ENLINK MIDSTREAM PARTNERS, LP, 10-Q filed on 11/5/2014
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2014
Oct. 24, 2014
Document Information [Line Items]
 
 
Document Type
10-Q 
 
Document Fiscal Period Focus
Q3 
 
Document Period End Date
Sep. 30, 2014 
 
Document Fiscal Year Focus
2014 
 
Amendment Flag
false 
 
Entity Registrant Name
EnLink Midstream 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
 
233,042,749 
Condensed Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Current assets:
 
 
Cash and cash equivalents
$ 24.1 
$ 0 
Accounts receivable:
 
 
Trade, net of allowance for bad debt
46.3 
0.4 
Accrued revenue and other
220.6 
0 
Related party
113.8 
0 
Fair value of derivative assets
1.1 
0 
Natural gas and natural gas liquids, inventory, prepaid expenses and other
56.4 
5.8 
Assets held for disposition
0 
72.7 
Total current assets
462.3 
78.9 
Property and equipment, net of accumulated depreciation of $1,347.2 and $1,169.8, respectively
4,390.6 
1,768.1 
Fair value of derivative assets
0.2 
0 
Intangible assets, net of accumulated amortization of $23.2
501.8 
0 
Goodwill
2,257.8 
401.7 
Investment in unconsolidated affiliate
276.1 
61.1 
Other Assets, net
28.8 
0 
Total assets
7,917.6 
2,309.8 
Current liabilities:
 
 
Accounts payable, drafts payable and other
33.5 
1.7 
Related party payables
4.2 
0 
Accrued gas and crude oil purchases
198.3 
0 
Fair value of derivative liabilities
0.9 
0 
Accrued capital expenditures
35.6 
0 
Contract liability
21.2 
0 
Other current liabilities
84.3 
38.7 
Accrued interest
30.9 
0 
Liabilities held for disposition
0 
37.0 
Total current liabilities
408.9 
77.4 
Long-term debt
1,746.7 
0 
Asset retirement obligation
10.8 
7.7 
Fair value of derivative liabilities
0.6 
0 
Other long-term liabilities
87.7 
0 
Deferred tax liability
72.7 
440.9 
Partners' equity
5,590.2 
1,783.8 
Total liabilities and partners' equity
$ 7,917.6 
$ 2,309.8 
Condensed Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Assets, Noncurrent [Abstract]
 
 
Allowance for bad debt
$ 0 
$ 0 
Property and equipment, accumulated depreciation
1,347.2 
1,169.8 
Intangible assets, accumulated amortization
$ 23.2 
$ 0 
Condensed Consolidated Statements of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Revenues:
 
 
 
 
Revenues
$ 644.1 
$ 46.8 
$ 1,627.9 
$ 136.1 
Revenue - affiliates
206.3 
531.4 
872.0 
1,557.0 
Gain (loss) on derivative activity
1.0 
0 
(1.9)
0 
Total Revenues
851.4 
578.2 
2,498.0 
1,693.1 
Operating costs and expenses:
 
 
 
 
Purchased gas, NGLs, condensate and crude oil
597.2 
435.5 
1,798.0 
1,279.6 
Operating expenses
75.8 
35.8 
193.3 
116.0 
General and administrative
22.8 
10.8 
62.8 
32.3 
Depreciation and amortization
71.6 
48.0 
192.3 
138.6 
Gain on Litigation Settlement
(6.1)
0 
(6.1)
0 
Total operating cost and expenses
761.3 
530.1 
2,240.3 
1,566.5 
Operating income
90.1 
48.1 
257.7 
126.6 
Other income (expense):
 
 
 
 
Interest expense, net of interest income
(12.7)
0 
(30.5)
0 
Income from equity investment
5.6 
5.8 
14.3 
10.2 
Gain on Extinguishment of Debt
2.4 
0 
3.2 
0 
Other income (expense)
0.2 
0 
(0.7)
0 
Total other income (expense)
(4.5)
5.8 
(13.7)
10.2 
Income from continuing operations before non-controlling interest and income taxes
85.6 
53.9 
244.0 
136.8 
Income tax (provision) benefit
0.1 
(19.3)
(20.7)
(49.2)
Net income from continuing operations
85.7 
34.6 
223.3 
87.6 
Discontinued Operations:
 
 
 
 
Income (loss) from discontinued operations, net of tax
0 
(4.0)
1.0 
6.3 
Income from discontinued operations attributable to non-controlling interest, net of tax
0 
0.3 
0 
1.4 
Discontinued operations, net of tax
0 
(4.3)
1.0 
4.9 
Net income
85.7 
30.3 
224.3 
92.5 
Net income attributable to the non-controlling interest
41.7 
0 
94.8 
0 
Net income attributable to EnLink Midstream Partners, LP
44.0 
30.3 
129.5 
92.5 
Predecessor interest in net income
0 
30.3 
35.5 
92.5 
General partner interest in net income
3.5 
0 
7.5 
0 
Limited partners' interest in net income attributable to EnLink Midstream Partners, LP
$ 40.5 
$ 0 
$ 86.5 
$ 0 
Net income attributable to EnLink Midstream Partners, LP per limited partners' unit:
 
 
 
 
Basic per common unit
$ 0.18 
$ 0.00 
$ 0.38 
$ 0.00 
Diluted per common unit
$ 0.18 
$ 0.00 
$ 0.38 
$ 0.00 
Condensed Consolidated Statements of Operations (parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Affiliate purchased gas, NGLs, condensate and crude
$ 597.2 
$ 435.5 
$ 1,798.0 
$ 1,279.6 
Affiliate general and administrative expense
22.8 
10.8 
62.8 
32.3 
Affiliated Entity [Member]
 
 
 
 
Affiliate purchased gas, NGLs, condensate and crude
24.1 
397.8 
349.9 
1,170.4 
Affiliate operating expenses
0 
8.9 
5.9 
26.9 
Affiliate general and administrative expense
$ 1.0 
$ 10.8 
$ 10.6 
$ 32.3 
Consolidated Statements of Changes in Partners' Equity (USD $)
In Millions, except Share data, unless otherwise specified
Total
Common Units
General Partner Interest
Predecessor [Member]
Noncontrolling Interest [Member]
Balance at Dec. 31, 2013
$ 1,783.8 
$ 0 
$ 0 
$ 1,783.8 
$ 0 
Balance (Shares) at Dec. 31, 2013
 
0 
0 
 
 
Increase (Decrease) in Partners' Capital
 
 
 
 
 
Distributions to predecessor
(95.0)
0 
0 
(95.0)
0 
Elimination of deferred taxes due to reorganization of predecessor
467.5 
0 
0 
467.5 
0 
Issuance of units for reorganization of predecessor equity
0 
1,095.9 
0 
(2,191.8)
1,095.9 
Issuance of common units for acquisition of Partnership
3,378.3 
3,329.6 
48.7 
0 
0 
Units acquired during period in business combination
 
109,100,000 
1,600,000 
 
 
Issuance of units for reorganization of predecessor equity, shares
 
120,500,000 
0 
 
 
Issuance of common units
71.9 
71.9 
0 
0 
0 
Issuance of common units for acquisition of Partnership, shares
 
2,400,000 
0 
 
 
Proceeds from exercise of unit options
0.4 
0.4 
0 
0 
0 
Conversion of restricted units for common units, net of units withheld for taxes
(0.5)
(0.5)
0 
0 
0 
Restricted Stock, Shares Issued Net of Shares for Tax Withholdings
 
0 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period
31,382 
100,000 
0 
 
 
Unit-based compensation
12.7 
5.9 
6.8 
0 
0 
Stock-based compensation, shares
 
0 
0 
 
 
Distributions
(146.3)
(136.1)
(10.2)
0 
0 
Distributions to non-controlling interest
(106.9)
0 
0 
0 
(106.9)
Other Ownership Interests, Units Issued
 
0 
0 
 
 
Net income (loss)
224.3 
86.5 
7.5 
35.5 
94.8 
Net Income (Loss), shares
 
0 
0 
 
 
Balance at Sep. 30, 2014
$ 5,590.2 
$ 4,453.6 
$ 52.8 
$ 0 
$ 1,083.8 
Balance (Shares) at Sep. 30, 2014
 
232,100,000 
1,600,000 
 
 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Statement of Cash Flows [Abstract]
 
 
Net income from continuing operations
$ 223.3 
$ 87.6 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization
192.3 
138.6 
Accretion expense
0.4 
0.3 
Gain on Extinguishment of Debt
(3.2)
0 
Deferred tax expense (benefit)
20.4 
10.8 
Non-cash stock-based compensation
12.7 
0 
Loss on derivatives recognized in net income
1.9 
0 
Cash paid on derivatives
1.7 
0 
Amortization of debt issue costs
0.6 
0 
Amortization of premium on notes
(1.7)
0 
Distribution of earnings from equity investment
6.3 
10.9 
Income from equity investment
(14.3)
(10.2)
Changes in assets and liabilities:
 
 
Accounts receivable, accrued revenue and other
42.4 
0 
Natural gas and natural gas liquids, prepaid expenses and other
(26.4)
(1.1)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities
(67.6)
8.1 
Net cash provided by operating activities
385.4 
245.0 
Cash flows from investing activities:
 
 
Additions to property and equipment
(472.1)
(201.3)
Acquisition of business
(35.2)
0 
Deposit for acquisition
(23.5)
0 
Investment in Equity Method Investments
(5.7)
0 
Distribution from equity investment company in excess of earnings
7.6 
1.1 
Net cash used in investing activities
(528.9)
(200.2)
Cash flows from financing activities:
 
 
Proceeds from borrowings
1,974.0 
0 
Payments on borrowings
(1,586.7)
0 
Payments on capital lease obligations
(2.1)
0 
Decrease in drafts payable
(2.6)
0 
Debt refinancing costs
(6.4)
0 
Conversion of restricted units, net of units withheld for taxes
(0.5)
0 
Proceeds from Issuance of Common Units
71.9 
0 
Distribution to non-controlling partners
(106.9)
0 
Proceeds from exercise of unit options
0.4 
0 
Distributions to partners
(146.3)
0 
Distributions to Predecessor
(27.2)
(117.7)
Net cash provided by financing activities
167.6 
(117.7)
Net cash provided by operating activities, Discontinued Operations
5.0 
11.2 
Net cash used in investing activities, Discontinued Operations
(0.6)
143.7 
Net cash used in financing activities - net distributions to Devon and non-controlling
(4.4)
(97.6)
Net cash provided by (used in) discontinued operations
0 
57.3 
Net increase (decrease) in cash and cash equivalents
24.1 
(15.6)
Cash and cash equivalents, end of period
24.1 
0 
Cash paid for interest
18.3 
0 
Cash paid for Income Taxes
$ 7.1 
$ 0 
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 and Midstream Holdings 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 (formerly known as Crosstex Energy, L.P.) 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 (formerly known as Crosstex Energy Services, L.P.), a Delaware limited partnership (the “Operating Partnership”), and the subsidiaries of the Operating Partnership.

EnLink Midstream GP, LLC (formerly known as Crosstex Energy 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 of limited partnership interests in the Partnership. At the same time, EnLink Midstream, Inc. (formerly known as Crosstex Energy, Inc.) (“EMI”), the entity that directly owns our General Partner, became a wholly-owned subsidiary of ENLC (together with the Acquisition, the “business combination”). Another wholly-owned subsidiary of ENLC owns the remaining 50% of the outstanding equity interests in Midstream Holdings. In this report, 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.

(b)Nature of Business
The Partnership primarily focuses on providing midstream energy services, including gathering, transmission, processing, fractionation and marketing, to producers of natural gas, natural gas liquids ("NGLs"), crude oil and condensate. We connect the wells of natural gas producers in our market areas to our gathering systems, process natural gas for the removal of NGLs, fractionate NGLs into purity products and market those products for a fee, transport natural gas and ultimately provide natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply sources and sell that natural gas to utilities, industrial consumers, other marketers and pipelines. We operate processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee-based arrangements. We provide a variety of crude oil and condensate services throughout the Ohio River Valley (“ORV”), which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks and brine disposal. We also have crude oil and condensate terminal facilities in south Louisiana that provide access for crude oil and condensate producers to the premium markets in this area. 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. Our crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a fee, transport oil from a producer site to an end user. Our processing plants remove NGLs and CO2 from a natural gas stream and our fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline.
Significant Accounting Policies
Significant Accounting Policies
(2) Significant Accounting Policies

(a)
Basis of Presentation

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles in the United States of America ("US GAAP") for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation.
 
Further, the unaudited consolidated financial statements give effect to the business combination and related transactions discussed above under the acquisition method of accounting and are treated as a reverse acquisition. Under the acquisition method of accounting, Midstream Holdings was the accounting acquirer in the transactions because its parent company, Devon, obtained control of the Partnership through the indirect control of the General Partner as a result of the business combination. Consequently, Midstream Holdings’ assets and liabilities retained their carrying values and are reflected in the balance sheet as of December 31, 2013 as the Predecessor. All financial results prior to March 7, 2014 reflect the historical operations of Midstream Holdings and are reflected as Predecessor income on 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 which was treated as a reorganization under common control with the removal of historical deferred taxes reflected through equity.

(b)
Management's Use of Estimates

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

(c)
Revenue Recognition

The Partnership recognizes revenue for sales or services at the time the natural gas, NGLs, condensate or crude oil are delivered or at the time the service is performed at a fixed or determinable price. The Partnership generally accrues one month of sales and the related gas, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. The Partnership's purchase and sale arrangements are generally reported in revenues and costs on a gross basis in the consolidated statement of operations in accordance with the Financial Accounting Standards Board Accounting Standards Codification ("FASB ASC") 605-45-45-1. Except for fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, has the risk and reward of ownership as evidenced by title transfer, schedules the transportation and assumes credit risk.

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

(d)
Gas Imbalance Accounting

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

(e)
Cash and Cash Equivalents

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

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

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

(g)
Property, Plant, and Equipment

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

Change in Depreciation Method. Historically, Midstream Holdings depreciated certain property, plant, and equipment using the units-of-production method. As a result of the business combination, the Partnership is operated as an independent midstream company and thus no longer has access to Devon’s proprietary reserve and production data historically used to compute depreciation under the units-of-production method. Additionally, the existing contracts with Devon were revised to a fee-based arrangement with minimum volume commitments. Effective March 7, 2014, the Partnership changed its method of computing depreciation for these assets to the straight-line method, consistent with the depreciation method applied to the Partnership’s acquired assets. In accordance with FASB ASC 250, the Partnership determined that the change in depreciation method is a change in accounting estimate effected by a change in accounting principle, and accordingly, the straight-line method will be applied on a prospective basis. This change is considered preferable because the straight-line method will more accurately reflect the pattern of usage and the expected benefits of such assets. The effect of this change in estimate resulted in a decrease in depreciation expense for the three and nine months ended September 30, 2014 by approximately $9.3 million and $21.0 million, or $0.04 and $0.09 per unit, respectively.

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

Impairment Review. We evaluate our property, plant and equipment for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment loss is recognized equal to the excess of the asset’s carrying value over its fair value. The fair values of long-lived assets are generally determined from estimated discounted future net cash flows. Our estimate of cash flows is based on assumptions which include (1) the amount of fee based services and the purchase and resale margins on natural gas, together with volume of gas, NGL, condensate and crude oil available to the asset, (2) markets available to the asset, (3) operating expenses, and (4) future natural gas prices, crude prices, condensate prices and NGL product prices. The volume of available gas, condensate, NGLs and crude oil to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, condensate and crude oil prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

(h)
Equity Method of Accounting

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

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

(i)
Goodwill

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

The Partnership has approximately $2.3 billion of goodwill at September 30, 2014 primarily related to the legacy Partnership operations as a result of the March 7, 2014 business combination.

(j)
Intangible Assets

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

The following table represents the Partnership's total intangible assets as of September 30, 2014 (in millions):
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount

 
 
 
 
 
Customer relationships
$
525.0

 
$
(23.2
)
 
$
501.8



The weighted average amortization period for intangible assets is 13.7 years. Amortization expense for intangibles was approximately $10.2 million and $23.2 million for the three and nine months ended September 30, 2014, respectively.

The following table summarizes the Partnership's estimated aggregate amortization expense for the identified periods (in millions):
2014 (remaining)
$
10.2

2015
41.0

2016
41.0

2017
41.0

2018
41.0

Thereafter
327.6

Total
$
501.8



(k) Asset Retirement Obligations

The Partnership recognizes liabilities for retirement obligations associated with its pipelines and processing and fractionation facilities. Such liabilities are recognized when there is a legal obligation associated with the retirement of the assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property, plant and equipment. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The Partnership’s retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of the long-lived assets. The asset retirement cost is depreciated using the straight line depreciation method similar to that used for the associated property, plant and equipment.
(l) Other Long-Term Liabilities
Included in other current and long-term liabilities is an $85.2 million total liability related to an onerous performance obligation assumed in the business combination. The Partnership has one delivery contract which requires it to deliver a specified volume of gas each month at an indexed base price with a term to 2019. The Partnership realizes a loss on the delivery of gas under this contract each month based on current prices. The fair value of this onerous performance obligation was recorded as a result of the March 7, 2014 business combination and was based on forecasted discounted cash obligations in excess of market under this gas delivery contract. The liability is reduced each month as delivery is made over the remaining life of the contract with an offsetting reduction in purchase gas costs.
(m) Derivatives

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

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

(n) Concentrations of Credit Risk

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

During the three and nine months ended September 30, 2014 and 2013, the Partnership had no third party customer that individually represented greater than 10.0% of its consolidated midstream revenues other than affiliate transactions with Devon which represented 24.2% and 34.9% of the consolidated midstream revenues for the three and nine months ended September 30, 2014, respectively, and 91.9% and 92.0% for the three and nine months ended September 30, 2013, respectively. As the Partnership continues to grow and expand, the relationship between individual customer sales and consolidated total sales is expected to continue to change. Devon represents a significant percentage of revenues and the loss of Devon as a customer would have a material adverse impact on the Partnership's results of operations because the gross operating margin received from transactions with this customer is material to the Partnership.

(o) Environmental Costs

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

(p) Unit-Based Awards

Prior to the business combination, Devon granted certain share-based awards to members of its board of directors and selected employees. The Predecessor did not grant share-based awards because it previously participated in Devon’s share-based award plans since the Predecessor comprised Devon's U.S. midstream assets. The awards granted under Devon’s plans were measured at fair value on the date of grant and were recognized as expense over the applicable requisite service periods.
The Partnership recognizes compensation cost related to all unit-based awards in its consolidated financial statements in accordance with FASB ASC 718. The Partnership and ENLC each have similar unit-based payment plans for employees. Unit-based compensation associated with ENLC's unit-based compensation plans awarded to directors, officers and employees of the General Partner of the Partnership are recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership and Midstream Holdings.

(q) Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
(r) Discontinued Operations
The Partnership classifies as discontinued operations its assets or asset groups that have clearly distinguishable cash flows and are in the process of being sold or have been sold. The Partnership also includes as discontinued operations Predecessor assets that were not contributed in the business combination.
(s) Debt Issue Costs
Costs incurred in connection with the issuance of long-term debt are deferred and recorded as interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs.
(t) Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"). ASU 2014-09 will replace existing revenue recognition requirements in US GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires significantly expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period and is to be applied retrospectively, with early application not permitted. We are currently evaluating the impact the pronouncement will have on our consolidated financial statements and related disclosures. Subject to this evaluation, we have reviewed all recently issued accounting pronouncements that became effective during the nine months ended September 30, 2014, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.
Acquisition
Mergers Acquisitions And Dispositions Disclosures
(3) Acquisition
 
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 120,542,441 units representing a new class of limited partnership interests in the Partnership (the "Class B Units"). 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 burdens and benefits of Devon’s 38.75% interest in Gulf Coast Fractionator ("GCF") in Mt. Belvieu, Texas.
Under the acquisition method of accounting, Midstream Holdings is 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.
Since equity consideration was issued for this business combination, the purchase of these assets and liabilities has been excluded from our statement of cash flows, except for transaction related costs totaling $34.7 million assumed by the Partnership at closing and subsequently paid by the Partnership.
The following table summarizes the purchase price (in millions, except per unit price):
EnLink Midstream Partners, LP outstanding units:
 
    Common units held by public unitholders
75.1

    Common units held by EMI
18.0

    Preferred units held by third party (1)
17.1

    Restricted units
0.4

        Total units exchanged
110.6

 
 
EnLink Midstream Partners, LP common unit price (2)
$
30.51

EnLink Midstream Partners, LP common units fair value
$
3,374.4

EnLink Midstream Partners, LP outstanding unit options fair value
$
3.9

        Total purchase price
$
3,378.3

(1)
The Partnership converted the preferred units to common units in February 2014.
(2)
The final purchase price is based on the market value of the Partnership's common units as of the closing date, March 7, 2014.

The following table is a summary of the preliminary fair value of the assets acquired and liabilities assumed from the Partnership in the business combination as of March 7, 2014 (in millions):
Assets acquired:
 
     Current assets
$
435.9

     Property, plant and equipment
2,341.9

Intangibles assets
524.9

Equity investment
221.5

Goodwill
1,856.0

Other long-term assets
1.1

Liabilities assumed:
 
     Current liabilities
(474.0
)
     Long-term debt
(1,364.3
)
     Deferred taxes
(63.6
)
     Other long-term liabilities
(101.1
)
         Net assets acquired
$
3,378.3



Goodwill recognized from the business combination primarily relates to the value created from additional growth opportunities and greater operating leverage in core areas. The goodwill is allocated among our Texas, Louisiana, Oklahoma, and ORV segments. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. All of the goodwill is non-deductible for tax purposes.
For the period from March 7, 2014 to September 30, 2014, the Partnership recognized $1,661.7 million of revenues and $1,636.7 million of operating expenses 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, 2014 and 2013 gives effect to the business combination as if it had occurred on January 1, 2013. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results. As of March 7, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 4. Pro forma financial information associated with the business combination and with these agreements with Devon is reflected below.
 
Three Months Ended
 
Nine Months Ended
 
September 30, 2013
 
September 30, 2014
 
September 30, 2013
 
(in millions, except for per unit data)
Pro forma total revenues
$
621.6

 
$
2,667.9

 
$
1,818.4

Pro forma net income
$
5.5

 
$
217.3

 
$
114.0

Pro forma net income attributable to EnLink Midstream Partners, LP
$
(24.4
)
 
$
101.2

 
$
30.3

Pro forma net income per common unit:
 
 


 
 
Basic
$
(0.13
)
 
$
0.38

 
$
0.11

Diluted
$
(0.13
)
 
$
0.38

 
$
0.11

Affiliate Transactions
Related Party Transactions Disclosure
(4) Affiliate Transactions

The Partnership engages in various transactions with Devon and other affiliated entities. Prior to March 7, 2014, these 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. Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with nonaffiliated third parties. The amounts related to affiliate transactions are specified in the accompanying financial statements.
The Predecessor’s historical assets comprised all of Devon’s U.S. midstream assets and operations. However, only its assets serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as contractual rights to the burdens and benefits of Devon's 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the business combination. Assets that were not contributed from the Predecessor are reflected as discontinued operations prior to March 7, 2014 and reflected as a reduction in equity at March 7, 2014. Further, the Predecessor’s historical combined financial statements include U.S. federal and state income tax expense. As a result of the business combination, Midstream Holdings is a legal entity that is treated as a partnership for tax purposes and is not subject to U.S. federal income tax or certain state income taxes in the future. The business combination transactions were treated as a reorganization under common control for tax purposes. Therefore, the elimination of the related deferred tax liability is reflected as an increase in equity.
Midstream Holdings, in which the Partnership holds a 50% economic interest as of March 7, 2014, conducts business with Devon pursuant to the gathering and processing agreements described below.  The legacy Partnership also historically has maintained a relationship with Devon as a customer, as described in more detail below.
Gathering and Processing Agreements
As described in Note 1, Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon.  In connection with the consummation of the business combination, EnLink Midstream Services, LLC, a wholly-owned subsidiary of Midstream Holdings ("EnLink Midstream Services"), entered into 10-year gathering and processing agreements with Devon pursuant to which EnLink Midstream Services provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon Gas Services, L.P., a subsidiary of Devon ("Gas Services") to Midstream Holdings’ gathering and processing systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. SWG Pipeline, L.L.C. (“SWG Pipeline”), another wholly-owned subsidiary of Midstream Holdings, entered into a 10-year gathering agreement with Devon pursuant to which SWG Pipeline provides gathering, treating, compression, dehydration and redelivery services, as applicable, for natural gas delivered by Gas Services to another of the Partnership's gathering system in the Barnett Shale.
These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. Pursuant to the gathering and processing agreements, Devon has committed to deliver specified average minimum daily volumes of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter for a five-year period following execution. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.
The gathering and processing agreements are fee-based, and Midstream Holdings is paid a specified fee per MMBtu for natural gas gathered on Midstream Holdings’ gathering systems and a specified fee per MMBtu for natural gas processed. The particular fees, all of which are subject to an automatic annual inflation escalator at the beginning of each year, differ from one system to another and do not contain a fee redetermination clause.
On August 29, 2014, Gas Services assigned its 10-year gathering and processing agreement to Linn Exchange Properties, LLC (“Linn Energy”), which is a subsidiary of Linn Energy, LLC, in connection with Gas Services' divestiture of certain of its southeastern Oklahoma assets. Such assignment will be effective as of December 1, 2014. Accordingly, beginning on December 1, 2014, Linn Energy will perform Gas Services' obligations under the agreement, which remains in full force and effect. The assignment of this agreement relates to production dedicated to our Northridge assets in southeastern Oklahoma. Gross operating margin related to our Northridge assets totaled $6.5 million and $22.3 million for the three and nine months ended September 30, 2014, respectively.
Historical Customer Relationship with Devon
As noted above, the Partnership maintained a customer relationship with Devon prior to the business combination pursuant to which certain of the Partnership's subsidiaries provide gathering, transportation, processing and gas lift services to Devon subsidiaries in exchange for fee-based compensation under several agreements with Devon.  The terms of these agreements vary, but the agreements expire between March 2015 and July 2021 and they automatically renew for month-to-month or year-to-year periods unless canceled by Devon prior to expiration.  In addition, one of the Partnership's subsidiaries has agreements with a subsidiary of Devon pursuant to which the Partnership's subsidiary purchases and sells NGLs and pays or receives, as applicable, a margin-based fee.  These NGL purchase and sale agreements have month-to-month terms.
Transition Services Agreement
In connection with the consummation of the business combination, the Partnership entered into a transition services agreement with Devon pursuant to which Devon provides certain services to the Partnership with respect to the business and operations of Midstream Holdings, including IT, accounting, pipeline integrity, compliance management and procurement services, and the Partnership provides certain services to Devon and its subsidiaries, including IT, human resources and other commercial and operational services. The Partnership expects most services under the transition services agreement to end by December 31, 2014.
GCF Agreement
In connection with the closing of the business combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Devon agreed, from and after the closing of the business combination, to hold for the benefit of Midstream Holdings the economic benefits and burdens of Devon’s 38.75% interest in GCF, which owns a fractionation facility in Mont Belvieu, Texas.
Lone Camp Gas Storage Agreement
In connection with the closing of the business combination, Midstream Holdings entered into an agreement with Gas Services under which Midstream Holdings provides gas storage services at its Lone Camp storage facility. Under this agreement, Gas Services reimburses Midstream Holdings for the expenses it incurs in providing the storage services. This agreement has minimal to no impact on Midstream Holdings' annual revenue.
Acacia Transportation Agreement
In connection with the closing of the business combination, Midstream Holdings entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Midstream Holdings provides transportation services to Devon on its Acacia pipeline.
Office Leases
In connection with the closing of the business combination, the Operating Partnership entered into three office lease agreements with a wholly-owned subsidiary of Devon pursuant to which the Operating Partnership leases office space from Devon at its Bridgeport, Oklahoma City and Cresson office buildings. Rent payable to Devon under these lease agreements is $174,000, $31,000 and $66,000, respectively, on an annual basis.
Tax Sharing Agreement
In connection with the closing of the business combination, the Partnership, ENLC and Devon entered into a tax sharing agreement providing for the allocation of responsibilities, liabilities and benefits relating to any tax for which a combined tax return is due.

The following presents financial information for the Predecessor's affiliate transactions and other transactions with Devon, all of which are settled through an adjustment to equity prior to March 7, 2014 (in millions):
 
Three Months Ended
 September 30,
 
Nine Months Ended
September 30,
 
2013
 
2014
 
2013
Continuing Operations:
 
 
 
 
 
Operating revenues - affiliates
$
(531.4
)
 
$
(436.4
)
 
$
(1,557.0
)
Operating expenses - affiliates
417.5

 
340.0

 
1,229.6

Net affiliate transactions
(113.9
)
 
(96.4
)

(327.4
)
Capital expenditures
44.7

 
16.2

 
201.3

Other third-party transactions, net
(50.8
)
 
53.0

 
8.4

Net third-party transactions
(6.1
)
 
69.2


209.7

Net cash distributions to Devon - continuing operations
(120.0
)
 
(27.2
)

(117.7
)
Non-cash distribution of net assets to Devon
—

 
(23.5
)
 
—

Total net distributions per equity
$
(120.0
)
 
$
(50.7
)
 
$
(117.7
)
 
 
 
 
 
 
Discontinued operations:
 
 
 
 
 
Operating revenues - affiliates
$
(20.8
)
 
$
(10.4
)
 
$
(68.1
)
Operating expenses - affiliates
7.8

 
5.0

 
25.4

Cash used in financing activities - affiliates
(0.4
)
 
—

 
(5.6
)
Net affiliate transactions
(13.4
)
 
(5.4
)

(48.3
)
Capital expenditures
(0.1
)
 
0.6

 
5.3

Other third-party transactions, net
(73.5
)
 
0.4

 
(54.6
)
Net third-party transactions
(73.6
)
 
1.0


(49.3
)
Net distributions to Devon and non-controlling interests - discontinued operations
(87.0
)
 
(4.4
)
 
(97.6
)
Non-cash distribution of net assets to Devon
—

 
(39.9
)
 
—

Total net distributions per equity
$
(87.0
)
 
$
(44.3
)
 
$
(97.6
)
Total distributions- continuing and discontinued operations
$
(207.0
)
 
$
(95.0
)
 
$
(215.3
)


For the three and nine months ended September 30, 2014 and 2013, Devon was a significant customer to the Partnership. Devon accounted for 24.2% and 34.9% of the Partnership's revenues for the three and nine months ended September 30, 2014, respectively, and 91.9% and 92.0% for the three and nine months ended September 30, 2013, respectively. The affiliate revenues after March 7, 2014 through September 30, 2014 were $435.6 million. The Partnership had an accounts receivable balance related to transactions with Devon of $113.2 million as of September 30, 2014. The remaining related party receivable balance of $0.6 million is attributable to transactions with ENLC. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $3.8 million as of September 30, 2014.
Share-based compensation costs included in the management services fee charged to Midstream Holdings by Devon were approximately $2.8 million for the nine months ended September 30, 2014 and $3.5 million and $10.1 million for the three and nine months ended September 30, 2013, respectively. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Partnership by Devon were approximately $1.6 million for the nine months ended September 30, 2014 and $2.2 million and $6.1 million for the three and nine months ended September 30, 2013, respectively. These amounts are included in general and administrative expenses in the accompanying statements of operations.
Long-Term Debt
Long-Term Debt
5) Long-Term Debt
 
As of September 30, 2014, long-term debt consisted of the following (in millions):
 
September 30, 2014
Bank credit facility (due 2019), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at September 30, 2014 was 1.9%
$
371.0

Senior unsecured notes (due 2019), net of discount of $2.7 million, which bear interest at the rate of 2.70%
397.3

Senior unsecured notes (due 2022), including a premium of $22.6 million, which bear interest at the rate of 7.125%
185.1

Senior unsecured notes (due 2024), net of discount of $3.5 million, which bear interest at the rate of 4.40%
446.5

Senior unsecured notes (due 2044), net of discount of $3.3 million, which bear interest at the rate of 5.60%
346.8

Debt classified as long-term
$
1,746.7



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

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

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

The percentages per annum, based upon the debt rating are as set forth below:
 
Pricing Level
Debt Ratings
Applicable Rate Commitment Fee
EuroDollar Rate/Letter of Credit
Base Rate +
 
 
1
A-/A3 or better
0.100%
1.000%
—
 
2
BBB+/Baa1
0.125%
1.125%
0.125%
 
3
BBB/Baa2
0.175%
1.250%
0.250%
 
4
BBB-/Baa3
0.225%
1.500%
0.500%
 
5
BB+/Ba1
0.275%
1.625%
0.625%
 
6
BB/Ba2 or worse
0.350%
1.750%
0.750%

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

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

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

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

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

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

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

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

The indentures governing the Senior Notes contain covenants that, among other things, limit 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.
Income Taxes
Income Tax Disclosure
(6) Income Taxes
The Predecessor’s historical combined financial statements include U.S. federal and state income tax expense. As a result of the business combination, the Predecessor was reorganized and Midstream Holdings is treated as a partnership and not subject to federal or certain state income taxes subsequent to the March 7, 2014 transaction date. The elimination of the related deferred federal and state income tax liabilities totaling $467.5 million, excluding $8.2 million of deferred taxes related to the Texas margin tax, is reflected through equity and treated as a reorganization under common control.
Net deferred tax liabilities also include $62.5 million of deferred taxes assumed in the business combination with the Partnership on March 7, 2014. The legacy Partnership has a wholly-owned corporate entity that was formed to acquire the common stock of Clearfield Energy, Inc. and assumed the carryover tax basis of the ORV assets acquired from Clearfield. This net deferred tax liability represents the future tax payable on the difference between the fair value and the tax basis of the assets acquired and is expected to become payable no later than 2027.
Partners' Capital Partners Capital
Partners' Capital Disclosure
(7)      Partners’ Capital

(a) Issuance of Common Units

In May 2014, the Partnership entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (“BMOCM”). Pursuant to the terms of the EDA, the Partnership may from time to time through BMOCM, as its sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75.0 million.
Through September 30, 2014, the Partnership sold an aggregate of 2.4 million common units under the EDA, generating proceeds of approximately $71.9 million (net of approximately $0.7 million of commissions to BMOCM). The Partnership used the net proceeds for general partnership purposes, including working capital, capital expenditures and repayments of indebtedness.

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

(c) 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 three and nine months ended September 30, 2014 (in millions except per unit amounts):
 
Three Months Ended
 September 30, 2014
 
Nine Months Ended
 September 30, 2014*
Limited partners’ interest in net income
$
40.5

 
$
86.5

Distributed earnings allocated to:
 
 
 
Common units and Class B Units (1) (2)
$
85.5

 
$
220.6

Unvested restricted units (1)
0.4

 
0.9

Total distributed earnings
$
85.9

 
$
221.5

Undistributed loss allocated to:
 
 
 
Common units and Class B Units (2)
$
(45.1
)
 
$
(134.6
)
Unvested restricted units
(0.2
)
 
(0.5
)
Total undistributed loss
$
(45.3
)
 
$
(135.1
)
Net income allocated to:
 
 
 
Common units and Class B Units (2)
$
40.3

 
$
86.1

Unvested restricted units
0.2

 
0.4

Total limited partners’ interest in net income
$
40.5

 
$
86.5

Basic and diluted net income per unit:
 
 
 
Basic
$
0.18

 
$
0.38

Diluted
$
0.18

 
$
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, 2014 represents a declared distribution of $0.37 per unit for common units payable on November 13, 2014 and nine months ended September 30, 2014 represents distributions of $0.36 per unit paid on May 14, 2014, distributions of $0.365 per unit paid on August 13, 2014 and distributions declared of $0.37 per unit payable on November 13, 2014.
(2) Nine months ended September 30, 2014 includes distribution of $0.10 per unit for Class B Units paid on May 14, 2014. The Class B Units converted into common units on a one-for-one basis on May 6, 2014.
 
The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the three and nine months ended September 30, 2014 (in millions):
 
Three Months Ended
 September 30, 2014
 
Nine Months Ended
 September 30, 2014*
Basic weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
231.0

 
230.3

Diluted weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
231.0

 
230.3

Dilutive effect of restricted units issued
0.4

 
0.3

    Total weighted average limited partner diluted common units outstanding
231.4

 
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 period presented.
Net income is allocated to the General Partner in an amount equal to its incentive distributions as described in Note 7(b). The General Partner's share of net income consists of incentive distributions to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of the Partnership’s net income adjusted for ENLC's unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows for the three and nine months ended September 30, 2014 (in millions
 
Three Months Ended
 September 30, 2014
 
Nine Months Ended
 September 30, 2014*
Income allocation for incentive distributions
$
6.3

 
$
13.6

Unit-based compensation attributable to ENLC’s restricted units
(3.1
)
 
(6.8
)
General Partner interest in net income
0.3

 
0.7

General Partner share of net income
$
3.5

 
$
7.5


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

The schedule below summarizes the changes in the Partnership’s asset retirement obligations:
 
September 30, 2014
 
September 30, 2013
 
(in millions)
Beginning asset retirement obligations
$
7.7

 
$
9.1

Revisions to existing liabilities
2.2

 
0.4

Liabilities acquired
0.5

 
—

Accretion
0.4

 
0.3

Ending asset retirement obligations
$
10.8

 
$
9.8

Investment in Unconsolidated Affiliate
Investment in unconsolidated affiliate
(9) Investment in Unconsolidated Affiliates

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

The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):
 
Gulf Coast Fractionators
 
Howard Energy Partners (1)
 
Total
Three months ended
 
 
 
 
 
September 30, 2014
 
 
 
 
 
Distributions
$
5.2

 
$
3.0

 
$
8.2

Equity in income
$
5.2

 
$
0.4

 
$
5.6

 
 
 
 
 
 
September 30, 2013
 
 
 
 
 
Distributions
$
12.0

 
$
—

 
$
12.0

Equity in income
$
5.8

 
$
—

 
$
5.8

 
 
 
 
 
 
Nine months ended
 
 
 
 
 
September 30, 2014 (1)
 
 
 
 
 
Distributions
$
5.2

 
$
8.7

 
$
13.9

Equity in income
$
13.2

 
$
1.1

 
$
14.3

 
 
 
 
 


September 30, 2013
 
 
 
 


Distributions
$
12.0

 
$
—

 
$
12.0

Equity in income
$
10.2

 
$
—

 
$
10.2


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

The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):
 
September 30, 2014
 
December 31, 2013
Gulf Coast Fractionators (1)
$
56.0

 
$
61.1

Howard Energy Partners
220.1

 
—

Total investments in unconsolidated affiliates
$
276.1

 
$
61.1

(1) Devon retained $13.1 million of the undistributed earnings due from GCF, as of March 7, 2014 when the GCF contractual right allocating the benefits and burdens of the 38.75% ownership interest in GCF to the Partnership became effective. The $13.1 million of the undistributed earnings was reflected as a reduction in the GCF investment on March 7, 2014.
Employee Incentive Plans
Employee Incentive Plans
(10) Employee Incentive Plans
 
(a)         Long-Term Incentive Plans
 
The Partnership and ENLC each have similar unit or unit-based payment plans for employees, which are described below.  Unit-based compensation associated with ENLC's unit-based compensation plan awarded to officers and employees of the Partnership are recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership and Midstream Holdings. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions): 
 
Three Months Ended
September 30,
 
Nine Months Ended 
September 30,
 
2014
 
2013
 
2014
 
2013
Cost of unit-based compensation allocated to Predecessor general and
    administrative expense (1)
$
—

 
$
3.5

 
$
2.8

 
$
10.1

Cost of unit-based compensation charged to general and administrative
    expense
4.9

 
—

 
10.9

 
—

Cost of unit-based compensation charged to operating expense
0.8

 
—

 
1.8

 
—

    Total amount charged to income
$
5.7

 
$
3.5

 
$
15.5

 
$
10.1


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

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

(b)  Restricted Incentive Units
 
The restricted incentive units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, 2014 is provided below:
 
Nine Months Ended 
September 30, 2014
EnLink Midstream Partners, LP Restricted Incentive Units:
Number of
Units
 
Weighted
Average
Grant-Date
 Fair Value
Non-vested, beginning of period
—

 
$
—

Assumed in business combination
371,225

 
30.51

Granted
701,119

 
31.65

Vested*
(39,833
)
 
30.63

Forfeited
(13,196
)
 
31.83

Non-vested, end of period
1,019,315

 
$
31.27

Aggregate intrinsic value, end of period (in millions)
$
31.0

 
 


 * Vested units include16,471 units withheld for payroll taxes paid on behalf of employees.

Restricted incentive units assumed in the business combination were valued as of March 7, 2014, will vest at the end of two years and are included in the restricted incentive units outstanding and the current unit-based compensation cost calculations at September 30, 2014. The Partnership issued restricted incentive units in 2014 to officers and other employees. These restricted incentive units typically vest at the end of three years.
 
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and nine months ended September 30, 2014 are provided below (in millions):


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

2014

2014
Aggregate intrinsic value of units vested

$
1.2


$
1.2

Fair value of units vested

$
1.2


$
1.2



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

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

(d)         EnLink Midstream, LLC’s Restricted Incentive Units
 
On February 5, 2014, ENLC's sole unitholder at the time, EnLink Midstream Manager, LLC, approved the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “Company Plan”). The Company Plan provides for the issuance of 11.0 million awards.
On March 7, 2014, effective as of the closing of the business combination, ENLC (i) assumed the Crosstex Energy, Inc. 2009 Long-Term Incentive Plan (the “2009 Plan”) and all awards thereunder outstanding following the business combination and (ii) amended and restated the 2009 Plan to reflect the conversion of the awards under the 2009 Plan relating to EMI’s common stock to awards in respect of common units of ENLC.
ENLC’s restricted incentive units are valued at their fair value at the date of grant which is equal to the market value of the common units on such date. A summary of the restricted incentive units activities for the nine months ended September 30, 2014 is provided below:
 
Nine Months Ended 
September 30, 2014
EnLink Midstream, LLC Restricted Incentive Units:
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-vested, beginning of period
—

 
$
—

Assumed in business combination
435,674

 
37.60

Granted
626,341

 
36.59

Vested*
(59,553
)
 
37.56

Forfeited
(11,859
)
 
36.54

Non-vested, end of period
990,603

 
$
36.97

Aggregate intrinsic value, end of period (in millions)
$
40.9

 
 


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

Restricted incentive units assumed in the business combination were valued as of March 7, 2014, will vest at the end of two years and are included in restricted incentive units outstanding and the current unit-based compensation cost calculations at September 30, 2014. ENLC issued restricted incentive units in 2014 to officers and other employees. These restricted incentive units typically vest at the end of three years and are included in restricted incentive units outstanding.
 
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and nine months ended September 30, 2014 are provided below (in millions):
 
 
Three Months Ended  
September 30,
Nine Months Ended 
September 30,
EnLink Midstream, LLC Restricted Incentive Units:
 
2014
 
2014
Aggregate intrinsic value of units vested
 
$
2.4

 
$
2.4

Fair value of units vested
 
$
2.2

 
$
2.2


As of September 30, 2014, there was $23.3 million of unrecognized compensation costs related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted average period of 2.1 years.
Derivatives
Derivatives
(11) Derivatives
 
Commodity Swaps
The Partnership manages its exposure to fluctuation in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge price and location risk related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs. The Partnership does not designate transactions as cash flow or fair value hedges for hedge accounting treatment under FASB ASC 815. Therefore, changes in the fair value of the Partnership's derivatives are recorded in revenue in the period incurred. In addition, the risk management policy does not allow the Partnership to take speculative positions with its derivative contracts.
The Partnership commonly enters into index (float-for-float) or fixed-for-float swaps in order to mitigate its cash flow exposure to fluctuations in the future prices of natural gas, NGLs and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. They are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate and crude, fixed-for-float swaps are used to protect cash flows against price fluctuations: 1) where the Partnership receives a percentage of liquids as a fee for processing third-party gas, 2) in the natural gas processing and fractionation components of our business and 3) where the Partnership is mitigating the price risk for product held in inventory or storage.
The components of gain (loss) on derivative activity in the consolidated statements of operations relating to commodity swaps are as follows for the three and nine months ended September 30, 2014 (in millions):
 
Three Months Ended
September 30, 2014
 
Nine Months Ended
September 30, 2014*
Change in fair value of derivatives
$
1.8

 
$
(0.2
)
Realized losses on derivatives
(0.8
)
 
(1.7
)
    Gain (loss) on derivative activity
$
1.0

 
$
(1.9
)

* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014. 
The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions):
 
September 30, 2014
Fair value of derivative assets — current
$
1.1

Fair value of derivative assets — long term
0.2

Fair value of derivative liabilities — current
(0.9
)
Fair value of derivative liabilities — long term
(0.6
)
    Net fair value of derivatives
$
(0.2
)

 
Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets at September 30, 2014. The remaining term of the contracts extend no later than December 2016.
 
 
 
 
 
 
September 30, 2014
Commodity
 
Instruments
 
Unit
 
Volume
 
Fair Value
 
 
 
 
 
 
(In millions)
NGL (short contracts)
 
Swaps
 
Gallons
 
(61.3
)
 
$
0.7

NGL (long contracts)
 
Swaps
 
Gallons
 
47.9

 
(0.9
)
Natural Gas (short contracts)
 
Swaps
 
MMBtu
 
(2.2
)
 
0.1

Natural Gas (long contracts)
 
Swaps
 
MMBtu
 
0.4

 
(0.1
)
Total fair value of derivatives
 
 
 
 
 
 
 
$
(0.2
)

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

Fair Value of Derivative Instruments
Assets and liabilities related to the Partnership's derivative contracts are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as a loss on derivatives in the consolidated statement of operations. The Partnership estimates the fair value of all of its derivative contracts using actively quoted prices. The estimated fair value of derivative contracts by maturity date was as follows (in millions):
 
Maturity Periods
 
Less than one year
 
One to two years
 
More than two years
 
Total fair value
September 30, 2014
$
0.2

 
$
(0.3
)
 
$
(0.1
)
 
$
(0.2
)
Fair Value Measurements
Fair Value Measurements
(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, 2014
Level 2
Commodity Swaps*
$
(0.2
)
Total
$
(0.2
)
 
__________________________________________________
*                 The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.
 
Fair Value of Financial Instruments
 
The estimated fair value of the 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, 2014
 
Carrying
Value
 
Fair
Value
Long-term debt
$
1,746.7

 
$
1,809.2

Obligations under capital leases
$
20.7

 
$
20.3


 
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 $371.0 million in outstanding borrowings under its revolving credit facility as of September 30, 2014. 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, 2014, the Partnership had borrowings totaling $397.3 million, $446.5 million and $346.8 million, net of discount, under the 2019 Notes, 2024 Notes and 2044 Notes, with a fixed rate of 2.70%, 4.40% and 5.60%, respectively. Additionally, the Partnership had borrowings of $185.1 million, including premium, under the 2022 Notes with a fixed rate of 7.125% as of September 30, 2014. The fair value of all senior unsecured notes as of September 30, 2014 was based on Level 2 inputs from third-party market quotations.  The fair value of obligations under capital leases was calculated using Level 2 inputs from third-party banks.
Commitments and Contingencies
Commitments and Contingencies Disclosure
(13) Commitments and Contingencies
 
(a) Employment and Severance Agreements
 
Certain members of management of the Partnership are parties to employment and/or severance agreements with the General Partner. The employment and severance agreements provide those managers with severance payments in certain circumstances and, in the case of employment agreements, prohibit each such person from competing with the General Partner or its affiliates for a certain period of time following the termination of such person’s employment.
 
(b) Environmental Issues
 
The operation of pipelines, plants and other facilities for the gathering, processing, transmitting or disposing of natural gas, NGLs, brine and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's results of operations, financial condition or cash flows.

(c) Litigation Contingencies
 
The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position or results of operations.
 
At times, the Partnership’s subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations or financial condition.
 
The Partnership (or its subsidiaries) is defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. 

In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans, but was removed to the United States District Court for the Eastern District of Louisiana.  The amount of damages is unspecified. The Partnership's subsidiary, Crosstex LIG, LLC, is one of the named defendants as the owner of pipelines in the area.  The validity of the causes of action, as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable.  The Partnership intends to vigorously defend the case.
In June 2014, a group of landowners in Assumption Parish, Louisiana added a subsidiary of the Partnership, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine Company, LLC, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the August 2012 sinkhole that formed in the Bayou Corne area of Assumption Parish, Louisiana. The suit is pending in the 23rd Judicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants have been pending since October 2012, plaintiffs are now alleging that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.
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 these pipelines and underground storage reservoirs. We are assessing the potential for recovering our losses from responsible parties. We have sued Texas Brine, LLC, the operator of a failed cavern in the area, and its insurers seeking recovery for this damage. We also filed a claim with our insurers. Our insurers denied our claim. We dispute the denial but 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 in the amount of $6.1 million. Additional claims related to this matter 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 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
Segment Information
 
Identification 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 the ORV. 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
 
Ohio River Valley
 
Corporate
 
Totals
 
(In millions)
Three Months Ended September 30, 2014
 

 
 

 
 

 
 

 
 

 
 

Sales to external customers
$
77.3

 
$
491.3

 
$
—

 
$
75.5

 
$
—

 
$
644.1

Sales to affiliates
148.9

 
39.5

 
45.9

 
—

 
(28.0
)
 
206.3

Purchased gas, NGLs, condensate and
    crude oil
(76.8
)
 
(486.9
)
 
—

 
(61.5
)
 
28.0

 
(597.2
)
Operating expenses
(36.2
)
 
(23.7
)
 
(7.0
)
 
(8.9
)
 
—

 
(75.8
)
Gain on litigation settlement
—

 
6.1

 
—

 
—

 
—

 
6.1

Gain on derivative activity
—

 
—

 
—

 
—

 
1.0

 
1.0

Segment profit
$
113.2

 
$
26.3

 
$
38.9

 
$
5.1

 
$
1.0

 
$
184.5

Depreciation and amortization
$
(31.6
)
 
$
(19.1
)
 
$
(11.8
)
 
$
(8.2
)
 
$
(0.9
)
 
$
(71.6
)
Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
—

 
$
2,257.8

Capital expenditures
$
79.7

 
$
79.1

 
$
2.5

 
$
25.4

 
$
3.9

 
$
190.6

Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
Sales to external customers
$
32.9

 
$
—

 
$
13.9

 
$
—

 
$
—

 
$
46.8

Sales to affiliates
359.4

 
—

 
172.0

 
—

 
—

 
531.4

Purchased gas, NGLs, condensate and
    crude oil
(286.2
)
 
—

 
(149.3
)
 
—

 
—

 
(435.5
)
Operating expenses
(26.9
)
 
—

 
(8.9
)
 
—

 
—

 
(35.8
)
Segment profit
$
79.2

 
$
—

 
$
27.7

 
$
—

 
$
—

 
$
106.9

Depreciation and amortization
$
(29.0
)
 
$
—

 
$
(19.0
)
 
$
—

 
$
—

 
$
(48.0
)
Goodwill
$
325.4

 
$
—

 
$
76.3

 
$
—

 
$
—

 
$
401.7

Capital expenditures
$
27.1

 
$
—

 
$
10.0

 
$
—

 
$
—

 
$
37.1

Nine Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
 
 
Sales to external customers
$
214.3

 
$
1,221.9

 
$
11.5

 
$
180.2

 
$
—

 
$
1,627.9

Sales to affiliates
637.7

 
41.7

 
256.0

 
—

 
(63.4
)
 
872.0

Purchased gas, NGLs, condensate and crude oil
(423.0
)
 
(1,158.2
)
 
(133.8
)
 
(146.4
)
 
63.4

 
(1,798.0
)
Operating expenses
(106.5
)
 
(45.5
)
 
(20.9
)
 
(20.4
)
 
—

 
(193.3
)
Gain on litigation settlement
—

 
6.1

 
—

 
—

 
—

 
6.1

Gain on derivative activity
—

 
—

 
—

 
—

 
(1.9
)
 
(1.9
)
Segment profit (loss)
$
322.5

 
$
66.0

 
$
112.8

 
$
13.4

 
$
(1.9
)
 
$
512.8

Depreciation and amortization
$
(91.7
)
 
$
(43.4
)
 
$
(37.6
)
 
$
(18.1
)
 
$
(1.5
)
 
$
(192.3
)
Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
—

 
$
2,257.8

Capital expenditures
$
180.2

 
$
222.4

 
$
10.5

 
$
27.7

 
$
12.6

 
$
453.4

Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
Sales to external customers
$
96.6

 
$
—

 
$
39.5

 
$
—

 
$
—

 
$
136.1

Sales to affiliates
1,052.3

 
—

 
504.7

 
—

 
—

 
1,557.0

Purchased gas, NGLs, condensate and
crude oil
(838.7
)
 
—

 
(440.9
)
 
—

 
—

 
(1,279.6
)
Operating expenses
(92.0
)
 
—

 
(24.0
)
 
—

 
—

 
(116.0
)
Segment profit
$
218.2

 
$
—

 
$
79.3

 
$
—

 
$
—

 
$
297.5

Depreciation and amortization
$
(82.4
)
 
$
—

 
$
(56.2
)
 
$
—

 
$
—

 
$
(138.6
)
Goodwill
$
325.4

 
$
—

 
$
76.3

 
$
—

 
$
—

 
$
401.7

Capital expenditures
$
113.9

 
$
—

 
$
58.7

 
$
—

 
$
—

 
$
172.6



The table below presents information about segment assets as of September 30, 2014 and December 31, 2013:
 
September 30, 2014
 
December 31, 2013
Segment Identifiable Assets:
(In millions)
Texas
$
3,236.9

 
$
1,460.0

Louisiana
2,925.3

 
—

Oklahoma
894.5

 
777.1

Ohio River Valley
513.6

 
—

Corporate
347.3

 
72.7

Total identifiable assets
$
7,917.6

 
$
2,309.8



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

Three Months Ended
 September 30,
 
Nine Months Ended
 September 30,
 
2014
 
2013
 
2014
 
2013
Segment profits
$
184.5

 
$
106.9

 
$
512.8

 
$
297.5

General and administrative expenses
(22.8
)
 
(10.8
)
 
(62.8
)
 
(32.3
)
Depreciation and amortization
(71.6
)
 
(48.0
)
 
(192.3
)
 
(138.6
)
Operating income
$
90.1

 
$
48.1

 
$
257.7


$
126.6

Discontinued Operations (Notes)
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 benefits and burdens associated with Devon's 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the business combination on March 7, 2014. Therefore, the Predecessor's non-contributed historical assets and liabilities are presented as held for sale as of December 31, 2013. All operations activity related to the non-contributed assets prior to March 7, 2014 are classified as discontinued operations.

The following schedule summarizes net income from discontinued operations (in millions):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2013
 
2014
 
2013
Operating revenues:
 
 
 
 
 
Operating revenues
$
10.9

 
$
6.8

 
$
33.5

Operating revenues - affiliates
20.8

 
10.5

 
68.1

Total operating revenues
31.7

 
17.3

 
101.6

 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
Operating expenses
37.9

 
15.7

 
91.7

Total operating expenses
37.9

 
15.7

 
91.7

 
 
 
 
 
 
Income (loss) before income taxes
(6.2
)
 
1.6

 
9.9

Income tax provision (benefit)
(2.2
)
 
0.6

 
3.6

Net income (loss)
(4.0
)
 
1.0

 
6.3

Net income attributable to non-controlling interest
(0.3
)
 
—

 
(1.4
)
Net income (loss) including non-controlling interest
$
(4.3
)
 
$
1.0

 
$
4.9


The following table presents the main classes of assets and liabilities associated with the Partnership's discontinued operations at December 31, 2013. There were no assets and liabilities associated with discontinued operations at September 30, 2014:
 
December 31, 2013
 
(in millions)
Inventories
$
0.2

Other current assets
0.2

Total current assets
0.4

Property, plant & equipment
72.3

Total assets
$
72.7

 
 
Accounts payable
$
3.2

Other current liabilities
1.1

Total current liabilities
4.3

Asset retirement obligations
7.1

Deferred income taxes
25.3

Other long-term liabilities
0.3

Total liabilities
$
37.0

Subsequent Events (Notes)
Subsequent Events [Text Block]
Subsequent Events
E2 Drop Down. On October 22, 2014, the Partnership acquired from EnLink Midstream, Inc. (“EMI”), a wholly-owned subsidiary of ENLC, 100% of the Class A Units and 50% of the Class B Units (collectively, the “E2 Appalachian Units”) in E2 Appalachian Compression, LLC (“E2 Appalachian”), and 93.7% of the Class A Units (the “Energy Services Units” and, together with the E2 Appalachian Units, the “Purchased Units”) in E2 Energy Services, LLC (“Energy Services”). The total consideration paid by the Partnership to EMI for the Purchased Units included (i) $13.0 million in cash for the Energy Services Units and (ii) $150.0 million in cash and 1,016,322 common units representing limited partner interests in the Partnership for the E2 Appalachian Units. The remaining 50% of the Class B Units in E2 Appalachian are owned by members of the E2 Appalachian management team and are designed to provide such management team members with equity incentives. Pursuant to the limited liability company agreement of E2 Appalachian, such management owners will be required to sell their Class B Units to ENLK on either December 31, 2015 or March 31, 2016.
Acquisition of Natural Gas Pipeline Assets. Effective November 1, 2014, the Partnership acquired, through one of its wholly owned subsidiaries, Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana for $235.0 million, subject to certain adjustments. The natural gas assets include natural gas pipelines spanning from Beaumont, Texas to the Mississippi River corridor and working natural gas storage capacity in southern Louisiana.
In September 2014, the Partnership paid the sellers, Chevron Pipe Line Company and Chevron Midstream Pipelines LLC, a $23.5 million deposit, which is included in "Other assets, net" on the condensed consolidated balance sheet.
Significant Accounting Policy (Policies)
Basis of Presentation and Significant Accounting Policies 
(a)
Basis of Presentation

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles in the United States of America ("US GAAP") for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation.
 
Further, the unaudited consolidated financial statements give effect to the business combination and related transactions discussed above under the acquisition method of accounting and are treated as a reverse acquisition. Under the acquisition method of accounting, Midstream Holdings was the accounting acquirer in the transactions because its parent company, Devon, obtained control of the Partnership through the indirect control of the General Partner as a result of the business combination. Consequently, Midstream Holdings’ assets and liabilities retained their carrying values and are reflected in the balance sheet as of December 31, 2013 as the Predecessor. All financial results prior to March 7, 2014 reflect the historical operations of Midstream Holdings and are reflected as Predecessor income on 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 which was treated as a reorganization under common control with the removal of historical deferred taxes reflected through equity.

Use of Estimates 
(b)
Management's Use of Estimates

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

Revenue Recognition 

(c)
Revenue Recognition

The Partnership recognizes revenue for sales or services at the time the natural gas, NGLs, condensate or crude oil are delivered or at the time the service is performed at a fixed or determinable price. The Partnership generally accrues one month of sales and the related gas, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. The Partnership's purchase and sale arrangements are generally reported in revenues and costs on a gross basis in the consolidated statement of operations in accordance with the Financial Accounting Standards Board Accounting Standards Codification ("FASB ASC") 605-45-45-1. Except for fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, has the risk and reward of ownership as evidenced by title transfer, schedules the transportation and assumes credit risk.

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

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

Cash and Cash Equivalents 
(e)
Cash and Cash Equivalents

The Partnership considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Natural Gas and Natural Gas Liquids Inventory 
(f)
Natural Gas, Natural Gas Liquids, Crude Oil and Condensate Inventory

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

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

Change in Depreciation Method. Historically, Midstream Holdings depreciated certain property, plant, and equipment using the units-of-production method. As a result of the business combination, the Partnership is operated as an independent midstream company and thus no longer has access to Devon’s proprietary reserve and production data historically used to compute depreciation under the units-of-production method. Additionally, the existing contracts with Devon were revised to a fee-based arrangement with minimum volume commitments. Effective March 7, 2014, the Partnership changed its method of computing depreciation for these assets to the straight-line method, consistent with the depreciation method applied to the Partnership’s acquired assets. In accordance with FASB ASC 250, the Partnership determined that the change in depreciation method is a change in accounting estimate effected by a change in accounting principle, and accordingly, the straight-line method will be applied on a prospective basis. This change is considered preferable because the straight-line method will more accurately reflect the pattern of usage and the expected benefits of such assets. The effect of this change in estimate resulted in a decrease in depreciation expense for the three and nine months ended September 30, 2014 by approximately $9.3 million and $21.0 million, or $0.04 and $0.09 per unit, respectively.

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

Impairment Review. We evaluate our property, plant and equipment for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment loss is recognized equal to the excess of the asset’s carrying value over its fair value. The fair values of long-lived assets are generally determined from estimated discounted future net cash flows. Our estimate of cash flows is based on assumptions which include (1) the amount of fee based services and the purchase and resale margins on natural gas, together with volume of gas, NGL, condensate and crude oil available to the asset, (2) markets available to the asset, (3) operating expenses, and (4) future natural gas prices, crude prices, condensate prices and NGL product prices. The volume of available gas, condensate, NGLs and crude oil to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, condensate and crude oil prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.
Equity Method of Accounting 
(h)
Equity Method of Accounting

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

The Partnership evaluates its equity investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable.
Goodwill and Intangible Assets, Goodwill, Policy 
(i)
Goodwill

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

The Partnership has approximately $2.3 billion of goodwill at September 30, 2014 primarily related to the legacy Partnership operations as a result of the March 7, 2014 business combination.
Goodwill and Intangible Assets, Intangible Assets, Policy 
(j)
Intangible Assets

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

The following table represents the Partnership's total intangible assets as of September 30, 2014 (in millions):
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount

 
 
 
 
 
Customer relationships
$
525.0

 
$
(23.2
)
 
$
501.8



The weighted average amortization period for intangible assets is 13.7 years. Amortization expense for intangibles was approximately $10.2 million and $23.2 million for the three and nine months ended September 30, 2014, respectively.

The following table summarizes the Partnership's estimated aggregate amortization expense for the identified periods (in millions):
2014 (remaining)
$
10.2

2015
41.0

2016
41.0

2017
41.0

2018
41.0

Thereafter
327.6

Total
$
501.8



Asset Retirement Obligations 
(k) Asset Retirement Obligations

The Partnership recognizes liabilities for retirement obligations associated with its pipelines and processing and fractionation facilities. Such liabilities are recognized when there is a legal obligation associated with the retirement of the assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property, plant and equipment. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The Partnership’s retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of the long-lived assets. The asset retirement cost is depreciated using the straight line depreciation method similar to that used for the associated property, plant and equipment.
Other Long-Term Liabilities 
(l) Other Long-Term Liabilities
Included in other current and long-term liabilities is an $85.2 million total liability related to an onerous performance obligation assumed in the business combination. The Partnership has one delivery contract which requires it to deliver a specified volume of gas each month at an indexed base price with a term to 2019. The Partnership realizes a loss on the delivery of gas under this contract each month based on current prices. The fair value of this onerous performance obligation was recorded as a result of the March 7, 2014 business combination and was based on forecasted discounted cash obligations in excess of market under this gas delivery contract. The liability is reduced each month as delivery is made over the remaining life of the contract with an offsetting reduction in purchase gas costs.
Derivative 
(m) Derivatives

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

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

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

During the three and nine months ended September 30, 2014 and 2013, the Partnership had no third party customer that individually represented greater than 10.0% of its consolidated midstream revenues other than affiliate transactions with Devon which represented 24.2% and 34.9% of the consolidated midstream revenues for the three and nine months ended September 30, 2014, respectively, and 91.9% and 92.0% for the three and nine months ended September 30, 2013, respectively. As the Partnership continues to grow and expand, the relationship between individual customer sales and consolidated total sales is expected to continue to change. Devon represents a significant percentage of revenues and the loss of Devon as a customer would have a material adverse impact on the Partnership's results of operations because the gross operating margin received from transactions with this customer is material to the Partnership.
Environmental Costs 
(o) Environmental Costs

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

Prior to the business combination, Devon granted certain share-based awards to members of its board of directors and selected employees. The Predecessor did not grant share-based awards because it previously participated in Devon’s share-based award plans since the Predecessor comprised Devon's U.S. midstream assets. The awards granted under Devon’s plans were measured at fair value on the date of grant and were recognized as expense over the applicable requisite service periods.
The Partnership recognizes compensation cost related to all unit-based awards in its consolidated financial statements in accordance with FASB ASC 718. The Partnership and ENLC each have similar unit-based payment plans for employees. Unit-based compensation associated with ENLC's unit-based compensation plans awarded to directors, officers and employees of the General Partner of the Partnership are recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership and Midstream Holdings.
Commitments and Contingencies, Policy 
(q) Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Discontinued Operations, Policy 
(r) Discontinued Operations
The Partnership classifies as discontinued operations its assets or asset groups that have clearly distinguishable cash flows and are in the process of being sold or have been sold. The Partnership also includes as discontinued operations Predecessor assets that were not contributed in the business combination.
Debt Issue Costs 
(s) Debt Issue Costs
Costs incurred in connection with the issuance of long-term debt are deferred and recorded as interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs.
Recent Accounting Pronouncements 
(t) Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"). ASU 2014-09 will replace existing revenue recognition requirements in US GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires significantly expanded disclosures regarding the qualitative and quantitative information of an entity's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period and is to be applied retrospectively, with early application not permitted. We are currently evaluating the impact the pronouncement will have on our consolidated financial statements and related disclosures. Subject to this evaluation, we have reviewed all recently issued accounting pronouncements that became effective during the nine months ended September 30, 2014, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.
Significant Accounting Policy (Tables)
Schedule of Finite-Lived Intangible Assets 
The following table represents the Partnership's total intangible assets as of September 30, 2014 (in millions):
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount

 
 
 
 
 
Customer relationships
$
525.0

 
$
(23.2
)
 
$
501.8

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense 
The following table summarizes the Partnership's estimated aggregate amortization expense for the identified periods (in millions):
2014 (remaining)
$
10.2

2015
41.0

2016
41.0

2017
41.0

2018
41.0

Thereafter
327.6

Total
$
501.8

Acquisition (Table)
Business Combination, Purchase Price Summary 
The following table summarizes the purchase price (in millions, except per unit price):
EnLink Midstream Partners, LP outstanding units:
 
    Common units held by public unitholders
75.1

    Common units held by EMI
18.0

    Preferred units held by third party (1)
17.1

    Restricted units
0.4

        Total units exchanged
110.6

 
 
EnLink Midstream Partners, LP common unit price (2)
$
30.51

EnLink Midstream Partners, LP common units fair value
$
3,374.4

EnLink Midstream Partners, LP outstanding unit options fair value
$
3.9

        Total purchase price
$
3,378.3

(1)
The Partnership converted the preferred units to common units in February 2014.
(2)
The final purchase price is based on the market value of the Partnership's common units as of the closing date, March 7, 2014.
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed 
The following table is a summary of the preliminary fair value of the assets acquired and liabilities assumed from the Partnership in the business combination as of March 7, 2014 (in millions):
Assets acquired:
 
     Current assets
$
435.9

     Property, plant and equipment
2,341.9

Intangibles assets
524.9

Equity investment
221.5

Goodwill
1,856.0

Other long-term assets
1.1

Liabilities assumed:
 
     Current liabilities
(474.0
)
     Long-term debt
(1,364.3
)
     Deferred taxes
(63.6
)
     Other long-term liabilities
(101.1
)
         Net assets acquired
$
3,378.3

Pro Forma 
The following unaudited pro forma condensed financial information for the nine months ended September 30, 2014 and 2013 gives effect to the business combination as if it had occurred on January 1, 2013. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results. As of March 7, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 4. Pro forma financial information associated with the business combination and with these agreements with Devon is reflected below.
 
Three Months Ended
 
Nine Months Ended
 
September 30, 2013
 
September 30, 2014
 
September 30, 2013
 
(in millions, except for per unit data)
Pro forma total revenues
$
621.6

 
$
2,667.9

 
$
1,818.4

Pro forma net income
$
5.5

 
$
217.3

 
$
114.0

Pro forma net income attributable to EnLink Midstream Partners, LP
$
(24.4
)
 
$
101.2

 
$
30.3

Pro forma net income per common unit:
 
 


 
 
Basic
$
(0.13
)
 
$
0.38

 
$
0.11

Diluted
$
(0.13
)
 
$
0.38

 
$
0.11

Affiliate Transactions (Tables)
Schedule of Related Party Transactions
 
Three Months Ended
 September 30,
 
Nine Months Ended
September 30,
 
2013
 
2014
 
2013
Continuing Operations:
 
 
 
 
 
Operating revenues - affiliates
$
(531.4
)
 
$
(436.4
)
 
$
(1,557.0
)
Operating expenses - affiliates
417.5

 
340.0

 
1,229.6

Net affiliate transactions
(113.9
)
 
(96.4
)

(327.4
)
Capital expenditures
44.7

 
16.2

 
201.3

Other third-party transactions, net
(50.8
)
 
53.0

 
8.4

Net third-party transactions
(6.1
)
 
69.2


209.7

Net cash distributions to Devon - continuing operations
(120.0
)
 
(27.2
)

(117.7
)
Non-cash distribution of net assets to Devon
—

 
(23.5
)
 
—

Total net distributions per equity
$
(120.0
)
 
$
(50.7
)
 
$
(117.7
)
 
 
 
 
 
 
Discontinued operations:
 
 
 
 
 
Operating revenues - affiliates
$
(20.8
)
 
$
(10.4
)
 
$
(68.1
)
Operating expenses - affiliates
7.8

 
5.0

 
25.4

Cash used in financing activities - affiliates
(0.4
)
 
—

 
(5.6
)
Net affiliate transactions
(13.4
)
 
(5.4
)

(48.3
)
Capital expenditures
(0.1
)
 
0.6

 
5.3

Other third-party transactions, net
(73.5
)
 
0.4

 
(54.6
)
Net third-party transactions
(73.6
)
 
1.0


(49.3
)
Net distributions to Devon and non-controlling interests - discontinued operations
(87.0
)
 
(4.4
)
 
(97.6
)
Non-cash distribution of net assets to Devon
—

 
(39.9
)
 
—

Total net distributions per equity
$
(87.0
)
 
$
(44.3
)
 
$
(97.6
)
Total distributions- continuing and discontinued operations
$
(207.0
)
 
$
(95.0
)
 
$
(215.3
)
Long-Term Debt (Tables)
Indebtedness Table 
As of September 30, 2014, long-term debt consisted of the following (in millions):
 
September 30, 2014
Bank credit facility (due 2019), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at September 30, 2014 was 1.9%
$
371.0

Senior unsecured notes (due 2019), net of discount of $2.7 million, which bear interest at the rate of 2.70%
397.3

Senior unsecured notes (due 2022), including a premium of $22.6 million, which bear interest at the rate of 7.125%
185.1

Senior unsecured notes (due 2024), net of discount of $3.5 million, which bear interest at the rate of 4.40%
446.5

Senior unsecured notes (due 2044), net of discount of $3.3 million, which bear interest at the rate of 5.60%
346.8

Debt classified as long-term
$
1,746.7

Debt Rating Table 
The percentages per annum, based upon the debt rating are as set forth below:
 
Pricing Level
Debt Ratings
Applicable Rate Commitment Fee
EuroDollar Rate/Letter of Credit
Base Rate +
 
 
1
A-/A3 or better
0.100%
1.000%
—
 
2
BBB+/Baa1
0.125%
1.125%
0.125%
 
3
BBB/Baa2
0.175%
1.250%
0.250%
 
4
BBB-/Baa3
0.225%
1.500%
0.500%
 
5
BB+/Ba1
0.275%
1.625%
0.625%
 
6
BB/Ba2 or worse
0.350%
1.750%
0.750%

Partners' Capital (Tables)
Schedule of Earnings Per Share, Basic and Diluted 
The following table reflects the computation of basic and diluted earnings per limited partner unit for the three and nine months ended September 30, 2014 (in millions except per unit amounts):
 
Three Months Ended
 September 30, 2014
 
Nine Months Ended
 September 30, 2014*
Limited partners’ interest in net income
$
40.5

 
$
86.5

Distributed earnings allocated to:
 
 
 
Common units and Class B Units (1) (2)
$
85.5

 
$
220.6

Unvested restricted units (1)
0.4

 
0.9

Total distributed earnings
$
85.9

 
$
221.5

Undistributed loss allocated to:
 
 
 
Common units and Class B Units (2)
$
(45.1
)
 
$
(134.6
)
Unvested restricted units
(0.2
)
 
(0.5
)
Total undistributed loss
$
(45.3
)
 
$
(135.1
)
Net income allocated to:
 
 
 
Common units and Class B Units (2)
$
40.3

 
$
86.1

Unvested restricted units
0.2

 
0.4

Total limited partners’ interest in net income
$
40.5

 
$
86.5

Basic and diluted net income per unit:
 
 
 
Basic
$
0.18

 
$
0.38

Diluted
$
0.18

 
$
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, 2014 represents a declared distribution of $0.37 per unit for common units payable on November 13, 2014 and nine months ended September 30, 2014 represents distributions of $0.36 per unit paid on May 14, 2014, distributions of $0.365 per unit paid on August 13, 2014 and distributions declared of $0.37 per unit payable on November 13, 2014.
(2) Nine months ended September 30, 2014 includes distribution of $0.10 per unit for Class B Units paid on May 14, 2014. The Class B Units converted into common units on a one-for-one basis on May 6, 2014.
 
Schedule of Weighted Average Number of Shares 
The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the three and nine months ended September 30, 2014 (in millions):
 
Three Months Ended
 September 30, 2014
 
Nine Months Ended
 September 30, 2014*
Basic weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
231.0

 
230.3

Diluted weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
231.0

 
230.3

Dilutive effect of restricted units issued
0.4

 
0.3

    Total weighted average limited partner diluted common units outstanding
231.4

 
230.6

Incentive Distributions 
The net income allocated to the General Partner is as follows for the three and nine months ended September 30, 2014 (in millions
 
Three Months Ended
 September 30, 2014
 
Nine Months Ended
 September 30, 2014*
Income allocation for incentive distributions
$
6.3

 
$
13.6

Unit-based compensation attributable to ENLC’s restricted units
(3.1
)
 
(6.8
)
General Partner interest in net income
0.3

 
0.7

General Partner share of net income
$
3.5

 
$
7.5

Asset Retirement Obligation (Table)
Schedule of Change in Asset Retirement Obligation [Table Text Block]
(8) Asset Retirement Obligations

The schedule below summarizes the changes in the Partnership’s asset retirement obligations:
 
September 30, 2014
 
September 30, 2013
 
(in millions)
Beginning asset retirement obligations
$
7.7

 
$
9.1

Revisions to existing liabilities
2.2

 
0.4

Liabilities acquired
0.5

 
—

Accretion
0.4

 
0.3

Ending asset retirement obligations
$
10.8

 
$
9.8

Investment in Unconsolidated Affiliate (Tables)
Equity Method Investments
The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):
 
Gulf Coast Fractionators
 
Howard Energy Partners (1)
 
Total
Three months ended
 
 
 
 
 
September 30, 2014
 
 
 
 
 
Distributions
$
5.2

 
$
3.0

 
$
8.2

Equity in income
$
5.2

 
$
0.4

 
$
5.6

 
 
 
 
 
 
September 30, 2013
 
 
 
 
 
Distributions
$
12.0

 
$
—

 
$
12.0

Equity in income
$
5.8

 
$
—

 
$
5.8

 
 
 
 
 
 
Nine months ended
 
 
 
 
 
September 30, 2014 (1)
 
 
 
 
 
Distributions
$
5.2

 
$
8.7

 
$
13.9

Equity in income
$
13.2

 
$
1.1

 
$
14.3

 
 
 
 
 


September 30, 2013
 
 
 
 


Distributions
$
12.0

 
$
—

 
$
12.0

Equity in income
$
10.2

 
$
—

 
$
10.2


(1) Includes income and distributions for the period from March 7, 2014 through September 30, 2014.
The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):
 
September 30, 2014
 
December 31, 2013
Gulf Coast Fractionators (1)
$
56.0

 
$
61.1

Howard Energy Partners
220.1

 
—

Total investments in unconsolidated affiliates
$
276.1

 
$
61.1

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


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

2014

2014
Aggregate intrinsic value of units vested

$
1.2


$
1.2

Fair value of units vested

$
1.2


$
1.2

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

 
$
2.4

Fair value of units vested
 
$
2.2

 
$
2.2

Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs 
Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions): 
 
Three Months Ended
September 30,
 
Nine Months Ended 
September 30,
 
2014
 
2013
 
2014
 
2013
Cost of unit-based compensation allocated to Predecessor general and
    administrative expense (1)
$
—

 
$
3.5

 
$
2.8

 
$
10.1

Cost of unit-based compensation charged to general and administrative
    expense
4.9

 
—

 
10.9

 
—

Cost of unit-based compensation charged to operating expense
0.8

 
—

 
1.8

 
—

    Total amount charged to income
$
5.7

 
$
3.5

 
$
15.5

 
$
10.1


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

 
$
—

Assumed in business combination
371,225

 
30.51

Granted
701,119

 
31.65

Vested*
(39,833
)
 
30.63

Forfeited
(13,196
)
 
31.83

Non-vested, end of period
1,019,315

 
$
31.27

Aggregate intrinsic value, end of period (in millions)
$
31.0

 
 


 * Vested units include16,471 units withheld for payroll taxes paid on behalf of employees.
A summary of the restricted incentive units activities for the nine months ended September 30, 2014 is provided below:
 
Nine Months Ended 
September 30, 2014
EnLink Midstream, LLC Restricted Incentive Units:
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-vested, beginning of period
—

 
$
—

Assumed in business combination
435,674

 
37.60

Granted
626,341

 
36.59

Vested*
(59,553
)
 
37.56

Forfeited
(11,859
)
 
36.54

Non-vested, end of period
990,603

 
$
36.97

Aggregate intrinsic value, end of period (in millions)
$
40.9

 
 


 * Vested units include 24,727 units withheld for payroll taxes paid on behalf of employees.
Derivatives (Tables)
Fair Value of Derivative Assets and Liabilities relating to commodity swaps 
The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions):
 
September 30, 2014
Fair value of derivative assets — current
$
1.1

Fair value of derivative assets — long term
0.2

Fair value of derivative liabilities — current
(0.9
)
Fair value of derivative liabilities — long term
(0.6
)
    Net fair value of derivatives
$
(0.2
)
Notional Amount and Fair Value of Derivative Instruments 
 
 
 
 
 
 
September 30, 2014
Commodity
 
Instruments
 
Unit
 
Volume
 
Fair Value
 
 
 
 
 
 
(In millions)
NGL (short contracts)
 
Swaps
 
Gallons
 
(61.3
)
 
$
0.7

NGL (long contracts)
 
Swaps
 
Gallons
 
47.9

 
(0.9
)
Natural Gas (short contracts)
 
Swaps
 
MMBtu
 
(2.2
)
 
0.1

Natural Gas (long contracts)
 
Swaps
 
MMBtu
 
0.4

 
(0.1
)
Total fair value of derivatives
 
 
 
 
 
 
 
$
(0.2
)
Derivatives Other than Cash Flow Hedges 
The estimated fair value of derivative contracts by maturity date was as follows (in millions):
 
Maturity Periods
 
Less than one year
 
One to two years
 
More than two years
 
Total fair value
September 30, 2014
$
0.2

 
$
(0.3
)
 
$
(0.1
)
 
$
(0.2
)
The components of gain (loss) on derivative activity in the consolidated statements of operations relating to commodity swaps are as follows for the three and nine months ended September 30, 2014 (in millions):
 
Three Months Ended
September 30, 2014
 
Nine Months Ended
September 30, 2014*
Change in fair value of derivatives
$
1.8

 
$
(0.2
)
Realized losses on derivatives
(0.8
)
 
(1.7
)
    Gain (loss) on derivative activity
$
1.0

 
$
(1.9
)

* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014. 
Fair Value Measurements (Tables)
Fair Value Derivative Instrument 
Net liabilities measured at fair value on a recurring basis are summarized below (in millions):
 
September 30, 2014
Level 2
Commodity Swaps*
$
(0.2
)
Total
$
(0.2
)
 
__________________________________________________
*                 The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for credit risk of the Partnership and/or the counterparty as required under FASB ASC 820.
Fair Value Financial Instrument 
Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Partnership could realize upon the sale or refinancing of such financial instruments (in millions):
 
September 30, 2014
 
Carrying
Value
 
Fair
Value
Long-term debt
$
1,746.7

 
$
1,809.2

Obligations under capital leases
$
20.7

 
$
20.3

Segement Information (Tables)
Reconciliation of Operating Profit (Loss) from Segments to Consolidated [Table Text Block] 
The following table reconciles the segment profits reported above to the operating income as reported in the condensed consolidated statements of operations (in millions):

Three Months Ended
 September 30,
 
Nine Months Ended
 September 30,
 
2014
 
2013
 
2014
 
2013
Segment profits
$
184.5

 
$
106.9

 
$
512.8

 
$
297.5

General and administrative expenses
(22.8
)
 
(10.8
)
 
(62.8
)
 
(32.3
)
Depreciation and amortization
(71.6
)
 
(48.0
)
 
(192.3
)
 
(138.6
)
Operating income
$
90.1

 
$
48.1

 
$
257.7


$
126.6

Partnership Reportable Segement 
Summarized financial information concerning the Partnership’s reportable segments is shown in the following tables:
 
Texas
 
Louisiana
 
Oklahoma
 
Ohio River Valley
 
Corporate
 
Totals
 
(In millions)
Three Months Ended September 30, 2014
 

 
 

 
 

 
 

 
 

 
 

Sales to external customers
$
77.3

 
$
491.3

 
$
—

 
$
75.5

 
$
—

 
$
644.1

Sales to affiliates
148.9

 
39.5

 
45.9

 
—

 
(28.0
)
 
206.3

Purchased gas, NGLs, condensate and
    crude oil
(76.8
)
 
(486.9
)
 
—

 
(61.5
)
 
28.0

 
(597.2
)
Operating expenses
(36.2
)
 
(23.7
)
 
(7.0
)
 
(8.9
)
 
—

 
(75.8
)
Gain on litigation settlement
—

 
6.1

 
—

 
—

 
—

 
6.1

Gain on derivative activity
—

 
—

 
—

 
—

 
1.0

 
1.0

Segment profit
$
113.2

 
$
26.3

 
$
38.9

 
$
5.1

 
$
1.0

 
$
184.5

Depreciation and amortization
$
(31.6
)
 
$
(19.1
)
 
$
(11.8
)
 
$
(8.2
)
 
$
(0.9
)
 
$
(71.6
)
Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
—

 
$
2,257.8

Capital expenditures
$
79.7

 
$
79.1

 
$
2.5

 
$
25.4

 
$
3.9

 
$
190.6

Three Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
Sales to external customers
$
32.9

 
$
—

 
$
13.9

 
$
—

 
$
—

 
$
46.8

Sales to affiliates
359.4

 
—

 
172.0

 
—

 
—

 
531.4

Purchased gas, NGLs, condensate and
    crude oil
(286.2
)
 
—

 
(149.3
)
 
—

 
—

 
(435.5
)
Operating expenses
(26.9
)
 
—

 
(8.9
)
 
—

 
—

 
(35.8
)
Segment profit
$
79.2

 
$
—

 
$
27.7

 
$
—

 
$
—

 
$
106.9

Depreciation and amortization
$
(29.0
)
 
$
—

 
$
(19.0
)
 
$
—

 
$
—

 
$
(48.0
)
Goodwill
$
325.4

 
$
—

 
$
76.3

 
$
—

 
$
—

 
$
401.7

Capital expenditures
$
27.1

 
$
—

 
$
10.0

 
$
—

 
$
—

 
$
37.1

Nine Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
 
 
Sales to external customers
$
214.3

 
$
1,221.9

 
$
11.5

 
$
180.2

 
$
—

 
$
1,627.9

Sales to affiliates
637.7

 
41.7

 
256.0

 
—

 
(63.4
)
 
872.0

Purchased gas, NGLs, condensate and crude oil
(423.0
)
 
(1,158.2
)
 
(133.8
)
 
(146.4
)
 
63.4

 
(1,798.0
)
Operating expenses
(106.5
)
 
(45.5
)
 
(20.9
)
 
(20.4
)
 
—

 
(193.3
)
Gain on litigation settlement
—

 
6.1

 
—

 
—

 
—

 
6.1

Gain on derivative activity
—

 
—

 
—

 
—

 
(1.9
)
 
(1.9
)
Segment profit (loss)
$
322.5

 
$
66.0

 
$
112.8

 
$
13.4

 
$
(1.9
)
 
$
512.8

Depreciation and amortization
$
(91.7
)
 
$
(43.4
)
 
$
(37.6
)
 
$
(18.1
)
 
$
(1.5
)
 
$
(192.3
)
Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
—

 
$
2,257.8

Capital expenditures
$
180.2

 
$
222.4

 
$
10.5

 
$
27.7

 
$
12.6

 
$
453.4

Nine Months Ended September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
Sales to external customers
$
96.6

 
$
—

 
$
39.5

 
$
—

 
$
—

 
$
136.1

Sales to affiliates
1,052.3

 
—

 
504.7

 
—

 
—

 
1,557.0

Purchased gas, NGLs, condensate and
crude oil
(838.7
)
 
—

 
(440.9
)
 
—

 
—

 
(1,279.6
)
Operating expenses
(92.0
)
 
—

 
(24.0
)
 
—

 
—

 
(116.0
)
Segment profit
$
218.2

 
$
—

 
$
79.3

 
$
—

 
$
—

 
$
297.5

Depreciation and amortization
$
(82.4
)
 
$
—

 
$
(56.2
)
 
$
—

 
$
—

 
$
(138.6
)
Goodwill
$
325.4

 
$
—

 
$
76.3

 
$
—

 
$
—

 
$
401.7

Capital expenditures
$
113.9

 
$
—

 
$
58.7

 
$
—

 
$
—

 
$
172.6

Segment Table reconciliation to Condensed Consolidated Financial Statement 
The table below presents information about segment assets as of September 30, 2014 and December 31, 2013:
 
September 30, 2014
 
December 31, 2013
Segment Identifiable Assets:
(In millions)
Texas
$
3,236.9

 
$
1,460.0

Louisiana
2,925.3

 
—

Oklahoma
894.5

 
777.1

Ohio River Valley
513.6

 
—

Corporate
347.3

 
72.7

Total identifiable assets
$
7,917.6

 
$
2,309.8

Discontinued Operations (Tables)
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures
The following schedule summarizes net income from discontinued operations (in millions):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2013
 
2014
 
2013
Operating revenues:
 
 
 
 
 
Operating revenues
$
10.9

 
$
6.8

 
$
33.5

Operating revenues - affiliates
20.8

 
10.5

 
68.1

Total operating revenues
31.7

 
17.3

 
101.6

 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
Operating expenses
37.9

 
15.7

 
91.7

Total operating expenses
37.9

 
15.7

 
91.7

 
 
 
 
 
 
Income (loss) before income taxes
(6.2
)
 
1.6

 
9.9

Income tax provision (benefit)
(2.2
)
 
0.6

 
3.6

Net income (loss)
(4.0
)
 
1.0

 
6.3

Net income attributable to non-controlling interest
(0.3
)
 
—

 
(1.4
)
Net income (loss) including non-controlling interest
$
(4.3
)
 
$
1.0

 
$
4.9


The following table presents the main classes of assets and liabilities associated with the Partnership's discontinued operations at December 31, 2013. There were no assets and liabilities associated with discontinued operations at September 30, 2014:
 
December 31, 2013
 
(in millions)
Inventories
$
0.2

Other current assets
0.2

Total current assets
0.4

Property, plant & equipment
72.3

Total assets
$
72.7

 
 
Accounts payable
$
3.2

Other current liabilities
1.1

Total current liabilities
4.3

Asset retirement obligations
7.1

Deferred income taxes
25.3

Other long-term liabilities
0.3

Total liabilities
$
37.0

General (Details)
9 Months Ended
Sep. 30, 2014
Mar. 7, 2014
Business Acquisition [Line Items]
 
 
Limited Liability Company or Limited Partnership, Business, Formation Date
Jul. 12, 2002 
 
Noncash or Part Noncash Acquisition, Interest Acquired
 
50.00% 
Limited Liability Company or Limited Partnership, Managing Member or General Partner, Name
EnLink Midstream GP, LLC 
 
Limited Liability Company or Limited Partnership, Business, Formation State
Delaware 
 
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest
70.00% 
 
Business Acquisition, Effective Date of Acquisition
Mar. 07, 2014 
 
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares
120,542,441 
 
Significant Accounting Policies (Other Policies) (Details Textuals) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Other Assets, Noncurrent [Abstract]
 
 
Gas Balancing Payable, Current
$ 1.1 
 
Gas Balancing Asset (Liability)
$ 1.3 
$ 0 
Significant Accounting Policies (Property Plant and Equipment) (Details Textuals)
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2014
Property, Plant and Equipment [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Change in Accounting Estimate, Financial Effect
9300000 
21000000 
Depreciation per share [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Change in Accounting Estimate, Financial Effect
.04 
.09 
Significant Accounting Policies (Goodwill) (Details Textuals) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Sep. 30, 2013
Goodwill [Line Items]
 
 
 
Goodwill
$ 2,257.8 
$ 401.7 
$ 401.7 
Significant Accounting Policies (Intangible Assets Table) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Finite-Lived Intangible Assets, Net [Abstract]
 
 
Gross Carrying Amount
$ 525.0 
 
Accumulated Amortization
23.2 
0 
Total
$ 501.8 
 
Significant Accounting Policies (Intangible Assets Amortization) (Details Textuals) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2014
Finite-Lived Intangible Assets, Net [Abstract]
 
 
Weighted Average Useful Life
 
13 years 8 months 
Amortization of Intangible Assets
$ 10.2 
$ 23.2 
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
 
 
2014 (remaining)
10.2 
10.2 
2015
41.0 
41.0 
2016
41.0 
41.0 
2017
41.0 
41.0 
2018
41.0 
41.0 
Thereafter
327.6 
327.6 
Total
$ 501.8 
$ 501.8 
Significant Accounting Policies (Other Long Term Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Other Commitments [Line Items]
 
 
Contract liability
$ 21.2 
$ 0 
total contract commitment [Member]
 
 
Other Commitments [Line Items]
 
 
Contract liability
$ 85.2 
 
Significant Accounting Policies (Concentration of Credit Risk) (Details Textuals) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Concentration Risk [Line Items]
 
 
 
 
Allowance for Doubtful Accounts Receivable
$ 0 
 
$ 0 
 
Sales Revenue [Member]
 
 
 
 
Concentration Risk [Line Items]
 
 
 
 
Concentration Risk, Percentage
 
 
10.00% 
 
Sales Revenue [Member] |
Devon Energy Corporation [Member]
 
 
 
 
Concentration Risk [Line Items]
 
 
 
 
Concentration Risk, Percentage
24.20% 
91.90% 
34.90% 
92.00% 
Acquisition (Details Textuals) (USD $)
In Millions, except Share data, unless otherwise specified
0 Months Ended 7 Months Ended 9 Months Ended
Mar. 7, 2014
Sep. 30, 2014
Sep. 30, 2014
Business Acquisition [Line Items]
 
 
 
Business Acquisition, Percentage of Voting Interests Acquired
50.00% 
 
 
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares
 
 
120,542,441 
Business Acquisition, Transaction Costs
$ 34.7 
 
 
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual
 
1,661.7 
 
EnLink Midstream Partners, LP [Member]
 
 
 
Business Acquisition [Line Items]
 
 
 
Business Acquisition, Date of Acquisition Agreement
 
 
Mar. 07, 2014 
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares
110,600,000 
 
 
Business Combination, Separately Recognized Transactions, Expenses and Losses Recognized
 
$ 1,636.7 
 
EnLink Midstream Holdings, LP [Member]
 
 
 
Business Acquisition [Line Items]
 
 
 
Business Acquisition, Date of Acquisition Agreement
 
 
Mar. 07, 2014 
Limited Liability Company (LLC) or Limited Partnership (LP), Predecessor Entity(ies) to Business Combination
 
 
Midstream Holdings 
Gulf Coast Fractionators [Member]
 
 
 
Business Acquisition [Line Items]
 
 
 
Equity Method Investment, Ownership Percentage
 
38.75% 
38.75% 
Acquisition (Details) (USD $)
In Millions, except Share data, unless otherwise specified
9 Months Ended 0 Months Ended 0 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Sep. 30, 2013
Mar. 7, 2014
EnLink Midstream Partners, LP [Member]
Mar. 7, 2014
EnLink Midstream Partners, LP [Member]
Mar. 7, 2014
Enlink Midstream, Inc. [Member]
EnLink Midstream Partners, LP [Member]
Mar. 7, 2014
Convertible Preferred Stock [Member]
EnLink Midstream Partners, LP [Member]
Mar. 7, 2014
Restricted Stock Units (RSUs) [Member]
EnLink Midstream Partners, LP [Member]
Mar. 7, 2014
Common Unit [Member]
EnLink Midstream Partners, LP [Member]
Mar. 7, 2014
Options Held [Member]
EnLink Midstream Partners, LP [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
Common units held by public unitholders
 
 
 
 
75,100,000 
18,000,000 
17,100,000 
400,000 
 
 
Total units exchanged
120,542,441 
 
 
110,600,000 
 
 
 
 
 
 
Common unit price
 
 
 
 
$ 30.51 
 
 
 
 
 
Business Combination, Consideration Transferred
 
 
 
$ 3,378.3 
 
 
 
 
$ 3,374.4 
$ 3.9 
Assets acquired [Abstract]
 
 
 
 
 
 
 
 
 
 
Current assets
 
 
 
 
435.9 
 
 
 
 
 
Property, plant and equipment
 
 
 
 
2,341.9 
 
 
 
 
 
Assets held for disposition
 
 
 
 
524.9 
 
 
 
 
 
Equity investment
 
 
 
 
221.5 
 
 
 
 
 
Goodwill
2,257.8 
401.7 
401.7 
 
1,856.0 
 
 
 
 
 
Other long-term assets
 
 
 
 
1.1 
 
 
 
 
 
Liabilities assumed:
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
(474.0)
 
 
 
 
 
Liabilities held for disposition
 
 
 
 
(1,364.3)
 
 
 
 
 
Deferred taxes
 
 
 
 
(63.6)
 
 
 
 
 
Long term liabilities
 
 
 
 
(101.1)
 
 
 
 
 
Net assets acquired
 
 
 
 
$ 3,378.3 
 
 
 
 
 
Affiliate Transactions (Details) (USD $)
3 Months Ended 9 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 7 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Mar. 7, 2014
Sep. 30, 2014
Sales Revenue [Member]
Sep. 30, 2014
Northridge Assets [Member]
Sep. 30, 2014
Northridge Assets [Member]
Sep. 30, 2014
Enlink midstream, LLC [Member]
Sep. 30, 2013
Devon Energy Corporation [Member]
Sep. 30, 2014
Devon Energy Corporation [Member]
Sep. 30, 2013
Devon Energy Corporation [Member]
Sep. 30, 2014
Devon Energy Corporation [Member]
Sales Revenue [Member]
Sep. 30, 2013
Devon Energy Corporation [Member]
Sales Revenue [Member]
Sep. 30, 2014
Devon Energy Corporation [Member]
Sales Revenue [Member]
Sep. 30, 2013
Devon Energy Corporation [Member]
Sales Revenue [Member]
Sep. 30, 2014
Affiliated Entity [Member]
Sep. 30, 2013
Affiliated Entity [Member]
Sep. 30, 2014
Affiliated Entity [Member]
Sep. 30, 2014
Affiliated Entity [Member]
Sep. 30, 2013
Affiliated Entity [Member]
Sep. 30, 2013
Continuing Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2014
Continuing Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2013
Continuing Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2013
Continuing Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2014
Continuing Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2013
Continuing Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Sep. 30, 2014
Discontinued Operations [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2014
Discontinued Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Devon Energy Corporation [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2014
Discontinued Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2013
Discontinued Operations [Member]
Affiliated Entity [Member]
Sep. 30, 2014
Bridgeport [Member]
Sep. 30, 2014
Oklahoma City [Member]
Sep. 30, 2014
Cresson [Member]
Sep. 30, 2014
Gulf Coast Fractionators [Member]
Sep. 30, 2014
EnLink Midstream Holdings, LP [Member]
Related Party Transaction [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$ (644,100,000)
$ (46,800,000)
$ (1,627,900,000)
$ (136,100,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ (435,600,000)
 
 
 
 
 
$ (531,400,000)
$ (436,400,000)
$ (1,557,000,000)
 
 
 
 
 
 
$ (20,800,000)
$ (10,400,000)
$ (68,100,000)
 
 
 
 
 
Operating Expenses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
8,900,000 
 
5,900,000 
26,900,000 
 
 
 
417,500,000 
340,000,000 
1,229,600,000 
 
 
 
 
 
 
7,800,000 
5,000,000 
25,400,000 
 
 
 
 
 
Net Related Party transactions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(113,900,000)
(96,400,000)
(327,400,000)
 
 
 
 
 
 
(13,400,000)
(5,400,000)
(48,300,000)
 
 
 
 
 
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
38.75% 
 
Cash Provided by (Used in) Financing Activities, Discontinued Operations
 
 
167,600,000 
(117,700,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(400,000)
0 
(5,600,000)
 
 
 
 
 
Business Acquisition, Percentage of Voting Interests Acquired
 
 
 
 
50.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Expenditures
190,600,000 
37,100,000 
453,400,000 
172,600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
44,700,000 
16,200,000 
201,300,000 
 
 
 
 
 
 
(100,000)
600,000 
5,300,000 
 
 
 
 
 
Other Expenses
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(50,800,000)
53,000,000 
8,400,000 
 
 
 
 
 
 
(73,500,000)
400,000 
(54,600,000)
 
 
 
 
 
Business Acquisition, Date of Acquisition Agreement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mar. 07, 2014 
Gross Profit
184,500,000 
106,900,000 
512,800,000 
297,500,000 
 
 
6,500,000 
22,300,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Leases, Rent Expense
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
174,000 
31,000 
66,000 
 
 
Total Third-Party Transactions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(6,100,000)
69,200,000 
209,700,000 
 
 
 
 
 
 
(73,600,000)
1,000,000 
(49,300,000)
 
 
 
 
 
Net distributions from (to) related party
 
(207,000,000)
(95,000,000)
(215,300,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(120,000,000)
(27,200,000)
(117,700,000)
(120,000,000)
(50,700,000)
(117,700,000)
(87,000,000)
(4,400,000)
(97,600,000)
 
 
 
(87,000,000)
(44,300,000)
(97,600,000)
 
 
 
 
 
Net distributions from (to) related party, non-cash
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0 
(23,500,000)
0 
 
 
 
0 
(39,900,000)
0 
 
 
 
 
 
 
 
 
Concentration Risk, Percentage
 
 
 
 
 
10.00% 
 
 
 
 
 
 
24.20% 
91.90% 
34.90% 
92.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Due from Affiliate, Current
113,200,000 
 
113,200,000 
 
 
 
 
 
600,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Due to Related Parties, Current
3,800,000 
 
3,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Allocated Share-based Compensation Expense
5,700,000 
3,500,000 
15,500,000 
10,100,000 
 
 
 
 
 
3,500,000 
2,800,000 
10,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and Other Postretirement Benefit Expense
 
 
 
 
 
 
 
 
 
$ 2,200,000 
$ 1,600,000 
$ 6,100,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt (Indebtedness Table) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Amount Outstanding
$ 371.0 
 
Long-term Debt
1,746.7 
 
Debt classified as long-term
1,746.7 
0 
Revolving Credit Facility [Member]
 
 
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Amount Outstanding
371.0 
 
2.7% Senior Notes due 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
397.3 
 
7.125% Senior Notes due 2022 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
185.1 1
 
4.4% Senior Notes due 2024 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
446.5 
 
5.6% Senior Notes due 2044 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
$ 346.8 
 
Long-Term Debt (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Feb. 20, 2014
Feb. 20, 2014
Letter of Credit [Member]
Sep. 30, 2014
Revolving Credit Facility [Member]
Sep. 30, 2014
8.875% Senior Notes due 2018 [Member]
Mar. 7, 2014
8.875% Senior Notes due 2018 [Member]
Sep. 30, 2014
8.875% Senior Notes due 2018 [Member]
Debt Instrument, Redemption, Period Two [Member]
Apr. 18, 2014
8.875% Senior Notes due 2018 [Member]
Debt Instrument, Redemption, Period Two [Member]
Sep. 30, 2014
8.875% Senior Notes due 2018 [Member]
Debt Instrument, Redemption, Period One [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Sep. 20, 2014
7.125% Senior Notes due 2022 [Member]
Jul. 20, 2014
7.125% Senior Notes due 2022 [Member]
Mar. 7, 2014
7.125% Senior Notes due 2022 [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
September Redemption [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Debt Instrument, Redemption, Period Two [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Debt Instrument, Redemption, Period One [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Debt Instrument, Redemption, Period Three [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Debt Instrument, Redemption, Period Four [Member]
Sep. 30, 2014
Unsecured Debt [Member]
Sep. 30, 2014
2.7% Senior Notes due 2019 [Member]
Sep. 30, 2014
4.4% Senior Notes due 2024 [Member]
Sep. 30, 2014
5.6% Senior Notes due 2044 [Member]
Sep. 30, 2014
Maximum [Member]
Sep. 30, 2014
Base Rate [Member]
Sep. 30, 2014
Revolving Credit Facility [Member]
Maximum [Member]
Sep. 30, 2014
Eurodollar [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Initiation Date
 
 
Feb. 20, 2014 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Issuance Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mar. 19, 2014 
 
 
 
 
 
 
 
Debt Instrument, Face Amount
 
 
 
 
 
 
 
 
$ 725.0 
 
 
 
 
 
 
$ 196.5 
 
 
 
 
 
$ 1,200.0 
$ 400.0 
$ 450.0 
$ 350.0 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage
 
 
 
 
 
 
 
 
8.875% 
 
 
 
7.125% 
 
 
7.125% 
 
 
 
 
 
 
2.70% 
4.40% 
5.60% 
 
 
 
 
Long-term Debt
1,746.7 
 
1,746.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Senior Notes
 
 
 
 
 
 
 
 
 
 
 
 
185.1 1
 
 
 
 
 
 
 
 
 
397.3 
446.5 
346.8 
 
 
 
 
Debt Instrument, Maturity Date
 
 
 
 
 
 
 
Feb. 15, 2018 
 
 
 
 
Jun. 01, 2022 
 
 
 
 
 
 
 
 
 
Apr. 01, 2019 
Apr. 01, 2024 
Apr. 01, 2044 
 
 
 
 
Selling Priceof Debt Instrument
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
99.85% 
99.83% 
99.925% 
 
 
 
 
Long-term Debt, Fair Value
 
 
 
 
 
 
 
 
761.3 
 
 
 
 
 
 
226.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Unamortized Discount (Premium), Net
 
 
 
 
 
 
 
 
36.3 
 
 
 
22.6 
 
 
29.5 
 
 
 
 
 
 
(2.7)
(3.5)
(3.3)
 
 
 
 
Debt Instrument Repurchase, Tendered Offer Date
 
 
 
 
 
 
 
Mar. 12, 2014 
 
Apr. 18, 2014 
 
Mar. 19, 2014 
Jul. 20, 2014 
 
 
 
Sep. 20, 2014 
Jun. 01, 2018 
Jun. 01, 2017 
Jun. 01, 2019 
Jun. 01, 2020 
 
Mar. 01, 2019 
Jan. 01, 2024 
Oct. 01, 2043 
 
 
 
 
Debt Instrument Repurchase, Tendered Amount
 
 
 
 
 
 
 
536.1 
 
 
 
 
 
15.5 
18.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument Repurchase, Amount of Outstanding Tendered, Percent
 
 
 
 
 
 
 
74.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument Repurchase, Amount Paid
 
 
 
 
 
 
 
 
 
 
200.2 
567.4 
 
17.0 
20.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gain on Extinguishment of Debt
2.4 
0 
3.2 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Redemption price
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
102.375% 
103.563% 
101.188% 
100.00% 
 
100.00% 
100.00% 
100.00% 
 
 
 
 
Line of Credit Facility, Maximum Borrowing Capacity
1,000.0 
 
1,000.0 
 
1,000.0 
500.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Leverage ratios
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5.0 to 1.0 
 
5.5 to 1.0 
 
Conditional acquisition purchase price
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50.0 
 
 
 
Line of Credit Facility, Interest Rate During Period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.50% 
 
1.00% 
Letters of Credit Outstanding, Amount
14.0 
 
14.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Amount Outstanding
371.0 
 
371.0 
 
 
 
371.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Remaining Borrowing Capacity
$ 615.0 
 
$ 615.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt (Percentages Per Annum) (Details)
9 Months Ended
Sep. 30, 2014
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Interest Rate During Period
1.00% 
Level 1 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Instrument, Credit Rating
A-/A3 or better 
Applicable Rate Commitment Fee
0.10% 
Base Rate
0.00% 
Level 1 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Interest Rate During Period
1.00% 
Level 2 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Instrument, Credit Rating
BBB+/Baa1 
Applicable Rate Commitment Fee
0.125% 
Base Rate
0.125% 
Level 2 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Interest Rate During Period
1.125% 
Level 3 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Instrument, Credit Rating
BBB/Baa2 
Applicable Rate Commitment Fee
0.175% 
Base Rate
0.25% 
Level 3 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Interest Rate During Period
1.25% 
Level 4 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Instrument, Credit Rating
BBB-/Baa3 
Applicable Rate Commitment Fee
0.225% 
Base Rate
0.50% 
Level 4 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Interest Rate During Period
1.50% 
Level 5 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Instrument, Credit Rating
BB+/Ba1 
Applicable Rate Commitment Fee
0.275% 
Base Rate
0.625% 
Level 5 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Interest Rate During Period
1.625% 
Level 6 [Member]
 
Line of Credit Facility [Line Items]
 
Debt Instrument, Credit Rating
BB/Ba2 or worse 
Applicable Rate Commitment Fee
0.35% 
Base Rate
0.75% 
Level 6 [Member] |
Eurodollar [Member]
 
Line of Credit Facility [Line Items]
 
Line of Credit Facility, Interest Rate During Period
1.75% 
Long-Term Debt (Parenthetical) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Line of Credit [Member]
Sep. 30, 2014
2.7% Senior Notes due 2019 [Member]
Sep. 30, 2014
4.4% Senior Notes due 2024 [Member]
Sep. 30, 2014
5.6% Senior Notes due 2044 [Member]
Sep. 30, 2014
7.125% Senior Notes due 2022 [Member]
Mar. 7, 2014
7.125% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
Line of Credit Facility, Interest Rate During Period
1.90% 
 
 
 
 
 
Senior notes fixed interest rate
 
2.70% 
4.40% 
5.60% 
7.125% 
7.125% 
Debt Instrument, Unamortized Discount (Premium), Net
 
$ 2.7 
$ 3.5 
$ 3.3 
$ (22.6)
$ (29.5)
Income Taxes (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Income Tax Contingency [Line Items]
 
 
Deferred Tax Liability, Elimination
$ 467.5 
 
Deferred Tax Liabilities, Net, Noncurrent
72.7 
440.9 
Texas Margin Tax [Member]
 
 
Income Tax Contingency [Line Items]
 
 
Deferred Tax Liabilities, Net, Noncurrent
8.2 
 
EnLink Midstream Holdings, LP [Member]
 
 
Income Tax Contingency [Line Items]
 
 
Deferred Tax Liabilities, Net, Noncurrent
$ 62.5 
 
Partners' Capital (Details Textuals)
3 Months Ended 9 Months Ended
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Sep. 30, 2014
Subsidiary Sale Of Stock [Line Items]
 
 
 
 
Percentage of avaliable cash to distribute
100.00% 
 
 
100.00% 
Number of days from end of quarter for distribution
 
 
 
45 days 
Distribution Made to Limited Partner, Distribution Date
Nov. 13, 2014 
Aug. 13, 2014 
May 14, 2014 
 
Distribution Made to Limited Partner, Distributions Declared, Per Unit
$ 0.37 
$ 0.365 
$ 0.36 
 
Class B units conversion date
 
 
 
May 06, 2014 
Class B units [Member]
 
 
 
 
Subsidiary Sale Of Stock [Line Items]
 
 
 
 
Distribution Made to Limited Partner, Distribution Date
 
 
 
May 14, 2014 
Distribution Made to Limited Partner, Distributions Declared, Per Unit
 
 
$ 0.10 
$ 0.10 
General Partner [Member] |
13% Distribution [Member]
 
 
 
 
Subsidiary Sale Of Stock [Line Items]
 
 
 
 
Incentive Distribution Percentage Levels
 
 
 
13.00% 
Incentive Distribution, Distribution Per Unit
 
 
 
$ 0.25 
General Partner [Member] |
23% Distribution [Member]
 
 
 
 
Subsidiary Sale Of Stock [Line Items]
 
 
 
 
Incentive Distribution Percentage Levels
 
 
 
23.00% 
Incentive Distribution, Distribution Per Unit
 
 
 
$ 0.31 
General Partner [Member] |
48% Distribution [Member]
 
 
 
 
Subsidiary Sale Of Stock [Line Items]
 
 
 
 
Incentive Distribution Percentage Levels
 
 
 
48.00% 
Incentive Distribution, Distribution Per Unit
 
 
 
$ 0.38 
Partners' Capital (EPU Computation Schedule) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Capital Unit [Line Items]
 
 
 
 
 
 
Distribution Made to Limited Partner, Distributions Declared, Per Unit
$ 0.37 
$ 0.365 
$ 0.36 
 
 
 
Distribution Made to Limited Partner, Distribution Date
Nov. 13, 2014 
Aug. 13, 2014 
May 14, 2014 
 
 
 
Limited partners' interest in net income attributable to EnLink Midstream Partners, LP
$ 40.5 
 
 
$ 0 
$ 86.5 
$ 0 
Earnings Per Share, Basic
$ 0.18 
 
 
$ 0.00 
$ 0.38 
$ 0.00 
Distributed Earnings
85.9 
 
 
 
221.5 
 
Undistributed Earnings, Basic
(45.3)
 
 
 
(135.1)
 
Diluted per common unit
$ 0.18 
 
 
$ 0.00 
$ 0.38 
$ 0.00 
Common Unit [Member]
 
 
 
 
 
 
Capital Unit [Line Items]
 
 
 
 
 
 
Limited partners' interest in net income attributable to EnLink Midstream Partners, LP
40.3 
 
 
 
86.1 
 
Distributed Earnings
85.5 
 
 
 
220.6 
 
Undistributed Earnings, Basic
(45.1)
 
 
 
(134.6)
 
Restricted Stock Units (RSUs) [Member]
 
 
 
 
 
 
Capital Unit [Line Items]
 
 
 
 
 
 
Limited partners' interest in net income attributable to EnLink Midstream Partners, LP
0.2 
 
 
 
0.4 
 
Distributed Earnings
0.4 
 
 
 
0.9 
 
Undistributed Earnings, Basic
$ (0.2)
 
 
 
$ (0.5)
 
Class B units [Member]
 
 
 
 
 
 
Capital Unit [Line Items]
 
 
 
 
 
 
Distribution Made to Limited Partner, Distributions Declared, Per Unit
 
 
$ 0.10 
 
$ 0.10 
 
Distribution Made to Limited Partner, Distribution Date
 
 
 
 
May 14, 2014 
 
Partners' Capital (Weighted Average Schedule) (Details)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2014
Class of Stock [Line Items]
 
 
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities
0.4 
0.3 
Weighted Average Number of Shares Outstanding, Basic and Diluted
231.4 
230.6 
Common Unit [Member]
 
 
Class of Stock [Line Items]
 
 
Weighted Average Limited Partnership Units Outstanding, Basic
231.0 
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, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Incentive Distribution Made to Managing Member or General Partner [Line Items]
 
 
 
 
Income allocation for incentive distributions
$ 6.3 
 
$ 13.6 
 
Unit-based compensation attributable to ENLC’s restricted units
(3.1)
 
(6.8)
 
General Partner interest in net income
0.3 
 
0.7 
 
General Partner share of net income
$ 3.5 
$ 0 
$ 7.5 
$ 0 
Partners Capital (Issuance of Common Units) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Class of Stock [Line Items]
 
 
Proceeds from Issuance of Common Units
$ 71.9 
$ 0 
ATM [Member]
 
 
Class of Stock [Line Items]
 
 
Approximate Date of Commencement of Proposed Sale to Public
May 29, 2014 
 
AggregateAmountOfEquitySecuritiesAllowedUnderEquityDistributionAgreement
75.0 
 
Partners' Capital Account, Units, Sold in Public Offering
2.4 
 
Proceeds from Issuance of Common Units
71.9 
 
Sales Commissions and Fees
$ 0.7 
 
Asset Retirement Obligation (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
 
 
 
 
Asset Retirement Obligation
$ 10.8 
$ 9.8 
$ 7.7 
$ 9.1 
Asset Retirement Obligation, Revision of Estimate
2.2 
0.4 
 
 
Asset Retirement Obligation, Liabilities Incurred
0.5 
0 
 
 
Asset Retirement Obligation, Accretion Expense
$ 0.4 
$ 0.3 
 
 
Investment in Unconsolidated Affiliate (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
Distribution of earnings from equity investment
 
 
$ 6.3 
$ 10.9 
 
Income (Loss) from Equity Method Investments
5.6 
5.8 
14.3 
10.2 
 
Income (Loss) from Equity Method Investments
276.1 
 
276.1 
 
61.1 
Undistributed Earnings, Basic
45.3 
 
135.1 
 
 
Gulf Coast Fractionators [Member]
 
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
Distribution of earnings from equity investment
5.2 
12.0 
5.2 1
12.0 
 
Income (Loss) from Equity Method Investments
5.2 
5.8 
13.2 1
10.2 
 
Income (Loss) from Equity Method Investments
56.0 2
 
56.0 2
 
61.1 2
Undistributed Earnings, Basic
 
 
13.1 
 
 
Equity Method Investment, Ownership Percentage
38.75% 
 
38.75% 
 
 
Howard Energy Partners [Member]
 
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
Distribution of earnings from equity investment
3.0 
0 
8.7 1
0 
 
Income (Loss) from Equity Method Investments
0.4 
0 
1.1 1
0 
 
Income (Loss) from Equity Method Investments
220.1 
 
220.1 
 
0 
Equity Method Investment, Ownership Percentage
30.60% 
 
30.60% 
 
 
Total [Member]
 
 
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
 
 
Distribution of earnings from equity investment
8.2 
12.0 
13.9 1
12.0 
 
Income (Loss) from Equity Method Investments
$ 5.6 
$ 5.8 
$ 14.3 1
$ 10.2 
 
Employee Incentive Plan (Textuals) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 9 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2014
ENLC Restricted Units [Member]
Sep. 30, 2014
ENLC Restricted Units [Member]
Feb. 5, 2014
ENLC Restricted Units [Member]
Sep. 30, 2014
Pre acquisition [Member]
ENLK Restricted Units [Member]
Sep. 30, 2014
Pre acquisition [Member]
ENLC Restricted Units [Member]
Sep. 30, 2014
post acquisition [Member]
ENLK Restricted Units [Member]
Sep. 30, 2014
post acquisition [Member]
ENLC Restricted Units [Member]
Mar. 7, 2014
Common Unit [Member]
ENLK Restricted Units [Member]
Sep. 30, 2014
Restricted Stock Units (RSUs) [Member]
ENLK Restricted Units [Member]
Sep. 30, 2014
Restricted Stock Units (RSUs) [Member]
ENLK Restricted Units [Member]
Sep. 30, 2014
Restricted Stock [Member]
ENLC Restricted Units [Member]
Sep. 30, 2014
EnLink Midstream Partners, LP [Member]
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
ShareBasedCompensationArrangementByShareBasedPaymentAwardEquityInstrumentsOtherThanOptionsVestedInPeriodIntrinsicValue1
$ 2.4 
$ 2.4 
 
 
 
 
 
 
$ 1.2 
$ 1.2 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized
 
 
11,000,000 
 
 
 
 
9,070,000 
 
 
 
 
Unrecognized compensation cost related to non-vested restricted incentive units
 
 
 
 
 
 
 
 
 
 
23.3 
21.3 
Vesting Period
 
 
 
2 years 
2 years 
3 years 
3 years 
 
 
 
 
 
Unrecognized compensation costs, weighted average period for recognition
 
 
 
 
 
 
 
 
 
 
2 years 1 month 
2 years 1 month 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value
$ 2.2 
$ 2.2 
 
 
 
 
 
 
$ 1.2 
$ 1.2 
 
 
Employee Incentive Plan (Expense Schedule) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Allocated Share-based Compensation Expense
$ 5.7 
$ 3.5 
$ 15.5 
$ 10.1 
General and Administrative Expense [Member]
 
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Allocated Share-based Compensation Expense
4.9 
0 
10.9 
0 
Operating Expense [Member]
 
 
 
 
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
 
 
 
 
Allocated Share-based Compensation Expense
0.8 
0 
1.8 
0 
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 
$ 3.5 
$ 2.8 
$ 10.1 
Employee Incentive Plan (Compensation Schedule) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
9 Months Ended
Sep. 30, 2014
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
16,471 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Assumed in Business Combination
371,225 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Assumed in Business Combination, price
$ 30.51 
Number of Units
 
Non-vested, beginning of period (Units)
0 
Granted (Units)
701,119 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
(39,833)
Forfeited (Units)
(13,196)
Non-vested, end of period (Units)
1,019,315 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 0.00 
Granted
$ 31.65 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 30.63 
Forfeited
$ 31.83 
Non-vested, end of period
$ 31.27 
Aggregate intrinsic value, end of period (in thousands)
$ 31.0 
ENLC Restricted Units [Member]
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Shares Paid for Tax Withholding for Share Based Compensation
24,727 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Assumed in Business Combination
435,674 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Assumed in Business Combination, price
$ 37.60 
Number of Units
 
Non-vested, beginning of period (Units)
0 
Granted (Units)
626,341 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
(59,553)
Forfeited (Units)
(11,859)
Non-vested, end of period (Units)
990,603 
Weighted Average Grant-Date Fair Value
 
Non-vested, beginning of period
$ 0.00 
Granted
$ 36.59 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 37.56 
Forfeited
$ 36.54 
Non-vested, end of period
$ 36.97 
Aggregate intrinsic value, end of period (in thousands)
$ 40.9 
Employee Incentive Plan (Instrinsic Value of Options Units Vested) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period
31,382 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value
$ 0.6 
Employee Incentive Plan (Intrinsic and Fair Value of Units Vested) (Details) (ENLK Restricted Units [Member], Restricted Stock Units (RSUs) [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2014
ENLK Restricted Units [Member] |
Restricted Stock Units (RSUs) [Member]
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
ShareBasedCompensationArrangementByShareBasedPaymentAwardEquityInstrumentsOtherThanOptionsVestedInPeriodIntrinsicValue1
$ 1.2 
$ 1.2 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value
$ 1.2 
$ 1.2 
Derivatives (Summary of Derivative Income Expense) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Derivative, Gain (Loss) on Derivative, Net
 
 
$ (1.9)
$ 0 
Gain (loss) on derivative activity
1.0 
0 
(1.9)
0 
Commodity Swap [Member]
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Derivative, Gain (Loss) on Derivative, Net
1.8 
 
(0.2)
 
Change in fair value of derivatives
(0.8)
 
(1.7)
 
Gain (loss) on derivative activity
$ 1.0 
 
$ (1.9)
 
Derivatives (Schedule of Derivative Assets Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative assets, current
$ 1.1 
$ 0 
Derivative Asset, Noncurrent
0.2 
0 
Fair value of derivative liabilities, current
(0.9)
0 
Derivative Liability, Noncurrent
(0.6)
 
Net fair value of derivatives
$ (0.2)
 
Derivatives (Derivatives Outstanding) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Derivative [Line Items]
 
Total mark to market derivatives
$ (0.2)
Gas [Member] |
Long [Member]
 
Derivative [Line Items]
 
Derivative Nonmonetary Notional Amount
400,000 
Total mark to market derivatives
(0.1)
Gas [Member] |
Short [Member]
 
Derivative [Line Items]
 
Derivative Nonmonetary Notional Amount
2,200,000 
Total mark to market derivatives
0.1 
Natural Gas Liquids [Member] |
Long [Member]
 
Derivative [Line Items]
 
Derivative Nonmonetary Notional Amount
47,900,000 
Total mark to market derivatives
(0.9)
Natural Gas Liquids [Member] |
Short [Member]
 
Derivative [Line Items]
 
Derivative Nonmonetary Notional Amount
61,300,000 
Total mark to market derivatives
0.7 
Commodity [Member]
 
Derivative [Line Items]
 
Total mark to market derivatives
$ (0.2)
Derivatives (Details Textuals) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Derivative [Line Items]
 
Maximum counterparty loss
$ 1.3 
Maximum counterparty loss with netting feature
$ 0.2 
Derivatives (Derivatives Other Than Cash Flow Hedges Table) (Details) (Market Approach Valuation Technique [Member], USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Derivative [Line Items]
 
Less than one year
$ (0.2)
Maturity More Than Two Years [Member]
 
Derivative [Line Items]
 
Less than one year
(0.1)
Maturity Within One to Two Years [Member]
 
Derivative [Line Items]
 
Less than one year
(0.3)
Maturity Less Than One Year [Member]
 
Derivative [Line Items]
 
Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value
$ 0.2 
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, 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
$ (0.2)
Fair Value Measurement (Fair Value of Financial Instrument) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
Long-term Debt
$ 1,746.7 
Carrying Value [Member]
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
Long-term Debt
1,746.7 
Obligations under capital lease
20.7 
Fair Value [Member]
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
Long-term Debt, Fair Value
1,809.2 
Obligations under capital lease
$ 20.3 
Fair Value Measurement (Details Textuals) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Mar. 7, 2014
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Amount Outstanding
$ 371.0 
 
Long-term Debt
1,746.7 
 
Revolving Credit Facility [Member]
 
 
Debt Instrument [Line Items]
 
 
Line of Credit Facility, Amount Outstanding
371.0 
 
2.7% Senior Notes due 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
397.3 
 
Senior notes fixed interest rate
2.70% 
 
4.4% Senior Notes due 2024 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
446.5 
 
Senior notes fixed interest rate
4.40% 
 
5.6% Senior Notes due 2044 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
346.8 
 
Senior notes fixed interest rate
5.60% 
 
8.875% Senior Notes due 2018 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior notes fixed interest rate
 
8.875% 
7.125% Senior Notes due 2022 [Member]
 
 
Debt Instrument [Line Items]
 
 
Senior Notes
$ 185.1 1
 
Senior notes fixed interest rate
7.125% 
7.125% 
Commitments and Contingencies (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Gain Contingencies [Line Items]
 
 
 
 
Gain on Litigation Settlement
$ 6.1 
$ 0 
$ 6.1 
$ 0 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Segment Reporting Information [Line Items]
 
 
 
 
 
Sales to external customers
$ 644.1 
$ 46.8 
$ 1,627.9 
$ 136.1 
 
Sales to affiliates
206.3 
531.4 
872.0 
1,557.0 
 
Purchased gas, NGLs, Condensate and crude oil
(597.2)
(435.5)
(1,798.0)
(1,279.6)
 
Operating expenses
(75.8)
(35.8)
(193.3)
(116.0)
 
Gain on Litigation Settlement
6.1 
0 
6.1 
0 
 
Gain (loss) on derivative activity
1.0 
0 
(1.9)
0 
 
Segment profit (loss)
184.5 
106.9 
512.8 
297.5 
 
Depreciation and Amortization
(71.6)
(48.0)
(192.3)
(138.6)
 
Goodwill
2,257.8 
401.7 
2,257.8 
401.7 
401.7 
Capital Expenditures
190.6 
37.1 
453.4 
172.6 
 
Identifiable assets
7,917.6 
 
7,917.6 
 
2,309.8 
Texas Operating Segment [Member]
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
Sales to external customers
77.3 
32.9 
214.3 
96.6 
 
Sales to affiliates
148.9 
359.4 
637.7 
1,052.3 
 
Purchased gas, NGLs, Condensate and crude oil
(76.8)
(286.2)
(423.0)
(838.7)
 
Operating expenses
(36.2)
(26.9)
(106.5)
(92.0)
 
Gain on Litigation Settlement
0 
 
0 
 
 
Gain (loss) on derivative activity
0 
 
0 
 
 
Segment profit (loss)
113.2 
79.2 
322.5 
218.2 
 
Depreciation and Amortization
(31.6)
(29.0)
(91.7)
(82.4)
 
Goodwill
1,168.2 
325.4 
1,168.2 
325.4 
 
Capital Expenditures
79.7 
27.1 
180.2 
113.9 
 
Identifiable assets
3,236.9 
 
3,236.9 
 
1,460.0 
Louisiana Operating Segment [Member]
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
Sales to external customers
491.3 
0 
1,221.9 
0 
 
Sales to affiliates
39.5 
0 
41.7 
0 
 
Purchased gas, NGLs, Condensate and crude oil
(486.9)
0 
(1,158.2)
0 
 
Operating expenses
(23.7)
0 
(45.5)
0 
 
Gain on Litigation Settlement
6.1 
 
6.1 
 
 
Gain (loss) on derivative activity
0 
 
0 
 
 
Segment profit (loss)
26.3 
0 
66.0 
0 
 
Depreciation and Amortization
(19.1)
0 
(43.4)
0 
 
Goodwill
786.8 
0 
786.8 
0 
 
Capital Expenditures
79.1 
0 
222.4 
0 
 
Identifiable assets
2,925.3 
 
2,925.3 
 
0 
Oklahoma Operating Segment [Member]
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
Sales to external customers
0 
13.9 
11.5 
39.5 
 
Sales to affiliates
45.9 
172.0 
256.0 
504.7 
 
Purchased gas, NGLs, Condensate and crude oil
0 
(149.3)
(133.8)
(440.9)
 
Operating expenses
(7.0)
(8.9)
(20.9)
(24.0)
 
Gain on Litigation Settlement
0 
 
0 
 
 
Gain (loss) on derivative activity
0 
 
0 
 
 
Segment profit (loss)
38.9 
27.7 
112.8 
79.3 
 
Depreciation and Amortization
(11.8)
(19.0)
(37.6)
(56.2)
 
Goodwill
190.3 
76.3 
190.3 
76.3 
 
Capital Expenditures
2.5 
10.0 
10.5 
58.7 
 
Identifiable assets
894.5 
 
894.5 
 
777.1 
ORV Operating Segments [Member]
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
Sales to external customers
75.5 
0 
180.2 
0 
 
Sales to affiliates
0 
0 
0 
0 
 
Purchased gas, NGLs, Condensate and crude oil
(61.5)
0 
(146.4)
0 
 
Operating expenses
(8.9)
0 
(20.4)
0 
 
Gain on Litigation Settlement
0 
 
0 
 
 
Gain (loss) on derivative activity
0 
 
0 
 
 
Segment profit (loss)
5.1 
0 
13.4 
0 
 
Depreciation and Amortization
(8.2)
0 
(18.1)
0 
 
Goodwill
112.5 
0 
112.5 
0 
 
Capital Expenditures
25.4 
0 
27.7 
0 
 
Identifiable assets
513.6 
 
513.6 
 
0 
Corporate Segment [Member]
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
Sales to external customers
0 
0 
0 
0 
 
Sales to affiliates
(28.0)
0 
(63.4)
0 
 
Purchased gas, NGLs, Condensate and crude oil
28.0 
0 
63.4 
0 
 
Operating expenses
0 
0 
0 
0 
 
Gain on Litigation Settlement
0 
 
0 
 
 
Gain (loss) on derivative activity
1.0 
 
(1.9)
 
 
Segment profit (loss)
1.0 
0 
(1.9)
0 
 
Depreciation and Amortization
(0.9)
0 
(1.5)
0 
 
Goodwill
0 
0 
0 
0 
 
Capital Expenditures
3.9 
0 
12.6 
0 
 
Identifiable assets
$ 347.3 
 
$ 347.3 
 
$ 72.7 
Segment Information (Reconciliation of Segment Profit to Operating Income) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Segment Reporting [Abstract]
 
 
 
 
Segment profit (loss)
$ 184.5 
$ 106.9 
$ 512.8 
$ 297.5 
General and administrative
(22.8)
(10.8)
(62.8)
(32.3)
Depreciation and Amortization
(71.6)
(48.0)
(192.3)
(138.6)
Operating Income (Loss)
$ 90.1 
$ 48.1 
$ 257.7 
$ 126.6 
Discontinued Operations (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
Disposal Group, Including Discontinued Operation, Revenue, External
 
$ 10.9 
$ 6.8 
$ 33.5 
 
Disposal Group, Including Discontinued Operation, Revenue, Related Party
 
20.8 
10.5 
68.1 
 
Operating revenues
 
31.7 
17.3 
101.6 
 
Operating expenses
 
37.9 
15.7 
91.7 
 
Income before income taxes
 
(6.2)
1.6 
9.9 
 
Income tax expense
 
(2.2)
0.6 
3.6 
 
Net income
0 
(4.0)
1.0 
6.3 
 
Net income attributable to non-controlling interest
0 
(0.3)
0 
(1.4)
 
Net income including non-controlling interest
0 
(4.3)
1.0 
4.9 
 
Inventories
 
 
 
 
0.2 
Other current assets
 
 
 
 
0.2 
DisposalGroupIncludingDiscontinuedOperationCurrentTotal
 
 
 
 
0.4 
Total current assets
0 
 
0 
 
72.7 
Property, Plant, and Equipment
 
 
 
 
72.3 
Accounts Payable
 
 
 
 
3.2 
Other current liabilities
 
 
 
 
1.1 
Liabilities Of Disposal Group Including Discontinued Operations
 
 
 
 
4.3 
Total current liabilities
0 
 
0 
 
37.0 
Asset Retirement Obligation
 
 
 
 
7.1 
Deferred income taxes
 
 
 
 
25.3 
Other long-term liabilities
 
 
 
 
$ 0.3 
Gulf Coast Fractionators [Member]
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
Equity Method Investment, Ownership Percentage
38.75% 
 
38.75% 
 
 
Subsequent Events (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 0 Months Ended 3 Months Ended 0 Months Ended 3 Months Ended
Sep. 30, 2014
Oct. 22, 2014
Subsequent Event [Member]
Dec. 31, 2014
Energy Services [Member]
Subsequent Event [Member]
Dec. 31, 2014
Appalachian [Member]
Subsequent Event [Member]
Sep. 30, 2014
GulfCoast [Member]
Oct. 22, 2014
GulfCoast [Member]
Subsequent Event [Member]
Dec. 31, 2014
GulfCoast [Member]
Subsequent Event [Member]
Dec. 31, 2014
Class B [Member]
Appalachian [Member]
Subsequent Event [Member]
Dec. 31, 2014
Class A [Member]
Energy Services [Member]
Subsequent Event [Member]
Dec. 31, 2014
Class A [Member]
Appalachian [Member]
Subsequent Event [Member]
Subsequent Event [Line Items]
 
 
 
 
 
 
 
 
 
 
Deposits Assets, Noncurrent
 
 
 
 
$ 23.5 
 
 
 
 
 
Business Acquisition, Effective Date of Acquisition
Mar. 07, 2014 
Oct. 22, 2014 
 
 
 
Nov. 01, 2014 
 
 
 
 
Business Combination, Consideration Transferred
 
 
 
 
 
 
235.0 
 
 
 
Payments to Acquire Businesses, Gross
 
 
13.0 
150.0 
 
 
 
 
 
 
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable
 
 
 
$ 1.0 
 
 
 
$ 0 
$ 0 
$ 0