ENLINK MIDSTREAM PARTNERS, LP, 10-Q filed on 5/3/2017
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2017
Apr. 27, 2017
Document And Entity Information [Abstract]
 
 
Document Type
10-Q 
 
Document Fiscal Period Focus
Q1 
 
Document Period End Date
Mar. 31, 2017 
 
Document Fiscal Year Focus
2017 
 
Amendment Flag
false 
 
Entity Registrant Name
ENLINK MIDSTREAM PARTNERS, LP 
 
Entity Central Index Key
0001179060 
 
Entity Current Reporting Status
Yes 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
346,452,004 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Current assets:
 
 
Cash and cash equivalents
$ 14.8 
$ 11.6 
Accounts receivable:
 
 
Trade, net of allowance for bad debt of $0.1 and $0.1, respectively
47.1 
63.9 
Accrued revenue and other
358.1 
369.6 
Related party
111.5 
100.2 
Fair value of derivative assets
2.1 
1.3 
Natural gas and NGLs inventory, prepaid expenses and other
25.7 
31.0 
Investment in unconsolidated affiliates—current
0 
193.1 
Total current assets
559.3 
770.7 
Property and equipment, net of accumulated depreciation of $2,220.6 and $2,124.1, respectively
6,396.3 
6,256.7 
Fair value of derivative assets
0.1 
0 
Intangible assets, net of accumulated amortization of $201.1 and $171.6, respectively
1,594.7 
1,624.2 
Goodwill
422.3 
422.3 
Investment in unconsolidated affiliates—non-current
84.5 
77.3 
Other assets, net
2.2 
2.2 
Total assets
9,059.4 
9,153.4 
Current liabilities:
 
 
Accounts payable and drafts payable
70.9 
69.2 
Accounts payable to related party
12.5 
10.4 
Accrued gas, NGLs, condensate and crude oil purchases
306.2 
333.3 
Fair value of derivative liabilities
2.9 
7.6 
Installment payable, net of discount of $19.9 and $0.5, respectively
230.1 
249.5 
Other current liabilities
213.8 
217.0 
Total current liabilities
836.4 
887.0 
Long-term debt
3,478.1 
3,268.0 
Asset retirement obligations
13.7 
13.5 
Installment payable, net of discount of $26.3 at December 31, 2016
0 
223.7 
Other long-term liabilities
42.1 
42.6 
Deferred tax liability
72.7 
73.0 
Fair value of derivative liabilities
0.3 
0 
Redeemable non-controlling interest
4.8 
5.2 
Partners’ equity:
 
 
Common unitholders (346,443,821 and 342,856,292 units issued and outstanding at March 31, 2017 and December 31, 2016, respectively)
3,109.7 
3,193.2 
Preferred unitholders (54,312,781 and 53,182,651 units issued and outstanding at March 31, 2017 and December 31, 2016, respectively)
815.5 
794.0 
General partner interest (1,594,974 equivalent units outstanding at March 31, 2017 and December 31, 2016)
208.8 
209.1 
Non-controlling interest
477.3 
444.1 
Total partners’ equity
4,611.3 
4,640.4 
Commitments and contingencies (Note 13)
   
   
Total liabilities and partners’ equity
$ 9,059.4 
$ 9,153.4 
Condensed Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Assets [Abstract]
 
 
Allowance for bad debt
$ 0.1 
$ 0.1 
Accumulated depreciation
2,220.6 
2,124.1 
Accumulated amortization
201.1 
171.6 
Liabilities [Abstract]
 
 
Discount of installment payable, current
19.9 
0.5 
Discount of installment payable, noncurrent
$ 0 
$ 26.3 
Partners’ equity:
 
 
Common units issued (in shares)
346,443,821 
342,856,292 
Common units outstanding (in shares)
346,443,821 
342,856,292 
Preferred units issued (in shares)
54,312,781 
53,182,651 
Preferred unit outstanding (in shares)
54,312,781 
53,182,651 
General partner interest, equivalent units outstanding (in shares)
1,594,974 
1,594,974 
Consolidated Statements of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Revenues:
 
 
Product sales
$ 990.0 
$ 588.5 
Product sales—related parties
42.7 
24.5 
Midstream services
127.4 
114.5 
Midstream services—related parties
159.0 
162.6 
Gain (loss) on derivative activity
2.8 
(0.4)
Total revenues
1,321.9 
889.7 
Operating costs and expenses:
 
 
Cost of sales
1,002.3 1
586.2 1
Operating expenses
104.1 2
98.2 2
General and administrative
35.0 
33.2 
(Gain) loss on disposition of assets
5.1 
(0.2)
Depreciation and amortization
128.3 
121.9 
Impairments
7.0 
566.3 
Gain on litigation settlement
(17.5)
0 
Total operating costs and expenses
1,264.3 
1,405.6 
Operating income (loss)
57.6 
(515.9)
Other income (expense):
 
 
Interest expense, net of interest income
(44.5)
(43.7)
Income (loss) from unconsolidated affiliates
0.7 
(2.4)
Other income
0 
0.1 
Total other expense
(43.8)
(46.0)
Income (loss) before non-controlling interest and income taxes
13.8 
(561.9)
Income tax provision
(0.5)
(1.0)
Net income (loss)
13.3 
(562.9)
Net loss attributable to the non-controlling interest
(4.8)
(2.5)
Net income (loss) attributable to EnLink Midstream Partners, LP
18.1 
(560.4)
General partner interest in net income
5.9 
7.4 
Limited partners’ interest in net loss attributable to EnLink Midstream Partners, LP
(9.3)
(567.2)
Class C partners’ interest in net loss attributable to EnLink Midstream Partners, LP
0 
(12.4)
Preferred interest in net income attributable to EnLink Midstream Partners, LP
$ 21.5 
$ 11.8 
Net loss attributable to EnLink Midstream Partners, LP per limited partners’ unit:
 
 
Basic common unit (in dollars per share)
$ (0.03)
$ (1.74)
Diluted common unit (in dollars per share)
$ (0.03)
$ (1.74)
Condensed Consolidated Statements of Operations (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Income Statement [Abstract]
 
 
Related party cost of sales
$ 28.7 
$ 42.6 
Related party operating expenses
$ 0.2 
$ 0.1 
Consolidated Statement of Changes in Partners' Equity - Partners Equity (USD $)
In Millions, unless otherwise specified
Total
Devon
Non-Controlling Interest
General Partner Interest
Common Units
Limited Partner
Common Units
Limited Partner
Devon
Preferred Units
Beginning balance at Dec. 31, 2016
$ 4,640.4 
 
$ 444.1 
$ 209.1 
$ 3,193.2 
 
$ 794.0 
Beginning balance (in shares) at Dec. 31, 2016
 
 
 
1.6 
342.9 
 
53.2 
Increase (Decrease) in Partners' Capital
 
 
 
 
 
 
 
Issuance of common units
55.2 
 
 
 
55.2 
 
 
Issuance of common units (in shares)
 
 
 
 
3.0 
 
 
Conversion of restricted units for common units, net of units withheld for taxes
(5.0)
 
 
 
(5.0)
 
 
Conversion of restricted units for common units, net of units withheld for taxes (in shares)
 
 
 
 
0.5 
 
 
Unit-based compensation
17.7 
 
 
8.9 
8.8 
 
 
Contribution from Devon
 
1.3 
 
 
 
1.3 
 
Distributions
(149.6)
 
 
(15.1)
(134.5)
 
 
Distribution (in shares)
 
 
 
 
 
 
1.1 
Non-controlling interest contributions
40.9 
 
40.9 
 
 
 
 
Distributions to non-controlling interest
(2.9)
 
(2.9)
 
 
 
 
Net income (loss)
13.3 
 
(4.8)
5.9 
(9.3)
 
21.5 
Ending balance at Mar. 31, 2017
$ 4,611.3 
 
$ 477.3 
$ 208.8 
$ 3,109.7 
 
$ 815.5 
Ending balance (in shares) at Mar. 31, 2017
 
 
 
1.6 
346.4 
 
54.3 
Consolidated Statement of Changes in Partners' Equity - Redeemable Non-controlling Interest (Temporary Equity) (USD $)
In Millions, unless otherwise specified
Total
Redeemable Non-Controlling Interest (Temporary Equity)
Beginning balance at Dec. 31, 2016
 
$ 5.2 
Increase (Decrease) in Temporary Equity
 
 
Distributions to redeemable non-controlling interest
(2.9)
(0.4)
Ending balance at Mar. 31, 2017
 
$ 4.8 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Cash flows from operating activities:
 
 
Net income (loss)
$ 13.3 
$ (562.9)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Impairments
7.0 
566.3 
Depreciation and amortization
128.3 
121.9 
(Gain) loss on disposition of assets
5.1 
(0.2)
Non-cash unit-based compensation
19.3 
7.9 
(Gain) loss on derivatives recognized in net income (loss)
(2.8)
0.4 
Cash settlements on derivatives
(2.9)
5.6 
Amortization of debt issue costs
0.9 
0.8 
Amortization of net discount on notes
6.3 
11.7 
Redeemable non-controlling interest expense
0 
0.2 
(Income) loss from unconsolidated affiliates
(0.7)
2.4 
Other
0 
0.1 
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
 
 
Accounts receivable, accrued revenue and other
17.1 
32.0 
Natural gas and NGLs inventory, prepaid expenses and other
2.3 
14.9 
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities
(19.0)
(12.0)
Net cash provided by operating activities
174.2 
189.1 
Cash flows from investing activities, net of assets acquired and liabilities assumed:
 
 
Additions to property and equipment
(256.3)
(135.4)
Acquisition of business, net of cash acquired
0 
(774.9)
Proceeds from sale of unconsolidated affiliate investment
189.7 
0 
Proceeds from sale of property
0.5 
0.2 
Investment in unconsolidated affiliates
(6.0)
(7.1)
Distribution from unconsolidated affiliates in excess of earnings
2.8 
6.2 
Net cash used in investing activities
(69.3)
(911.0)
Cash flows from financing activities:
 
 
Proceeds from borrowings
793.0 
379.0 
Payments on borrowings
(583.0)
(250.0)
Payment of installment payable for EnLink Oklahoma T.O. acquisition
(250.0)
0 
Payments on capital lease obligations
(1.0)
(1.1)
Debt financing costs
(0.2)
(0.2)
Conversion of restricted units, net of units withheld for taxes
(5.0)
(1.1)
Proceeds from issuance of common units
55.2 
2.1 
Proceeds from issuance of preferred units
0 
724.5 
Distributions to non-controlling partners
(3.3)
(0.8)
Contributions by non-controlling partners (including contributions from affiliates of $20.1 million and $6.7 million, respectively)
40.9 
9.7 
Distribution to partners
(149.6)
(141.8)
Contribution from Devon
1.3 
1.4 
Net cash provided by (used in) financing activities
(101.7)
721.7 
Net increase (decrease) in cash and cash equivalents
3.2 
(0.2)
Cash and cash equivalents, beginning of period
11.6 
5.9 
Cash and cash equivalents, end of period
14.8 
5.7 
Cash paid for interest
15.6 
3.3 
Cash paid for income taxes
$ 2.4 
$ 1.5 
Consolidated Statements of Cash Flows (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Proceeds from affiliates
$ 40.9 
$ 9.7 
Affiliates
 
 
Proceeds from affiliates
$ 20.1 
$ 6.7 
General
General
(1) General
 
In this report, the term “Partnership,” as well as the terms “ENLK,” “our,” “we,” “us” and “its,” are sometimes used as abbreviated references to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership (as defined below) and EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”). EnLink Oklahoma T.O. is sometimes used to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP together with its consolidated subsidiaries.
 
(a)
Organization of Business
 
EnLink Midstream Partners, LP is a publicly traded Delaware limited partnership formed in 2002. Our common units are traded on the New York Stock Exchange under the symbol “ENLK.” Our business activities are conducted through our subsidiary, EnLink Midstream Operating, LP, a Delaware limited partnership (the “Operating Partnership”), and the subsidiaries of the Operating Partnership.
 
EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities. Our general partner is an indirect wholly-owned subsidiary of EnLink Midstream, LLC (“ENLC”). ENLC’s units are traded on the New York Stock Exchange under the symbol “ENLC.” Devon Energy Corporation (“Devon”) owns ENLC’s managing member and common units, which represent approximately 64% of the outstanding limited liability company interests in ENLC.

(b)
Nature of Business
 
We primarily focus on providing midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services and marketing to producers of natural gas, natural gas liquids (“NGLs”), crude oil and condensate. We connect the wells of producers in our market areas to our gathering systems, process natural gas to remove NGLs, fractionate NGLs into purity products and market those products for a fee, transport natural gas and ultimately provide natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply sources and sell that natural gas to utilities, industrial consumers, other marketers and pipelines. We operate processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems mainly under a variety of fee-based arrangements. We provide a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. We also have crude oil and condensate terminal facilities that provide access for crude oil and condensate producers to premium markets. Our gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Our transmission pipelines primarily receive natural gas from our gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. We also have transmission lines that transport NGLs from east Texas and from our south Louisiana processing plants to our fractionators in south Louisiana. Our crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a fee, transport crude oil from a producer site to end users and other pipelines. 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 consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles in the United States of America (“GAAP”) for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation.

(b)
Adopted Accounting Standards

In March 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which simplifies several aspects related to the accounting for share-based payment transactions. Effective January 1, 2017, we adopted ASU 2016-09. We prospectively adopted the guidance that requires excess tax benefits and deficiencies be recognized on the income statement. The new cash flow statement guidance requires the presentation of excess tax benefits and deficiencies as an operating activity and the presentation of cash paid by an employer when directly withholding shares for tax-withholding purposes as a financing activity, and this treatment is consistent with our historical accounting treatment. Finally, we elected to estimate the number of awards that are expected to vest, which is consistent with our historical accounting treatment. The adoption of the new guidance did not materially affect the consolidated statement of operations for the three months ended March 31, 2017.
 
In January 2017, the FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350)—Simplifying the Test for Goodwill Impairment (“ASU 2017-04”). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in Accounting Standards Codification (“ASC”) 350, Intangibles - Goodwill and Other (“ASC 350”). As a result, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. In January 2017, we elected to early adopt ASU 2017-04, and the adoption had no impact on our consolidated financial statements. We will perform future goodwill impairment tests according to ASU 2017-04.

(c)    Accounting Standards to be Adopted in Future Periods

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842)—Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on the balance sheet by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements and lease term assessments including variable lease payment, discount rate and lease incentives. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018 including interim periods within those annual periods. Early adoption is permitted. Entities are required to adopt ASU 2016-02 using a modified retrospective transition. We are currently assessing the impact of adopting ASU 2016-02. This assessment includes the gathering and evaluation of our current lease contracts and the analysis of contracts that may contain lease components. While we cannot currently estimate the quantitative effect that ASU 2016-02 will have on our consolidated financial statements, the adoption of ASU 2016-02 will increase our asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that are currently classified as operating leases. In addition, there are industry-specific concerns with the implementation of ASU 2016-02, including the application of ASU 2016-02 to contracts involving easements/right-of-ways, which will require further evaluation before we are able to fully assess the impact on our consolidated financial statements.
 
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which established ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which we expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 will also require significantly expanded disclosures regarding the qualitative and quantitative information of our nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”), which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles, including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied using the modified retrospective or full retrospective transition methods, with early application permitted for annual reporting periods beginning after December 15, 2016. We plan to use the modified retrospective transition method and do not plan to early adopt ASC 606. We have aggregated and reviewed our contracts that are within the scope of ASC 606. Based on our evaluation to date, we do not anticipate this standard will have a material impact on our consolidated financial statements. We continue to evaluate the impacts ASC 606 will have on our disclosures.

(d)    Property, Plant & Equipment

Gain or Loss on Disposition. We recognize any gain or loss upon the disposition or retirement of property, plant and equipment in operating income in the consolidated statement of operations. For the three months ended March 31, 2017, we retired certain plant assets in the Permian Basin that were damaged by fire, which resulted in a loss on disposition of $5.1 million.

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. For the three months ended March 31, 2017, we recognized an impairment of $7.0 million, which related to the carrying values of right-of-ways that expired and a brine disposal well that will be abandoned.
Acquisition
Acquisition
(3) Acquisition

On January 7, 2016, we and ENLC acquired an 84% and 16% voting interest, respectively, in EnLink Oklahoma T.O. for approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The second installment of $250.0 million was paid on January 6, 2017, and the final installment of $250.0 million is due no later than January 7, 2018. The installment payables are valued net of discount within the total purchase price.

The first installment of approximately $1.02 billion was funded by (a) approximately $783.6 million in cash paid by us, which was primarily derived from the issuance of Series B Cumulative Convertible Preferred Units (“Preferred Units”), (b) 15,564,009 common units representing limited liability company interests in ENLC issued directly by ENLC and (c) approximately $22.2 million in cash paid by ENLC. The transaction was accounted for using the acquisition method.

The following table presents the consideration ENLK and ENLC paid and the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):
Consideration:
 
Cash
$
783.6

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

Contribution from ENLC
237.1

Total consideration
$
1,441.6

 
 
Purchase Price Allocation:
 
Assets acquired:
 
Current assets (including $12.8 million in cash)
$
23.0

Property, plant and equipment
406.1

Intangibles
1,051.3

Liabilities assumed:
 
Current liabilities
(38.8
)
Total identifiable net assets
$
1,441.6



The fair value of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. We recognized intangible assets related to customer relationships and determined their fair value using the income approach. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 15 years.

We incurred a total of $4.1 million of direct transaction costs, of which $3.6 million were recognized as expense for the three months ended March 31, 2016. These costs are included in general and administrative costs in the accompanying consolidated statements of operations.

For the period from January 7, 2016 to March 31, 2016, we recognized $27.3 million of revenues and $14.2 million of net loss related to the assets acquired.
Goodwill and Intangible Assets
Goodwill and Intangible Assets
(4) Goodwill and Intangible Assets

Goodwill

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The fair value of goodwill is based on inputs that are not observable in the market and thus represent Level 3 inputs. We evaluate goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.

We perform our goodwill assessments at the reporting unit level for all reporting units. We use a discounted cash flow analysis to perform the assessments. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples and estimated future cash flows including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, we incorporate current and historical market and financial information, among other factors. Impairment determinations involve significant assumptions and judgments and differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.

During February 2016, we determined that weakness in the overall energy sector, driven by low commodity prices, together with a decline in our unit price, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units. Based on this analysis, a goodwill impairment loss for our Texas and Crude and Condensate reporting units in the amount of $566.3 million was recognized in the first quarter of 2016 and is included as an impairment loss in the consolidated statement of operations for the three months ended March 31, 2016.We concluded that the fair value of our Oklahoma reporting unit exceeded its carrying value, and the amount of goodwill disclosed on the consolidated balance sheet associated with this reporting unit is recoverable. Therefore, no other goodwill impairment was identified or recorded for this reporting unit as a result of our goodwill impairment analysis.

During the first quarter of 2017, we elected to early adopt ASU 2017-04, which simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in ASC 350. Although no interim assessment was required for the first quarter of 2017, we will perform future goodwill impairment tests according to ASU 2017-04. For additional information, see Note 2—Significant Accounting Policies.

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

The following table represents our change in carrying value of intangible assets (in millions):
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount
Three Months Ended March 31, 2017
 
 
 
 
 
Customer relationships, beginning of period
$
1,795.8

 
$
(171.6
)
 
$
1,624.2

Amortization expense
—

 
(29.5
)
 
(29.5
)
Customer relationships, end of period
$
1,795.8

 
$
(201.1
)
 
$
1,594.7


 
The weighted average amortization period is 13.7 years. Amortization expense was approximately $29.5 million and $27.5 million for the three months ended March 31, 2017 and 2016, respectively.
 
The following table summarizes our estimated aggregate amortization expense for the next five years (in millions):
2017 (remaining)
$
88.4

2018
117.9

2019
117.9

2020
117.9

2021
117.9

Thereafter
1,034.7

Total
$
1,594.7

Related Party Transactions
Related Party Transactions
(5) Related Party Transactions
 
We engage in various transactions with Devon and other related parties. For the three months ended March 31, 2017 and 2016, Devon accounted for 14.9% and 21.0% of our revenues, respectively. We had an accounts receivable balance related to transactions with Devon of $106.9 million as of March 31, 2017 and $100.2 million as of December 31, 2016. Additionally, we had an accounts payable balance related to transactions with Devon of $11.8 million as of March 31, 2017 and $10.4 million as of December 31, 2016. Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with unrelated third parties. The amounts related to related party transactions are specified in the accompanying financial statements.
Long-Term Debt
Long-Term Debt
(6) Long-Term Debt

As of March 31, 2017 and December 31, 2016, long-term debt consisted of the following (in millions):
 
March 31, 2017
 
December 31, 2016
 
Outstanding Principal
 
Premium (Discount)
 
Long-Term Debt
 
Outstanding Principal
 
Premium (Discount)
 
Long-Term Debt
Partnership credit facility due 2020 (1)
$
330.0

 
$
—

 
$
330.0

 
$
120.0

 
$
—

 
$
120.0

2.70% Senior unsecured notes due 2019
400.0

 
(0.2
)
 
399.8

 
400.0

 
(0.3
)
 
399.7

7.125% Senior unsecured notes due 2022 (2)
162.5

 
15.2

 
177.7

 
162.5

 
16.0

 
178.5

4.40% Senior unsecured notes due 2024
550.0

 
2.4

 
552.4

 
550.0

 
2.5

 
552.5

4.15% Senior unsecured notes due 2025
750.0

 
(1.1
)
 
748.9

 
750.0

 
(1.1
)
 
748.9

4.85% Senior unsecured notes due 2026
500.0

 
(0.6
)
 
499.4

 
500.0

 
(0.7
)
 
499.3

5.60% Senior unsecured notes due 2044
350.0

 
(0.2
)
 
349.8

 
350.0

 
(0.2
)
 
349.8

5.05% Senior unsecured notes due 2045
450.0

 
(6.6
)
 
443.4

 
450.0

 
(6.6
)
 
443.4

Debt classified as long-term
$
3,492.5

 
$
8.9

 
$
3,501.4

 
$
3,282.5

 
$
9.6

 
$
3,292.1

Debt issuance cost (3)
 
 
 
 
(23.3
)
 
 
 
 
 
(24.1
)
Long-term debt, net of unamortized issuance cost
 
 
 
 
$
3,478.1

 
 
 
 
 
$
3,268.0

                                                           
(1)
Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.0% and 2.3% at March 31, 2017 and December 31, 2016, respectively.
(2)
On April 3, 2017, we issued notice to redeem our 7.125% senior unsecured notes due 2022 (the “2022 notes”). The 2022 notes will be redeemed on June 1, 2017 at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174.1 million.
(3)
Net of amortization of $9.2 million and $8.3 million at March 31, 2017 and December 31, 2016, respectively.

Credit Facility

We have a $1.5 billion unsecured revolving credit facility that matures on March 6, 2020 and includes a $500.0 million letter of credit subfacility. Under our credit facility, we are permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under our credit facility by an additional amount not to exceed $500.0 million and (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of our credit facility by one year on each occasion. Our credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (which is defined in our credit facility and includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If we consummate one or more acquisitions, in which the aggregate purchase price is $50.0 million or more, we can elect to increase the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

Borrowings under our credit facility bear interest at our option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.00% to 1.75%) 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 (ranging from zero percent to 0.75%). The applicable margins vary depending on our credit rating. If we breach certain covenants governing our credit facility, amounts outstanding under our credit facility, if any, may become due and payable immediately. At March 31, 2017, we were in compliance and expect to be in compliance with the covenants in our credit facility for at least the next twelve months.

As of March 31, 2017, there were $9.1 million in outstanding letters of credit and $330.0 million in outstanding borrowings under our credit facility, leaving approximately $1.2 billion available for future borrowing based on the borrowing capacity of $1.5 billion.

All other material terms and conditions of our credit facility are described in Part II, “Item 8. Financial Statements and Supplementary Data—Note 6” in our Annual Report on Form 10-K for the year ended December 31, 2016.
Partners Capital
Partners' Capital
(7) Partners' Capital
 
(a)
Issuance of Common Units
 
In November 2014, we entered into an Equity Distribution Agreement (the “BMO EDA”) with BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC (collectively, the “Sales Agents”) to sell up to $350.0 million in aggregate gross sales of our common units representing our limited partner interests from time to time through an “at the market” equity offering program. We may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. We have no obligation to sell any of the common units under the BMO EDA and may at any time suspend solicitation and offers under the BMO EDA. For the three months ended March 31, 2017, we sold an aggregate of approximately 3.0 million common units under the BMO EDA, generating proceeds of approximately $55.2 million (net of approximately $0.6 million of commissions). We used the net proceeds for general partnership purposes. As of March 31, 2017,
approximately $92.0 million of gross common unit issuances remain available under the BMO EDA.
 
(b)
Distributions
 
Unless restricted by the terms of our credit facility and/or the indentures governing our unsecured senior notes, we 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. Our general partner is not entitled to its general partner or incentive distributions with respect to the Preferred Units until such units are converted to common units.
 
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 the partnership agreement. Under the quarterly incentive distribution provisions, 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.

Distributions on the Preferred Units for the three months ended December 31, 2016 were paid-in kind through the issuance of 1,130,131 additional Preferred Units on February 13, 2017. A distribution on the Preferred Units was declared for the three months ended March 31, 2017, which will result in the issuance of 1,154,147 additional Preferred Units on May 12, 2017.

A summary of the distribution activity relating to the common units for the three months ended March 31, 2017 and 2016, respectively, is provided below:
Declaration period
 
Distribution/unit
 
Date paid/payable
2017
 
 
 
 
Fourth Quarter of 2016
 
$
0.39

 
February 13, 2017
First Quarter of 2017
 
$
0.39

 
May 12, 2017
 
 
 
 
 
2016
 
 
 
 
Fourth Quarter of 2015
 
$
0.39

 
February 11, 2016
First Quarter of 2016
 
$
0.39

 
May 12, 2016

(c)
Earnings per Unit and Dilution Computations
 
As required under ASC 260, Earnings Per Share, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities for earnings per unit calculations. The following table reflects the computation of basic and diluted earnings per limited partner units for the periods presented (in millions, except per unit amounts):
 
Three Months Ended March 31,
 
2017
 
2016
Limited partners’ interest in net loss
$
(9.3
)
 
$
(567.2
)
Distributed earnings allocated to:
 
 
 
Common units (1)
$
134.0

 
$
126.9

Unvested restricted units (1)
0.9

 
0.8

Total distributed earnings
$
134.9

 
$
127.7

Undistributed loss allocated to:
 
 
 
Common units
$
(143.2
)
 
$
(690.7
)
Unvested restricted units
(1.0
)
 
(4.2
)
Total undistributed loss
$
(144.2
)
 
$
(694.9
)
Net loss allocated to:
 
 
 
Common units
$
(9.2
)
 
$
(563.8
)
Unvested restricted units
(0.1
)
 
(3.4
)
Total limited partners’ interest in net loss
$
(9.3
)
 
$
(567.2
)
Basic and diluted net loss per unit:
 
 
 
Basic
$
(0.03
)
 
$
(1.74
)
Diluted
$
(0.03
)
 
$
(1.74
)
                                                           
(1)
For the three months ended March 31, 2017 and 2016, represents a declared distribution of $0.39 per unit payable May 12, 2017 and a distribution of $0.39 per unit paid May 12, 2016, respectively.

The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the periods presented (in millions): 
 
Three Months Ended March 31,
 
2017
 
2016
Basic weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
343.6

 
325.2

Weighted average Class C Common Units outstanding
—

 
7.2

Total weighted average limited partner common units outstanding
343.6

 
332.4

 
 
 
 
Diluted weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
343.6

 
332.4

Dilutive effect of restricted units issued
—

 
—

Total weighted average limited partner diluted common units outstanding
343.6

 
332.4


 
All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the periods presented. All common unit equivalents were antidilutive for the three months ended March 31, 2017 and 2016 because the limited partners were allocated a net loss.

Net income is allocated to the General Partner in an amount equal to its incentive distribution rights as described in (b) above. The General Partner’s share of net income consists of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units, the percentage interest of our net income adjusted for ENLC’s unit-based compensation specifically allocated to our General Partner. The net income allocated to the General Partner is as follows (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Income allocation for incentive distributions
$
14.7

 
$
13.8

Unit-based compensation attributable to ENLC’s restricted units
(8.8
)
 
(4.0
)
General partner share of net income (loss)
—

 
(2.4
)
General partner interest in net income
$
5.9

 
$
7.4

Asset Retirement Obligations
Asset Retirement Obligation
(8) Asset Retirement Obligations

The schedule below summarizes the changes in our asset retirement obligations (in millions):

Three Months Ended March 31, 2017
 
Balance, beginning of period
$
13.5

Accretion expense
0.2

Balance, end of period
$
13.7



Asset retirement obligations of $13.7 million and $13.5 million were included in “Asset retirement obligations” as non-current liabilities on the consolidated balance sheets as of March 31, 2017 and December 31, 2016, respectively.
Investment in Unconsolidated Affiliates
Investment in Unconsolidated Affiliates
(9) Investment in Unconsolidated Affiliates
 
Our unconsolidated investments consisted of:

•
a contractual right to the economic benefits and burdens associated with Devon’s 38.75% ownership interest in Gulf Coast Fractionators (“GCF”) at March 31, 2017 and December 31, 2016;

•
an approximate 30.0% ownership in Cedar Cove Midstream LLC (“Cedar Cove JV”) at March 31, 2017 and December 31, 2016. On November 9, 2016, we formed the Cedar Cove JV with Kinder Morgan, Inc., which consists of gathering and compression assets in Blaine County, Oklahoma, the heart of the Sooner Trend Anadarko Basin Canadian and Kingfisher Counties play;

•
an approximate 31.0% common unit ownership interest in Howard Energy Partners (“HEP”) at December 31, 2016. In December 2016, we entered into an agreement to sell our ownership interest in HEP. We finalized the sale in the first quarter of 2017 and received net proceeds of $189.7 million.

The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):
 
Gulf Coast
Fractionators
 
Howard Energy Partners
 
Cedar Cove JV
 
Total
Three Months Ended
 
 
 
 
 
 
 
March 31, 2017
 
 
 
 
 
 
 
Contributions
$
—

 
—

 
6.0

 
$
6.0

Distributions
$
2.7

 
—

 
0.2

 
$
2.9

Equity in income (loss) (1)
$
4.0

 
(3.4
)
 
0.1

 
$
0.7

 
 
 
 
 
 
 
 
March 31, 2016
 
 
 
 
 
 
 
Contributions
$
—

 
7.1

 
—

 
$
7.1

Distributions
$
3.0

 
6.2

 
—

 
$
9.2

Equity in loss
$
(1.7
)
 
(0.7
)
 
—

 
$
(2.4
)
(1)
Includes a loss of $3.4 million for the three months ended March 31, 2017 from the sale of HEP in March 2017.

The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2017 and December 31, 2016 (in millions): 
 
March 31, 2017
 
December 31, 2016
Gulf Coast Fractionators
$
49.8

 
$
48.5

Howard Energy Partners
—

 
193.1

Cedar Cove JV
34.7

 
28.8

Total investment in unconsolidated affiliates
$
84.5

 
$
270.4

Employee Incentive Plans
Employee Incentive Plans
(10) Employee Incentive Plans
 
(a)
Long-Term Incentive Plans
 
We and ENLC each have similar unit-based compensation payment plans for officers and employees. We grant unit-based awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”), and ENLC grants unit-based awards under the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “LLC Plan”).

We account for unit-based compensation in accordance with ASC 718, Stock Compensation (“ASC 718”), which requires that compensation related to all unit-based awards be recognized in the consolidated financial statements. Unit-based compensation cost is recognized as expense over each award’s requisite service period with a corresponding increase to equity or liability based on the terms of each award and the appropriate accounting treatment under ASC 718. Unit-based compensation associated with ENLC’s unit-based compensation plan awarded to our officers and employees is recorded by us since ENLC has no substantial or managed operating activities other than its interests in us and EnLink Oklahoma T.O. Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Cost of unit-based compensation charged to general and administrative expense
$
14.3

 
$
6.2

Cost of unit-based compensation charged to operating expense
5.0

 
1.7

Total unit-based compensation expense
$
19.3

 
$
7.9






(b)
EnLink Midstream Partners, LP Restricted Incentive Units
 
ENLK restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of common units on such date. A summary of the restricted incentive unit activity for the three months ended March 31, 2017 is provided below:
 
 
Three Months Ended
March 31, 2017
EnLink Midstream Partners, LP Restricted Incentive Units:
 
Number of Units
 
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period
 
2,024,820

 
$
19.05

Granted (1)
 
822,865

 
18.46

Vested (1)(2)
 
(795,188
)
 
25.84

Forfeited
 
(6,997
)
 
16.87

Non-vested, end of period
 
2,045,500

 
$
16.18

Aggregate intrinsic value, end of period (in millions)
 
$
37.4

 
 

                                                           
(1)
Restricted incentive units were issued in the first quarter of 2017 to officers and other employees. These restricted incentive units typically vest at the end of three years. In March 2017, we issued 262,288 restricted incentive units with a fair value of $5.1 million to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
(2)
Vested units include 258,145 units withheld for payroll taxes paid on behalf of employees.
 
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2017 and 2016, respectively, is provided below (in millions):
 
 
Three Months Ended March 31,
EnLink Midstream Partners, LP Restricted Incentive Units:
 
2017
 
2016
Aggregate intrinsic value of units vested
 
$
15.3

 
$
3.7

Fair value of units vested
 
$
20.5

 
$
9.0


 
As of March 31, 2017, there was $20.7 million of unrecognized compensation cost related to non-vested restricted incentive units for officers and employees. That cost is expected to be recognized over a weighted-average period of 2.0 years.
 
(c)
EnLink Midstream Partners, LP Performance Units
 
For the three months ended March 31, 2017, our general partner and the managing member of ENLC granted performance awards under the GP Plan and the LLC Plan, respectively. The performance award agreements provide that the vesting of restricted incentive units granted thereunder is dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding us and ENLC (collectively, “EnLink”), on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of our and ENLC’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

 At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200 percent of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of our common units and the designated peer group securities; (iii) an estimated ranking of us among the designated peer group; and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of approximately three years.     
The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:
 
EnLink Midstream Partners, LP Performance Units:
 
March 2017
Beginning TSR Price
 
$
17.55

Risk-free interest rate
 
1.62
%
Volatility factor
 
43.94
%
Distribution yield
 
8.7
%


The following table presents a summary of the performance units: 
 
 
Three Months Ended
March 31, 2017
EnLink Midstream Partners, LP Performance Units:
 
Number of Units
 
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period
 
408,637

 
$
11.53

Granted
 
176,648

 
25.73

Forfeited
 
—

 
—

Non-vested, end of period
 
585,285

 
$
15.82

Aggregate intrinsic value, end of period (in millions)
 
$
10.7

 
 


 
As of March 31, 2017, there was $8.0 million of unrecognized compensation expense that related to non-vested Partnership performance units. That cost is expected to be recognized over a weighted-average period of 2.3 years.
 
(d)
EnLink Midstream, LLC Restricted Incentive Units
 
ENLC restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of the common units on such date. A summary of the restricted incentive unit activity for the three months ended March 31, 2017 is provided below:
 
 
Three Months Ended
March 31, 2017
EnLink Midstream, LLC Restricted Incentive Units:
 
Number of Units
 
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period
 
1,897,298

 
$
19.96

Granted (1)
 
781,842

 
19.29

Vested (1)(2)
 
(726,692
)
 
28.07

Forfeited
 
(6,706
)
 
17.58

Non-vested, end of period
 
1,945,742

 
$
16.67

Aggregate intrinsic value, end of period (in millions)
 
$
37.7

 
 

                                                           
(1)
Restricted incentive units were issued in the first quarter of 2017 to officers and other employees. These restricted incentive units typically vest at the end of three years. In March 2017, ENLC issued 258,606 restricted incentive units with a fair value of $5.0 million to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
(2)
Vested units include 224,709 units withheld for payroll taxes paid on behalf of employees.

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2017 and 2016, respectively, are provided below (in millions):
 
 
Three Months Ended
March 31,
EnLink Midstream, LLC Restricted Incentive Units:
 
2017
 
2016
Aggregate intrinsic value of units vested
 
$
14.3

 
$
3.8

Fair value of units vested
 
$
20.4

 
$
11.8


 
As of March 31, 2017, there was $20.2 million of unrecognized compensation costs related to non-vested ENLC restricted incentive units for directors, officers and employees. The cost is expected to be recognized over a weighted-average period of 2.0 years.
 
(e)
EnLink Midstream, LLC’s Performance Units
 
For the three months ended March 31, 2017, ENLC granted performance awards under the LLC Plan. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200% of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC’s common units and the designated peer group securities; (iii) an estimated ranking of ENLC among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of approximately three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:

EnLink Midstream, LLC Performance Units:
 
March 2017
Beginning TSR Price
 
$
18.29

Risk-free interest rate
 
1.62
%
Volatility factor
 
52.07
%
Distribution yield
 
5.4
%


 The following table presents a summary of the performance units:
 
 
Three Months Ended
March 31, 2017
EnLink Midstream, LLC Performance Units:
 
Number of Units
 
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period
 
384,264

 
$
19.30

Granted
 
164,575

 
28.77

Forfeited
 
—

 
—

Non-vested, end of period
 
548,839

 
$
22.14

Aggregate intrinsic value, end of period (in millions)
 
$
10.6

 
 



As of March 31, 2017, there was $8.1 million of unrecognized compensation expense that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 2.3 years.
Derivatives
Derivatives
(11) Derivatives
 
Commodity Swaps
 
We manage our exposure to changes 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 crude, condensate, natural gas and NGLs. We do not designate transactions as cash flow or fair value hedges for hedge accounting treatment under ASC 815, Derivatives and Hedging. Therefore, changes in the fair value of our derivatives are recorded in revenue in the period incurred. In addition, our risk management policy does not allow us to take speculative positions with our derivative contracts.

We commonly enter into index (float-for-float) or fixed-for-float swaps in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, NGLs and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. They are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate and crude, fixed-for-float swaps are used to protect cash flows against price fluctuations: (1) where we receive a percentage of liquids as a fee for processing third-party gas or where we receive a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation components of our business and (3) where we are mitigating the price risk for product held in inventory or storage.
 
The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Change in fair value of derivatives
$
5.3

 
$
(6.0
)
Realized gain (loss) on derivatives
(2.5
)
 
5.6

Gain (loss) on derivative activity
$
2.8

 
$
(0.4
)

 
The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions):
 
March 31, 2017
 
December 31, 2016
Fair value of derivative assets — current
$
2.1

 
$
1.3

Fair value of derivative assets — long-term
0.1

 
—

Fair value of derivative liabilities — current
(2.9
)
 
(7.6
)
Fair value of derivative liabilities — long-term
(0.3
)
 
—

Net fair value of derivatives
$
(1.0
)
 
$
(6.3
)

 
Assets and liabilities related to our derivative contracts are included in the fair value of derivative assets and liabilities and the change in fair value of these contracts are recorded at net as a gain (loss) on derivative activity in the consolidated statements of operations. We estimate the fair value of all of our derivative contracts using actively-quoted prices.
 
Set forth below is the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at March 31, 2017 (in millions). The remaining term of the contracts extend no later than October 2018.
 
 
 
 
March 31, 2017
Commodity
 
Instruments
 
Unit
 
Volume
 
Fair Value
NGL (short contracts)
 
Swaps
 
Gallons
 
(32.9
)
 
$
(0.3
)
NGL (long contracts)
 
Swaps
 
Gallons
 
12.8

 
(0.2
)
Natural Gas (short contracts)
 
Swaps
 
MMBtu
 
(15.4
)
 
(0.3
)
Natural Gas (long contracts)
 
Swaps
 
MMBtu
 
15.1

 
(0.4
)
Condensate (short contracts)
 
Swaps
 
MMbbls
 
—

 
0.1

Condensate (long contracts)
 
Swaps
 
MMbbls
 
—

 
0.1

Total fair value of derivatives
 
 
 
 
 
 

 
$
(1.0
)

 
On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. We have entered into Master International Swaps and Derivatives Association Agreements (“ISDAs”) that allow for netting of swap contract receivables and payables in the event of default by either party. If our counterparties failed to perform under existing swap contracts, our maximum loss of $2.2 million as of March 31, 2017 would be reduced to $0.4 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs.
Fair Value Measurements
Fair Value Measurements
(12) Fair Value Measurements
 
ASC 820, Fair Value Measurements and Disclosures (“ASC 820”), sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under 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.
 
ASC 820 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.
 
Our derivative contracts primarily consist of commodity swap contracts, which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly-quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy.
 
Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in millions):
 
Level 2
 
March 31, 2017
 
December 31, 2016
Commodity Swaps (1)
$
(1.0
)
 
$
(6.3
)
Total
$
(1.0
)
 
$
(6.3
)
                                                           
(1)
The fair values of derivative contracts included in assets or liabilities for risk management activities represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.

Fair Value of Financial Instruments
 
The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):
 
March 31, 2017
 
December 31, 2016
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Long-term debt (1)
$
3,478.1

 
$
3,499.6

 
$
3,268.0

 
$
3,225.8

Installment Payables
$
230.1

 
$
232.9

 
$
473.2

 
$
476.6

Obligations under capital lease
$
5.1

 
$
4.3

 
$
6.6

 
$
6.1

                                                           
(1)
The carrying values of long-term debt are reduced by debt issuance costs of $23.3 million and $24.1 million at March 31, 2017 and December 31, 2016, respectively. The respective fair values do not factor in debt issuance costs.

The carrying amounts of our cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.
 
We had $330.0 million and $120.0 million in outstanding borrowings under our revolving credit facility as of March 31, 2017 and December 31, 2016, respectively. As borrowings under the credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of March 31, 2017 and December 31, 2016, we had total borrowings under senior unsecured notes of $3.1 billion, maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. The fair values of all senior unsecured notes and installment payables as of March 31, 2017 and December 31, 2016 were based on Level 2 inputs from third-party market quotations. The fair values of obligations under capital leases were calculated using Level 2 inputs from third-party banks.
Commitments and Contingencies
Commitments and Contingencies
(13) Commitments and Contingencies
 
(a)
Severance and Change in Control Agreements
 
Certain members of our management are parties to severance and change of control agreements with the Operating Partnership. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individuals from, among other things, competing with the General Partner or its affiliates during his or her employment. In addition, the severance and change of control agreements prohibit subject individuals from, among other things, disclosing confidential information about the General Partner or its affiliates or interfering with a client or customer of the General Partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment.
 
(b)
Environmental Issues
 
The operation of pipelines, plants and other facilities for the gathering, processing, transmitting or disposing of natural gas, NGLs, crude oil, condensate, brine and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner, partner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.

In the third quarter of 2016, in connection with the transition to our operational control of E2 Appalachian Compression, LLC and in preparation to commence operational control of E2 Ohio Compression, LLC, we discovered instances of noncompliance with air regulations and permits. This noncompliance was self-reported to the Ohio Environmental Protection Agency (“OEPA”), resulting in the issuance of notices of violations (“NOVs”). We have taken appropriate measures to achieve compliance with applicable requirements, and we are working with the OEPA on a settlement agreement for the NOVs, which we believe will not include any fines or penalties that would be material to our results of operations. On July 29, 2016, after concluding a multi-year internal environmental compliance assessment of our Louisiana operations, we commenced discussions with the Louisiana Department of Environmental Quality (“LDEQ”) relating to a global settlement to resolve environmental noncompliance discovered or investigated during our assessment involving several of our Louisiana facilities and notices of potential violation and NOVs received from the LDEQ. We have taken appropriate measures to resolve all instances of noncompliance, and we continue to work with the LDEQ with respect to the proposed global settlement, which we believe will not include any fines or penalties that would be material to our results of operations. Lastly, we continue to work with Pipeline and Hazardous Materials Safety Administration regarding the notice of potential violation discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016.
 
(c)
Litigation Contingencies
 
We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.

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

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

In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans, but was removed to the United States District Court for the Eastern District of Louisiana. The amount of damages is unspecified. Our subsidiary, EnLink LIG, LLC, is one of the named defendants as the owner of pipelines in the area. On February 13, 2015, the court granted defendants’ joint motion to dismiss and dismissed the plaintiff’s claims with prejudice. Plaintiffs have appealed the matter to the United States Court of Appeals for the Fifth Circuit. On March 3, 2017, the Court of Appeals affirmed the district court’s dismissal of the plaintiff’s claims. On March 17, 2017, the plaintiff filed a petition for rehearing en banc. On April 12, 2017, the Court of Appeals denied the plaintiffs petition for rehearing. We intend to continue vigorously defending the case. The success of the plaintiffs’ appeal as well as our costs and legal exposure, if any, related to the lawsuit are not currently determinable.

We own and operate a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs, resulting in damage to certain of our facilities. We are seeking to recover our losses from responsible parties. We sued Texas Brine Company, LLC (“Texas Brine”), the operator of a failed cavern in the area and its insurers, seeking recovery for these losses, as well as other parties we alleged contributed to the formation of the sinkhole. In August 2014, we received a partial settlement with respect to our claims in the amount of $6.1 million. In March 2017, we received an additional settlement payment of $17.5 million, which was recognized in “Gain on litigation settlement” in the consolidated statement of operations for the three months ended March 31, 2017. Additional claims remain outstanding. We also filed a claim with our insurers, which our insurers denied. We disputed the denial and sued our insurers. We cannot give assurance that we will be able to fully recover our losses through insurance recovery or claims against responsible parties.

In June 2014, a group of landowners in Assumption Parish, Louisiana added our subsidiary, EnLink Processing Services, LLC, as a defendant in a pending lawsuit in the 23rd Judicial Court, Assumption Parish, Louisiana they had filed against other defendants relating to claims arising from the Bayou Corne Sinkhole. Plaintiffs alleged that EnLink Processing Services, LLC’s negligence contributed to the formation of the sinkhole. The amount of damages was unspecified. EnLink Processing Services, LLC reached a settlement with the plaintiffs in February 2017, funded by EnLink Processing Services, LLC’s insurance carriers. The plaintiffs’ claims against EnLink Processing Services, LLC were dismissed with prejudice in March 2017. 
Segment Information
Segment Information
(14) Segment Information
 
Identification of the majority of our operating segments is based principally upon geographic regions served. Our reportable segments consist of the following: natural gas gathering, processing, transmission and fractionation operations located in north Texas and the Permian Basin in west Texas (“Texas”), the pipelines and processing plants located in Louisiana and NGL assets located in south Louisiana (“Louisiana”), natural gas gathering and processing operations located throughout Oklahoma (“Oklahoma”) and crude rail, truck, pipeline and barge facilities in west Texas, south Texas, Louisiana and the Ohio River Valley (“Crude and Condensate”). Operating activity for intersegment eliminations is shown in the Corporate segment. Our sales are derived from external domestic customers. We evaluate the performance of our operating segments based on operating revenues and segment profits.
 
Corporate assets consist primarily of cash, property and equipment, including software, for general corporate support, debt financing costs and unconsolidated affiliate investments in GCF and the Cedar Cove JV. As of December 31, 2016, our Corporate assets included our unconsolidated affiliate investment in HEP. In December 2016, we entered into an agreement to sell our ownership interest in HEP, and we finalized the sale during the first quarter of 2017.


Summarized financial information for our reportable segments is shown in the following table (in millions):
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
Three Months Ended March 31, 2017
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
85.1

 
$
544.5

 
$
14.5

 
$
345.9

 
$
—

 
$
990.0

Product sales—related parties
106.5

 
10.2

 
64.4

 
0.8

 
(139.2
)
 
42.7

Midstream services
27.8

 
53.1

 
27.9

 
18.6

 
—

 
127.4

Midstream services—related parties
105.1

 
29.0

 
49.4

 
3.3

 
(27.8
)
 
159.0

Cost of sales
(179.2
)
 
(564.7
)
 
(88.7
)
 
(336.7
)
 
167.0

 
(1,002.3
)
Operating expenses
(43.9
)
 
(25.4
)
 
(14.1
)
 
(20.7
)
 
—

 
(104.1
)
Gain on derivative activity
—

 
—

 
—

 
—

 
2.8

 
2.8

Segment profit
$
101.4

 
$
46.7

 
$
53.4

 
$
11.2

 
$
2.8

 
$
215.5

Depreciation and amortization
$
(49.8
)
 
$
(28.1
)
 
$
(36.5
)
 
$
(11.5
)
 
$
(2.4
)
 
$
(128.3
)
Goodwill
$
232.0

 
$
—

 
$
190.3

 
$
—

 
$
—

 
$
422.3

Capital expenditures
$
28.3

 
$
32.7

 
$
140.7

 
$
37.4

 
$
9.0

 
$
248.1

 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2016
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
62.5

 
$
287.7

 
$
7.8

 
$
230.5

 
$
—

 
$
588.5

Product sales—related parties
37.3

 
7.4

 
10.6

 
0.2

 
(31.0
)
 
24.5

Midstream services
27.4

 
55.2

 
15.1

 
16.8

 
—

 
114.5

Midstream services—related parties
110.3

 
12.7

 
45.0

 
5.2

 
(10.6
)
 
162.6

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

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

 
(98.2
)
Loss on derivative activity
—

 
—

 
—

 
—

 
(0.4
)
 
(0.4
)
Segment profit (loss)
$
106.9

 
$
37.6

 
$
46.4

 
$
14.8

 
$
(0.4
)
 
$
205.3

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

 
$
—

 
$
(93.2
)
 
$
—

 
$
(566.3
)
Goodwill
$
230.4

 
$
—

 
$
190.3

 
$
—

 
$
—

 
$
420.7

Capital expenditures
$
23.3

 
$
22.7

 
$
69.2

 
$
3.3

 
$
1.9

 
$
120.4

 
The table below represents information about segment assets as of March 31, 2017 and December 31, 2016 (in millions):
Segment Identifiable Assets:
March 31, 2017
 
December 31, 2016
Texas
$
3,132.6

 
$
3,142.6

Louisiana
2,312.7

 
2,349.3

Oklahoma
2,629.8

 
2,524.5

Crude and Condensate
861.9

 
836.8

Corporate
122.4

 
300.2

Total identifiable assets
$
9,059.4

 
$
9,153.4


 
The following table reconciles the segment profits reported above to the operating income (loss) as reported in the consolidated statements of operations (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Segment profits
$
215.5

 
$
205.3

General and administrative expenses
(35.0
)
 
(33.2
)
Gain (loss) on disposition of assets
(5.1
)
 
0.2

Depreciation and amortization
(128.3
)
 
(121.9
)
Impairments
(7.0
)
 
(566.3
)
Gain on litigation settlement
17.5

 
—

Operating income (loss)
$
57.6

 
$
(515.9
)
Supplemental Cash Flow Information
Supplemental Cash Flow Information
(15) Supplemental Cash Flow Information
 
The following schedule summarizes non-cash financing activities for the periods presented (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Non-cash financing activities:
 
 
 
Installment payable, net of discount of $79.1 million (1)
$
—

 
$
420.9

Contribution from ENLC (2)
—

 
237.1

                                                           
(1)
We incurred installment purchase obligations, net of discount, payable to the seller in connection with the EnLink Oklahoma T.O. assets. We paid the first installment on January 6, 2017 and will pay the final installment no later than January 7, 2018. See “Note 3—Acquisition” for further discussion.
(2)
Contribution from ENLC in connection with the acquisition of EnLink Oklahoma T.O. assets. See “Note 3—Acquisition” for further discussion.
Other Information
Other Information
(16) Other Information

The following table presents additional detail for other current liabilities, which consists of the following (in millions):
 
March 31, 2017
 
December 31, 2016
Accrued interest
$
58.3

 
$
34.2

Accrued wages and benefits, including taxes
9.2

 
19.0

Accrued ad valorem taxes
13.0

 
23.5

Capital expenditure accruals
56.3

 
64.6

Onerous performance obligations
15.8

 
15.9

Other
61.2

 
59.8

Other current liabilities
$
213.8

 
$
217.0

Subsequent Events
Subsequent Events
(17) Subsequent Event

On April 3, 2017, we issued a notice to redeem our 2022 notes. The 2022 notes will be redeemed on June 1, 2017 at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174.1 million, and we expect to recognize a gain on extinguishment of debt of approximately $3.2 million for the three months ending June 30, 2017.
Significant Accounting Policies (Policies)
Basis of Presentation 
Basis of Presentation

The accompanying consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles in the United States of America (“GAAP”) for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation.
Adopted Accounting Standards; Accounting Standards to be Adopted in Future Periods 
Adopted Accounting Standards

In March 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which simplifies several aspects related to the accounting for share-based payment transactions. Effective January 1, 2017, we adopted ASU 2016-09. We prospectively adopted the guidance that requires excess tax benefits and deficiencies be recognized on the income statement. The new cash flow statement guidance requires the presentation of excess tax benefits and deficiencies as an operating activity and the presentation of cash paid by an employer when directly withholding shares for tax-withholding purposes as a financing activity, and this treatment is consistent with our historical accounting treatment. Finally, we elected to estimate the number of awards that are expected to vest, which is consistent with our historical accounting treatment. The adoption of the new guidance did not materially affect the consolidated statement of operations for the three months ended March 31, 2017.
 
In January 2017, the FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350)—Simplifying the Test for Goodwill Impairment (“ASU 2017-04”). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test referenced in Accounting Standards Codification (“ASC”) 350, Intangibles - Goodwill and Other (“ASC 350”). As a result, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. In January 2017, we elected to early adopt ASU 2017-04, and the adoption had no impact on our consolidated financial statements. We will perform future goodwill impairment tests according to ASU 2017-04.

(c)    Accounting Standards to be Adopted in Future Periods

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842)—Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on the balance sheet by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard. Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements and lease term assessments including variable lease payment, discount rate and lease incentives. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018 including interim periods within those annual periods. Early adoption is permitted. Entities are required to adopt ASU 2016-02 using a modified retrospective transition. We are currently assessing the impact of adopting ASU 2016-02. This assessment includes the gathering and evaluation of our current lease contracts and the analysis of contracts that may contain lease components. While we cannot currently estimate the quantitative effect that ASU 2016-02 will have on our consolidated financial statements, the adoption of ASU 2016-02 will increase our asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that are currently classified as operating leases. In addition, there are industry-specific concerns with the implementation of ASU 2016-02, including the application of ASU 2016-02 to contracts involving easements/right-of-ways, which will require further evaluation before we are able to fully assess the impact on our consolidated financial statements.
 
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which established ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which we expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 will also require significantly expanded disclosures regarding the qualitative and quantitative information of our nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”), which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles, including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied using the modified retrospective or full retrospective transition methods, with early application permitted for annual reporting periods beginning after December 15, 2016. We plan to use the modified retrospective transition method and do not plan to early adopt ASC 606. We have aggregated and reviewed our contracts that are within the scope of ASC 606. Based on our evaluation to date, we do not anticipate this standard will have a material impact on our consolidated financial statements. We continue to evaluate the impacts ASC 606 will have on our disclosures.
Property, Plant and Equipment 
Property, Plant & Equipment

Gain or Loss on Disposition. We recognize any gain or loss upon the disposition or retirement of property, plant and equipment in operating income in the consolidated statement of operations. For the three months ended March 31, 2017, we retired certain plant assets in the Permian Basin that were damaged by fire, which resulted in a loss on disposition of $5.1 million.

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.
Acquisition (Tables)
Schedule of Consideration and Fair Value of Identified Assets Received and Liabilities Assumed
The following table presents the consideration ENLK and ENLC paid and the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):
Consideration:
 
Cash
$
783.6

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

Contribution from ENLC
237.1

Total consideration
$
1,441.6

 
 
Purchase Price Allocation:
 
Assets acquired:
 
Current assets (including $12.8 million in cash)
$
23.0

Property, plant and equipment
406.1

Intangibles
1,051.3

Liabilities assumed:
 
Current liabilities
(38.8
)
Total identifiable net assets
$
1,441.6

Goodwill and Intangible Assets (Tables)
Summary of Change in Carrying Value 
The following table represents our change in carrying value of intangible assets (in millions):
 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount
Three Months Ended March 31, 2017
 
 
 
 
 
Customer relationships, beginning of period
$
1,795.8

 
$
(171.6
)
 
$
1,624.2

Amortization expense
—

 
(29.5
)
 
(29.5
)
Customer relationships, end of period
$
1,795.8

 
$
(201.1
)
 
$
1,594.7

Summary of Estimated Aggregate Amortization Expense 
The following table summarizes our estimated aggregate amortization expense for the next five years (in millions):
2017 (remaining)
$
88.4

2018
117.9

2019
117.9

2020
117.9

2021
117.9

Thereafter
1,034.7

Total
$
1,594.7

Long-Term Debt (Tables)
Schedule of Long-Term Debt
As of March 31, 2017 and December 31, 2016, long-term debt consisted of the following (in millions):
 
March 31, 2017
 
December 31, 2016
 
Outstanding Principal
 
Premium (Discount)
 
Long-Term Debt
 
Outstanding Principal
 
Premium (Discount)
 
Long-Term Debt
Partnership credit facility due 2020 (1)
$
330.0

 
$
—

 
$
330.0

 
$
120.0

 
$
—

 
$
120.0

2.70% Senior unsecured notes due 2019
400.0

 
(0.2
)
 
399.8

 
400.0

 
(0.3
)
 
399.7

7.125% Senior unsecured notes due 2022 (2)
162.5

 
15.2

 
177.7

 
162.5

 
16.0

 
178.5

4.40% Senior unsecured notes due 2024
550.0

 
2.4

 
552.4

 
550.0

 
2.5

 
552.5

4.15% Senior unsecured notes due 2025
750.0

 
(1.1
)
 
748.9

 
750.0

 
(1.1
)
 
748.9

4.85% Senior unsecured notes due 2026
500.0

 
(0.6
)
 
499.4

 
500.0

 
(0.7
)
 
499.3

5.60% Senior unsecured notes due 2044
350.0

 
(0.2
)
 
349.8

 
350.0

 
(0.2
)
 
349.8

5.05% Senior unsecured notes due 2045
450.0

 
(6.6
)
 
443.4

 
450.0

 
(6.6
)
 
443.4

Debt classified as long-term
$
3,492.5

 
$
8.9

 
$
3,501.4

 
$
3,282.5

 
$
9.6

 
$
3,292.1

Debt issuance cost (3)
 
 
 
 
(23.3
)
 
 
 
 
 
(24.1
)
Long-term debt, net of unamortized issuance cost
 
 
 
 
$
3,478.1

 
 
 
 
 
$
3,268.0

                                                           
(1)
Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.0% and 2.3% at March 31, 2017 and December 31, 2016, respectively.
(2)
On April 3, 2017, we issued notice to redeem our 7.125% senior unsecured notes due 2022 (the “2022 notes”). The 2022 notes will be redeemed on June 1, 2017 at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174.1 million.
(3)
Net of amortization of $9.2 million and $8.3 million at March 31, 2017 and December 31, 2016, respectively.
Partners Capital (Tables)
Summary of Distribution Activity 
A summary of the distribution activity relating to the common units for the three months ended March 31, 2017 and 2016, respectively, is provided below:
Declaration period
 
Distribution/unit
 
Date paid/payable
2017
 
 
 
 
Fourth Quarter of 2016
 
$
0.39

 
February 13, 2017
First Quarter of 2017
 
$
0.39

 
May 12, 2017
 
 
 
 
 
2016
 
 
 
 
Fourth Quarter of 2015
 
$
0.39

 
February 11, 2016
First Quarter of 2016
 
$
0.39

 
May 12, 2016

Computation of Basic and Diluted Earnings per Limited Partner Units 
The following table reflects the computation of basic and diluted earnings per limited partner units for the periods presented (in millions, except per unit amounts):
 
Three Months Ended March 31,
 
2017
 
2016
Limited partners’ interest in net loss
$
(9.3
)
 
$
(567.2
)
Distributed earnings allocated to:
 
 
 
Common units (1)
$
134.0

 
$
126.9

Unvested restricted units (1)
0.9

 
0.8

Total distributed earnings
$
134.9

 
$
127.7

Undistributed loss allocated to:
 
 
 
Common units
$
(143.2
)
 
$
(690.7
)
Unvested restricted units
(1.0
)
 
(4.2
)
Total undistributed loss
$
(144.2
)
 
$
(694.9
)
Net loss allocated to:
 
 
 
Common units
$
(9.2
)
 
$
(563.8
)
Unvested restricted units
(0.1
)
 
(3.4
)
Total limited partners’ interest in net loss
$
(9.3
)
 
$
(567.2
)
Basic and diluted net loss per unit:
 
 
 
Basic
$
(0.03
)
 
$
(1.74
)
Diluted
$
(0.03
)
 
$
(1.74
)
                                                           
(1)
For the three months ended March 31, 2017 and 2016, represents a declared distribution of $0.39 per unit payable May 12, 2017 and a distribution of $0.39 per unit paid May 12, 2016, respectively.
Schedule of Unit Amounts Used to Compute Basic and Diluted Earnings per Limited Partner Unit 
The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the periods presented (in millions): 
 
Three Months Ended March 31,
 
2017
 
2016
Basic weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
343.6

 
325.2

Weighted average Class C Common Units outstanding
—

 
7.2

Total weighted average limited partner common units outstanding
343.6

 
332.4

 
 
 
 
Diluted weighted average units outstanding:
 
 
 
Weighted average limited partner basic common units outstanding
343.6

 
332.4

Dilutive effect of restricted units issued
—

 
—

Total weighted average limited partner diluted common units outstanding
343.6

 
332.4

Incentive Distributions 
Net income is allocated to the General Partner in an amount equal to its incentive distribution rights as described in (b) above. The General Partner’s share of net income consists of incentive distribution rights to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units, the percentage interest of our net income adjusted for ENLC’s unit-based compensation specifically allocated to our General Partner. The net income allocated to the General Partner is as follows (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Income allocation for incentive distributions
$
14.7

 
$
13.8

Unit-based compensation attributable to ENLC’s restricted units
(8.8
)
 
(4.0
)
General partner share of net income (loss)
—

 
(2.4
)
General partner interest in net income
$
5.9

 
$
7.4

Asset Retirement Obligations (Tables)
Summary of Changes
The schedule below summarizes the changes in our asset retirement obligations (in millions):

Three Months Ended March 31, 2017
 
Balance, beginning of period
$
13.5

Accretion expense
0.2

Balance, end of period
$
13.7

Investment in Unconsolidated Affiliates (Tables)
Summary of Activity and Investment in Unconsolidated Affiliates
The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):
 
Gulf Coast
Fractionators
 
Howard Energy Partners
 
Cedar Cove JV
 
Total
Three Months Ended
 
 
 
 
 
 
 
March 31, 2017
 
 
 
 
 
 
 
Contributions
$
—

 
—

 
6.0

 
$
6.0

Distributions
$
2.7

 
—

 
0.2

 
$
2.9

Equity in income (loss) (1)
$
4.0

 
(3.4
)
 
0.1

 
$
0.7

 
 
 
 
 
 
 
 
March 31, 2016
 
 
 
 
 
 
 
Contributions
$
—

 
7.1

 
—

 
$
7.1

Distributions
$
3.0

 
6.2

 
—

 
$
9.2

Equity in loss
$
(1.7
)
 
(0.7
)
 
—

 
$
(2.4
)
(1)
Includes a loss of $3.4 million for the three months ended March 31, 2017 from the sale of HEP in March 2017.

The following table shows the balances related to our investment in unconsolidated affiliates as of March 31, 2017 and December 31, 2016 (in millions): 
 
March 31, 2017
 
December 31, 2016
Gulf Coast Fractionators
$
49.8

 
$
48.5

Howard Energy Partners
—

 
193.1

Cedar Cove JV
34.7

 
28.8

Total investment in unconsolidated affiliates
$
84.5

 
$
270.4

Employee Incentive Plans (Tables)
Schedule of Amounts Recognized in Consolidated Financial Statements 
Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Cost of unit-based compensation charged to general and administrative expense
$
14.3

 
$
6.2

Cost of unit-based compensation charged to operating expense
5.0

 
1.7

Total unit-based compensation expense
$
19.3

 
$
7.9

Summary of Restricted Incentive Unit Activity 
ENLK restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of common units on such date. A summary of the restricted incentive unit activity for the three months ended March 31, 2017 is provided below:
 
 
Three Months Ended
March 31, 2017
EnLink Midstream Partners, LP Restricted Incentive Units:
 
Number of Units
 
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period
 
2,024,820

 
$
19.05

Granted (1)
 
822,865

 
18.46

Vested (1)(2)
 
(795,188
)
 
25.84

Forfeited
 
(6,997
)
 
16.87

Non-vested, end of period
 
2,045,500

 
$
16.18

Aggregate intrinsic value, end of period (in millions)
 
$
37.4

 
 

                                                           
(1)
Restricted incentive units were issued in the first quarter of 2017 to officers and other employees. These restricted incentive units typically vest at the end of three years. In March 2017, we issued 262,288 restricted incentive units with a fair value of $5.1 million to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
(2)
Vested units include 258,145 units withheld for payroll taxes paid on behalf of employees.
ENLC restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of the common units on such date. A summary of the restricted incentive unit activity for the three months ended March 31, 2017 is provided below:
 
 
Three Months Ended
March 31, 2017
EnLink Midstream, LLC Restricted Incentive Units:
 
Number of Units
 
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period
 
1,897,298

 
$
19.96

Granted (1)
 
781,842

 
19.29

Vested (1)(2)
 
(726,692
)
 
28.07

Forfeited
 
(6,706
)
 
17.58

Non-vested, end of period
 
1,945,742

 
$
16.67

Aggregate intrinsic value, end of period (in millions)
 
$
37.7

 
 

                                                           
(1)
Restricted incentive units were issued in the first quarter of 2017 to officers and other employees. These restricted incentive units typically vest at the end of three years. In March 2017, ENLC issued 258,606 restricted incentive units with a fair value of $5.0 million to officers and certain employees as bonus payments for 2016, and these restricted incentive units vested immediately and are included in the restricted incentive units granted and vested line items.
(2)
Vested units include 224,709 units withheld for payroll taxes paid on behalf of employees.
Summary of Restricted Units' Aggregate Intrinsic Value 
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2017 and 2016, respectively, is provided below (in millions):
 
 
Three Months Ended March 31,
EnLink Midstream Partners, LP Restricted Incentive Units:
 
2017
 
2016
Aggregate intrinsic value of units vested
 
$
15.3

 
$
3.7

Fair value of units vested
 
$
20.5

 
$
9.0

A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) for the three months ended March 31, 2017 and 2016, respectively, are provided below (in millions):
 
 
Three Months Ended
March 31,
EnLink Midstream, LLC Restricted Incentive Units:
 
2017
 
2016
Aggregate intrinsic value of units vested
 
$
14.3

 
$
3.8

Fair value of units vested
 
$
20.4

 
$
11.8

Summary of Grant-Date Fair Values 
The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:

EnLink Midstream, LLC Performance Units:
 
March 2017
Beginning TSR Price
 
$
18.29

Risk-free interest rate
 
1.62
%
Volatility factor
 
52.07
%
Distribution yield
 
5.4
%
The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:
 
EnLink Midstream Partners, LP Performance Units:
 
March 2017
Beginning TSR Price
 
$
17.55

Risk-free interest rate
 
1.62
%
Volatility factor
 
43.94
%
Distribution yield
 
8.7
%
Summary of Performance Units 
The following table presents a summary of the performance units: 
 
 
Three Months Ended
March 31, 2017
EnLink Midstream Partners, LP Performance Units:
 
Number of Units
 
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period
 
408,637

 
$
11.53

Granted
 
176,648

 
25.73

Forfeited
 
—

 
—

Non-vested, end of period
 
585,285

 
$
15.82

Aggregate intrinsic value, end of period (in millions)
 
$
10.7

 
 

 The following table presents a summary of the performance units:
 
 
Three Months Ended
March 31, 2017
EnLink Midstream, LLC Performance Units:
 
Number of Units
 
Weighted Average Grant-Date Fair Value
Non-vested, beginning of period
 
384,264

 
$
19.30

Granted
 
164,575

 
28.77

Forfeited
 
—

 
—

Non-vested, end of period
 
548,839

 
$
22.14

Aggregate intrinsic value, end of period (in millions)
 
$
10.6

 
 

Derivatives (Tables)
Components of Gain (Loss) 
The components of gain (loss) on derivative activity in the consolidated statements of operations related to commodity swaps are (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Change in fair value of derivatives
$
5.3

 
$
(6.0
)
Realized gain (loss) on derivatives
(2.5
)
 
5.6

Gain (loss) on derivative activity
$
2.8

 
$
(0.4
)
Fair Value of Derivative Assets and Liabilities 
The fair value of derivative assets and liabilities related to commodity swaps are as follows (in millions):
 
March 31, 2017
 
December 31, 2016
Fair value of derivative assets — current
$
2.1

 
$
1.3

Fair value of derivative assets — long-term
0.1

 
—

Fair value of derivative liabilities — current
(2.9
)
 
(7.6
)
Fair value of derivative liabilities — long-term
(0.3
)
 
—

Net fair value of derivatives
$
(1.0
)
 
$
(6.3
)
Summary of Notional Volumes and Fair Value of Instruments 
Set forth below is the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at March 31, 2017 (in millions). The remaining term of the contracts extend no later than October 2018.
 
 
 
 
March 31, 2017
Commodity
 
Instruments
 
Unit
 
Volume
 
Fair Value
NGL (short contracts)
 
Swaps
 
Gallons
 
(32.9
)
 
$
(0.3
)
NGL (long contracts)
 
Swaps
 
Gallons
 
12.8

 
(0.2
)
Natural Gas (short contracts)
 
Swaps
 
MMBtu
 
(15.4
)
 
(0.3
)
Natural Gas (long contracts)
 
Swaps
 
MMBtu
 
15.1

 
(0.4
)
Condensate (short contracts)
 
Swaps
 
MMbbls
 
—

 
0.1

Condensate (long contracts)
 
Swaps
 
MMbbls
 
—

 
0.1

Total fair value of derivatives
 
 
 
 
 
 

 
$
(1.0
)
Fair Value Measurements (Tables)
Schedule of Net Assets (Liabilities) Measured on a Recurring Basis 
Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in millions):
 
Level 2
 
March 31, 2017
 
December 31, 2016
Commodity Swaps (1)
$
(1.0
)
 
$
(6.3
)
Total
$
(1.0
)
 
$
(6.3
)
                                                           
(1)
The fair values of derivative contracts included in assets or liabilities for risk management activities represent the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our credit risk and/or the counterparty credit risk as required under ASC 820.
Fair Value of Financial Instruments 
The estimated fair value of our financial instruments has been determined using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):
 
March 31, 2017
 
December 31, 2016
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Long-term debt (1)
$
3,478.1

 
$
3,499.6

 
$
3,268.0

 
$
3,225.8

Installment Payables
$
230.1

 
$
232.9

 
$
473.2

 
$
476.6

Obligations under capital lease
$
5.1

 
$
4.3

 
$
6.6

 
$
6.1

                                                           
(1)
The carrying values of long-term debt are reduced by debt issuance costs of $23.3 million and $24.1 million at March 31, 2017 and December 31, 2016, respectively. The respective fair values do not factor in debt issuance costs.
Segment Information (Tables)
Summarized Financial Information 
Summarized financial information for our reportable segments is shown in the following table (in millions):
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
Three Months Ended March 31, 2017
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
85.1

 
$
544.5

 
$
14.5

 
$
345.9

 
$
—

 
$
990.0

Product sales—related parties
106.5

 
10.2

 
64.4

 
0.8

 
(139.2
)
 
42.7

Midstream services
27.8

 
53.1

 
27.9

 
18.6

 
—

 
127.4

Midstream services—related parties
105.1

 
29.0

 
49.4

 
3.3

 
(27.8
)
 
159.0

Cost of sales
(179.2
)
 
(564.7
)
 
(88.7
)
 
(336.7
)
 
167.0

 
(1,002.3
)
Operating expenses
(43.9
)
 
(25.4
)
 
(14.1
)
 
(20.7
)
 
—

 
(104.1
)
Gain on derivative activity
—

 
—

 
—

 
—

 
2.8

 
2.8

Segment profit
$
101.4

 
$
46.7

 
$
53.4

 
$
11.2

 
$
2.8

 
$
215.5

Depreciation and amortization
$
(49.8
)
 
$
(28.1
)
 
$
(36.5
)
 
$
(11.5
)
 
$
(2.4
)
 
$
(128.3
)
Goodwill
$
232.0

 
$
—

 
$
190.3

 
$
—

 
$
—

 
$
422.3

Capital expenditures
$
28.3

 
$
32.7

 
$
140.7

 
$
37.4

 
$
9.0

 
$
248.1

 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2016
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
62.5

 
$
287.7

 
$
7.8

 
$
230.5

 
$
—

 
$
588.5

Product sales—related parties
37.3

 
7.4

 
10.6

 
0.2

 
(31.0
)
 
24.5

Midstream services
27.4

 
55.2

 
15.1

 
16.8

 
—

 
114.5

Midstream services—related parties
110.3

 
12.7

 
45.0

 
5.2

 
(10.6
)
 
162.6

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

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

 
(98.2
)
Loss on derivative activity
—

 
—

 
—

 
—

 
(0.4
)
 
(0.4
)
Segment profit (loss)
$
106.9

 
$
37.6

 
$
46.4

 
$
14.8

 
$
(0.4
)
 
$
205.3

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

 
$
—

 
$
(93.2
)
 
$
—

 
$
(566.3
)
Goodwill
$
230.4

 
$
—

 
$
190.3

 
$
—

 
$
—

 
$
420.7

Capital expenditures
$
23.3

 
$
22.7

 
$
69.2

 
$
3.3

 
$
1.9

 
$
120.4

Schedule of Assets 
The table below represents information about segment assets as of March 31, 2017 and December 31, 2016 (in millions):
Segment Identifiable Assets:
March 31, 2017
 
December 31, 2016
Texas
$
3,132.6

 
$
3,142.6

Louisiana
2,312.7

 
2,349.3

Oklahoma
2,629.8

 
2,524.5

Crude and Condensate
861.9

 
836.8

Corporate
122.4

 
300.2

Total identifiable assets
$
9,059.4

 
$
9,153.4

Reconciliation of Profits Reported to Operating Income (Loss) 
The following table reconciles the segment profits reported above to the operating income (loss) as reported in the consolidated statements of operations (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Segment profits
$
215.5

 
$
205.3

General and administrative expenses
(35.0
)
 
(33.2
)
Gain (loss) on disposition of assets
(5.1
)
 
0.2

Depreciation and amortization
(128.3
)
 
(121.9
)
Impairments
(7.0
)
 
(566.3
)
Gain on litigation settlement
17.5

 
—

Operating income (loss)
$
57.6

 
$
(515.9
)
Supplemental Cash Flow Information (Tables)
Summary of Non-Cash Financing Activities
The following schedule summarizes non-cash financing activities for the periods presented (in millions):
 
Three Months Ended March 31,
 
2017
 
2016
Non-cash financing activities:
 
 
 
Installment payable, net of discount of $79.1 million (1)
$
—

 
$
420.9

Contribution from ENLC (2)
—

 
237.1

                                                           
(1)
We incurred installment purchase obligations, net of discount, payable to the seller in connection with the EnLink Oklahoma T.O. assets. We paid the first installment on January 6, 2017 and will pay the final installment no later than January 7, 2018. See “Note 3—Acquisition” for further discussion.
(2)
Contribution from ENLC in connection with the acquisition of EnLink Oklahoma T.O. assets. See “Note 3—Acquisition” for further discussion.
Other Information (Tables)
Schedule of Other Current Liabilities
The following table presents additional detail for other current liabilities, which consists of the following (in millions):
 
March 31, 2017
 
December 31, 2016
Accrued interest
$
58.3

 
$
34.2

Accrued wages and benefits, including taxes
9.2

 
19.0

Accrued ad valorem taxes
13.0

 
23.5

Capital expenditure accruals
56.3

 
64.6

Onerous performance obligations
15.8

 
15.9

Other
61.2

 
59.8

Other current liabilities
$
213.8

 
$
217.0

General (Details) (Devon)
3 Months Ended
Mar. 31, 2017
Devon
 
Business Acquisition [Line Items]
 
Percentage of outstanding limited liability company interests
64.00% 
Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Property, Plant and Equipment [Line Items]
 
 
Gain (loss) on disposition of assets
$ (5.1)
$ 0.2 
Recognized impairment
7.0 
566.3 
Permian Basin
 
 
Property, Plant and Equipment [Line Items]
 
 
Gain (loss) on disposition of assets
$ 5.1 
 
Acquisition - Narrative (Details) (EnLink Oklahoma T.O., USD $)
0 Months Ended 3 Months Ended
Jan. 6, 2017
Jan. 7, 2016
Mar. 31, 2016
Jan. 7, 2016
Business Acquisition [Line Items]
 
 
 
 
Acquired voting interest
 
 
 
84.00% 
Consideration
 
$ 1,441,600,000 
 
 
First installment
 
1,020,000,000 
 
 
Payment of second installment
250,000,000 
 
 
 
Final installment payable
 
250,000,000 
 
 
Cash
 
783,600,000 
 
 
Estimated life of acquired intangible assets
 
15 years 
 
 
Transaction costs
 
 
3,600,000 
4,100,000 
Recognized revenue
 
 
27,300,000 
 
Net gain (loss) related to assets acquired
 
 
(14,200,000)
 
ENLC
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
Acquired voting interest
 
 
 
16.00% 
Common units issued (in shares)
 
 
 
15,564,009 
Cash paid
 
$ 22,200,000 
 
 
Acquisition - Schedule of Consideration, Assets and Liabilities (Details) (USD $)
In Millions, unless otherwise specified
0 Months Ended 3 Months Ended 0 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2016
Jan. 7, 2016
EnLink Oklahoma T.O.
Mar. 31, 2017
EnLink Oklahoma T.O.
Mar. 31, 2016
EnLink Oklahoma T.O.
Jan. 7, 2016
EnLink Oklahoma T.O.
Jan. 7, 2016
EnLink Oklahoma T.O.
ENLC
Consideration:
 
 
 
 
 
 
 
 
Cash
 
 
 
$ 783.6 
 
 
 
 
Total installment payable, net of discount of $79.1 million assuming payments made on January 7, 2017 and 2018
 
 
 
420.9 
0 
420.9 
 
 
Installment payable discount
 
 
 
 
79.1 
79.1 
79.1 
 
Contribution from ENLC
 
 
 
 
 
 
 
237.1 
Total consideration
 
 
 
1,441.6 
 
 
 
 
Assets acquired:
 
 
 
 
 
 
 
 
Current assets (including $12.8 million in cash)
 
 
 
 
 
 
23.0 
 
Cash acquired
 
 
 
12.8 
 
 
 
 
Property, plant and equipment
 
 
 
 
 
 
406.1 
 
Intangibles
 
 
 
 
 
 
1,051.3 
 
Goodwill
422.3 
422.3 
420.7 
 
 
 
 
 
Liabilities assumed:
 
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
(38.8)
 
Total identifiable net assets
 
 
 
 
 
 
$ 1,441.6 
 
Goodwill and Intangible Assets - Narrative (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Goodwill
 
 
Goodwill impairment loss
 
$ 566.3 
Amortization expense
$ 29.5 
$ 27.5 
Minimum
 
 
Goodwill
 
 
Amortization period
10 years 
 
Maximum
 
 
Goodwill
 
 
Amortization period
20 years 
 
Weighted average
 
 
Goodwill
 
 
Amortization period
13 years 8 months 
 
Goodwill and Intangible Assets - Changes in Carrying Value (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Finite-lived Intangible Assets [Roll Forward]
 
 
Accumulated Amortization, Beginning Balance
$ (171.6)
 
Accumulated Amortization, Amortization expense
(29.5)
(27.5)
Accumulated Amortization, Ending Balance
(201.1)
 
Net Carrying Amount, Ending Balance
1,594.7 
 
Customer relationships
 
 
Finite-lived Intangible Assets [Roll Forward]
 
 
Gross Carrying Amount, Beginning Balance
1,795.8 
 
Accumulated Amortization, Beginning Balance
(171.6)
 
Net Carrying Amount, Beginning Balance
1,624.2 
 
Accumulated Amortization, Amortization expense
(29.5)
 
Gross Carrying Amount, Ending Balance
1,795.8 
 
Accumulated Amortization, Ending Balance
(201.1)
 
Net Carrying Amount, Ending Balance
$ 1,594.7 
 
Goodwill and Intangible Assets - Amortization Expense (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Summary of estimated amortization expense
 
2017 (remaining)
$ 88.4 
2018
117.9 
2019
117.9 
2020
117.9 
2021
117.9 
Thereafter
1,034.7 
Total
$ 1,594.7 
Related Party Transactions (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2017
Devon
Dec. 31, 2016
Devon
Mar. 31, 2017
Sales Revenue, Net
Customer Concentration Risk
Devon
Mar. 31, 2016
Sales Revenue, Net
Customer Concentration Risk
Devon
Related Party Transaction
 
 
 
 
 
 
Concentration risk
 
 
 
 
14.90% 
21.00% 
Accounts receivable balance
 
 
$ 106.9 
$ 100.2 
 
 
Accounts payable to related party
$ 12.5 
$ 10.4 
$ 11.8 
$ 10.4 
 
 
Long-Term Debt - Summary (Details) (USD $)
In Millions, unless otherwise specified
0 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2017
Partnership credit facility due 2020
Dec. 31, 2016
Partnership credit facility due 2020
Mar. 31, 2017
2.70% Senior unsecured notes due 2019
Dec. 31, 2016
2.70% Senior unsecured notes due 2019
Mar. 31, 2017
7.125% Senior unsecured notes due 2022
Dec. 31, 2016
7.125% Senior unsecured notes due 2022
Mar. 31, 2017
4.40% Senior unsecured notes due 2024
Dec. 31, 2016
4.40% Senior unsecured notes due 2024
Mar. 31, 2017
4.15% Senior unsecured notes due 2025
Dec. 31, 2016
4.15% Senior unsecured notes due 2025
Mar. 31, 2017
4.85% Senior unsecured notes due 2026
Dec. 31, 2016
4.85% Senior unsecured notes due 2026
Mar. 31, 2017
5.60% Senior unsecured notes due 2044
Dec. 31, 2016
5.60% Senior unsecured notes due 2044
Mar. 31, 2017
5.05% Senior unsecured notes due 2045
Dec. 31, 2016
5.05% Senior unsecured notes due 2045
Jun. 1, 2017
Unsecured, 2022 Notes
Forecast
Senior notes
Apr. 3, 2017
Unsecured, 2022 Notes
Subsequent event
Senior notes
Debt Instrument
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stated interest rate
 
 
 
 
2.70% 
 
7.125% 
 
4.40% 
 
4.15% 
 
4.85% 
 
5.60% 
 
5.05% 
 
 
7.125% 
Outstanding Principal
$ 3,492.5 
$ 3,282.5 
$ 330.0 
$ 120.0 
$ 400.0 
$ 400.0 
$ 162.5 
$ 162.5 
$ 550.0 
$ 550.0 
$ 750.0 
$ 750.0 
$ 500.0 
$ 500.0 
$ 350.0 
$ 350.0 
$ 450.0 
$ 450.0 
 
 
Premium (Discount)
8.9 
9.6 
0 
0 
(0.2)
(0.3)
15.2 
16.0 
2.4 
2.5 
(1.1)
(1.1)
(0.6)
(0.7)
(0.2)
(0.2)
(6.6)
(6.6)
 
 
Long-Term Debt
3,501.4 
3,292.1 
330.0 
120.0 
399.8 
399.7 
177.7 
178.5 
552.4 
552.5 
748.9 
748.9 
499.4 
499.3 
349.8 
349.8 
443.4 
443.4 
 
 
Debt issuance costs
(23.3)
(24.1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt, net of unamortized issuance cost
3,478.1 
3,268.0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effective interest rate
3.00% 
2.30% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Redemption price as a percentage of the principal amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
103.60% 
 
Redemption price plus accrued interest
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
174.1 
 
Amortization
$ 9.2 
$ 8.3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt - Narrative (Details) (USD $)
3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2017
Credit Facility
extension
Mar. 31, 2017
Credit Facility
Maximum
Mar. 31, 2017
Credit Facility
LIBOR Rate
Maximum
Mar. 31, 2017
Credit Facility
LIBOR Rate
Minimum
Mar. 31, 2017
Credit Facility
Federal Funds
Mar. 31, 2017
Credit Facility
Eurodollar
Mar. 31, 2017
Credit Facility
Eurodollar
Maximum
Mar. 31, 2017
Credit Facility
Eurodollar
Minimum
Mar. 31, 2017
Credit Facility
Letter of Credit
Debt Instrument
 
 
 
 
 
 
 
 
 
 
 
Maximum borrowing capacity
 
 
$ 1,500,000,000.0 
 
 
 
 
 
 
 
$ 500,000,000.0 
Additional amount available (not to exceed)
 
 
500,000,000.0 
 
 
 
 
 
 
 
 
Number of allowed extensions
 
 
2 
 
 
 
 
 
 
 
 
Extension period
 
 
1 year 
 
 
 
 
 
 
 
 
Ratio of consolidated indebtedness to consolidated EBITDA
 
 
5.0 
5.5 
 
 
 
 
 
 
 
Conditional acquisition purchase price
 
 
 
50,000,000.0 
 
 
 
 
 
 
 
Variable interest rate
 
 
 
 
1.75% 
1.00% 
0.50% 
1.00% 
0.75% 
0.00% 
 
Outstanding letters of credit
 
 
9,100,000 
 
 
 
 
 
 
 
 
Outstanding borrowings under credit facility
330,000,000 
120,000,000 
330,000,000 
 
 
 
 
 
 
 
 
Amount available for future borrowing
 
 
$ 1,200,000,000 
 
 
 
 
 
 
 
 
Partners Capital - Narrative and Distribution Activity (Details) (USD $)
3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2016
Mar. 31, 2017
Preferred Units
Mar. 31, 2017
General Partner Interest
Incentive Distribution Level 1
Mar. 31, 2017
General Partner Interest
Incentive Distribution Level 2
Mar. 31, 2017
General Partner Interest
Incentive Distribution Level 3
Mar. 31, 2017
Common Units
Dec. 31, 2016
Common Units
Mar. 31, 2016
Common Units
Dec. 31, 2015
Common Units
Mar. 31, 2017
Common Units
BMO EDA
Nov. 30, 2014
Common Units
BMO EDA
Partners' capital
 
 
 
 
 
 
 
 
 
 
 
 
 
Agreement for gross sales of common units (up to)
 
 
 
 
 
 
 
 
 
 
 
 
$ 350,000,000.0 
Common units sold
55,200,000 
 
 
 
 
 
 
 
 
 
 
3,000,000 
 
Proceeds from sale of common units
55,200,000 
 
2,100,000 
 
 
 
 
 
 
 
 
55,200,000 
 
Commissions
 
 
 
 
 
 
 
 
 
 
 
600,000 
 
Gross common unit issuances available
 
 
 
 
 
 
 
 
 
 
 
$ 92,000,000 
 
Percentage of available cash to distribute
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Period after quarter for distribution
45 days 
 
 
 
 
 
 
 
 
 
 
 
 
Incentive distribution for general partner
 
 
 
 
13.00% 
23.00% 
48.00% 
 
 
 
 
 
 
Incentive distribution, conditional distribution per unit (in dollars per share)
 
 
 
 
$ 0.25 
$ 0.3125 
$ 0.375 
 
 
 
 
 
 
Distributions of Preferred Units paid-in kind (in shares)
 
1,130,131 
 
 
 
 
 
 
 
 
 
 
 
Distribution of Preferred Units declared (in shares)
 
 
 
1,154,147 
 
 
 
 
 
 
 
 
 
Distribution/unit (in dollars per share)
 
 
 
 
 
 
 
$ 0.39 
$ 0.39 
$ 0.39 
$ 0.39 
 
 
Partners Capital - Computation of Basic and Diluted Earnings per Limited Partner Units (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2016
Dec. 31, 2015
Class of Stock [Line Items]
 
 
 
 
Limited partners’ interest in net loss
$ (9.3)
 
$ (567.2)
 
Distributed earnings allocated to:
 
 
 
 
Total distributed earnings
134.9 
 
127.7 
 
Undistributed loss allocated to:
 
 
 
 
Total undistributed loss
(144.2)
 
(694.9)
 
Net loss allocated to:
 
 
 
 
Total limited partners’ interest in net loss
(9.3)
 
(567.2)
 
Basic and diluted net loss per unit:
 
 
 
 
Basic (in dollars per share)
$ (0.03)
 
$ (1.74)
 
Diluted (in dollars per share)
$ (0.03)
 
$ (1.74)
 
Unvested restricted units
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
Limited partners’ interest in net loss
(0.1)
 
(3.4)
 
Distributed earnings allocated to:
 
 
 
 
Total distributed earnings
0.9 
 
0.8 
 
Undistributed loss allocated to:
 
 
 
 
Total undistributed loss
(1.0)
 
(4.2)
 
Net loss allocated to:
 
 
 
 
Total limited partners’ interest in net loss
(0.1)
 
(3.4)
 
Common Units
 
 
 
 
Class of Stock [Line Items]
 
 
 
 
Limited partners’ interest in net loss
(9.2)
 
(563.8)
 
Distributed earnings allocated to:
 
 
 
 
Total distributed earnings
134.0 
 
126.9 
 
Undistributed loss allocated to:
 
 
 
 
Total undistributed loss
(143.2)
 
(690.7)
 
Net loss allocated to:
 
 
 
 
Total limited partners’ interest in net loss
$ (9.2)
 
$ (563.8)
 
Basic and diluted net loss per unit:
 
 
 
 
Declared distribution (in dollars per share)
$ 0.39 
$ 0.39 
$ 0.39 
$ 0.39 
Partners Capital - Unit Amounts Used to Computer Earnings per Limited Partner Unit (Details)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Basic weighted average units outstanding:
 
 
Total weighted average limited partner common units outstanding
343.6 
332.4 
Diluted weighted average units outstanding:
 
 
Total weighted average limited partner diluted common units outstanding
343.6 
332.4 
Basic common units
 
 
Basic weighted average units outstanding:
 
 
Total weighted average limited partner common units outstanding
343.6 
325.2 
Class C Common Units
 
 
Basic weighted average units outstanding:
 
 
Total weighted average limited partner common units outstanding
0 
7.2 
Partners Capital - Net Income Allocated to the General Partner (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Incentive
 
 
General partner interest in net income
$ 5.9 
$ 7.4 
General Partner Interest
 
 
Incentive
 
 
Income allocation for incentive distributions
14.7 
13.8 
Unit-based compensation attributable to ENLC’s restricted units
(8.8)
(4.0)
General partner share of net income (loss)
0 
(2.4)
General partner interest in net income
$ 5.9 
$ 7.4 
Asset Retirement Obligations (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Asset retirement obligation
 
Balance, beginning of period
$ 13.5 
Accretion expense
0.2 
Balance, end of period
$ 13.7 
Investment in Unconsolidated Affiliates (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Dec. 31, 2016
Schedule of Equity Method Investments
 
 
 
Net proceeds received
$ 189.7 
$ 0 
 
Contributions
6.0 
7.1 
 
Distributions
2.9 
9.2 
 
Equity in income (loss)
0.7 
(2.4)
 
Total investment in unconsolidated affiliates
84.5 
 
270.4 
Gulf Coast Fractionators
 
 
 
Schedule of Equity Method Investments
 
 
 
Ownership interest
38.75% 
 
38.75% 
Contributions
0 
0 
 
Distributions
2.7 
3.0 
 
Equity in income (loss)
4.0 
(1.7)
 
Total investment in unconsolidated affiliates
49.8 
 
48.5 
Howard Energy Partners
 
 
 
Schedule of Equity Method Investments
 
 
 
Ownership interest
 
 
31.00% 
Net proceeds received
189.7 
 
 
Contributions
0 
7.1 
 
Distributions
0 
6.2 
 
Equity in income (loss)
(3.4)
(0.7)
 
Total investment in unconsolidated affiliates
0 
 
193.1 
Cedar Cove JV
 
 
 
Schedule of Equity Method Investments
 
 
 
Ownership interest
30.00% 
 
30.00% 
Contributions
6.0 
0 
 
Distributions
0.2 
0 
 
Equity in income (loss)
0.1 
0 
 
Total investment in unconsolidated affiliates
$ 34.7 
 
$ 28.8 
Employee Incentive Plans - Amounts Recognized in Consolidated Financial Statements (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Compensation allocation
 
 
Total unit-based compensation expense
$ 19.3 
$ 7.9 
Cost of unit-based compensation charged to general and administrative expense
 
 
Compensation allocation
 
 
Total unit-based compensation expense
14.3 
6.2 
Cost of unit-based compensation charged to operating expense
 
 
Compensation allocation
 
 
Total unit-based compensation expense
$ 5.0 
$ 1.7 
Employee Incentive Plans - Restricted and Performance Awards (Details) (USD $)
In Millions, except Share data, unless otherwise specified
1 Months Ended 3 Months Ended
Mar. 31, 2017
Mar. 31, 2017
Mar. 31, 2016
Unvested restricted units
 
 
 
Number of Units
 
 
 
Non-vested, beginning of period (in shares)
 
2,024,820 
 
Granted (in shares)
 
822,865 
 
Vested (in shares)
(262,288)
(795,188)
 
Forfeited (in shares)
 
(6,997)
 
Non-vested, end of period (in shares)
2,045,500 
2,045,500 
 
Aggregate intrinsic value, end of period
$ 37.4 
$ 37.4 
 
Weighted Average Grant-Date Fair Value
 
 
 
Non-vested, beginning of period (in dollars per share)
 
$ 19.05 
 
Granted (in dollars per share)
 
$ 18.46 
 
Vested (in dollars per share)
 
$ 25.84 
 
Forfeited (in dollars per share)
 
$ 16.87 
 
Non-vested, end of period (in dollars per share)
$ 16.18 
$ 16.18 
 
Fair value of units vested
5.1 
20.5 
9.0 
Units withheld for payroll taxes (in shares)
 
258,145 
 
Aggregate intrinsic value of units vested
 
15.3 
3.7 
Unrecognized compensation cost related to non-vested restricted incentive units
20.7 
20.7 
 
Unrecognized compensation costs, weighted average period for recognition
 
2 years 
 
Vesting period
 
3 years 
 
Unvested restricted units |
ENLC
 
 
 
Number of Units
 
 
 
Non-vested, beginning of period (in shares)
 
1,897,298 
 
Granted (in shares)
 
781,842 
 
Vested (in shares)
(258,606)
(726,692)
 
Forfeited (in shares)
 
(6,706)
 
Non-vested, end of period (in shares)
1,945,742 
1,945,742 
 
Aggregate intrinsic value, end of period
37.7 
37.7 
 
Weighted Average Grant-Date Fair Value
 
 
 
Non-vested, beginning of period (in dollars per share)
 
$ 19.96 
 
Granted (in dollars per share)
 
$ 19.29 
 
Vested (in dollars per share)
 
$ 28.07 
 
Forfeited (in dollars per share)
 
$ 17.58 
 
Non-vested, end of period (in dollars per share)
$ 16.67 
$ 16.67 
 
Fair value of units vested
5.0 
20.4 
11.8 
Units withheld for payroll taxes (in shares)
 
224,709 
 
Aggregate intrinsic value of units vested
 
14.3 
3.8 
Unrecognized compensation cost related to non-vested restricted incentive units
20.2 
20.2 
 
Unrecognized compensation costs, weighted average period for recognition
 
2 years 
 
Vesting period
 
3 years 
 
Performance Units
 
 
 
Number of Units
 
 
 
Non-vested, beginning of period (in shares)
 
408,637 
 
Granted (in shares)
 
176,648 
 
Forfeited (in shares)
 
0 
 
Non-vested, end of period (in shares)
585,285 
585,285 
 
Aggregate intrinsic value, end of period
10.7 
10.7 
 
Weighted Average Grant-Date Fair Value
 
 
 
Non-vested, beginning of period (in dollars per share)
 
$ 11.53 
 
Granted (in dollars per share)
 
$ 25.73 
 
Forfeited (in dollars per share)
 
$ 0.00 
 
Non-vested, end of period (in dollars per share)
$ 15.82 
$ 15.82 
 
Unrecognized compensation cost related to non-vested restricted incentive units
8.0 
8.0 
 
Unrecognized compensation costs, weighted average period for recognition
 
2 years 3 months 
 
Vesting period
 
3 years 
 
Grant date fair value assumptions
 
 
 
Beginning TSR Price
 
$ 17.55 
 
Risk-free interest rate
 
1.62% 
 
Volatility factor
 
43.94% 
 
Distribution yield
 
8.70% 
 
Performance Units |
ENLC
 
 
 
Number of Units
 
 
 
Non-vested, beginning of period (in shares)
 
384,264 
 
Granted (in shares)
 
164,575 
 
Forfeited (in shares)
 
0 
 
Non-vested, end of period (in shares)
548,839 
548,839 
 
Aggregate intrinsic value, end of period
10.6 
10.6 
 
Weighted Average Grant-Date Fair Value
 
 
 
Non-vested, beginning of period (in dollars per share)
 
$ 19.30 
 
Granted (in dollars per share)
 
$ 28.77 
 
Forfeited (in dollars per share)
 
$ 0.00 
 
Non-vested, end of period (in dollars per share)
$ 22.14 
$ 22.14 
 
Unrecognized compensation cost related to non-vested restricted incentive units
$ 8.1 
$ 8.1 
 
Unrecognized compensation costs, weighted average period for recognition
 
2 years 3 months 
 
Vesting period
 
3 years 
 
Grant date fair value assumptions
 
 
 
Beginning TSR Price
 
$ 18.29 
 
Risk-free interest rate
 
1.62% 
 
Volatility factor
 
52.07% 
 
Distribution yield
 
5.40% 
 
Performance Units |
Minimum
 
 
 
Weighted Average Grant-Date Fair Value
 
 
 
Percent of units vesting
 
0.00% 
 
Performance Units |
Minimum |
ENLC
 
 
 
Weighted Average Grant-Date Fair Value
 
 
 
Percent of units vesting
 
0.00% 
 
Performance Units |
Maximum
 
 
 
Weighted Average Grant-Date Fair Value
 
 
 
Percent of units vesting
 
200.00% 
 
Performance Units |
Maximum |
ENLC
 
 
 
Weighted Average Grant-Date Fair Value
 
 
 
Percent of units vesting
 
200.00% 
 
Derivatives - Components of Gain (Loss) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Derivative Instruments
 
 
Gain (loss) on derivative activity
$ 2.8 
$ (0.4)
Commodity Swaps
 
 
Derivative Instruments
 
 
Change in fair value of derivatives
5.3 
(6.0)
Realized gain (loss) on derivatives
(2.5)
5.6 
Gain (loss) on derivative activity
$ 2.8 
$ (0.4)
Derivatives - Assets and Liabilities (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
 
 
Fair value of derivative assets — current
$ 2.1 
$ 1.3 
Fair value of derivative assets — long-term
0.1 
0 
Fair value of derivative liabilities — current
(2.9)
(7.6)
Fair value of derivative liabilities — long-term
(0.3)
0 
Net fair value of derivatives
$ (1.0)
$ (6.3)
Derivatives - Commodities (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Mar. 31, 2017
Commodity
Mar. 31, 2017
Commodity
NGL
Short
gal
Mar. 31, 2017
Commodity
NGL
Long
gal
Mar. 31, 2017
Commodity
Natural Gas
Short
MMBTU
Mar. 31, 2017
Commodity
Natural Gas
Long
MMBTU
Mar. 31, 2017
Commodity
Condensate
Short
MMBbls
Mar. 31, 2017
Commodity
Condensate
Long
MMBbls
Derivative
 
 
 
 
 
 
 
 
 
Notional amount (in gallons and mmbls)
 
 
 
32,900,000 
12,800,000 
 
 
0 
0 
Notional amount (in mmbtu)
 
 
 
 
 
15,400,000 
15,100,000 
 
 
Fair Value
$ (1.0)
$ (6.3)
$ (1.0)
$ (0.3)
$ (0.2)
$ (0.3)
$ (0.4)
$ 0.1 
$ 0.1 
Maximum loss if counterparties fail to perform
 
 
2.2 
 
 
 
 
 
 
Possible reduction in maximum loss if counterparties fail to perform
 
 
$ 0.4 
 
 
 
 
 
 
Fair Value Measurements - Measured on a Recurring Basis (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Measured at fair value
 
 
Fair Value
$ (1.0)
$ (6.3)
Level 2 |
Recurring
 
 
Measured at fair value
 
 
Fair Value
(1.0)
(6.3)
Level 2 |
Commodity Swaps |
Recurring
 
 
Measured at fair value
 
 
Fair Value
$ (1.0)
$ (6.3)
Fair Value Measurements - Financial Instruments (Details) (USD $)
Mar. 31, 2017
Dec. 31, 2016
Fair Value
 
 
Debt issuance costs
$ 23,300,000 
$ 24,100,000 
Line of credit amount outstanding
330,000,000 
120,000,000 
Senior unsecured notes
3,100,000,000 
3,100,000,000 
Minimum
 
 
Fair Value
 
 
Stated interest rate
2.70% 
2.70% 
Maximum
 
 
Fair Value
 
 
Stated interest rate
7.10% 
7.10% 
Carrying Value
 
 
Fair Value
 
 
Long-term debt
3,478,100,000 
3,268,000,000 
Installment Payables
230,100,000 
473,200,000 
Obligations under capital lease
5,100,000 
6,600,000 
Fair Value
 
 
Fair Value
 
 
Long-term debt
3,499,600,000 
3,225,800,000 
Installment Payables
232,900,000 
476,600,000 
Obligations under capital lease
$ 4,300,000 
$ 6,100,000 
Commitments and Contingencies (Details) (USD $)
In Millions, unless otherwise specified
1 Months Ended 3 Months Ended 1 Months Ended
Mar. 31, 2017
Aug. 31, 2014
Mar. 31, 2017
Mar. 31, 2016
Jul. 31, 2013
Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans
Judicial ruling
defendant
Loss Contingencies [Line Items]
 
 
 
 
 
Number of energy companies sued (in defendant)
 
 
 
 
100 
Gain on litigation settlement
 
$ 6.1 
$ 17.5 
$ 0 
 
Additional settlement payment received
$ 17.5 
 
 
 
 
Segment Information - Financial Information and Assets (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Dec. 31, 2016
Segment Reporting
 
 
 
Product sales
$ 990.0 
$ 588.5 
 
Product sales—related parties
42.7 
24.5 
 
Midstream services
127.4 
114.5 
 
Midstream services—related parties
159.0 
162.6 
 
Cost of sales
(1,002.3)1
(586.2)1
 
Operating expenses
(104.1)2
(98.2)2
 
Gain (loss) on derivative activity
2.8 
(0.4)
 
Segment profit
215.5 
205.3 
 
Depreciation and amortization
(128.3)
(121.9)
 
Impairments
(7.0)
(566.3)
 
Goodwill
422.3 
420.7 
422.3 
Capital expenditures
248.1 
120.4 
 
Total identifiable assets
9,059.4 
 
9,153.4 
Corporate
 
 
 
Segment Reporting
 
 
 
Product sales
0 
0 
 
Product sales—related parties
(139.2)
(31.0)
 
Midstream services
0 
0 
 
Midstream services—related parties
(27.8)
(10.6)
 
Cost of sales
167.0 
41.6 
 
Operating expenses
0 
0 
 
Gain (loss) on derivative activity
2.8 
(0.4)
 
Segment profit
2.8 
(0.4)
 
Depreciation and amortization
(2.4)
(2.2)
 
Impairments
 
0 
 
Goodwill
0 
0 
 
Capital expenditures
9.0 
1.9 
 
Total identifiable assets
122.4 
 
300.2 
Texas |
Operating Segments
 
 
 
Segment Reporting
 
 
 
Product sales
85.1 
62.5 
 
Product sales—related parties
106.5 
37.3 
 
Midstream services
27.8 
27.4 
 
Midstream services—related parties
105.1 
110.3 
 
Cost of sales
(179.2)
(91.3)
 
Operating expenses
(43.9)
(39.3)
 
Gain (loss) on derivative activity
0 
0 
 
Segment profit
101.4 
106.9 
 
Depreciation and amortization
(49.8)
(46.2)
 
Impairments
 
(473.1)
 
Goodwill
232.0 
230.4 
 
Capital expenditures
28.3 
23.3 
 
Total identifiable assets
3,132.6 
 
3,142.6 
Louisiana |
Operating Segments
 
 
 
Segment Reporting
 
 
 
Product sales
544.5 
287.7 
 
Product sales—related parties
10.2 
7.4 
 
Midstream services
53.1 
55.2 
 
Midstream services—related parties
29.0 
12.7 
 
Cost of sales
(564.7)
(302.1)
 
Operating expenses
(25.4)
(23.3)
 
Gain (loss) on derivative activity
0 
0 
 
Segment profit
46.7 
37.6 
 
Depreciation and amortization
(28.1)
(29.3)
 
Impairments
 
0 
 
Goodwill
0 
0 
 
Capital expenditures
32.7 
22.7 
 
Total identifiable assets
2,312.7 
 
2,349.3 
Oklahoma |
Operating Segments
 
 
 
Segment Reporting
 
 
 
Product sales
14.5 
7.8 
 
Product sales—related parties
64.4 
10.6 
 
Midstream services
27.9 
15.1 
 
Midstream services—related parties
49.4 
45.0 
 
Cost of sales
(88.7)
(19.3)
 
Operating expenses
(14.1)
(12.8)
 
Gain (loss) on derivative activity
0 
0 
 
Segment profit
53.4 
46.4 
 
Depreciation and amortization
(36.5)
(33.8)
 
Impairments
 
0 
 
Goodwill
190.3 
190.3 
 
Capital expenditures
140.7 
69.2 
 
Total identifiable assets
2,629.8 
 
2,524.5 
Crude and Condensate |
Operating Segments
 
 
 
Segment Reporting
 
 
 
Product sales
345.9 
230.5 
 
Product sales—related parties
0.8 
0.2 
 
Midstream services
18.6 
16.8 
 
Midstream services—related parties
3.3 
5.2 
 
Cost of sales
(336.7)
(215.1)
 
Operating expenses
(20.7)
(22.8)
 
Gain (loss) on derivative activity
0 
0 
 
Segment profit
11.2 
14.8 
 
Depreciation and amortization
(11.5)
(10.4)
 
Impairments
 
(93.2)
 
Goodwill
0 
0 
 
Capital expenditures
37.4 
3.3 
 
Total identifiable assets
$ 861.9 
 
$ 836.8 
Segment Information - Reconciliation (Details) (USD $)
In Millions, unless otherwise specified
1 Months Ended 3 Months Ended
Aug. 31, 2014
Mar. 31, 2017
Mar. 31, 2016
Segment Reporting [Abstract]
 
 
 
Segment profits
 
$ 215.5 
$ 205.3 
General and administrative expenses
 
(35.0)
(33.2)
Gain (loss) on disposition of assets
 
(5.1)
0.2 
Depreciation and amortization
 
(128.3)
(121.9)
Impairments
 
(7.0)
(566.3)
Gain on litigation settlement
6.1 
17.5 
0 
Operating income (loss)
 
$ 57.6 
$ (515.9)
Other Information (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2017
Dec. 31, 2016
Other Liabilities Disclosure [Abstract]
 
 
Accrued interest
$ 58.3 
$ 34.2 
Accrued wages and benefits, including taxes
9.2 
19.0 
Accrued ad valorem taxes
13.0 
23.5 
Capital expenditure accruals
56.3 
64.6 
Onerous performance obligations
15.8 
15.9 
Other
61.2 
59.8 
Other current liabilities
$ 213.8 
$ 217.0 
Subsequent Events (Details) (Unsecured, 2022 Notes, Senior notes, Forecast, USD $)
In Millions, unless otherwise specified
0 Months Ended 3 Months Ended
Jun. 1, 2017
Jun. 30, 2017
Unsecured, 2022 Notes |
Senior notes |
Forecast
 
 
Subsequent Event [Line Items]
 
 
Redemption price as a percentage of the principal amount
103.60% 
 
Redemption price plus accrued interest
$ 174.1 
 
Gains on extinguishment of debt
 
$ 3.2