ENLINK MIDSTREAM PARTNERS, LP, 10-Q filed on 11/4/2015
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2015
Oct. 23, 2015
Document Information [Line Items]
 
 
Document Type
10-Q 
 
Document Fiscal Period Focus
Q3 
 
Document Period End Date
Sep. 30, 2015 
 
Document Fiscal Year Focus
2015 
 
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
 
322,228,649 
Common Class C [Member]
 
 
Document Information [Line Items]
 
 
Entity Common Stock, Shares Outstanding
 
6,924,701 
Condensed Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Current assets:
 
 
Cash and cash equivalents
$ 24.9 
$ 9.6 
Accounts receivable:
 
 
Trade, net of allowance for bad debt of $1.7
30.7 
139.0 
Accrued revenue and other
333.5 
253.3 
Related party
119.1 
121.6 
Fair value of derivative assets
15.5 
16.7 
Natural gas and NGLs inventory, prepaid expenses and other
53.5 
30.8 
Total current assets
577.2 
571.0 
Property and equipment, net of accumulated depreciation of $1,671.1 and $1,426.3, respectively
5,565.8 
5,042.8 
Intangible assets, net of accumulated amortization of $42.9 and $36.5, respectively
602.8 
533.0 
Goodwill
1,729.9 
2,257.8 
Fair value of derivative assets
2.9 
10.0 
Investments in unconsolidated affiliates
263.5 
270.8 
Other assets, net
25.9 
16.6 
Total assets
8,768.0 
8,702.0 
Current liabilities:
 
 
Accounts payable and drafts payable
40.6 
121.8 
Accounts payable to related party
24.2 
3.0 
Accrued gas, NGLs, condensate and crude oil purchases
262.9 
204.5 
Fair value of derivative liabilities
3.4 
3.0 
Other current liabilities
205.9 
149.8 
Total current liabilities
537.0 
482.1 
Long-term debt
2,851.5 
2,022.5 
Fair value of derivative liabilities
0.5 
2.0 
Asset retirement obligation
12.8 
12.4 
Other long-term liabilities
70.7 
84.0 
Deferred tax liability
77.2 
73.1 
Redeemable non-controlling interest
6.9 
0 
Common unitholders (321,570,669 units issued and outstanding at September 30, 2015 and 245,421,549 units issued and outstanding at December 31, 2014)
4,818.5 
5,833.3 
Class C unitholders (6,924,701 units issued and outstanding at September 30, 2015)
164.8 
0 
General partner interest (1,594,974 equivalent units outstanding at September 30, 2015 and December 31, 2014)
216.2 
180.3 
Non controlling interest
11.9 
12.3 
Total partners' equity
5,211.4 
6,025.9 
Commitments and Contingencies
   
   
Total liabilities and partners’ equity
$ 8,768.0 
$ 8,702.0 
Condensed Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Statement of Financial Position [Abstract]
 
 
Allowance for bad debt
$ 1.7 
$ 0 
Property and equipment, accumulated depreciation
1,671.1 
1,426.3 
Intangible assets, accumulated amortization
$ 42.9 
$ 36.5 
Common Stock, Shares, Issued
321,570,669 
245,421,549 
General Partners' Capital Account, Units Issued
1,594,974 
1,594,974 
Other Ownership Interests, Units Outstanding
6,924,701 
0 
Condensed Consolidated Statements of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Revenues:
 
 
 
 
Product sales
$ 863.5 
$ 579.1 
$ 2,488.8 
$ 1,480.4 
Product sales - affiliates
40.3 
37.8 
89.6 
474.2 
Midstream services
111.3 
68.6 
351.3 
154.8 
Midstream services-affiliates
150.3 
170.9 
449.3 
400.2 
Gain (loss) on derivative activity
5.2 
1.0 
6.6 
(1.9)
Revenues
1,170.6 
857.4 
3,385.6 
2,507.7 
Operating costs and expenses:
 
 
 
 
Cost of sales (1)
861.8 
597.2 
2,487.4 
1,798.0 
Operating expenses (2)
105.0 
79.8 
312.6 
200.4 
General and administrative (3)
33.5 
23.5 
102.3 
64.8 
Loss on disposition of assets
3.2 
0 
3.2 
0 
Depreciation and amortization
98.4 
74.6 
289.1 
197.6 
Impairments
799.2 
0 
799.2 
0 
Gain on litigation settlement
0 
(6.1)
0 
(6.1)
Total operating costs and expenses
1,901.1 
769.0 
3,993.8 
2,254.7 
Operating income (loss)
(730.5)
88.4 
(608.2)
253.0 
Other income (expense):
 
 
 
 
Interest expense, net of interest income
(30.2)
(13.1)
(71.5)
(31.1)
Equity in income of equity investment
6.4 
5.6 
16.1 
14.3 
Gain on extinguishment of debt
0 
2.4 
0 
3.2 
Other income (expense)
0.1 
0.1 
0.7 
(0.7)
Total other expense
(23.7)
(5.0)
(54.7)
(14.3)
Income (loss) from continuing operations before non-controlling interest and income taxes
(754.2)
83.4 
(662.9)
238.7 
Income tax (provision) benefit
(1.0)
0.1 
(2.9)
(20.7)
Net income (loss) from continuing operations
(755.2)
83.5 
(665.8)
218.0 
Discontinued Operations:
 
 
 
 
Income from discontinued operations, net of tax
0 
0 
0 
1.0 
Discontinued operations, net of tax
0 
0 
0 
1.0 
Net income (loss)
(755.2)
83.5 
(665.8)
219.0 
Net income attributable to non-controlling interest
(0.3)
0.1 
(0.3)
0.2 
Net income (loss) attributable to EnLink Midstream Partners, LP
(754.9)
83.4 
(665.5)
218.8 
Predecessor interest in net income (4)
0 
0 
0 
35.5 
General partner interest in net income
6.3 
42.9 
50.2 
96.8 
Limited partners’ interest in net income (loss) attributable to EnLink Midstream Partners, LP
(745.2)
40.5 
(700.5)
86.5 
Class C partners’ interest in net income (loss) attributable to EnLink Midstream Partners, LP
$ (16.0)
$ 0 
$ (15.2)
$ 0 
Basic per common unit
$ (2.32)
$ 0.18 
$ (2.38)
$ 0.38 
Diluted per common unit
$ (2.32)
$ 0.18 
$ (2.38)
$ 0.38 
Condensed Consolidated Statements of Operations (parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Affiliate purchased gas, NGLs, condensate and crude
$ 861.8 
$ 597.2 
$ 2,487.4 
$ 1,798.0 
Affiliate general and administrative expense
33.5 
23.5 
102.3 
64.8 
Affiliated Entity [Member]
 
 
 
 
Affiliate purchased gas, NGLs, condensate and crude
51.9 
24.1 
91.7 
349.9 
Operating expenses - affiliates
0.1 
0 
0.3 
5.9 
Affiliate general and administrative expense
$ 0.1 
$ 1.0 
$ 0.2 
$ 10.6 
Consolidated Statements of Changes in Partners' Equity (USD $)
In Millions, unless otherwise specified
Total
Common Units
General Partner Interest
Noncontrolling Interest [Member]
Common Class C [Member]
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount at Dec. 31, 2014
$ 0 
 
 
 
 
Balance at Dec. 31, 2014
6,025.9 
5,833.3 
180.3 
12.3 
0 
Balance (Shares) at Dec. 31, 2014
 
245.4 
1.6 
 
0 
Increase (Decrease) in Partners' Capital
 
 
 
 
 
Issuance of common units
372.9 
192.9 
 
 
180.0 
Issuance of common units for acquisition of Partnership, shares
 
76.0 
 
 
6.7 
Conversion of restricted units for common units, net of units withheld for taxes
(2.5)
(2.5)
 
 
 
Restricted Stock, Shares Issued Net of Shares for Tax Withholdings
 
0.2 
 
 
 
Unit-based compensation
28.6 
14.0 
14.6 
 
 
Contribution from Devon
28.8 
28.8 
 
 
 
Distribution To Affiliate
(171.0)
(171.0)
 
 
 
Distributions
(338.9)
(310.0)
(28.9)
 
 
Dividends, Paid-in-kind
 
 
 
 
0.2 
Noncontrolling Interest contributions
12.2 
 
 
12.2 
 
Distributions to non-controlling interest
(66.5)
 
 
(66.5)
 
Adjustment related to mandatory redemption of E2 non-controlling interest
(5.4)
 
 
(5.4)
 
Redeemable non-controlling interest
(6.9)
 
 
(6.9)
 
Partners' Capital, Other
0 
(66.5)
 
66.5 
 
Net income (loss)
(665.8)
(700.5)
50.2 
(0.3)
(15.2)
Increase (Decrease) in Temporary Equity
 
 
 
 
 
Redeemable Noncontrolling Interest Reclassifications Between Permanen And Temporary Equity
6.9 
 
 
 
 
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount at Sep. 30, 2015
6.9 
 
 
 
 
Balance at Sep. 30, 2015
$ 5,211.4 
$ 4,818.5 
$ 216.2 
$ 11.9 
$ 164.8 
Balance (Shares) at Sep. 30, 2015
 
321.6 
1.6 
 
6.9 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Statement of Cash Flows [Abstract]
 
 
Net income (loss) from continuing operations
$ (665.8)
$ 218.0 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Impairments
799.2 
0 
Depreciation and amortization
289.1 
197.6 
Accretion expense
0.4 
0.4 
Loss on disposition of assets
3.2 
0 
Gain on extinguishment of debt
0 
(3.2)
Deferred tax expense
0 
20.4 
Non-cash unit-based compensation
28.6 
12.7 
(Gain) loss on derivatives recognized in net income
(6.6)
1.9 
Cash settlements on derivatives
13.0 
(1.7)
Amortization of debt issue costs
2.2 
0.6 
Amortization of premium on notes
(2.2)
(1.7)
Redeemable non-controlling interest expense
(2.0)
0 
Distribution of earnings from equity investment
17.1 
6.3 
Equity in income from equity investments
(16.1)
(14.3)
Changes in assets and liabilities:
 
 
Accounts receivable, accrued revenue and other
124.3 
41.4 
Natural gas and NGLs inventory, prepaid expenses and other
(18.4)
(26.7)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities
(58.0)
(71.4)
Net cash provided by operating activities
508.0 
380.3 
Cash flows from investing activities:
 
 
Additions to property and equipment
(450.3)
(540.1)
Acquisition of business, net of cash acquired
(330.6)
(74.9)
Other Payments to Acquire Businesses
0 
(23.5)
Proceeds from sale of property
0.4 
0 
Investment in limited liability company
(8.1)
(5.7)
Distribution from equity investment company in excess of earnings
14.3 
7.6 
Net cash used in investing activities
(774.3)
(636.6)
Cash flows from financing activities:
 
 
Proceeds from borrowings
2,604.4 
2,003.6 
Payments on borrowings
(1,773.2)
(1,603.7)
Payments on capital lease obligations
(2.5)
(2.1)
Decrease in drafts payable
(12.6)
(2.6)
Debt financing costs
(9.5)
(6.4)
Conversion of restricted units, net of units withheld for taxes
(2.5)
(0.5)
Proceeds from issuance of common units
12.9 
71.9 
Proceeds from exercise of unit options
0 
0.4 
Distributions to non-controlling partners
(66.5)
(106.9)
Contributions by non-controlling partners
12.2 
1.2 
Distributions to partners
(338.9)
(146.3)
Contributions from Devon
28.8 
105.3 
Distributions to Devon for net assets acquired (Note 3)
(171.0)
0 
Distributions to Predecessor
0 
(27.2)
Net cash provided by financing activities
281.6 
286.7 
Net cash provided by operating activities
0 
5.0 
Net cash used in investing activities
0 
(0.6)
Net cash used in financing activities – net distributions to Devon and non-controlling interests
0 
(4.4)
Net cash provided by discontinued operations
0 
0 
Net increase in cash and cash equivalents
15.3 
30.4 
Cash and cash equivalents, beginning of period
9.6 
0 
Cash and cash equivalents, end of period
24.9 
30.4 
Cash paid for interest
45.5 
18.3 
Cash paid for income taxes
$ 0.4 
$ 7.1 
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 Midstream Holdings (as defined below) and their consolidated subsidiaries. The term “Midstream Holdings” is sometimes used to refer to EnLink Midstream Holdings, LP itself or to EnLink Midstream Holdings, LP together with EnLink Midstream Holdings GP, LLC and their subsidiaries.

(a)Organization of Business

EnLink Midstream 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 (the “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 70% of the outstanding limited liability company interests in ENLC.

Effective as of March 7, 2014, the Operating Partnership acquired (the “Acquisition”) 50% of the outstanding equity interests in EnLink Midstream Holdings, LP (“Midstream Holdings”) and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings, in exchange for the issuance by the Partnership of 120,542,441 units representing limited partnership interests in the Partnership. At the same time, EnLink Midstream, Inc. (“EMI”), the entity that directly owns our General Partner, became a wholly-owned subsidiary of ENLC (together with the Acquisition, the “business combination”). At the conclusion of the business combination, another wholly-owned subsidiary of ENLC, Acacia Natural Gas Corp. I, Inc. (“Acacia”), owned the remaining 50% of the outstanding equity interests in Midstream Holdings.

On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings (the "February Transferred Interests") to us in a drop down transaction (the "February EMH Drop Down") in exchange for 31,618,311 of our Class D Common Units. On May 27, 2015, Acacia contributed the remaining 25% limited partner interest in Midstream Holdings (the “May Transferred Interests”) to us in a drop down transaction (the "May EMH Drop Down" and together with the February EMH Drop Down, the "EMH Drop Downs") in exchange for 36,629,888 of our Class E Common Units. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings. In addition, on April 1, 2015 the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets from Devon (the "VEX Interests"). See Note 3 - Acquisitions for further discussion.

(b)Nature of Business

The Partnership primarily focuses on providing midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization, and brine services to producers of natural gas, natural gas liquids ("NGLs"), crude oil and condensate. 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 our south Louisiana processing plants to our fractionators in south Louisiana. 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 arrangements. 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. We also provide a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucking facilities as well as brine disposal services.
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.

Further, the unaudited condensed consolidated financial statements give effect to the business combination and related transactions discussed in Note 1(a) above under the acquisition method of accounting and are treated as a reverse acquisition. Under the acquisition method of accounting, Midstream Holdings was the accounting acquirer in the transactions because its parent company, Devon, obtained control of the Partnership through the indirect control of the General Partner as a result of the business combination. All financial results prior to March 7, 2014 reflect the historical operations of Midstream Holdings and are reflected as Predecessor income in the statement of operations. Additionally, the Partnership’s assets acquired and liabilities assumed by Midstream Holdings in the business combination were recorded at their fair values measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of the Partnership’s net assets acquired was recorded as goodwill. Financial results subsequent to March 7, 2014 reflect the combined operations of Midstream Holdings and the Partnership, which give effect to new contracts entered into with Devon and include the legacy Partnership assets. Certain assets were not contributed to Midstream Holdings from the Predecessor and the operations of such non contributed assets have been presented as discontinued operations. In conjunction with the business combination, Midstream Holdings became a non-taxable entity that was treated as a reorganization under common control with the removal of historical deferred taxes reflected through equity.

During the fourth quarter of 2014 and the first half of 2015, the Partnership acquired assets from ENLC and Devon through drop down transactions. Due to ENLC's control of the Partnership through its ownership and control of the General Partner and Devon's control of the Partnership 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, the Partnership was required to recast its historical financial statements to include the activities of such assets from the date that these entities were under common control. The consolidated financial statements for periods prior to the Partnership’s 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 the Partnership had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from ENLC and Devon for periods prior to the Partnership’s acquisition is allocated to the general partner.

(b) Revenue Recognition

The Partnership generates the majority of its revenues from midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization and brine services, through various contractual arrangements, which include fee based contract arrangements or arrangements where it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the Partnership's transactions vary in form, the essential element of each transaction is the use of its assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal or pipeline. The Partnership reflects revenue as Product sales and Midstream services revenue on the Condensed Consolidated Statements of Operations as follows:

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

•
Midstream services - Midstream services represents all other revenue generated as a result of performing the Partnership's midstream services outlined above.

The Partnership recognizes revenue for sales or services at the time the natural gas, NGLs, crude oil or condensate are delivered or at the time the service is performed at a fixed or determinable price. The Partnership generally accrues one month of sales and the related natural gas, NGL, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. Except for fixed-fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, bearing the risk and reward of ownership as evidenced by title transfer, scheduling the transportation of products and assuming credit risk. The Partnership accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).
    
(c) Redeemable Non-Controlling Interest

Non-controlling interests that contain an option for the non-controlling interest holder to require the Partnership to buy out such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within the control of the Partnership. Redeemable non-controlling interest is not considered to be a component of partners' equity and is reported as temporary equity in the mezzanine section on the Condensed Consolidated Balance Sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder's share of net income or loss and distributions).

(d) Recent Accounting Pronouncements

In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments ("ASU 2015-16"), 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. ASU 2015-16 is effective for public business entities for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. For all other entities, ASU 2015-16 is effective for fiscal years beginning after December 15, 2016, and interim periods within fiscal years beginning after December 15, 2017. Early adoption is permitted. The update is effective for us beginning on January 1, 2016.

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 this standard will have on our condensed consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835). The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard requires retrospective application and is effective for us beginning on January 1, 2016.

In April 2015, the FASB issued 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 fiscal years. ASU 2015-06 requires retrospective application and early adoption is permitted.

In February 2015, the FASB issued 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. The update is effective for us beginning on January 1, 2016, and we are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures.

Subject to these evaluations, we have reviewed all recently issued accounting pronouncements that became effective during the nine months ended September 30, 2015, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.
Acquisition
Mergers Acquisitions And Dispositions Disclosures
(3) Acquisitions

Chevron Acquisition

Effective November 1, 2014, the Partnership acquired, from affiliates of Chevron Corporation, Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana, together with 100% of the equity interests (all of which were voting) in certain entities, for approximately $231.5 million in cash. The natural gas assets include natural gas pipelines spanning from Beaumont, Texas to the Mississippi River corridor and working natural gas storage capacity in southern Louisiana. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date.
Purchase Price Allocation (in millions):
 
 
Assets acquired:
 
 
Property, plant and equipment
 
$
225.3

Intangibles
 
13.0

Liabilities assumed:
 
 
Current liabilities
 
(6.8
)
Total identifiable net assets
 
$
231.5



The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 20 years.

We incurred $0.6 million of direct transaction costs for the nine months ended September 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from January 1, 2015 to September 30, 2015, the Partnership recognized $24.2 million of revenues and $2.2 million of net income related to the assets acquired.

LPC Acquisition

On January 31, 2015, the Partnership acquired 100% of the equity interests (all of which were voting) of LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $108.1 million ($87.0 million, net of cash acquired). 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.

Purchase Price Allocation (in millions):
 
 
Assets acquired:
 
 
Current assets (including $21.1 million in cash)
 
$
107.4

Property, plant and equipment
 
29.8

Intangibles
 
43.2

Goodwill
 
29.6

Liabilities assumed:
 
 
Current liabilities
 
(97.9
)
Deferred tax liability
 
(4.0
)
Total identifiable net assets
 
$
108.1


The Partnership recognized intangible assets related to customer relationships and trade name. The acquired intangible assets related to customer relationships will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 years.

The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. 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 Crude and Condensate segment and is non-deductible for tax purposes.

We incurred $0.2 million of direct transaction costs for the nine months ended September 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from January 31, 2015 to September 30, 2015, the Partnership recognized $853.3 million of revenues and $1.2 million of net income related to the assets acquired.

Coronado Acquisition

On March 16, 2015, the Partnership acquired 100% of the equity interests (all of which were voting) in Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600.2 million. The purchase price consisted of $240.2 million in cash ($238.8 million, net of cash acquired), 6,704,285 common units and 6,704,285 Class C Common Units, both in the Partnership.

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 (including $1.4 million in cash)
 
$
20.8

Property, plant and equipment
 
302.1

Intangibles
 
281.0

  Goodwill
 
18.6

Liabilities assumed:
 
 
Current liabilities
 
(22.3
)
Total identifiable net assets
 
$
600.2



The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 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.

We incurred $3.1 million of direct transaction costs for the nine months ended September 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from March 17, 2015 to September 30, 2015, the Partnership recognized $126.0 million of revenues and $7.7 million of net loss related to the assets acquired.

EMH Drop Downs

On February 17, 2015, the Partnership acquired an additional 25% limited partner interest in Midstream Holdings from Acacia in the February EMH Drop Down. As consideration for the February Transferred Interests, the Partnership issued 31.6 million Class D Common Units in the Partnership to Acacia with an implied value of $925.0 million. The Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they received only a pro rata distribution for the fiscal quarter ended March 31, 2015. The Class D Common Units converted into common units on a one-for-one basis on May 4, 2015.

On May 27, 2015, the Partnership acquired the remaining 25% limited partner interest in Midstream Holdings from Acacia in the May EMH Drop Down in exchange for 36.6 million Class E Common Units in the Partnership with an implied value of $900.0 million. The Class E Common Units are substantially similar in all respects to the Partnership’s common units, except that they received only a pro rata distribution for the fiscal quarter ended June 30, 2015. The Class E Common Units converted into common units on a one-for-one basis on August 3, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings. The period of common control for EMH began on March 7, 2014, the effective date of the business combination described under "Devon Transaction" below.

The Partnership accounted for the acquisition of the EMH Drop Downs from Acacia as a transfer between entities under common control in accordance with ASC 805-50-30. As such, the February Transferred Interests and May Transferred Interests were recorded on the Partnership’s books at historical cost on the date of transfer, which was February 17, 2015 and May 27, 2015, respectively. The “Transfer of interest in Midstream Holdings” presented in the Consolidated Statement of Changes in Partners’ Equity represents the adjustment to equity due to the recast to offset distributions paid to ENLC for its related ownership during the period January 1, 2015 to May 27, 2015.

VEX Pipeline Drop Down

On April 1, 2015, the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in south Texas, together with 100% of the equity interests (all of which were voting) in certain entities, from Devon in a drop down transaction (the "VEX Drop Down"). The aggregate consideration paid by the Partnership consisted of $171.0 million in cash, 338,159 common units representing limited partner interests in the Partnership with an aggregate value of approximately $9.0 million and the Partnership’s assumption of up to $40.0 million in certain construction costs related to VEX. The VEX pipeline is a multi-grade crude oil pipeline located in the Eagle Ford Shale. Other VEX assets at the destination of the pipeline include a truck unloading terminal, above-ground storage and rights to barge loading docks. The acquisition has been accounted for as an acquisition under common control under ASC 805, resulting in the retrospective adjustment of our prior results. As such, the VEX Interests were recorded on the Partnership's books at historical cost on the date of transfer of $131.0 million. The difference between the historical cost of the net assets and consideration given was $40.0 million and is recognized as a distribution to Devon. The period of common control for VEX began on February 28, 2014, the effective date of the acquisition of the VEX Interests by Devon.

E2 Drop Down

On October 22, 2014, the Partnership acquired all remaining voting equity interests in E2 Appalachian Compression, LLC and E2 Energy Services, LLC (together “E2”) in a drop down transaction from EMI (the "E2 Drop Down"). The total consideration for the transaction was approximately $194.0 million, including a cash payment of $163.0 million and the issuance of approximately 1.0 million common units (valued at approximately $31.2 million based on the October 22, 2014 closing price of the common units). This acquisition has been accounted for as an acquisition under common control under ASC 805. The period of common control for E2 began on March 7, 2014, the effective date of the business combination described in "Devon Transaction" below.

The following tables present the collective impact of the E2 Drop Down, the VEX Drop Down and the EMH Drop Downs as presented in the Partnership's historical Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and the nine months ended September 30, 2015:
 
 
Nine Months Ended September 30, 2015
 
 
Partnership Historical
 
EMH
 
VEX
 
Combined
 
 
(in millions)
Revenues
 
$
3,381.4

 
$
—

 
$
4.2

 
$
3,385.6

Net income (loss)
 
$
(666.5
)
 
$
—

 
$
0.7

 
$
(665.8
)
Net income attributable to non-controlling interest
 
$
15.0

 
$
(15.3
)
 
$
—

 
$
(0.3
)
Net income (loss) attributable to EnLink Midstream Partners, LP
 
$
(681.5
)
 
$
15.3

 
$
0.7

 
$
(665.5
)
General partner interest in net income (loss)
 
$
34.2

 
$
15.3

 
$
0.7

 
$
50.2



 
 
Three Months Ended September 30, 2014
 
 
Partnership Historical
 
EMH
 
E2
 
VEX
 
Combined
 
 
(in millions)
Revenues
 
$
851.4

 
$
—

 
$
3.6

 
$
2.4

 
$
857.4

Net income (loss)
 
$
85.7

 
$
—

 
$
0.1

 
$
(2.3
)
 
$
83.5

Net income attributable to non-controlling interest
 
$
41.7

 
$
(41.7
)
 
$
0.1

 
$
—

 
$
0.1

Net income (loss) attributable to EnLink Midstream
    Partners, LP
 
$
44.0

 
$
41.7

 
$
—

 
$
(2.3
)
 
$
83.4

General partner interest in net income (loss)
 
$
3.5

 
$
41.7

 
$
—

 
$
(2.3
)
 
$
42.9



 
 
Nine Months Ended September 30, 2014
 
 
Partnership Historical
 
EMH*
 
E2
 
VEX**
 
Combined
 
 
(in millions)
Revenues
 
$
2,498.0

 
$
—

 
$
7.3

 
$
2.4

 
$
2,507.7

Net income (loss)
 
$
224.3

 
$
—

 
$
—

 
$
(5.3
)
 
$
219.0

Net income attributable to non-controlling interest
 
$
94.8

 
$
(94.8
)
 
$
0.2

 
$
—

 
$
0.2

Net income (loss) attributable to EnLink Midstream
Partners, LP
 
$
129.5

 
$
94.8

 
$
(0.2
)
 
$
(5.3
)
 
$
218.8

General partner interest in net income (loss)
 
$
7.5

 
$
94.8

 
$
(0.2
)
 
$
(5.3
)
 
$
96.8

* Represents the Transferred Interests amounts for the period from March 7, 2014 through September 30, 2014.
** Represents the VEX Interests amounts for the period from February 28, 2014 through September 30, 2014.


Devon Transaction

As discussed in Note 1(a), on March 7, 2014, the Partnership acquired, through one of its wholly owned subsidiaries, 50% of the outstanding equity interests in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings, in exchange for the issuance by the Partnership of 120.5 million units representing limited partnership interests in the Partnership. Midstream Holdings owns midstream assets in the Barnett Shale in North Texas and the Cana-Woodford and Arkoma-Woodford Shales in Oklahoma, as well as a contractual right to the economic burdens and benefits of Devon’s 38.75% interest in Gulf Coast Fractionators (“GCF”) in Mt. Belvieu, Texas.

Under the acquisition method of accounting, Midstream Holdings was the acquirer in the business combination because its parent company, Devon, obtained control of the Partnership through the indirect control of the General Partner. Consequently, Midstream Holdings’ assets and liabilities retained their carrying values and the Partnership’s assets acquired and liabilities assumed by Midstream Holdings as the Predecessor in the business combination have been recorded at their fair values measured as of the acquisition date. The excess of the purchase price over the estimated fair values of the Partnership’s net assets acquired has been recorded as goodwill.

For the period from March 7, 2014 to September 30, 2014, the Partnership recognized $1,669.0 million of revenues and $0.7 million of net loss related to the assets acquired in the business combination.

Pro Forma Information

The following unaudited pro forma condensed financial information for the nine months ended September 30, 2015 and the three and nine months ended September 30, 2014 gives effect to the business combination, Chevron acquisition, Coronado acquisition, LPC acquisition, EMH Drop Downs, VEX Drop Down and E2 Drop Down as if they had occurred on January 1, 2014. 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 business combination and acquisitions is reflected below.
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2014
 
2015
 
2014
 
(in millions)
Pro forma total revenues (1)
 
$
1,398.7

 
$
3,507.7

 
$
4,232.0

Pro forma net income (loss)
 
$
72.1

 
$
(671.4
)
 
$
177.7

Pro forma net income (loss) attributable to EnLink Midstream Partners, LP
 
$
72.1

 
$
(671.1
)
 
$
177.6

Pro forma net income (loss) per common unit:
 
 
 


 
 
Basic
 
$
0.13

 
$
(2.39
)
 
$
0.24

Diluted
 
$
0.13

 
$
(2.39
)
 
$
0.24


(1)On January 1, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which
are described in Note 5.
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 31st, 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 September 2015, we determined that sustained weakness in the overall energy sector driven by low commodity prices together with a decline in our unit price caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis on all reporting units.

We perform our goodwill assessment at the reporting unit level. We use a discounted cash flow analysis to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples and estimated future cash flows including volume forecasts and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market 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 value of our Louisiana reporting unit was less than its carrying amount, primarily related to commodity prices and discount rates. 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 Louisiana reporting unit in the amount of $576.1 million was recognized for the three months ended September 30, 2015, which is included in impairment expense in the Condensed Consolidated Statements of Operations.

We concluded that the fair value of goodwill of our remaining reporting units exceeded their carrying value, and the entire amount of goodwill disclosed on the Condensed Consolidated Balance Sheet associated with these remaining reporting units is recoverable. Therefore, no other goodwill impairment was identified or recorded for the remaining reporting units as a result of our interim goodwill assessment.

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. A continuing prolonged period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future goodwill impairment charges for other reporting units due to the potential impact on the cash flows of our operations.

The table below provides a summary of the Partnership’s change in carrying amount of goodwill, by assigned reporting unit.
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
 
(in millions)
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
Balance, beginning of period
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
—

 
$
2,257.8

Acquisitions (1)
18.6

 
—

 
—

 
29.6

 
—

 
48.2

Impairment
—

 
(576.1
)
 
—

 
—

 
—

 
(576.1
)
Balance, end of period
$
1,186.8

 
$
210.7

 
$
190.3

 
$
142.1

 
$
—

 
$
1,729.9


(1)See Note 3-Acquisitions for further discussion.

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.

In the third quarter of 2015, we reviewed our various assets groups for impairment due to the triggering events described in the goodwill impairment analysis above. The undiscounted cash flows related to one of our assets groups in the Crude and Condensate segment were not in excess of its related carrying value. We estimated the fair value of this reporting unit and determined the fair of the intangible assets was not in excess of their carrying value. This resulted in a $223.1 million impairment of intangible assets in our Crude and Condensate segment. The non-cash impairment charge is included in the impairment expense line item of the Condensed Consolidated Statement of Operations. We utilized Level 3 fair value measurements in our impairment analysis of this definite-lived intangible asset, which included discounted cash flow assumptions by management consistent with those utilized in our goodwill impairment analysis.

The following table represents the Partnership's change in carrying value of intangible assets for the periods stated (in millions):
 
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
Carrying
Amount
Nine Months Ended September 30, 2015
 
 
 
 
 
 
Customer relationships, beginning of period
 
$
569.5

 
$
(36.5
)
 
$
533.0

Acquisitions
 
337.2

 
—

 
337.2

Amortization expense
 
—

 
(44.3
)
 
(44.3
)
Impairment
 
(261.0
)
 
37.9

 
(223.1
)
Customer relationships, end of period
 
$
645.7

 
$
(42.9
)
 
$
602.8



The weighted average amortization period for intangible assets is 11.4 years. Amortization expense for intangibles was approximately $14.6 million and $10.2 million for the three months ended September 30, 2015 and 2014, respectively, and $44.3 million and $23.2 million for the nine months ended September 30, 2015 and 2014, respectively.

The following table summarizes the Partnership's estimated aggregate amortization expense for the next five years (in millions):

2015 (remaining)
$
10.3

2016
41.2

2017
41.2

2018
41.2

2019
41.2

Thereafter
427.7

Total
$
602.8

Affiliate Transactions
Related Party Transactions Disclosure
(5) Affiliate Transactions

The Partnership engages in various transactions with Devon and other affiliated entities. For the three and nine months ended September 30, 2015 and 2014, Devon was a significant customer to the Partnership. Devon accounted for 16.3% and 15.9% of the Partnership's revenues for the three and nine months ended September 30, 2015, respectively, and 24.3% and 34.9% for the three and nine months ended September 30, 2014, respectively. The Partnership had an accounts receivable balance related to transactions with Devon of $119.3 million as of September 30, 2015 and $121.6 million as of December 31, 2014. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $24.2 million as of September 30, 2015 and $3.0 million as of December 31, 2014. 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.

Gathering, Processing and Transportation Agreements with Devon

As described in Note 1, Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon.  On January 1, 2014, in connection with the consummation of the business combination, EnLink Midstream Services, LLC, a wholly-owned subsidiary of Midstream Holdings ("EnLink Midstream Services"), entered into 10-year gathering and processing agreements with Devon pursuant to which EnLink Midstream Services provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon Gas Services, L.P., a subsidiary of Devon ("Gas Services"), to Midstream Holdings’ gathering and processing systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. On January 1, 2014, SWG Pipeline, L.L.C. (“SWG Pipeline”), another wholly-owned subsidiary of Midstream Holdings, entered into a 10-year gathering agreement with Devon pursuant to which SWG Pipeline provides gathering, treating, compression, dehydration and redelivery services, as applicable, for natural gas delivered by Gas Services to another of the Partnership's gathering systems in the Barnett Shale.

These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. Pursuant to the gathering and processing agreements entered into on January 1, 2014, Devon has committed to deliver specified average minimum daily volumes of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter for a five-year period following execution. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

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

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

Effective December 1, 2014, Gas Services assigned one of its 10-year gathering and processing agreements to Linn Exchange Properties, LLC (“Linn Energy”), which is a subsidiary of Linn Energy, LLC, in connection with Gas Services' divestiture of certain of its southeastern Oklahoma assets. Accordingly, beginning on December 1, 2014, Linn Energy began performing Gas Services' obligations under the applicable agreement, which relates to production dedicated to our Northridge assets in southeastern Oklahoma and remains in full force and effect.

Other Commercial Relationships with Devon

As noted above, the Partnership continues to maintain a customer relationship with Devon originally established prior to the business combination pursuant to which the Partnership provides gathering, transportation, processing and gas lift services to Devon in exchange for fee-based compensation under several agreements with Devon.  The terms of these agreements vary, but the agreements expire between October 2015 and July 2021, renewing automatically for month-to-month or year-to-year periods unless canceled by Devon prior to expiration.  In addition, the Partnership has agreements with Devon pursuant to which the Partnership purchases and sells NGLs, gas and crude oil and pays or receives, as applicable, a margin-based fee.  These NGL, gas and crude oil purchase and sale agreements have month-to-month terms.

VEX Transportation Agreement

In connection with the VEX acquisition, the Operating Partnership became party to a five year transportation services agreement with Devon pursuant to which the Operating Partnership provides transportation services to Devon on the VEX pipeline.
Transition Services Agreement

In connection with the consummation of the business combination, the Partnership entered into a transition services agreement with Devon pursuant to which Devon provides certain services to the Partnership with respect to the business and operations of Midstream Holdings and the Partnership provides certain services to Devon. General and administrative expenses related to the transition service agreement were $0.1 million and $0.2 million for the three and nine months ended September 30, 2015, respectively and $1.0 million and $2.3 million for the three and nine months ended September 30, 2014, respectively. We received $0.2 million from Devon under the transition services agreement for the nine months ended September 30, 2015. Substantially all services under the transition services agreement were completed during 2014.

Drop Down Transactions

During the fourth quarter of 2014 and the first half of 2015, the Partnership acquired assets from ENLC and Devon through drop down transactions. See Note 3 - Acquisitions for further discussion.

Predecessor Affiliate Transactions

Prior to March 7, 2014, affiliate transactions relate to Predecessor transactions consisting of sales to and from affiliates, services provided by affiliates, cost allocations from affiliates and centralized cash management activities performed by affiliates.

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

 
Nine Months Ended September 30, 2014
Continuing Operations:
 
Revenues - affiliates
$
(436.4
)
Operating cost and expenses - affiliates
340.0

Net affiliate transactions
(96.4
)
Capital expenditures
16.2

Other third-party transactions, net
53.0

Net third-party transactions
69.2

Net cash distributions to Devon - continuing operations
(27.2
)
Non-cash distribution of net assets to Devon
(23.5
)
Total net distributions per equity
$
(50.7
)
 
 
Discontinued operations:
 
Revenues - affiliates
$
(10.4
)
Operating costs and expenses - affiliates
5.0

Net affiliate transactions
(5.4
)
Capital expenditures
0.6

Other third-party transactions, net
0.4

Net third-party transactions
1.0

Net cash distributions to Devon and non-controlling interests - discontinued operations
(4.4
)
Non-cash distribution of net assets to Devon
(39.9
)
Total net distributions per equity
$
(44.3
)
Total distributions- continuing and discontinued operations
$
(95.0
)


Share-based compensation costs included in the management services fee charged to Midstream Holdings by Devon were approximately $2.8 million for the nine months ended September 30, 2014. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Partnership by Devon were approximately $1.6 million for the nine months ended September 30, 2014. These amounts are included in general and administrative expenses in the accompanying statements of operations.
Long-Term Debt
Long-Term Debt
(6) Long-Term Debt

As of September 30, 2015 and December 31, 2014, long-term debt consisted of the following (in millions):
 
September 30,
2015
 
December 31,
2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at September 30, 2015 and December 31, 2014 was 1.5% and 1.9%, respectively
$
175.0

 
$
237.0

Senior unsecured notes (due 2019), net of discount of $0.4 million at September 30, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70%
399.6

 
399.5

Senior unsecured notes (due 2022), including a premium of $19.7 million at September 30, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%
182.2

 
184.4

Senior unsecured notes (due 2024), net of premium of $2.9 million at September 30, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%
552.9

 
553.2

Senior unsecured notes (due 2025), net of discount of $1.2 million at September 30, 2015, which bear interest at the rate of 4.15%
748.8

 
—

Senior unsecured notes (due 2044), net of discount of $0.3 million at September 30, 2015 and December 31, 2014, which bear interest at the rate of 5.60%
349.7

 
349.7

Senior unsecured notes (due 2045), net of discount of $6.9 million at September 30, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%
443.1

 
298.3

Other debt
0.2

 
0.4

Debt classified as long-term
$
2,851.5

 
$
2,022.5



Credit Facility

On February 20, 2014, the Partnership entered into a $1.0 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”). On February 5, 2015, the Partnership exercised the accordion under the Partnership credit facility, increasing the size of the facility to $1.5 billion and also exercised an option to extend the maturity date of the Partnership credit facility to March 6, 2020. The Partnership also entered into certain amendments to the Partnership credit facility pursuant to which the Partnership is permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under the Partnership 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 the Partnership credit facility by one year on each occasion. The Partnership credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the Partnership credit facility, which definition includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If the Partnership consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA may be increased to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

Borrowings under the Partnership credit facility bear interest at the Partnership’s option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin. The applicable margins vary depending on the Partnership’s credit rating. Upon breach by the Partnership of certain covenants governing the Partnership credit facility, amounts outstanding under the Partnership credit facility, if any, may become due and payable immediately.

As of September 30, 2015, there were $2.8 million in outstanding letters of credit and $175.0 million in outstanding borrowings under the Partnership credit facility, leaving approximately $1.3 billion available for future borrowing based on the borrowing capacity of $1.5 billion.

All other material terms and conditions of the Partnership credit facility are described in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014, as recast by the Partnership's Current Report on Form 8-K dated May 28, 2015. The Partnership expects to be in compliance with all credit facility covenants for at least the next twelve months.

On May 12, 2015, the Partnership issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of its 4.150% senior notes due 2025 (the “2025 Notes”) and $150.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 Notes” and together with the 2025 Notes, "Senior Notes") at prices to the public of 99.827% and 96.381%, respectively, of their face value. The 2025 Notes mature on June 1, 2025 and the 2045 Notes mature on April 1, 2045. Interest payments on the 2025 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2015. Interest payments on the 2045 Notes are payable on April 1 and October 1 of each year, beginning October 1, 2015.

Prior to March 1, 2025, the 2025 Notes are redeemable, at the option of the Partnership, at any time in whole, or from time to time in part, at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2025 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2025 Notes to be redeemed that would be due if the 2025 Notes matured on March 1, 2025 (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus, in either case, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after March 1, 2025, the 2025 Notes are redeemable, at the option of the Partnership, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2025 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to October 1, 2044, the Partnership may redeem all or a part of the 2045 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2045 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2045 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus, in either case, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after October 1, 2044, the Partnership may redeem all or a part of the 2045 Notes at a redemption price equal to 100% of the principal amount of the 2045 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

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

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

•
failure to pay any principal or interest when due;

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

•
our default under other indebtedness that exceeds a certain threshold amount;

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

•
bankruptcy or other insolvency events involving us.

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

(a) Issuance of Common Units

In November 2014, the Partnership 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 the Partnership’s common units from time to time through an “at the market” equity offering program. The Partnership 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. The Partnership has 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 nine months ended September 30, 2015, the Partnership sold an aggregate of 0.7 million common units under the BMO EDA, generating proceeds of approximately $12.9 million (net of less than $0.1 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of September 30, 2015, approximately $328.7 million remains available to be issued under the BMO EDA.

(b) Class C Common Units

In March 2015, the Partnership issued 6,704,285 Class C Common Units representing a new class of limited partner interests as partial consideration for the acquisition of Coronado. For further discussion see Note 3- Acquisitions. The Class C Common Units are substantially similar in all respects to the Partnership's 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 the General Partner in its sole discretion. The Class C Common Units will automatically convert into common units on a one-for-one basis on the earlier to occur of (i) the date on which the General Partner, in its sole discretion, determines to convert all of the outstanding Class C Common Units into common units and (ii) the first business day following the date of the distribution for the quarter ended March 31, 2016. Distributions on the Class C Common Units for the three months ended March 31, 2015 and June 30, 2015 were paid-in-kind ("PIK") through the issuance of 99,794 and 120,622 Class C Common Units on May 14, 2015 and August 13, 2015, respectively. A distribution on the Class C Common Units of $0.390 per unit was declared for the three months ended September 30, 2015, which will result in the issuance of 150,732 additional Class C Common Units on November 12, 2015.

(c) Class D Common Units

In February 2015, the Partnership issued 31,618,311 Class D Common Units to Acacia as consideration for a 25% interest in Midstream Holdings. For further discussion see Note 3 - Acquisitions. The Partnership’s Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution from the date of issuance for the fiscal quarter ended March 31, 2015. The Partnership’s Class D Common Units automatically converted into the Partnership’s common units on a one-for-one basis on May 4, 2015.

(d) Class E Common Units

In May 2015, the Partnership issued 36,629,888 Class E Common Units to Acacia as consideration for the remaining 25% interest in Midstream Holdings. For further discussion, see Note 3 - Acquisitions. The Partnership’s Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution from the date of issuance for the fiscal quarter ended June 30, 2015. The Partnership’s Class E Common Units automatically converted into the Partnership’s common units on a one-for-one basis on August 3, 2015.

(e)  Distributions
 
Unless restricted by the terms of the Partnership credit facility and/or the indentures governing the Partnership's senior unsecured notes, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions are made to the General Partner in accordance with its current percentage interest with the remainder to the common unitholders, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. The General Partner is not entitled to its general partner or incentive distributions with respect to the Class C Common 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 nine months ended September 30, 2015 is provided below:
Declaration period
 
Distribution/unit
 
Date paid/payable
Fourth Quarter of 2014
 
$
0.375

 
February 12, 2015
First Quarter of 2015 (1)
 
$
0.38

 
May 14, 2015
Second Quarter of 2015 (2)
 
$
0.385

 
August 13, 2015
Third Quarter of 2015
 
$
0.39

 
November 12, 2015

(1)
The Partnership's partial first quarter 2015 distributions on its Class D Common Units of $0.18 per unit were paid on May 14, 2015. Distributions paid for the Class D Common Units represent a pro rata distribution for the number of days the Class D Common Units were issued and outstanding during the quarter. The Class D Common Units automatically converted into common units on a one-for-one basis on May 4, 2015.
(2)
The Partnership's partial second quarter 2015 distributions on its Class E Common Units of $0.15 per unit were paid on August 13, 2015. Distributions paid for the Class E Common Units represent a pro rata distribution for the number of days the Class E Common Units were issued and outstanding during the quarter. The Class E Common Units automatically converted into common units on a one-for-one basis on August 3, 2015.

(f) Earnings per Unit and Dilution Computations
 
As required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations. Net income earned by the Predecessor prior to March 7, 2014 is not included for purposes of calculating earnings per unit as the Predecessor did not have any unitholders.  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
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014*
Limited partners’ interest in net income (loss)
$
(745.2
)
 
$
40.5

 
$
(700.5
)
 
$
86.5

Distributed earnings allocated to:
 
 
 
 
 
 
 
Common units (1) (2) (3)
$
125.2

 
$
85.4

 
$
339.5

 
$
220.7

Unvested restricted units (1)
0.5

 
0.4

 
1.5

 
0.9

Total distributed earnings
$
125.7

 
$
85.8

 
$
341.0

 
$
221.6

Undistributed loss allocated to:
 
 
 
 
 
 
 
Common units (2) (3)
$
(867.6
)
 
$
(45.1
)
 
$
(1,037.1
)
 
$
(134.6
)
Unvested restricted units
(3.3
)
 
(0.2
)
 
(4.4
)
 
(0.5
)
Total undistributed loss
$
(870.9
)
 
$
(45.3
)
 
$
(1,041.5
)
 
$
(135.1
)
Net income (loss) allocated to:
 
 
 
 
 
 
0

Common units (2) (3)
$
(742.4
)
 
$
40.3

 
$
(697.6
)
 
$
86.1

Unvested restricted units
(2.8
)
 
0.2

 
(2.9
)
 
0.4

Total limited partners’ interest in net income (loss)
$
(745.2
)
 
$
40.5

 
$
(700.5
)
 
$
86.5

Basic and diluted net income (loss) per unit:
 
 
 
 
 
 
 
Basic
$
(2.32
)
 
$
0.18

 
$
(2.38
)
 
$
0.38

Diluted
$
(2.32
)
 
$
0.18

 
$
(2.38
)
 
$
0.38

* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.
(1)
Three months ended September 30, 2015 and 2014 represents a declared distribution of $0.39 per unit payable on November 12, 2015 and a distribution of $0.37 per unit paid on November 13, 2014, respectively.
(2)
Nine months ended September 30, 2015 and 2014 represents a declared distribution of $0.39 per unit payable on November 12, 2015, and distributions paid of $0.38 per unit on May 14, 2015, $0.385 per unit on August 13, 2015, $0.36 per unit on May 14, 2014, $0.365 per unit on August 13, 2014 and $0.37 per unit on November 13, 2014.
(3)
Nine months ended September 30, 2015 includes a partial distribution of $0.15 per unit for Class E Common Units paid on August 13, 2015 and a partial distribution of $0.18 per unit for Class D Common Units paid on May 14, 2015. The nine months ended September 30, 2014 includes a partial distribution of $0.10 per unit for Class B Common Units paid on May 14, 2014.
 
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 September 30,
 
Nine Months Ended September 30,
Basic weighted average units outstanding:
2015
 
2014
 
2015
 
2014*
Weighted average limited partner basic common units outstanding
321.0

 
231.0

 
294.0

 
230.3

Weighted average Class C Common Units outstanding
6.9

 
—

 
4.9

 
—

    Total weighted average limited partner common units outstanding
327.9

 
231.0

 
298.9

 
230.3

Diluted weighted average units outstanding:
 
 
 
 
 
 
 
Weighted average limited partner basic common units outstanding
327.9

 
231.0

 
298.9

 
230.3

Dilutive effect of restricted units issued
—

 
0.4

 
—

 
0.3

    Total weighted average limited partner diluted common units outstanding
327.9

 
231.4

 
298.9

 
230.6


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

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the periods presented.

Net income is allocated to the General Partner in an amount equal to its incentive distributions as described in Note 7(e). The General Partner's share of net income consists of incentive distributions to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of the Partnership’s net income adjusted for ENLC's unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows for the periods presented (in millions).
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014*
Income allocation for incentive distributions
$
13.6

 
$
6.3

 
$
33.7

 
$
13.6

Unit-based compensation attributable to ENLC’s restricted units
(3.7
)
 
(3.1
)
 
(14.6
)
 
(6.8
)
General Partner share of net income (loss)
(3.6
)
 
0.3

 
(3.3
)
 
0.7

General Partner interest in drop down transactions
—

 
39.4

 
34.4

 
89.3

General Partner interest in net income
$
6.3

 
$
42.9

 
$
50.2

 
$
96.8


* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.
Asset Retirement Obligation
Asset Retirement Obligation Disclosure
(8) Asset Retirement Obligations

The schedule below summarizes the changes in the Partnership’s asset retirement obligation:
 
September 30,
2015
 
September 30,
2014
 
(in millions)
Beginning asset retirement obligation
$
20.6

 
$
8.1

Revisions to existing liabilities
(4.0
)
 
3.2

Liabilities acquired
—

 
0.5

Accretion
0.4

 
0.4

Liabilities settled
(3.2
)
 
—

Ending asset retirement obligation
$
13.8

 
$
12.2



Asset retirement obligations of $1.0 million and $8.2 million as of September 30, 2015 and December 31, 2014, respectively are included in Other Current Liabilities.
Investment in Unconsolidated Affiliate
Investment in unconsolidated affiliate
(9) Investment in Unconsolidated Affiliates

The Partnership’s unconsolidated investments consisted of a contractual right to the economic benefits and burdens associated with Devon's 38.75% ownership interest in GCF at September 30, 2015 and 2014 and a 30.6% ownership interest in Howard Energy Partners ("HEP") at September 30, 2015 and 2014.

The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):
 
Gulf Coast Fractionators
 
Howard Energy Partners
 
Total
Three months ended
 
 
 
 
 
September 30, 2015
 
 
 
 
 
Contributions
$
—

 
$
8.1

 
$
8.1

Distributions
$
3.8

 
$
8.4

 
$
12.2

Equity in income
$
3.4

 
$
3.0

 
$
6.4

 
 
 
 
 
 
September 30, 2014 (1)
 
 
 
 
 
Contributions
$
—

 
$
—

 
$
—

Distributions
$
5.2

 
$
3.0

 
$
8.2

Equity in income
$
5.2

 
$
0.4

 
$
5.6

 
 
 
 
 
 
Nine months ended
 
 
 
 
 
September 30, 2015
 
 
 
 
 
Contributions
$
—

 
$
8.1

 
$
8.1

Distributions
$
10.7

 
$
20.7

 
$
31.4

Equity in income
$
9.7

 
$
6.4

 
$
16.1

 
 
 
 
 
 
September 30, 2014 (1)
 
 
 
 
 
Contributions
$
—

 
$
5.7

 
$
5.7

Distributions
$
5.2

 
$
8.7

 
$
13.9

Equity in income
$
13.2

 
$
1.1

 
$
14.3

(1) Includes income, distributions, and contributions for the period from March 7, 2014 through September 30, 2014 for HEP.

The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):
 
September 30,
2015
 
December 31,
2014
Gulf Coast Fractionators
$
53.0

 
$
54.1

Howard Energy Partners
210.5

 
216.7

Total investments in unconsolidated affiliates
$
263.5

 
$
270.8

Employee Incentive Plans
Employee Incentive Plans
(10) Employee Incentive Plans
 
(a)         Long-Term Incentive Plans
 
The Partnership accounts for unit-based compensation in accordance with FASB ASC 718, which requires that compensation related to all unit-based awards, including unit options, be recognized in the consolidated financial statements.

The Partnership 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 officers and employees of the Partnership are recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions): 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
Cost of unit-based compensation allocated to Predecessor general and
    administrative expense (1)
$
—

 
$
—

 
$
—

 
$
2.8

Cost of unit-based compensation charged to general and administrative
    expense
6.3

 
4.9

 
24.6

 
10.9

Cost of unit-based compensation charged to operating expense
1.0

 
0.8

 
4.0

 
1.8

    Total amount charged to income
$
7.3

 
$
5.7

 
$
28.6

 
$
15.5


(1)
Unit-based compensation expense was treated as a contribution by the Predecessor in the Consolidated Statement of Changes in Partners' Equity in 2014.

(b)  EnLink Midstream Partners, LP Restricted Incentive Units
 
The Partnership's restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, 2015 is provided below:
 
 
Nine Months Ended 
September 30, 2015
EnLink Midstream Partners, LP Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
 Fair Value
Non-vested, beginning of period
 
1,022,191

 
$
31.25

Granted
 
581,047

 
26.82

Vested*
 
(264,651
)
 
28.81

Forfeited
 
(68,913
)
 
30.92

Non-vested, end of period
 
1,269,674

 
$
29.75

Aggregate intrinsic value, end of period (in millions)
 
$
20.0

 
 


 * Vested units include 90,567 units withheld for payroll taxes paid on behalf of employees.

The Partnership issued restricted incentive units in the first quarter of 2015 to officers and other employees. These restricted incentive units typically vest at the end of three years. In March 2015, the Partnership issued 128,675 restricted incentive units with a fair value of $3.4 million to officers and certain employees as bonus payments for 2014, which vested immediately and are included in the restricted units granted and vested line items above.
 
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and nine months ended September 30, 2015 are provided below (in millions):

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
EnLink Midstream Partners, LP Restricted Incentive Units:
 
2015

2014
 
2015
 
2014
Aggregate intrinsic value of units vested
 
$
0.1


$
1.2

 
$
7.2

 
$
1.2

Fair value of units vested
 
$
0.1


$
1.2

 
$
7.6

 
$
1.2



As of September 30, 2015, there was $19.5 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 1.7 years.

(c)  EnLink Midstream Partners, LP Performance Units

In March 2015, the Partnership and ENLC granted performance awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the "GP Plan") and the 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 the Partnership 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 with respect to the number of performance units vested. The vesting of units may be between zero and 200 percent of the units granted depending on the EnLink TSR as compared to the peer group 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 the Partnership and the designated peer group; (iii) an estimated ranking of the Partnership 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:
 
2015
Beginning TSR Price
 
$
27.68

Risk-free interest rate
 
0.99
%
Volatility factor
 
33.01
%
Distribution yield
 
5.66
%


The following table presents a summary of the Partnership's performance units.
 
 
Nine Months Ended 
September 30, 2015
EnLink Midstream Partners, LP Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
—

 
$
—

Granted
 
118,126

 
35.41

Vested
 
—

 
—

Non-vested, end of period
 
118,126

 
$
35.41

Aggregate intrinsic value, end of period (in millions)
 
$
1.9

 



As of September 30, 2015, there was $3.3 million of unrecognized compensation expense that related to non-vested Partnership performance units. That cost is expected to be recognized over a weighted-average period of 2.3 years.

(d)         EnLink Midstream, LLC’s Restricted Incentive Units
 
ENLC’s restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of the common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, 2015 is provided below:
 
 
Nine Months Ended 
September 30, 2015
EnLink Midstream, LLC Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-vested, beginning of period
 
986,472

 
$
37.03

Granted
 
493,582

 
31.58

Vested*
 
(261,144
)
 
35.79

Forfeited
 
(59,203
)
 
35.99

Non-vested, end of period
 
1,159,707

 
$
35.04

Aggregate intrinsic value, end of period (in millions)
 
$
21.2

 
 


* Vested units include 83,176 units withheld for payroll taxes paid on behalf of employees.

ENLC issued restricted incentive units in the first quarter of 2015 to officers and other employees. These restricted incentive units typically vest at the end of three years and are included in restricted incentive units outstanding. In March 2015, ENLC issued 102,543 restricted incentive units with a fair value of $3.4 million to officers and certain employees as bonus payments for 2014, which vested immediately and are included in the restricted units granted and vested line items above.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and nine months ended September 30, 2015 are provided below (in millions):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
EnLink Midstream, LLC Restricted Incentive Units:
 
2015
 
2014
 
2015
 
2014
Aggregate intrinsic value of units vested
 
$
0.1

 
$
2.4

 
$
8.9

 
$
2.4

Fair value of units vested
 
$
0.1

 
$
2.2

 
$
9.3

 
$
2.2



As of September 30, 2015, there was $20.2 million of unrecognized compensation costs related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted-average period of 1.7 years.


(e) EnLink Midstream, LLC's Performance Units

In March 2015, ENLC granted performance awards under the LLC Plan discussed in Note (c) above. At the end of the vesting period, recipients receive distribution equivalents with respect to the number of performance units vested. The vesting of units may be between zero and 200 percent of the units granted depending on EnLink’s TSR as compared to the peer group 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 and the designated peer group; (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:
 
2015
Beginning TSR Price
 
$
34.24

Risk-free interest rate
 
0.99
%
Volatility factor
 
33.02
%
Distribution yield
 
2.98
%


The following table presents a summary of the ENLC's performance units.
 
 
Nine Months Ended 
September 30, 2015
EnLink Midstream, LLC Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
—

 
$
—

Granted
 
105,080

 
40.5

Vested
 
—

 
—

Non-vested, end of period
 
105,080

 
$
40.5

Aggregate intrinsic value, end of period (in millions)
 
$
1.9

 



As of September 30, 2015, there was $3.3 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 2.3 years.
Derivatives
Derivatives
(11) Derivatives
 
Interest Rate Swaps

The Partnership entered into interest rate swaps in April and May 2015 in connection with the issuance of the 2025 Notes in May 2015.        
        
The impact of the interest rate swaps on net income is included in other income (expense) in the Condensed Consolidated Statements of Operations as part of interest expense, net, as follows (in millions):
 
 
Three Months Ended September 30, 2015
 
Nine Months Ended September 30, 2015
Settlement gains on derivatives
 
$
—

 
$
3.6



Commodity Swaps

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

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

The components of gain (loss) on derivative activity in the Condensed Consolidated Statements of Operations relating to commodity swaps are as follows for the three and nine months ended September 30, 2015 and 2014 (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014*
Change in fair value of derivatives
$
(0.2
)
 
$
1.8

 
$
(6.4
)
 
$
(0.2
)
Realized gain (loss) on derivatives
5.4

 
(0.8
)
 
13.0

 
(1.7
)
    Gain (loss) on derivative activity
$
5.2

 
$
1.0

 
$
6.6

 
$
(1.9
)

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

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

 
September 30,
2015
 
December 31,
2014
Fair value of derivative assets — current
$
15.5

 
$
16.7

Fair value of derivative assets — long term
2.9

 
10.0

Fair value of derivative liabilities — current
(3.4
)
 
(3.0
)
Fair value of derivative liabilities — long term
(0.5
)
 
(2.0
)
    Net fair value of derivatives
$
14.5

 
$
21.7


 
Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets at September 30, 2015. The remaining term of the contracts extend no later than December 2016.

 
 
 
 
 
 
September 30, 2015
Commodity
 
Instruments
 
Unit
 
Volume
 
Fair Value
 
 
 
 
 
 
(In millions)
NGL (short contracts)
 
Swaps
 
Gallons
 
(53.3
)
 
$
16.4

NGL (long contracts)
 
Swaps
 
Gallons
 
35.8

 
(2.4
)
Natural Gas (short contracts)
 
Swaps
 
MMBtu
 
(3.1
)
 
1.3

Natural Gas (long contracts)
 
Swaps
 
MMBtu
 
1.3

 
(0.9
)
Condensate (long contracts)
 
Swaps
 
MBbls
 
0.1

 
0.1

Total fair value of derivatives
 
 
 
 
 
 
 
$
14.5


 
On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty's financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis. The Partnership primarily deals with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. The Partnership has entered into Master International Swaps and Derivatives Association Agreements ("ISDAs") that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership's counterparties failed to perform under existing swap contracts, the Partnership's maximum loss as of September 30, 2015 of $18.4 million would be reduced to $14.5 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs. 

Fair Value of Derivative Instruments

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

 
Maturity Periods
 
Less than one year
 
One to two years
 
More than two years
 
Total fair value
September 30, 2015
$
12.1

 
$
2.4

 
$
—

 
$
14.5

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, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.
 
FASB ASC 820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.
 
The Partnership’s derivative contracts primarily consist of commodity swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy.
 
Net liabilities measured at fair value on a recurring basis are summarized below (in millions):
 
September 30, 2015
Level 2
 
December 31, 2014
Level 2
Commodity Swaps*
$
14.5

 
$
21.7

Total
$
14.5

 
$
21.7

 
*                 The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.
 
Fair Value of Financial Instruments
 
The estimated fair value of the Partnership’s financial instruments has been determined by the Partnership using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Partnership could realize upon the sale or refinancing of such financial instruments (in millions):
 
September 30, 2015
 
December 31, 2014
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Long-term debt
$
2,851.5

 
$
2,663.2

 
$
2,022.5

 
$
2,026.1

Obligations under capital leases
$
17.7

 
$
17.0

 
$
20.3

 
$
19.8


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

The Partnership had $175.0 million and $237.0 million in outstanding borrowings under its revolving credit facility as of September 30, 2015 and December 31, 2014, 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 September 30, 2015, the Partnership 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%. As of December 31, 2014, the Partnership had total borrowings of $1.8 billion 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 September 30, 2015 and December 31, 2014 was based on Level 2 inputs from third-party market quotations.  The fair value of obligations under capital leases was calculated using Level 2 inputs from third-party banks.
Commitments and Contingencies
Commitments and Contingencies Disclosure
(13) Commitments and Contingencies
 
(a) Severance and Change in Control Agreements
 
Certain members of management of the Partnership are parties to severance and change of control agreements with the General Partner. 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 the General Partner or its affiliates during his employment. In addition, the severance and change of control agreements prohibit subject individuals from disclosing confidential information about the General Partner or interfering with a client or customer of the General Partner or its affiliates, in each case during his employment and for a certain period of time following the termination of such person’s employment.
 
(b) Environmental Issues
 
The operation of pipelines, plants and other facilities for the gathering, processing, transmitting or disposing of natural gas, NGLs, 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, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's results of operations, financial condition or cash flows.

(c) Litigation Contingencies
 
The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position, results of operations or cash flows. 

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

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

In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans, but was removed to the United States District Court for the Eastern District of Louisiana.  The amount of damages is unspecified. The Partnership's subsidiary, 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. The Partnership intends to continue vigorously defending the case. The success of the plaintiffs' appeal as well as the Partnership's 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 sued our insurers, but we have agreed to stay the matter pending resolution of our claims against Texas Brine and its 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 a subsidiary of the Partnership, 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 the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

In October 2014, Williams Olefins, L.L.C. filed a lawsuit against a subsidiary of the Partnership, EnLink NGL Marketing, LP, in the District Court of Tulsa County, Oklahoma. The plaintiff alleges breach of contract and negligent misrepresentation relating to an ethane output contract between the parties and the subsidiary’s termination of ethane production from one of its fractionation plants. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership’s costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case.
Segment Information
Segment Information
(14) Segment Information
 
Identification of the majority of the Partnership's operating segments is based principally upon geographic regions served.  The Partnership’s reportable segments consist of the following: natural gas gathering, processing, transmission and fractionation operations located in north Texas, south Texas and the Permian Basin in west Texas ("Texas"), the pipelines and processing plants located in Louisiana and NGL assets located in south Louisiana ("Louisiana"), natural gas gathering and processing operations located throughout Oklahoma ("Oklahoma") and crude rail, truck, pipeline and barge facilities in west Texas, south Texas, Louisiana and Ohio River Valley ("Crude and Condensate"). The Partnership's Crude and Condensate segment, which is identified based upon the nature of services provided to customers of the segment, has historically been referred to as the Partnership's ORV segment. Due to the growth in this segment, including the acquisitions of LPC and VEX, the Partnership has renamed this segment to more accurately reflect the assets included therein. The Partnership has restated the prior period to include certain crude and condensate activity in the Crude and Condensate segment. Operating activity for intersegment eliminations is shown in the corporate segment.  The Partnership’s sales are derived from external domestic customers.

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




Summarized financial information concerning the Partnership’s reportable segments is shown in the following tables:
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
 
(In millions)
Three Months Ended September 30, 2015
 

 
 

 
 

 
 

 
 

 
 

Product sales
$
106.9

 
$
399.0

 
$
3.9

 
$
353.7

 
$
—

 
$
863.5

Product sales-affiliates
35.3

 
17.6

 
4.6

 
0.4

 
(17.6
)
 
40.3

Midstream services
20.3

 
63.3

 
9.4

 
18.3

 
—

 
111.3

Midstream services-affiliates
111.6

 
5.1

 
34.5

 
3.6

 
(4.5
)
 
150.3

Cost of sales
(124.5
)
 
(415.2
)
 
(9.4
)
 
(334.8
)
 
22.1

 
(861.8
)
Operating expenses
(44.3
)
 
(27.2
)
 
(7.2
)
 
(26.3
)
 
—

 
(105.0
)
Gain on derivative activity
—

 
—

 
—

 
—

 
5.2

 
5.2

Segment profit
$
105.3

 
$
42.6

 
$
35.8

 
$
14.9

 
$
5.2

 
$
203.8

Depreciation and amortization
$
(44.4
)
 
$
(27.4
)
 
$
(11.9
)
 
$
(12.9
)
 
$
(1.8
)
 
$
(98.4
)
Impairments
$
—

 
$
(576.1
)
 
$
—

 
$
(223.1
)
 
$
—

 
$
(799.2
)
Goodwill
$
1,186.8

 
$
210.7

 
$
190.3

 
$
142.1

 
$
—

 
$
1,729.9

Capital expenditures
$
29.0

 
$
13.5

 
$
19.7

 
$
38.6

 
$
3.9

 
$
104.7

Three Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
52.5

 
$
426.5

 
$
—

 
$
100.1

 
$
—

 
$
579.1

Product sales-affiliates
19.2

 
36.4

 
—

 
—

 
(17.8
)
 
37.8

Midstream services
19.1

 
38.9

 
—

 
10.6

 
—

 
68.6

Midstream services-affiliates
122.7

 
2.0

 
45.8

 
2.4

 
(2.0
)
 
170.9

Cost of sales
(64.2
)
 
(462.6
)
 
—

 
(90.2
)
 
19.8

 
(597.2
)
Operating expenses
(37.9
)
 
(20.3
)
 
(7.0
)
 
(14.6
)
 
—

 
(79.8
)
Gain on litigation settlement
—

 
6.1

 
—

 
—

 
—

 
6.1

Gain on derivative activity
—

 
—

 
—

 
—

 
1.0

 
1.0

Segment profit
$
111.4

 
$
27.0

 
$
38.8

 
$
8.3

 
$
1.0

 
$
186.5

Depreciation and amortization
$
(31.6
)
 
$
(19.1
)
 
$
(11.8
)
 
$
(11.2
)
 
$
(0.9
)
 
$
(74.6
)
Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
—

 
$
2,257.8

Capital expenditures
$
79.7

 
$
79.1

 
$
2.5

 
$
43.8

 
$
3.9

 
$
209.0

 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
237.3

 
$
1,173.6

 
$
2.4

 
$
1,075.5

 
$
—

 
$
2,488.8

Product sales-affiliates
91.5

 
37.4

 
10.2

 
0.8

 
(50.3
)
 
89.6

Midstream services
76.2

 
184.5

 
29.9

 
60.7

 
—

 
351.3

Midstream services-affiliates
342.5

 
14.3

 
94.7

 
10.6

 
(12.8
)
 
449.3

Cost of sales
(305.1
)
 
(1,210.4
)
 
(14.6
)
 
(1,020.4
)
 
63.1

 
(2,487.4
)
Operating expenses
(136.9
)
 
(78.7
)
 
(23.3
)
 
(73.7
)
 
—

 
(312.6
)
Gain on derivative activity
—

 
—

 
—

 
—

 
6.6

 
6.6

Segment profit
$
305.5

 
$
120.7

 
$
99.3

 
$
53.5

 
$
6.6

 
$
585.6

Depreciation and amortization
$
(123.6
)
 
$
(81.8
)
 
$
(37.2
)
 
$
(41.5
)
 
$
(5.0
)
 
$
(289.1
)
Impairments
$
—

 
$
(576.1
)
 
$
—

 
$
(223.1
)
 
$
—

 
$
(799.2
)
Goodwill
$
1,186.8

 
$
210.7

 
$
190.3

 
$
142.1

 
$
—

 
$
1,729.9

Capital expenditures
$
183.4

 
$
43.4

 
$
37.2

 
$
170.6

 
$
10.6

 
$
445.2

Nine Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
167.0

 
$
1,075.6

 
$
11.5

 
$
226.3

 
$
—

 
$
1,480.4

Product sales-affiliates
331.1

 
38.7

 
147.9

 
—

 
(43.5
)
 
474.2

Midstream services
38.6

 
87.3

 
—

 
28.9

 
—

 
154.8

Midstream services-affiliates
289.7

 
2.0

 
108.1

 
2.4

 
(2.0
)
 
400.2

Cost of sales
(397.6
)
 
(1,104.2
)
 
(133.9
)
 
(207.8
)
 
45.5

 
(1,798.0
)
Operating expenses
(108.2
)
 
(41.9
)
 
(21.0
)
 
(29.3
)
 
—

 
(200.4
)
Gain on litigation settlement
—

 
6.1

 
—

 
—

 
—

 
6.1

Loss on derivative activity
—

 
—

 


 
—

 
(1.9
)
 
(1.9
)
Segment profit
$
320.6

 
$
63.6

 
$
112.6

 
$
20.5

 
$
(1.9
)
 
$
515.4

Depreciation and amortization
$
(91.7
)
 
$
(43.4
)
 
$
(37.6
)
 
$
(23.4
)
 
$
(1.5
)
 
$
(197.6
)
Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
—

 
$
2,257.8

Capital expenditures
$
180.2

 
$
222.4

 
$
10.5

 
$
91.3

 
$
12.6

 
$
517.0



The table below presents information about segment assets as of September 30, 2015 and December 31, 2014:
 
September 30,
 2015
 
December 31,
2014
Segment Identifiable Assets:
(In millions)
Texas
$
3,995.0

 
$
3,302.9

Louisiana
2,562.3

 
3,316.5

Oklahoma
895.7

 
892.8

Crude and Condensate
980.8

 
871.8

Corporate
334.2

 
318.0

Total identifiable assets
$
8,768.0

 
$
8,702.0


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

Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
Segment profits
$
203.8

 
$
186.5

 
$
585.6

 
$
515.4

General and administrative expenses
(33.5
)
 
(23.5
)
 
(102.3
)
 
(64.8
)
Loss on disposition of assets
(3.2
)
 
—

 
(3.2
)
 
—

Depreciation and amortization
(98.4
)
 
(74.6
)
 
(289.1
)
 
(197.6
)
Impairments
(799.2
)
 
—

 
(799.2
)
 
—

Operating income (loss)
$
(730.5
)
 
$
88.4

 
$
(608.2
)
 
$
253.0

Discontinued Operations
Disposal Groups, Including Discontinued Operations, Disclosure
(15) Discontinued Operations

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

The following schedule summarizes net income from discontinued operations (in millions):
 
Nine Months Ended
September 30,
 
2014
Revenues:
 
Revenues
$
6.8

Revenues - affiliates
10.5

Total revenues
17.3

 
 
Operating costs and expenses:
 
Operating expenses
15.7

Total operating costs and expenses
15.7

 
 
Income before income taxes
1.6

Income tax provision
0.6

Net income
$
1.0

Supplemental Cash Flow Information (Notes)
Cash Flow, Supplemental Disclosures
(16) Supplemental Cash Flow Information

The following schedule summarizes non-cash financing activities for the period presented.
 
 
Nine Months Ended
September 30,
 
 
2015
 
 
(In millions)
Non-cash financing activities:
 
 
     Non-cash issuance of common units (1)
 
$
180.0

     Non-cash issuance of Class C Common Units (1)
 
$
180.0

     Non-cash adjustment of interest in Midstream Holdings (2)
 
$
66.5


(1) Non-cash common units and Class C Common Units were issued as partial consideration for the Coronado acquisition. See Note 3 - Acquisitions for further discussion.
(2) Non-cash adjustment to reflect recast of Midstream Holdings' interests acquired on February 17, 2015 and May 27, 2015. See Note 3 - Acquisitions for further discussion.

Also, see Note 5 - Affiliate Transactions for non-cash activities related to Predecessor operations with Devon prior to March 7, 2014.
Other Information (Notes)
Other Liabilities Disclosure [Text Block]
(17) Other Information

The following tables present additional detail for certain balance sheet captions.

Other Current Liabilities

Other current liabilities consisted of the following:
 
September 30, 2015
 
December 31, 2014
 
(in millions)
Accrued interest
$
54.7

 
$
16.9

Accrued wages and benefits, including taxes
29.9

 
19.7

Accrued ad valorem taxes
30.2

 
23.2

Capital expenditure accruals
18.4

 
22.6

Suspense producer payments
17.5

 
—

Other
55.2

 
67.4

Other current liabilities
$
205.9

 
$
149.8

Subsequent Events (Notes)
Subsequent Events [Text Block]
(18) Subsequent Events

Acquisition of Natural Gas Gathering and Processing Assets. On October 1, 2015, the Partnership acquired all of the voting interests in DLK Wolf Midstream, LLC, a subsidiary of MRC Energy Company, which owns natural gas gathering and processing assets predominantly located in west Texas for $143.0 million, subject to certain adjustments. The natural gas assets include a cryogenic gas processing plant and approximately 6 miles of high-pressure gathering pipeline within the Delaware Basin. Due to the timing of this acquisition, the Partnership has not yet completed its initial accounting and analysis.

Issuance of Common Units. On October 29, 2015, the Partnership issued 2,849,100 common units to a subsidiary of ENLC for aggregate consideration of approximately $50.0 million in a private placement transaction.
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.

Further, the unaudited condensed consolidated financial statements give effect to the business combination and related transactions discussed in Note 1(a) above under the acquisition method of accounting and are treated as a reverse acquisition. Under the acquisition method of accounting, Midstream Holdings was the accounting acquirer in the transactions because its parent company, Devon, obtained control of the Partnership through the indirect control of the General Partner as a result of the business combination. All financial results prior to March 7, 2014 reflect the historical operations of Midstream Holdings and are reflected as Predecessor income in the statement of operations. Additionally, the Partnership’s assets acquired and liabilities assumed by Midstream Holdings in the business combination were recorded at their fair values measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of the Partnership’s net assets acquired was recorded as goodwill. Financial results subsequent to March 7, 2014 reflect the combined operations of Midstream Holdings and the Partnership, which give effect to new contracts entered into with Devon and include the legacy Partnership assets. Certain assets were not contributed to Midstream Holdings from the Predecessor and the operations of such non contributed assets have been presented as discontinued operations. In conjunction with the business combination, Midstream Holdings became a non-taxable entity that was treated as a reorganization under common control with the removal of historical deferred taxes reflected through equity.

Revenue Recognition, Policy [Policy Text Block] 
(b) Revenue Recognition

The Partnership generates the majority of its revenues from midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization and brine services, through various contractual arrangements, which include fee based contract arrangements or arrangements where it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the Partnership's transactions vary in form, the essential element of each transaction is the use of its assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal or pipeline. The Partnership reflects revenue as Product sales and Midstream services revenue on the Condensed Consolidated Statements of Operations as follows:

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

•
Midstream services - Midstream services represents all other revenue generated as a result of performing the Partnership's midstream services outlined above.

The Partnership recognizes revenue for sales or services at the time the natural gas, NGLs, crude oil or condensate are delivered or at the time the service is performed at a fixed or determinable price. The Partnership generally accrues one month of sales and the related natural gas, NGL, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. Except for fixed-fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, bearing the risk and reward of ownership as evidenced by title transfer, scheduling the transportation of products and assuming credit risk. The Partnership accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).
    
Redeemable Noncontrolling Interest [Policy Text Block] 
(c) Redeemable Non-Controlling Interest

Non-controlling interests that contain an option for the non-controlling interest holder to require the Partnership to buy out such interests for cash are considered to be redeemable non-controlling interests because the redemption feature is not deemed to be a freestanding financial instrument and because the redemption is not solely within the control of the Partnership. Redeemable non-controlling interest is not considered to be a component of partners' equity and is reported as temporary equity in the mezzanine section on the Condensed Consolidated Balance Sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holder's share of net income or loss and distributions).

New Accounting Pronouncements, Policy [Policy Text Block] 

(d) Recent Accounting Pronouncements

In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments ("ASU 2015-16"), 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. ASU 2015-16 is effective for public business entities for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. For all other entities, ASU 2015-16 is effective for fiscal years beginning after December 15, 2016, and interim periods within fiscal years beginning after December 15, 2017. Early adoption is permitted. The update is effective for us beginning on January 1, 2016.

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 this standard will have on our condensed consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835). The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard requires retrospective application and is effective for us beginning on January 1, 2016.

In April 2015, the FASB issued 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 fiscal years. ASU 2015-06 requires retrospective application and early adoption is permitted.

In February 2015, the FASB issued 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. The update is effective for us beginning on January 1, 2016, and we are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures.

Subject to these evaluations, we have reviewed all recently issued accounting pronouncements that became effective during the nine months ended September 30, 2015, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.
Acquisition (Table)
9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Business Acquisition [Line Items]
 
 
ScheduleOfPriorPeriodAdjustmentsRelatedToAssetDropDown [Table Text Block]
Text Block 
Text Block 
BusinessAcquisitionProFormaInformation
Text Block 
 
Chevron Acquisition [Member]
 
 
Business Acquisition [Line Items]
 
 
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed
Text Block 
 
LPC [Member]
 
 
Business Acquisition [Line Items]
 
 
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed
Text Block 
 
Coronado [Member]
 
 
Business Acquisition [Line Items]
 
 
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed
Text Block 
 
ScheduleOfPriorPeriodAdjustmentsRelatedToAssetDropDown [Table Text Block] 
The following tables present the collective impact of the E2 Drop Down, the VEX Drop Down and the EMH Drop Downs as presented in the Partnership's historical Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and the nine months ended September 30, 2015:
 
 
Nine Months Ended September 30, 2015
 
 
Partnership Historical
 
EMH
 
VEX
 
Combined
 
 
(in millions)
Revenues
 
$
3,381.4

 
$
—

 
$
4.2

 
$
3,385.6

Net income (loss)
 
$
(666.5
)
 
$
—

 
$
0.7

 
$
(665.8
)
Net income attributable to non-controlling interest
 
$
15.0

 
$
(15.3
)
 
$
—

 
$
(0.3
)
Net income (loss) attributable to EnLink Midstream Partners, LP
 
$
(681.5
)
 
$
15.3

 
$
0.7

 
$
(665.5
)
General partner interest in net income (loss)
 
$
34.2

 
$
15.3

 
$
0.7

 
$
50.2

ScheduleOfPriorPeriodAdjustmentsRelatedToAssetDropDown [Table Text Block] 
 
 
Three Months Ended September 30, 2014
 
 
Partnership Historical
 
EMH
 
E2
 
VEX
 
Combined
 
 
(in millions)
Revenues
 
$
851.4

 
$
—

 
$
3.6

 
$
2.4

 
$
857.4

Net income (loss)
 
$
85.7

 
$
—

 
$
0.1

 
$
(2.3
)
 
$
83.5

Net income attributable to non-controlling interest
 
$
41.7

 
$
(41.7
)
 
$
0.1

 
$
—

 
$
0.1

Net income (loss) attributable to EnLink Midstream
    Partners, LP
 
$
44.0

 
$
41.7

 
$
—

 
$
(2.3
)
 
$
83.4

General partner interest in net income (loss)
 
$
3.5

 
$
41.7

 
$
—

 
$
(2.3
)
 
$
42.9



 
 
Nine Months Ended September 30, 2014
 
 
Partnership Historical
 
EMH*
 
E2
 
VEX**
 
Combined
 
 
(in millions)
Revenues
 
$
2,498.0

 
$
—

 
$
7.3

 
$
2.4

 
$
2,507.7

Net income (loss)
 
$
224.3

 
$
—

 
$
—

 
$
(5.3
)
 
$
219.0

Net income attributable to non-controlling interest
 
$
94.8

 
$
(94.8
)
 
$
0.2

 
$
—

 
$
0.2

Net income (loss) attributable to EnLink Midstream
Partners, LP
 
$
129.5

 
$
94.8

 
$
(0.2
)
 
$
(5.3
)
 
$
218.8

General partner interest in net income (loss)
 
$
7.5

 
$
94.8

 
$
(0.2
)
 
$
(5.3
)
 
$
96.8

* Represents the Transferred Interests amounts for the period from March 7, 2014 through September 30, 2014.
BusinessAcquisitionProFormaInformation 
The following unaudited pro forma condensed financial information for the nine months ended September 30, 2015 and the three and nine months ended September 30, 2014 gives effect to the business combination, Chevron acquisition, Coronado acquisition, LPC acquisition, EMH Drop Downs, VEX Drop Down and E2 Drop Down as if they had occurred on January 1, 2014. 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 business combination and acquisitions is reflected below.
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2014
 
2015
 
2014
 
(in millions)
Pro forma total revenues (1)
 
$
1,398.7

 
$
3,507.7

 
$
4,232.0

Pro forma net income (loss)
 
$
72.1

 
$
(671.4
)
 
$
177.7

Pro forma net income (loss) attributable to EnLink Midstream Partners, LP
 
$
72.1

 
$
(671.1
)
 
$
177.6

Pro forma net income (loss) per common unit:
 
 
 


 
 
Basic
 
$
0.13

 
$
(2.39
)
 
$
0.24

Diluted
 
$
0.13

 
$
(2.39
)
 
$
0.24

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.
Purchase Price Allocation (in millions):
 
 
Assets acquired:
 
 
Property, plant and equipment
 
$
225.3

Intangibles
 
13.0

Liabilities assumed:
 
 
Current liabilities
 
(6.8
)
Total identifiable net assets
 
$
231.5

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.

Purchase Price Allocation (in millions):
 
 
Assets acquired:
 
 
Current assets (including $21.1 million in cash)
 
$
107.4

Property, plant and equipment
 
29.8

Intangibles
 
43.2

Goodwill
 
29.6

Liabilities assumed:
 
 
Current liabilities
 
(97.9
)
Deferred tax liability
 
(4.0
)
Total identifiable net assets
 
$
108.1


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 (including $1.4 million in cash)
 
$
20.8

Property, plant and equipment
 
302.1

Intangibles
 
281.0

  Goodwill
 
18.6

Liabilities assumed:
 
 
Current liabilities
 
(22.3
)
Total identifiable net assets
 
$
600.2

Goodwill and Intangible Assets (Tables)
Schedule of Goodwill 
The table below provides a summary of the Partnership’s change in carrying amount of goodwill, by assigned reporting unit.
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
 
(in millions)
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
Balance, beginning of period
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
—

 
$
2,257.8

Acquisitions (1)
18.6

 
—

 
—

 
29.6

 
—

 
48.2

Impairment
—

 
(576.1
)
 
—

 
—

 
—

 
(576.1
)
Balance, end of period
$
1,186.8

 
$
210.7

 
$
190.3

 
$
142.1

 
$
—

 
$
1,729.9


(1)See Note 3-Acquisitions for further discussion.
Schedule of Finite-Lived Intangible Assets 
The following table represents the Partnership's change in carrying value of intangible assets for the periods stated (in millions):
 
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
Carrying
Amount
Nine Months Ended September 30, 2015
 
 
 
 
 
 
Customer relationships, beginning of period
 
$
569.5

 
$
(36.5
)
 
$
533.0

Acquisitions
 
337.2

 
—

 
337.2

Amortization expense
 
—

 
(44.3
)
 
(44.3
)
Impairment
 
(261.0
)
 
37.9

 
(223.1
)
Customer relationships, end of period
 
$
645.7

 
$
(42.9
)
 
$
602.8

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense 
The following table summarizes the Partnership's estimated aggregate amortization expense for the next five years (in millions):

2015 (remaining)
$
10.3

2016
41.2

2017
41.2

2018
41.2

2019
41.2

Thereafter
427.7

Total
$
602.8

Affiliate Transactions (Tables)
Schedule of Related Party Transactions [Table Text Block]
The following presents financial information for the Predecessor's affiliate transactions and other transactions with Devon, all of which are settled through an adjustment to equity prior to March 7, 2014 (in millions):

 
Nine Months Ended September 30, 2014
Continuing Operations:
 
Revenues - affiliates
$
(436.4
)
Operating cost and expenses - affiliates
340.0

Net affiliate transactions
(96.4
)
Capital expenditures
16.2

Other third-party transactions, net
53.0

Net third-party transactions
69.2

Net cash distributions to Devon - continuing operations
(27.2
)
Non-cash distribution of net assets to Devon
(23.5
)
Total net distributions per equity
$
(50.7
)
 
 
Discontinued operations:
 
Revenues - affiliates
$
(10.4
)
Operating costs and expenses - affiliates
5.0

Net affiliate transactions
(5.4
)
Capital expenditures
0.6

Other third-party transactions, net
0.4

Net third-party transactions
1.0

Net cash distributions to Devon and non-controlling interests - discontinued operations
(4.4
)
Non-cash distribution of net assets to Devon
(39.9
)
Total net distributions per equity
$
(44.3
)
Total distributions- continuing and discontinued operations
$
(95.0
)
Long-Term Debt (Tables)
Indebtedness Table
As of September 30, 2015 and December 31, 2014, long-term debt consisted of the following (in millions):
 
September 30,
2015
 
December 31,
2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at September 30, 2015 and December 31, 2014 was 1.5% and 1.9%, respectively
$
175.0

 
$
237.0

Senior unsecured notes (due 2019), net of discount of $0.4 million at September 30, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70%
399.6

 
399.5

Senior unsecured notes (due 2022), including a premium of $19.7 million at September 30, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%
182.2

 
184.4

Senior unsecured notes (due 2024), net of premium of $2.9 million at September 30, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%
552.9

 
553.2

Senior unsecured notes (due 2025), net of discount of $1.2 million at September 30, 2015, which bear interest at the rate of 4.15%
748.8

 
—

Senior unsecured notes (due 2044), net of discount of $0.3 million at September 30, 2015 and December 31, 2014, which bear interest at the rate of 5.60%
349.7

 
349.7

Senior unsecured notes (due 2045), net of discount of $6.9 million at September 30, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%
443.1

 
298.3

Other debt
0.2

 
0.4

Debt classified as long-term
$
2,851.5

 
$
2,022.5

Partners' Capital (Tables)
Distributions Made to Limited Partner, by Distribution 
A summary of the distribution activity relating to the common units for the nine months ended September 30, 2015 is provided below:
Declaration period
 
Distribution/unit
 
Date paid/payable
Fourth Quarter of 2014
 
$
0.375

 
February 12, 2015
First Quarter of 2015 (1)
 
$
0.38

 
May 14, 2015
Second Quarter of 2015 (2)
 
$
0.385

 
August 13, 2015
Third Quarter of 2015
 
$
0.39

 
November 12, 2015
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
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014*
Limited partners’ interest in net income (loss)
$
(745.2
)
 
$
40.5

 
$
(700.5
)
 
$
86.5

Distributed earnings allocated to:
 
 
 
 
 
 
 
Common units (1) (2) (3)
$
125.2

 
$
85.4

 
$
339.5

 
$
220.7

Unvested restricted units (1)
0.5

 
0.4

 
1.5

 
0.9

Total distributed earnings
$
125.7

 
$
85.8

 
$
341.0

 
$
221.6

Undistributed loss allocated to:
 
 
 
 
 
 
 
Common units (2) (3)
$
(867.6
)
 
$
(45.1
)
 
$
(1,037.1
)
 
$
(134.6
)
Unvested restricted units
(3.3
)
 
(0.2
)
 
(4.4
)
 
(0.5
)
Total undistributed loss
$
(870.9
)
 
$
(45.3
)
 
$
(1,041.5
)
 
$
(135.1
)
Net income (loss) allocated to:
 
 
 
 
 
 
0

Common units (2) (3)
$
(742.4
)
 
$
40.3

 
$
(697.6
)
 
$
86.1

Unvested restricted units
(2.8
)
 
0.2

 
(2.9
)
 
0.4

Total limited partners’ interest in net income (loss)
$
(745.2
)
 
$
40.5

 
$
(700.5
)
 
$
86.5

Basic and diluted net income (loss) per unit:
 
 
 
 
 
 
 
Basic
$
(2.32
)
 
$
0.18

 
$
(2.38
)
 
$
0.38

Diluted
$
(2.32
)
 
$
0.18

 
$
(2.38
)
 
$
0.38

* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.
(1)
Three months ended September 30, 2015 and 2014 represents a declared distribution of $0.39 per unit payable on November 12, 2015 and a distribution of $0.37 per unit paid on November 13, 2014, respectively.
(2)
Nine months ended September 30, 2015 and 2014 represents a declared distribution of $0.39 per unit payable on November 12, 2015, and distributions paid of $0.38 per unit on May 14, 2015, $0.385 per unit on August 13, 2015, $0.36 per unit on May 14, 2014, $0.365 per unit on August 13, 2014 and $0.37 per unit on November 13, 2014.
(3)
Nine months ended September 30, 2015 includes a partial distribution of $0.15 per unit for Class E Common Units paid on August 13, 2015 and a partial distribution of $0.18 per unit for Class D Common Units paid on May 14, 2015. The nine months ended September 30, 2014 includes a partial distribution of $0.10 per unit for Class B Common Units paid on May 14, 2014.
 
Schedule of Weighted Average Number of Shares 
The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the periods presented (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Basic weighted average units outstanding:
2015
 
2014
 
2015
 
2014*
Weighted average limited partner basic common units outstanding
321.0

 
231.0

 
294.0

 
230.3

Weighted average Class C Common Units outstanding
6.9

 
—

 
4.9

 
—

    Total weighted average limited partner common units outstanding
327.9

 
231.0

 
298.9

 
230.3

Diluted weighted average units outstanding:
 
 
 
 
 
 
 
Weighted average limited partner basic common units outstanding
327.9

 
231.0

 
298.9

 
230.3

Dilutive effect of restricted units issued
—

 
0.4

 
—

 
0.3

    Total weighted average limited partner diluted common units outstanding
327.9

 
231.4

 
298.9

 
230.6


* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.
Incentive Distributions 
Net income is allocated to the General Partner in an amount equal to its incentive distributions as described in Note 7(e). The General Partner's share of net income consists of incentive distributions to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of the Partnership’s net income adjusted for ENLC's unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows for the periods presented (in millions).
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014*
Income allocation for incentive distributions
$
13.6

 
$
6.3

 
$
33.7

 
$
13.6

Unit-based compensation attributable to ENLC’s restricted units
(3.7
)
 
(3.1
)
 
(14.6
)
 
(6.8
)
General Partner share of net income (loss)
(3.6
)
 
0.3

 
(3.3
)
 
0.7

General Partner interest in drop down transactions
—

 
39.4

 
34.4

 
89.3

General Partner interest in net income
$
6.3

 
$
42.9

 
$
50.2

 
$
96.8


* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.
Asset Retirement Obligation (Table)
Schedule of Change in Asset Retirement Obligation
The schedule below summarizes the changes in the Partnership’s asset retirement obligation:
 
September 30,
2015
 
September 30,
2014
 
(in millions)
Beginning asset retirement obligation
$
20.6

 
$
8.1

Revisions to existing liabilities
(4.0
)
 
3.2

Liabilities acquired
—

 
0.5

Accretion
0.4

 
0.4

Liabilities settled
(3.2
)
 
—

Ending asset retirement obligation
$
13.8

 
$
12.2

Investment in Unconsolidated Affiliate (Tables)
Equity Method Investments
The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):
 
September 30,
2015
 
December 31,
2014
Gulf Coast Fractionators
$
53.0

 
$
54.1

Howard Energy Partners
210.5

 
216.7

Total investments in unconsolidated affiliates
$
263.5

 
$
270.8

The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):
 
Gulf Coast Fractionators
 
Howard Energy Partners
 
Total
Three months ended
 
 
 
 
 
September 30, 2015
 
 
 
 
 
Contributions
$
—

 
$
8.1

 
$
8.1

Distributions
$
3.8

 
$
8.4

 
$
12.2

Equity in income
$
3.4

 
$
3.0

 
$
6.4

 
 
 
 
 
 
September 30, 2014 (1)
 
 
 
 
 
Contributions
$
—

 
$
—

 
$
—

Distributions
$
5.2

 
$
3.0

 
$
8.2

Equity in income
$
5.2

 
$
0.4

 
$
5.6

 
 
 
 
 
 
Nine months ended
 
 
 
 
 
September 30, 2015
 
 
 
 
 
Contributions
$
—

 
$
8.1

 
$
8.1

Distributions
$
10.7

 
$
20.7

 
$
31.4

Equity in income
$
9.7

 
$
6.4

 
$
16.1

 
 
 
 
 
 
September 30, 2014 (1)
 
 
 
 
 
Contributions
$
—

 
$
5.7

 
$
5.7

Distributions
$
5.2

 
$
8.7

 
$
13.9

Equity in income
$
13.2

 
$
1.1

 
$
14.3

(1) Includes income, distributions, and contributions for the period from March 7, 2014 through September 30, 2014 for HEP.
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:
 
2015
Beginning TSR Price
 
$
27.68

Risk-free interest rate
 
0.99
%
Volatility factor
 
33.01
%
Distribution yield
 
5.66
%
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:
 
2015
Beginning TSR Price
 
$
34.24

Risk-free interest rate
 
0.99
%
Volatility factor
 
33.02
%
Distribution yield
 
2.98
%
Schedule of Nonvested Performance-based Units Activity [Table Text Block] 
The following table presents a summary of the ENLC's performance units.
 
 
Nine Months Ended 
September 30, 2015
EnLink Midstream, LLC Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
—

 
$
—

Granted
 
105,080

 
40.5

Vested
 
—

 
—

Non-vested, end of period
 
105,080

 
$
40.5

Aggregate intrinsic value, end of period (in millions)
 
$
1.9

 

The following table presents a summary of the Partnership's performance units.
 
 
Nine Months Ended 
September 30, 2015
EnLink Midstream Partners, LP Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
—

 
$
—

Granted
 
118,126

 
35.41

Vested
 
—

 
—

Non-vested, end of period
 
118,126

 
$
35.41

Aggregate intrinsic value, end of period (in millions)
 
$
1.9

 

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 and nine months ended September 30, 2015 are provided below (in millions):

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
EnLink Midstream Partners, LP Restricted Incentive Units:
 
2015

2014
 
2015
 
2014
Aggregate intrinsic value of units vested
 
$
0.1


$
1.2

 
$
7.2

 
$
1.2

Fair value of units vested
 
$
0.1


$
1.2

 
$
7.6

 
$
1.2

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
EnLink Midstream, LLC Restricted Incentive Units:
 
2015
 
2014
 
2015
 
2014
Aggregate intrinsic value of units vested
 
$
0.1

 
$
2.4

 
$
8.9

 
$
2.4

Fair value of units vested
 
$
0.1

 
$
2.2

 
$
9.3

 
$
2.2

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs 
The Partnership 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 officers and employees of the Partnership are recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions): 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
Cost of unit-based compensation allocated to Predecessor general and
    administrative expense (1)
$
—

 
$
—

 
$
—

 
$
2.8

Cost of unit-based compensation charged to general and administrative
    expense
6.3

 
4.9

 
24.6

 
10.9

Cost of unit-based compensation charged to operating expense
1.0

 
0.8

 
4.0

 
1.8

    Total amount charged to income
$
7.3

 
$
5.7

 
$
28.6

 
$
15.5


(1)
Unit-based compensation expense was treated as a contribution by the Predecessor in the Consolidated Statement of Changes in Partners' Equity in 2014.
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity 
A summary of the restricted incentive unit activity for the nine months ended September 30, 2015 is provided below:
 
 
Nine Months Ended 
September 30, 2015
EnLink Midstream Partners, LP Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
 Fair Value
Non-vested, beginning of period
 
1,022,191

 
$
31.25

Granted
 
581,047

 
26.82

Vested*
 
(264,651
)
 
28.81

Forfeited
 
(68,913
)
 
30.92

Non-vested, end of period
 
1,269,674

 
$
29.75

Aggregate intrinsic value, end of period (in millions)
 
$
20.0

 
 


 * Vested units include 90,567 units withheld for payroll taxes paid on behalf of employees.
A summary of the restricted incentive unit activity for the nine months ended September 30, 2015 is provided below:
 
 
Nine Months Ended 
September 30, 2015
EnLink Midstream, LLC Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-vested, beginning of period
 
986,472

 
$
37.03

Granted
 
493,582

 
31.58

Vested*
 
(261,144
)
 
35.79

Forfeited
 
(59,203
)
 
35.99

Non-vested, end of period
 
1,159,707

 
$
35.04

Aggregate intrinsic value, end of period (in millions)
 
$
21.2

 
 


* Vested units include 83,176 units withheld for payroll taxes paid on behalf of employees.
Derivatives (Tables)
Schedule of Interest Rate Derivatives [Table Text Block] 
The impact of the interest rate swaps on net income is included in other income (expense) in the Condensed Consolidated Statements of Operations as part of interest expense, net, as follows (in millions):
 
 
Three Months Ended September 30, 2015
 
Nine Months Ended September 30, 2015
Settlement gains on derivatives
 
$
—

 
$
3.6

Commodity Swap 
The components of gain (loss) on derivative activity in the Condensed Consolidated Statements of Operations relating to commodity swaps are as follows for the three and nine months ended September 30, 2015 and 2014 (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014*
Change in fair value of derivatives
$
(0.2
)
 
$
1.8

 
$
(6.4
)
 
$
(0.2
)
Realized gain (loss) on derivatives
5.4

 
(0.8
)
 
13.0

 
(1.7
)
    Gain (loss) on derivative activity
$
5.2

 
$
1.0

 
$
6.6

 
$
(1.9
)

* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014. 
Fair Value of Derivative Assets and Liabilities relating to commodity swaps 
The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions):

 
September 30,
2015
 
December 31,
2014
Fair value of derivative assets — current
$
15.5

 
$
16.7

Fair value of derivative assets — long term
2.9

 
10.0

Fair value of derivative liabilities — current
(3.4
)
 
(3.0
)
Fair value of derivative liabilities — long term
(0.5
)
 
(2.0
)
    Net fair value of derivatives
$
14.5

 
$
21.7

Notional Amount and Fair Value of Derivative Instruments 
Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets at September 30, 2015. The remaining term of the contracts extend no later than December 2016.

 
 
 
 
 
 
September 30, 2015
Commodity
 
Instruments
 
Unit
 
Volume
 
Fair Value
 
 
 
 
 
 
(In millions)
NGL (short contracts)
 
Swaps
 
Gallons
 
(53.3
)
 
$
16.4

NGL (long contracts)
 
Swaps
 
Gallons
 
35.8

 
(2.4
)
Natural Gas (short contracts)
 
Swaps
 
MMBtu
 
(3.1
)
 
1.3

Natural Gas (long contracts)
 
Swaps
 
MMBtu
 
1.3

 
(0.9
)
Condensate (long contracts)
 
Swaps
 
MBbls
 
0.1

 
0.1

Total fair value of derivatives
 
 
 
 
 
 
 
$
14.5

Derivatives Other than Cash Flow Hedges 
The estimated fair value of derivative contracts by maturity date was as follows (in millions):

 
Maturity Periods
 
Less than one year
 
One to two years
 
More than two years
 
Total fair value
September 30, 2015
$
12.1

 
$
2.4

 
$
—

 
$
14.5

Fair Value Measurements (Tables)
Fair Value Derivative Instrument 
Net liabilities measured at fair value on a recurring basis are summarized below (in millions):
 
September 30, 2015
Level 2
 
December 31, 2014
Level 2
Commodity Swaps*
$
14.5

 
$
21.7

Total
$
14.5

 
$
21.7

 
*                 The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.
Fair Value Financial Instrument 
Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Partnership could realize upon the sale or refinancing of such financial instruments (in millions):
 
September 30, 2015
 
December 31, 2014
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Long-term debt
$
2,851.5

 
$
2,663.2

 
$
2,022.5

 
$
2,026.1

Obligations under capital leases
$
17.7

 
$
17.0

 
$
20.3

 
$
19.8

Segement Information (Tables)
Partnership Reportable Segement 



Summarized financial information concerning the Partnership’s reportable segments is shown in the following tables:
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
 
(In millions)
Three Months Ended September 30, 2015
 

 
 

 
 

 
 

 
 

 
 

Product sales
$
106.9

 
$
399.0

 
$
3.9

 
$
353.7

 
$
—

 
$
863.5

Product sales-affiliates
35.3

 
17.6

 
4.6

 
0.4

 
(17.6
)
 
40.3

Midstream services
20.3

 
63.3

 
9.4

 
18.3

 
—

 
111.3

Midstream services-affiliates
111.6

 
5.1

 
34.5

 
3.6

 
(4.5
)
 
150.3

Cost of sales
(124.5
)
 
(415.2
)
 
(9.4
)
 
(334.8
)
 
22.1

 
(861.8
)
Operating expenses
(44.3
)
 
(27.2
)
 
(7.2
)
 
(26.3
)
 
—

 
(105.0
)
Gain on derivative activity
—

 
—

 
—

 
—

 
5.2

 
5.2

Segment profit
$
105.3

 
$
42.6

 
$
35.8

 
$
14.9

 
$
5.2

 
$
203.8

Depreciation and amortization
$
(44.4
)
 
$
(27.4
)
 
$
(11.9
)
 
$
(12.9
)
 
$
(1.8
)
 
$
(98.4
)
Impairments
$
—

 
$
(576.1
)
 
$
—

 
$
(223.1
)
 
$
—

 
$
(799.2
)
Goodwill
$
1,186.8

 
$
210.7

 
$
190.3

 
$
142.1

 
$
—

 
$
1,729.9

Capital expenditures
$
29.0

 
$
13.5

 
$
19.7

 
$
38.6

 
$
3.9

 
$
104.7

Three Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
52.5

 
$
426.5

 
$
—

 
$
100.1

 
$
—

 
$
579.1

Product sales-affiliates
19.2

 
36.4

 
—

 
—

 
(17.8
)
 
37.8

Midstream services
19.1

 
38.9

 
—

 
10.6

 
—

 
68.6

Midstream services-affiliates
122.7

 
2.0

 
45.8

 
2.4

 
(2.0
)
 
170.9

Cost of sales
(64.2
)
 
(462.6
)
 
—

 
(90.2
)
 
19.8

 
(597.2
)
Operating expenses
(37.9
)
 
(20.3
)
 
(7.0
)
 
(14.6
)
 
—

 
(79.8
)
Gain on litigation settlement
—

 
6.1

 
—

 
—

 
—

 
6.1

Gain on derivative activity
—

 
—

 
—

 
—

 
1.0

 
1.0

Segment profit
$
111.4

 
$
27.0

 
$
38.8

 
$
8.3

 
$
1.0

 
$
186.5

Depreciation and amortization
$
(31.6
)
 
$
(19.1
)
 
$
(11.8
)
 
$
(11.2
)
 
$
(0.9
)
 
$
(74.6
)
Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
—

 
$
2,257.8

Capital expenditures
$
79.7

 
$
79.1

 
$
2.5

 
$
43.8

 
$
3.9

 
$
209.0

 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
237.3

 
$
1,173.6

 
$
2.4

 
$
1,075.5

 
$
—

 
$
2,488.8

Product sales-affiliates
91.5

 
37.4

 
10.2

 
0.8

 
(50.3
)
 
89.6

Midstream services
76.2

 
184.5

 
29.9

 
60.7

 
—

 
351.3

Midstream services-affiliates
342.5

 
14.3

 
94.7

 
10.6

 
(12.8
)
 
449.3

Cost of sales
(305.1
)
 
(1,210.4
)
 
(14.6
)
 
(1,020.4
)
 
63.1

 
(2,487.4
)
Operating expenses
(136.9
)
 
(78.7
)
 
(23.3
)
 
(73.7
)
 
—

 
(312.6
)
Gain on derivative activity
—

 
—

 
—

 
—

 
6.6

 
6.6

Segment profit
$
305.5

 
$
120.7

 
$
99.3

 
$
53.5

 
$
6.6

 
$
585.6

Depreciation and amortization
$
(123.6
)
 
$
(81.8
)
 
$
(37.2
)
 
$
(41.5
)
 
$
(5.0
)
 
$
(289.1
)
Impairments
$
—

 
$
(576.1
)
 
$
—

 
$
(223.1
)
 
$
—

 
$
(799.2
)
Goodwill
$
1,186.8

 
$
210.7

 
$
190.3

 
$
142.1

 
$
—

 
$
1,729.9

Capital expenditures
$
183.4

 
$
43.4

 
$
37.2

 
$
170.6

 
$
10.6

 
$
445.2

Nine Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
167.0

 
$
1,075.6

 
$
11.5

 
$
226.3

 
$
—

 
$
1,480.4

Product sales-affiliates
331.1

 
38.7

 
147.9

 
—

 
(43.5
)
 
474.2

Midstream services
38.6

 
87.3

 
—

 
28.9

 
—

 
154.8

Midstream services-affiliates
289.7

 
2.0

 
108.1

 
2.4

 
(2.0
)
 
400.2

Cost of sales
(397.6
)
 
(1,104.2
)
 
(133.9
)
 
(207.8
)
 
45.5

 
(1,798.0
)
Operating expenses
(108.2
)
 
(41.9
)
 
(21.0
)
 
(29.3
)
 
—

 
(200.4
)
Gain on litigation settlement
—

 
6.1

 
—

 
—

 
—

 
6.1

Loss on derivative activity
—

 
—

 


 
—

 
(1.9
)
 
(1.9
)
Segment profit
$
320.6

 
$
63.6

 
$
112.6

 
$
20.5

 
$
(1.9
)
 
$
515.4

Depreciation and amortization
$
(91.7
)
 
$
(43.4
)
 
$
(37.6
)
 
$
(23.4
)
 
$
(1.5
)
 
$
(197.6
)
Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
—

 
$
2,257.8

Capital expenditures
$
180.2

 
$
222.4

 
$
10.5

 
$
91.3

 
$
12.6

 
$
517.0

Segment Table reconciliation to Condensed Consolidated Financial Statement 
The table below presents information about segment assets as of September 30, 2015 and December 31, 2014:
 
September 30,
 2015
 
December 31,
2014
Segment Identifiable Assets:
(In millions)
Texas
$
3,995.0

 
$
3,302.9

Louisiana
2,562.3

 
3,316.5

Oklahoma
895.7

 
892.8

Crude and Condensate
980.8

 
871.8

Corporate
334.2

 
318.0

Total identifiable assets
$
8,768.0

 
$
8,702.0

Reconciliation of Operating Profit (Loss) from Segments to Consolidated 
The following table reconciles the segment profits reported above to the operating income as reported in the condensed consolidated statements of operations (in millions):

Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
Segment profits
$
203.8

 
$
186.5

 
$
585.6

 
$
515.4

General and administrative expenses
(33.5
)
 
(23.5
)
 
(102.3
)
 
(64.8
)
Loss on disposition of assets
(3.2
)
 
—

 
(3.2
)
 
—

Depreciation and amortization
(98.4
)
 
(74.6
)
 
(289.1
)
 
(197.6
)
Impairments
(799.2
)
 
—

 
(799.2
)
 
—

Operating income (loss)
$
(730.5
)
 
$
88.4

 
$
(608.2
)
 
$
253.0

Discontinued Operations (Tables)
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures
The following schedule summarizes net income from discontinued operations (in millions):
 
Nine Months Ended
September 30,
 
2014
Revenues:
 
Revenues
$
6.8

Revenues - affiliates
10.5

Total revenues
17.3

 
 
Operating costs and expenses:
 
Operating expenses
15.7

Total operating costs and expenses
15.7

 
 
Income before income taxes
1.6

Income tax provision
0.6

Net income
$
1.0

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.
 
 
Nine Months Ended
September 30,
 
 
2015
 
 
(In millions)
Non-cash financing activities:
 
 
     Non-cash issuance of common units (1)
 
$
180.0

     Non-cash issuance of Class C Common Units (1)
 
$
180.0

     Non-cash adjustment of interest in Midstream Holdings (2)
 
$
66.5

Other Information (Tables)
Other Current Liabilities [Table Text Block]
The following tables present additional detail for certain balance sheet captions.

Other Current Liabilities

Other current liabilities consisted of the following:
 
September 30, 2015
 
December 31, 2014
 
(in millions)
Accrued interest
$
54.7

 
$
16.9

Accrued wages and benefits, including taxes
29.9

 
19.7

Accrued ad valorem taxes
30.2

 
23.2

Capital expenditure accruals
18.4

 
22.6

Suspense producer payments
17.5

 
—

Other
55.2

 
67.4

Other current liabilities
$
205.9

 
$
149.8

General (Details)
0 Months Ended 9 Months Ended 0 Months Ended
Mar. 7, 2014
Sep. 30, 2015
Mar. 7, 2014
May 27, 2015
EMH Drop Down [Member]
Affiliated Entity [Member]
Midstream Holdings [Member]
EnLink Midstream LP [Member]
May 27, 2015
EMH Drop Down [Member]
Affiliated Entity [Member]
EnLink Midstream LP [Member]
Midstream Holdings [Member]
Acacia [Member]
EnLink Midstream Holdings, LP [Member]
Feb. 17, 2015
EMH Drop Down [Member]
Affiliated Entity [Member]
EnLink Midstream LP [Member]
Midstream Holdings [Member]
Acacia [Member]
EnLink Midstream Holdings, LP [Member]
Feb. 17, 2015
Class D Common Unit [Member]
EMH Drop Down [Member]
Affiliated Entity [Member]
EnLink Midstream LP [Member]
Midstream Holdings [Member]
Acacia [Member]
EnLink Midstream Holdings, LP [Member]
May 27, 2015
Class E Common Unit [Member] [Member]
EMH Drop Down [Member]
Affiliated Entity [Member]
EnLink Midstream LP [Member]
Midstream Holdings [Member]
Acacia [Member]
EnLink Midstream Holdings, LP [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
Noncash or Part Noncash Acquisition, Interest Acquired
 
 
50.00% 
 
 
 
 
 
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares
120,542,441 
 
 
 
 
 
 
 
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest
 
70.00% 
 
 
 
 
 
 
Related Party Transaction, Ownership Interest Transferred
 
 
 
 
25.00% 
25.00% 
 
 
Related Party Transaction, Amounts of Transaction, Shares
 
 
 
 
 
 
31,618,311 
36,629,888 
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions
 
 
 
100.00% 
 
 
 
 
Acquisition (Details Textuals) (USD $)
In Millions, except Share data, unless otherwise specified
0 Months Ended 3 Months Ended 9 Months Ended 7 Months Ended 0 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended 9 Months Ended 0 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 0 Months Ended
Mar. 7, 2014
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Apr. 1, 2015
Mar. 7, 2014
Sep. 30, 2014
Crosstex Energy L.P. [Domain]
Apr. 1, 2015
VEX Pipeline [Member]
Apr. 1, 2015
VEX Pipeline [Member]
Sep. 30, 2014
VEX [Member]
Sep. 30, 2015
VEX [Member]
Sep. 30, 2014
VEX [Member]
Sep. 30, 2014
ENLK Historical [Member]
Sep. 30, 2015
ENLK Historical [Member]
Sep. 30, 2014
ENLK Historical [Member]
Nov. 1, 2014
Chevron Acquisition [Member]
Sep. 30, 2015
Chevron Acquisition [Member]
Nov. 1, 2014
Chevron Acquisition [Member]
Jan. 31, 2015
LPC [Member]
Sep. 30, 2015
LPC [Member]
Jan. 31, 2015
LPC [Member]
Mar. 16, 2015
Coronado [Member]
Sep. 30, 2015
Coronado [Member]
Mar. 16, 2015
Coronado [Member]
Oct. 22, 2014
E2 [Member]
Sep. 30, 2014
E2 [Member]
Sep. 30, 2014
E2 [Member]
Sep. 30, 2014
Midstream Holdings [Member]
Sep. 30, 2015
Midstream Holdings [Member]
Sep. 30, 2014
Midstream Holdings [Member]
Mar. 31, 2014
EnLink Midstream Holdings, LP [Member]
Sep. 30, 2015
Gulf Coast Fractionators [Member]
Mar. 31, 2014
Gulf Coast Fractionators [Member]
Sep. 30, 2015
Common Class C [Member]
Mar. 16, 2015
Common Class C [Member]
Coronado [Member]
May 27, 2015
Midstream Holdings [Member]
Affiliated Entity [Member]
EMH Drop Down [Member]
Acacia [Member]
EnLink Midstream LP [Member]
EnLink Midstream Holdings, LP [Member]
Feb. 17, 2015
Midstream Holdings [Member]
Affiliated Entity [Member]
EMH Drop Down [Member]
Acacia [Member]
EnLink Midstream LP [Member]
EnLink Midstream Holdings, LP [Member]
May 27, 2015
Midstream Holdings [Member]
Affiliated Entity [Member]
EMH Drop Down [Member]
EnLink Midstream LP [Member]
Feb. 17, 2015
Class D Common Unit [Member]
Midstream Holdings [Member]
Affiliated Entity [Member]
EMH Drop Down [Member]
Acacia [Member]
EnLink Midstream LP [Member]
EnLink Midstream Holdings, LP [Member]
May 27, 2015
Class E Common Unit [Member] [Member]
Midstream Holdings [Member]
Affiliated Entity [Member]
EMH Drop Down [Member]
Acacia [Member]
EnLink Midstream LP [Member]
EnLink Midstream Holdings, LP [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
 
$ 1,170.6 
$ 857.4 
$ 3,385.6 
$ 2,507.7 
 
 
 
 
 
$ 2.4 
$ 4.2 
$ 2.4 
$ 851.4 
$ 3,381.4 
$ 2,498.0 
 
 
 
 
 
 
 
 
 
 
$ 3.6 
$ 7.3 
$ 0 
$ 0 
$ 0 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Transaction Costs
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.6 
 
 
0.2 
 
 
3.1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Combination, Consideration Transferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
108.1 
 
 
600.2 
 
 
194.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Combination, Initial Cash Consideration
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
240.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payments to Acquire Businesses, Gross
 
 
 
 
 
 
 
 
171.0 
 
 
 
 
 
 
 
231.5 
 
 
 
 
 
 
 
 
163.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares
120,542,441 
 
 
 
 
 
 
 
338,159 
 
 
 
 
 
 
 
 
 
 
 
 
 
6,704,285 
 
 
1,000,000 
 
 
 
 
 
 
 
 
 
6,704,285 
 
 
 
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
 
 
 
 
 
50.00% 
 
 
100.00% 
 
 
 
 
 
 
 
 
100.00% 
 
 
100.00% 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Limited Liability Company (LLC) or Limited Partnership (LP), Predecessor Entity(ies) to Business Combination
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Midstream Holdings 
 
 
 
 
 
 
 
 
 
Equity Method Investment, Ownership Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
38.75% 
38.75% 
 
 
 
 
 
 
 
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual
 
 
 
 
 
 
 
1,669.0 
 
 
 
 
 
 
 
 
 
24.2 
 
 
853.3 
 
 
126.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual
 
 
 
 
 
 
 
(0.7)
 
 
 
 
 
 
 
 
 
2.2 
 
 
1.2 
 
 
(7.7)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
31.2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Party Transaction, Ownership Interest Transferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25.00% 
25.00% 
 
 
 
Related Party Transaction, Amounts of Transaction, Shares
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
31,618,311 
36,629,888 
Related Party Transaction, Amounts of Transaction
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
925.0 
 
 
900.0 
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
 
Finite-Lived Intangible Asset, Useful Life
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
20 years 
 
 
10 years 
 
 
10 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
 
(755.2)
83.5 
(665.8)
219.0 
 
 
 
 
 
(2.3)
0.7 
(5.3)
85.7 
(666.5)
224.3 
 
 
 
 
 
 
 
 
 
 
0.1 
0 
0 
0 
0 
 
 
 
(15.2)
 
 
 
 
 
 
Net income attributable to non-controlling interest
 
(0.3)
0.1 
(0.3)
0.2 
 
 
 
 
 
0 
0 
0 
41.7 
15.0 
94.8 
 
 
 
 
 
 
 
 
 
 
0.1 
0.2 
(41.7)
(15.3)
(94.8)
 
 
 
 
 
 
 
 
 
 
Net income (loss) attributable to EnLink Midstream Partners, LP
 
(754.9)
83.4 
(665.5)
218.8 
 
 
 
 
 
(2.3)
0.7 
(5.3)
44.0 
(681.5)
129.5 
 
 
 
 
 
 
 
 
 
 
0 
(0.2)
41.7 
15.3 
94.8 
 
 
 
 
 
 
 
 
 
 
General partner interest in net income
 
6.3 
42.9 
50.2 
96.8 
 
 
 
 
 
(2.3)
0.7 
(5.3)
3.5 
34.2 
7.5 
 
 
 
 
 
 
 
 
 
 
0 
(0.2)
41.7 
15.3 
94.8 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned
 
 
 
 
 
 
 
 
 
9.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capitalized Costs, Support Equipment and Facilities
 
 
 
 
 
40.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Combination, Historical Cost of Entity Under Common Control
 
 
 
 
 
131.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payments of Distributions to Affiliates
 
 
 
 
 
40.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Acquired from Acquisition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
21.1 
 
 
1.4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Combination, Consideration Transferred, Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 87.0 
 
 
$ 238.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Acquisition (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Sep. 30, 2014
Jan. 31, 2015
LPC [Member]
Mar. 16, 2015
Coronado [Member]
Nov. 1, 2014
Chevron Acquisition [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets
 
 
 
$ 107.4 
$ 20.8 
 
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment
 
 
 
29.8 
302.1 
225.3 
Assets acquired [Abstract]
 
 
 
 
 
 
Goodwill
1,729.9 
2,257.8 
2,257.8 
29.6 
18.6 
 
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles
 
 
 
43.2 
281.0 
13.0 
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities
 
 
 
(97.9)
(22.3)
(6.8)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent
 
 
 
(4.0)
 
 
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net
 
 
 
$ 108.1 
$ 600.2 
$ 231.5 
Acquisition (Proforma) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Business Acquisition [Line Items]
 
 
 
Pro forma total revenues (1)
$ 1,398.7 
$ 3,507.7 
$ 4,232.0 
Pro forma net income (loss)
72.1 
(671.4)
177.7 
Pro forma net income (loss) attributable to EnLink Midstream Partners, LP
$ 72.1 
$ (671.1)
$ 177.6 
Basic
$ 0.13 
$ (2.39)
$ 0.24 
Diluted
$ 0.13 
$ (2.39)
$ 0.24 
Acquisition (Recast) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Business Acquisition [Line Items]
 
 
 
 
Revenues
$ 1,170.6 
$ 857.4 
$ 3,385.6 
$ 2,507.7 
Net income (loss)
(755.2)
83.5 
(665.8)
219.0 
Net income attributable to non-controlling interest
(0.3)
0.1 
(0.3)
0.2 
Net income (loss) attributable to EnLink Midstream Partners, LP
(754.9)
83.4 
(665.5)
218.8 
General partner interest in net income (loss)
6.3 
42.9 
50.2 
96.8 
ENLK Historical [Member]
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
Revenues
 
851.4 
3,381.4 
2,498.0 
Net income (loss)
 
85.7 
(666.5)
224.3 
Net income attributable to non-controlling interest
 
41.7 
15.0 
94.8 
Net income (loss) attributable to EnLink Midstream Partners, LP
 
44.0 
(681.5)
129.5 
General partner interest in net income (loss)
 
3.5 
34.2 
7.5 
Midstream Holdings [Member]
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
Revenues
 
0 
0 
0 
Net income (loss)
 
0 
0 
0 
Net income attributable to non-controlling interest
 
(41.7)
(15.3)
(94.8)
Net income (loss) attributable to EnLink Midstream Partners, LP
 
41.7 
15.3 
94.8 
General partner interest in net income (loss)
 
41.7 
15.3 
94.8 
E2 [Member]
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
Revenues
 
3.6 
 
7.3 
Net income (loss)
 
0.1 
 
0 
Net income attributable to non-controlling interest
 
0.1 
 
0.2 
Net income (loss) attributable to EnLink Midstream Partners, LP
 
0 
 
(0.2)
General partner interest in net income (loss)
 
0 
 
(0.2)
VEX [Member]
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
Revenues
 
2.4 
4.2 
2.4 
Net income (loss)
 
(2.3)
0.7 
(5.3)
Net income attributable to non-controlling interest
 
0 
0 
0 
Net income (loss) attributable to EnLink Midstream Partners, LP
 
(2.3)
0.7 
(5.3)
General partner interest in net income (loss)
 
$ (2.3)
$ 0.7 
$ (5.3)
Acquisition (Phantom) (Details) (USD $)
In Millions, unless otherwise specified
0 Months Ended
Mar. 16, 2015
Coronado [Member]
Jan. 31, 2015
LPC [Member]
Business Acquisition [Line Items]
 
 
Cash Acquired from Acquisition
$ 1.4 
$ 21.1 
Goodwill and Intangible Assets (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Dec. 31, 2014
Goodwill [Line Items]
 
 
 
 
 
Impairments
$ 799.2 
$ 0 
$ 799.2 
$ 0 
 
Goodwill
1,729.9 
2,257.8 
1,729.9 
2,257.8 
2,257.8 
Goodwill, Acquired During Period
 
 
48.2 
 
 
Goodwill, Impairment Loss
 
 
(576.1)
 
 
Crude And Condensate Segment [Member]
 
 
 
 
 
Goodwill [Line Items]
 
 
 
 
 
Impairments
223.1 
 
223.1 
 
 
Goodwill
142.1 
112.5 
142.1 
112.5 
112.5 
Goodwill, Acquired During Period
 
 
29.6 
 
 
Goodwill, Impairment Loss
 
 
0 
 
 
Corporate Segment [Member]
 
 
 
 
 
Goodwill [Line Items]
 
 
 
 
 
Impairments
0 
 
0 
 
 
Goodwill
0 
0 
0 
0 
0 
Goodwill, Acquired During Period
 
 
0 
 
 
Goodwill, Impairment Loss
 
 
0 
 
 
Texas Operating Segment [Member]
 
 
 
 
 
Goodwill [Line Items]
 
 
 
 
 
Impairments
0 
 
0 
 
 
Goodwill
1,186.8 
1,168.2 
1,186.8 
1,168.2 
1,168.2 
Goodwill, Acquired During Period
 
 
18.6 
 
 
Goodwill, Impairment Loss
 
 
0 
 
 
Louisiana Operating Segment [Member]
 
 
 
 
 
Goodwill [Line Items]
 
 
 
 
 
Impairments
576.1 
 
576.1 
 
 
Goodwill
210.7 
786.8 
210.7 
786.8 
786.8 
Goodwill, Acquired During Period
 
 
0 
 
 
Goodwill, Impairment Loss
 
 
(576.1)
 
 
Oklahoma Operating Segment [Member]
 
 
 
 
 
Goodwill [Line Items]
 
 
 
 
 
Impairments
0 
 
0 
 
 
Goodwill
190.3 
190.3 
190.3 
190.3 
190.3 
Goodwill, Acquired During Period
 
 
0 
 
 
Goodwill, Impairment Loss
 
 
$ 0 
 
 
Minimum [Member]
 
 
 
 
 
Goodwill [Line Items]
 
 
 
 
 
Finite-Lived Intangible Asset, Useful Life
 
 
10 years 
 
 
Maximum [Member]
 
 
 
 
 
Goodwill [Line Items]
 
 
 
 
 
Finite-Lived Intangible Asset, Useful Life
 
 
20 years 
 
 
Goodwill and Intangible Assets (Intangible Asset by Major Class) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Dec. 31, 2014
Acquired Finite-Lived Intangible Assets [Line Items]
 
 
 
 
 
Finite-Lived Intangible Assets, Gross
$ 645.7 
 
$ 645.7 
 
$ 569.5 
Finite-Lived Intangible Assets, Accumulated Amortization
(42.9)
 
(42.9)
 
(36.5)
Finite-Lived Intangible Assets, Net
602.8 
 
602.8 
 
533.0 
Finite-Lived Intangibles Assets Acquired
 
 
337.2 
 
 
Impairment of Intangible Assets, Finite-lived
 
 
(223.1)
 
 
Accumulated Depreciation, Depletion and Amortization, Reclassifications from Property, Plant and Equipment
 
 
37.9 
 
 
Amortization of Intangible Assets
(14.6)
(10.2)
(44.3)
(23.2)
 
ImpairmentOfIntangibleAssetsFinitelivedGross
 
 
$ 261.0 
 
 
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life
 
 
11 years 5 months 
 
 
Goodwill and Intangible Assets (Amortization Expense Table) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Finite-Lived Intangibles Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
 
 
2015
$ 10.3 
 
2016
41.2 
 
2017
41.2 
 
2018
41.2 
 
2019
41.2 
 
Thereafter
427.7 
 
Total
$ 602.8 
$ 533.0 
Affiliate Transactions (Textual) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Dec. 31, 2014
Mar. 7, 2014
Sep. 30, 2015
Affiliated Entity [Member]
Sep. 30, 2014
Affiliated Entity [Member]
Sep. 30, 2015
Affiliated Entity [Member]
Sep. 30, 2014
Affiliated Entity [Member]
Sep. 30, 2015
Devon Energy Corporation [Member]
Sep. 30, 2014
Devon Energy Corporation [Member]
Sep. 30, 2015
Devon Energy Corporation [Member]
Sep. 30, 2014
Devon Energy Corporation [Member]
Sep. 30, 2015
Gulf Coast Fractionators [Member]
Mar. 31, 2014
Gulf Coast Fractionators [Member]
Sep. 30, 2015
Transmission Service Agreement [Member]
Affiliated Entity [Member]
Sep. 30, 2014
Transmission Service Agreement [Member]
Affiliated Entity [Member]
Sep. 30, 2015
Transmission Service Agreement [Member]
Affiliated Entity [Member]
Sep. 30, 2014
Transmission Service Agreement [Member]
Affiliated Entity [Member]
Related Party Transaction [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Concentration Risk, Percentage
 
 
 
 
 
 
 
 
 
 
16.30% 
24.30% 
15.90% 
34.90% 
 
 
 
 
 
 
Due from Affiliate, Current
$ 119.3 
 
$ 119.3 
 
$ 121.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses - affiliates
 
 
 
 
 
 
0.1 
0 
0.3 
5.9 
 
 
 
 
 
 
 
 
 
 
Other Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.2 
 
Segment profit
203.8 
186.5 
585.6 
515.4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accounts payable to related party
24.2 
 
24.2 
 
3.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Affiliate general and administrative expense
33.5 
23.5 
102.3 
64.8 
 
 
0.1 
1.0 
0.2 
10.6 
 
 
 
 
 
 
0.1 
1.0 
0.2 
2.3 
Allocated Share-based Compensation Expense
7.3 
5.7 
28.6 
15.5 
 
 
 
 
 
 
 
 
 
2.8 
 
 
 
 
 
 
Equity Method Investment, Ownership Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
38.75% 
38.75% 
 
 
 
 
Pension and Other Postretirement Benefit Expense
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 1.6 
 
 
 
 
 
 
Affiliate Transactions (Predecessor's Affiliate Transactions) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Related Party Transaction [Line Items]
 
 
 
 
Affiliate general and administrative expense
$ 33.5 
$ 23.5 
$ 102.3 
$ 64.8 
Capital expenditures
104.7 
209.0 
445.2 
517.0 
Net distributions from (to) related party
 
 
 
(95.0)
Affiliated Entity [Member]
 
 
 
 
Related Party Transaction [Line Items]
 
 
 
 
Affiliate general and administrative expense
0.1 
1.0 
0.2 
10.6 
Operating expenses - affiliates
0.1 
0 
0.3 
5.9 
Transmission Service Agreement [Member] |
Affiliated Entity [Member]
 
 
 
 
Related Party Transaction [Line Items]
 
 
 
 
Affiliate general and administrative expense
0.1 
1.0 
0.2 
2.3 
Continuing Operations [Member] |
Affiliated Entity [Member]
 
 
 
 
Related Party Transaction [Line Items]
 
 
 
 
Operating revenues - affiliates
 
 
 
(436.4)
Operating expenses - affiliates
 
 
 
340.0 
Net Related Party transactions
 
 
 
(96.4)
Capital expenditures
 
 
 
16.2 
Other Expenses
 
 
 
53.0 
Total Third-Party Transactions
 
 
 
69.2 
Net distributions from (to) related party
 
 
 
(50.7)
Net distributions from (to) related party, non-cash
 
 
 
(23.5)
Continuing Operations [Member] |
Devon Energy Corporation [Member]
 
 
 
 
Related Party Transaction [Line Items]
 
 
 
 
Net distributions from (to) related party
 
 
 
(27.2)
Discontinued Operations [Member]
 
 
 
 
Related Party Transaction [Line Items]
 
 
 
 
Net distributions from (to) related party
 
 
 
(4.4)
Discontinued Operations [Member] |
Affiliated Entity [Member]
 
 
 
 
Related Party Transaction [Line Items]
 
 
 
 
Operating revenues - affiliates
 
 
 
(10.4)
Operating expenses - affiliates
 
 
 
5.0 
Net Related Party transactions
 
 
 
(5.4)
Capital expenditures
 
 
 
0.6 
Other Expenses
 
 
 
0.4 
Total Third-Party Transactions
 
 
 
1.0 
Net distributions from (to) related party
 
 
 
(44.3)
Discontinued Operations [Member] |
Devon Energy Corporation [Member]
 
 
 
 
Related Party Transaction [Line Items]
 
 
 
 
Net distributions from (to) related party, non-cash
 
 
 
$ (39.9)
Long-Term Debt (Indebtedness Table) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Amount Outstanding
$ 175.0 
$ 237.0 
Other Long-term Debt
0.2 
0.4 
2.7% Senior Notes due 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
399.6 
399.5 
7.125% Senior Notes due 2022 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
182.2 
184.4 
4.4% Senior Notes due 2024 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
552.9 
553.2 
4.15% Senior Notes due 2025 [Member] [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
748.8 
0 
5.6% Senior Notes due 2044 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
349.7 
349.7 
5.05% Senior Notes due 2045 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
$ 443.1 
$ 298.3 
Long-Term Debt (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2015
Dec. 31, 2014
Feb. 20, 2014
Letter of Credit [Member]
Sep. 30, 2015
4.15% Senior Notes due 2025 [Member] [Member]
May 12, 2015
4.15% Senior Notes due 2025 [Member] [Member]
Dec. 31, 2014
4.15% Senior Notes due 2025 [Member] [Member]
Sep. 30, 2015
4.15% Senior Notes due 2025 [Member] [Member]
Debt Instrument, Redemption, Period One [Member]
Sep. 30, 2015
4.15% Senior Notes due 2025 [Member] [Member]
Debt Instrument, Redemption, Period Two [Member]
Sep. 30, 2015
4.4% Senior Notes due 2024 [Member]
Dec. 31, 2014
4.4% Senior Notes due 2024 [Member]
Sep. 30, 2015
5.6% Senior Notes due 2044 [Member]
Dec. 31, 2014
5.6% Senior Notes due 2044 [Member]
Sep. 30, 2015
5.05% Senior Notes due 2045 [Member]
May 12, 2015
5.05% Senior Notes due 2045 [Member]
Dec. 31, 2014
5.05% Senior Notes due 2045 [Member]
Sep. 30, 2015
5.05% Senior Notes due 2045 [Member]
Debt Instrument, Redemption, Period One [Member]
Sep. 30, 2015
5.05% Senior Notes due 2045 [Member]
Debt Instrument, Redemption, Period Two [Member]
May 12, 2015
Unsecured Debt [Member]
Sep. 30, 2015
Maximum [Member]
Sep. 30, 2015
Revolving Credit Facility [Member]
Maximum [Member]
Feb. 20, 2014
Pre Amendment [Member]
Feb. 5, 2015
Post Amendment [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Long-term Debt
$ 0.2 
$ 0.4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage
 
 
 
4.15% 
4.15% 
4.15% 
 
 
4.40% 
4.40% 
5.60% 
5.60% 
5.05% 
5.05% 
5.05% 
 
 
 
 
 
 
 
Senior Notes
 
 
 
748.8 
 
0 
 
 
552.9 
553.2 
349.7 
349.7 
443.1 
 
298.3 
 
 
 
 
 
 
 
Debt Instrument, Unamortized Discount (Premium), Net
 
 
 
(1.2)
 
0 
 
 
2.9 
3.2 
(0.3)
(0.3)
(6.9)
 
(1.7)
 
 
 
 
 
 
 
Line of Credit Facility, Maximum Borrowing Capacity
1,500.0 
 
500.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,000.0 
1,500.0 
Debt Instrument, Face Amount
 
 
 
 
750.0 
 
 
 
 
 
 
 
 
150.0 
 
 
 
900.0 
 
 
 
 
Line Of Credit Facility, Additional Borrowing Limit
500.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Leverage ratios
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.0 
5.5 
 
 
Conditional acquisition purchase price
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50.0 
 
 
 
Letters of Credit Outstanding, Amount
2.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Amount Outstanding
175.0 
237.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Remaining Borrowing Capacity
$ 1,320.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Selling Priceof Debt Instrument
 
 
 
 
99.827% 
 
 
 
 
 
 
 
 
96.381% 
 
 
 
 
 
 
 
 
Debt Instrument, Redemption Price, Percentage
 
 
 
 
 
 
100.00% 
100.00% 
 
 
 
 
 
 
 
100.00% 
100.00% 
 
 
 
 
 
Long-Term Debt (Percentages Per Annum) (Details)
9 Months Ended
Sep. 30, 2015
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) (USD $)
In Millions, unless otherwise specified
9 Months Ended 12 Months Ended
Sep. 30, 2015
Line of Credit [Member]
Dec. 31, 2014
Line of Credit [Member]
Sep. 30, 2015
2.7% Senior Notes due 2019 [Member]
Dec. 31, 2014
2.7% Senior Notes due 2019 [Member]
Sep. 30, 2015
7.125% Senior Notes due 2022 [Member]
Dec. 31, 2014
7.125% Senior Notes due 2022 [Member]
Sep. 30, 2015
4.4% Senior Notes due 2024 [Member]
Dec. 31, 2014
4.4% Senior Notes due 2024 [Member]
Sep. 30, 2015
5.6% Senior Notes due 2044 [Member]
Dec. 31, 2014
5.6% Senior Notes due 2044 [Member]
Sep. 30, 2015
5.05% Senior Notes due 2045 [Member]
May 12, 2015
5.05% Senior Notes due 2045 [Member]
Dec. 31, 2014
5.05% Senior Notes due 2045 [Member]
Sep. 30, 2015
4.15% Senior Notes due 2025 [Member] [Member]
May 12, 2015
4.15% Senior Notes due 2025 [Member] [Member]
Dec. 31, 2014
4.15% Senior Notes due 2025 [Member] [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Interest Rate During Period
1.50% 
1.90% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Senior notes fixed interest rate
 
 
2.70% 
2.70% 
7.125% 
7.125% 
4.40% 
4.40% 
5.60% 
5.60% 
5.05% 
5.05% 
5.05% 
4.15% 
4.15% 
4.15% 
Debt Instrument, Unamortized Discount (Premium), Net
 
 
$ (0.4)
$ (0.5)
$ 19.7 
$ 21.9 
$ 2.9 
$ 3.2 
$ (0.3)
$ (0.3)
$ (6.9)
 
$ (1.7)
$ (1.2)
 
$ 0 
Partners' Capital (Details Textuals) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 9 Months Ended 0 Months Ended 3 Months Ended 0 Months Ended 3 Months Ended
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
General Partner [Member]
Incentive Distribution Percentage, Level1 [Member]
Sep. 30, 2015
General Partner [Member]
Incentive Distribution Percentage, Level2 [Member]
Sep. 30, 2015
General Partner [Member]
Incentive Distribution Percentage, Level3 [Member]
Sep. 30, 2015
EDA [Member]
BMO Capital Markets Corp. [Member]
Nov. 30, 2014
EDA [Member]
BMO Capital Markets Corp. [Member]
May 27, 2015
EMH Drop Down [Member]
EnLink Midstream Holdings, LP [Member]
Midstream Holdings [Member]
Affiliated Entity [Member]
Acacia [Member]
EnLink Midstream LP [Member]
Feb. 17, 2015
EMH Drop Down [Member]
EnLink Midstream Holdings, LP [Member]
Midstream Holdings [Member]
Affiliated Entity [Member]
Acacia [Member]
EnLink Midstream LP [Member]
May 27, 2015
EMH Drop Down [Member]
EnLink Midstream Holdings, LP [Member]
Midstream Holdings [Member]
Affiliated Entity [Member]
Class E Common Unit [Member] [Member]
Acacia [Member]
EnLink Midstream LP [Member]
Feb. 17, 2015
EMH Drop Down [Member]
EnLink Midstream Holdings, LP [Member]
Midstream Holdings [Member]
Affiliated Entity [Member]
Class D Common Unit [Member]
Acacia [Member]
EnLink Midstream LP [Member]
Jun. 30, 2015
Class E Common Unit [Member]
Mar. 31, 2015
Class D Common Unit [Member]
Mar. 31, 2014
Capital Unit, Class B [Member]
Mar. 16, 2015
Common Class C [Member]
Sep. 30, 2015
Common Class C [Member]
Jun. 30, 2015
Common Class C [Member]
Mar. 31, 2015
Common Class C [Member]
Subsidiary Sale Of Stock [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AggregateAmountOfEquitySecuritiesAllowedUnderEquityDistributionAgreement
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 350.0 
 
 
 
 
 
 
 
 
 
 
 
Percentage of avaliable cash to distribute
100.00% 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of days from end of quarter for distribution
 
 
 
 
 
 
 
45 days 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Made to Limited Partner, Distribution Date
Nov. 12, 2015 
Aug. 13, 2015 
May 14, 2015 
Feb. 12, 2015 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Made to Limited Partner, Distributions Declared, Per Unit
$ 0.39 
$ 0.385 
$ 0.38 
$ 0.375 
$ 0.37 
$ 0.365 
$ 0.36 
 
 
 
 
 
 
 
 
 
 
 
$ 0.15 
$ 0.18 
$ 0.10 
 
$ 0.390 
 
 
Proceeds from issuance of common units
 
 
 
 
 
 
 
12.9 
71.9 
 
 
 
12.9 
 
 
 
 
 
 
 
 
 
 
 
 
Payments of Stock Issuance Costs
 
 
 
 
 
 
 
 
 
 
 
 
0.1 
 
 
 
 
 
 
 
 
 
 
 
 
AggregateAmountOfEquitySecurityRemainingUnderEquityDistributionAgreement
 
 
 
 
 
 
 
 
 
 
 
 
$ 328.7 
 
 
 
 
 
 
 
 
 
 
 
 
Stock Issued During Period, Shares, Acquisitions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6,704,285 
 
 
 
Paid In Kind Dividends
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
150,732 
120,622 
99,794 
Related Party Transaction, Amounts of Transaction, Shares
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
36,629,888 
31,618,311 
 
 
 
 
 
 
 
Related Party Transaction, Ownership Interest Transferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25.00% 
25.00% 
 
 
 
 
 
 
 
 
 
Incentive Distribution Percentage Levels
 
 
 
 
 
 
 
 
 
13.00% 
23.00% 
48.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
Incentive Distribution, Distribution Per Unit
 
 
 
 
 
 
 
 
 
$ 0.25 
$ 0.3125 
$ 0.375 
 
 
 
 
 
 
 
 
 
 
 
 
 
Partners' Capital (EPU Computation Schedule) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Capital Unit [Line Items]
 
 
 
 
Total distributed earnings
$ 125.7 
$ 85.8 
$ 341.0 
$ 221.6 
Limited partners’ interest in net income (loss)
(745.2)
40.5 
(700.5)
86.5 
Total undistributed loss
(870.9)
(45.3)
(1,041.5)
(135.1)
Basic
$ (2.32)
$ 0.18 
$ (2.38)
$ 0.38 
Diluted
$ (2.32)
$ 0.18 
$ (2.38)
$ 0.38 
Common Unit [Member]
 
 
 
 
Capital Unit [Line Items]
 
 
 
 
Total distributed earnings
125.2 
85.4 
339.5 
220.7 
Limited partners’ interest in net income (loss)
(742.4)
40.3 
(697.6)
86.1 
Total undistributed loss
(867.6)
(45.1)
(1,037.1)
(134.6)
Restricted Stock Units (RSUs) [Member]
 
 
 
 
Capital Unit [Line Items]
 
 
 
 
Total distributed earnings
0.5 
0.4 
1.5 
0.9 
Limited partners’ interest in net income (loss)
(2.8)
0.2 
(2.9)
0.4 
Total undistributed loss
$ (3.3)
$ (0.2)
$ (4.4)
$ (0.5)
Partners' Capital (Weighted Average Schedule) (Details)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Class of Stock [Line Items]
 
 
 
 
Weighted Average Number of Shares Outstanding, Basic
327.9 
231.0 
298.9 
230.3 
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities
0 
0.4 
0 
0.3 
Weighted Average Number of Shares Outstanding, Diluted
327.9 
231.4 
298.9 
230.6 
Common Class C [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
Weighted Average Limited Partnership Units Outstanding, Basic
6.9 
0 
4.9 
0 
Common Units [Member]
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
Weighted Average Limited Partnership Units Outstanding, Basic
321.0 
231.0 
294.0 
230.3 
Partners' Capital (Allocated Net Income (loss) to the General Partner) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
 
 
General Partner share of net income
$ 6.3 
$ 42.9 
$ 50.2 
$ 96.8 
General Partner [Member]
 
 
 
 
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
 
 
Income allocation for incentive distributions
13.6 
6.3 
33.7 
13.6 
Unit-based compensation attributable to ENLC’s restricted units
(3.7)
(3.1)
(14.6)
(6.8)
General Partner interest in net income (loss)
(3.6)
0.3 
(3.3)
0.7 
General Partner interest in asset drop
$ 0 
$ 39.4 
$ 34.4 
$ 89.3 
Partners Capital (Issuance of Common Units) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
EDA [Member]
BMO Capital Markets Corp. [Member]
Nov. 30, 2014
EDA [Member]
BMO Capital Markets Corp. [Member]
Sep. 30, 2015
EDA [Member]
BMO Capital Markets Corp, Merrilly Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc, Jeffries LLC, Raymond James and Associates, Inc and RBC Capital Markets LLC [Member]
Sep. 30, 2015
Common Class C [Member]
Class of Stock [Line Items]
 
 
 
 
 
 
AggregateAmountOfEquitySecuritiesAllowedUnderEquityDistributionAgreement
 
 
 
$ 350.0 
 
 
Issuance of common units
372.9 
 
 
 
0.7 
180.0 
Proceeds from issuance of common units
12.9 
71.9 
12.9 
 
 
 
Payments of Stock Issuance Costs
 
 
0.1 
 
 
 
AggregateAmountOfEquitySecurityRemainingUnderEquityDistributionAgreement
 
 
$ 328.7 
 
 
 
Asset Retirement Obligation (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Dec. 31, 2014
Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
 
 
 
 
Asset Retirement Obligation
$ 13.8 
$ 12.2 
$ 20.6 
$ 8.1 
Asset Retirement Obligation, Revision of Estimate
(4.0)
3.2 
 
 
Asset Retirement Obligation, Liabilities Incurred
0 
0.5 
 
 
Asset Retirement Obligation, Accretion Expense
0.4 
0.4 
 
 
Asset Retirement Obligation, Liabilities Settled
(3.2)
0 
 
 
Asset Retirement Obligation, Current
$ 1.0 
 
$ 8.2 
 
Investment in Unconsolidated Affiliate (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
CashContributionPaidByParentCompanyToUnconsolidatedSubsidiaries
$ 8.1 
$ 0 
$ 8.1 
$ 5.7 
 
Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries
12.2 
8.2 1
31.4 
13.9 1
 
Income (Loss) from Equity Method Investments
6.4 
5.6 
16.1 
14.3 
 
Income (Loss) from Equity Method Investments
263.5 
 
263.5 
 
270.8 
Gulf Coast Fractionators [Member]
 
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
CashContributionPaidByParentCompanyToUnconsolidatedSubsidiaries
0 
0 
0 
0 
 
Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries
3.8 
5.2 
10.7 
5.2 
 
Income (Loss) from Equity Method Investments
3.4 
5.2 
9.7 
13.2 
 
Income (Loss) from Equity Method Investments
53.0 
 
53.0 
 
54.1 
Equity Method Investment, Ownership Percentage
38.75% 
 
38.75% 
 
 
Howard Energy Partners [Member]
 
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
CashContributionPaidByParentCompanyToUnconsolidatedSubsidiaries
8.1 
0 
8.1 
5.7 
 
Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries
8.4 
3.0 1
20.7 
8.7 1
 
Income (Loss) from Equity Method Investments
3.0 
0.4 
6.4 
1.1 
 
Income (Loss) from Equity Method Investments
$ 210.5 
 
$ 210.5 
 
$ 216.7 
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 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
ENLK Restricted Units [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Vesting Period
 
 
3 years 
 
ENLC Restricted Units [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Vesting Period
 
 
3 years 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value
$ 0.1 
$ 2.2 
$ 9.3 
$ 2.2 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
 
 
261,144 
 
Restricted Stock Units (RSUs) [Member] |
ENLK Restricted Units [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value
0.1 
1.2 
7.6 
1.2 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
 
 
264,651 
 
Restricted Stock Units (RSUs) [Member] |
ENLK Restricted Unit March Vest [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value
 
 
3.4 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
 
 
128,675 
 
Restricted Stock Units (RSUs) [Member] |
ENLC Restricted Units March Vest [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value
 
 
3.4 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
 
 
102,543 
 
Restricted Stock [Member] |
ENLC Restricted Units [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Unrecognized compensation cost related to non-vested restricted incentive units
20.2 
 
20.2 
 
Unrecognized compensation costs, weighted average period for recognition
 
 
1 year 8 months 
 
Enlink midstream, LLC [Member] |
Performance Based Restricted Unit [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Unrecognized compensation cost related to non-vested restricted incentive units
3.3 
 
3.3 
 
Unrecognized compensation costs, weighted average period for recognition
 
 
2 years 3 months 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
 
 
0 
 
EnLink Midstream Partners, LP [Member] |
Performance Based Restricted Unit [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Unrecognized compensation cost related to non-vested restricted incentive units
3.3 
 
3.3 
 
Unrecognized compensation costs, weighted average period for recognition
 
 
2 years 3 months 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
 
 
0 
 
EnLink Midstream Partners, LP [Member] |
Restricted Stock Units (RSUs) [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Unrecognized compensation cost related to non-vested restricted incentive units
$ 19.5 
 
$ 19.5 
 
Unrecognized compensation costs, weighted average period for recognition
 
 
1 year 8 months 
 
Minimum [Member] |
EnLink Midstream Partners, LP [Member] |
Performance Based Restricted Unit [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage
 
 
0.00% 
 
Minimum [Member] |
Enlink midstream, LLC [Member] |
Performance Based Restricted Unit [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage
 
 
0.00% 
 
Maximum [Member] |
EnLink Midstream Partners, LP [Member] |
Performance Based Restricted Unit [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage
 
 
200.00% 
 
Maximum [Member] |
Enlink midstream, LLC [Member] |
Performance Based Restricted Unit [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage
 
 
200.00% 
 
Employee Incentive Plan (Expense Schedule) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Allocated Share-based Compensation Expense
$ 7.3 
$ 5.7 
$ 28.6 
$ 15.5 
General and Administrative Expense [Member]
 
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Allocated Share-based Compensation Expense
6.3 
4.9 
24.6 
10.9 
Operating Expense [Member]
 
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Allocated Share-based Compensation Expense
1.0 
0.8 
4.0 
1.8 
Predecessor [Member] |
General and Administrative Expense [Member]
 
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Allocated Share-based Compensation Expense
$ 0 
$ 0 
$ 0 
$ 2.8 
Employee Incentive Plan (Compensation Schedule) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
9 Months Ended
Sep. 30, 2015
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
90,567 
Number of Units
 
Non-vested, beginning of period (Units)
1,022,191 
Granted
581,047 
Vested
(264,651)
Forfeited
(68,913)
Non-vested, end of period (Units)
1,269,674 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 31.25 
Granted
$ 26.82 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 28.81 
Forfeited
$ 30.92 
Non-vested, end of period
$ 29.75 
Aggregate intrinsic value, end of period (in thousands)
$ 20.0 
ENLC Restricted Units [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Shares Paid for Tax Withholding for Share Based Compensation
83,176 
Number of Units
 
Non-vested, beginning of period (Units)
986,472 
Granted
493,582 
Vested
(261,144)
Forfeited
(59,203)
Non-vested, end of period (Units)
1,159,707 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 37.03 
Granted
$ 31.58 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 35.79 
Forfeited
$ 35.99 
Non-vested, end of period
$ 35.04 
Aggregate intrinsic value, end of period (in thousands)
21.2 
Enlink midstream, LLC [Member] |
Performance Based Restricted Unit [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Share Based Compensation Arrangement Grant Date Fair Value
$ 34.24 
Number of Units
 
Non-vested, beginning of period (Units)
0 
Granted
105,080 
Vested
0 
Non-vested, end of period (Units)
105,080 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 0.00 
Granted
$ 40.50 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 0.00 
Non-vested, end of period
$ 40.50 
Aggregate intrinsic value, end of period (in thousands)
1.9 
Fair Value Assumptions, Risk Free Interest Rate
0.99% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
33.02% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate
2.98% 
EnLink Midstream Partners, LP [Member] |
Performance Based Restricted Unit [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Share Based Compensation Arrangement Grant Date Fair Value
$ 27.68 
Number of Units
 
Non-vested, beginning of period (Units)
0 
Granted
118,126 
Vested
0 
Non-vested, end of period (Units)
118,126 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 0.00 
Granted
$ 35.41 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 0.00 
Non-vested, end of period
$ 35.41 
Aggregate intrinsic value, end of period (in thousands)
$ 1.9 
Fair Value Assumptions, Risk Free Interest Rate
0.99% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
33.01% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate
5.66% 
Employee Incentive Plan (Intrinsic and Fair Value of Units Vested) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
ENLC Restricted Units [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
ShareBasedCompensationArrangementByShareBasedPaymentAwardEquityInstrumentsOtherThanOptionsVestedInPeriodIntrinsicValue1
$ 0.1 
$ 2.4 
$ 8.9 
$ 2.4 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value
0.1 
2.2 
9.3 
2.2 
ENLK Restricted Units [Member] |
Restricted Stock Units (RSUs) [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
ShareBasedCompensationArrangementByShareBasedPaymentAwardEquityInstrumentsOtherThanOptionsVestedInPeriodIntrinsicValue1
0.1 
1.2 
7.2 
1.2 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value
$ 0.1 
$ 1.2 
$ 7.6 
$ 1.2 
Employee Incentive Plans Total Shareholder Return Unit Summary (Details) (Performance Based Restricted Unit [Member], USD $)
9 Months Ended
Sep. 30, 2015
EnLink Midstream Partners, LP [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Share Based Compensation Arrangement Grant Date Fair Value
$ 27.68 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate
5.66% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
33.01% 
Fair Value Assumptions, Risk Free Interest Rate
0.99% 
Enlink midstream, LLC [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Share Based Compensation Arrangement Grant Date Fair Value
$ 34.24 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate
2.98% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
33.02% 
Fair Value Assumptions, Risk Free Interest Rate
0.99% 
Derivatives (Summary of Derivative Income Expense) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Gain (loss) on derivative activity
$ 5.2 
$ 1.0 
$ 6.6 
$ (1.9)
Interest Rate Swap [Member]
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Change in fair value of derivatives
0 
 
3.6 
 
Commodity Swap [Member]
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Derivative, Gain (Loss) on Derivative, Net
(0.2)
1.8 
(6.4)
(0.2)
Change in fair value of derivatives
$ 5.4 
$ (0.8)
$ 13.0 
$ (1.7)
Derivatives (Schedule of Derivative Assets Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative assets — current
$ 15.5 
$ 16.7 
Fair value of derivative assets — long term
2.9 
10.0 
Fair value of derivative liabilities — current
(3.4)
(3.0)
Fair value of derivative liabilities — long term
(0.5)
(2.0)
Net fair value of derivatives
14.5 
21.7 
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Net fair value of derivatives
$ 14.5 
 
Derivatives (Derivatives Outstanding) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Derivative [Line Items]
 
 
Total mark to market derivatives
$ 14.5 
$ 21.7 
Not Designated as Hedging Instrument [Member]
 
 
Derivative [Line Items]
 
 
Total mark to market derivatives
14.5 
 
Liquids [Member] |
Short Contracts [Member]
 
 
Derivative [Line Items]
 
 
Derivative Nonmonetary Notional Amount
53,300,000 
 
Total mark to market derivatives
16.4 
 
Liquids [Member] |
Long Contracts [Member]
 
 
Derivative [Line Items]
 
 
Derivative Nonmonetary Notional Amount
35,800,000 
 
Total mark to market derivatives
(2.4)
 
Gas [Member] |
Short Contracts [Member]
 
 
Derivative [Line Items]
 
 
Derivative Nonmonetary Notional Amount
3,100,000 
 
Total mark to market derivatives
1.3 
 
Gas [Member] |
Long Contracts [Member]
 
 
Derivative [Line Items]
 
 
Derivative Nonmonetary Notional Amount
1,300,000 
 
Total mark to market derivatives
(0.9)
 
Condensate [Member] |
Long Contracts [Member]
 
 
Derivative [Line Items]
 
 
Derivative Nonmonetary Notional Amount
100,000 
 
Total mark to market derivatives
$ 0.1 
 
Derivatives (Details Textuals) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Derivative [Line Items]
 
Maximum counterparty loss
$ (18.4)
Maximum counterparty loss with netting feature
$ (14.5)
Derivatives (Derivatives Other Than Cash Flow Hedges Table) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Derivative [Line Items]
 
Derivative Instruments at fair value
$ 14.5 
Market Approach Valuation Technique [Member] |
Less than on year
 
Derivative [Line Items]
 
Derivative Instruments at fair value
12.1 
Market Approach Valuation Technique [Member] |
One to two years
 
Derivative [Line Items]
 
Derivative Instruments at fair value
2.4 
Market Approach Valuation Technique [Member] |
More than two years
 
Derivative [Line Items]
 
Derivative Instruments at fair value
$ 0 
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
Sep. 30, 2015
Dec. 31, 2014
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
$ 14.5 
$ 21.7 
Fair Value Measurement (Fair Value of Financial Instrument) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Carrying Value [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
$ 2,851.5 
$ 2,022.5 
Obligations under capital lease
17.7 
20.3 
Fair Value [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt, Fair Value
2,663.2 
2,026.1 
Obligations under capital lease
$ 17.0 
$ 19.8 
Fair Value Measurement (Details Textuals) (USD $)
In Millions, unless otherwise specified
9 Months Ended 12 Months Ended
Sep. 30, 2015
Dec. 31, 2014
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Amount Outstanding
$ 175.0 
$ 237.0 
Unsecured Debt
$ 2,676.3 
$ 1,785.1 
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 3 Months Ended 9 Months Ended
Aug. 31, 2014
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Gain Contingencies [Line Items]
 
 
 
 
 
Gain on Litigation Settlement
$ 6.1 
$ 0 
$ 6.1 
$ 0 
$ 6.1 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
1 Months Ended 3 Months Ended 9 Months Ended
Aug. 31, 2014
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Dec. 31, 2014
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Product sales
 
$ 863.5 
$ 579.1 
$ 2,488.8 
$ 1,480.4 
 
Product sales - affiliates
 
40.3 
37.8 
89.6 
474.2 
 
Midstream services
 
111.3 
68.6 
351.3 
154.8 
 
Midstream services-affiliates
 
150.3 
170.9 
449.3 
400.2 
 
Cost of sales
 
(861.8)
(597.2)
(2,487.4)
(1,798.0)
 
Operating expenses
 
(105.0)
(79.8)
(312.6)
(200.4)
 
Gain on Litigation Settlement
6.1 
0 
6.1 
0 
6.1 
 
Gain (loss) on derivative activity
 
5.2 
1.0 
6.6 
(1.9)
 
Segment profit
 
203.8 
186.5 
585.6 
515.4 
 
Depreciation and amortization
 
(98.4)
(74.6)
(289.1)
(197.6)
 
Impairment
 
(799.2)
0 
(799.2)
0 
 
Goodwill
 
1,729.9 
2,257.8 
1,729.9 
2,257.8 
2,257.8 
Capital expenditures
 
104.7 
209.0 
445.2 
517.0 
 
Identifiable assets
 
8,768.0 
 
8,768.0 
 
8,702.0 
Texas Operating Segment [Member]
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Product sales
 
106.9 
52.5 
237.3 
167.0 
 
Product sales - affiliates
 
35.3 
19.2 
91.5 
331.1 
 
Midstream services
 
20.3 
19.1 
76.2 
38.6 
 
Midstream services-affiliates
 
111.6 
122.7 
342.5 
289.7 
 
Cost of sales
 
(124.5)
(64.2)
(305.1)
(397.6)
 
Operating expenses
 
(44.3)
(37.9)
(136.9)
(108.2)
 
Gain on Litigation Settlement
 
 
0 
 
0 
 
Gain (loss) on derivative activity
 
0 
0 
0 
0 
 
Segment profit
 
105.3 
111.4 
305.5 
320.6 
 
Depreciation and amortization
 
(44.4)
(31.6)
(123.6)
(91.7)
 
Impairment
 
0 
 
0 
 
 
Goodwill
 
1,186.8 
1,168.2 
1,186.8 
1,168.2 
1,168.2 
Capital expenditures
 
29.0 
79.7 
183.4 
180.2 
 
Identifiable assets
 
3,995.0 
 
3,995.0 
 
3,302.9 
Louisiana Operating Segment [Member]
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Product sales
 
399.0 
426.5 
1,173.6 
1,075.6 
 
Product sales - affiliates
 
17.6 
36.4 
37.4 
38.7 
 
Midstream services
 
63.3 
38.9 
184.5 
87.3 
 
Midstream services-affiliates
 
5.1 
2.0 
14.3 
2.0 
 
Cost of sales
 
(415.2)
(462.6)
(1,210.4)
(1,104.2)
 
Operating expenses
 
(27.2)
(20.3)
(78.7)
(41.9)
 
Gain on Litigation Settlement
 
 
6.1 
 
6.1 
 
Gain (loss) on derivative activity
 
0 
0 
0 
0 
 
Segment profit
 
42.6 
27.0 
120.7 
63.6 
 
Depreciation and amortization
 
(27.4)
(19.1)
(81.8)
(43.4)
 
Impairment
 
(576.1)
 
(576.1)
 
 
Goodwill
 
210.7 
786.8 
210.7 
786.8 
786.8 
Capital expenditures
 
13.5 
79.1 
43.4 
222.4 
 
Identifiable assets
 
2,562.3 
 
2,562.3 
 
3,316.5 
Oklahoma Operating Segment [Member]
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Product sales
 
3.9 
0 
2.4 
11.5 
 
Product sales - affiliates
 
4.6 
0 
10.2 
147.9 
 
Midstream services
 
9.4 
0 
29.9 
0 
 
Midstream services-affiliates
 
34.5 
45.8 
94.7 
108.1 
 
Cost of sales
 
(9.4)
0 
(14.6)
(133.9)
 
Operating expenses
 
(7.2)
(7.0)
(23.3)
(21.0)
 
Gain on Litigation Settlement
 
 
0 
 
0 
 
Gain (loss) on derivative activity
 
0 
0 
0 
   
 
Segment profit
 
35.8 
38.8 
99.3 
112.6 
 
Depreciation and amortization
 
(11.9)
(11.8)
(37.2)
(37.6)
 
Impairment
 
0 
 
0 
 
 
Goodwill
 
190.3 
190.3 
190.3 
190.3 
190.3 
Capital expenditures
 
19.7 
2.5 
37.2 
10.5 
 
Identifiable assets
 
895.7 
 
895.7 
 
892.8 
Crude And Condensate Segment [Member]
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Product sales
 
353.7 
100.1 
1,075.5 
226.3 
 
Product sales - affiliates
 
0.4 
0 
0.8 
0 
 
Midstream services
 
18.3 
10.6 
60.7 
28.9 
 
Midstream services-affiliates
 
3.6 
2.4 
10.6 
2.4 
 
Cost of sales
 
(334.8)
(90.2)
(1,020.4)
(207.8)
 
Operating expenses
 
(26.3)
(14.6)
(73.7)
(29.3)
 
Gain on Litigation Settlement
 
 
0 
 
0 
 
Gain (loss) on derivative activity
 
0 
0 
0 
0 
 
Segment profit
 
14.9 
8.3 
53.5 
20.5 
 
Depreciation and amortization
 
(12.9)
(11.2)
(41.5)
(23.4)
 
Impairment
 
(223.1)
 
(223.1)
 
 
Goodwill
 
142.1 
112.5 
142.1 
112.5 
112.5 
Capital expenditures
 
38.6 
43.8 
170.6 
91.3 
 
Identifiable assets
 
980.8 
 
980.8 
 
871.8 
Corporate Segment [Member]
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
Product sales
 
0 
0 
0 
0 
 
Product sales - affiliates
 
(17.6)
(17.8)
(50.3)
(43.5)
 
Midstream services
 
0 
0 
0 
0 
 
Midstream services-affiliates
 
(4.5)
(2.0)
(12.8)
(2.0)
 
Cost of sales
 
22.1 
19.8 
63.1 
45.5 
 
Operating expenses
 
0 
0 
0 
0 
 
Gain on Litigation Settlement
 
 
0 
 
0 
 
Gain (loss) on derivative activity
 
5.2 
1.0 
6.6 
(1.9)
 
Segment profit
 
5.2 
1.0 
6.6 
(1.9)
 
Depreciation and amortization
 
(1.8)
(0.9)
(5.0)
(1.5)
 
Impairment
 
0 
 
0 
 
 
Goodwill
 
0 
0 
0 
0 
0 
Capital expenditures
 
3.9 
3.9 
10.6 
12.6 
 
Identifiable assets
 
$ 334.2 
 
$ 334.2 
 
$ 318.0 
Segment Information (Reconciliation of Segment Profit to Operating Income) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Segment Reporting [Abstract]
 
 
 
 
Segment profit
$ 203.8 
$ 186.5 
$ 585.6 
$ 515.4 
General and administrative expenses
(33.5)
(23.5)
(102.3)
(64.8)
Loss on disposition of assets
(3.2)
0 
(3.2)
0 
Depreciation and amortization
(98.4)
(74.6)
(289.1)
(197.6)
Impairment
(799.2)
0 
(799.2)
0 
Operating income (loss)
$ (730.5)
$ 88.4 
$ (608.2)
$ 253.0 
Discontinued Operations (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Sep. 30, 2014
Sep. 30, 2015
Gulf Coast Fractionators [Member]
Mar. 31, 2014
Gulf Coast Fractionators [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
Disposal Group, Including Discontinued Operation, Revenue, External
 
 
 
$ 6.8 
 
 
Disposal Group, Including Discontinued Operation, Revenue, Related Party
 
 
 
10.5 
 
 
Operating revenues
 
 
 
17.3 
 
 
Operating expenses
 
 
 
15.7 
 
 
Disposal Group, Including Discontinued Operation, Total
 
 
 
15.7 
 
 
Income before income taxes
 
 
 
1.6 
 
 
Income tax expense
 
 
 
0.6 
 
 
Net income
0 
0 
0 
1.0 
 
 
Net income including non-controlling interest
$ 0 
$ 0 
$ 0 
$ 1.0 
 
 
Equity Method Investment, Ownership Percentage
 
 
 
 
38.75% 
38.75% 
Supplemental Cash Flow Information (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2015
Other Significant Noncash Transactions [Line Items]
 
Other Significant Noncash Transaction, Value of Consideration Given
$ 180.0 
Common Class C [Member]
 
Other Significant Noncash Transactions [Line Items]
 
Other Significant Noncash Transaction, Value of Consideration Given
180.0 
Midstream Holdings [Member]
 
Other Significant Noncash Transactions [Line Items]
 
Other Significant Noncash Transaction, Value of Consideration Given
$ 66.5 
Other Information (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2015
Dec. 31, 2014
Other Liabilities Disclosure [Abstract]
 
 
Accrued interest
$ 54.7 
$ 16.9 
Accrued wages and benefits, including taxes
29.9 
19.7 
Accrued ad valorem taxes
30.2 
23.2 
Capital expenditure accruals
18.4 
22.6 
Suspense producer payments
17.5 
0 
Current Other Liabilities
55.2 
67.4 
Other current liabilities
$ 205.9 
$ 149.8 
Subsequent Events (Details) (Subsequent Event [Member], USD $)
0 Months Ended 0 Months Ended
Oct. 29, 2015
Oct. 29, 2015
Oct. 1, 2015
Delaware Basin System [Member]
Subsequent Event [Line Items]
 
 
 
Business Acquisition, Effective Date of Acquisition
 
 
Oct. 01, 2015 
Business Combination, Consideration Transferred
 
 
$ 143,000,000 
Issuance of Common Shares to Parent In a Private Placement
 
2,849,100 
 
Proceeds from Issuance of Common Stock
$ 50,000,000.0