ENLINK MIDSTREAM, LLC, 10-K filed on 2/21/2018
Annual Report
Document and Entity Information (USD $)
In Billions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Feb. 14, 2018
Jun. 30, 2017
Entity Information [Abstract]
 
 
 
Document Type
10-K 
 
 
Document Fiscal Period Focus
FY 
 
 
Document Period End Date
Dec. 31, 2017 
 
 
Document Fiscal Year Focus
2017 
 
 
Amendment Flag
false 
 
 
Entity Registrant Name
ENLINK MIDSTREAM, LLC 
 
 
Entity Central Index Key
0001592000 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Common Stock, Shares Outstanding
 
180,883,369 
 
Entity Public Float
 
 
$ 1.1 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Current assets:
 
 
Cash and cash equivalents
$ 31.2 
$ 11.7 
Accounts receivable:
 
 
Trade, net of allowance for bad debt of $0.3 and $0.1, respectively
50.1 
63.9 
Accrued revenue and other
576.6 
369.6 
Related party
102.8 
100.2 
Fair value of derivative assets
6.8 
1.3 
Natural gas and NGLs inventory, prepaid expenses and other
41.2 
33.5 
Investment in unconsolidated affiliates—current
193.1 
Total current assets
808.7 
773.3 
Property and equipment, net of accumulated depreciation of $2,533.0 and $2,124.1, respectively
6,587.0 
6,256.7 
Intangible assets, net of accumulated amortization of $298.7 and $171.6, respectively
1,497.1 
1,624.2 
Goodwill
1,542.2 
1,542.2 
Investment in unconsolidated affiliates—non-current
89.4 
77.3 
Other assets, net
13.4 
2.2 
Total assets
10,537.8 
10,275.9 
Current liabilities:
 
 
Accounts payable and drafts payable
66.9 
69.2 
Accounts payable to related party
16.3 
10.4 
Accrued gas, NGLs, condensate and crude oil purchases
476.1 
333.3 
Fair value of derivative liabilities
8.4 
7.6 
Installment payable, net of discount of $0.5 and $0.5, respectively
249.5 
249.5 
Other current liabilities
222.9 
217.5 
Total current liabilities
1,040.1 
887.5 
Long-term debt
3,542.1 
3,295.3 
Asset retirement obligations
14.2 
13.5 
Installment payable, net of discount of $26.3 at December 31, 2016
223.7 
Other long-term liabilities
33.9 
42.5 
Deferred tax liability
346.2 
542.6 
Redeemable non-controlling interest
4.6 
5.2 
Members’ equity:
 
 
Members’ equity (180,600,728 and 180,049,316 units issued and outstanding, respectively)
1,924.2 
1,880.9 
Accumulated other comprehensive loss
(2.0)
Non-controlling interest
3,634.5 
3,384.7 
Total members’ equity
5,556.7 
5,265.6 
Commitments and contingencies (Note 15)
   
   
Total liabilities and members’ equity
$ 10,537.8 
$ 10,275.9 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
ASSETS
 
 
Allowance for bad debt
$ 0.3 
$ 0.1 
Property and equipment accumulated depreciation
2,533.0 
2,124.1 
Intangible assets accumulated amortization
298.7 
171.6 
Liabilities:
 
 
Current installment payable discount
0.5 
0.5 
Noncurrent installment payable discount
$ 0 
$ 26.3 
Members’ equity:
 
 
Common units issued (in shares)
180,600,728 
180,049,316 
Common units outstanding (in shares)
180,600,728 
180,049,316 
Consolidated Statements of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Revenues:
 
 
 
Product sales
$ 4,358.4 
$ 3,008.9 
$ 3,253.7 
Product sales—related parties
144.9 
134.3 
119.4 
Midstream services
552.3 
467.2 
451.0 
Midstream services—related parties
688.2 
653.1 
618.6 
Gain (loss) on derivative activity
(4.2)
(11.1)
9.4 
Total revenues
5,739.6 
4,252.4 
4,452.1 
Operating costs and expenses:
 
 
 
Cost of sales
4,361.5 1
3,015.5 1
3,245.3 1
Operating expenses
418.7 
398.5 
419.9 
General and administrative
128.6 
122.5 
136.9 
Loss on disposition of assets
13.2 
1.2 
Depreciation and amortization
545.3 
503.9 
387.3 
Impairments
17.1 
873.3 
1,563.4 
Gain on litigation settlement
(26.0)
Total operating costs and expenses
5,445.2 
4,926.9 
5,754.0 
Operating income (loss)
294.4 
(674.5)
(1,301.9)
Other income (expense):
 
 
 
Interest expense, net of interest income
(190.4)
(189.5)
(103.3)
Gain on extinguishment of debt
9.0 
Income (loss) from unconsolidated affiliates
9.6 
(19.9)
20.4 
Other income
0.6 
0.3 
0.8 
Total other expense
(171.2)
(209.1)
(82.1)
Income (loss) before non-controlling interest and income taxes
123.2 
(883.6)
(1,384.0)
Income tax benefit (provision)
196.8 
(4.6)
(25.7)
Net income (loss)
320.0 
(888.2)
(1,409.7)
Net income (loss) attributable to non-controlling interest
107.2 
(428.2)
(1,054.5)
Net income (loss) attributable to EnLink Midstream, LLC
212.8 
(460.0)
(355.2)
Devon investment interest in net income
1.8 
EnLink Midstream, LLC interest in net income (loss)
$ 212.8 
$ (460.0)
$ (357.0)
Net income (loss) attributable to EnLink Midstream, LLC per unit:
 
 
 
Basic common unit (in dollars per share)
$ 1.18 
$ (2.56)
$ (2.17)
Diluted common unit (in dollars per share)
$ 1.17 
$ (2.56)
$ (2.17)
Consolidated Statements of Operations (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Income Statement [Abstract]
 
 
 
Related party cost of sales
$ 211.0 
$ 150.1 
$ 141.3 
Consolidated Statements of Comprehensive Income (Loss) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
 
 
 
Net income (loss)
$ 320.0 
$ (888.2)
$ (1,409.7)
Loss on designated cash flow hedge, net of tax benefit and amortization to interest expense
(2.0)1
1
1
Comprehensive income (loss)
318.0 
(888.2)
(1,409.7)
Comprehensive income (loss) attributable to non-controlling interest
105.6 
(428.2)
(1,054.5)
Comprehensive income (loss) attributable to EnLink Midstream, LLC
$ 212.4 
$ (460.0)
$ (355.2)
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
 
Derivatives qualifying as hedges, tax
$ 0.2 
Consolidated Statements of Changes in Members' Equity (USD $)
In Millions, except Share data, unless otherwise specified
Total
Common Units
Net Devon Investment
Accumulated Other Comprehensive Loss
Non-Controlling Interest
Redeemable Non-Controlling Interest (Temporary Equity)
Redeemable noncontrolling interest, beginning balance at Dec. 31, 2014
 
 
 
 
 
$ 0 
Member equity, beginning balance at Dec. 31, 2014
7,074.8 
2,774.3 
103.7 
 
4,196.8 
 
Units outstanding, beginning balance (in shares) at Dec. 31, 2014
 
164,100,000 
 
 
 
 
Increase (Decrease) in Members' Equity
 
 
 
 
 
 
Issuance of common units by ENLK
384.4 
 
 
 
384.4 
 
Conversion of restricted units for common units, net of units withheld for taxes
(2.9)
(2.9)
 
 
 
 
Conversion of restricted units for common units, net of units withheld for taxes (in shares)
 
100,000 
 
 
 
 
Non-controlling interest’s impact of conversion of restricted units
(2.5)
 
 
 
(2.5)
 
Unit-based compensation
36.1 
18.5 
 
 
17.6 
 
Change in equity due to issuance of units by ENLK
(5.2)
8.5 
 
 
(13.7)
 
Non-controlling interest distributions
(359.5)
 
 
 
(359.5)
7.0 
Non-controlling interest contribution
16.4 
 
 
 
16.4 
 
Distributions to members
(162.8)
(162.8)
 
 
 
 
Adjustment related to mandatory redemption of E2 non-controlling interest
(5.4)
 
 
 
(5.4)
 
Redeemable non-controlling interest
(7.0)
 
 
 
(7.0)
 
Contribution from Devon to ENLC
7.1 
7.1 
 
 
 
 
Contribution from Devon to ENLK
27.8 
 
25.6 
 
2.2 
 
Distribution attributable to VEX interests transferred (Note 3)
(166.7)
 
(131.1)
 
(35.6)
 
Net income (loss)
(1,409.7)
(357.0)
1.8 
 
(1,054.5)
 
Increase (Decrease) in Temporary Equity
 
 
 
 
 
 
Redeemable non-controlling interest
(359.5)
 
 
 
(359.5)
7.0 
Redeemable noncontrolling interest, ending balance at Dec. 31, 2015
 
 
 
 
 
7.0 
Member equity, end balance at Dec. 31, 2015
5,424.9 
2,285.7 
 
3,139.2 
 
Units outstanding, end balance (in shares) at Dec. 31, 2015
 
164,200,000 
 
 
 
 
Increase (Decrease) in Members' Equity
 
 
 
 
 
 
Issuance of common units by ENLK
167.5 
 
 
 
167.5 
 
Issuance of Preferred Units by ENLK
724.1 
 
 
 
724.1 
 
Issuance of common units
214.9 
214.9 
 
 
 
 
Issuance of common units (in shares)
 
15,600,000 
 
 
 
 
Conversion of restricted units for common units, net of units withheld for taxes
(1.2)
(1.2)
 
 
 
 
Conversion of restricted units for common units, net of units withheld for taxes (in shares)
 
200,000 
 
 
 
 
Non-controlling interest’s impact of conversion of restricted units
(1.2)
 
 
 
(1.2)
 
Unit-based compensation
30.3 
15.1 
 
 
15.2 
 
Change in equity due to issuance of units by ENLK
(7.1)
11.8 
 
 
(18.9)
 
Non-controlling interest distributions
(382.4)
 
 
 
(382.4)
(1.8)
Non-controlling interest contribution
167.9 
 
 
 
167.9 
 
Distributions to members
(185.4)
(185.4)
 
 
 
 
Contribution from Devon to ENLK
1.5 
 
 
 
1.5 
 
Net income (loss)
(888.2)
(460.0)
 
 
(428.2)
 
Increase (Decrease) in Temporary Equity
 
 
 
 
 
 
Redeemable non-controlling interest
(382.4)
 
 
 
(382.4)
(1.8)
Redeemable noncontrolling interest, ending balance at Dec. 31, 2016
 
 
 
 
 
5.2 
Member equity, end balance at Dec. 31, 2016
5,265.6 
1,880.9 
 
3,384.7 
 
Units outstanding, end balance (in shares) at Dec. 31, 2016
180,049,316 
180,000,000 
 
 
 
 
Increase (Decrease) in Members' Equity
 
 
 
 
 
 
Issuance of common units by ENLK
106.9 
 
 
 
106.9 
 
Issuance of Preferred Units by ENLK
394.0 
 
 
 
394.0 
 
Conversion of restricted units for common units, net of units withheld for taxes
(4.8)
(4.8)
 
 
 
 
Conversion of restricted units for common units, net of units withheld for taxes (in shares)
 
600,000 
 
 
 
 
Non-controlling interest’s impact of conversion of restricted units
(5.3)
 
 
 
(5.3)
 
Unit-based compensation
42.7 
21.3 
 
 
21.4 
 
Change in equity due to issuance of units by ENLK
0.1 
 
 
 
0.1 
 
Non-controlling interest distributions
(433.1)
 
 
 
(433.1)
(0.6)
Non-controlling interest contribution
57.3 
 
 
 
57.3 
 
Distributions to members
(186.0)
(186.0)
 
 
 
 
Contribution from Devon to ENLK
1.3 
 
 
 
1.3 
 
Loss on designated cash flow hedge
(2.0)
 
 
(2.0)
 
 
Net income (loss)
320.0 
212.8 
 
 
107.2 
 
Increase (Decrease) in Temporary Equity
 
 
 
 
 
 
Redeemable non-controlling interest
(433.1)
 
 
 
(433.1)
(0.6)
Redeemable noncontrolling interest, ending balance at Dec. 31, 2017
 
 
 
 
 
4.6 
Member equity, end balance at Dec. 31, 2017
$ 5,556.7 
$ 1,924.2 
 
$ (2.0)
$ 3,634.5 
 
Units outstanding, end balance (in shares) at Dec. 31, 2017
180,600,728 
180,600,000 
 
 
 
 
Consolidated Statements of Cash Flows (USD $)
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Cash flows from operating activities:
 
 
 
Net income (loss)
$ 320,000,000 
$ (888,200,000)
$ (1,409,700,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Impairments
17,100,000 
873,300,000 
1,563,400,000 
Depreciation and amortization
545,300,000 
503,900,000 
387,300,000 
Loss on disposition of assets
13,200,000 
1,200,000 
Gain on extinguishment of debt
(9,000,000)
Deferred tax expense (benefit)
(197,200,000)
2,100,000 
22,600,000 
Non-cash unit-based compensation
48,100,000 
30,300,000 
36,100,000 
(Gain) loss on derivatives recognized in net income (loss)
4,200,000 
11,100,000 
(9,400,000)
Cash settlements on derivatives
(11,200,000)
10,500,000 
17,100,000 
Amortization of debt issue costs, net (premium) discount of notes and installment payable
29,300,000 
53,400,000 
400,000 
Distribution of earnings from unconsolidated affiliates
13,300,000 
3,100,000 
21,600,000 
(Income) loss from unconsolidated affiliates
(9,600,000)
19,900,000 
(20,400,000)
Other operating activities
600,000 
900,000 
(1,200,000)
Changes in assets and liabilities net of assets acquired and liabilities assumed:
 
 
 
Accounts receivable, accrued revenue and other
(189,400,000)
(118,100,000)
197,500,000 
Natural gas and NGLs inventory, prepaid expenses and other
(23,500,000)
18,700,000 
(6,700,000)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities
162,100,000 
132,300,000 
(171,400,000)
Net cash provided by operating activities
700,100,000 
666,400,000 
628,400,000 
Cash flows from investing activities, net of assets acquired and liabilities assumed:
 
 
 
Additions to property and equipment
(790,800,000)
(663,000,000)
(572,300,000)
Acquisition of business, net of cash acquired
(791,500,000)
(524,200,000)
Proceeds from insurance settlement
400,000 
300,000 
2,900,000 
Proceeds from sale of unconsolidated affiliate investment
189,700,000 
Proceeds from sale of property
2,300,000 
93,100,000 
1,000,000 
Investment in unconsolidated affiliates
(12,600,000)
(73,800,000)
(25,800,000)
Distribution from unconsolidated affiliates in excess of earnings
200,000 
54,600,000 
21,100,000 
Net cash used in investing activities
(610,800,000)
(1,380,300,000)
(1,097,300,000)
Cash flows from financing activities:
 
 
 
Proceeds from borrowings
2,381,800,000 
2,150,400,000 
3,204,400,000 
Payments on borrowings
(2,123,400,000)
(1,917,500,000)
(2,134,300,000)
Payment of installment payable for EnLink Oklahoma T.O. acquisition
(250,000,000)
Debt financing costs
(5,500,000)
(4,700,000)
(9,600,000)
Proceeds from issuance of ENLK common units
106,900,000 
167,500,000 
24,400,000 
Distributions to non-controlling interest
(433,700,000)
(384,200,000)
(359,500,000)
Distribution to members
(186,000,000)
(185,400,000)
(162,800,000)
Distribution to Devon for VEX interests transferred (Note 3)
(166,700,000)
Contributions by non-controlling interest
57,300,000 
167,900,000 
16,400,000 
Contribution from Devon
1,300,000 
1,500,000 
27,800,000 
Other financing activities
(12,500,000)
(12,000,000)
(21,600,000)
Net cash provided by (used in) financing activities
(69,800,000)
707,600,000 
418,500,000 
Net increase (decrease) in cash and cash equivalents
19,500,000 
(6,300,000)
(50,400,000)
Cash and cash equivalents, beginning of period
11,700,000 
18,000,000 
68,400,000 
Cash and cash equivalents, end of period
31,200,000 
11,700,000 
18,000,000 
Cash paid for interest
165,900,000 
133,700,000 
110,000,000 
Cash paid (refunded) for income taxes
3,300,000 
(7,000,000)
13,700,000 
Series B Preferred Units
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from issuance of ENLK Preferred Units
724,100,000 
Series C Preferred Units
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from issuance of ENLK Preferred Units
$ 394,000,000 
$ 0 
$ 0 
Organization and Summary of Significant Agreements
Organization and Summary of Significant Agreements
(1) Organization and Summary of Significant Agreements

(a) Organization of Business and Nature of Business

EnLink Midstream, LLC (“ENLC”) is a publicly traded Delaware limited liability company formed in 2013. Effective as of March 7, 2014, EnLink Midstream, Inc. (“EMI”) merged with and into a wholly-owned subsidiary of the Company and Acacia Natural Gas Corp I, Inc. (“Acacia”), formerly a wholly-owned subsidiary of Devon Energy Corporation (“Devon”), merged with and into a wholly-owned subsidiary of the Company (collectively, the “Mergers”). Pursuant to the Mergers, each of EMI and New Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. EMI owns common units representing an approximate 5.0% limited partner interest in EnLink Midstream Partners, LP (the “Partnership” or “ENLK”) as of December 31, 2017 and also owns EnLink Midstream GP, LLC (the “General Partner”). Acacia directly owned a 50% limited partner interest in Midstream Holdings, which was formerly a wholly-owned subsidiary of Devon. Upon closing of the Business Combination (as defined below), ENLC issued 115,495,669 units to a wholly-owned subsidiary of Devon, represent approximately 64.0% of the outstanding limited liability company interests in ENLC as of December 31, 2017. Concurrently with the consummation of the Mergers, a wholly-owned subsidiary of ENLK acquired the remaining 50% of the outstanding limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the Mergers, the “Business Combination”). The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.”

In 2015, Acacia contributed the remaining 50% interest in Midstream Holdings to ENLK in exchange for 68.2 million ENLK common units in two separate drop down transactions, with 25% contributed in February 2015 and 25% contributed in May 2015 (the “EMH Drop Downs”). After giving effect to the EMH Drop Downs, ENLK owns 100% of Midstream Holdings. As a result of the EMH Drop Downs, Acacia owned approximately 16.7% of the limited partner interests in ENLK as of December 31, 2017, which brings ENLC’s total ownership, through its wholly-owned subsidiaries, of limited partner interests in ENLK to 21.7% as of December 31, 2017.

In addition, in April 2015, ENLK acquired the Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in South Texas (VEX”), together with 100% of the voting equity interests (the “VEX interests”) in certain entities, from Devon in a drop down transaction (the “VEX Drop Down”).

Effective as of January 7, 2016, ENLK acquired 83.9% of the outstanding equity interests in EnLink Oklahoma T.O., and ENLC acquired the remaining 16.1% equity interests in EnLink Oklahoma T.O. Since we control EnLink Oklahoma T.O., we reflect our ownership in EnLink Oklahoma T.O. on a consolidated basis in the consolidated financial statements and related disclosures. See “Note 3—Acquisitions” for further discussion.

Our assets consist of equity interests in ENLK and EnLink Oklahoma T.O. ENLK is a Delaware publicly traded limited partnership formed on July 12, 2002 and is engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or natural gas liquids (“NGLs”), condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. EnLink Oklahoma T.O. is a partnership held by us and ENLK, and is engaged in the gathering and processing of natural gas. As of December 31, 2017, our interests in ENLK consisted of the following:

88,528,451 common units representing an aggregate 21.7% limited partner interest in ENLK;
100.0% ownership interest in EnLink Midstream GP, LLC, the general partner of ENLK (the “General Partner”), which owns a 0.4% general partner interest and all of the incentive distribution rights in ENLK; and
16.1% limited partner interest in EnLink Oklahoma T.O.

(b) Nature of Business

We primarily focus on providing midstream energy services, including:

gathering, compressing, treating, processing, transporting, storing and selling natural gas;
fractionating, transporting, storing, exporting and selling NGLs; and
gathering, transporting, stabilizing, storing, trans-loading and selling crude oil and condensate.

Our midstream energy asset network includes approximately 11,000 miles of pipelines, 20 natural gas processing plants with approximately 4.8 Bcf/d of processing capacity, 7 fractionators with approximately 260,000 Bbls/d of fractionation capacity, barge and rail terminals, product storage facilities, purchasing and marketing capabilities, brine disposal wells, a crude oil trucking fleet, and equity investments in certain joint ventures. Our operations are based in the United States, and our sales are derived primarily from domestic customers.

We connect the wells of producers in our market areas to our gathering systems, which consist of networks of pipelines that collect natural gas from points near producing wells and transport it to our processing plants or to larger pipelines for further transmission. We operate processing plants that remove NGLs from the natural gas stream that is transported to the processing plants by our own gathering systems or by third-party pipelines. In conjunction with our gathering and processing business, we may purchase natural gas and NGLs from producers and other supply sources and sell that natural gas or NGLs to utilities, industrial consumers, other markets and pipelines. Our transmission pipelines 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.

Our fractionators separate NGLs into separate purity products, including ethane, propane, iso-butane, normal butane and natural gasoline. Our fractionators receive NGLs primarily through our transmission lines that transport NGLs from East Texas and from our South Louisiana processing plants, and our fractionators also have the capability to receive NGLs by truck or rail terminals. We also have agreements pursuant to which third parties transport NGLs from our West Texas and Central Oklahoma operations to our NGL transmission lines that then transport the NGLs to our fractionators. In addition, we have NGL storage capacity to provide storage for customers.

Our crude oil and condensate business includes gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. We may purchase crude oil and condensate from producers and other supply sources and sell that crude oil and condensate through our terminal facilities that provide market access.

Across our businesses, we primarily earn our fees through various fee-based contractual arrangements, which include stated fee-only contract arrangements or arrangements with fee-based components where we purchase and resell commodities in connection with providing the related service and earn a net margin as our fee. We earn our net margin under our purchase and resell contract arrangements primarily as a result of stated service-related fees that are deducted from the price of the commodities purchased. While our transactions vary in form, the essential element of each transaction is the use of our assets to transport a product or provide a processed product to an end-user or other marketer or pipeline at the tailgate of the plant, barge terminal or pipeline.
Significant Accounting Policies
Significant Accounting Policies
(2) Significant Accounting Policies

(a) Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements.

(b) Management’s Use of Estimates

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

(c) Revenue Recognition

We generate the majority of our revenues from midstream energy services, including gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services and marketing, through various contractual arrangements, which include fee-based contract arrangements or arrangements where we purchase and resell commodities in connection with providing the related service and earn a net margin for our fee. While our transactions vary in form, the essential element of each transaction is the use of our assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal or pipeline. We reflect revenue as “Product sales” and “Midstream services” revenue on the consolidated statements of operations as follows:

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

Midstream services—Midstream services represent all other revenue generated as a result of performing our midstream services outlined above.

We recognize revenue for sales or services at the time the natural gas, NGLs, crude oil or condensate are delivered or at the time the service is performed at a fixed or determinable price. We generally accrue one month of sales and the related natural gas, NGL, condensate and crude oil purchases and reverse these accruals when the sales and purchases are invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. Except for fixed-fee based arrangements, we act as the principal in these purchase and sale transactions, bearing the risk and reward of ownership, scheduling the transportation of products and assuming credit risk. We account for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

Certain gathering and processing agreements in our Texas, Oklahoma and Crude and Condensate segments provide for quarterly or annual minimum volume commitments (“MVC” or “MVCs”), including MVCs from Devon from certain of our Barnett Shale assets in North Texas and our Cana plant in Oklahoma. Under these agreements, our customers agree to ship and/or process a minimum volume of production on our systems over an agreed time period. If a customer under such an agreement fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based upon the shortfall between actual production volumes and the MVC for that period. Some of these agreements also contain make-up right provisions that allow a customer to utilize gathering or processing fees in excess of the MVC in subsequent periods to offset shortfall amounts in previous periods. We record revenue under MVC contracts during periods of shortfall when it is known that the customer cannot, or will not, make up the deficiency in subsequent periods.

(d) Gas Imbalance Accounting

Quantities of natural gas and NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas or NGLs. We had imbalance payables of $7.3 million and $7.1 million at December 31, 2017 and 2016, respectively, which approximate the fair value of these imbalances. We had imbalance receivables of $5.8 million and $3.9 million at December 31, 2017 and 2016, respectively, which are carried at the lower of cost or market value. Imbalance receivables and imbalance payables are included in the line items “Accrued revenue and other” and “Accrued gas, NGLs, condensate and crude oil purchases,” respectively, on the consolidated balance sheets.

(e) Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(f) Income Taxes

Certain of our operations are subject to income taxes assessed by the federal and various state jurisdictions in the U.S. Additionally, certain of our operations are subject to tax assessed by the state of Texas that is computed based on modified gross margin as defined by the State of Texas. The Texas franchise tax is presented as income tax expense in the accompanying statements of operations.

We account for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In the event interest or penalties are incurred with respect to income tax matters, our policy will be to include such items in income tax expense.

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

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

(h) Property and Equipment

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

The components of property and equipment are as follows (in millions):
 
Year Ended December 31,
 
2017
 
2016
Transmission assets
$
1,338.7

 
$
1,191.7

Gathering systems
4,040.9

 
3,530.9

Gas processing plants
3,401.8

 
3,163.0

Other property and equipment
157.8

 
149.5

Construction in process
180.8

 
345.7

Property and equipment
$
9,120.0

 
$
8,380.8

Accumulated depreciation
(2,533.0
)
 
(2,124.1
)
Property and equipment, net of accumulated depreciation
$
6,587.0

 
$
6,256.7



Depreciation is calculated using the straight-line method based on the estimated useful life of each asset, as follows:
 
Useful Lives
Transmission assets
20 - 25 years
Gathering systems
20 - 25 years
Gas processing plants
20 - 25 years
Other property and equipment
3 - 15 years


Depreciation expense of $418.2 million, $386.9 million and $331.3 million was recorded for the years ended December 31, 2017, 2016 and 2015, respectively.

Gain or Loss on Disposition. Upon the disposition or retirement of property and equipment, any gain or loss is recognized in operating income in the statement of operations. For the year ended December 31, 2017, we disposed of assets with a net book value of $8.4 million, and these dispositions primarily related to the retirement of compressors due to fire damage. This decrease in book value was offset by $6.1 million in expected insurance settlements and $2.3 million of proceeds from the sale of property, resulting in no gain or loss on disposition of assets in the consolidated statement of operations for the year ended December 31, 2017.

For the year ended December 31, 2016, we retired or sold net property and equipment of $106.6 million, which was offset by $0.3 million of insurance settlements and $93.1 million of proceeds from the sale of property, resulting in a loss on disposition of assets of $13.2 million. The loss on disposition of assets primarily related to the sale of the North Texas Pipeline System (“NPTL”), a 140-mile natural gas transportation pipeline, that resulted in net proceeds of $84.6 million and a loss on sale of $13.4 million.

For the year ended December 31, 2015, we retired net property and equipment of $5.1 million, which was offset by $2.9 million of insurance settlements and $1.0 million of proceeds from the sale of property. This resulted in a loss on disposition of assets of $1.2 million, which primarily relates to the retirement of a compressor due to fire damage. Additionally, we collected $2.4 million of business interruption proceeds from our insurance carrier that was presented in the “Midstream services” revenue line item in the consolidated statement of operations for the year ended December 31, 2015.

Impairment Review. In accordance with ASC 360, Property, Plant and Equipment, we evaluate long-lived assets of identifiable business activities for potential impairment whenever events or changes in circumstances indicate that their carrying value 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.

When determining whether impairment of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our estimate of cash flows is based on assumptions regarding:

the future fee-based rate of new business or contract renewals;
the purchase and resale margins on natural gas, NGLs, crude oil and condensate;
the volume of natural gas, NGLs, crude oil and condensate available to the asset;
markets available to the asset;
operating expenses; and
future natural gas, NGLs, crude oil and condensate prices.

The amount of availability of natural gas, NGLs, crude oil and condensate to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas, NGL, crude oil and condensate prices. Projections of natural gas, NGL, crude oil and condensate volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:

changes in general economic conditions in regions in which our markets are located;
the availability and prices of natural gas, NGLs, crude oil and condensate supply;
our ability to negotiate favorable sales agreements;
the risks that natural gas, NGLs, crude oil and condensate exploration and production activities will not occur or be successful;
our dependence on certain significant customers, producers and transporters of natural gas, NGLs, crude oil and condensate; and
competition from other midstream companies, including major energy companies.

For the year ended December 31, 2017, we recognized impairments on property and equipment of $17.1 million, which related to the carrying values of rights-of-way that we are no longer using and an abandoned brine disposal well. For the year ended December 31, 2015, we recognized a $12.1 million impairment on property and equipment, primarily related to costs associated with the cancellation of various capital projects in our Texas, Louisiana, and Crude and Condensate segments.

(i) Comprehensive Income (Loss)

Comprehensive income (loss) is composed of net income (loss), which consists of the effective portion of gains or losses on derivative financial instruments that qualify as cash flow hedges pursuant to ASC 815, Derivatives and Hedging (“ASC 815”). For the year ended December 31, 2017, we reclassified an immaterial amount of losses from accumulated other comprehensive income (loss) to earnings. For additional information, see “Note 13—Derivatives.”

(j) Equity Method of Accounting

We account for investments where we do not control the investment but have the ability to exercise significant influence using the equity method of accounting. Under this method, unconsolidated affiliate investments are initially carried at the acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received.

We evaluate our unconsolidated affiliate investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable. We recognize impairments of our investments as a loss from unconsolidated affiliates on our consolidated statements of operations. For additional information, see “Note 11—Investment in Unconsolidated Affiliates.”

(k) Goodwill

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. For additional information regarding our assessment of goodwill for impairment, see “Note 4—Goodwill and Intangible Assets.”

(l) 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. For additional information regarding our intangible assets, including our assessment of intangible assets for impairment, seeNote 4—Goodwill and Intangible Assets.”

(m) Asset Retirement Obligations

We recognize liabilities for retirement obligations associated with our pipelines and processing and fractionation facilities. Such liabilities are recognized when there is a legal obligation associated with the retirement of the assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Our retirement obligations include estimated environmental remediation costs that arise from normal operations and are associated with the retirement of the long-lived assets. The asset retirement cost is depreciated using the straight-line depreciation method similar to that used for the associated property and equipment. For additional information, seeNote 10—Asset Retirement Obligations.”

(n) Other Long-Term Liabilities

Other current and long-term liabilities include a liability related to an onerous performance obligation assumed in the Business Combination of $26.9 million and $44.8 million as of December 31, 2017 and 2016, respectively. We have one delivery contract that requires us to deliver a specified volume of gas each month at an indexed base price with a term to mid-2019. We realize a loss on the delivery of gas under this contract each month based on current prices. The fair value of this onerous performance obligation was based on forecasted discounted cash obligations in excess of market under this gas delivery contract in March 2014. The liability is reduced each month as delivery is made over the remaining life of the contract with an offsetting reduction in purchased gas costs.

(o) Derivatives

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

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

We periodically enter into interest rate swaps in connection with new debt issuances. During the debt issuance process, we are exposed to variability in future long-term debt interest payments that may result from changes in the benchmark interest rate (commonly the U.S. Treasury yield) prior to the debt being issued. In order to hedge this variability, we enter into interest rate swaps to effectively lock in the benchmark interest rate at the inception of the swap. Prior to 2017, we did not designate interest rate swaps as hedges and, therefore, included the associated settlement gains and losses as interest expense on the consolidated statements of operations.

In May 2017, we entered into an interest rate swap in connection with the issuance of our senior unsecured notes due June 1, 2047 (the “2047 Notes”). In accordance with ASC 815, we designated this swap as a cash flow hedge. Upon settlement of the interest rate swap in May 2017, we recorded the associated $2.2 million settlement loss in accumulated other comprehensive loss on the consolidated balance sheets. We will amortize the settlement loss into interest expense on the consolidated statements of operations over the term of the 2047 Notes.

For additional information, see “Note 13—Derivatives.”

(p) Concentrations of Credit Risk

Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade accounts receivable and commodity financial instruments. Management believes the risk is limited, other than our exposure to Devon discussed below, since our customers represent a broad and diverse group of energy marketers and end users. In addition, we continually monitor and review the credit exposure of our marketing counter-parties, and letters of credit or other appropriate security are obtained when considered necessary to limit the risk of loss. We record reserves for uncollectible accounts on a specific identification basis since there is not a large volume of late paying customers. We had a reserve for uncollectible receivables of $0.3 million and $0.1 million as of December 31, 2017 and 2016, respectively.

For the years ended December 31, 2017, 2016 and 2015, we had two customers that individually represented greater than 10.0% of our consolidated revenues. Dow Hydrocarbons & Resources LLC (“Dow Hydrocarbons”) is located in the Louisiana segment and represented 11.2%, 10.8% and 11.7% of our consolidated revenues for the years ended December 31, 2017, 2016 and 2015, respectively. The affiliate transactions with Devon represented 14.4%, 18.5% and 16.6% of our consolidated revenues for the years ended December 31, 2017, 2016 and 2015, respectively. Devon and Dow Hydrocarbons represent a significant percentage of revenues, and the loss of either as a customer would have a material adverse impact on our results of operations because the gross operating margin received from transactions with these customers is material to us.

(q) Environmental Costs

Environmental expenditures are expensed or capitalized depending on the nature of the expenditures and the future economic benefit. Expenditures that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or a discounted basis when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. Environmental expenditures were $0.9 million and $3.5 million for the years ended December 31, 2017 and 2015. For the year ended December 31, 2016, such expenditures were not material.

(r) Unit-Based Awards

We recognize compensation cost related to all unit-based awards in our consolidated financial statements in accordance with ASC 718, Compensation—Stock Compensation (“ASC 718”). We and ENLK each have similar unit-based payment plans for employees. Unit-based compensation associated with ENLC’s unit-based compensation plans awarded to directors, officers and employees of our general partner are recorded by us since ENLC has no substantial or managed operating activities other than its interests in us and EnLink Oklahoma T.O. For additional information, see “Note 12—Employee Incentive Plans.”

(s) Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. For additional information, see “Note 15—Commitments and Contingencies.”

(t) Debt Issuance Costs

Costs incurred in connection with the issuance of long-term debt are deferred and recorded as interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs. Unamortized debt issuance costs totaling $26.2 million and $24.6 million as of December 31, 2017 and 2016, respectively, are included in “Long-term debt” on the consolidated balance sheets as a direct reduction from the carrying amount of long-term debt. Debt issuance costs are amortized into interest expense using the straight-line method over the term of the related debt issuance.

(u) Legal Costs Expected to be Incurred in Connection with a Loss Contingency

Legal costs incurred in connection with a loss contingency are expensed as incurred.

(v) Redeemable Non-Controlling Interest

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

(w) Adopted Accounting Standards

In March 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which amends ASC Topic 718, Compensation Stock Compensation (“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 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 ASU 2016-09 did not materially affect the consolidated statement of operations for the year ended December 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 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 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.

(x) 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 that 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 they expect to be entitled in exchange for transferring goods or services to a customer. ASC 606 will also require significantly expanded disclosures containing qualitative and quantitative information regarding the 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 will adopt ASC 606 using the modified retrospective method for annual and interim reporting periods beginning January 1, 2018.

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 the adoption of ASC 606 will have a material impact on our results of operations, financial condition or cash flows. However, ASC 606 will affect how certain transactions are recorded in the financial statements. For each contract with a customer, we will need to identify our performance obligations, of which the identification includes careful evaluation of when control and the economic benefits of the commodities transfer to us. The evaluation of control will change the way we account for certain transactions, specifically those in which there is both a commodity purchase component and a service component. For contracts where control of commodities transfers to us before we perform our services, we generally have no performance obligation for our services, and accordingly, we will not consider these revenue-generating contracts. Based on that determination, all fees or fee-equivalent deductions stated in such contracts would reduce the cost to purchase commodities. Alternatively, for contracts where control of commodities transfers to us after we perform our services, we have performance obligations for our services. Accordingly, we will consider the satisfaction of these performance obligations as revenue-generating and recognize these fees as midstream service revenues at the time we satisfy our performance obligations. For contracts where control of commodities never transfers to us and we simply earn a fee for our services, we will recognize these fees as midstream services revenues at the time we satisfy our performance obligations. Based on our review of our performance obligations in our contracts with customers, we will change the statement of operations classification for certain transactions from revenue to cost of sales or from cost of sales to revenue. We estimate that the reclassification of revenues and costs will result in a net decrease in revenue of approximately 6-10%, although this estimate is based on historical information and could change based on commodity prices going forward. This reclassification of revenues and costs will have no effect on operating income and gross operating margin.

Our performance obligations represent promises to transfer a series of distinct goods or services that are satisfied over time and that are substantially the same to the customer. As permitted by ASC 606, we will utilize the practical expedient that allows an entity to recognize revenue in the amount to which the entity has a right to invoice, if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date. Accordingly, we will continue to recognize revenue at the time commodities are delivered or services are performed, so ASC 606 will not significantly affect the timing of revenue and expense recognition on our statements of operations.

Based on the disclosure requirements of ASC 606, upon adoption, we expect to provide expanded disclosures relating to our revenue recognition policies and how these relate to our revenue-generating contractual performance obligations. In addition, we expect to present revenues disaggregated based on the type of good or service in order to more fully depict the nature of our revenues.
Acquisitions
Acquisitions
(3) Acquisitions

LPC Acquisition

On January 31, 2015, we acquired 100% of the voting equity interests of LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $108.1 million. The transaction was accounted for using the acquisition method.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

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

Property and equipment
29.8

Intangibles
43.2

Goodwill
29.6

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



We recognized intangible assets related to customer relationships and trade name. The acquired intangible assets related to customer relationships are amortized on a straight-line basis over the estimated customer life of approximately 10 years. Goodwill recognized from the acquisition primarily related to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill was allocated to our Crude and Condensate segment and was subsequently impaired during the year ended December 31, 2016.

We incurred $0.3 million of direct transaction costs for the year ended December 31, 2015. These costs are included in general and administrative costs in the accompanying consolidated statements of operations.

For the period from January 31, 2015 to December 31, 2015, we recognized $1.1 billion of revenues and $0.9 million of net income related to the assets acquired.

Coronado Acquisition

On March 16, 2015, we acquired 100% of the voting equity interests in Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600.3 million. The purchase price consisted of $240.3 million in cash, 6,704,285 ENLK common units and 6,704,285 ENLK Class C Common Units.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

Purchase Price Allocation:
 
Assets acquired:
 
Current assets (including $1.4 million in cash)
$
20.8

Property and equipment
302.1

Intangibles
281.0

Goodwill
18.7

Liabilities assumed:
 
Current liabilities
(22.3
)
Total identifiable net assets
$
600.3



We recognized intangible assets related to customer relationships. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 10 to 20 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to our Texas segment.

We incurred $3.1 million of direct transaction costs for the year ended December 31, 2015. These costs are included in general and administrative expenses in the accompanying consolidated statements of operations.

For the period from March 16, 2015 to December 31, 2015, we recognized $182.0 million of revenues and $14.2 million of net loss related to the assets acquired.

Matador Acquisition

On October 1, 2015, we acquired 100% of the voting equity interests in a subsidiary of Matador Resources Company (“Matador”), which has gathering and processing assets operations in the Delaware Basin, for approximately $141.3 million. The transaction was accounted for using the acquisition method.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

Purchase Price Allocation:
 
Assets acquired:
 
Current assets
$
1.1

Property and equipment
35.5

Intangibles
98.8

Goodwill
10.7

Liabilities assumed:
 
Current liabilities
(4.8
)
Total identifiable net assets
$
141.3



We recognized intangible assets related to customer relationships. The acquired intangible assets are amortized on a straight-line basis over the estimated customer life of approximately 15 years. Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin. All such goodwill is allocated to our Texas segment.

We incurred $0.1 million of direct transaction costs for the year ended December 31, 2015. These costs are included in general and administrative expenses in the accompanying consolidated statements of operations.

For the period from October 1, 2015 to December 31, 2015, we recognized $5.6 million of revenues and $0.7 million of net loss related to the assets acquired.

Deadwood Acquisition

Prior to November 2015, we co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”). On November 16, 2015, we acquired Apache’s 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.1 million, all of which is considered property and equipment. The transaction was accounted for using the acquisition method. Direct transaction costs attributable to this acquisition were less than $0.1 million.

For the period from November 16, 2015 to December 31, 2015, we recognized $3.5 million of revenues and $1.3 million of net income related to the assets acquired.

VEX Pipeline Drop Down

On April 1, 2015, we acquired VEX, located in the Eagle Ford Shale in South Texas, together with 100% of the voting equity interests in certain entities, from Devon in the VEX Drop Down. The aggregate consideration paid by us consisted of $166.7 million in cash, 338,159 ENLK common units representing its limited partner interests with an aggregate value of approximately $9.0 million and our assumption of up to $40.0 million in certain construction costs related to VEX. The acquisition has been accounted for as an acquisition under common control under ASC 805, resulting in the retrospective adjustment of our prior results. As such, the VEX interests were recorded on our books at historical cost on the date of transfer of $131.0 million. The difference between the historical cost of the net assets and consideration given was $35.7 million and is recognized as a distribution to Devon. Construction costs paid by Devon during the first quarter of 2015 totaling $25.6 million are reflected as contributions from Devon to ENLK in our consolidated statements of changes in partners’ equity and consolidated statements of cash flows for the year ended December 31, 2015.

Pro Forma of Acquisitions for the Years Ended 2015

The following unaudited pro forma condensed financial information (in millions, except for per unit data) for the year ended December 31, 2015 gives effect to the January 2015 LPC acquisition, March 2015 Coronado acquisition, October 2015 Matador acquisition and the VEX Drop Down as if they had occurred on January 1, 2015. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results.

 
Year Ended December 31, 2015
Pro forma total revenues
$
4,585.5

Pro forma net loss
$
(1,413.0
)
Pro forma net loss attributable to EnLink Midstream, LLC
$
(355.5
)
Pro forma net loss per common unit:
 
Basic
$
(2.18
)
Diluted
$
(2.18
)

EnLink Oklahoma T.O. Acquisition

On January 7, 2016, ENLC and ENLK acquired an 16.1% and 83.9% voting interest, respectively, in EnLink Oklahoma T.O. for aggregate consideration of approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The second and final installments, each equal to $250.0 million, were paid in January 2017 and January 2018, respectively.

The first installment of approximately $1.02 billion was funded by (a) approximately $783.6 million in cash paid by ENLK, which was primarily derived from the issuance of Series B Cumulative Convertible Preferred Units (“Series B 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 considerations ENLC and ENLK paid and the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

Consideration:
 
Cash
$
805.8

Issuance of ENLC common units
214.9

ENLK’s total installment payable, net of discount of $79.1 million
420.9

Total consideration
$
1,441.6

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

Property 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 $4.4 million and $0.4 million of direct transaction costs for the year ended December 31, 2016 and December 31, 2015, respectively. These costs are incurred in general and administrative costs in the accompanying consolidated statements of operations.

For the period from January 7, 2016 to December 31, 2016, we recognized $246.1 million of revenues and $34.1 million of net loss related to the assets acquired.

Pro Forma of the EnLink Oklahoma T.O. Acquisition

The following unaudited pro forma condensed financial information (in millions, except for per unit data) for the year ended December 31, 2016 and 2015 gives effect to the January 2016 acquisition of EnLink Oklahoma T.O as if it had occurred on January 1, 2015. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transaction taken place on the dates indicated and is not intended to be a projection of future results.
 
Year Ended December 31,
 
2016
 
2015
Pro forma total revenues
$
4,254.4

 
$
4,647.8

Pro forma net loss
$
(879.9
)
 
$
(1,471.8
)
Pro forma net loss attributable to EnLink Midstream, LLC
$
(451.3
)
 
$
(368.4
)
Pro forma net loss per common unit:
 
 
 
Basic
$
(2.51
)
 
$
(2.05
)
Diluted
$
(2.51
)
 
$
(2.05
)
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.

The table below provides a summary of our change in carrying amount of goodwill (in millions) for the year ended December 31, 2016, by assigned reporting unit:
 
Texas
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
Year Ended December 31, 2016
 
 
 
 
 
 
 
 
 
Balance, beginning of period
$
703.5

 
$
190.3

 
$
93.2

 
$
1,426.9

 
$
2,413.9

Impairment
(473.1
)
 

 
(93.2
)
 
(307.0
)
 
(873.3
)
Acquisition adjustment
1.6

 

 

 

 
1.6

Balance, end of period
$
232.0

 
$
190.3

 
$

 
$
1,119.9

 
$
1,542.2



For the year ended December 31, 2017, there were no changes to the carrying amount of goodwill.

We evaluate goodwill for impairment annually as of October 31 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform a goodwill impairment test. We may elect to perform a goodwill impairment test without completing a qualitative assessment.

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.

Prior to January 2017, if a goodwill impairment test was elected or required, we performed a two-step goodwill impairment test. The first step involved comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeded its fair value, the second step of the process involved comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeded the implied fair value of that goodwill, the excess of the carrying value over the implied fair value was recognized as an impairment loss.

Effective January 2017, we elected to early adopt ASU 2017-04, Intangibles—Goodwill and Other (Topic 350)— Simplifying the Test for Goodwill Impairment, which simplified 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. Therefore, our annual impairment test as of October 31, 2017 was performed according to ASU 2017-04.

Impairment Analysis for the Year Ended December 31, 2015
 
During the third quarter of 2015, we determined that sustained weakness in the overall energy sector, driven by low commodity prices together with a decline in our unit price, caused a change in circumstances warranting an interim impairment test. We also performed our annual impairment analysis during the fourth quarter of 2015. Although our established annual effective date for this goodwill analysis is October 31, we updated the effective date for this impairment analysis for the 2015 annual period to December 31, 2015 due to continued declines in commodity prices and our unit price during the fourth quarter of 2015.

Using the fair value approaches described above, in step one of the goodwill impairment test, we determined that the estimated fair values of our Louisiana, Texas and Crude and Condensate reporting units were less than their carrying amounts, primarily related to commodity prices, volume forecasts and discount rates. Based on that determination, we performed the second step of the goodwill impairment test by measuring the amount of impairment loss and allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Based on this analysis, a goodwill impairment loss for our Louisiana, Texas, and Crude and Condensate reporting units in the amount of $1,328.2 million was recognized for the year ended December 31, 2015 and is included as an impairment loss in the consolidated statement of operations.
 
We concluded that the fair value of goodwill for our Oklahoma reporting unit exceeded its carrying value, and the amount of goodwill disclosed on the consolidated balance sheet associated with this reporting unit was recoverable. Therefore, no goodwill impairment was identified or recorded for this reporting unit as a result of our annual goodwill assessment.

Impairment Analysis for the Year Ended December 31, 2016

During February 2016, we determined that continued further weakness in the overall energy sector, driven by low commodity prices together with a further decline in our unit price subsequent to year-end, caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units. Based on this analysis, a goodwill impairment loss for our Texas, Crude and Condensate, and Corporate reporting units in the amount of $873.3 million was recognized in the first quarter of 2016 and is included as an impairment loss in the consolidated statement of operations for the year ended December 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 was recoverable. Therefore, no goodwill impairment was identified or recorded for this reporting unit as a result of our goodwill impairment analysis.

During our annual impairment test for 2016 performed as of October 31, 2016, we determined that no further impairments were required for the year ended December 31, 2016.

Impairment Analysis for the Year Ended December 31, 2017

During our annual impairment test for 2017 performed as of October 31, 2017, we determined that no impairments were required for the year ended December 31, 2017. The estimated fair value of our reporting units may be impacted in the future by a decline in our unit price or a prolonged period of lower commodity prices which may adversely affect our estimate of future cash flows, both of which could result in future goodwill impairment charges for our reporting units.

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 10 to 20 years.

The following table represents our change in carrying value of intangible assets for the periods stated (in millions):

 
Gross Carrying Amount
 
Accumulated Amortization
 
Net Carrying Amount
Year Ended December 31, 2017
 
 
 
 
 
Customer relationships, beginning of period
$
1,795.8

 
$
(171.6
)
 
$
1,624.2

Amortization expense

 
(127.1
)
 
(127.1
)
Customer relationships, end of period
$
1,795.8

 
$
(298.7
)
 
$
1,497.1

 
 
 
 
 
 
Year Ended December 31, 2016
 
 
 
 
 
Customer relationships, beginning of period
$
744.5

 
$
(54.6
)
 
$
689.9

Acquisitions
1,051.3

 

 
1,051.3

Amortization expense

 
(117.0
)
 
(117.0
)
Customer relationships, end of period
$
1,795.8

 
$
(171.6
)
 
$
1,624.2



For 2016 and 2015, we reviewed our various assets groups for impairment due to the triggering events described in the goodwill impairment analysis above. We utilized Level 3 fair value measurements in our impairment analysis, which included discounted cash flow assumptions by management consistent with those utilized in our goodwill impairment analysis. During 2016, the undiscounted cash flows of our assets exceeded their carrying values, and no impairment was recorded. During 2015, the undiscounted cash flows related to one of our asset groups in the Crude and Condensate segment were not in excess of its related carrying value. We estimated the fair value of this reporting unit and determined the fair values of certain intangible assets were not in excess of their carrying values. This resulted in a $223.1 million impairment of intangible assets in our Crude and Condensate segment, and this non-cash impairment charge was included as an impairment loss on the consolidated statement of operations for the year ended December 31, 2015. For the year ended December 31, 2017, we determined that no triggering events existed that would indicate an impairment of our intangibles assets.

The weighted average amortization period for intangible assets is 15.0 years. Amortization expense was approximately $127.1 million, $117.0 million, and $56.0 million for the years ended December 31, 2017, 2016 and 2015, respectively.

The following table summarizes our estimated aggregate amortization expense for the next five years and thereafter (in millions):
2018
$
123.4

2019
123.4

2020
123.4

2021
123.4

2022
123.4

Thereafter
880.1

Total
$
1,497.1

Related Party Transactions
Related Party Transactions
(5) Related Party Transactions

We engage in various transactions with Devon and other related parties. For the years ended December 31, 2017, 2016 and 2015, Devon was a significant customer to us. Devon accounted for 14.4%, 18.5% and 16.6% of our revenues for the years ended December 31, 2017, 2016 and 2015, respectively. We had an accounts receivable balance related to transactions with Devon of $102.7 million and $100.2 million as of December 31, 2017 and 2016, respectively. Additionally, we had an accounts payable balance related to transactions with Devon of $16.3 million and $10.4 million as of December 31, 2017 and 2016, respectively. Management believes these transactions are executed on terms that are fair and reasonable. The amounts from related party transactions are specified in the accompanying financial statements.

Gathering, Processing and Transportation Agreements Associated with Our Business Combination with Devon

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

These agreements provide Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by Devon. Pursuant to the gathering and processing agreements entered into on January 1, 2014, Devon has committed to deliver specified minimum daily volumes of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter. We recognized revenue under these agreements of $615.5 million, $611.8 million and $596.3 million for the years ended December 31, 2017, 2016 and 2015, respectively. Included in these amounts of revenue recognized is revenue from MVCs attributable to Devon of $81.9 million, $46.2 million, and $24.4 million for the years ended December 31, 2017, 2016 and 2015, respectively. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

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

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

EnLink Oklahoma T.O. Gathering and Processing Agreement with Devon

In January 2016, in connection with the acquisition of EnLink Oklahoma T.O., we acquired a gas gathering and processing agreement with Devon Energy Production Company, L.P. (“DEPC”) pursuant to which EnLink Oklahoma T.O. provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by DEPC. The agreement has an MVC that will remain in place during each calendar quarter for four years and an overall term of approximately 15 years. Additionally, the agreement provides EnLink Oklahoma T.O. with dedication of all of the natural gas owned or controlled by DEPC and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by DEPC. DEPC is entitled to firm service, meaning a level of gathering and processing service in which DEPC’s reserved capacity may not be interrupted, except due to force majeure, and may not be displaced by another customer or class of service. This agreement accounted for approximately $100.4 million and $34.4 million of our combined revenues for the years ended December 31, 2017 and 2016, respectively.

Cedar Cove Joint Venture
 
On November 9, 2016, we formed a joint venture (the “Cedar Cove JV”) with Kinder Morgan, Inc. consisting of gathering and compression assets in Blaine County, Oklahoma. Under a 15-year, fixed-fee agreement, all gas gathered by the Cedar Cove JV will be processed at our Central Oklahoma processing system. For the period from November 9, 2016 through December 31, 2016, revenue generated from processing gas from the Cedar Cove JV was immaterial. For the year ended December 31, 2017, we recorded service revenue of $5.4 million that is recorded as “Midstream services—related parties” on the consolidated statements of operations. In addition, for the year ended December 31, 2017, we recorded cost of sales of $30.6 million related to our purchase of residue gas and NGLs from the Cedar Cove JV subsequent to processing at our Central Oklahoma processing facilities.

Other Commercial Relationships with Devon

As noted above, we continue to maintain a customer relationship with Devon originally established prior to the Business Combination pursuant to which we provide gathering, transportation, processing and gas lift services to Devon in exchange for fee-based compensation under several agreements with Devon. The terms of these agreements vary, but the agreements began to expire in January 2016 and continue to expire through July 2021, renewing automatically for month-to-month or year-to-year periods unless canceled by Devon prior to expiration. In addition, we have agreements with Devon pursuant to which we purchase and sell NGLs, gas and crude oil and pay or receive, as applicable, a margin-based fee. These NGL, gas and crude oil purchase and sale agreements have month-to-month terms. These historical agreements collectively comprise $78.0 million, $107.2 million and $107.5 million of our combined revenue for the years ended December 31, 2017, 2016, and 2015, respectively.

VEX Transportation Agreement

In connection with the VEX Drop Down, we became party to a five-year transportation services agreement with Devon pursuant to which we provide transportation services to Devon on the VEX pipeline. This agreement includes a five-year MVC with Devon. The MVC was executed in June 2014, and the initial term expires July 2019. This agreement accounted for approximately $17.8 million, $18.7 million and $17.8 million of service revenues for the years ended December 31, 2017, 2016 and 2015, respectively.

Acacia Transportation Agreement

In connection with the consummation of the Business Combination, we entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which we provide transportation services to Devon on its Acacia line. This agreement accounted for approximately $13.8 million, $15.2 million and $16.4 million of our combined revenues for the years ended December 31, 2017, 2016 and 2015, respectively.

GCF Agreement

In connection with the consummation of the Business Combination, we entered into an agreement with a wholly-owned subsidiary of Devon pursuant to which Devon agreed, from and after the closing of the Business Combination, to hold for the benefit of Midstream Holdings the economic benefits and burdens of Devon’s 38.75% general partner interest in Gulf Coast Fractionators in Mont Belvieu, Texas. This agreement contributed approximately $12.6 million, $3.4 million and $13.0 million to our income from unconsolidated affiliate investment for the years ended December 31, 2017, 2016 and 2015, respectively.

Transactions with ENLK

We paid ENLK $2.4 million, $2.3 million and $2.1 million as reimbursement during the years ended December 31, 2017, 2016, and 2015, respectively, to cover our portion of administrative and compensation costs for officers and employees that perform services for ENLC. This reimbursement is evaluated on an annual basis. Officers and employees that perform services for us provide an estimate of the portion of their time devoted to such services. A portion of their annual compensation (including bonuses, payroll taxes and other benefit costs) is allocated to ENLC for reimbursement based on these estimates. In addition, an administrative burden is added to such costs to reimburse ENLK for additional support costs, including, but not limited to, consideration for rent, office support and information service support.

We paid ENLK $48.4 million and $31.5 million for our interest in EnLink Oklahoma T.O.s’ capital expenditures for the years ended December 31, 2017 and 2016, respectively. We pay our contribution for EnLink Oklahoma T.O.’s capital expenditures to ENLK monthly, net of EnLink Oklahoma T.O.’s adjusted EBITDA distributable to us, which is defined as earnings before depreciation and amortization and provision for income taxes and includes allocated expenses from ENLK.

On October 29, 2015, ENLK issued 2,849,100 common units at an offering price of $17.55 per common unit to a subsidiary of ours for aggregate consideration of approximately $50.0 million in a private placement transaction.

Tax Sharing Agreement

In connection with the consummation of the Business Combination, we, ENLK and Devon, entered into a tax sharing agreement providing for the allocation of responsibilities, liabilities and benefits relating to any tax for which a combined tax return is due. For the years ended December 31, 2017, 2016 and 2015 we incurred approximately $1.2 million, $2.3 million and $3.0 million, respectively, in taxes that are subject to the tax sharing agreement.
Long-Term Debt
Long-Term Debt
(6) Long-Term Debt

As of December 31, 2017 and 2016, long-term debt consisted of the following (in millions):

 
 
December 31, 2017
 
December 31, 2016
 
 
Outstanding Principal
 
Premium (Discount)
 
Long-Term Debt
 
Outstanding Principal
 
Premium (Discount)
 
Long-Term Debt
ENLK credit facility, due 2020 (1)
 
$

 
$

 
$

 
$
120.0

 
$

 
$
120.0

ENLC credit facility, due 2019 (2)
 
74.6

 

 
74.6

 
27.8

 

 
27.8

2.70% Senior unsecured notes due 2019
 
400.0

 
(0.1
)
 
399.9

 
400.0

 
(0.3
)
 
399.7

7.125% Senior unsecured notes due 2022
 

 

 

 
162.5

 
16.0

 
178.5

4.40% Senior unsecured notes due 2024
 
550.0

 
2.2

 
552.2

 
550.0

 
2.5

 
552.5

4.15% Senior unsecured notes due 2025
 
750.0

 
(1.0
)
 
749.0

 
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

 
(6.5
)
 
443.5

 
450.0

 
(6.6
)
 
443.4

5.45% Senior unsecured notes due 2047
 
500.0

 
(0.1
)
 
499.9

 

 

 

Debt classified as long-term
 
$
3,574.6

 
$
(6.3
)
 
3,568.3

 
$
3,310.3

 
$
9.6

 
3,319.9

Debt issuance cost (3)
 
 
 
 
 
(26.2
)
 
 
 
 
 
(24.6
)
Long-term debt, net of unamortized issuance cost
 
 
 
 
 
$
3,542.1

 
 
 
 
 
$
3,295.3

(1)
Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 2.3% at December 31, 2016.
(2)
Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.2% and 3.4% at December 31, 2017 and 2016, respectively.
(3)
Net of amortization of $12.9 million and $9.0 million at December 31, 2017 and 2016, respectively.

Maturities

Maturities for the long-term debt as of December 31, 2017 are as follows (in millions):
2018
$

2019
474.6

2020

2021

2022

Thereafter
3,100.0

Subtotal
3,574.6

Less: net discount
(6.3
)
Less: debt issuance cost
(26.2
)
Long-term debt, net of unamortized issuance cost
$
3,542.1



ENLC Credit Facility

 We have a $250.0 million revolving credit facility that matures on March 7, 2019 and includes a $125.0 million letter of credit subfacility (the “ENLC Credit Facility”). Our obligations under the ENLC Credit Facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 88,528,451 ENLK common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us and (iii) any additional equity interests subsequently pledged as collateral under the ENLC Credit Facility.

The ENLC Credit Facility contains certain financial, operational and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter, and include (i) maintaining a maximum consolidated leverage ratio (as defined in the ENLC Credit Facility, but generally computed as the ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the ENLC Credit Facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the ENLC Credit Facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) of 2.50 to 1.00 unless an investment grade event (as defined in the ENLC Credit Facility) occurs.

Borrowings under the ENLC Credit Facility bear interest at our option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin (ranging from 1.75% to 2.50%) 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 0.75% percent to 1.50%). The applicable margins vary depending on our leverage ratio. Upon breach by us of certain covenants governing the ENLC Credit Facility, amounts outstanding under the ENLC Credit Facility, if any, may become due and payable immediately and the liens securing the ENLC Credit Facility could be foreclosed upon. At December 31, 2017, ENLC was in compliance and expects to be in compliance with the covenants in the ENLC Credit Facility for at least the next twelve months.

As of December 31, 2017, there were no outstanding letters of credit and $74.6 million in outstanding borrowings under the ENLC Credit Facility, leaving approximately $175.4 million available for future borrowing.

ENLK Credit Facility

ENLK has a $1.5 billion unsecured revolving credit facility that matures on March 6, 2020, and includes a $500.0 million letter of credit subfacility (the “ENLK Credit Facility”). Under the ENLK Credit Facility, ENLK is permitted to (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under the ENLK 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 the ENLK Credit Facility by one year on each occasion. The ENLK 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 the ENLK Credit Facility and includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If ENLK consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, ENLK 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 the ENLK Credit Facility bear interest at ENLK’s 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 0.0% to 0.75%). The applicable margins vary depending on ENLK’s credit rating. If ENLK breaches certain covenants governing the ENLK Credit Facility, amounts outstanding under the ENLK Credit Facility, if any, may become due and payable immediately. At December 31, 2017, ENLK was in compliance and expect to be in compliance with the covenants in the ENLK Credit Facility for at least the next twelve months.

As of December 31, 2017, there were $9.8 million in outstanding letters of credit and no outstanding borrowings under the ENLK Credit Facility, leaving approximately $1.5 billion available for future borrowing.

Issuances and Redemptions of Senior Unsecured Notes

On March 7, 2014, ENLK recorded $196.5 million in aggregate principal amount of 7.125% senior unsecured notes (the “2022 Notes”) due on June 1, 2022 in the Business Combination. The interest payments on the 2022 Notes were due semi-annually in arrears in June and December. As a result of the Business Combination, the 2022 Notes were recorded at fair value in accordance with acquisition accounting at an amount of $226.0 million, including a premium of $29.5 million. On July 20, 2014, ENLK redeemed $18.5 million aggregate principal amount of the 2022 Notes for $20.0 million, including accrued interest. On September 20, 2014, ENLK redeemed an additional $15.5 million aggregate principal amount of the 2022 Notes for $17.0 million, including accrued interest. On June 1, 2017, ENLK redeemed the remaining $162.5 million in aggregate principal amount of its 2022 Notes at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174.1 million, which resulted in a gain on extinguishment of debt of $9.0 million for the year ended December 31, 2017.

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

On November 12, 2014, ENLK issued an additional $100.0 million aggregate principal amount of the 2024 Notes and $300.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 Notes”), at prices to the public of 104.007% and 99.452%, respectively, of their face value. The new 2024 Notes were offered as an additional issue of ENLK’s outstanding 2024 Notes issued on March 19, 2014. The 2024 Notes issued on March 19, 2014 and November 12, 2014 are treated as a single class of debt securities and have identical terms, other than the issue date. The 2045 Notes mature on April 1, 2045, and interest payments on the 2045 Notes are due semi-annually in arrears in April and October.

On May 12, 2015, ENLK issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of its 4.150% senior notes due 2025 (the “2025 Notes”) and an additional $150.0 million aggregate principal amount of 2045 Notes at prices to the public of 99.827% and 96.381%, respectively, of their face value. The 2025 Notes mature on June 1, 2025. Interest payments on the 2025 Notes are due semi-annually in arrears in June and December. The new 2045 Notes were offered as an additional issue of ENLK’s outstanding 2045 Notes issued on November 12, 2014. The 2045 Notes issued on November 12, 2014 and May 12, 2015 are treated as a single class of debt securities and have identical terms, other than the issue date.

On July 14, 2016, ENLK issued $500.0 million in aggregate principal amount of 4.850% senior notes due 2026 (the “2026 Notes”) at a price to the public of 99.859% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 2026 Notes are payable on January 15 and July 15 of each year. Net proceeds of approximately $495.7 million were used to repay outstanding borrowings under the ENLK Credit Facility and for general partnership purposes.

On May 11, 2017, ENLK issued $500.0 million in aggregate principal amount of 5.450% senior unsecured notes due June 1, 2047 (the “2047 Notes”) at a price to the public of 99.981% of their face value. Interest payments on the 2047 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2017. Net proceeds of approximately $495.2 million were used to repay outstanding borrowings under the ENLK Credit Facility and for general partnership purposes.

Senior Unsecured Note Redemption Provisions

Each issuance of the senior unsecured notes may be fully or partially redeemed prior to an early redemption date (see "Early Redemption Date" in table below) at a redemption price equal to the greater of: (i) 100% of the principal amount of the notes to be redeemed; or (ii) the sum of the remaining scheduled payments of principal and interest on the respective notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus a specified basis point premium (see "Basis Point Premium" in the table below); plus accrued and unpaid interest to, but excluding, the redemption date. At any time on or after the Early Redemption Date, the senior unsecured notes may be fully or partially redeemed at a redemption price equal to 100% of the principal amount of the applicable notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date. See applicable redemption provision terms below:


Issuance
 
Maturity Date of Notes
 
Early Redemption Date
 
Basis Point Premium
2019 Notes
 
April 1, 2019
 
Prior to March 1, 2019
 
20 Basis Points
2024 Notes
 
April 1, 2024
 
Prior to January 1, 2024
 
25 Basis Points
2025 Notes
 
June 1, 2025
 
Prior to March 1, 2025
 
30 Basis Points
2026 Notes
 
July 15, 2026
 
Prior to April 15, 2026
 
50 Basis Points
2044 Notes
 
April 1, 2044
 
Prior to October 1, 2043
 
30 Basis Points
2045 Notes
 
April 1, 2045
 
Prior to October 1, 2044
 
30 Basis Points
2047 Notes
 
June 1, 2047
 
Prior to June 1, 2047
 
40 Basis Points


Senior Unsecured Note Indentures

The indentures governing the senior unsecured notes contain covenants that, among other things, limit ENLK’s ability to create or incur certain liens or consolidate, merge or transfer all or substantially all of ENLK’s assets.

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

failure to pay any principal or interest when due;
failure to observe any other agreement, obligation or other covenant in the indenture, subject to the cure periods for certain failures; and
bankruptcy or other insolvency events involving ENLK.

If an event of default relating to bankruptcy or other insolvency events occurs, the senior unsecured notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the senior unsecured notes may accelerate the maturity of the senior unsecured notes and exercise other rights and remedies. At December 31, 2017, ENLK was in compliance and expects to be in compliance with the covenants in the senior unsecured notes for at least the next twelve months.
Income Taxes
Income Taxes
(7) Income Taxes

The components of our income tax provision (benefit) are as follows (in millions):

 
Year Ended December 31,
 
2017
 
2016
 
2015
Current income tax provision
$
0.4

 
$
2.5

 
$
3.1

Deferred tax provision (benefit)
(197.2
)
 
2.1

 
22.6

Total income tax provision (benefit)
$
(196.8
)
 
$
4.6

 
$
25.7



The following schedule reconciles total income tax expense (benefit) and the amount calculated by applying the statutory U.S. federal tax rate to income before income taxes (in millions):

 
Year Ended December 31,
 
2017
 
2016
 
2015
Expected income tax provision (benefit) based on federal statutory rate of 35%
$
5.6

 
$
(159.4
)
 
$
(116.0
)
State income taxes, net of federal benefit
0.4

 
(11.4
)
 
(8.3
)
Statutory rate change (1)
(210.6
)
 

 

Income tax expense from partnership
0.9

 
1.2

 
(0.5
)
Unit-based compensation (2)
2.9

 

 

Non-deductible expense related to asset impairment

 
173.8

 
149.4

Other
4.0

 
0.4

 
1.1

Total income tax provision (benefit)
$
(196.8
)
 
$
4.6

 
$
25.7

(1)
On December 22, 2017, the Tax Cuts and Jobs Act was signed into legislation which resulted in a change in the federal statutory corporate rate from 35% to 21%, effective January 1, 2018. Accordingly, we have recorded a total tax benefit of $210.6 million due to a remeasurement of deferred tax liabilities. Of this amount, $185.7 million was related to ENLC’s standalone deferred tax liabilities, and $24.9 million was related to ENLK’s re-measurement of deferred tax liabilities of its wholly-owned corporate subsidiaries.
(2)
Related to tax deficiencies recorded upon the vesting of restricted incentive units, which were recognized in accordance with the adoption of ASU 2016-09. For additional information on ASU 2016-09, see “Note 2—Significant Accounting Policies.”

Deferred Tax Assets and Liabilities

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Our deferred income tax assets and liabilities as of December 31, 2017 and 2016 are as follows (in millions):

 
December 31, 2017
 
December 31, 2016
Deferred income tax assets:
 
 
 
Federal net operating loss carryforward
$
54.5

 
$
59.5

State net operating loss carryforward
14.2

 
6.5

Asset retirement obligations and other

 
0.9

Total deferred tax assets
68.7

 
66.9

Deferred tax liabilities:
 
 
 
Property, equipment, and intangible assets (1)
(414.9
)
 
(609.5
)
Deferred tax liability, net
$
(346.2
)
 
$
(542.6
)
(1)
Includes our investment in ENLK and primarily relates to differences between the book and tax bases of property and equipment.

As of December 31, 2017, we had federal net operating loss carryforwards of $259.4 million that represent a net deferred tax asset of $54.5 million. As of December 31, 2017, we had state net operating loss carryforwards of $262.7 million that represent a net deferred tax asset of $14.2 million. These carryforwards will begin expiring in 2028 through 2036. Management believes that it is more likely than not that the future results of operations will generate sufficient taxable income to utilize these net operating loss carryforwards before they expire.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in millions):

 
Year Ended December 31,
 
2017
 
2016
 
2015
Beginning Balance, January 1
$

 
$
1.5

 
$
2.0

Decrease due to prior year tax positions

 
(1.5
)
 
(0.5
)
Ending Balance, December 31
$

 
$

 
$
1.5



Per our accounting policy election, penalties and interest related to unrecognized tax benefits are recorded to income tax expense. As of December 31, 2017, tax years 2013 through 2017 remain subject to examination by various taxing authorities.
Certain Provisions of the Partnership Agreement
Certain Provisions of the Partnership Agreement
(8) Certain Provisions of the Partnership Agreement

(a) Issuance of ENLK Common Units

In November 2014, ENLK entered into an Equity Distribution Agreement (the “2014 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 to sell up to $350.0 million in aggregate gross sales of ENLK’s common units from time to time through an “at the market” equity offering program.

For the year ended December 31, 2015, ENLK sold an aggregate of 1.3 million common units under the 2014 EDA, generating proceeds of approximately $24.4 million (net of approximately $0.3 million of commissions). For the year ended December 31, 2016, ENLK sold an aggregate of 10.0 million common units under the 2014 EDA, generating proceeds of approximately $167.5 million (net of approximately $1.7 million of commissions).

In August 2017, ENLK ceased trading under the 2014 EDA and entered into an Equity Distribution Agreement (the “2017 EDA”) with UBS Securities LLC, Barclays Capital Inc., BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Markets Inc., Jefferies LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC (collectively, the “Sales Agents”) to sell up to $600.0 million in aggregate gross sales of ENLK’s common units from time to time through an “at the market” equity offering program. ENLK 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. ENLK has no obligation to sell any of the common units under the 2017 EDA and may at any time suspend solicitation and offers under the 2017 EDA.

For the year ended December 31, 2017, ENLK sold an aggregate of approximately 6.2 million common units under the 2014 EDA and the 2017 EDA, generating proceeds of approximately $106.9 million (net of approximately $1.1 million of commissions and $0.2 million of registration fees). ENLK used the net proceeds for general partnership purposes. As of December 31, 2017, approximately $565.4 million remains available to be issued under the 2017 EDA.

On October 29, 2015, ENLK issued 2,849,100 common units at an offering price of $17.55 per unit to a subsidiary of ENLC for aggregate consideration of approximately $50.0 million in a private placement transaction.

As explained in “Note 1—Organization and Summary of Significant Agreements,” in 2015, Acacia contributed its remaining 50% interest in Midstream Holdings to ENLK in exchange for 68.2 million units of ENLK common units in the EMH Drop Downs.

(b) Class C Common Units

In March 2015, ENLK issued 6,704,285 Class C Common Units representing a new class of limited partner interests as partial consideration for the acquisition of Coronado. The Class C Common Units were substantially similar in all respects to ENLK’s common units, except that distributions paid on the Class C Common Units could be paid in cash or in additional Class C Common Units issued in kind, as determined by our general partner in its sole discretion. Distributions on the Class C Common Units for the three months ended March 31, 2015, June 30, 2015, and September 30, 2015 were paid-in-kind through the issuance of 99,794120,622, and 150,732 Class C Common Units on May 14, 2015, August 13, 2015, and November 12, 2015, respectively. Distributions on the Class C Common Units for the three months ended December 31, 2015 and March 31, 2016 were paid-in-kind through the issuance of 209,044 and 233,107 Class C Common Units on February 11, 2016 and May 12, 2016, respectively. All of the outstanding Class C Common Units were converted into common units on a one-for-one basis on May 13, 2016.

(c) ENLK Series B Preferred Units

In January 2016, ENLK issued an aggregate of 50,000,000 Series B Preferred Units representing ENLK limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00 per Series B Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the private placement were used to partially fund ENLK’s portion of the purchase price payable in connection with the acquisition of our EnLink Oklahoma T.O. assets. Affiliates of the Goldman Sachs Group, Inc. and affiliates of TPG Global, LLC own interests in the general partner of Enfield. The Series B Preferred Units are convertible into ENLK common units on a one-for-one basis, subject to certain adjustments, (a) in full, at ENLK’s option, if the volume weighted average price of a common unit over the 30-trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of ENLK’s general partner or the managing member of ENLC, all of the Series B Preferred Units will automatically convert into a number of ENLK common units equal to the greater of (i) the number of ENLK common units into which the Series B Preferred Units would then convert and (ii) the number of Series B Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP.

For each of the calendar quarters between March 31, 2016 through June 30, 2017, Enfield received a quarterly distribution equal to an annual rate of 8.5% on the Issue Price payable in-kind in the form of additional Series B Preferred Units. For the quarter ended September 30, 2017 and each subsequent quarter, Enfield received or is entitled to receive a quarterly distribution, subject to certain adjustments, equal to an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) 0.0025 Series B Preferred Units per Series B Preferred Unit and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Series B Preferred Units converted into ENLK common units over the Cash Distribution Component, divided by (ii) the Issue Price.

A summary of the distribution activity relating to the Series B Preferred Units for the years ended December 31, 2017 and 2016 is provided below:
Declaration period
 
Distribution
paid as additional Series B Preferred Units
 
Cash distribution
(in millions)
 
Date paid/payable
2017
 
 
 
 
 
 
First Quarter of 2017
 
1,154,147

 
$

 
May 12, 2017
Second Quarter of 2017
 
1,178,672

 
$

 
August 11, 2017
Third Quarter of 2017
 
410,681

 
$
15.9

 
November 13, 2017
Fourth Quarter of 2017
 
413,658

 
$
16.1

 
February 13, 2018
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
First Quarter of 2016
 
992,445

 
$

 
May 12, 2016
Second Quarter of 2016
 
1,083,589

 
$

 
August 11, 2016
Third Quarter of 2016
 
1,106,616

 
$

 
November 10, 2016
Fourth Quarter of 2016
 
1,130,131

 
$

 
February 13, 2017


(d) ENLK Series C Preferred Units

In September 2017, ENLK issued 400,000 Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series C Preferred Units”) representing ENLK limited partner interests at a price to the public of $1,000 per unit. ENLK used the net proceeds of $394.0 million for capital expenditures, general partnership purposes and to repay borrowings under the ENLK Credit Facility. The Series C Preferred Units represent perpetual equity interests in ENLK and, unlike ENLK indebtedness, will not give rise to a claim for payment of a principal amount at a particular date. As to the payment of distributions and amounts payable on a liquidation event, the Series C Preferred Units rank senior to ENLK’s common units and to each other class of limited partner interests or other equity securities established after the issue date of the Series C Preferred Units that is not expressly made senior or on parity with the Series C Preferred Units. The Series C Preferred Units rank junior to the Series B Preferred Units with respect to the payment of distributions, and junior to the Series B Preferred Units and all current and future indebtedness with respect to amounts payable upon a liquidation event.

At any time on or after December 15, 2022, ENLK may redeem, at ENLK’s option, in whole or in part, the Series C Preferred Units at a redemption price in cash equal to $1,000 per Series C Preferred Unit plus an amount equal to all accumulated and unpaid distributions, whether or not declared. ENLK may undertake multiple partial redemptions. In addition, at any time within 120 days after the conclusion of any review or appeal process instituted by ENLK following certain rating agency events, ENLK may redeem, at ENLK’s option, the Series C Preferred Units in whole at a redemption price in cash per unit equal to $1,020 plus an amount equal to all accumulated and unpaid distributions, whether or not declared.

Distributions on the Series C Preferred Units accrue and are cumulative from the date of original issue and payable semi-annually in arrears on the 15th day of June and December of each year through and including December 15, 2022 and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year, in each case, if and when declared by ENLK’s general partner out of legally available funds for such purpose. The initial distribution rate for the Series C Preferred Units from and including the date of original issue to, but not including, December 15, 2022 is 6.0% per annum. On and after December 15, 2022, distributions on the Series C Preferred Units will accumulate for each distribution period at a percentage of the $1,000 liquidation preference per unit equal to an annual floating rate of the three-month LIBOR plus a spread of 4.11%. For the year ended December 31, 2017, ENLK made distributions of $5.6 million to holders of Series C Preferred Units.

(e) ENLK Common Unit Distributions

Unless restricted by the terms of the ENLK Credit Facility and/or the indentures governing ENLK’s senior unsecured notes, ENLK must make distributions of 100% of available cash, as defined in the partnership agreement, within 45days following the end of each quarter. Distributions are made to the General Partner in accordance with its current percentage interest with the remainder to the common unitholders, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. The General Partner was not entitled to its incentive distributions with respect to the Class C Common Units issued in kind. In addition, the general partner is not entitled to its incentive distributions with respect to (i) distributions on the Series B Preferred Units until such units convert into common units or (ii) the Series C Preferred Units.

The General Partner owns the general partner interest in ENLK and all of our incentive distribution rights. The General Partner is entitled to receive incentive distributions if the amount ENLK distribute with respect to any quarter exceeds levels specified in its partnership agreement. Under the quarterly incentive distribution provisions, the General Partner is entitled to 13.0% of amounts ENLK distributes in excess of $0.25 per unit, 23.0% of the amounts ENLK distributes in excess of $0.3125 per unit and 48.0% of amounts ENLK distributes in excess of $0.375 per unit.

A summary of ENLK’s distribution activity relating to the common units for the years ended December 31, 2017, 2016 and 2015 is provided below:
Declaration period
 
Distribution/unit
 
Date paid/payable
2017
 
 
 
 
First Quarter of 2017
 
$
0.390

 
May 12, 2017
Second Quarter of 2017
 
$
0.390

 
August 11, 2017
Third Quarter of 2017
 
$
0.390

 
November 13, 2017
Fourth Quarter of 2017
 
$
0.390

 
February 13, 2018
 
 
 
 
 
2016
 
 
 
 
First Quarter of 2016
 
$
0.390

 
May 12, 2016
Second Quarter of 2016
 
$
0.390

 
August 11, 2016
Third Quarter of 2016
 
$
0.390

 
November 11, 2016
Fourth Quarter of 2016
 
$
0.390

 
February 13, 2017
 
 
 
 
 
2015
 
 
 
 
First Quarter of 2015
 
$
0.380

 
May 14, 2015
Second Quarter of 2015
 
$
0.385

 
August 13, 2015
Third Quarter of 2015
 
$
0.390

 
November 12, 2015
Fourth Quarter of 2015
 
$
0.390

 
February 11, 2016

(f) Allocation of Partnership Income

Net income is allocated to the General Partner in an amount equal to its incentive distribution rights as described in section “(e) ENLK Common Unit Distributions” 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 and the percentage interest of ENLK’s net income adjusted for ENLC’s unit-based compensation specifically allocated to the General Partner and net income attributable to the drop down transactions described in Note 1—Organization and Summary of Significant Agreements.” The net income allocated to the General Partner is as follows (in millions):

 
Year Ended December 31,
 
2017
 
2016
 
2015
Income allocation for incentive distributions
$
58.9

 
$
56.8

 
$
47.5

Unit-based compensation attributable to ENLC’s restricted units
(21.0
)
 
(14.7
)
 
(18.3
)
General partner share of net income (loss)
0.4

 
(2.6
)
 
(6.7
)
General partner interest in drop down transactions

 

 
35.5

General partner interest in net income
$
38.3

 
$
39.5

 
$
58.0

Members' Equity
Members' Equity
(9) Members' Equity

(a) 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 unit for the periods presented (in millions, except per unit amounts):

 
Year Ended December 31,
 
2017
 
2016
 
2015
EnLink Midstream, LLC interest in net income (loss)
$
212.8

 
$
(460.0
)
 
$
(357.0
)
Distributed earnings allocated to:
 
 
 
 
 
Common units (1)
$
184.8

 
$
183.3

 
$
165.0

Unvested restricted units (1)
2.5

 
2.2

 
1.1

Total distributed earnings
$
187.3

 
$
185.5

 
$
166.1

Undistributed income (loss) allocated to:
 
 
 
 
 
Common units
$
25.2

 
$
(638.0
)
 
$
(519.5
)
Unvested restricted units
0.3

 
(7.5
)
 
(3.6
)
Total undistributed income (loss)
$
25.5

 
$
(645.5
)
 
$
(523.1
)
Net income (loss) allocated to:
 
 
 
 
 
Common units
$
210.0

 
$
(454.6
)
 
$
(354.5
)
Unvested restricted units
2.8

 
(5.4
)
 
(2.5
)
Total net income (loss)
$
212.8

 
$
(460.0
)
 
$
(357.0
)
Basic and diluted net income (loss) per unit:
 
 
 
 
 
Basic
$
1.18

 
$
(2.56
)
 
$
(2.17
)
Diluted
$
1.17

 
$
(2.56
)
 
$
(2.17
)
(1)
Represents distribution activity consistent with the distribution activity table below.

The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):

 
Year Ended December 31,
 
2017
 
2016
 
2015
Basic weighted average units outstanding:
 
 
 
 
 
Weighted average common units outstanding
180.5

 
179.7

 
164.2

 
 
 
 
 
 
Diluted weighted average units outstanding:
 
 
 
 
 
Weighted average basic common units outstanding
180.5

 
179.7

 
164.2

Dilutive effect of restricted units issued (1)
1.3

 

 

Total weighted average diluted common units outstanding
181.8

 
179.7