 gives effect to the January 2015 LPC acquisition, March 2015 Coronado acquisition, October 2015 Matador acquisition, November 2015 Deadwood acquisition and January 2016 Tall Oak acquisition as if they had occurred on January 1, 2015. 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. Pro forma financial information associated with the acquisitions is reflected below.
 
 
Three Months Ended
March 31,
 
 
2015
 
 
(in millions)

Pro forma total revenues
 
$
1,067.6

Pro forma net income
 
$
10.8

Pro forma net income attributable to EnLink Midstream Partners, LP
 
$
14.0

Pro forma net income (loss) per common unit:
 
 
Basic
 
$
(0.14
)
Diluted
 
$
(0.14
)
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed 
The following table presents the consideration we paid and the fair value of the identified assets received and liabilities assumed at the acquisition date. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change.
Consideration (in millions):
 
 
Cash
 
$
783.9

Total installment payable, net of discount of $79.1 million assuming payments are made on January 7, 2017 and 2018
 
420.9

Contribution from ENLC
 
237.1

Total consideration
 
$
1,441.9

 
 

Purchase Price Allocation (in millions):
 


Assets acquired:
 
 
Current assets (including $6.8 million in cash)
 
$
20.2

Property, plant and equipment
 
423.2

Intangibles
 
1,034.3

Liabilities assumed:
 
 
Current liabilities
 
(35.8
)
Total identifiable net assets
 
$
1,441.9

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed 
The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change.
Purchase Price Allocation (in millions):
 
 
Assets acquired:
 
 
Current assets
 
$
1.1

Property, plant and equipment
 
36.2

Intangibles
 
98.8

Goodwill
 
9.1

Liabilities assumed:
 
 
Current liabilities
 
(3.9
)
Total identifiable net assets
 
$
141.3

Goodwill and Intangible Assets (Tables)
Schedule of Goodwill 
The table below provides a summary of our change in carrying amount of goodwill, by assigned reporting unit (in millions):
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
Three Months Ended March 31, 2016
 
 
 
 
 
 
 
 
 
 
 
Balance, beginning of period
$
703.5

 
$
—

 
$
190.3

 
$
93.2

 
$
—

 
$
987.0

Impairment
(473.1
)
 
—

 
—

 
(93.2
)
 
—

 
(566.3
)
Balance, end of period
$
230.4

 
$
—


$
190.3


$
—


$
—

 
$
420.7

Schedule of Finite-Lived Intangible Assets 
The following table represents our change in carrying value of intangible assets (in millions):
 
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
Carrying
Amount
Three Months Ended March 31, 2016
 
 
 
 
 
 
Customer relationships, beginning of period
 
$
744.5

 
$
(54.6
)
 
$
689.9

Acquisitions
 
1,034.3

 
—

 
1,034.3

Amortization expense
 
—

 
(27.5
)
 
(27.5
)
Customer relationships, end of period
 
$
1,778.8

 
$
(82.1
)
 
$
1,696.7

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense 
The following table summarizes our estimated aggregate amortization expense for the next five years (in millions):
2016 (remaining)
$
86.3

2017
115.1

2018
115.1

2019
115.1

2020
115.1

Thereafter
1,150.0

Total
$
1,696.7

Long-Term Debt (Tables)
Indebtedness Table
As of March 31, 2016 and December 31, 2015, long-term debt consisted of the following (in millions):
 
March 31,
2016
 
December 31,
2015
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at March 31, 2016 and December 31, 2015 was 2.2% and 1.8%, respectively
$
543.0

 
$
414.0

Senior unsecured notes (due 2019), net of discount of $0.4 million at March 31, 2016 and $0.4 million at December 31, 2015, which bear interest at the rate of 2.70%
399.6

 
399.6

Senior unsecured notes (due 2022), including a premium of $18.2 million at March 31, 2016 and $18.9 million at December 31, 2015, which bear interest at the rate of 7.125%
180.7

 
181.4

Senior unsecured notes (due 2024), net of premium of $2.8 million at March 31, 2016 and $2.9 million at December 31, 2015, which bear interest at the rate of 4.40%
552.8

 
552.9

Senior unsecured notes (due 2025), net of discount of $1.2 million at March 31, 2016 and $1.2 million at December 31, 2015, which bear interest at the rate of 4.15%
748.8

 
748.8

Senior unsecured notes (due 2044), net of discount of $0.3 million at March 31, 2016 and $0.2 million at December 31, 2015, which bear interest at the rate of 5.60%
349.7

 
349.8

Senior unsecured notes (due 2045), net of discount of $6.8 million at March 31, 2016 and $6.9 million at December 31, 2015, which bear interest at the rate of 5.05%
443.2

 
443.1

Debt issuance cost, net of amortization of $5.5 million at March 31, 2016 and $4.7 million at December 31, 2015
(22.4
)
 
(23.0
)
Other debt
0.2

 
0.2

Debt classified as long-term
$
3,195.6

 
$
3,066.8

Partners' Capital (Tables)
Distributions Made to Limited Partner, by Distribution 
A summary of the distribution activity relating to the common units for the three months ended March 31, 2016 is provided below:
Declaration period
 
Distribution/unit
 
Date paid/payable
Fourth Quarter of 2015
 
$
0.39

 
February 11, 2016
First Quarter of 2016
 
$
0.39

 
May 12, 2016
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 period presented (in millions, except per unit amounts):
 
Three Months Ended
March 31,
 
2016
 
2015
Limited partners’ interest in net income (loss)
$
(567.2
)
 
$
9.0

Distributed earnings allocated to:
 
 
 
Common units (1)
$
126.9

 
$
99.5

Unvested restricted units (1)
0.8

 
0.4

Total distributed earnings
$
127.7

 
$
99.9

Undistributed loss allocated to:
 
 
 
Common units
$
(690.7
)
 
$
(90.5
)
Unvested restricted units
(4.2
)
 
(0.4
)
Total undistributed loss
$
(694.9
)
 
$
(90.9
)
Net income (loss) allocated to:
 
 
 
Common units
$
(563.8
)
 
$
9.0

Unvested restricted units
(3.4
)
 
—

Total limited partners’ interest in net income (loss)
$
(567.2
)
 
$
9.0

Basic and diluted net income (loss) per unit:
 
 
 
Basic
$
(1.74
)
 
$
0.03

Diluted
$
(1.74
)
 
$
0.03


(1)
Three months ended March 31, 2016 and 2015 represents a declared distribution of $0.39 per unit payable on May 12, 2016 and a distribution of $0.38 per unit paid on May 14, 2015, respectively.

 
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 periods presented (in millions):
 
Three Months Ended
March 31,
 
2016
 
2015
Basic weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
325.2

 
261.8

Weighted average Class C Common Units outstanding
7.2

 
1.1

    Total weighted average limited partner common units outstanding
332.4

 
262.9

Diluted weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
332.4

 
262.9

Dilutive effect of restricted units issued
—

 
0.4

    Total weighted average limited partner diluted common units outstanding
332.4

 
263.3

Incentive Distributions 
The net income allocated to our general partner is as follows for the periods presented (in millions):
 
Three Months Ended
March 31,
 
2016
 
2015
Income allocation for incentive distributions
$
13.8

 
$
8.8

Unit-based compensation attributable to ENLC’s restricted units
(4.0
)
 
(7.0
)
General partner share of net income (loss)
(2.4
)
 
0.1

General partner interest in drop down transactions
—

 
24.6

General partner interest in net income
$
7.4

 
$
26.5

Asset Retirement Obligation (Table)
Schedule of Change in Asset Retirement Obligation
The schedule below summarizes the changes in our asset retirement obligation:
 
Three Months Ended
March 31,
 
2016
 
2015
 
(in millions)
Beginning asset retirement obligations
$
14.0

 
$
20.6

Revisions to existing liabilities
(0.4
)
 
(3.9
)
Accretion
0.1

 
0.1

Liabilities settled
(0.6
)
 
(3.2
)
Ending asset retirement obligations
$
13.1

 
$
13.6

Investment in Unconsolidated Affiliate (Tables)
Equity Method Investments
The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):
 
Gulf Coast Fractionators
 
Howard Energy Partners
 
Total
Three months ended
 
 
 
 
 
March 31, 2016
 
 
 
 
 
Contributions
$
—

 
$
7.1

 
$
7.1

Distributions
$
3.0

 
$
6.2

 
$
9.2

Equity in net loss
$
(1.7
)
 
$
(0.7
)
 
$
(2.4
)
 
 
 
 
 
 
March 31, 2015
 
 
 
 
 
Distributions
$
2.7

 
$
4.1

 
$
6.8

Equity in net income
$
3.3

 
$
0.4

 
$
3.7

The following table shows the balances related to our investment in unconsolidated affiliates for the periods indicated (in millions):
 
March 31,
2016
 
December 31,
2015
Gulf Coast Fractionators
$
47.9

 
$
52.6

Howard Energy Partners
221.9

 
221.7

Total investment in unconsolidated affiliates
$
269.8

 
$
274.3

Employee Incentive Plan (Tables)
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block] 
The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:
EnLink Midstream Partners, LP Performance Units:
 
January 2016
 
February 2016
Beginning TSR Price
 
$
14.82

 
$
14.82

Risk-free interest rate
 
1.10
%
 
0.89
%
Volatility factor
 
39.71
%
 
42.33
%
Distribution yield
 
12.10
%
 
19.20
%
The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:
EnLink Midstream, LLC Performance Units:
 
January 2016
 
February 2016
Beginning TSR Price
 
$
15.38

 
$
15.38

Risk-free interest rate
 
1.10
%
 
0.89
%
Volatility factor
 
46.02
%
 
52.05
%
Distribution yield
 
8.60
%
 
14.00
%
Schedule of Nonvested Performance-based Units Activity [Table Text Block] 
The following table presents a summary of the ENLC's performance units:
 
 
Three Months Ended 
March 31, 2016
EnLink Midstream, LLC Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
105,080

 
$
40.50

Granted
 
242,646

 
9.59

Forfeited
 
(2,525
)
 
41.31

Non-vested, end of period
 
345,201

 
$
18.76

Aggregate intrinsic value, end of period (in millions)
 
$
3.9

 

The following table presents a summary of our performance units:
 
 
Three Months Ended 
March 31, 2016
EnLink Midstream Partners, LP Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
118,126

 
$
35.41

Granted
 
258,078

 
9.81

Forfeited
 
(2,798
)
 
36.18

Non-vested, end of period
 
373,406

 
$
17.71

Aggregate intrinsic value, end of period (in millions)
 
$
4.5

 

ScheduleofShareBasedCompensationRestrictedStockandRestrictedStockUnitsVestedandFairValueVested 
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three months ended March 31, 2016 and 2015 are provided below (in millions):

 
Three Months Ended
March 31,
EnLink Midstream Partners, LP Restricted Incentive Units:
 
2016

2015
Aggregate intrinsic value of units vested
 
$
3.7


$
6.8

Fair value of units vested
 
$
9.0


$
7.0

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three months ended March 31, 2016 and 2015 are provided below (in millions):
 
 
Three Months Ended
March 31,
EnLink Midstream, LLC Restricted Incentive Units:
 
2016
 
2015
Aggregate intrinsic value of units vested
 
$
3.8

 
$
8.3

Fair value of units vested
 
$
11.8

 
$
8.6

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs 
We and ENLC each have similar unit-based compensation payment plans for officers and employees, which are described below.  Unit-based compensation associated with ENLC's unit-based compensation plan awarded to our officers and employees is recorded by us since ENLC has no substantial or managed operating activities other than its interests in us and TOM. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions): 
 
Three Months Ended
March 31,
 
2016
 
2015
Cost of unit-based compensation charged to general and administrative expense
$
6.2

 
$
11.9

Cost of unit-based compensation charged to operating expense
1.7

 
1.9

    Total amount charged to income
$
7.9

 
$
13.8

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity 
A summary of the restricted incentive unit activity for the three months ended March 31, 2016 is provided below:
 
 
Three Months Ended
March 31, 2016
EnLink Midstream Partners, LP Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-vested, beginning of period
 
1,253,729

 
$
29.59

Granted
 
1,041,022

 
10.01

Vested*
 
(294,460
)
 
30.40

Forfeited
 
(27,797
)
 
24.12

Non-vested, end of period
 
1,972,494

 
$
19.21

Aggregate intrinsic value, end of period (in millions)
 
$
23.8

 
 


 * Vested units include 84,429 units withheld for payroll taxes paid on behalf of employees.
A summary of the restricted incentive unit activity for the three months ended March 31, 2016 is provided below:
 
 
Three Months Ended 
March 31, 2016
EnLink Midstream, LLC Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-vested, beginning of period
 
1,148,893

 
$
34.78

Granted
 
1,032,976

 
9.42

Vested*
 
(317,726
)
 
37.03

Forfeited
 
(24,970
)
 
26.85

Non-vested, end of period
 
1,839,173

 
$
20.26

Aggregate intrinsic value, end of period (in millions)
 
$
20.7

 
 


* Vested units include 90,326 units withheld for payroll taxes paid on behalf of employees.
Derivatives (Tables)
Commodity Swap 
The components of gain (loss) on derivative activity in the Condensed Consolidated Statements of Operations relating to commodity swaps are (in millions):
 
Three Months Ended
March 31,
 
2016
 
2015
Change in fair value of derivatives
$
(6.0
)
 
$
(3.7
)
Realized gain on derivatives
5.6

 
3.9

    Gain (loss) on derivative activity
$
(0.4
)
 
$
0.2

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):
 
March 31,
2016
 
December 31,
2015
Fair value of derivative assets — current
$
10.5

 
$
16.8

Fair value of derivative liabilities — current
(3.2
)
 
(2.9
)
Fair value of derivative liabilities — long term
—

 
(0.1
)
    Net fair value of derivatives
$
7.3

 
$
13.8

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 March 31, 2016. The remaining term of the contracts extend no later than March 2017.
 
 
 
 
 
 
March 31, 2016
Commodity
 
Instruments
 
Unit
 
Volume
 
Fair Value
 
 
 
 
 
 
(In millions)
NGL (short contracts)
 
Swaps
 
Gallons
 
(42.9
)
 
$
8.8

NGL (long contracts)
 
Swaps
 
Gallons
 
17.1

 
(1.8
)
Natural Gas (short contracts)
 
Swaps
 
MMBtu
 
(6.7
)
 
0.8

Natural Gas (long contracts)
 
Swaps
 
MMBtu
 
2.2

 
(0.3
)
Condensate (short contracts)
 
Swaps
 
MMBbls
 
(0.1
)
 
(0.2
)
Total fair value of derivatives
 
 
 
 
 
 
 
$
7.3

Fair Value Measurements (Tables)
Fair Value Derivative Instrument 
Net liabilities measured at fair value on a recurring basis are summarized below (in millions):
 
March 31, 2016
Level 2
 
December 31, 2015
Level 2
Commodity Swaps*
$
7.3

 
$
13.8

Total
$
7.3

 
$
13.8

 
*               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 our and/or the counterparty credit risk 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 we could realize upon the sale or refinancing of such financial instruments (in millions):
 
March 31, 2016
 
December 31, 2015
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Long-term debt
$
3,195.6

 
$
2,629.0

 
$
3,066.8

 
$
2,585.5

Obligations under capital leases
$
13.4

 
$
12.7

 
$
16.7

 
$
15.6

Segement Information (Tables)
Partnership Reportable Segement 
Summarized financial information concerning our reportable segments is shown in the following tables:
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
 
(In millions)
Three Months Ended March 31, 2016
 

 
 

 
 

 
 

 
 

 
 

Product sales
$
62.5

 
$
287.7

 
$
7.8

 
$
230.5

 
$
—

 
$
588.5

Product sales-affiliates
37.3

 
7.4

 
10.6

 
0.2

 
(31.0
)
 
24.5

Midstream services
27.4

 
55.2

 
15.1

 
16.8

 
—

 
114.5

Midstream services-affiliates
110.3

 
12.7

 
45.0

 
5.2

 
(10.6
)
 
162.6

Cost of sales
(91.3
)
 
(302.1
)
 
(19.3
)
 
(215.1
)
 
41.6

 
(586.2
)
Operating expenses
(39.3
)
 
(23.3
)
 
(12.8
)
 
(22.8
)
 
—

 
(98.2
)
Loss on derivative activity
—

 
—

 
—

 
—

 
(0.4
)
 
(0.4
)
Segment profit
$
106.9

 
$
37.6

 
$
46.4

 
$
14.8

 
$
(0.4
)
 
$
205.3

Depreciation and amortization
$
(46.2
)
 
$
(29.3
)
 
$
(33.8
)
 
$
(10.4
)
 
$
(2.2
)
 
$
(121.9
)
Impairments
$
(473.1
)
 
$
—

 
$
—

 
$
(93.2
)
 
$
—

 
$
(566.3
)
Goodwill
$
230.4

 
$
—

 
$
190.3

 
$
—

 
$
—

 
$
420.7

Capital expenditures
$
23.3

 
$
22.7

 
$
69.2

 
$
3.3

 
$
1.9

 
$
120.4

 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
49.8

 
$
372.2

 
$
—

 
$
248.7

 
$
—

 
$
670.7

Product sales-affiliates
25.9

 
7.1

 
3.7

 
—

 
(20.5
)
 
16.2

Midstream services
19.6

 
57.9

 
10.7

 
14.2

 
—

 
102.4

Midstream services-affiliates
115.5

 
0.1

 
31.2

 
4.2

 
—

 
151.0

Cost of sales
(67.2
)
 
(370.9
)
 
(5.1
)
 
(234.7
)
 
20.5

 
(657.4
)
Operating expenses
(47.0
)
 
(24.3
)
 
(7.0
)
 
(20.1
)
 
—

 
(98.4
)
Gain on derivative activity
—

 
—

 
—

 
—

 
0.2

 
0.2

Segment profit
$
96.6

 
$
42.1

 
$
33.5

 
$
12.3

 
$
0.2

 
$
184.7

Depreciation and amortization
$
(36.4
)
 
$
(27.5
)
 
$
(13.5
)
 
$
(12.4
)
 
$
(1.5
)
 
$
(91.3
)
Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
137.8

 
$
—

 
$
2,283.1

Capital expenditures
$
73.5

 
$
15.2

 
$
5.2

 
$
77.6

 
$
4.2

 
$
175.7

Segment Table reconciliation to Condensed Consolidated Financial Statement 
The table below presents information about segment assets as of March 31, 2016 and December 31, 2015:
 
March 31,
 2016
 
December 31,
2015
Segment Identifiable Assets:
(In millions)
Texas
$
3,175.4

 
$
3,709.5

Louisiana
2,290.6

 
2,309.3

Oklahoma
2,380.7

 
873.4

Crude and Condensate
798.1

 
898.0

Corporate
299.7

 
302.6

Total identifiable assets
$
8,944.5

 
$
8,092.8

Reconciliation of Operating Profit (Loss) from Segments to Consolidated Financial Statement 
The following table reconciles the segment profits reported above to the operating income (loss) as reported in the Condensed Consolidated Statements of Operations (in millions):

Three Months Ended
March 31,
 
2016
 
2015
Segment profits
$
205.3

 
$
184.7

General and administrative expenses
(33.2
)
 
(41.9
)
Gain on disposition of assets
0.2

 
—

Depreciation and amortization
(121.9
)
 
(91.3
)
Impairments
(566.3
)
 
—

Operating income (loss)
$
(515.9
)
 
$
51.5

Supplemental Cash Flow Information (Tables)
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]
The following schedule summarizes non-cash financing activities for the period presented:
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
Non-cash financing activities:
 
(In millions)
Installment payable, net of discount of $79.1 million (1)
 
$
420.9

 
$
—

Non-cash issuance of common units (2)
 
—

 
180.0

Non-cash issuance of Class C Common Units (2)
 
—

 
180.0

Contribution from ENLC (3)
 
237.1

 
—

Non-cash adjustment of interest in Midstream Holdings (4)
 
—

 
20.9


(1) We incurred installment purchase obligations, net of discount assuming payments of $250.0 million are made on January 7, 2017 and 2018, payable to the seller in connection with the Tall Oak acquisition. See Note 3 - Acquisitions for further discussion.
(2) Non-cash common units and Class C Common Units were issued as partial consideration for the Coronado acquisition.
(3) Contribution from ENLC in connection with the acquisition of Tall Oak. See Note 3 - Acquisitions for further discussion.
(4) Non-cash adjustment to reflect recast of the interests in EnLink Midstream Holdings, LP (“Midstream Holdings”) acquired on February 17, 2015.
Other Information (Tables)
Other Current Liabilities [Table Text Block]
Other current liabilities consisted of the following:
 
March 31, 2016
 
December 31, 2015
 
(in millions)
Accrued interest
$
53.3

 
$
23.2

Accrued wages and benefits, including taxes
7.5

 
27.7

Accrued ad valorem taxes
12.5

 
27.0

Capital expenditure accruals
32.0

 
22.3

Onerous performance obligations
16.6

 
17.0

Other
65.3

 
57.2

Other current liabilities
$
187.2

 
$
174.4

General (Details)
3 Months Ended
Mar. 31, 2016
Jan. 7, 2016
Tall Oak [Member]
ENLC [Member]
Jan. 7, 2016
Tall Oak [Member]
EnLink Midstream LP [Member]
Business Acquisition [Line Items]
 
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
16.00% 
84.00% 
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest
64.00% 
 
 
Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Accounting Policies [Abstract]
 
 
Deferred Finance Costs, Noncurrent, Net
$ 22.4 
$ 23.0 
Acquisition (Details Textuals) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended 3 Months Ended 0 Months Ended 0 Months Ended
Mar. 31, 2016
Oct. 1, 2015
Matador [Member]
Oct. 1, 2015
Matador [Member]
Nov. 16, 2015
Deadwood Acquisition [Member]
Nov. 16, 2015
Deadwood Acquisition [Member]
Jan. 7, 2016
Tall Oak [Member]
Mar. 31, 2016
Tall Oak [Member]
Jan. 7, 2016
Tall Oak [Member]
EnLink Midstream LP [Member]
Jan. 7, 2016
Tall Oak [Member]
ENLC [Member]
Jan. 7, 2016
Tall Oak [Member]
ENLC [Member]
Jan. 7, 2016
Tall Oak [Member]
EnLink Midstream Partners, LP [Member]
Jan. 7, 2016
Tall Oak [Member]
Common Units [Member]
ENLC [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Transaction Costs
 
 
 
 
 
 
$ 3.6 
 
 
 
 
 
Total Purchase Price
 
141.3 
 
40.1 
 
1,441.9 
 
 
 
 
 
 
BusinessCombinationFirstInstallment
 
 
 
 
 
1,020.0 
 
 
 
 
 
 
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual
 
 
 
 
 
 
27.3 
 
 
 
 
 
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual
 
 
 
 
 
 
14.2 
 
 
 
 
 
Finite-Lived Intangible Asset, Useful Life
14 years 0 months 
15 years 
 
 
 
15 years 
 
 
 
 
 
 
Business Combination, Consideration Transferred, Other
 
 
 
1.5 
 
 
 
 
 
 
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
 
100.00% 
 
50.00% 
 
 
84.00% 
 
16.00% 
 
 
Business Combination, Cash Consideration Transferred
 
 
 
 
 
 
 
 
22.0 
 
783.9 
 
Common Unit, Issued
 
 
 
 
 
 
 
 
 
 
 
15,564,009 
Business Combination, Total Installment Payable
 
 
 
 
 
$ 500.0 
 
 
 
 
 
 
Acquisition (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Mar. 31, 2015
Jan. 7, 2016
Tall Oak [Member]
Jan. 7, 2016
Tall Oak [Member]
Oct. 1, 2015
Matador [Member]
Oct. 1, 2015
Matador [Member]
Nov. 16, 2015
Deadwood Acquisition [Member]
Jan. 7, 2016
EnLink Midstream Partners, LP [Member]
Tall Oak [Member]
Jan. 7, 2016
ENLC [Member]
Tall Oak [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
Business Combination, Cash Consideration Transferred
 
 
 
 
 
 
 
 
$ 783.9 
$ 22.0 
Proceeds from Contributions from Parent
237.1 
 
 
 
 
 
 
 
 
237.1 
Total Purchase Price
 
 
 
1,441.9 
 
141.3 
 
40.1 
 
 
Assets acquired [Abstract]
 
 
 
 
 
 
 
 
 
 
Current Assets
 
 
 
 
20.2 
 
1.1 
 
 
 
Property, Plant, and Equipment
 
 
 
 
423.2 
 
36.2 
 
 
 
Goodwill
420.7 
987.0 
2,283.1 
 
 
 
9.1 
 
 
 
Intangibles
 
 
 
 
1,034.3 
 
98.8 
 
 
 
Liabilities assumed [Abstract]
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
 
 
 
(35.8)
 
(3.9)
 
 
 
Total Purchase Price
 
 
 
 
$ 1,441.9 
 
$ 141.3 
 
 
 
Acquisition (Proforma) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Business Acquisition [Line Items]
 
Pro forma total revenues
$ 1,067.6 
Pro forma net income
10.8 
Pro forma net income attributable to EnLink Midstream Partners, LP
$ 14.0 
Basic
$ (0.14)
Diluted
$ (0.14)
Acquisition (Phantom) (Details) (Tall Oak [Member], USD $)
In Millions, unless otherwise specified
0 Months Ended
Jan. 7, 2016
Mar. 31, 2016
Jan. 7, 2016
Tall Oak [Member]
 
 
 
Business Acquisition [Line Items]
 
 
 
Cash Acquired from Acquisition
$ 6.8 
 
 
Debt Instrument, Unamortized Discount (Premium), Net
 
$ 79.1 
$ 79.1 
Goodwill and Intangible Assets (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Mar. 31, 2015
Goodwill [Line Items]
 
 
 
Goodwill
$ 420.7 
$ 987.0 
$ 2,283.1 
Goodwill, Impairment Loss
(566.3)
 
 
Texas Operating Segment [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Goodwill
230.4 
703.5 
1,168.2 
Goodwill, Impairment Loss
(473.1)
 
 
Louisiana Operating Segment [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Goodwill
0 
0 
786.8 
Goodwill, Impairment Loss
0 
 
 
Oklahoma Operating Segment [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Goodwill
190.3 
190.3 
190.3 
Goodwill, Impairment Loss
0 
 
 
Crude And Condensate Segment [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Goodwill
0 
93.2 
137.8 
Goodwill, Impairment Loss
(93.2)
 
 
Corporate Segment [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Goodwill
0 
0 
0 
Goodwill, Impairment Loss
$ 0 
 
 
Goodwill and Intangible Assets (Intangible Asset by Major Class) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Dec. 31, 2015
Acquired Finite-Lived Intangible Assets [Line Items]
 
 
 
Finite-Lived Intangible Asset, Useful Life
14 years 0 months 
 
 
Finite-Lived Intangible Assets, Gross
$ 1,778.8 
 
$ 744.5 
Finite-Lived Intangible Assets, Accumulated Amortization
(82.1)
 
(54.6)
Finite-Lived Intangible Assets, Net
1,696.7 
 
689.9 
Finite-Lived Intangibles Assets Acquired
1,034.3 
 
 
Amortization of Intangible Assets
$ (27.5)
$ (11.5)
 
Minimum [Member]
 
 
 
Acquired Finite-Lived Intangible Assets [Line Items]
 
 
 
Finite-Lived Intangible Asset, Useful Life
10 years 
 
 
Maximum [Member]
 
 
 
Acquired Finite-Lived Intangible Assets [Line Items]
 
 
 
Finite-Lived Intangible Asset, Useful Life
20 years 
 
 
Goodwill and Intangible Assets (Amortization Expense Table) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Finite-Lived Intangibles Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
 
 
Finite-Lived Intangible Assets, Amortization Expense, Remainder of Fiscal Year
$ 86.3 
 
2017
115.1 
 
2018
115.1 
 
2019
115.1 
 
2020
115.1 
 
Thereafter
1,150.0 
 
Total
$ 1,696.7 
$ 689.9 
Affiliate Transactions (Textual) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 3 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Mar. 31, 2016
Devon Energy Corporation [Member]
Mar. 31, 2015
Devon Energy Corporation [Member]
Dec. 31, 2015
Devon Energy Corporation [Member]
Mar. 31, 2016
Devon Energy Production Company [Member]
Related Party Transaction [Line Items]
 
 
 
 
 
 
Concentration Risk, Percentage
 
 
21.00% 
17.80% 
 
 
Due from Affiliate, Current
 
 
$ 88.3 
 
$ 110.8 
 
Accounts payable to related party
$ 22.8 
$ 14.8 
$ 22.8 
 
$ 14.8 
 
Minimum Volume Commitment
 
 
 
 
 
5 years 
Term Of Contract
 
 
 
 
 
13 years 
Long-Term Debt (Indebtedness Table) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Amount Outstanding
$ 543.0 
$ 414.0 
Deferred Finance Costs, Noncurrent, Net
(22.4)
(23.0)
Other Long-term Debt
0.2 
0.2 
Long-term Debt
3,195.6 
3,066.8 
2.7% Senior Notes due 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
399.6 
399.6 
7.125% Senior Notes due 2022 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
180.7 
181.4 
4.4% Senior Notes due 2024 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
552.8 
552.9 
4.15% Senior Notes due 2025 [Member] [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
748.8 
748.8 
5.6% Senior Notes due 2044 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
349.7 
349.8 
5.05% Senior Notes due 2045 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
$ 443.2 
$ 443.1 
Long-Term Debt (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
Other Long-term Debt
$ 0.2 
$ 0.2 
Line of Credit Facility, Maximum Borrowing Capacity
1,500.0 
 
Line Of Credit Facility, Additional Borrowing Limit
500.0 
 
Letters of Credit Outstanding, Amount
10.8 
 
Long-term Debt
3,195.6 
3,066.8 
Line of Credit Facility, Amount Outstanding
543.0 
414.0 
Line of Credit Facility, Remaining Borrowing Capacity
946.2 
 
Letter of Credit [Member]
 
 
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Maximum Borrowing Capacity
500.0 
 
Maximum [Member]
 
 
Debt Instrument [Line Items]
 
 
Leverage ratios
5.0 
 
Conditional acquisition purchase price
$ 50.0 
 
Revolving Credit Facility [Member] |
Maximum [Member]
 
 
Debt Instrument [Line Items]
 
 
Leverage ratios
5.5 
 
Long-Term Debt (Percentages Per Annum) (Details)
3 Months Ended
Mar. 31, 2016
Base Rate [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Interest Rate During Period
0.50% 
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Interest Rate During Period
1.00% 
Long-Term Debt (Details) (Line of Credit [Member])
3 Months Ended 12 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Line of Credit [Member]
 
 
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Interest Rate During Period
2.20% 
1.80% 
Long-Term Debt (Phantom - Interest Rates) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
Accumulated Amortization, Deferred Finance Costs
$ 5.5 
$ 4.7 
Line of Credit [Member]
 
 
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Interest Rate During Period
2.20% 
1.80% 
2.7% Senior Notes due 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior notes fixed interest rate
2.70% 
2.70% 
Debt Instrument, Unamortized Discount (Premium), Net
0.4 
0.4 
4.4% Senior Notes due 2024 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior notes fixed interest rate
4.40% 
4.40% 
Debt Instrument, Unamortized Discount (Premium), Net
(2.8)
(2.9)
5.6% Senior Notes due 2044 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior notes fixed interest rate
5.60% 
5.60% 
Debt Instrument, Unamortized Discount (Premium), Net
0.3 
0.2 
7.125% Senior Notes due 2022 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior notes fixed interest rate
7.125% 
7.125% 
Debt Instrument, Unamortized Discount (Premium), Net
(18.2)
(18.9)
5.05% Senior Notes due 2045 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior notes fixed interest rate
5.05% 
5.05% 
Debt Instrument, Unamortized Discount (Premium), Net
6.8 
6.9 
4.15% Senior Notes due 2025 [Member] [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior notes fixed interest rate
4.15% 
4.15% 
Debt Instrument, Unamortized Discount (Premium), Net
$ 1.2 
$ 1.2 
Partners' Capital (Details Textuals) (USD $)
In Millions, except Share data, unless otherwise specified
0 Months Ended 3 Months Ended 3 Months Ended 0 Months Ended 3 Months Ended
Jan. 7, 2016
Mar. 31, 2016
Dec. 31, 2015
Mar. 31, 2015
Jan. 7, 2016
Mar. 31, 2016
General Partner [Member]
Incentive Distribution Percentage, Level1 [Member]
Mar. 31, 2016
General Partner [Member]
Incentive Distribution Percentage, Level2 [Member]
Mar. 31, 2016
General Partner [Member]
Incentive Distribution Percentage, Level3 [Member]
Mar. 31, 2016
EDA [Member]
BMO Capital Markets Corp. [Member]
Nov. 30, 2014
EDA [Member]
BMO Capital Markets Corp. [Member]
Mar. 16, 2015
Common Class C [Member]
Mar. 31, 2016
Common Class C [Member]
Dec. 31, 2015
Common Class C [Member]
Mar. 31, 2016
Preferred Stock [Member]
Subsidiary Sale Of Stock [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AggregateAmountOfEquitySecuritiesAllowedUnderEquityDistributionAgreement
 
 
 
 
 
 
 
 
 
$ 350.0 
 
 
 
 
Percentage of avaliable cash to distribute
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Number of days from end of quarter for distribution
 
45 days 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Made to Limited Partner, Distribution Date
 
May 12, 2016 
Feb. 11, 2016 
 
 
 
 
 
 
 
 
 
 
 
Distribution Made to Limited Partner, Distributions Declared, Per Unit
 
$ 0.39 
$ 0.390 
$ 0.38 
 
 
 
 
 
 
 
$ 0.390 
 
 
Proceeds from issuance of common units
 
2.1 
 
2.2 
 
 
 
 
2.1 
 
 
 
 
 
Payments of Stock Issuance Costs
 
 
 
 
 
 
 
 
0.1 
 
 
 
 
 
AggregateAmountOfEquitySecurityRemainingUnderEquityDistributionAgreement
 
 
 
 
 
 
 
 
314.8 
 
 
 
 
 
Stock Issued During Period, Shares, Acquisitions
 
 
 
 
 
 
 
 
 
 
6,704,285 
 
 
 
Preferred Units, Issued
 
50,000,000 
0 
 
50,000,000 
 
 
 
 
 
 
 
 
 
Incentive Distribution Percentage Levels
 
 
 
 
 
13.00% 
23.00% 
48.00% 
 
 
 
 
 
 
Incentive Distribution, Distribution Per Unit
 
 
 
 
 
$ 0.25 
$ 0.3125 
$ 0.375 
 
 
 
 
 
 
Shares Issued, Price Per Share
 
 
 
 
$ 15.00 
 
 
 
 
 
 
 
 
 
Proceeds from issuance of preferred units
$ 724.5 
$ 724.5 
 
$ 0 
 
 
 
 
 
 
 
 
 
 
Preferred Stock, Conversion Basis
 
150.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Percent Of Issue Price
 
140.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Annual Rate On Issue Price Payable In-Kind
 
8.50% 
 
 
 
 
 
 
 
 
 
 
 
 
Annual Rate On Issue Price Payable In Cash
 
7.50% 
 
 
 
 
 
 
 
 
 
 
 
 
Annual Rate On Issue Price
 
1.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividends, Shares
 
 
 
 
 
 
 
 
 
 
 
233,107 
209,044 
992,445 
Issuance of common units
 
 
 
 
 
 
 
 
200,000 
 
 
 
 
50,000,000 
Partners' Capital (EPU Computation Schedule) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Capital Unit [Line Items]
 
 
Total distributed earnings
$ 127.7 
$ 99.9 
Limited partners’ interest in net income (loss)
(567.2)
9.0 
Total undistributed loss
(694.9)
(90.9)
Basic
$ (1.74)
$ 0.03 
Diluted
$ (1.74)
$ 0.03 
Common Unit [Member]
 
 
Capital Unit [Line Items]
 
 
Total distributed earnings
126.9 
99.5 
Limited partners’ interest in net income (loss)
(563.8)
9.0 
Total undistributed loss
(690.7)
(90.5)
Restricted Stock Units (RSUs) [Member]
 
 
Capital Unit [Line Items]
 
 
Total distributed earnings
0.8 
0.4 
Limited partners’ interest in net income (loss)
(3.4)
0 
Total undistributed loss
$ (4.2)
$ (0.4)
Partners' Capital (Weighted Average Schedule) (Details)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Class of Stock [Line Items]
 
 
Weighted Average Number of Shares Outstanding, Basic
332.4 
262.9 
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities
0 
0.4 
Weighted Average Number of Shares Outstanding, Diluted
332.4 
263.3 
Common Units [Member]
 
 
Class of Stock [Line Items]
 
 
Weighted Average Limited Partnership Units Outstanding, Basic
325.2 
261.8 
Common Class C [Member]
 
 
Class of Stock [Line Items]
 
 
Weighted Average Limited Partnership Units Outstanding, Basic
7.2 
1.1 
Partners' Capital (Allocated Net Income (loss) to the General Partner) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
General partner interest in net income
$ 7.4 
$ 26.5 
General Partner [Member]
 
 
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
Income allocation for incentive distributions
13.8 
8.8 
Unit-based compensation attributable to ENLC’s restricted units
(4.0)
(7.0)
General partner share of net income (loss)
(2.4)
0.1 
General partner interest in drop down transactions
$ 0 
$ 24.6 
Partners Capital (Issuance of Common Units) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
EDA [Member]
BMO Capital Markets Corp. [Member]
Nov. 30, 2014
EDA [Member]
BMO Capital Markets Corp. [Member]
Class of Stock [Line Items]
 
 
 
 
AggregateAmountOfEquitySecuritiesAllowedUnderEquityDistributionAgreement
 
 
 
$ 350.0 
Issuance of common units
 
 
0.2 
 
Proceeds from issuance of common units
2.1 
2.2 
2.1 
 
Payments of Stock Issuance Costs
 
 
0.1 
 
AggregateAmountOfEquitySecurityRemainingUnderEquityDistributionAgreement
 
 
$ 314.8 
 
Asset Retirement Obligation (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Dec. 31, 2015
Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
 
 
 
 
Asset Retirement Obligation
$ 13.1 
$ 13.6 
$ 14.0 
$ 20.6 
Asset Retirement Obligation, Revision of Estimate
(0.4)
(3.9)
 
 
Asset Retirement Obligation, Accretion Expense
0.1 
0.1 
 
 
Asset Retirement Obligation, Liabilities Settled
(0.6)
(3.2)
 
 
Asset Retirement Obligation, Current
$ 0 
$ 1.1 
 
 
Investment in Unconsolidated Affiliate (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
 
 
 
Contributions
$ 7.1 
 
 
Distributions
9.2 
6.8 
 
Equity in net income (loss)
(2.4)
3.7 
 
Investment in unconsolidated affiliates
269.8 
 
274.3 
Gulf Coast Fractionators [Member]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Contributions
0 
 
 
Distributions
3.0 
2.7 
 
Equity in net income (loss)
(1.7)
3.3 
 
Investment in unconsolidated affiliates
47.9 
 
52.6 
Equity Method Investment, Ownership Percentage
38.75% 
38.75% 
 
Howard Energy Partners [Member]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Contributions
7.1 
 
 
Distributions
6.2 
4.1 
 
Equity in net income (loss)
(0.7)
0.4 
 
Investment in unconsolidated affiliates
$ 221.9 
 
$ 221.7 
Equity Method Investment, Ownership Percentage
30.60% 
30.60% 
 
Investment in Unconsolidated Affiliates (Phantom) (Details)
Mar. 31, 2016
Mar. 31, 2015
Gulf Coast Fractionators [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investment, Ownership Percentage
38.75% 
38.75% 
Howard Energy Partners [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investment, Ownership Percentage
30.60% 
30.60% 
Employee Incentive Plan (Textuals) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 0 Months Ended
Mar. 31, 2016
Restricted Stock Units (RSUs) [Member]
ENLC Restricted Units [Member]
Mar. 31, 2016
EnLink Midstream Partners, LP [Member]
Performance Based Restricted Unit [Member]
Mar. 31, 2016
Enlink midstream, LLC [Member]
Performance Based Restricted Unit [Member]
Mar. 31, 2016
EnLink Midstream Partners, LP [Member]
Performance Based Restricted Unit [Member]
Mar. 31, 2016
EnLink Midstream Partners, LP [Member]
Restricted Stock Units (RSUs) [Member]
Mar. 31, 2016
Minimum [Member]
EnLink Midstream Partners, LP [Member]
Performance Based Restricted Unit [Member]
Mar. 31, 2016
Minimum [Member]
Enlink midstream, LLC [Member]
Performance Based Restricted Unit [Member]
Mar. 31, 2016
Maximum [Member]
EnLink Midstream Partners, LP [Member]
Performance Based Restricted Unit [Member]
Mar. 31, 2016
Maximum [Member]
Enlink midstream, LLC [Member]
Performance Based Restricted Unit [Member]
Apr. 7, 2016
Subsequent Event [Member]
Apr. 7, 2016
Subsequent Event [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized
 
 
 
 
 
 
 
 
 
5,000,000 
 
Unrecognized compensation cost related to non-vested restricted incentive units
$ 21.9 
 
$ 4.7 
$ 4.9 
$ 22.4 
 
 
 
 
 
 
Unrecognized compensation costs, weighted average period for recognition
1 year 11 months 
 
2 years 2 months 
2 years 2 months 
1 year 11 months 
 
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage
 
 
 
 
 
0.00% 
0.00% 
200.00% 
200.00% 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized
 
 
 
 
 
 
 
 
 
 
14,070,000 
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period
 
3 years 
3 years 
 
 
 
 
 
 
 
 
Employee Incentive Plan (Expense Schedule) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
Allocated Share-based Compensation Expense
$ 7.9 
$ 13.8 
General and Administrative Expense [Member]
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
Allocated Share-based Compensation Expense
6.2 
11.9 
Operating Expense [Member]
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
Allocated Share-based Compensation Expense
$ 1.7 
$ 1.9 
Employee Incentive Plan (Compensation Schedule) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2016
ENLK Restricted Units [Member] |
Restricted Stock Units (RSUs) [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Shares Paid for Tax Withholding for Share Based Compensation
84,429 
Number of Units
 
Non-vested, beginning of period (Units)
1,253,729 
Granted
1,041,022 
Vested
(294,460)
Forfeited
(27,797)
Non-vested, end of period (Units)
1,972,494 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 29.59 
Granted
$ 10.01 
Vested in Period
$ 30.40 
Forfeited
$ 24.12 
Non-vested, end of period
$ 19.21 
Aggregate intrinsic value, end of period
$ 23.8 
ENLC Restricted Units [Member] |
Restricted Stock Units (RSUs) [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Shares Paid for Tax Withholding for Share Based Compensation
90,326 
Number of Units
 
Non-vested, beginning of period (Units)
1,148,893 
Granted
1,032,976 
Vested
(317,726)
Forfeited
(24,970)
Non-vested, end of period (Units)
1,839,173 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 34.78 
Granted
$ 9.42 
Vested in Period
$ 37.03 
Forfeited
$ 26.85 
Non-vested, end of period
$ 20.26 
Aggregate intrinsic value, end of period
20.7 
Enlink midstream, LLC [Member] |
Performance Based Restricted Unit [Member]
 
Number of Units
 
Non-vested, beginning of period (Units)
105,080 
Granted
242,646 
Forfeited
(2,525)
Non-vested, end of period (Units)
345,201 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 40.50 
Granted
$ 9.59 
Forfeited
$ 41.31 
Non-vested, end of period
$ 18.76 
Aggregate intrinsic value, end of period
3.9 
EnLink Midstream Partners, LP [Member] |
Performance Based Restricted Unit [Member]
 
Number of Units
 
Non-vested, beginning of period (Units)
118,126 
Granted
258,078 
Forfeited
(2,798)
Non-vested, end of period (Units)
373,406 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 35.41 
Granted
$ 9.81 
Forfeited
$ 36.18 
Non-vested, end of period
$ 17.71 
Aggregate intrinsic value, end of period
$ 4.5 
Employee Incentive Plan (Intrinsic and Fair Value of Units Vested) (Details) (Restricted Stock Units (RSUs) [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
ENLC Restricted Units [Member]
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Aggregate intrinsic value of units vested
$ 3.8 
$ 8.3 
Fair value of units vested
11.8 
8.6 
ENLK Restricted Units [Member]
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Aggregate intrinsic value of units vested
3.7 
6.8 
Fair value of units vested
$ 9.0 
$ 7.0 
Employee Incentive Plans Total Shareholder Return Unit Summary (Details) (Performance Based Restricted Unit [Member], USD $)
0 Months Ended
Feb. 19, 2016
Jan. 22, 2016
EnLink Midstream Partners, LP [Member]
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Beginning TSR price
$ 14.82 
$ 14.82 
Fair Value Assumptions, Risk Free Interest Rate
0.89% 
1.097% 
Volatility Rate
42.33% 
39.71% 
Distribution yield
19.20% 
12.10% 
Enlink midstream, LLC [Member]
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Beginning TSR price
$ 15.38 
$ 15.38 
Fair Value Assumptions, Risk Free Interest Rate
0.89% 
1.097% 
Volatility Rate
52.05% 
46.02% 
Distribution yield
14.00% 
8.60% 
Derivatives (Summary of Derivative Income Expense) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Gain (loss) on derivative activity
$ (0.4)
$ 0.2 
Commodity Swap [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Change in fair value of derivatives
(6.0)
(3.7)
Realized gain on derivatives
$ 5.6 
$ 3.9 
Derivatives (Schedule of Derivative Assets Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative assets — current
$ 10.5 
$ 16.8 
Fair value of derivative liabilities — current
(3.2)
(2.9)
Fair value of derivative liabilities — long term
0 
(0.1)
Net fair value of derivatives
7.3 
13.8 
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Net fair value of derivatives
$ 7.3 
 
Derivatives (Derivatives Outstanding) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Derivative [Line Items]
 
 
Total mark to market derivatives
$ 7.3 
$ 13.8 
Not Designated as Hedging Instrument [Member]
 
 
Derivative [Line Items]
 
 
Total mark to market derivatives
7.3 
 
Liquids [Member] |
Short Contracts [Member]
 
 
Derivative [Line Items]
 
 
Derivative Nonmonetary Notional Amount
42,900,000 
 
Total mark to market derivatives
8.8 
 
Liquids [Member] |
Long Contracts [Member]
 
 
Derivative [Line Items]
 
 
Derivative Nonmonetary Notional Amount
17,100,000 
 
Total mark to market derivatives
(1.8)
 
Gas [Member] |
Short Contracts [Member]
 
 
Derivative [Line Items]
 
 
Derivative Nonmonetary Notional Amount
6,700,000 
 
Total mark to market derivatives
0.8 
 
Gas [Member] |
Long Contracts [Member]
 
 
Derivative [Line Items]
 
 
Derivative Nonmonetary Notional Amount
2,200,000 
 
Total mark to market derivatives
(0.3)
 
Condensate [Member] |
Short Contracts [Member]
 
 
Derivative [Line Items]
 
 
Derivative Nonmonetary Notional Amount
100,000 
 
Total mark to market derivatives
$ (0.2)
 
Derivatives (Details Textuals) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Derivative [Line Items]
 
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value
$ 7.3 
Maximum counterparty loss
10.5 
Maximum counterparty loss with netting feature
$ 7.3 
Fair Value Measurement (Fair Measurement on a Recurring Nonrecurring Basis) (Details) (Fair Value, Inputs, Level 2 [Member], Commodity Swap [Member], Fair Value, Measurements, Recurring [Member], USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Fair Value, Inputs, Level 2 [Member] |
Commodity Swap [Member] |
Fair Value, Measurements, Recurring [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Net Fair value of derivatives
$ 7.3 
$ 13.8 
Fair Value Measurement (Fair Value of Financial Instrument) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
$ 3,195.6 
$ 3,066.8 
Carrying Value [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Obligations under capital lease
13.4 
16.7 
Fair Value [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt, Fair Value
2,629.0 
2,585.5 
Obligations under capital lease
$ 12.7 
$ 15.6 
Fair Value Measurement (Details Textuals) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Amount Outstanding
$ 543.0 
$ 414.0 
Unsecured Debt
$ 2,674.8 
$ 2,674.8 
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum
2.70% 
2.70% 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum
7.10% 
7.10% 
Fair Value Measurement (Phantom) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Mar. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
Unsecured Debt
$ 2,674.8 
$ 2,674.8 
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimum
2.70% 
2.70% 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum
7.10% 
7.10% 
Commitments and Contingencies (Details) (USD $)
In Millions, unless otherwise specified
1 Months Ended
Aug. 31, 2014
Gain Contingencies [Line Items]
 
Gain on Litigation Settlement
$ 6.1 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Dec. 31, 2015
Segment Reporting Information [Line Items]
 
 
 
Product sales
$ 588.5 
$ 670.7 
 
Product sales - affiliates
24.5 
16.2 
 
Midstream services
114.5 
102.4 
 
Midstream services-affiliates
162.6 
151.0 
 
Cost of sales
(586.2)
(657.4)
 
Operating expenses
(98.2)
(98.4)
 
Gain (loss) on derivative activity
(0.4)
0.2 
 
Segment profit
205.3 
184.7 
 
Depreciation and amortization
(121.9)
(91.3)
 
Impairments
(566.3)
0 
 
Goodwill
420.7 
2,283.1 
987.0 
Capital expenditures
120.4 
175.7 
 
Identifiable assets
8,944.5 
 
8,092.8 
Texas Operating Segment [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Product sales
62.5 
49.8 
 
Product sales - affiliates
37.3 
25.9 
 
Midstream services
27.4 
19.6 
 
Midstream services-affiliates
110.3 
115.5 
 
Cost of sales
(91.3)
(67.2)
 
Operating expenses
(39.3)
(47.0)
 
Gain (loss) on derivative activity
0 
0 
 
Segment profit
106.9 
96.6 
 
Depreciation and amortization
(46.2)
(36.4)
 
Impairments
(473.1)
 
 
Goodwill
230.4 
1,168.2 
703.5 
Capital expenditures
23.3 
73.5 
 
Identifiable assets
3,175.4 
 
3,709.5 
Louisiana Operating Segment [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Product sales
287.7 
372.2 
 
Product sales - affiliates
7.4 
7.1 
 
Midstream services
55.2 
57.9 
 
Midstream services-affiliates
12.7 
0.1 
 
Cost of sales
(302.1)
(370.9)
 
Operating expenses
(23.3)
(24.3)
 
Gain (loss) on derivative activity
0 
0 
 
Segment profit
37.6 
42.1 
 
Depreciation and amortization
(29.3)
(27.5)
 
Impairments
0 
 
 
Goodwill
0 
786.8 
0 
Capital expenditures
22.7 
15.2 
 
Identifiable assets
2,290.6 
 
2,309.3 
Oklahoma Operating Segment [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Product sales
7.8 
0 
 
Product sales - affiliates
10.6 
3.7 
 
Midstream services
15.1 
10.7 
 
Midstream services-affiliates
45.0 
31.2 
 
Cost of sales
(19.3)
(5.1)
 
Operating expenses
(12.8)
(7.0)
 
Gain (loss) on derivative activity
0 
0 
 
Segment profit
46.4 
33.5 
 
Depreciation and amortization
(33.8)
(13.5)
 
Impairments
0 
 
 
Goodwill
190.3 
190.3 
190.3 
Capital expenditures
69.2 
5.2 
 
Identifiable assets
2,380.7 
 
873.4 
Crude And Condensate Segment [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Product sales
230.5 
248.7 
 
Product sales - affiliates
0.2 
0 
 
Midstream services
16.8 
14.2 
 
Midstream services-affiliates
5.2 
4.2 
 
Cost of sales
(215.1)
(234.7)
 
Operating expenses
(22.8)
(20.1)
 
Gain (loss) on derivative activity
0 
0 
 
Segment profit
14.8 
12.3 
 
Depreciation and amortization
(10.4)
(12.4)
 
Impairments
(93.2)
 
 
Goodwill
0 
137.8 
93.2 
Capital expenditures
3.3 
77.6 
 
Identifiable assets
798.1 
 
898.0 
Corporate Segment [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
Product sales
0 
0 
 
Product sales - affiliates
(31.0)
(20.5)
 
Midstream services
0 
0 
 
Midstream services-affiliates
(10.6)
0 
 
Cost of sales
41.6 
20.5 
 
Operating expenses
0 
0 
 
Gain (loss) on derivative activity
(0.4)
0.2 
 
Segment profit
(0.4)
0.2 
 
Depreciation and amortization
(2.2)
(1.5)
 
Impairments
0 
 
 
Goodwill
0 
0 
0 
Capital expenditures
1.9 
4.2 
 
Identifiable assets
$ 299.7 
 
$ 302.6 
Segment Information (Reconciliation of Segment Profit to Operating Income) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Segment Reporting [Abstract]
 
 
Segment profit
$ 205.3 
$ 184.7 
General and administrative expenses
(33.2)
(41.9)
Gain on disposition of assets
0.2 
0 
Depreciation and amortization
(121.9)
(91.3)
Impairments
(566.3)
0 
Operating income (loss)
$ (515.9)
$ 51.5 
Supplemental Cash Flow Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 0 Months Ended 3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2015
Common Class C [Member]
Mar. 31, 2015
Midstream Holdings [Member]
Jan. 7, 2016
Tall Oak [Member]
Mar. 31, 2016
Tall Oak [Member]
Other Significant Noncash Transactions [Line Items]
 
 
 
 
 
 
Business Combination, Installment, Current
$ 250.0 
 
 
 
 
 
Installment payable, net of discount of $79.1 million (1)
 
 
 
 
420.9 
420.9 
Other Significant Noncash Transaction, Value of Consideration Given
 
180.0 
180.0 
20.9 
 
 
Contribution from ENLC (3)
$ 237.1 
 
 
 
 
 
Supplemental Cash Flow Information (Phantom) (Details) (Tall Oak [Member], USD $)
In Millions, unless otherwise specified
0 Months Ended 3 Months Ended
Jan. 7, 2016
Mar. 31, 2016
Jan. 7, 2016
Tall Oak [Member]
 
 
 
Other Significant Noncash Transactions [Line Items]
 
 
 
Debt Instrument, Unamortized Discount (Premium), Net
 
$ 79.1 
$ 79.1 
Business Combination, Installment, Long-term Payable
$ 250.0 
$ 250.0 
 
Other Information (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Other Liabilities Disclosure [Abstract]
 
 
Accrued interest
$ 53.3 
$ 23.2 
Accrued wages and benefits, including taxes
7.5 
27.7 
Accrued ad valorem taxes
12.5 
27.0 
Capital expenditure accruals
32.0 
22.3 
Onerous performance obligations
16.6 
17.0 
Other
65.3 
57.2 
Other current liabilities
$ 187.2 
$ 174.4