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EX-32.1 - EXHIBIT 32.1 - EnLink Midstream Partners, LPex321enlkq2-2016.htm
EX-31.2 - EXHIBIT 31.2 - EnLink Midstream Partners, LPex312enlkq2-2016.htm
EX-31.1 - EXHIBIT 31.1 - EnLink Midstream Partners, LPex311enlkq2-2016.htm
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
Form 10-Q
 
x      Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
for the quarterly period ended June 30, 2016
 
OR
 
o         Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
for the transition period from               to               
 
Commission file number: 001-36340
 
ENLINK MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter) 
Delaware
 
16-1616605
(State of organization)
 
(I.R.S. Employer Identification No.)
 
 
 
2501 CEDAR SPRINGS RD.
 
 
DALLAS, TEXAS
 
75201
(Address of principal executive offices)
 
(Zip Code)
 
(214) 953-9500
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer x
 
Accelerated filer o
 
 
 
Non-accelerated filer o
 
Smaller reporting company o
(Do not check if a smaller reporting company)
 
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
 
As of July 22, 2016, the Registrant had 336,390,302 common units outstanding.
 



TABLE OF CONTENTS
 
Item
 
Description
 
Page
 
 
 
 
 
 
 
PART I—FINANCIAL INFORMATION
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2




ENLINK MIDSTREAM PARTNERS, LP 
Condensed Consolidated Balance Sheets 
 
June 30, 2016
 
December 31, 2015
 
(Unaudited)
 
 
 
(In millions, except unit data)
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
10.1

 
$
5.9

Accounts receivable:
 

 
 

Trade, net of allowance for bad debt of $0.3 and $0.3, respectively
68.5

 
37.5

Accrued revenue and other
295.7

 
268.7

Related party
72.6

 
111.1

Fair value of derivative assets
5.3

 
16.8

Natural gas and NGLs inventory, prepaid expenses and other
38.0

 
32.1

Total current assets
490.2


472.1

Property and equipment, net of accumulated depreciation of $1,941.4 and $1,757.6, respectively
6,160.4

 
5,666.8

Intangible assets, net of accumulated amortization of $112.1 and $54.6, respectively
1,666.7

 
689.9

Goodwill
421.4

 
987.0

Investment in unconsolidated affiliates
299.7

 
274.3

Other assets, net
2.4

 
2.7

Total assets
$
9,040.8

 
$
8,092.8

 
 
 
 
LIABILITIES AND PARTNERS’ EQUITY
 

 
 

Current liabilities:
 

 
 

Accounts payable and drafts payable
$
46.0

 
$
33.2

Accounts payable to related party
10.4

 
14.8

Accrued gas, NGLs, condensate and crude oil purchases
247.3

 
206.7

Fair value of derivative liabilities
5.8

 
2.9

Installment payable, net of discount of $14.2
235.8

 

Other current liabilities
146.0

 
174.4

Total current liabilities
691.3


432.0

Long-term debt
3,349.6

 
3,066.8

Fair value of derivative liabilities

 
0.1

Asset retirement obligation
13.2

 
12.9

Installment payable, net of discount of $39.3
210.7

 

Other long-term liabilities
57.0

 
65.9

Deferred tax liability
73.2

 
73.6

 
 
 
 
Redeemable non-controlling interest
6.5

 
7.0

 
 
 
 
Partners’ equity:
 
 
 
Common unitholders (336,182,533 units issued and outstanding at June 30, 2016 and 325,090,624 units issued and outstanding at December 31, 2015)
3,407.1

 
4,055.8

Class C unitholders (7,075,433 units issued and outstanding at December 31, 2015)

 
149.4

Preferred unitholders (50,992,445 units issued and outstanding at June 30, 2016)
753.9

 

General partner interest (1,594,974 equivalent units outstanding at June 30, 2016 and December 31, 2015)
210.2

 
213.4

Non-controlling interest
268.1

 
15.9

Total partners' equity
4,639.3

 
4,434.5

Commitment and Contingencies (Note 13)


 


Total liabilities and partners’ equity
$
9,040.8


$
8,092.8


See accompanying notes to condensed consolidated financial statements.
3


ENLINK MIDSTREAM PARTNERS, LP
Condensed Consolidated Statements of Operations
 
Three Months Ended  
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
 
(Unaudited)
(In millions, except per unit amounts)
Revenues:
 
 
 
 
 
 
 
Product sales
$
738.3

 
$
956.2

 
$
1,326.8

 
$
1,626.9

Product sales - affiliates
31.7

 
31.7

 
56.2

 
47.9

Midstream services
108.3

 
135.9

 
222.8

 
238.3

Midstream services - affiliates
160.6

 
149.5

 
323.2

 
300.5

Gain (loss) on derivative activity
(5.7
)
 
1.2

 
(6.1
)
 
1.4

Total revenues
1,033.2

 
1,274.5

 
1,922.9

 
2,215.0

Operating costs and expenses:
 

 
 

 
 
 
 
Cost of sales (1)
732.4

 
968.2

 
1,318.6

 
1,625.6

Operating expenses (2)
100.1

 
109.1

 
198.3

 
207.6

General and administrative (3)
29.1

 
27.0

 
62.3

 
68.8

Loss on disposition of assets
0.3

 

 
0.1

 

Depreciation and amortization
124.9

 
97.7

 
246.8

 
189.0

Impairments

 

 
566.3

 

Total operating costs and expenses
986.8

 
1,202.0

 
2,392.4

 
2,091.0

Operating income (loss)
46.4

 
72.5

 
(469.5
)
 
124.0

Other income (expense):
 
 
 
 
 
 
 
Interest expense, net of interest income
(46.2
)
 
(22.4
)
 
(89.9
)
 
(41.3
)
Income (loss) from unconsolidated affiliates
0.8

 
5.9

 
(1.6
)
 
9.7

Other income (loss)
(0.1
)
 
0.1

 

 
0.6

Total other expense
(45.5
)
 
(16.4
)
 
(91.5
)
 
(31.0
)
Income (loss) before non-controlling interest and income taxes
0.9

 
56.1

 
(561.0
)
 
93.0

Income tax benefit (provision)
2.3

 
(0.7
)
 
1.3

 
(1.9
)
Net income (loss)
3.2

 
55.4

 
(559.7
)
 
91.1

Net loss attributable to the non-controlling interest
(1.8
)
 
(0.1
)
 
(4.3
)
 

Net income (loss) attributable to EnLink Midstream Partners, LP
$
5.0

 
$
55.5

 
$
(555.4
)
 
$
91.1

General partner interest in net income
$
10.6

 
$
19.1

 
$
18.0

 
$
45.6

Limited partners’ interest in net income (loss) attributable to EnLink Midstream Partners, LP
$
(23.5
)
 
$
35.7

 
$
(590.7
)
 
$
44.7

Class C partners’ interest in net income (loss) attributable to EnLink Midstream Partners, LP
$
(0.1
)
 
$
0.7

 
$
(12.5
)
 
$
0.8

Preferred interest in net income attributable to EnLink Midstream Partners, LP
$
18.0

 
$

 
$
29.8

 
$

Net income (loss) attributable to EnLink Midstream Partners, LP per limited partners’ unit:
 

 
 

 
 
 
 
Basic common unit
$
(0.07
)
 
$
0.12

 
$
(1.80
)
 
$
0.16

Diluted common unit
$
(0.07
)
 
$
0.12

 
$
(1.80
)
 
$
0.16


(1)
Includes $49.8 million and $32.0 million for the three months ended June 30, 2016 and 2015, respectively, and $92.4 million and $39.9 million for the six months ended June 30, 2016 and 2015, respectively, of affiliate cost of sales.
(2)
Includes $0.2 million and $0.2 million for the three months ended June 30, 2016 and 2015, respectively, and $0.3 million and $0.2 million for the six months ended June 30, 2016 and 2015, respectively, of affiliate operating expenses.
(3)
Includes $0.1 million for the three and six months ended June 30, 2015 of affiliate general and administrative expenses.




See accompanying notes to condensed consolidated financial statements.
4


ENLINK MIDSTREAM PARTNERS, LP
Consolidated Statement of Changes in Partners’ Equity
Six Months Ended June 30, 2016
 
Common Units
 
Class C Common Units
 
Preferred Units
 
General Partner
Interest

Non-Controlling Interest
 
 
 
Redeemable Non-controlling Interest (Temporary Equity)
 
 
Units
 
 
Units
 
$
 
Units
 
 
Units
 
 
Total
 
 
(Unaudited)
 
 
 
(In millions)
 
 
Balance, December 31, 2015
$
4,055.8

 
325.2

 
$
149.4

 
7.1

 
$

 

 
$
213.4

 
1.6

 
$
15.9

 
$
4,434.5

 
$
7.0

Issuance of common units
52.3

 
3.3

 

 

 

 

 

 

 

 
52.3

 

Issuance of Preferred Units

 

 

 

 
724.1

 
50.0

 

 

 

 
724.1

 
 
Contribution from ENLC

 

 

 

 

 

 

 

 
237.1

 
237.1

 

Conversion of restricted units for common units, net of units withheld for taxes
(1.1
)
 
0.2

 

 

 

 

 

 

 

 
(1.1
)
 

Unit-based compensation
7.6

 

 

 

 

 

 
7.6

 

 

 
15.2

 

Contribution from Devon
1.4

 

 

 

 

 

 

 

 

 
1.4

 

Distributions
(255.1
)
 

 

 
0.4

 

 
1.0

 
(28.8
)
 

 

 
(283.9
)
 

Conversion of Class C Common Units to common units
136.9

 
7.5

 
(136.9
)
 
(7.5
)
 

 

 

 

 

 

 

Non-controlling interest contributions

 

 

 

 

 

 

 

 
21.5

 
21.5

 

Distributions to non-controlling interest

 

 

 

 

 

 

 

 
(2.1
)
 
(2.1
)
 

Distributions to redeemable non-controlling interest

 

 

 

 

 

 

 

 

 

 
(0.5
)
Net income (loss)
(590.7
)
 

 
(12.5
)
 

 
29.8

 

 
18.0

 

 
(4.3
)
 
(559.7
)
 

Balance, June 30, 2016
$
3,407.1

 
336.2

 
$

 

 
$
753.9

 
51.0

 
$
210.2

 
1.6

 
$
268.1

 
$
4,639.3

 
$
6.5



See accompanying notes to condensed consolidated financial statements.
5


ENLINK MIDSTREAM PARTNERS, LP
Consolidated Statements of Cash Flows
 
Six Months Ended June 30,
 
2016
 
2015
 
(Unaudited)
(In millions)
Cash flows from operating activities:
 

 
 

Net income (loss)
$
(559.7
)
 
$
91.1

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 
 

Impairments
566.3

 

Depreciation and amortization
246.8

 
189.0

Accretion expense
0.2

 
0.3

Loss on disposition of assets
0.1

 

Non-cash unit-based compensation
15.2

 
21.4

Deferred tax benefit
(0.3
)
 

(Gain) loss on derivatives recognized in net income (loss)
6.1

 
(5.0
)
Cash settlements on derivatives
8.3

 
11.3

Amortization of debt issue costs
1.7

 
1.4

Amortization of net (premium) discount on notes
24.3

 
(1.5
)
Redeemable non-controlling interest expense
0.3

 
(3.3
)
Distribution of earnings from unconsolidated affiliates

 
10.3

(Income) loss from unconsolidated affiliates
1.6

 
(9.7
)
Changes in assets and liabilities net of assets acquired and liabilities assumed:
 

 
 

Accounts receivable, accrued revenue and other
(18.1
)
 
57.3

Natural gas and NGLs inventory, prepaid expenses and other
3.8

 
(18.3
)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities
3.0

 
(52.0
)
Net cash provided by operating activities
299.6

 
292.3

Cash flows from investing activities, net of assets acquired and liabilities assumed:
 

 
 

Additions to property and equipment
(288.2
)
 
(349.2
)
Acquisition of business, net of cash acquired
(769.1
)
 
(324.8
)
Proceeds from sale of property
0.8

 
0.1

Investment in unconsolidated affiliates
(41.8
)
 

Distribution from unconsolidated affiliates in excess of earnings
14.8

 
8.9

Net cash used in investing activities
(1,083.5
)
 
(665.0
)
Cash flows from financing activities:
 

 
 

Proceeds from borrowings
820.0

 
2,327.4

Payments on borrowings
(537.2
)
 
(1,521.2
)
Payments on capital lease obligations
(2.1
)
 
(1.6
)
Decrease in drafts payable

 
(12.4
)
Debt financing costs
(0.3
)
 
(9.5
)
Conversion of restricted units, net of units withheld for taxes
(1.1
)
 
(2.5
)
Proceeds from issuance of common units
52.3

 
4.1

Proceeds from issuance of Preferred Units
724.1

 

Distributions to non-controlling partners
(2.6
)
 
(66.5
)
Contributions by non-controlling partners
21.5

 
7.2

Distributions to partners
(283.9
)
 
(211.6
)
Mandatorily redeemable non-controlling interest
(4.0
)
 

Contributions from Devon
1.4

 
28.8

Distribution to Devon for net assets acquired

 
(171.0
)
Net cash provided by financing activities
788.1

 
371.2

Net increase (decrease) in cash and cash equivalents
4.2


(1.5
)
Cash and cash equivalents, beginning of period
5.9

 
9.6

Cash and cash equivalents, end of period
$
10.1

 
$
8.1

Cash paid for interest
$
67.4

 
$
44.0

Cash paid for income taxes
$
2.3

 
$
0.1

 

See accompanying notes to condensed consolidated financial statements.
6


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements 
June 30, 2016
(Unaudited)
 
(1) General
In this report, the term “Partnership,” as well as the terms “our,” “we,” “us” and “its,” are sometimes used as abbreviated references to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership (as defined below) and EnLink Oklahoma Gas Processing, LP (formerly known as EnLink TOM Holdings, LP) and its consolidated subsidiaries (collectively, “EnLink Oklahoma T.O.”). EnLink Oklahoma T.O. is sometimes used to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP together with its consolidated subsidiaries.
(a)Organization of Business
EnLink Midstream Partners, LP is a publicly traded Delaware limited partnership formed in 2002. Our common units are traded on the New York Stock Exchange under the symbol “ENLK.” Our business activities are conducted through our subsidiary, EnLink Midstream Operating, LP, a Delaware limited partnership (the “Operating Partnership”), and the subsidiaries of the Operating Partnership.
EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities. Our general partner is an indirect wholly-owned subsidiary of EnLink Midstream, LLC (“ENLC”). ENLC’s units are traded on the New York Stock Exchange under the symbol “ENLC.” Devon Energy Corporation (“Devon”) owns ENLC's managing member and common units which represent approximately 64% of the outstanding limited liability company interests in ENLC.
Effective as of January 7, 2016, the Operating Partnership acquired 84% of the outstanding equity interests in EnLink Oklahoma T.O., and ENLC acquired the remaining 16% 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 condensed consolidated financial statements and related disclosures.
(b)Nature of Business
We primarily focus on providing midstream energy services, including gathering, transmission, processing, fractionation, brine services and marketing to producers of natural gas, natural gas liquids (“NGLs”), crude oil and condensate. We connect the wells of producers in our market areas to our gathering systems, process natural gas to remove NGLs, fractionate NGLs into purity products and market those products for a fee, transport natural gas and ultimately provide natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply sources and sell that natural gas to utilities, industrial consumers, other marketers and pipelines. We operate processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee-based arrangements. We provide a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. We also have crude oil and condensate terminal facilities that provide access for crude oil and condensate producers to premium markets. Our gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Our transmission pipelines primarily receive natural gas from our gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. We also have transmission lines that transport NGLs from east Texas and from our south Louisiana processing plants to our fractionators in south Louisiana. Our crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a fee, transport oil from a producer site to an end user. Our processing plants remove NGLs and CO2 from a natural gas stream and our fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline.
(2) Significant Accounting Policies
(a) Basis of Presentation
The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles in the United States of America (“GAAP”) for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation.

7


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



During the first half of 2015, we acquired assets from ENLC and Devon through drop down transactions. Due to ENLC's control of us through its ownership and control of our general partner and Devon's control of us through its ownership of the managing member of ENLC, each acquisition from ENLC and Devon was considered a transfer of net assets between entities under common control. As such, we were required to recast our historical financial statements to include the activities of such assets from the date that these entities were under common control. The condensed consolidated financial statements for periods prior to our acquisition of the assets from ENLC and Devon have been prepared from ENLC’s and Devon's historical cost-basis accounts for the acquired assets and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from ENLC and Devon for periods prior to our acquisition is allocated to our general partner.
(b) Recent Accounting Pronouncements
In January 2016, we adopted ASU 2015-03, Interest - Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability and requires retrospective application.  The application of this new accounting guidance resulted in the reclassification of $23.0 million of debt issuance costs from “Other Assets, Net” to “Long-term debt” in our accompanying Condensed Consolidated Balance Sheet as of December 31, 2015.
In January 2016, we adopted ASU 2015-17, Balance Sheet Classification of Deferred Taxes on a prospective basis. This new standard required that deferred tax assets and liabilities be classified as noncurrent in our Condensed Consolidated Balance Sheet.
In January 2016, we adopted ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated.
In January 2016, we adopted ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This update has no impact on our condensed consolidated financial statements or related disclosures.
In January 2016, we adopted ASU 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a Consensus of the FASB Emerging Issues Task Force) (“ASU 2015-06”), which requires a master limited partnership (MLP) to allocate earnings (losses) of a transferred business entirely to the general partner when computing earnings per unit (EPU) for periods before the dropdown transaction occurred. The EPU that the limited partners previously reported would not change as a result of the dropdown transaction. ASU 2015-06 also requires an MLP to disclose the effects of the dropdown transaction on EPU for the periods before and after the dropdown transaction occurred. ASU 2015-06 is effective for the fiscal years beginning after December 15, 2015, and interim periods within those annual periods. ASU 2015-06 requires retrospective application and early adoption is permitted. The update is effective for us beginning on January 1, 2016 and had no impact on our condensed consolidated financial statements and related disclosures.
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 will update ASU 2014-09, Revenue from Contracts with Customers (“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 2016-12 has the same effective date and transition requirements as ASU 2014-09, which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods. We are currently evaluating the impact the pronouncement will have on our condensed consolidated financial statements and related disclosures.
In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which amends ASC Topic 718, Compensation – Stock Compensation (“ASU 2016-09”). First, the new standard will require all of the tax effects related to share-based payments at settlement (or expiration) to be recorded through the income statement, and is required to be applied prospectively. Second, the new standard also allows entities to withhold taxes of an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in liability classification of the award, and is required to be adopted using a modified retrospective approach. Third, under the ASU, forfeitures can be estimated, as currently required, or recognized when they occur. If elected, the change to recognize forfeitures when they occur must be adopted using a modified retrospective approach. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016 including interim periods within those annual periods. Early adoption is permitted. We do not expect this standard to materially impact our condensed consolidated financial statements and related disclosures.

8


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



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, and is required to be adopted using a modified retrospective transition. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for transferring goods or services to a customer. The new standard will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Partnership's nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, and is to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the pronouncement will have on our condensed consolidated financial statements and related disclosures.
(3) Acquisitions
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. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change.
Purchase Price Allocation (in millions):
 
 
Assets acquired:
 
 
Current assets
 
$
1.1

Property, plant and equipment
 
35.5

Intangibles
 
98.8

Goodwill
 
9.8

Liabilities assumed:
 
 
Current liabilities
 
(3.9
)
Total identifiable net assets
 
$
141.3

We recognized intangible assets related to customer relationships. The acquired intangible assets will be 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 and is non-deductible for tax purposes.
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, plant and equipment. The final working capital settlement paid to Apache was approximately $1.5 million. The transaction was accounted for using the acquisition method.

9


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Tall Oak Acquisition
On January 7, 2016, we and ENLC acquired an 84% and 16% voting interest, respectively, in EnLink Oklahoma T.O. for approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The final installment of $500.0 million is due by us no later than the first anniversary of the closing date with the option to defer $250.0 million of the final installment up to 24 months following the closing date. The installment payables are valued net of discount within the total purchase price.
The first installment consisted of approximately $1.02 billion and was funded by (a) approximately $784.2 million in cash paid by us, the majority of which was derived from the proceeds from the issuance of Preferred Units, and (b) 15,564,009 common units representing limited liability company interests in ENLC issued directly by ENLC and approximately $22.2 million in cash paid by ENLC. The transaction was accounted for using the acquisition method.
The following table presents the consideration we paid and the fair value of the identified assets received and liabilities assumed at the acquisition date. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change.
Consideration (in millions):
 
 
Cash
 
$
784.2

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

Contribution from ENLC
 
237.1

Total consideration
 
$
1,442.2

 
 

Purchase Price Allocation (in millions):
 


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

Property, plant and equipment
 
423.2

Intangibles
 
1,034.3

Liabilities assumed:
 
 
Current liabilities
 
(38.3
)
Total identifiable net assets
 
$
1,442.2

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 will be amortized on a straight-line basis over the estimated customer life of approximately 15 years.
We incurred $3.7 million of direct transaction costs for the six months ended June 30, 2016. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.
For the period from January 7, 2016 to June 30, 2016, we recognized $72.2 million of revenues and $23.5 million of net loss related to the assets acquired.

10


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Pro Forma Information
The following unaudited pro forma condensed financial information for the three and six months ended June 30, 2015 gives effect to the January 2015 LPC acquisition, March 2015 Coronado acquisition, October 2015 Matador acquisition, November 2015 Deadwood acquisition and January 2016 Tall Oak acquisition 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. Pro forma financial information associated with the acquisitions is reflected below.
 
 
Three Months Ended  
 June 30,
 
Six Months Ended 
 June 30,
 
 
2015
 
2015
 
 
(in millions)
Pro forma total revenues
 
$
1,283.3

 
$
2,350.9

Pro forma net income
 
$
37.3

 
$
48.0

Pro forma net income attributable to EnLink Midstream Partners, LP
 
$
40.5

 
$
54.4

Pro forma net income (loss) per common unit:
 
 
 
 
Basic
 
$
(0.01
)
 
$
(0.15
)
Diluted
 
$
(0.01
)
 
$
(0.15
)
(4) Goodwill and Intangible Assets
Goodwill
Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of October 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 the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value of goodwill to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. During 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.
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.
The fair value of goodwill is based on inputs that are not observable in the market and thus represent Level 3 inputs. Using the fair value approaches described above, in step one of the goodwill impairment test, we determined that the estimated fair values of our Texas and Crude and Condensate reporting units were less than their respective carrying amounts, primarily related to increases in our discount rate subsequent to year-end. The second step of the goodwill impairment test measures the amount of impairment loss and involves allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Through the analysis, a goodwill impairment loss for our Texas and Crude and Condensate reporting units in the amount of $566.3 million was recognized for the three months ended March 31, 2016, which is included in our six months ended June 30, 2016 impairments line item in the Condensed Consolidated Statements of Operations.
We concluded that the fair value of goodwill of our Oklahoma reporting unit exceeded its carrying value, and the entire amount of goodwill disclosed on the Condensed Consolidated Balance Sheet associated with this remaining reporting unit is

11


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



recoverable. Therefore, no other goodwill impairment was identified or recorded for this reporting unit as a result of our goodwill impairment analysis.
Our impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. The estimated fair value of our Texas reporting unit may be impacted in the future by a further decline in our unit price or a continuing 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 Texas reporting unit.
The table below provides a summary of our change in carrying amount of goodwill, by assigned reporting unit (in millions):
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
Six Months Ended June 30, 2016
 
 
 
 
 
 
 
 
 
 
 
Balance, beginning of period
$
703.5

 
$

 
$
190.3

 
$
93.2

 
$

 
$
987.0

Impairment
(473.1
)
 

 

 
(93.2
)
 

 
(566.3
)
Acquisition adjustment
0.7

 

 

 

 

 
0.7

Balance, end of period
$
231.1

 
$


$
190.3


$


$

 
$
421.4

Intangible Assets
Intangible assets associated with customer relationships are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from ten to twenty years.
The following table represents our change in carrying value of intangible assets (in millions):
 
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
Carrying
Amount
Six Months Ended June 30, 2016
 
 
 
 
 
 
Customer relationships, beginning of period
 
$
744.5

 
$
(54.6
)
 
$
689.9

Acquisitions
 
1,034.3

 

 
1,034.3

Amortization expense
 

 
(57.5
)
 
(57.5
)
Customer relationships, end of period
 
$
1,778.8

 
$
(112.1
)
 
$
1,666.7

The weighted average amortization period for intangible assets is 13.7 years. Amortization expense for intangibles was approximately $30.0 million and $18.2 million for the three months ended June 30, 2016 and 2015, respectively, and $57.5 million and $29.7 million for the six months ended June 30, 2016 and 2015, respectively.
The following table summarizes our estimated aggregate amortization expense for the next five years (in millions):
2016 (remaining)
$
58.4

2017
116.7

2018
116.7

2019
116.7

2020
116.7

Thereafter
1,141.5

Total
$
1,666.7

(5) Affiliate Transactions
We engage in various transactions with Devon and other affiliated entities. For the three and six months ended June 30, 2016 and 2015, Devon was a significant customer to us. Devon accounted for 18.6% and 19.7% of our revenues for the three and six months ended June 30, 2016, respectively, and 14.2% and 15.7% for the three and six months ended June 30, 2015,

12


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



respectively. We had an accounts receivable balance related to transactions with Devon of $72.6 million as of June 30, 2016 and $110.8 million as of December 31, 2015. Additionally, we had an accounts payable balance related to transactions with Devon of $10.4 million as of June 30, 2016 and $14.8 million as of December 31, 2015. Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with nonaffiliated third parties. The amounts related to affiliate transactions are specified in the accompanying financial statements.
EnLink Oklahoma T.O. Gathering and Processing Agreement with Devon
In January 2016, in connection with the Tall Oak acquisition, 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 a minimum volume commitment that will remain in place during each calendar quarter for the next five years and a remaining overall term of approximately 13 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. EnLink Oklahoma T.O. will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.
(6) Long-Term Debt
As of June 30, 2016 and December 31, 2015, long-term debt consisted of the following (in millions):
 
June 30,
2016
 
December 31,
2015
Credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at June 30, 2016 and December 31, 2015 was 2.2% and 1.8%, respectively
$
697.0

 
$
414.0

Senior unsecured notes (due 2019), net of discount of $0.3 million at June 30, 2016 and $0.4 million at December 31, 2015, which bear interest at the rate of 2.70%
399.7

 
399.6

Senior unsecured notes (due 2022), including a premium of $17.5 million at June 30, 2016 and $18.9 million at December 31, 2015, which bear interest at the rate of 7.125%
180.0

 
181.4

Senior unsecured notes (due 2024), net of premium of $2.7 million at June 30, 2016 and $2.9 million at December 31, 2015, which bear interest at the rate of 4.40%
552.7

 
552.9

Senior unsecured notes (due 2025), net of discount of $1.2 million at June 30, 2016 and $1.2 million at December 31, 2015, which bear interest at the rate of 4.15%
748.8

 
748.8

Senior unsecured notes (due 2044), net of discount of $0.2 million at June 30, 2016 and $0.2 million at December 31, 2015, which bear interest at the rate of 5.60%
349.8

 
349.8

Senior unsecured notes (due 2045), net of discount of $6.8 million at June 30, 2016 and $6.9 million at December 31, 2015, which bear interest at the rate of 5.05%
443.2

 
443.1

Debt issuance cost, net of amortization of $6.4 million at June 30, 2016 and $4.7 million at December 31, 2015
(21.6
)
 
(23.0
)
Other debt

 
0.2

Debt classified as long-term
$
3,349.6

 
$
3,066.8

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

13


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



consolidated indebtedness to consolidated EBITDA to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.
Borrowings under our credit facility bear interest at our option at the Eurodollar Rate (the LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0% or the administrative agent’s prime rate) plus an applicable margin. The applicable margins vary depending on our credit rating. If we breach certain covenants governing our credit facility, amounts outstanding under our credit facility, if any, may become due and payable immediately.
As of June 30, 2016, there were $11.1 million in outstanding letters of credit and $697.0 million in outstanding borrowings under our credit facility, leaving approximately $791.9 million available for future borrowing based on the borrowing capacity of $1.5 billion.
All other material terms and conditions of our credit facility are described in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness” in our Annual Report on Form 10-K for the year ended December 31, 2015. We expect to be in compliance with all credit facility covenants for at least the next twelve months.
(7)      Partners’ Capital
(a) Issuance of Common Units
In November 2014, we entered into an Equity Distribution Agreement (the “BMO EDA”) with BMO Capital Markets Corp., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., Jefferies LLC, Raymond James & Associates, Inc. and RBC Capital Markets, LLC (collectively, the “Sales Agents”) to sell up to $350.0 million in aggregate gross sales of our common units from time to time through an “at the market” equity offering program. We may also sell common units to any Sales Agent as principal for the Sales Agent’s own account at a price agreed upon at the time of sale. We have no obligation to sell any of the common units under the BMO EDA and may at any time suspend solicitation and offers under the BMO EDA. For the six months ended June 30, 2016, we sold an aggregate of 3.3 million common units under the BMO EDA, generating proceeds of approximately $52.3 million (net of approximately $0.5 million of commissions). We used the net proceeds for general partnership purposes. As of June 30, 2016, approximately $264.4 million remains available to be issued under the BMO EDA.
(b) Class C Common Units
In March 2015, we issued 6,704,285 Class C Common Units representing a new class of limited partner interests as partial consideration for the acquisition of Coronado. The Class C Common Units were substantially similar in all respects to our common units, except that distributions paid on the Class C Common Units could be paid in cash or in additional Class C Common Units issued in kind, as determined by our general partner in its sole discretion. Distributions on the Class C Common Units for the three months ended December 31, 2015 and March 31, 2016 were paid-in-kind through the issuance of 209,044 and 233,107 Class C Common Units on February 11, 2016 and May 12, 2016, respectively. All of the outstanding Class C Common Units converted into common units on a one-for-one basis on May 13, 2016.
(c) Preferred Units
In January 2016, we issued an aggregate of 50,000,000 Series B Cumulative Convertible Preferred Units (the “Preferred Units”) representing our limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00 per Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the private placement were used to partially fund our portion of the purchase price payable in connection with the Tall Oak acquisition. Affiliates of the Goldman Sachs Group, Inc. and affiliates of TPG Global, LLC own interests in the general partner of Enfield. The Preferred Units are convertible into our common units on a one-for-one basis, subject to certain adjustments, at any time after the record date for the quarter ending June 30, 2017 (a) in full, at our option, if the volume weighted average price of a common unit over the 30-trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of our general partner or the managing member of ENLC, all of the Preferred Units will automatically convert into a number of common units equal to the greater of (i) the number of common units into which the Preferred Units would then convert and (ii) the number of Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP.
As a holder of Preferred Units, Enfield is entitled to receive a quarterly distribution, subject to certain adjustments, equal to (x) during the quarter ending March 31, 2016 through the quarter ending June 30, 2017, an annual rate of 8.5% on the Issue

14


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Price payable in-kind in the form of additional Preferred Units and (y) thereafter, an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) an annual rate of 1.0% of the Issue Price and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the Issue Price. A distribution on the Preferred Units for the three months ended March 31, 2016, was paid-in kind through the issuance of 992,445 Preferred Units on May 12, 2016. A distribution on the Preferred Units was declared for the three months ended June 30, 2016, which will result in the issuance of 1,083,589 additional Preferred Units on August 11, 2016. Income was allocated to the Preferred Units in an amount equal to the quarterly distribution with respect to the period earned. For the three and six months ended June 30, 2016, $18.0 million and $29.8 million of income was allocated to the Preferred Units, respectively.
(d)  Distributions
Unless restricted by the terms of our credit facility and/or the indentures governing our senior unsecured notes, we must make distributions of 100% of available cash, as defined in our agreement, within 45 days following the end of each quarter. Distributions are made to our general partner in accordance with its current percentage interest with the remainder to the common unitholders, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. Our general partner is not entitled to its general partner or incentive distributions with respect to the Preferred Units issued in kind.
Our general partner owns the general partner interest in us and all of our incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13.0% of amounts we distribute in excess of $0.25 per unit, 23% of the amounts we distribute in excess of $0.3125 per unit and 48.0% of amounts we distribute in excess of $0.375 per unit.

15


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



A summary of the distribution activity relating to the common units for the six months ended June 30, 2016 is provided below:
Declaration period
 
Distribution/unit
 
Date paid/payable
Fourth Quarter of 2015
 
$
0.39

 
February 11, 2016
First Quarter of 2016
 
$
0.39

 
May 12, 2016
Second Quarter of 2016
 
$
0.39

 
August 11, 2016
(e) Earnings per Unit and Dilution Computations
As required under FASB ASC 260-10-45-61A, unvested share-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations. Net income (loss) attributable to drop down interests acquired during 2015 from ENLC and Devon for periods prior to acquisition is not allocated to the limited partners for purposes of calculating net income (loss) per common unit. The following table reflects the computation of basic and diluted earnings per limited partner unit for the period presented (in millions, except per unit amounts):
 
Three Months Ended  
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Limited partners’ interest in net income (loss)
$
(23.5
)
 
$
35.7

 
$
(590.7
)
 
$
44.7

Distributed earnings allocated to:
 
 
 
 
 
 
 
Common units (1) (2)
$
128.6

 
$
117.6

 
$
255.5

 
$
214.4

Unvested restricted units (1) (2)
0.9

 
0.4

 
1.7

 
0.9

Total distributed earnings
$
129.5

 
$
118.0

 
$
257.2

 
$
215.3

Undistributed loss allocated to:
 
 
 
 
 
 
 
Common units
$
(151.6
)
 
$
(82.0
)
 
$
(842.3
)
 
$
(169.9
)
Unvested restricted units
(1.4
)
 
(0.3
)
 
(5.6
)
 
(0.7
)
Total undistributed loss
$
(153.0
)
 
$
(82.3
)
 
$
(847.9
)
 
$
(170.6
)
Net income (loss) allocated to:
 
 
 
 
 
 
0

Common units
$
(23.0
)
 
$
35.6

 
$
(586.8
)
 
$
44.5

Unvested restricted units
(0.5
)
 
0.1

 
(3.9
)
 
0.2

Total limited partners’ interest in net income (loss)
$
(23.5
)
 
$
35.7

 
$
(590.7
)
 
$
44.7

Basic and diluted net income (loss) per unit:
 
 
 
 
 
 
 
Basic
$
(0.07
)
 
$
0.12

 
$
(1.80
)
 
$
0.16

Diluted
$
(0.07
)
 
$
0.12

 
$
(1.80
)
 
$
0.16

(1)
Three months ended June 30, 2016 and 2015 represents a declared distribution of $0.39 per unit payable on August 11, 2016 and a distribution of $0.385 per unit paid on August 13, 2015, respectively.
(2)
Six months ended June 30, 2016 and 2015 represents a distribution of $0.39 per unit paid on May 12, 2016, a declared distribution of $0.39 per unit payable on August 11, 2016 and distributions of $0.38 per unit paid on May 14, 2015 and of $0.385 per unit paid on August 13, 2015.

16


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the periods presented (in millions):
 
Three Months Ended  
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Basic weighted average units outstanding:
 
 
 
 
 
 
 
Weighted average limited partner basic common units outstanding (1)
330.1

 
305.2

 
327.6

 
284.2

Diluted weighted average units outstanding:
 
 
 
 
 
 
 
Weighted average limited partner basic common units outstanding
330.1

 
305.2

 
327.6

 
284.2

Dilutive effect of restricted units issued

 
0.4

 

 
0.4

    Total weighted average limited partner diluted common units
    outstanding
330.1

 
305.6

 
327.6

 
284.6

(1)
The three and six months ended June 30, 2016 includes the weighted average impact of 7,409,996 and 7,298,996 Common Class C Common Units, respectively, that converted into common units on May 13, 2016.  The three and six months ended June 30, 2015 includes the weighted average impact of 6,770,083 and 3,959,347 Common Class C Common Units, respectively, that converted into common units on May 13, 2016 and 14,088,418 and 7,083,128 Common Class E Common Units, respectively, that converted into common units on August 3, 2015.
All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the periods presented.
Net income is allocated to our general partner in an amount equal to its incentive distributions as described in (d) above. Our general partner's share of net income consists of incentive distributions to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of our net income adjusted for ENLC's unit-based compensation specifically allocated to our general partner. The net income allocated to our general partner is as follows for the periods presented (in millions):
 
Three Months Ended  
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Income allocation for incentive distributions
$
14.2

 
$
11.3

 
$
28.0

 
$
20.1

Unit-based compensation attributable to ENLC’s restricted units
(3.6
)
 
(3.9
)
 
(7.6
)
 
(10.9
)
General partner share of net income (loss)

 
0.2

 
(2.4
)
 
0.3

General partner interest in drop down transactions

 
11.5

 

 
36.1

General partner interest in net income
$
10.6

 
$
19.1

 
$
18.0

 
$
45.6

(8) Asset Retirement Obligations
The schedule below summarizes the changes in our asset retirement obligation:
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
(in millions)
Beginning asset retirement obligations
$
14.0

 
$
20.6

Revisions to existing liabilities
(0.4
)
 
(4.0
)
Accretion
0.2

 
0.3

Liabilities settled
(0.6
)
 
(3.2
)
Ending asset retirement obligations
$
13.2

 
$
13.7

There are no asset retirement obligations included in Other Current Liabilities as of June 30, 2016. Asset retirement obligations of $1.1 million are included in Other Current Liabilities as of December 31, 2015.

17


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



(9) Investment in Unconsolidated Affiliates
Our unconsolidated investments consisted of a contractual right to the economic benefits and burdens associated with Devon's 38.75% ownership interest in Gulf Coast Fractionators (“GCF”) at June 30, 2016 and 2015 and approximately 31.0% ownership interest in Howard Energy Partners (“HEP”) at June 30, 2016 and 2015.
The following table shows the activity related to our investment in unconsolidated affiliates for the periods indicated (in millions):
 
Gulf Coast Fractionators
 
Howard Energy Partners
 
Total
Three months ended
 
 
 
 
 
June 30, 2016
 
 
 
 
 
Contributions
$

 
$
34.7

 
$
34.7

Distributions
$
0.5

 
$
5.1

 
$
5.6

Equity in net income
$
0.5

 
$
0.3

 
$
0.8

 
 
 
 
 
 
June 30, 2015
 
 
 
 
 
Distributions
$
4.2

 
$
8.2

 
$
12.4

Equity in net income
$
2.9

 
$
3.0

 
$
5.9

 
 
 
 
 
 
Six months ended
 
 
 
 
 
June 30, 2016
 
 
 
 
 
Contributions
$

 
$
41.8

 
$
41.8

Distributions
$
3.5

 
$
11.3

 
$
14.8

Equity in net loss
$
(1.2
)
 
$
(0.4
)
 
$
(1.6
)
 
 
 
 
 
 
June 30, 2015
 
 
 
 
 
Distributions
$
6.9

 
$
12.3

 
$
19.2

Equity in net income
$
6.3

 
$
3.4

 
$
9.7

The following table shows the balances related to our investment in unconsolidated affiliates for the periods indicated (in millions):
 
June 30,
2016
 
December 31,
2015
Gulf Coast Fractionators
$
47.9

 
$
52.6

Howard Energy Partners
251.8

 
221.7

Total investment in unconsolidated affiliates
$
299.7

 
$
274.3

(10) Employee Incentive Plans
(a)         Long-Term Incentive Plans
We account for unit-based compensation in accordance with FASB ASC 718, which requires that compensation related to all unit-based awards, including unit options, be recognized in the condensed consolidated financial statements. On April 7, 2016, our general partner amended and restated the EnLink Midstream GP, LLC Long-Term Incentive Plan (the “GP Plan”). Amendments to the GP Plan included an increase to the number of common units of the Partnership authorized for issuance under the GP Plan by 5,000,000 common units to an aggregate of 14,070,000 common units and other technical changes.
We and ENLC each have similar unit-based compensation payment plans for officers and employees, which are described below.  Unit-based compensation associated with ENLC's unit-based compensation plan awarded to our officers and employees is recorded by us since ENLC has no substantial or managed operating activities other than its interests in us and EnLink

18


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Oklahoma T.O. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions):
 
 
Three Months Ended  
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Cost of unit-based compensation charged to general and administrative expense
$
5.7

 
$
6.5

 
$
11.9

 
$
18.4

Cost of unit-based compensation charged to operating expense
1.6

 
1.1

 
3.3

 
3.0

    Total amount charged to income
$
7.3

 
$
7.6

 
$
15.2

 
$
21.4

(b)  EnLink Midstream Partners, LP Restricted Incentive Units
Our restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of common units on such date. A summary of the restricted incentive unit activity for the six months ended June 30, 2016 is provided below:
 
 
Six Months Ended 
 June 30, 2016
EnLink Midstream Partners, LP Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-vested, beginning of period
 
1,253,729

 
$
29.59

Granted
 
1,046,685

 
10.03

Vested*
 
(297,439
)
 
30.33

Forfeited
 
(40,998
)
 
22.17

Non-vested, end of period
 
1,961,977

 
$
19.20

Aggregate intrinsic value, end of period (in millions)
 
$
32.6

 
 

*
Vested units include 85,366 units withheld for payroll taxes paid on behalf of employees.
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and six months ended June 30, 2016 and 2015, respectively, is provided below (in millions):

 
Three Months Ended  
 June 30,
 
Six Months Ended 
 June 30,
EnLink Midstream Partners, LP Restricted Incentive Units:
 
2016

2015
 
2016
 
2015
Aggregate intrinsic value of units vested
 
$
0.1


$
0.4

 
$
3.8

 
$
7.2

Fair value of units vested
 
$


$
0.5

 
$
9.0

 
$
7.5

As of June 30, 2016, there was $19.0 million of unrecognized compensation cost related to non-vested restricted incentive units. That cost is expected to be recognized over a weighted-average period of 1.8 years.
(c)  EnLink Midstream Partners, LP Performance Units
In 2016, our general partner and the managing member of ENLC granted performance awards under the GP Plan and the EnLink Midstream, LLC 2014 Long-Term Incentive Plan (the “LLC Plan”), respectively. The performance award agreements provide that the vesting of restricted incentive units granted thereunder is dependent on the achievement of certain total shareholder return (“TSR”) performance goals relative to the TSR achievement of a peer group of companies (the “Peer Companies”) over the applicable performance period. The performance award agreements contemplate that the Peer Companies for an individual performance award (the “Subject Award”) are the companies comprising the Alerian MLP Index for Master Limited Partnerships (“AMZ”), excluding us and ENLC (collectively, “EnLink”), on the grant date for the Subject Award. The performance units will vest based on the percentile ranking of the average of the Partnership’s and ENLC’s TSR achievement (“EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

19


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200 percent of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of our common units and the designated peer group securities; (iii) an estimated ranking of us among the designated peer group; and (iv) the distribution yield. The fair value of the performance unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:
EnLink Midstream Partners, LP Performance Units:
 
January
2016
 
February
2016
Beginning TSR Price
 
$
14.82

 
$
14.82

Risk-free interest rate
 
1.10
%
 
0.89
%
Volatility factor
 
39.71
%
 
42.33
%
Distribution yield
 
12.10
%
 
19.20
%
The following table presents a summary of our performance units:
 
 
Six Months Ended 
 June 30, 2016
EnLink Midstream Partners, LP Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
118,126

 
$
35.41

Granted
 
258,078

 
9.81

Forfeited
 
(2,798
)
 
36.18

Non-vested, end of period
 
373,406

 
$
17.71

Aggregate intrinsic value, end of period (in millions)
 
$
6.2

 

As of June 30, 2016, there was $4.4 million of unrecognized compensation expense that related to our non-vested performance units. That cost is expected to be recognized over a weighted-average period of 2.0 years.
(d)         EnLink Midstream, LLC Restricted Incentive Units
ENLC restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of the common units on such date. A summary of the restricted incentive unit activity for the six months ended June 30, 2016 is provided below:
 
 
Six Months Ended 
 June 30, 2016
EnLink Midstream, LLC Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-vested, beginning of period
 
1,148,893

 
$
34.78

Granted
 
1,038,619

 
9.44

Vested*
 
(320,497
)
 
36.92

Forfeited
 
(37,952
)
 
23.95

Non-vested, end of period
 
1,829,063

 
$
20.24

Aggregate intrinsic value, end of period (in millions)
 
$
29.1

 
 

*
Vested units include 91,256 units withheld for payroll taxes paid on behalf of employees.

20


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and six months ended June 30, 2016 and 2015, respectively, are provided below (in millions):
 
 
Three Months Ended  
 June 30,
 
Six Months Ended 
 June 30,
EnLink Midstream, LLC Restricted Incentive Units:
 
2016
 
2015
 
2016
 
2015
Aggregate intrinsic value of units vested
 
$

 
$
0.6

 
$
3.8

 
$
8.9

Fair value of units vested
 
$

 
$
0.6

 
$
11.8

 
$
9.2

As of June 30, 2016, there was $18.6 million of unrecognized compensation costs related to non-vested ENLC restricted incentive units. The cost is expected to be recognized over a weighted-average period of 1.7 years.
(e) EnLink Midstream, LLC's Performance Units
In 2016, ENLC granted performance awards under the LLC Plan discussed in Note (c) above. At the end of the vesting period, recipients receive distribution equivalents, if any, with respect to the number of performance units vested. The vesting of units range from zero to 200 percent of the units granted depending on the EnLink TSR as compared to the TSR of the Peer Companies on the vesting date. The fair value of each performance unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all performance unit grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of ENLC's common units and the designated peer group securities; (iii) an estimated ranking of ENLC among the designated peer group and (iv) the distribution yield. The fair value of the unit on the date of grant is expensed over a vesting period of three years. The following table presents a summary of the grant-date fair values of performance units granted and the related assumptions:
EnLink Midstream, LLC Performance Units:
 
January
2016
 
February
2016
Beginning TSR Price
 
$
15.38

 
$
15.38

Risk-free interest rate
 
1.10
%
 
0.89
%
Volatility factor
 
46.02
%
 
52.05
%
Distribution yield
 
8.60
%
 
14.00
%
The following table presents a summary of the ENLC's performance units:
 
 
Six Months Ended 
 June 30, 2016
EnLink Midstream, LLC Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
105,080

 
$
40.50

Granted
 
242,646

 
9.59

Forfeited
 
(2,525
)
 
41.31

Non-vested, end of period
 
345,201

 
$
18.76

Aggregate intrinsic value, end of period (in millions)
 
$
5.5

 

As of June 30, 2016, there was $4.2 million of unrecognized compensation expense that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 2.0 years.
(11) Derivatives
Commodity Swaps
We manage our exposure to fluctuation in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge price and location risk related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs. We do not designate transactions as cash flow or fair value hedges for hedge accounting treatment under FASB ASC 815. Therefore, changes in the

21


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



fair value of our derivatives are recorded in revenue in the period incurred. In addition, our risk management policy does not allow us to take speculative positions with our derivative contracts.
We commonly enter into index (float-for-float) or fixed-for-float swaps in order to mitigate our cash flow exposure to fluctuations in the future prices of natural gas, NGLs and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. They are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate and crude, fixed-for-float swaps are used to protect cash flows against price fluctuations: (1) where we receive a percentage of liquids as a fee for processing third-party gas or where we receive a portion of the proceeds of the sales of natural gas and liquids as a fee, (2) in the natural gas processing and fractionation components of our business and (3) where we are mitigating the price risk for product held in inventory or storage.
The components of gain (loss) on derivative activity in the Condensed Consolidated Statements of Operations relating to commodity swaps are (in millions):
 
Three Months Ended  
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Change in fair value of derivatives
$
(8.4
)
 
$
(2.5
)
 
$
(14.4
)
 
$
(6.3
)
Realized gain on derivatives
2.7

 
3.7

 
8.3

 
7.7

    Gain (loss) on derivative activity
$
(5.7
)
 
$
1.2

 
$
(6.1
)
 
$
1.4

The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions):
 
June 30,
2016
 
December 31,
2015
Fair value of derivative assets — current
$
5.3

 
$
16.8

Fair value of derivative liabilities — current
(5.8
)
 
(2.9
)
Fair value of derivative liabilities — long term

 
(0.1
)
    Net fair value of derivatives
$
(0.5
)
 
$
13.8

Assets and liabilities related to our derivative contracts are included in the fair value of derivative assets and liabilities and the change in fair value of these contracts is recorded net as a gain (loss) on derivative activity in the Condensed Consolidated Statement of Operations. We estimate the fair value of all of our derivative contracts using actively quoted prices. The total estimated fair value liability of derivative contracts of $0.5 million as of June 30, 2016 has a maturity date of less than one year.
Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets at June 30, 2016. The remaining term of the contracts extend no later than June 2017.
 
 
 
 
 
 
June 30, 2016
Commodity
 
Instruments
 
Unit
 
Volume
 
Fair Value
 
 
 
 
 
 
(In millions)
NGL (short contracts)
 
Swaps
 
Gallons
 
(31.9
)
 
$
3.4

NGL (long contracts)
 
Swaps
 
Gallons
 
11.4

 
(0.4
)
Natural Gas (short contracts)
 
Swaps
 
MMBtu
 
(6.3
)
 
(2.9
)
Natural Gas (long contracts)
 
Swaps
 
MMBtu
 
1.3

 
(0.1
)
Condensate (short contracts)
 
Swaps
 
MMBbls
 
(0.1
)
 
(0.5
)
Total fair value of derivatives
 
 
 
 
 
 
 
$
(0.5
)
On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish limits and monitor the appropriateness of these limits on an ongoing basis. We primarily deal with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. We have entered into Master International Swaps and Derivatives Association Agreements (“ISDAs”) that allow for netting of swap contract receivables and payables in the event of default by either party. If our

22


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



counterparties failed to perform under existing swap contracts, our maximum loss as of June 30, 2016 of $5.3 million would be eliminated due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs. 
Interest Rate Swaps
We entered into interest rate swaps during April and May 2015 in connection with the issuance of the 2025 Notes in May 2015. We did not enter into any interest rate swaps for the six months ended June 30, 2016.
The impact of the interest rate swaps on net income is included in other income (expense) in the Condensed Consolidated Statement of Operations as part of interest expense, net, as follows (in millions):
 
Three Months Ended  
 June 30,
 
Six Months Ended 
 June 30,
 
2016
 
2015
 
2016
 
2015
Settlement gains on derivatives
$

 
$
3.6

 
$

 
$
3.6

(12)      Fair Value Measurements
FASB ASC 820 sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under FASB ASC 820 is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability's fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.
FASB ASC 820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.
Our derivative contracts primarily consist of commodity swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument's term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy.
Net asset (liabilities) measured at fair value on a recurring basis are summarized below (in millions):
 
June 30, 2016
Level 2
 
December 31, 2015
Level 2
Commodity Swaps*
$
(0.5
)
 
$
13.8

Total
$
(0.5
)
 
$
13.8

 
*
The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction adjusted for our and/or the counterparty credit risk as required under FASB ASC 820.

23


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Fair Value of Financial Instruments
We have determined the estimated fair value of our financial instruments using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount we could realize upon the sale or refinancing of such financial instruments (in millions):
 
June 30, 2016
 
December 31, 2015
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
Long-term debt
$
3,349.6

 
$
3,133.4

 
$
3,066.8

 
$
2,585.5

Installment Payables
$
446.5

 
$
451.6

 
$

 
$

Obligations under capital leases
$
12.3

 
$
11.5

 
$
16.7

 
$
15.6

The carrying amounts of our cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.
We had $697.0 million and $414.0 million in outstanding borrowings under our revolving credit facility as of June 30, 2016 and December 31, 2015, respectively. As borrowings under the credit facility accrue interest under floating interest rate structures, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of June 30, 2016 and December 31, 2015, we had total borrowings of $2.7 billion under senior unsecured notes maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. The fair value of all senior unsecured notes and installment payables as of June 30, 2016 and December 31, 2015 was based on Level 2 inputs from third-party market quotations.  The fair value of obligations under capital leases was calculated using Level 2 inputs from third-party banks. 
(13) Commitments and Contingencies
(a) Severance and Change in Control Agreements
Certain members of our management are parties to severance and change of control agreements with the Operating Partnership. The severance and change in control agreements provide those individuals with severance payments in certain circumstances and prohibit such individual from, among other things, competing with our general partner or its affiliates during his or her employment. In addition, the severance and change of control agreements prohibit subject individuals from, among other things, disclosing confidential information about our general partner or its affiliates or interfering with a client or customer of our general partner or its affiliates, in each case during his or her employment and for certain periods (including indefinite periods) following the termination of such person’s employment.
(b) Environmental Issues
The operation of pipelines, plants and other facilities for the gathering, processing, transmitting or disposing of natural gas, NGLs, crude oil, condensate, brine and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows. In February 2016, a spill occurred at our Kill Buck Station in our Ohio operations.  State and federal agencies were notified and clean-up response efforts were promptly executed, which significantly lessened the impact of the spill.  On April 7, 2016, the state agency determined that the clean-up recovery efforts were completed and has internally transitioned monitoring to their water quality division.  We do not anticipate a material fine or penalty by either the state or federal agencies.  Additionally, although the spill that previously occurred in our West Virginia operations in the third quarter of 2015 is still pending, we do not believe that any fine or penalty that may be issued will be material to our operations.  Lastly, we continue to work with Pipeline and Hazardous Materials Safety Administration regarding the notice of potential violation discussed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

24


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



(c) Litigation Contingencies
We are involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.
At times, our subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain and common carrier. As a result, from time to time we (or our subsidiaries) are a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by our subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and any diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to inflate their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, we do not expect that awards in these matters will have a material adverse effect on our financial position, results of operations or cash flows.
We (or our subsidiaries) are defending lawsuits filed by owners of property located near processing facilities or compression facilities constructed, owned or operated by us as part of our systems. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the development of natural gas gathering, processing and treating facilities in urban and occupied rural areas.
In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans, but was removed to the United States District Court for the Eastern District of Louisiana. The amount of damages is unspecified. Our subsidiary, EnLink LIG, LLC, is one of the named defendants as the owner of pipelines in the area. On February 13, 2015, the court granted defendants’ joint motion to dismiss and dismissed the plaintiff’s claims with prejudice. Plaintiffs have appealed the matter to the United States Court of Appeals for the Fifth Circuit. We intend to continue vigorously defending the case. The success of the plaintiffs' appeal as well as our costs and legal exposure, if any, related to the lawsuit are not currently determinable.
We own and operate a high-pressure pipeline and underground natural gas and NGL storage reservoirs and associated facilities near Bayou Corne, Louisiana. In August 2012, a large sinkhole formed in the vicinity of this pipeline and underground storage reservoirs, resulting in damage to certain of our facilities. We are seeking to recover our losses from responsible parties. We have sued Texas Brine Company, LLC (“Texas Brine”), the operator of a failed cavern in the area and its insurers, seeking recovery for these losses. We have also sued Occidental Chemical Company and Legacy Vulcan Corp. f/k/a Vulcan Materials Company, two Chlor-Alkali plant operators that participated in Texas Brine’s operational decisions regarding the mining of the failed cavern. We also filed a claim with our insurers, which our insurers denied. We disputed the denial and have also sued our insurers. In August 2014, we received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million, but additional claims remain outstanding. We cannot give assurance that we will be able to fully recover our losses through insurance recovery or claims against responsible parties.
In June 2014, a group of landowners in Assumption Parish, Louisiana added our subsidiary, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine, Occidental Chemical Corporation, and Vulcan Materials Company relating to claims arising from the Bayou Corne sinkhole. The suit is pending in the 23rd Judicial Court, Assumption Parish, Louisiana. Although plaintiffs’ claims against the other defendants have been pending since October 2012, plaintiffs are now alleging that EnLink Processing Services, LLC’s negligence also contributed to the formation of the sinkhole. The amount of damages is unspecified. The validity of the causes of action, as well as our costs and legal exposure, if any, related to the lawsuit are not currently determinable. We intend to vigorously defend the case. We have also filed a claim for defense and indemnity with our insurers.
(14) Segment Information
Identification of the majority of our operating segments is based principally upon geographic regions served. Our reportable segments consist of the following: natural gas gathering, processing, transmission and fractionation operations located in north Texas, south Texas and the Permian Basin in west Texas (“Texas”), the pipelines and processing plants located in Louisiana and NGL assets located in south Louisiana (“Louisiana”), natural gas gathering and processing operations located throughout Oklahoma (“Oklahoma”) and crude rail, truck, pipeline and barge facilities in west Texas, south Texas, Louisiana and Ohio River Valley (“Crude and Condensate”). Operating activity for intersegment eliminations is shown in the corporate segment. Our sales are derived from external domestic customers.

25


ENLINK MIDSTREAM PARTNERS, LP
Notes to Condensed Consolidated Financial Statements (Continued)
(Unaudited)



Corporate expenses include general partnership expenses associated with managing all reportable operating segments. Corporate assets consist primarily of cash, property and equipment, including software, for general corporate support, debt financing costs and unconsolidated affiliate investments in HEP and GCF. We evaluate the performance of our operating segments based on operating revenues and segment profits.
Summarized financial information concerning our reportable segments is shown in the following tables:
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
 
(In millions)
Three Months Ended June 30, 2016
 

 
 

 
 

 
 

 
 

 
 

Product sales
$
41.9

 
$
399.5

 
$
8.9

 
$
288.0

 
$

 
$
738.3

Product sales-affiliates
72.7

 
15.2

 
22.5

 
0.9

 
(79.6
)
 
31.7

Midstream services
23.2

 
52.7

 
18.0

 
14.4

 

 
108.3

Midstream services-affiliates
111.9

 
25.5

 
41.7

 
4.0

 
(22.5
)
 
160.6

Cost of sales
(103.6
)
 
(425.5
)
 
(31.6
)
 
(273.8
)
 
102.1

 
(732.4
)
Operating expenses
(43.0
)
 
(25.4
)
 
(11.8
)
 
(19.9
)
 

 
(100.1
)
Loss on derivative activity