ENLINK MIDSTREAM PARTNERS, LP, 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
Document And 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 PARTNERS, LP 
 
 
Entity Central Index Key
0001179060 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Common Stock, Shares Outstanding
 
350,022,931 
 
Entity Public Float
 
 
$ 2.8 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Current assets:
 
 
Cash and cash equivalents
$ 30.8 
$ 11.6 
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
102.7 
100.2 
Fair value of derivative assets
6.8 
1.3 
Natural gas and NGLs inventory, prepaid expenses and other
39.7 
31.0 
Investment in unconsolidated affiliates—current
193.1 
Total current assets
806.7 
770.7 
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
422.3 
422.3 
Investment in unconsolidated affiliates—non-current
89.4 
77.3 
Other assets, net
11.5 
2.2 
Total assets
9,414.0 
9,153.4 
Current liabilities:
 
 
Accounts payable and drafts payable
66.9 
69.2 
Accounts payable to related party
18.4 
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
222.4 
217.0 
Total current liabilities
1,041.7 
887.0 
Long-term debt
3,467.8 
3,268.0 
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 
42.6 
Deferred tax liability
46.3 
73.0 
Redeemable non-controlling interest
4.6 
5.2 
Partners’ equity:
 
 
Common unitholders (349,702,372 and 342,856,292 units issued and outstanding, respectively)
2,791.6 
3,193.2 
General partner interest (1,594,974 equivalent units outstanding)
207.3 
209.1 
Accumulated other comprehensive loss
(2.1)
Non-controlling interest
549.5 
444.1 
Total partners’ equity
4,805.5 
4,640.4 
Commitments and contingencies (Note 14)
   
   
Total liabilities and partners’ equity
9,414.0 
9,153.4 
Series B Preferred Unitholders
 
 
Partners’ equity:
 
 
Preferred unitholders
864.1 
794.0 
Series C Preferred Unitholders
 
 
Partners’ equity:
 
 
Preferred unitholders
$ 395.1 
$ 0 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2017
Dec. 31, 2016
Allowance for bad debt
$ 0.3 
$ 0.1 
Accumulated depreciation
2,533.0 
2,124.1 
Accumulated amortization
298.7 
171.6 
Purchase price discount, current
0.5 
0.5 
Purchase price discount, noncurrent
$ 0 
$ 26.3 
Common units issued (in shares)
349,702,372 
342,856,292 
Common units outstanding (in shares)
349,702,372 
342,856,292 
General partner interest, equivalent units outstanding (in shares)
1,594,974 
1,594,974 
Series B Preferred Unitholders
 
 
Preferred units issued (in shares)
57,056,281 
53,182,651 
Preferred unit outstanding (in shares)
57,056,281 
53,182,651 
Series C Preferred Unitholders
 
 
Preferred units issued (in shares)
400,000 
Preferred unit outstanding (in shares)
400,000 
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
123.5 
119.3 
132.4 
Loss on disposition of assets
13.2 
1.2 
Depreciation and amortization
545.3 
503.9 
387.3 
Impairments
17.1 
566.3 
1,563.4 
Gain on litigation settlement
(26.0)
Total operating costs and expenses
5,440.1 
4,616.7 
5,749.5 
Operating income (loss)
299.5 
(364.3)
(1,297.4)
Other income (expense):
 
 
 
Interest expense, net of interest income
(187.9)
(188.1)
(102.5)
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
(168.7)
(207.7)
(81.3)
Income (loss) before non-controlling interest and income taxes
130.8 
(572.0)
(1,378.7)
Income tax benefit (provision)
24.0 
(1.3)
0.5 
Net income (loss)
154.8 
(573.3)
(1,378.2)
Net income (loss) attributable to non-controlling interest
5.9 
(8.1)
(0.4)
Net income (loss) attributable to EnLink Midstream Partners, LP
148.9 
(565.2)
(1,377.8)
General partner interest in net income
38.3 
39.5 
58.0 
Limited partners’ interest in net income (loss) attributable to EnLink Midstream Partners, LP
17.9 
(662.1)
(1,405.2)
Class C partners’ interest in net loss attributable to EnLink Midstream Partners, LP
(12.5)
(30.6)
Net income (loss) attributable to EnLink Midstream Partners, LP per limited partners’ unit:
 
 
 
Basic common unit (in dollars per share)
$ 0.05 
$ (1.99)
$ (4.66)
Diluted common unit (in dollars per share)
$ 0.05 
$ (1.99)
$ (4.66)
Series B Preferred Unitholders
 
 
 
Other income (expense):
 
 
 
Preferred interest in net income attributable to Enlink Midstream Partners, LP
86.0 
69.9 
Series C Preferred Unitholders
 
 
 
Other income (expense):
 
 
 
Preferred interest in net income attributable to Enlink Midstream Partners, LP
$ 6.7 
$ 0 
$ 0 
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)
$ 154.8 
$ (573.3)
$ (1,378.2)
Loss on designated cash flow hedge, net of amortization to interest expense
(2.1)
Comprehensive income (loss)
152.7 
(573.3)
(1,378.2)
Comprehensive income (loss) attributable to non-controlling interest
5.9 
(8.1)
(0.4)
Comprehensive income (loss) attributable to EnLink Midstream Partners, LP
$ 146.8 
$ (565.2)
$ (1,377.8)
Consolidated Statements of Changes in Partners' Equity - Partners Equity (USD $)
In Millions, except Share data, unless otherwise specified
Total
USD ($)
Devon
USD ($)
ENLC
USD ($)
Non-Controlling Interest
USD ($)
Non-Controlling Interest
ENLC
USD ($)
Accumulated Other Comprehensive Loss
USD ($)
General Partner Interest
USD ($)
Common Units
Limited Partner
USD ($)
Common Units
Limited Partner
Devon
USD ($)
Common Units
Limited Partner
ENLC
USD ($)
Class C Common Units
Class C Common Units
Limited Partner
USD ($)
Series B Preferred Unitholders
Limited Partner
USD ($)
Series C Preferred Unitholders
Limited Partner
USD ($)
Beginning balance at Dec. 31, 2014
 
 
 
 
 
$ 0 
 
 
 
 
 
 
$ 0 
$ 0 
Beginning balance (in shares) at Dec. 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Partners' Capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distributions (in shares)
 
 
 
 
 
 
 
 
 
 
99,794 
 
 
 
Ending balance at Mar. 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning balance at Dec. 31, 2014
6,025.9 
 
 
12.3 
 
180.3 
5,833.3 
 
 
 
Beginning balance (in shares) at Dec. 31, 2014
 
 
 
 
 
 
1,600,000 
245,400,000 
 
 
 
Increase (Decrease) in Partners' Capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of common units
384.3 
 
50.0 
 
 
 
 
204.3 
 
50.0 
 
180.0 
 
 
Issuance of common units (in shares)
 
 
 
 
 
 
 
76,800,000 
 
2,800,000 
 
6,700,000 
 
 
Conversion of restricted units for common units, net of units withheld for taxes
(2.5)
 
 
 
 
 
 
(2.5)
 
 
 
 
 
 
Conversion of restricted units for common units, net of units withheld for taxes (in shares)
 
 
 
 
 
 
 
200,000 
 
 
 
 
 
 
Unit-based compensation
35.7 
 
 
 
 
 
18.3 
17.4 
 
 
 
 
 
 
Contributions
 
27.8 
 
 
 
 
 
 
27.8 
 
 
 
 
 
Distribution attributable to VEX interests transferred (Note 3)
(166.7)
 
 
 
 
 
 
(166.7)
 
 
 
 
 
 
Distributions
(479.3)
 
 
 
 
 
(43.2)
(436.1)
 
 
 
 
 
 
Distributions (in shares)
 
 
 
 
 
 
 
 
 
 
 
400,000 
 
 
Non-controlling interest contributions
16.4 
 
 
16.4 
 
 
 
 
 
 
 
 
 
 
Distributions to non-controlling interest
(66.5)
 
 
(66.5)
 
 
 
 
 
 
 
 
 
 
Adjustment related to mandatory redemption of E2 non-controlling interest
(5.4)
 
 
(5.4)
 
 
 
 
 
 
 
 
 
 
Redeemable non-controlling interest
(7.0)
 
 
(7.0)
 
 
 
 
 
 
 
 
 
 
Transfer of interest in Midstream Holdings
 
 
66.5 
 
 
 
(66.5)
 
 
 
 
 
 
Net income (loss)
(1,378.2)
 
 
(0.4)
 
 
58.0 
(1,405.2)
 
 
 
(30.6)
 
 
Ending balance at Dec. 31, 2015
4,434.5 
 
 
15.9 
 
213.4 
4,055.8 
 
 
 
149.4 
 
Ending balance (in shares) at Dec. 31, 2015
 
 
 
 
 
 
1,600,000 
325,200,000 
 
 
 
7,100,000 
 
Beginning balance at Sep. 30, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Partners' Capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distributions (in shares)
 
 
 
 
 
 
 
 
 
 
209,044 
 
 
 
Ending balance at Dec. 31, 2015
 
 
 
 
 
 
 
 
 
 
 
Ending balance (in shares) at Dec. 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Partners' Capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Preferred Units (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
50,000,000 
 
Ending balance at Jan. 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning balance at Dec. 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
Beginning balance (in shares) at Dec. 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Partners' Capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distributions (in shares)
 
 
 
 
 
 
 
 
 
 
233,107 
 
 
 
Ending balance at Mar. 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning balance at Dec. 31, 2015
4,434.5 
 
 
15.9 
 
213.4 
4,055.8 
 
 
 
149.4 
Beginning balance (in shares) at Dec. 31, 2015
 
 
 
 
 
 
1,600,000 
325,200,000 
 
 
 
7,100,000 
Increase (Decrease) in Partners' Capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of common units
167.5 
 
 
 
 
 
 
167.5 
 
 
 
 
 
 
Issuance of common units (in shares)
 
 
 
 
 
 
 
10,000,000 
 
 
 
 
 
 
Issuance of Preferred Units
724.1 
 
 
 
 
 
 
 
 
 
 
 
724.1 
 
Issuance of Preferred Units (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
50,000,000 
 
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 
 
 
 
 
 
 
Unit-based compensation
30.0 
 
 
 
 
 
14.9 
15.1 
 
 
 
 
 
 
Contributions
1.5 
 
237.1 
 
237.1 
 
 
1.5 
 
 
 
 
 
 
Distributions
(579.0)
 
 
 
 
 
(58.7)
(520.3)
 
 
 
 
 
 
Distributions (in shares)
 
 
 
 
 
 
 
 
 
 
 
400,000 
3,200,000 
 
Conversion of Class C Common Units to common units
 
 
 
 
 
 
 
136.9 
 
 
 
(136.9)
 
 
Conversion of Class C Common Units to common units (in shares)
 
 
 
 
 
 
 
7,500,000 
 
 
 
(7,500,000)
 
 
Non-controlling interest contributions
207.4 
 
 
207.4 
 
 
 
 
 
 
 
 
 
 
Distributions to non-controlling interest
(8.2)
 
 
(8.2)
 
 
 
 
 
 
 
 
 
 
Net income (loss)
(573.3)
 
 
(8.1)
 
 
39.5 
(662.1)
 
 
 
(12.5)
69.9 
 
Ending balance at Dec. 31, 2016
4,640.4 
 
 
444.1 
 
209.1 
3,193.2 
 
 
 
794.0 
Ending balance (in shares) at Dec. 31, 2016
 
 
 
 
 
 
1,600,000 
342,900,000 
 
 
 
53,200,000 
Increase (Decrease) in Partners' Capital
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of common units
106.9 
 
 
 
 
 
 
106.9 
 
 
 
 
 
 
Issuance of common units (in shares)
 
 
 
 
 
 
 
6,200,000 
 
 
 
 
 
 
Issuance of Preferred Units
394.0 
 
 
 
 
 
 
 
 
 
 
 
 
394.0 
Issuance of Preferred Units (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
 
400,000 
Conversion of restricted units for common units, net of units withheld for taxes
(5.3)
 
 
 
 
 
 
(5.3)
 
 
 
 
 
 
Conversion of restricted units for common units, net of units withheld for taxes (in shares)
 
 
 
 
 
 
 
600,000 
 
 
 
 
 
 
Unit-based compensation
42.3 
 
 
 
 
 
21.1 
21.2 
 
 
 
 
 
 
Contributions
1.3 
 
 
 
 
 
 
 
1.3 
 
 
 
 
 
Distributions
(626.3)
 
 
 
 
 
(61.2)
(543.6)
 
 
 
 
(15.9)
(5.6)
Distributions (in shares)
 
 
 
 
 
 
 
 
 
 
 
 
3,900,000 
 
Non-controlling interest contributions
126.4 
 
 
126.4 
 
 
 
 
 
 
 
 
 
 
Distributions to non-controlling interest
(26.9)
 
 
(26.9)
 
 
 
 
 
 
 
 
 
 
Unrealized loss on derivatives, net of amortization to interest expense
(2.1)
 
 
 
 
(2.1)
 
 
 
 
 
 
 
 
Net income (loss)
154.8 
 
 
5.9 
 
 
38.3 
17.9 
 
 
 
 
86.0 
6.7 
Ending balance at Dec. 31, 2017
$ 4,805.5 
 
 
$ 549.5 
 
$ (2.1)
$ 207.3 
$ 2,791.6 
 
 
 
$ 0 
$ 864.1 
$ 395.1 
Ending balance (in shares) at Dec. 31, 2017
 
 
 
 
 
 
1,600,000 
349,700,000 
 
 
 
57,100,000 
400,000 
Consolidated Statements of Changes in Partners' Equity - Redeemable Non-controlling Interest (Temporary Equity) (USD $)
In Millions, unless otherwise specified
Total
Redeemable Noncontrolling Interest
Beginning balance at Dec. 31, 2014
 
$ 0 
Increase (Decrease) in Temporary Equity [Roll Forward]
 
 
Redeemable non-controlling interest
(7.0)
7.0 
Distributions to redeemable non-controlling interest
(66.5)
 
Ending balance at Dec. 31, 2015
 
7.0 
Increase (Decrease) in Temporary Equity [Roll Forward]
 
 
Distributions to redeemable non-controlling interest
(8.2)
(1.8)
Ending balance at Dec. 31, 2016
 
5.2 
Increase (Decrease) in Temporary Equity [Roll Forward]
 
 
Distributions to redeemable non-controlling interest
(26.9)
(0.6)
Ending balance at Dec. 31, 2017
 
$ 4.6 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Cash flows from operating activities:
 
 
 
Net income (loss)
$ 154.8 
$ (573.3)
$ (1,378.2)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Impairments
17.1 
566.3 
1,563.4 
Depreciation and amortization
545.3 
503.9 
387.3 
Loss on disposition of assets
13.2 
1.2 
Non-cash unit-based compensation
47.8 
30.0 
35.7 
Deferred tax benefit
(26.6)
(0.6)
(3.6)
(Gain) loss on derivatives recognized in net income (loss)
4.2 
11.1 
(9.4)
Cash settlements on derivatives
(11.2)
10.5 
17.1 
Gain on extinguishment of debt
(9.0)
Amortization of debt issue costs, net (premium) discount of notes and installment payable
29.1 
53.1 
0.2 
Distribution of earnings from unconsolidated affiliates
13.3 
3.1 
21.6 
(Income) loss from unconsolidated affiliates
(9.6)
19.9 
(20.4)
Other operating activities
0.6 
0.9 
(1.2)
Changes in assets and liabilities, net of assets acquired and liabilities assumed:
 
 
 
Accounts receivable, accrued revenue and other
(189.5)
(117.9)
197.4 
Natural gas and NGLs inventory, prepaid expenses and other
(23.7)
10.2 
4.2 
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities
163.9 
132.2 
(169.7)
Net cash provided by operating activities
706.5 
662.6 
645.6 
Cash flows from investing activities, net of assets acquired and liabilities assumed:
 
 
 
Additions to property and equipment
(790.8)
(663.0)
(572.3)
Proceeds from insurance settlement
0.4 
0.3 
2.9 
Acquisition of business, net of cash acquired
(769.3)
(524.2)
Proceeds from sale of unconsolidated affiliate investment
189.7 
Proceeds from sale of property
2.3 
93.1 
1.0 
Investment in unconsolidated affiliates
(12.6)
(73.8)
(25.8)
Distribution from unconsolidated affiliates in excess of earnings
0.2 
54.6 
21.1 
Net cash used in investing activities
(610.8)
(1,358.1)
(1,097.3)
Cash flows from financing activities:
 
 
 
Proceeds from borrowings
2,315.9 
2,057.8 
3,204.4 
Payments on borrowings
(2,104.3)
(1,852.7)
(2,134.3)
Payment of installment payable for EnLink Oklahoma T.O. acquisition
(250.0)
Debt financing costs
(5.5)
(4.6)
(9.5)
Proceeds from issuance of common units
106.9 
167.5 
24.4 
Proceeds from issuance of common units to general partner
50.0 
Distribution to common unitholders and to general partner
(604.8)
(579.0)
(479.3)
Distributions to non-controlling interests
(27.5)
(10.0)
(66.5)
Contributions by non-controlling interests, including contributions from affiliates of $69.1, $39.5 and $0.0, respectively
126.4 
207.4 
16.4 
Distributions to Devon for net assets acquired
(166.7)
Contribution from Devon
1.3 
1.5 
27.8 
Other financing activities
(7.4)
(10.8)
(18.7)
Net cash provided by (used in) financing activities
(76.5)
701.2 
448.0 
Net increase (decrease) in cash and cash equivalents
19.2 
5.7 
(3.7)
Cash and cash equivalents, beginning of period
11.6 
5.9 
9.6 
Cash and cash equivalents, end of period
30.8 
11.6 
5.9 
Cash paid for interest
163.8 
132.5 
109.4 
Cash paid for income taxes
4.8 
2.8 
0.5 
Series B Preferred Unitholders
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from issuance of Preferred Units
724.1 
Distributions to Preferred Unitholders
(15.9)
Series C Preferred Unitholders
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from issuance of Preferred Units
394.0 
Distributions to Preferred Unitholders
$ (5.6)
$ 0 
$ 0 
Consolidated Statements of Cash Flows (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Proceeds from affiliates
$ 126.4 
$ 207.4 
$ 16.4 
Affiliates
 
 
 
Proceeds from affiliates
$ 69.1 
$ 39.5 
$ 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 Partners, LP is a publicly traded Delaware limited partnership formed in 2002. Our common units are traded on the New York Stock Exchange under the symbol “ENLK.” Our business activities are conducted through our subsidiary, EnLink Midstream Operating, LP, a Delaware limited partnership (the “Operating Partnership”), and the subsidiaries of the Operating Partnership.
    
EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities. Our general partner is an indirect wholly-owned subsidiary of EnLink Midstream, LLC (“ENLC”). ENLC’s units are traded on the New York Stock Exchange under the symbol “ENLC.” Devon Energy Corporation (“Devon”) owns ENLC’s managing member and common units representing approximately 64% of the outstanding limited liability company interests in ENLC.

Effective as of March 7, 2014, the Operating Partnership acquired (the “Acquisition”) 50% of the outstanding equity interests in EnLink Midstream Holdings, LP (“Midstream Holdings”) and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings, in exchange for the issuance by us of 120,542,441 units of our limited partnership interests. At the same time, EnLink Midstream, Inc. (“EMI”), the entity that directly owns our general partner, became a wholly-owned subsidiary of ENLC (together with the Acquisition, the “Business Combination”). At the conclusion of the Business Combination, another wholly-owned subsidiary of ENLC, Acacia Natural Gas Corp. I, Inc. (“Acacia”), owned the remaining 50% of the outstanding equity interests in Midstream Holdings. In 2015, Acacia contributed the remaining 50% interest in Midstream Holdings to us in exchange for 68.2 million units of our limited partnership interests 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, we own 100% of Midstream Holdings.

We accounted for the EMH Drop Downs as a transfer between entities under common control in accordance with ASC 805, Business Combinations (“ASC 805”). As such, the EMH Drop Downs were recorded on our books at historical cost on the date of transfer. The “Transfer of interest in Midstream Holdings” presented in the consolidated statements of changes in partners’ equity represents the adjustment to equity due to the recast to offset distributions paid to ENLC for its related ownership during the period January 1, 2015 to May 27, 2015.

In addition, in April 2015, we 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, the Operating Partnership 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, and ENLC’s ownership is reflected as a non-controlling interest in the respective consolidated financial statements and related disclosures. See “Note 3—Acquisitions” for further discussion.

(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 12—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 10—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 9—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 12—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 ENLC each have similar unit-based payment plans for employees. Unit-based compensation associated with ENLC’s unit-based compensation plans awarded to directors, officers and employees of 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 11—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 14—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 $25.9 million and $24.1 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 of our common units and 6,704,285 of our 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 common units representing our 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 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
$
(1,381.8
)
Pro forma net loss attributable to EnLink Midstream Partners, LP
$
(1,381.4
)
Pro forma net loss per common unit:
 
Basic
$
(4.63
)
Diluted
$
(4.63
)


EnLink Oklahoma T.O. Acquisition

On January 7, 2016, ENLK and ENLC acquired an 83.9% and 16.1% 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 ENLK and ENLC paid and the fair value of the identified assets received and liabilities assumed at the acquisition date (in millions):

Consideration:
 
Cash
$
783.6

Total installment payable, net of discount of $79.1 million
420.9

Contribution from ENLC
237.1

Total consideration
$
1,441.6

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

Property 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 $3.7 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, of which $5.5 million is attributable to non-controlling interests, 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

 
$
4,514.3

Pro forma net loss
$
(574.1
)
 
$
(1,454.5
)
Pro forma net loss attributable to EnLink Midstream Partners, LP
$
(565.8
)
 
$
(1,441.8
)
Pro forma net loss per common unit:
 
 
 
Basic
$
(2.03
)
 
$
(5.10
)
Diluted
$
(2.03
)
 
$
(5.10
)
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
 
Totals
Year Ended December 31, 2016
 
 
 
 
 
 
 
Balance, beginning of period
$
703.5

 
$
190.3

 
$
93.2

 
$
987.0

Impairment
(473.1
)
 

 
(93.2
)
 
(566.3
)
Acquisition adjustment
1.6

 

 

 
1.6

Balance, end of period
$
232.0

 
$
190.3

 
$

 
$
422.3



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 and Crude and Condensate reporting units in the amount of $566.3 million was recognized in the first quarter of 2016 and is included as an impairment loss in the consolidated statement of operations for the 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 ENLC

ENLC paid us $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 its 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 ENLC 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 us for additional support costs, including, but not limited to, consideration for rent, office support and information service support.

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

On October 29, 2015, we issued 2,849,100 common units at an offering price of $17.55 per common unit to a subsidiary of ENLC 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, ENLC and Devon, entered into a tax sharing agreement providing for the allocation of responsibilities, liabilities and benefits relating to any tax for which a combined tax return is due. 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
Partnership credit facility, due 2020 (1)
 
$

 
$

 
$

 
$
120.0

 
$

 
$
120.0

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
 
$
3,500.0

 
$
(6.3
)
 
3,493.7

 
$
3,282.5

 
$
9.6

 
3,292.1

Debt issuance cost (2)
 
 
 
 
 
(25.9
)
 
 
 
 
 
(24.1
)
Long-term debt, net of unamortized issuance cost
 
 
 
 
 
$
3,467.8