10-Q

 
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 September 30, 2015
 
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: 001-36336
 
ENLINK MIDSTREAM, LLC
(Exact name of registrant as specified in its charter) 
Delaware
 
46-4108528
(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 October 23, 2015, the Registrant had 164,232,972 common units outstanding.
 


TABLE OF CONTENTS
 
Item
 
Description
 
Page
 
 
 
 
 
 
 
PART I—FINANCIAL INFORMATION
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2



ENLINK MIDSTREAM, LLC
 
Condensed Consolidated Balance Sheets
 
 
September 30, 2015
 
December 31, 2014
 
(Unaudited)
 
 
 
(In millions, except unit data)
ASSETS
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
82.5

 
$
68.4

Accounts receivable:
 

 
 

Trade, net of allowance for bad debt of $1.7
30.7

 
139.0

Accrued revenue and other
333.6

 
253.3

     Related party
119.2

 
121.6

Fair value of derivative assets
15.5

 
16.7

Natural gas and NGLs inventory, prepaid expenses and other
74.0

 
48.8

Total current assets
655.5


647.8

Property and equipment, net of accumulated depreciation of $1,671.1 and $1,426.3,
    respectively
5,565.8

 
5,042.8

Intangible assets, net of accumulated amortization of $42.9 and $36.5, respectively
602.8

 
533.0

Goodwill
3,156.8

 
3,684.7

Fair value of derivative assets
2.9

 
10.0

Investments in unconsolidated affiliates
263.5

 
270.8

Other assets, net
26.6

 
17.6

Total assets
$
10,273.9

 
$
10,206.7

 
 
 
 
LIABILITIES AND MEMBERS’ EQUITY
 

 
 

Current liabilities:
 

 
 

Accounts payable and drafts payable
$
40.6

 
$
121.8

Accounts payable to related party
24.2

 
3.0

Accrued gas, NGLs, condensate and crude oil purchases
263.0

 
204.5

Fair value of derivative liabilities
3.4

 
3.0

Other current liabilities
205.5

 
152.3

Total current liabilities
536.7


484.6

Long-term debt
2,851.5

 
2,022.5

Fair value of derivative liabilities
0.5

 
2.0

Asset retirement obligation
12.8

 
12.4

Other long-term liabilities
70.8

 
83.8

Deferred tax liability
539.3

 
526.6

Redeemable non-controlling interest
6.9

 
—

Members’ equity
 
 
 
Members' equity
2,518.6

 
2,774.3

Non-controlling interest
3,736.8

 
4,196.8

Net Devon investment
—

 
103.7

Total members' equity
6,255.4

 
7,074.8

Commitment and Contingencies (Note 15)


 


Total liabilities and members’ equity
$
10,273.9


$
10,206.7


See accompanying notes to condensed consolidated financial statements.
3

ENLINK MIDSTREAM, LLC
 
Condensed Consolidated Statements of Operations
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(Unaudited)
(In millions, except per unit amounts)
Revenues:
 
 
 
 
 
 
 
 
Product sales
 
$
863.5

 
$
579.1

 
$
2,488.8

 
$
1,480.4

Product sales - affiliates
 
40.3

 
37.8

 
89.6

 
474.2

Midstream services
 
111.3

 
68.6

 
351.3

 
154.8

Midstream services - affiliates
 
150.3

 
170.9

 
449.3

 
400.2

Gain (loss) on derivative activity
 
5.2

 
1.0

 
6.6

 
(1.9
)
Total revenues
 
1,170.6

 
857.4

 
3,385.6


2,507.7

Operating costs and expenses:
 
 
 
 
 
 

 
 

Cost of sales (1)
 
861.8

 
597.2

 
2,487.4

 
1,798.0

Operating expenses (2)
 
105.0

 
79.8

 
312.6

 
200.4

General and administrative (3)
 
34.8

 
24.4

 
105.6

 
66.9

Loss on disposition of assets
 
3.2

 
—

 
3.2

 
—

Depreciation and amortization
 
98.4

 
75.1

 
289.1

 
198.6

Impairments
 
799.2

 
—

 
799.2

 
—

Gain on litigation settlement
 
—

 
(6.1
)
 
—

 
(6.1
)
Total operating costs and expenses
 
1,902.4

 
770.4


3,997.1


2,257.8

Operating income (loss)
 
(731.8
)
 
87.0

 
(611.5
)

249.9

Other income (expense):
 
 
 
 
 
 
 
 
Interest expense, net of interest income
 
(30.4
)
 
(13.6
)
 
(72.1
)
 
(33.1
)
Equity in income of equity investment
 
6.4

 
5.6

 
16.1

 
14.3

Gain on extinguishment of debt
 
—

 
2.4

 
—

 
3.2

Other income (expense)
 
0.1

 
0.1

 
0.6

 
(0.7
)
Total other expense
 
(23.9
)
 
(5.5
)
 
(55.4
)
 
(16.3
)
Income (loss) from continuing operations before non-controlling interest and income taxes
 
(755.7
)
 
81.5

 
(666.9
)
 
233.6

Income tax provision
 
(0.2
)
 
(17.3
)
 
(21.1
)
 
(59.5
)
Net income (loss) from continuing operations
 
(755.9
)
 
64.2

 
(688.0
)
 
174.1

Discontinued operations:
 
 
 
 
 
 
 
 
Income from discontinued operations, net of tax
 
—

 
—

 
—

 
1.0

Discontinued operations, net of tax
 
—

 
—

 
—

 
1.0

Net income (loss)
 
(755.9
)
 
64.2

 
(688.0
)

175.1

Net income (loss) attributable to the non-controlling interest
 
(562.5
)
 
37.7

 
(526.1
)
 
80.5

Net income (loss) attributable to EnLink Midstream, LLC
 
$
(193.4
)
 
$
26.5

 
$
(161.9
)
 
$
94.6

Predecessor interest in net income (4)
 
$
—

 
$
—

 
$
—

 
$
35.5

Devon investment interest in net income (loss)
 
$
—

 
$
(2.3
)
 
$
0.7

 
$
(5.3
)
EnLink Midstream, LLC interest in net income (loss)
 
$
(193.4
)
 
$
28.8

 
$
(162.6
)
 
$
64.4

Net income (loss) attributable to EnLink Midstream, LLC per unit:
 
 
 
 
 
 

 
 

  Basic per common unit
 
$
(1.18
)
 
$
0.18

 
$
(0.99
)
 
$
0.39

  Diluted per common unit
 
$
(1.18
)
 
$
0.17

 
$
(0.99
)
 
$
0.39

(1) Includes $51.9 million and $24.1 million for the three months ended September 30, 2015 and 2014, respectively, and $91.7 million and $349.9 million for the nine months ended September 30, 2015 and 2014, respectively, of affiliate cost of sales.
(2) Includes $0.1 million and $0.3 million for the three and nine months ended September 30, 2015, respectively, and $5.9 million for the nine months ended September 30, 2014 of affiliate operating expenses.
(3) Includes $0.1 million and $0.2 million for the three and nine months ended September 30, 2015, respectively, and $1.0 million and $10.6 million for the three and nine months ended September 30, 2014, respectively, of affiliate general and administrative expenses.
(4) Represents net income attributable to the Predecessor for the period prior to March 7, 2014.

See accompanying notes to condensed consolidated financial statements.
4

ENLINK MIDSTREAM, LLC
 
Consolidated Statement of Changes in Members’ Equity
Nine Months Ended September 30, 2015
 
 
Common Units
 
Net Devon Investment
 
Non-Controlling Interest
 
 
 
Redeemable Non-controlling Interest (Temporary Equity)
 
$ 
 
Units
 
$ 
 
$ 
 
Total
 
$
 
(Unaudited)
 
(In millions)
Balance, December 31, 2014
$
2,774.3

 
164.1

 
$
103.7

 
$
4,196.8

 
$
7,074.8

 
$
—

 Unit-based compensation
14.8

 
—

 
—

 
14.1

 
28.9

 
—

 Issuance of units by the Partnership
—

 
—

 
—

 
372.9

 
372.9

 
—

 Conversion of restricted units for common, net of units withheld for taxes
(2.9
)
 
0.1

 
—

 
—

 
(2.9
)
 
—

 Non-controlling partner's impact of conversion of restricted units
—

 
—

 
—

 
(2.5
)
 
(2.5
)
 
—

 Change in equity due to issuance of units by the
    partnership
8.5

 
—

 
—

 
(13.7
)
 
(5.2
)
 
—

 Non-controlling interest distributions
—

 
—

 
—

 
(266.8
)
 
(266.8
)
 
—

 Non-controlling interest contribution
—

 
—

 
—

 
12.2

 
12.2

 
—

 Distributions to members
(120.6
)
 
—

 
—

 
—

 
(120.6
)
 
—

 Adjustment related to mandatory redemption of E2 non-controlling interest
—

 
—

 
—

 
(5.4
)
 
(5.4
)
 
—

 Redeemable non-controlling interest
—

 
—

 
—

 
(6.9
)
 
(6.9
)
 
6.9

 Contribution from Devon to the Company
7.1

 
—

 
—

 
—

 
7.1

 
—

 Contribution from Devon to the Partnership
—

 
—

 
26.6

 
2.2

 
28.8

 
—

 Distribution to Devon in connection with acquisition
    of net assets
—

 
—

 
(131.0
)
 
(40.0
)
 
(171.0
)
 
—

 Net income (loss)
(162.6
)
 
—

 
0.7

 
(526.1
)
 
(688.0
)
 
—

Balance, September 30, 2015
$
2,518.6

 
164.2

 
$
—

 
$
3,736.8

 
$
6,255.4

 
$
6.9



See accompanying notes to condensed consolidated financial statements.
5

ENLINK MIDSTREAM, LLC
 Consolidated Statements of Cash Flows
 
Nine Months Ended September 30,
 
2015
 
2014
 
(Unaudited)
(In millions)
Cash flows from operating activities:
 

 
 

Net income (loss) from continuing operations
$
(688.0
)
 
$
174.1

Adjustments to reconcile net income to net cash provided by operating activities:
 

 
 

Impairments
799.2

 
—

Depreciation and amortization
289.1

 
198.6

Accretion expense
0.4

 
0.4

Loss on disposition of assets
3.2

 
—

Gain on extinguishment of debt
—

 
(3.2
)
Deferred tax expense
18.2

 
53.7

Non-cash unit-based compensation
28.9

 
12.8

(Gain) loss on derivatives recognized in net income
(6.6
)
 
1.9

Cash settlements on derivatives
13.0

 
(1.7
)
Amortization of debt issue costs
2.4

 
0.8

Amortization of premium on notes
(2.2
)
 
(1.7
)
Redeemable non-controlling interest expense
(2.0
)
 
—

Distribution of earnings from equity investment
17.1

 
6.3

Equity in income from equity investments
(16.1
)
 
(14.3
)
Changes in assets and liabilities:
 
 
 
Accounts receivable, accrued revenue and other
124.1

 
26.2

Natural gas and NGLs inventory, prepaid expenses and other
(28.6
)
 
(27.0
)
Accounts payable, accrued gas and crude oil purchases and other accrued liabilities
(60.5
)
 
(66.9
)
Net cash provided by operating activities
491.6

 
360.0

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

 
 

Additions to property and equipment
(450.3
)
 
(540.1
)
Acquisition of business, net of cash acquired
(330.6
)
 
(126.9
)
Deposit for acquisition
—

 
(23.5
)
Proceeds from sale of property
0.4

 
—

Investment in limited liability company
(8.1
)
 
(5.7
)
Distribution from equity investment company in excess of earnings
14.3

 
7.6

Net cash used in investing activities
(774.3
)
 
(688.6
)
Cash flows from financing activities:
 

 
 

Proceeds from borrowings
2,604.4

 
2,170.3

Payments on borrowings
(1,773.2
)
 
(1,765.2
)
Payments on capital lease obligations
(2.5
)
 
(1.8
)
Decrease in drafts payable
(12.6
)
 
(2.6
)
Debt financing costs
(9.5
)
 
(7.5
)
Conversion of restricted units, net of units withheld for taxes
(2.8
)
 
(1.0
)
Conversion of Partnership's restricted units, net of units withheld for taxes
(2.5
)
 
(0.5
)
Proceeds from issuance of Partnership's common units
12.9

 
71.9

Proceeds from exercise of Partnership unit options
—

 
0.4

Distribution to non-controlling partners
(266.8
)
 
(124.2
)
Distribution to Members
(120.6
)
 
(51.0
)
Contribution from Devon
28.8

 
105.3

Distribution to Devon for net assets acquired (Note 3)
(171.0
)
 
—

Contributions by non-controlling interest
12.2

 
1.2

  Distributions to Predecessor
—

 
(27.2
)
Net cash provided by financing activities
296.8

 
368.1

Cash flow from discontinued operations:
 
 
 
    Net cash provided by operating activities
—

 
5.0

    Net cash used in investing activities
—

 
(0.6
)
    Net cash used in financing activities – net distributions to
       Devon and non-controlling interests
—

 
(4.4
)
Net cash provided by discontinued operations
—

 
—

Net increase in cash and cash equivalents
14.1


39.5

Cash and cash equivalents, beginning of period
68.4

 
—

Cash and cash equivalents, end of period
$
82.5

 
$
39.5

Cash paid for interest
$
46.0

 
$
19.9

Cash paid for income taxes
$
13.7

 
$
7.4

 

See accompanying notes to condensed consolidated financial statements.
6

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements
 
September 30, 2015
(Unaudited)
 
(1) General

In this report, the terms “Company” or “Registrant” as well as the terms “ENLC,” “our,” “we,” and “us,” or like terms, are sometimes used as references to EnLink Midstream, LLC and its consolidated subsidiaries. References in this report to “EnLink Midstream Partners, LP,” the “Partnership,” “ENLK” or like terms refer to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including EnLink Midstream Operating, LP and Midstream Holdings, together with their consolidated subsidiaries. “Midstream Holdings” is sometimes used to refer to EnLink Midstream Holdings, LP itself or to EnLink Midstream Holdings, LP together with EnLink Midstream Holdings GP, LLC and their subsidiaries.

(a)Organization of Business

EnLink Midstream, LLC is a Delaware limited liability company formed in October 2013. Effective as of March 7, 2014, EnLink Midstream, Inc. (“EMI”) merged with and into a wholly-owned subsidiary of the Company and Acacia Natural Gas Corp I, Inc. ("Acacia”), formerly a wholly-owned subsidiary of Devon Energy Corporation (“Devon”), merged with and into a wholly-owned subsidiary of the Company (collectively, the “mergers”). Pursuant to the mergers, each of EMI and Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. EMI owns common units representing an approximate 5.3% limited partner interest in the Partnership as of September 30, 2015 and also owns EnLink Midstream Partners GP, LLC (the “General Partner”). At the conclusion of the mergers, Acacia directly owned a 50% limited partner interest in Midstream Holdings, which was formerly a wholly-owned subsidiary of Devon. Upon closing of the business combination (as defined below), ENLC issued 115,495,669 common units to a wholly-owned subsidiary of Devon, which represents approximately 70% of the outstanding limited liability company interests in ENLC. Concurrently with the consummation of the mergers, a wholly-owned subsidiary of the Partnership acquired the remaining 50% of the outstanding limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the mergers, the “business combination”). The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.”

On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings (the "February Transferred Interests") to the Partnership in a drop down transaction (the "February EMH Drop Down") in exchange for 31,618,311 Class D Common Units in the Partnership, representing an approximate 9.6% limited partner interest in the Partnership as of September 30, 2015. On May 27, 2015, Acacia contributed the remaining 25% limited partner interest in Midstream Holdings (the "May Transferred Interests") to the Partnership in a drop down transaction (the "May EMH Drop Down" and together with the February EMH Drop Down, the "EMH Drop Downs") in exchange for 36,629,888 Class E Common Units in the Partnership, representing an approximate 11.2% limited partner interest in the Partnership as of September 30, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings. In addition, on April 1, 2015 the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets from Devon (the "VEX Interests"). See Note 3 - Acquisitions for further discussion.

Our assets consist of equity interests in the Partnership. The Partnership is a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. As of September 30, 2015, our interests in the Partnership consist of the following:

•85,679,351 common units representing an aggregate 26.1% limited partner interest in the Partnership; and
•
100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership, which owns a 0.5% general partner interest and all of the incentive distribution rights in the Partnership.


7

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


On October 29, 2015, EMI acquired 2,849,100 common units in the Partnership for aggregate consideration of approximately $50.0 million in a private placement transaction. As a result of this acquisition, our interest in the Partnership as of October 29, 2015 includes 88,528,451 common units representing a 26.7% limited partner interest.
(b) Nature of Business

The Partnership primarily focuses on providing midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization, and brine services to producers of natural gas, natural gas liquids ("NGLs"), crude oil and condensate. The Partnership's 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. The Partnership's transmission pipelines primarily receive natural gas from its gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. The Partnership also has transmission lines that transport NGLs from east Texas and its south Louisiana processing plants to its fractionators in south Louisiana. The Partnership operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of arrangements. The Partnership's processing plants remove NGLs and CO2 from a natural gas stream and its fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline. The Partnership also provides a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucking facilities as well as brine disposal services.
(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.

Further, the unaudited condensed consolidated financial statements give effect to the business combination and related transactions discussed in Note 1(a) above under the acquisition method of accounting and are treated as a reverse acquisition. Under the acquisition method of accounting, Midstream Holdings was the accounting acquirer in the transactions because its parent company, Devon, obtained control of ENLC after the business combination. All financial results prior to March 7, 2014 reflect the historical operations of Midstream Holdings and are reflected as Predecessor income in the statement of operations. Additionally, EMI’s assets acquired and liabilities assumed by the Company, as well as the Company's non-controlling interests in the Partnership, were recorded at their fair values measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of EMI’s net assets acquired was recorded as goodwill. Financial results on and subsequent to March 7, 2014 reflect the combined operations of Midstream Holdings and EMI, which give effect to new contracts entered into with Devon and include the legacy Partnership assets. Certain assets were not contributed to Midstream Holdings from the Predecessor and the operations of such non-contributed assets have been presented as discontinued operations.

On April 1, 2015 the Partnership acquired assets from Devon through drop down transactions. Due to Devon's control of the Partnership through its ownership of the managing member of ENLC, the acquisition from Devon was considered a transfer of net assets between entities under common control. As such, the Company was required to recast its historical financial statements to include the activities of such assets from the date that these entities were under common control. The consolidated financial statements for periods prior to the Partnership’s acquisition of the assets from Devon have been prepared from 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 the Partnership had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from Devon for periods prior to the Partnership’s acquisition is allocated to "Devon investment interest in net income" on the Company's Condensed Consolidated Statements of Operations.

(b) Revenue Recognition

8

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)



The Partnership generates the majority of its revenues from midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization and brine services, through various contractual arrangements, which include fee based contract arrangements or arrangements where it purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. While the transactions vary in form, the essential element of each transaction is the use of the Partnership's assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal or pipeline. The Partnership reflects 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 its midstream services as outlined above.

•
Midstream services - Midstream services represents all other revenue generated as a result of performing the Partnership's midstream services outlined above.

The Partnership recognizes 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. The Partnership generally accrues one month of sales and the related natural gas, NGL, condensate and crude oil purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent month. Actual results could differ from the accrual estimates. Except for fixed-fee based arrangements, the Partnership acts as the principal in these purchase and sale transactions, bearing the risk and reward of ownership as evidenced by title transfer, scheduling the transportation of products and assuming credit risk. The Partnership accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

(c) Redeemable Non-Controlling Interest

Non-controlling interests that contain an option for the non-controlling interest holder to require the Partnership 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 the control of the Partnership. Redeemable non-controlling interest is not considered to be a component of members' equity and is reported as temporary equity in the mezzanine section on the Condensed 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).

(d) Recent Accounting Pronouncements

In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments ("ASU 2015-16") 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. ASU 2015-16 is effective for public business entities for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. For all other entities, ASU 2015-16 is effective for fiscal years beginning after December 15, 2016, and interim periods within fiscal years beginning after December 15, 2017. Early adoption is permitted. The update is effective for us beginning on January 1, 2016.
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 Company 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 Company'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 standard will have on our condensed consolidated financial statements and related disclosures.

9

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835). The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard requires retrospective application and is effective for us beginning on January 1, 2016.
In February 2015, the FASB issued 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. The update is effective for us beginning on January 1, 2016, and we are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures.
Subject to these evaluations, we have reviewed all recently issued accounting pronouncements that became effective during the nine months ended September 30, 2015, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.

(3) Acquisitions

Chevron Acquisition

Effective November 1, 2014, the Partnership acquired, from affiliates of Chevron Corporation, Gulf Coast natural gas pipeline assets predominantly located in southern Louisiana, together with 100% of the equity interests (all of which were voting) in certain entities, for approximately $231.5 million in cash. The natural gas assets include natural gas pipelines spanning from Beaumont, Texas to the Mississippi River corridor and working natural gas storage capacity in southern Louisiana. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.

The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date.

Purchase Price Allocation (in millions):
 
 
Assets acquired:
 
 
Property, plant and equipment
 
$
225.3

Intangibles
 
13.0

Liabilities assumed:
 
 
Current liabilities
 
(6.8
)
Total identifiable net assets
 
$
231.5


The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 20 years.

The Partnership incurred $0.6 million of direct transaction costs for the nine months ended September 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from January 1, 2015 to September 30, 2015, the Partnership recognized $24.2 million of revenues and $2.2 million of net income related to the assets acquired.

LPC Acquisition

On January 31, 2015, the Partnership acquired 100% of the equity interests (all of which were voting) 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 ($87.0 million, net of cash acquired). The transaction was accounted for using the acquisition method.


10

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


The following table presents the fair value of the identified assets received and liabilities assumed at the acquisition date.

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

Property, plant 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


The Partnership recognized intangible assets related to customer relationships and trade name. The acquired intangible assets related to customer relationships will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 years.

The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change. 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 Crude and Condensate segment and is non-deductible for tax purposes.

The Partnership incurred $0.2 million of direct transaction costs for the nine months ended September 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from January 31, 2015 to September 30, 2015, the Partnership recognized $853.3 million of revenues and $1.2 million of net income related to the assets acquired.

Coronado Acquisition

On March 16, 2015, the Partnership acquired 100% of the equity interests (all of which were voting) in Coronado Midstream Holdings LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600.2 million. The purchase price consisted of $240.2 million in cash ($238.8 million, net of cash acquired), 6,704,285 common units and 6,704,285 Class C Common Units, both in the Partnership.

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 (including $1.4 million in cash)
 
$
20.8

Property, plant and equipment
 
302.1

Intangibles
 
281.0

Goodwill
 
18.6

Liabilities assumed:
 
 
Current liabilities
 
(22.3
)
Total identifiable net assets
 
$
600.2


11

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)



The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately 10 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.

The Partnership incurred $3.1 million of direct transaction costs for the nine months ended September 30, 2015. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from March 17, 2015 to September 30, 2015, the Partnership recognized $126.0 million of revenues and $7.7 million of net loss related to the assets acquired.
VEX Pipeline Drop Down
On April 1, 2015, the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets located in the Eagle Ford Shale in south Texas, together with 100% of the equity interests (all of which were voting) in certain entities, from Devon in a drop down transaction (the "VEX Drop Down"). The aggregate consideration paid by the Partnership consisted of $171.0 million in cash, 338,159 common units representing limited partner interests in the Partnership with an aggregate value of approximately $9.0 million and the Partnership’s assumption of up to $40.0 million in certain construction costs related to VEX. The VEX pipeline is a multi-grade crude oil pipeline located in the Eagle Ford Shale. Other VEX assets at the destination of the pipeline include a truck unloading terminal, above-ground storage and rights to barge loading docks. 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 the Partnership's 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 $40.0 million and is recognized as a distribution to Devon. The period of common control for VEX began on February 28, 2014, the effective date of the acquisition of the VEX Interests by Devon.
The following tables present the impact of the VEX Drop Down as presented in the Company's historical Condensed Consolidated Statements of Operations for the nine months ended September 30, 2015 and three and nine months ended September 30, 2014:
 
 
Nine Months Ended September 30, 2015
 
 
Company Historical
 
VEX
 
Combined
 
 
(in millions)
Revenues
 
$
3,381.4

 
$
4.2

 
$
3,385.6

Net income (loss)
 
$
(688.7
)
 
$
0.7

 
$
(688.0
)
Net loss attributable to non-controlling interest
 
$
(526.1
)
 
$
—

 
$
(526.1
)
Net income (loss) attributable to EnLink Midstream, LLC
 
$
(162.6
)
 
$
0.7

 
$
(161.9
)
EnLink Midstream, LLC interest in net loss
 
$
(162.6
)
 
$
—

 
$
(162.6
)
 
 
Three Months Ended September 30, 2014
 
 
Company Historical
 
VEX
 
Combined
 
 
(in millions)
Revenues
 
$
855.0

 
$
2.4

 
$
857.4

Net income (loss)
 
$
66.5

 
$
(2.3
)
 
$
64.2

Net income attributable to non-controlling interest
 
$
37.7

 
$
—

 
$
37.7

Net income (loss) attributable to EnLink Midstream, LLC
 
$
28.8

 
$
(2.3
)
 
$
26.5

EnLink Midstream, LLC interest in net income
 
$
28.8

 
$
—

 
$
28.8



12

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


 
 
Nine Months Ended September 30, 2014
 
 
Company Historical
 
VEX
 
Combined
 
 
(in millions)
Revenues
 
$
2,505.3

 
$
2.4

 
$
2,507.7

Net income (loss)
 
$
180.4

 
$
(5.3
)
 
$
175.1

Net income attributable to non-controlling interest
 
$
80.5

 
$
—

 
$
80.5

Net income attributable to EnLink Midstream, LLC
 
$
99.9

 
$
(5.3
)
 
$
94.6

EnLink Midstream, LLC interest in net income (1)
 
$
64.4

 
$
—

 
$
64.4

(1)
Represents net income for the period from February 28, 2014 through September 30, 2014.

Devon Merger

On March 7, 2014, EMI merged with and into a wholly-owned subsidiary of the Company, and Acacia, formerly a wholly-owned subsidiary of Devon, merged with and into another wholly-owned subsidiary of the Company (collectively, the “mergers”). Upon consummation of the mergers, EMI and Acacia became wholly-owned subsidiaries of the Company and the Company became publicly held. As of September 30, 2015, the Company, through its ownership of EMI, owned approximately 5.3% of the outstanding limited partner interests in the Partnership and owned 100% of the General Partner. The Company, through its ownership of Acacia, indirectly owns a 50% limited partner interest in Midstream Holdings. Midstream Holdings owns midstream assets previously held by Devon in the Barnett Shale in North Texas, the Cana-Woodford Shale and Arkoma-Woodford Shale in Oklahoma and a contractual right to the burdens and benefits associated with Devon’s 38.75% interest in Gulf Coast Fractionators (“GCF”) in Mt. Belvieu, Texas.

Also effective as of March 7, 2014, a wholly-owned subsidiary of the Partnership acquired the remaining 50% limited partner interest in Midstream Holdings and all of the outstanding equity interests in EnLink Midstream Holdings GP, LLC, the general partner of Midstream Holdings (together with the mergers, the “business combination”).

Under the acquisition method of accounting, Midstream Holdings was the acquirer in the business combination because its parent company, Devon, obtained control of ENLC. Consequently, Midstream Holdings’ assets and liabilities retained their carrying values. Additionally, EMI’s assets acquired and liabilities assumed by ENLC, as well as ENLC’s non-controlling interest in the Partnership, are recorded at their fair values measured as of the acquisition date. The excess of the purchase price over the estimated fair values of EMI’s net assets acquired is recorded as goodwill.

Since equity consideration was issued for this business combination, the purchase of these assets and liabilities has been excluded from our statement of cash flows, except for transaction related costs totaling $51.4 million assumed by ENLC at closing and subsequently paid by ENLC.

For the period from March 7, 2014 to September 30, 2014, the Company recognized $1,669.0 million of revenues and $45.7 million of net loss related to the assets acquired in the business combination.

Pro Forma Information

The following unaudited pro forma condensed financial information for the nine months ended September 30, 2015 and the three and nine months ended September 30, 2014 gives effect to the business combination, Chevron acquisition, Coronado acquisition, LPC acquisition, and VEX Drop Down as if they had occurred on January 1, 2014. 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 business combination and acquisitions is reflected below.

13

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


 
 
Three Months Ended
September 30,
 
Nine Months Ended 
 September 30,
 
 
2014
 
2015
 
2014
 
(in millions)
Pro forma total revenues (1)
 
$
1,396.4

 
$
3,507.8

 
$
4,233.4

Pro forma net income (loss)
 
$
52.9

 
$
(693.2
)
 
$
126.9

Pro forma net income (loss) attributable to EnLink Midstream, LLC
 
$
26.0

 
$
(163.7
)
 
$
68.6

Pro forma net income (loss) per common unit:
 
 
 


 
 
Basic
 
$
0.17

 
$
(1.00
)
 
$
0.45

Diluted
 
$
0.17

 
$
(1.00
)
 
$
0.45

(1)
On January 1, 2014, Midstream Holdings entered into gathering and processing agreements with Devon, which are described in Note 5.

(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 Partnership evaluates goodwill for impairment annually as of October 31st, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Partnership first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step 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 September 2015, the Partnership determined that sustained weakness in the overall energy sector driven by low commodity prices together with a decline in its unit price caused a change in circumstances warranting an interim impairment test. Based on these triggering events, the Partnership performed a goodwill impairment analysis on all reporting units.

The Partnership performs its goodwill assessment at the reporting unit level. The Partnership uses a discounted cash flow analysis to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples and estimated future cash flows, including volume forecasts and estimated operating and general and administrative costs. In estimating cash flows, the Partnership incorporates current and historical market information, among other factors.

Using the fair value approaches described above, in step one of the goodwill impairment test, the Partnership determined that the estimated fair value of its Louisiana reporting unit was less than its carrying amount, primarily related to commodity prices and discount rates. 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 the Partnership's Louisiana reporting unit in the amount of $576.1 million was recognized for the three months ended September 30, 2015, which is included in impairment expense in the Condensed Consolidated Statements of Operations.

The Partnership concluded that the fair value of goodwill of its remaining reporting units exceeded their carrying value, and the entire amount of goodwill disclosed on the Condensed Consolidated Balance Sheet associated with these remaining reporting units is recoverable. Therefore, no other goodwill impairment was identified or recorded for the remaining reporting units as a result of the Partnership's interim goodwill assessment.

The Partnership's 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 the Partnership's assumptions and estimates, or its assumptions and estimates change due to new

14

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


information, it may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. A continuing prolonged period of lower commodity prices may adversely affect the Partnership's estimate of future operating results, which could result in future goodwill impairment charges for other reporting units due to the potential impact on the cash flows of its operations.


The table below provides a summary of the Partnership’s change in carrying amount of goodwill, by assigned reporting unit.
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
 
(in millions)
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
Balance, beginning of period
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
1,426.9

 
$
3,684.7

Acquisitions (1)
18.6

 
—

 
—

 
29.6

 
—

 
48.2

Impairment
—

 
(576.1
)
 
—

 
—

 
—

 
(576.1
)
Balance, end of period
$
1,186.8

 
$
210.7

 
$
190.3

 
$
142.1

 
$
1,426.9

 
$
3,156.8

(1)See Note 3-Acquisitions for further discussion.

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.

In the third quarter of 2015, the Partnership reviewed its various assets groups for impairment due to the triggering events described in the goodwill impairment analysis above. The undiscounted cash flows related to one of the Partnership's assets groups in the Crude and Condensate segment were not in excess of its related carrying value. The Partnership estimated the fair value of this reporting unit and determined the fair of the intangible assets was not in excess of their carrying value. This resulted in a $223.1 million impairment of intangible assets in the Partnership's Crude and Condensate segment. The non-cash impairment charge is included in the impairment expense line item of the Condensed Consolidated Statement of Operations. The Partnership utilized Level 3 fair value measurements in its impairment analysis of this definite-lived intangible asset, which included discounted cash flow assumptions by management consistent with those utilized in its goodwill impairment analysis.

The following table represents the Partnership's change in carrying value of intangible assets for the periods stated (in millions):
 
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
Carrying
Amount
Nine Months Ended September 30, 2015
 
 
 
 
 
 
Customer relationships, beginning of period
 
$
569.5

 
$
(36.5
)
 
$
533.0

Acquisitions
 
337.2

 
—

 
337.2

Amortization expense
 
—

 
(44.3
)
 
(44.3
)
Impairment
 
(261.0
)
 
37.9

 
(223.1
)
Customer relationships, end of period
 
$
645.7

 
$
(42.9
)
 
$
602.8


The weighted average amortization period for intangible assets is 11.4 years. Amortization expense for intangibles was approximately $14.6 million and $10.2 million for the three months ended September 30, 2015 and 2014, respectively, and $44.3 million and $23.2 million for the nine months ended September 30, 2015 and 2014, respectively.


15

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


The following table summarizes the Partnership's estimated aggregate amortization expense for the next five years (in millions):
2015 (remaining)
$
10.3

2016
41.2

2017
41.2

2018
41.2

2019
41.2

Thereafter
427.7

Total
$
602.8


(5) Affiliate Transactions

The Partnership engages in various transactions with Devon and other affiliated entities. For the three and nine months ended September 30, 2015 and 2014, Devon was a significant customer to the Partnership. Devon accounted for 16.3% and 15.9% of the Partnership's revenues for the three and nine months ended September 30, 2015, respectively, and 24.3% and 34.9% for the three and nine months ended September 30, 2014, respectively. The Partnership had an accounts receivable balance related to transactions with Devon of $119.3 million as of September 30, 2015 and $121.6 million as of December 31, 2014. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $24.2 million as of September 30, 2015 and $3.0 million as of December 31, 2014. 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.

Gathering, Processing and Transportation Agreements with Devon

As described in Note 1, Midstream Holdings was previously a wholly-owned subsidiary of Devon, and all of its assets were contributed to it by Devon.  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 the Partnership's 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 average minimum daily volumes of natural gas to Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales during each calendar quarter for a five-year period following execution. Devon is entitled to firm service, meaning that if capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law.

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

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.

16

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)



Effective December 1, 2014, Gas Services assigned one of its 10-year gathering and processing agreements to Linn Exchange Properties, LLC (“Linn Energy”), which is a subsidiary of Linn Energy, LLC, in connection with Gas Services' divestiture of certain of its southeastern Oklahoma assets. Accordingly, beginning on December 1, 2014, Linn Energy began performing Gas Services' obligations under the applicable agreement, which relates to production dedicated to our Northridge assets in southeastern Oklahoma and remains in full force and effect.

Other Commercial Relationships with Devon

As noted above, the Partnership continues to maintain a customer relationship with Devon originally established prior to the business combination pursuant to which the Partnership provides 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 expire between October 2015 and July 2021, renewing automatically for month-to-month or year-to-year periods unless canceled by Devon prior to expiration.  In addition, the Partnership has agreements with Devon pursuant to which the Partnership purchases and sells NGLs, gas and crude oil and pays or receives, as applicable, a margin-based fee.  These NGL, gas and crude oil purchase and sale agreements have month-to-month terms.

VEX Transportation Agreement

In connection with the VEX acquisition, the Operating Partnership became party to a five year transportation services agreement with Devon pursuant to which the Operating Partnership provides transportation services to Devon on the VEX pipeline.

Transition Services Agreement

In connection with the consummation of the business combination, the Partnership entered into a transition services agreement with Devon pursuant to which Devon provides certain services to the Partnership with respect to the business and operations of Midstream Holdings and the Partnership provides certain services to Devon. General and administrative expenses related to the transition service agreement were $0.1 million and $0.2 million for the three and nine months ended September 30, 2015, respectively, and $1.0 million and $2.3 million for the three and nine months ended September 30, 2014, respectively. We received $0.2 million from Devon under the transition services agreement for the nine months ended September 30, 2015. Substantially all services under the transition services agreement were completed during 2014.

EMH Drop Down to Partnership

On February 17, 2015, Acacia contributed the February Transferred Interests to the Partnership in exchange for 31,618,311 Class D Common Units in the Partnership with an implied value of $925.0 million. The Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution for the fiscal quarter ended March 31, 2015. The Class D Common Units converted into common units on a one-for-one basis on May 4, 2015.

On May 27, 2015, Acacia contributed the May Transferred Interests to the Partnership in exchange for 36,629,888 Class E Common Units in the Partnership with an implied value of $900.0 million. The Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution for the fiscal quarter ended June 30, 2015. The Class E Common Units converted into common units on a one-for-one basis on August 3, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings.

E2 Drop Down to Partnership

On October 22, 2014, EMI contributed its equity interests in E2 Appalachian Compression, LLC and E2 Energy Services, LLC (together “E2”) to the Partnership in a drop down transaction (the "E2 Drop Down"). The total consideration for the transaction was approximately $194.0 million, including a cash payment of $163.0 million and the issuance of approximately 1.0 million Partnership units (valued at approximately $31.2 million based on the October 22, 2014 closing price of the Partnership's units).


17

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


Predecessor Affiliate Transactions

Prior to March 7, 2014, affiliate transactions relate to Predecessor transactions consisting of sales to and from affiliates, services provided by affiliates, cost allocations from affiliates and centralized cash management activities performed by affiliates.

The following presents financial information for the Predecessor's affiliate transactions and other transactions with Devon, all of which are settled through an adjustment to equity prior to March 7, 2014 (in millions):
 
Nine Months Ended September 30, 2014
Continuing Operations:
 
Revenues - affiliates
$
(436.4
)
Operating cost and expenses - affiliates
340.0

Net affiliate transactions
(96.4
)
Capital expenditures
16.2

Other third-party transactions, net
53.0

Net third-party transactions
69.2

Net cash distributions to Devon - continuing operations
(27.2
)
Non-cash distribution of net assets to Devon
(23.5
)
Total net distributions per equity
$
(50.7
)
 
 
Discontinued operations:
 
Revenues - affiliates
$
(10.4
)
Operating costs and expenses - affiliates
5.0

Net affiliate transactions
(5.4
)
Capital expenditures
0.6

Other third-party transactions, net
0.4

Net third-party transactions
1.0

Net cash distributions to Devon and non-controlling interests - discontinued operations
(4.4
)
Non-cash distribution of net assets to Devon
(39.9
)
Total net distributions per equity
$
(44.3
)
Total distributions- continuing and discontinued operations
$
(95.0
)

Share-based compensation costs included in the management services fee charged to Midstream Holdings by Devon were approximately $2.8 million for the nine months ended September 30, 2014. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Partnership by Devon were approximately $1.6 million for the nine months ended September 30, 2014. These amounts are included in general and administrative expenses in the accompanying statements of operations.


18

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


(6) Long-Term Debt
 
As of September 30, 2015 and December 31, 2014, long-term debt consisted of the following (in millions):
 
September 30, 2015
 
December 31,
2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at September 30, 2015 and December 31, 2014 was 1.5% and 1.9% respectively
$
175.0

 
$
237.0

Company credit facility (due 2019)
—

 
—

The Partnership's senior unsecured notes (due 2019), net of discount of $0.4 million at September 30, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70%
399.6

 
399.5

The Partnership's senior unsecured notes (due 2022), including a premium of $19.7 million at September 30, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%
182.2

 
184.4

The Partnership's senior unsecured notes (due 2024), net of premium of $2.9 million at September 30, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%
552.9

 
553.2

Partnership's Senior unsecured notes (due 2025), net of discount of $1.2 million at September 30, 2015, which bear interest at the rate of 4.15%
748.8

 
—

The Partnership's senior unsecured notes (due 2044), net of discount of $0.3 million at September 30, 2015 and December 31, 2014, which bear interest at the rate of 5.60%
349.7

 
349.7

The Partnership's senior unsecured notes (due 2045), net of discount of $6.9 million at September 30, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%
443.1

 
298.3

Other debt
0.2

 
0.4

Debt classified as long-term
$
2,851.5

 
$
2,022.5


Company Credit Facility

On March 7, 2014, the Company entered into a $250.0 million revolving credit facility, which includes a $125.0 million letter of credit subfacility (the “credit facility”). Our obligations under the credit facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 17,431,152 Partnership common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us and (iii) any additional equity interests subsequently pledged as collateral under the credit facility.

The credit facility will mature on March 7, 2019. The credit facility contains certain financial, operational and legal covenants. The financial covenants are tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter, and include (i) maintaining a maximum consolidated leverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the credit facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) of 2.50 to 1.00 at all times unless an investment grade event (as defined in the credit facility) occurs.

Borrowings under the credit facility bear interest, at our option, at either 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 leverage ratio. Upon breach by us of certain covenants governing the credit facility, amounts outstanding under the credit facility, if any, may become due and payable immediately and the liens securing the credit facility could be foreclosed upon. The Company expects to be in compliance with the covenants in the existing credit facility for at least the next twelve months.


19

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


As of September 30, 2015 there were no borrowings under the credit facility, leaving $250.0 million available for future borrowing based on the borrowing capacity of $250.0 million.

Partnership Credit Facility

On February 20, 2014, the Partnership entered into a $1.0 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”). On February 5, 2015, the Partnership exercised the accordion under the Partnership credit facility, increasing the size of the facility to $1.5 billion and also exercised an option to extend the maturity date of the Partnership credit facility to March 6, 2020. The Partnership also entered into certain amendments to the Partnership credit facility pursuant to which the Partnership is permitted to, (1) subject to certain conditions and the receipt of additional commitments by one or more lenders, increase the aggregate commitments under the Partnership credit facility by an additional amount not to exceed $500 million and, (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of the Partnership credit facility by one year on each occasion. The Partnership credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to consolidated EBITDA (as defined in the Partnership credit facility, which definition includes projected EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If the Partnership consummates one or more acquisitions in which the aggregate purchase price is $50.0 million or more, the maximum allowed ratio of consolidated indebtedness to consolidated EBITDA may be increased to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.

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

As of September 30, 2015, there were $2.8 million in outstanding letters of credit and $175.0 million in outstanding borrowings under the Partnership’s credit facility, leaving approximately $1.3 billion available for future borrowing based on the borrowing capacity of $1.5 billion.

All other material terms and conditions of the Partnership credit facility are described in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Indebtedness” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The Partnership expects to be in compliance with all credit facility covenants for at least the next twelve months.

On May 12, 2015, the Partnership issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of its 4.150% senior notes due 2025 (the “2025 Notes”) and $150.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 Notes” and together with the 2025 Notes, the "Senior Notes") at prices to the public of 99.827% and 96.381%, respectively, of their face value. The 2025 Notes mature on June 1, 2025 and the 2045 Notes mature on April 1, 2045. Interest payments on the 2025 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2015. Interest payments on the 2045 Notes are payable on April 1 and October 1 of each year, beginning October 1, 2015.

Prior to March 1, 2025, the 2025 Notes are redeemable, at the option of the Partnership, at any time in whole, or from time to time in part, at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2025 Notes to be redeemed; or (ii) the sum of the present values of the remaining scheduled payments of principal and interest on the 2025 Notes to be redeemed that would be due if the 2025 Notes matured on March 1, 2025 (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus, in either case, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after March 1, 2025, the 2025 Notes are redeemable, at the option of the Partnership, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2025 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

Prior to October 1, 2044, the Partnership may redeem all or a part of the 2045 Notes at a redemption price equal to the greater of: (i) 100% of the principal amount of the 2045 Notes to be redeemed; or (ii) the sum of the present values of the

20

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


remaining scheduled payments of principal and interest on the 2045 Notes to be redeemed that would be due after the related redemption date but for such redemption (exclusive of interest accrued to, but excluding, the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the applicable Treasury Rate plus 30 basis points; plus, in either case, accrued and unpaid interest to, but excluding, the redemption date. At any time on or after October 1, 2044, the Partnership may redeem all or a part of the 2045 Notes at a redemption price equal to 100% of the principal amount of the 2045 Notes to be redeemed plus accrued and unpaid interest to, but excluding, the redemption date.

The indentures governing the Senior Notes contain covenants that, among other things, limit our ability to create or incur certain liens or consolidate, merge or transfer all or substantially all of our assets.

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

•
failure to pay any principal or interest when due;

•
failure to observe any other agreement, obligation or other covenant in the indenture, subject to the cure periods for certain failures;

•
our default under other indebtedness that exceeds a certain threshold amount;

•
failure by us to pay final judgments that exceed a certain threshold amount; and

•
bankruptcy or other insolvency events involving us.

If an event of default relating to bankruptcy or other insolvency events occurs, the Senior Notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the Senior Notes may accelerate the maturity of the Senior Notes and exercise other rights and remedies.
(7)     Income Taxes

Income taxes included in the condensed consolidated financial statements were as follows for the periods presented.
 
 
Three Months Ended  
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Predecessor income tax expense
 
$
—

 
$
—

 
$
—

 
$
19.4

ENLC income tax expense
 
0.2

 
17.3

 
21.1

 
40.1

       Total income tax expense
 
$
0.2

 
$
17.3

 
$
21.1

 
$
59.5


The following schedule reconciles total income tax expense and the amount computed by applying the statutory U.S. federal tax rate to income from continuing operations before income taxes:

21

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


 
 
Three Months Ended  
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Tax computed at statutory federal rate (35%)
 
$
(67.6
)
 
$
16.1

 
$
(49.5
)
 
$
36.5

State income taxes, net of federal tax benefit
 
(4.8
)
 
1.2

 
(3.5
)
 
2.6

Predecessor income tax expense
 
—

 
—

 
—

 
19.4

Income taxes from partnership
 
0.6

 
—

 
1.7

 
0.8

Non-deductible expense related to asset impairment
 
72.3

 
—

 
72.3

 
—

Other
 
(0.3
)
 
—

 
0.1

 
0.2

       Total income tax expense
 
$
0.2

 
$
17.3

 
$
21.1

 
$
59.5


(8)      Certain Provisions of the Partnership Agreement

(a) Issuance of Common Units

In November 2014, the Partnership 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 the Partnership’s common units from time to time through an “at the market” equity offering program. The Partnership 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. The Partnership has 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 nine months ended September 30, 2015, the Partnership sold an aggregate of 0.7 million common units under the BMO EDA, generating proceeds of approximately $12.9 million (net of less than $0.1 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of September 30, 2015, approximately $328.7 million remains available to be issued under the BMO EDA.

(b) Class C Common Units

In March 2015, the Partnership issued 6,704,285 Class C Common Units representing a new class of limited partner interests as partial consideration for the acquisition of Coronado. For further discussion, see Note 3- Acquisitions. The Class C Common Units are substantially similar in all respects to the Partnership's common units, except that distributions paid on the Class C Common Units may be paid in cash or in additional Class C Common Units issued in kind, as determined by the General Partner in its sole discretion. The Class C Common Units will automatically convert into common units on a one-for-one basis on the earlier to occur of (i) the date on which the General Partner, in its sole discretion, determines to convert all of the outstanding Class C Common Units into common units and (ii) the first business day following the date of the distribution for the quarter ended March 31, 2016. Distributions on the Class C Common Units for the three months ended March 31, 2015 and June 30, 2015 were paid-in-kind ("PIK") through the issuance of 99,794 and 120,622 Class C Common Units on May 14, 2015 and August 13, 2015, respectively. A distribution on the Class C Common Units of $0.390 per unit was declared for the three months ended September 30, 2015, which will result in the issuance of 150,732 additional Class C Common Units on November 12, 2015.

(c) Class D Common Units

In February 2015, the Partnership issued 31,618,311 Class D Common Units to Acacia as consideration for a 25% interest in Midstream Holdings. For further discussion, see Note 3 - Acquisitions. The Partnership’s Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution from the date of issuance for the fiscal quarter ended March 31, 2015. The Partnership’s Class D Common Units automatically converted into the Partnership’s common units on a one-for-one basis on May 4, 2015.

(d) Class E Common Units

In May 2015, the Partnership issued 36,629,888 Class E Common Units to Acacia as consideration for the remaining 25% interest in Midstream Holdings. For further discussion see Note 5 - Affiliate Transactions. The Partnership’s Class E Common

22

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


Units were substantially similar in all respects to the Partnership’s common units, except that they only received a pro rata distribution from the date of issuance for the fiscal quarter ended June 30, 2015. The Partnership’s Class E Common Units automatically converted into the Partnership’s common units on a one-for-one basis on August 3, 2015.

(e)  Distributions
 
Unless restricted by the terms of the Partnership credit facility and/or the indentures governing the Partnership’s senior unsecured notes, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions are made to the General Partner in accordance with its current percentage interest with the remainder to the common unitholders, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. The General Partner is not entitled to its general partner or incentive distributions with respect to the Class C Common Units issued in kind.

Under the quarterly incentive distribution provisions, generally the Partnership's General Partner is entitled to 13.0% of amounts the Partnership distributes in excess of $0.25 per unit, 23% of the amounts the Partnership distributes in excess of $0.3125 per unit and 48.0% of amounts the Partnership distributes in excess of $0.375 per unit.

A summary of the Partnership's distribution activity relating to the common units for the nine months ended September 30, 2015 is provided below:
Declaration period
 
Distribution/unit
 
Date paid/payable
Fourth Quarter of 2014
 
$
0.375

 
February 12, 2015
First Quarter of 2015 (1)
 
$
0.38

 
May 14, 2015
Second Quarter of 2015 (2)
 
$
0.385

 
August 13, 2015
Third Quarter of 2015
 
$
0.39

 
November 12, 2015
(1) The Partnership partial first quarter 2015 distributions on its Class D Common Units of $0.18 per unit were paid on May 14, 2015. Distributions paid for the Class D Common Units represent a pro rata distribution for the number of days the Class D Common Units were issued and outstanding during the quarter. The Class D Common Units automatically converted into common units on a one-for-one basis on May 4, 2015.
(2) The Partnership partial second quarter 2015 distributions on its Class E Common Units of $0.15 per unit were paid on August 13, 2015. Distributions paid for the Class E Common Units represent a pro rata distribution for the number of days the Class E Common Units were issued and outstanding during the quarter. The Class E Common Units automatically converted into common units on a one-for-one basis on August 3, 2015.

(f) Allocation of Partnership Income

Net income is allocated to the General Partner in an amount equal to its incentive distributions as described in Note 8(e). The General Partner's share of net income consists of incentive distributions to the extent earned, a deduction for unit-based compensation attributable to ENLC’s restricted units and the percentage interest of the Partnership’s net income adjusted for ENLC's unit-based compensation specifically allocated to the General Partner. The net income allocated to the General Partner is as follows for the three and nine months ended September 30, 2015 and 2014 (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014*
Income allocation for incentive distributions
$
13.6

 
$
6.3

 
$
33.7

 
$
13.6

Unit-based compensation attributable to ENLC’s restricted units
(3.7
)
 
(3.1
)
 
(14.6
)
 
(6.8
)
General Partner share of net income (loss)
(3.6
)
 
0.3

 
(3.3
)
 
0.7

General Partner interest in drop down transactions
—

 
39.4

 
34.4

 
89.3

General Partner interest in net income
$
6.3

 
$
42.9

 
$
50.2

 
$
96.8

* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.


23

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


(9) Earnings per Unit and Dilution Computations

As required under FASB ASC 260-10-45-61A, unvested unit-based payments that entitle employees to receive non-forfeitable distributions are considered participating securities, as defined in FASB ASC 260-10-20, for earnings per unit calculations. Net income earned by the Predecessor prior to March 7, 2014 is not included for purposes of calculating earnings per unit as the Predecessor did not have any unitholders.

The following table reflects the computation of basic and diluted earnings per unit for the three and nine months ended September 30, 2015 and 2014 (in millions, except per unit amounts):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2015
 
2014
 
2015
 
2014*
EnLink Midstream, LLC interest in net income (loss)
$
(193.4
)
 
$
28.8

 
$
(162.6
)
 
$
64.4

Distributed earnings allocated to:
 
 
 
 
 
 
 
Common units (1) (2)
$
41.9

 
$
37.7

 
$
123.2

 
$
88.3

Unvested restricted units (1)
0.3

 
0.2

 
0.9

 
0.6

Total distributed earnings
$
42.2

 
$
37.9

 
$
124.1

 
$
88.9

Undistributed loss allocated to:
 
 
 
 
 
 
 
Common units
$
(233.9
)
 
$
(9.1
)
 
$
(284.7
)
 
$
(24.3
)
Unvested restricted units
(1.7
)
 
—

 
(2.0
)
 
(0.2
)
Total undistributed loss
$
(235.6
)
 
$
(9.1
)
 
$
(286.7
)
 
$
(24.5
)
Net income (loss) allocated to:
 
 
 
 
 
 
 
Common units
$
(192.0
)
 
$
28.6

 
$
(161.5
)
 
$
64.0

Unvested restricted units
(1.4
)
 
0.2

 
(1.1
)
 
0.4

Total net income (loss)
$
(193.4
)
 
$
28.8

 
$
(162.6
)
 
$
64.4

Total basic and diluted net income (loss) per unit:
 
 
 
 
 
 
 
Basic
$
(1.18
)
 
$
0.18

 
$
(0.99
)
 
$
0.39

Diluted
$
(1.18
)
 
$
0.17

 
$
(0.99
)
 
$
0.39

__________________________________________________
* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.
(1) Three months ended September 30, 2015 and 2014 represents a declared distribution of $0.255 per unit payable on November 13, 2015 and a distribution of $0.23 per unit paid on November 14, 2014.
(2) Nine months ended September 30, 2015 and 2014 represents a declared distribution of $0.255 per unit payable on November 13, 2015, and distributions paid of $0.245 per unit on May 15, 2015, $0.25 per unit on August 14, 2015, $0.18 per unit on May 15, 2014, $0.22 per unit on August 14, 2014, and $0.23 per unit on November 14, 2014. Additionally, the nine months ended September 30, 2014 includes distributions paid of $0.05 per unit for Class B Common Units on May 15, 2014.

The following are the unit amounts used to compute the basic and diluted earnings per unit for the periods presented (in millions):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2015
 
2014
 
2015
 
2014*
Basic and diluted earnings per unit:
 
 
 
 
 
 
 
Weighted average common units outstanding
164.2

 
164.0

 
164.2

 
164.0

Diluted weighted average units outstanding:
 
 
 
 
 
 
 
Weighted average basic common units outstanding
164.2

 
164.0

 
164.2

 
164.0

Dilutive effect of restricted units issued
—

 
0.4

 
—

 
0.3

Total weighted average diluted common units outstanding
164.2

 
164.4

 
164.2

 
164.3

_______________________________________________

24

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014.

All outstanding units were included in the computation of diluted earnings per unit and weighted based on the number of days such units were outstanding during the periods presented.


(10) Asset Retirement Obligations

The schedule below summarizes the changes in the Partnership’s asset retirement obligation:
 
September 30,
2015
 
September 30,
2014
 
(in millions)
Beginning asset retirement obligation
$
20.6

 
$
8.1

Revisions to existing liabilities
(4.0
)
 
3.2

Liabilities acquired
—

 
0.5

Accretion
0.4

 
0.4

    Liabilities settled
(3.2
)
 
—

Ending asset retirement obligation
$
13.8

 
$
12.2


Asset retirement obligations of $1.0 million and $8.2 million as of September 30, 2015 and December 31, 2014, respectively, are included in Other Current Liabilities.

(11) Investment in Unconsolidated Affiliates

The Partnership's unconsolidated investments consisted of a contractual right to the economic benefits and burdens associated with Devon's 38.75% ownership interest in GCF at September 30, 2015 and 2014 and a 30.6% ownership interest in Howard Energy Partners ("HEP") at September 30, 2015 and 2014.


25

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):

 
Gulf Coast Fractionators
 
Howard Energy Partners
 
Total
Three months ended
 
 
 
 
 
September 30, 2015
 
 
 
 
 
Contributions
$
—

 
$
8.1

 
$
8.1

Distributions
$
3.8

 
$
8.4

 
$
12.2

Equity in income
$
3.4

 
$
3.0

 
$
6.4

 
 
 
 
 
 
September 30, 2014 (1)
 
 
 
 
 
Contributions
$
—

 
$
—

 
$
—

Distributions
$
5.2

 
$
3.0

 
$
8.2

Equity in income
$
5.2

 
$
0.4

 
$
5.6

 
 
 
 
 
 
Nine months ended
 
 
 
 
 
September 30, 2015
 
 
 
 
 
Contributions
$
—

 
$
8.1

 
$
8.1

Distributions
$
10.7

 
$
20.7

 
$
31.4

Equity in income
$
9.7

 
$
6.4

 
$
16.1

 
 
 
 
 
 
September 30, 2014 (1)
 
 
 
 
 
Contributions
$
—

 
$
5.7

 
$
5.7

Distributions
$
5.2

 
$
8.7

 
$
13.9

Equity in income
$
13.2

 
$
1.1

 
$
14.3

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

The following table shows the balances related to the Partnership’s investment in unconsolidated affiliates for the periods indicated (in millions):
 
September 30,
2015
 
December 31,
2014
Gulf Coast Fractionators
$
53.0

 
$
54.1

Howard Energy Partners
210.5

 
216.7

Total investments in unconsolidated affiliates
$
263.5

 
$
270.8


(12) Employee Incentive Plans
 
(a)         Long-Term Incentive Plans
 
The Partnership accounts for unit-based compensation in accordance with FASB ASC 718, which requires that compensation related to all unit-based awards, including unit options, be recognized in the consolidated financial statements.

26

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)



The Partnership 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 officers and employees of the Partnership are recorded by the Partnership since ENLC has no substantial or managed operating activities other than its interests in the Partnership. Amounts recognized in the condensed consolidated financial statements with respect to these plans are as follows (in millions): 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Cost of unit-based compensation allocated to Predecessor general and
    administrative expense (1)
$
—

 
$
—

 
$
—

 
$
2.8

Cost of unit-based compensation charged to general and administrative
    expense
6.3

 
5.0

 
24.9

 
11.0

Cost of unit-based compensation charged to operating expense
1.0

 
0.8

 
4.0

 
1.8

    Total amount charged to income
$
7.3

 
$
5.8

 
$
28.9

 
$
15.6

Interest of non-controlling partners in unit-based compensation
$
2.6

 
$
2.5

 
$
11.4

 
$
5.4

Amount of related income tax benefit recognized in income
$
1.8

 
$
1.3

 
$
6.5

 
$
3.9

(1)
Unit-based compensation expense was treated as a contribution by the Predecessor in the Consolidated Statement of Changes in Members' Equity in 2014.

(b)  EnLink Midstream Partners, LP Restricted Incentive Units
 
The Partnership's restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, 2015 is provided below:
 
 
Nine Months Ended 
 September 30, 2015
EnLink Midstream Partners, LP Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
 Fair Value
Non-vested, beginning of period
 
1,022,191

 
$
31.25

Granted
 
581,047

 
26.82

Vested*
 
(264,651
)
 
28.81

Forfeited
 
(68,913
)
 
30.92

Non-vested, end of period
 
1,269,674

 
$
29.75

Aggregate intrinsic value, end of period (in millions)
 
$
20.0

 
 

 * Vested units include 90,567 units withheld for payroll taxes paid on behalf of employees.

The Partnership issued restricted incentive units in the first quarter of 2015 to officers and other employees. These restricted incentive units typically vest at the end of three years. In March 2015, the Partnership issued 128,675 restricted incentive units with a fair value of $3.4 million to officers and certain employees as bonus payments for 2014, which vested immediately and are included in the restricted units granted and vested line items above.
 

27

ENLINK MIDSTREAM, LLC
 
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 nine months ended September 30, 2015 are provided below (in millions):


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

2015
 
2014
 
2015
 
2014
Aggregate intrinsic value of units vested

$
0.1

 
$
1.2

 
$
7.2

 
$
1.2

Fair value of units vested

$
0.1

 
$
1.2

 
$
7.6

 
$
1.2


As of September 30, 2015, there was $19.5 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 1.7 years.

(c)       EnLink Midstream Partners, LP Performance Units

In March 2015, the Partnership and ENLC granted performance awards under the amended and restated EnLink Midstream GP, LLC Long-Term Incentive Plan (the "GP Plan") and the 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 the Partnership and the Company (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 (the “EnLink TSR”) for the applicable performance period relative to the TSR achievement of the Peer Companies.

At the end of the vesting period, recipients receive distribution equivalents with respect to the number of performance units vested. The vesting of units may be between zero and 200 percent of the units granted depending on the EnLink TSR as compared to the peer group 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 the Partnership and the designated peer group; (iii) an estimated ranking of the Partnership 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 Partners, LP Performance Units:
 
2015
Beginning TSR Price
 
$
27.68

Risk-free interest rate
 
0.99
%
Volatility factor
 
33.01
%
Distribution yield
 
5.66
%


28

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


The following table presents a summary of the Partnership's performance units.
 
 
Nine Months Ended 
 September 30, 2015
EnLink Midstream Partners, LP Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
—

 
$
—

Granted
 
118,126

 
35.41

Vested
 
—

 
—

Non-vested, end of period
 
118,126

 
$
35.41

Aggregate intrinsic value, end of period (in millions)
 
$
1.9

 
 

As of September 30, 2015 there was $3.3 million of unrecognized compensation expense that related to non-vested Partnership performance units. That cost is expected to be recognized over a weighted-average period of 2.3 years.

(d)         EnLink Midstream, LLC’s Restricted Incentive Units

ENLC’s restricted incentive units are valued at their fair value at the date of grant, which is equal to the market value of the common units on such date. A summary of the restricted incentive unit activity for the nine months ended September 30, 2015 is provided below:
 
 
Nine Months Ended 
 September 30, 2015
EnLink Midstream, LLC Restricted Incentive Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-vested, beginning of period
 
986,472

 
$
37.03

Granted
 
493,582

 
31.58

Vested*
 
(261,144
)
 
35.79

Forfeited
 
(59,203
)
 
35.99

Non-vested, end of period
 
1,159,707

 
$
35.04

Aggregate intrinsic value, end of period (in millions)
 
$
21.2

 
 

 * Vested units include 83,176 units withheld for payroll taxes paid on behalf of employees.

ENLC issued restricted incentive units in the first quarter of 2015 to officers and other employees. These restricted incentive units typically vest at the end of three years and are included in restricted incentive units outstanding. In March 2015, ENLC issued 102,543 restricted incentive units with a fair value of $3.4 million to officers and certain employees as bonus payments for 2014, which vested immediately and are included in the restricted units granted and vested line items above.
 
A summary of the restricted incentive units’ aggregate intrinsic value (market value at vesting date) and fair value of units vested during the three and nine months ended September 30, 2015 are provided below (in millions):
 
 
Three Months Ended
September 30,
 
Nine Months Ended 
 September 30,
EnLink Midstream, LLC Restricted Incentive Units:
 
2015
 
2014
 
2015
 
2014
Aggregate intrinsic value of units vested
 
$
0.1

 
$
2.4

 
$
8.9

 
$
2.4

Fair value of units vested
 
$
0.1

 
$
2.2

 
$
9.3

 
$
2.2


As of September 30, 2015, there was $20.2 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.


29

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


(e) EnLink Midstream, LLC's Performance Units

In March 2015, ENLC granted performance awards under the LLC Plan discussed in Note (c) above. At the end of the vesting period, recipients receive distribution equivalents with respect to the number of performance units vested. The vesting of units may be between zero and 200 percent of the units granted depending on EnLink’s TSR as compared to the peer group 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 and the designated peer group; (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:
 
2015
Beginning TSR Price
 
$
34.24

Risk-free interest rate
 
0.99
%
Volatility factor
 
33.02
%
Distribution yield
 
2.98
%

The following table presents a summary of the Company's performance units.
 
 
Nine Months Ended 
 September 30, 2015
EnLink Midstream, LLC Performance Units:
 
Number of
Units
 
Weighted
Average
Grant-Date
Fair Value
Non-Vested, beginning of period
 
—

 
$
—

Granted
 
105,080

 
40.5

Vested
 
—

 
—

Non-vested, end of period
 
105,080

 
$
40.5

Aggregate intrinsic value, end of period (in millions)
 
$
1.9

 
 

As of September 30, 2015 there was $3.3 million of unrecognized compensation expense that related to non-vested ENLC performance units. That cost is expected to be recognized over a weighted-average period of 2.3 years.
  
(13) Derivatives

Interest Rate Swaps
The Partnership entered into interest rate swaps in April and May 2015 in connection with the issuance of the 2025 Notes in May 2015.    
            
The impact of the interest rate swaps on net income is included in other income (expense) in the Condensed Consolidated Statements of Operations as part of interest expense, net, as follows (in millions):
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2015
 
2015
Settlement gains on derivatives
 
$
—

 
$
3.6


Commodity Swaps

The Partnership manages its exposure to fluctuation in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge price and location risk related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs. The

30

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


Partnership does not designate transactions as cash flow or fair value hedges for hedge accounting treatment under FASB ASC 815. Therefore, changes in the fair value of the Partnership's derivatives are recorded in revenue in the period incurred. In addition, the Partnership's risk management policy does not allow the Partnership to take speculative positions with its derivative contracts.

The Partnership commonly enters into index (float-for-float) or fixed-for-float swaps in order to mitigate its cash flow exposure to fluctuations in the future prices of natural gas, NGLs and crude oil. For natural gas, index swaps are used to protect against the price exposure of daily priced gas versus first-of-month priced gas. They are also used to hedge the basis location price risk resulting from supply and markets being priced on different indices. For natural gas, NGLs, condensate and crude, fixed-for-float swaps are used to protect cash flows against price fluctuations: (1) where the Partnership receives a percentage of liquids as a fee for processing third-party gas or where the Partnership receives 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 its business and (3) where the Partnership is mitigating the price risk for product held in inventory or storage.

The components of gain (loss) on derivative activity in the Condensed Consolidated Statements of Operations relating to commodity swaps are as follows for the three and nine months ended September 30, 2015 and 2014 (in millions):
 
Three Months Ended  
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014*
Change in fair value of derivatives
$
(0.2
)
 
$
1.8

 
$
(6.4
)
 
$
(0.2
)
Realized gain (loss) on derivatives
5.4

 
(0.8
)
 
13.0

 
(1.7
)
    Gain (loss) on derivative activity
$
5.2

 
$
1.0

 
$
6.6

 
$
(1.9
)
* The nine months ended September 30, 2014 amounts consist only of the period from March 7, 2014 through September 30, 2014. 

The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in millions):
 
September 30,
2015
 
December 31,
2014
Fair value of derivative assets — current
$
15.5

 
$
16.7

Fair value of derivative assets — long term
2.9

 
10.0

Fair value of derivative liabilities — current
(3.4
)
 
(3.0
)
Fair value of derivative liabilities — long term
(0.5
)
 
(2.0
)
    Net fair value of derivatives
$
14.5

 
$
21.7

 
Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets at September 30, 2015. The remaining term of the contracts extend no later than December 2016.
 
 
 
 
 
 
September 30, 2015
Commodity
 
Instruments
 
Unit
 
Volume
 
Fair Value
 
 
 
 
 
 
(In millions)
NGL (short contracts)
 
Swaps
 
Gallons
 
(53.3
)
 
$
16.4

NGL (long contracts)
 
Swaps
 
Gallons
 
35.8

 
(2.4
)
Natural Gas (short contracts)
 
Swaps
 
MMBtu
 
(3.1
)
 
1.3

Natural Gas (long contracts)
 
Swaps
 
MMBtu
 
1.3

 
(0.9
)
Condensate (long contracts)
 
Swaps
 
MBbls
 
0.1

 
0.1

Total fair value of derivatives
 
 
 
 
 
 
 
$
14.5

 
On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty's financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an

31

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


ongoing basis. The Partnership primarily deals with two types of counterparties, financial institutions and other energy companies, when entering into financial derivatives on commodities. The Partnership has entered into Master International Swaps and Derivatives Association Agreements ("ISDAs") that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership's counterparties failed to perform under existing swap contracts, the Partnership's maximum loss as of September 30, 2015 of $18.4 million would be reduced to $14.5 million due to the offsetting of gross fair value payables against gross fair value receivables as allowed by the ISDAs. 

Fair Value of Derivative Instruments

Assets and liabilities related to the Partnership's derivative contracts are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as a gain (loss) on derivatives in the Condensed Consolidated Statement of Operations. The Partnership estimates the fair value of all of its derivative contracts using actively quoted prices. The estimated fair value of derivative contracts by maturity date was as follows (in millions):
 
Maturity Periods
 
Less than one year
 
One to two years
 
More than two years
 
Total fair value
September 30, 2015
$
12.1

 
$
2.4

 
$
—

 
$
14.5

 
(14)      Fair Value Measurements
 
FASB ASC 820 sets forth a framework for measuring fair value and required disclosures about fair value measurements of assets and liabilities. Fair value under FASB ASC 820 is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.
 
FASB ASC 820 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.
 
The Partnership’s derivative contracts primarily consist of commodity swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined using discounted cash flow techniques. The techniques incorporate Level 1 and Level 2 inputs for future commodity prices that are readily available in public markets or can be derived from information available in publicly quoted markets. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in hierarchy.
 
Net liabilities measured at fair value on a recurring basis are summarized below (in millions):
 
September 30, 2015
Level 2
 
December 31, 2014
Level 2
Commodity Swaps*
$
14.5

 
$
21.7

Total
$
14.5

 
$
21.7

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

32

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


Fair Value of Financial Instruments
 
The estimated fair value of the Partnership’s financial instruments has been determined by the Partnership using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Partnership could realize upon the sale or refinancing of such financial instruments (in millions):
 
September 30, 2015
 
December 31, 2014
 
Carrying
Value
 
Fair
Value
 
Carrying Value
 
Fair
Value
Long-term debt
$
2,851.5

 
$
2,663.2

 
$
2,022.5

 
$
2,026.1

Obligations under capital leases
$
17.7

 
$
17.0

 
$
20.3

 
$
19.8

 
The carrying amounts of the Partnership’s cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities.

The Partnership had $175.0 million and $237.0 million in outstanding borrowings under its revolving credit facility as of September 30, 2015 and December 31, 2014, 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 September 30, 2015, the Partnership 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%. As of December 31, 2014, the Partnership had total borrowings of $1.8 billion maturing between 2019 and 2045 with fixed interest rates ranging from 2.7% to 7.1%. The fair value of all senior unsecured notes as of September 30, 2015 and December 31, 2014 was based on Level 2 inputs from third-party market quotations.  The fair value of obligations under capital leases was calculated using Level 2 inputs from third-party banks. 

(15) Commitments and Contingencies
 
(a) Severance and Change in Control Agreements
 
Certain members of management of the Partnership are parties to severance and change of control agreements with the General Partner. 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 the General Partner or its affiliates during his employment. In addition, the severance and change of control agreements prohibit subject individuals from disclosing confidential information about the General Partner or interfering with a client or customer of the General Partner or its affiliates, in each case during his employment and for a certain period of time following the termination of such person’s employment.

(b) Environmental Issues
 
The operation of pipelines, plants and other facilities for the gathering, processing, transmitting or disposing of natural gas, NGLs, 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, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's results of operations, financial condition or cash flows.


33

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


(c) Litigation Contingencies
 
The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position, results of operations or cash flows. 

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

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

In July 2013, the Board of Commissioners for the Southeast Louisiana Flood Protection Authority for New Orleans and surrounding areas filed a lawsuit against approximately 100 energy companies, seeking, among other relief, restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit was filed in Louisiana state court in New Orleans, but was removed to the United States District Court for the Eastern District of Louisiana.  The amount of damages is unspecified. The Partnership's subsidiary, 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. The Partnership intends to continue vigorously defending the case. The success of the plaintiffs' appeal as well as the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable.

The Partnership owns and operates 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. The Partnership is seeking to recover its losses from responsible parties. The Partnership has sued Texas Brine Company, LLC ("Texas Brine"), the operator of a failed cavern in the area and its insurers, seeking recovery for these losses.  The Partnership has 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. The Partnership also filed a claim with its insurers, which the Partnership's insurers denied. The Partnership disputed the denial and sued its insurers, but has agreed to stay the matter pending resolution of its claims against Texas Brine and its insurers. In August 2014, the Partnership received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million but additional claims remain outstanding. The Partnership cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties.

In June 2014, a group of landowners in Assumption Parish, Louisiana added a subsidiary of the Partnership, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine, 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 the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

In October 2014, Williams Olefins, L.L.C. filed a lawsuit against a subsidiary of the Partnership, EnLink NGL Marketing, LP, in the District Court of Tulsa County, Oklahoma. The plaintiff alleges breach of contract and negligent misrepresentation relating to an ethane output contract between the parties and the subsidiary’s termination of ethane production from one of its

34

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


fractionation plants. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership’s costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case.

(16) Segment Information
 
Identification of the majority of the Company's operating segments is based principally upon geographic regions served.  The Company’s reportable segments consist of the following: natural gas gathering, processing, transmission and fractionation operations located in north Texas, south Texas and the Permian Basin in west Texas ("Texas"), the pipelines and processing plants located in Louisiana and NGL assets located in south Louisiana ("Louisiana"), natural gas gathering and processing operations located throughout Oklahoma ("Oklahoma") and crude rail, truck, pipeline and barge facilities in west Texas, south Texas, Louisiana and Ohio River Valley ("Crude and Condensate"). The Company's Crude and Condensate segment, which is identified based upon the nature of services provided to customers of the segment, has historically been referred to as the Company's ORV segment. Due to the growth in this segment, including the acquisitions of LPC and VEX, the Company has renamed this segment to more accurately reflect the assets included therein. The Company has restated the prior period to include certain crude and condensate activity in the Crude and Condensate segment. Operating activity for intersegment eliminations is shown in the corporate segment.  The Company’s sales are derived from external domestic customers.
 
Corporate expenses include general partnership expenses associated with managing all reportable operating segments. Corporate assets consist primarily of cash, property and equipment, including software, for general corporate support, debt financing costs and investments in HEP and GCF. The Company evaluates the performance of its operating segments based on operating revenues and segment profits.

Summarized financial information concerning the Company’s reportable segments is shown in the following tables:
 
Texas
 
Louisiana
 
Oklahoma
 
Crude and Condensate
 
Corporate
 
Totals
 
(In millions)
Three Months Ended September 30, 2015
 

 
 

 
 

 
 

 
 

 
 

Product sales
$
106.9

 
$
399.0

 
$
3.9

 
$
353.7

 
$
—

 
$
863.5

Product sales-affiliates
35.3

 
17.6

 
4.6

 
0.4

 
(17.6
)
 
40.3

Midstream services
20.3

 
63.3

 
9.4

 
18.3

 
—

 
111.3

Midstream services-affiliates
111.6

 
5.1

 
34.5

 
3.6

 
(4.5
)
 
150.3

Cost of sales
(124.5
)
 
(415.2
)
 
(9.4
)
 
(334.8
)
 
22.1

 
(861.8
)
Operating expenses
(44.3
)
 
(27.2
)
 
(7.2
)
 
(26.3
)
 
—

 
(105.0
)
Gain on derivative activity
—

 
—

 
—

 
—

 
5.2

 
5.2

Segment profit
$
105.3

 
$
42.6

 
$
35.8

 
$
14.9

 
$
5.2

 
$
203.8

Depreciation and amortization
$
(44.4
)
 
$
(27.4
)
 
$
(11.9
)
 
$
(12.9
)
 
$
(1.8
)
 
$
(98.4
)
Impairments
$
—

 
$
(576.1
)
 
$
—

 
$
(223.1
)
 
$
—

 
$
(799.2
)
Goodwill
$
1,186.8

 
$
210.7

 
$
190.3

 
$
142.1

 
$
1,426.9

 
$
3,156.8

Capital expenditures
$
29.0

 
$
13.5

 
$
19.7

 
$
38.6

 
$
3.9

 
$
104.7

Three Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
52.5

 
$
426.5

 
$
—

 
$
100.1

 
$
—

 
$
579.1

Product sales-affiliates
19.2

 
36.4

 
—

 
—

 
(17.8
)
 
37.8

Midstream services
19.1

 
38.9

 
—

 
10.6

 
—

 
68.6

Midstream services-affiliates
122.7

 
2.0

 
45.8

 
2.4

 
(2.0
)
 
170.9

Cost of sales
(64.2
)
 
(462.6
)
 
—

 
(90.2
)
 
19.8

 
(597.2
)
Operating expenses
(37.9
)
 
(20.3
)
 
(7.0
)
 
(14.6
)
 
—

 
(79.8
)
Gain on litigation settlement
—

 
6.1

 
—

 
—

 
—

 
6.1

Gain on derivative activity
—

 
—

 
—

 
—

 
1.0

 
1.0

Segment profit
$
111.4

 
$
27.0

 
$
38.8

 
$
8.3

 
$
1.0

 
$
186.5

Depreciation and amortization
$
(31.6
)
 
$
(19.1
)
 
$
(11.8
)
 
$
(11.7
)
 
$
(0.9
)
 
$
(75.1
)

35

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
1,436.8

 
$
3,694.6

Capital expenditures
$
79.7

 
$
79.1

 
$
2.5

 
$
43.8

 
$
3.9

 
$
209.0

 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
237.3

 
$
1,173.6

 
$
2.4

 
$
1,075.5

 
$
—

 
$
2,488.8

Product sales-affiliates
91.5

 
37.4

 
10.2

 
0.8

 
(50.3
)
 
89.6

Midstream services
76.2

 
184.5

 
29.9

 
60.7

 
—

 
351.3

Midstream services-affiliates
342.5

 
14.3

 
94.7

 
10.6

 
(12.8
)
 
449.3

Cost of sales
(305.1
)
 
(1,210.4
)
 
(14.6
)
 
(1,020.4
)
 
63.1

 
(2,487.4
)
Operating expenses
(136.9
)
 
(78.7
)
 
(23.3
)
 
(73.7
)
 
—

 
(312.6
)
Gain on derivative activity
—

 
—

 
—

 
—

 
6.6

 
6.6

Segment profit
$
305.5

 
$
120.7

 
$
99.3

 
$
53.5

 
$
6.6

 
$
585.6

Depreciation and amortization
$
(123.6
)
 
$
(81.8
)
 
$
(37.2
)
 
$
(41.5
)
 
$
(5.0
)
 
$
(289.1
)
Impairments
$
—

 
$
(576.1
)
 
$
—

 
$
(223.1
)
 
$
—

 
$
(799.2
)
Goodwill
$
1,186.8

 
$
210.7

 
$
190.3

 
$
142.1

 
$
1,426.9

 
$
3,156.8

Capital expenditures
$
183.4

 
$
43.4

 
$
37.2

 
$
170.6

 
$
10.6

 
$
445.2

Nine Months Ended September 30, 2014
 
 
 
 
 
 
 
 
 
 
 
Product sales
$
167.0

 
$
1,075.6

 
$
11.5

 
$
226.3

 
$
—

 
$
1,480.4

Product sales-affiliates
331.1

 
38.7

 
147.9

 
—

 
(43.5
)
 
474.2

Midstream services
38.6

 
87.3

 
—

 
28.9

 
—

 
154.8

Midstream services-affiliates
289.7

 
2.0

 
108.1

 
2.4

 
(2.0
)
 
400.2

Cost of sales
(397.6
)
 
(1,104.2
)
 
(133.9
)
 
(207.8
)
 
45.5

 
(1,798.0
)
Operating expenses
(108.2
)
 
(41.9
)
 
(21.0
)
 
(29.3
)
 
—

 
(200.4
)
Gain on litigation settlement
—

 
6.1

 
—

 
—

 
—

 
6.1

Loss on derivative activity
—

 
—

 
—

 
—

 
(1.9
)
 
(1.9
)
Segment profit
$
320.6

 
$
63.6

 
$
112.6

 
$
20.5

 
$
(1.9
)
 
$
515.4

Depreciation and amortization
$
(91.7
)
 
$
(43.4
)
 
$
(37.6
)
 
$
(24.4
)
 
$
(1.5
)
 
$
(198.6
)
Goodwill
$
1,168.2

 
$
786.8

 
$
190.3

 
$
112.5

 
$
1,436.8

 
$
3,694.6

Capital expenditures
$
180.2

 
$
222.4

 
$
10.5

 
$
91.3

 
$
12.6

 
$
517.0


The table below presents information about segment assets as of September 30, 2015 and December 31, 2014:
 
September 30,
2015
 
December 31,
2014
Segment Identifiable Assets:
(In millions)
Texas
$
3,995.0

 
$
3,303.0

Louisiana
2,562.3

 
3,316.5

Oklahoma
895.7

 
892.8

Crude and Condensate
980.8

 
871.9

Corporate
1,840.1

 
1,822.5

Total identifiable assets
$
10,273.9

 
$
10,206.7



36

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


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

Three Months Ended  
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
Segment profits
$
203.8

 
$
186.5

 
$
585.6

 
$
515.4

General and administrative expenses
(34.8
)
 
(24.4
)
 
(105.6
)
 
(66.9
)
Loss on disposition of assets
(3.2
)
 
—

 
(3.2
)
 
—

Depreciation and amortization
(98.4
)
 
(75.1
)
 
(289.1
)
 
(198.6
)
Impairments
(799.2
)
 
—

 
(799.2
)
 
—

Operating income (loss)
$
(731.8
)
 
$
87.0

 
$
(611.5
)
 
$
249.9


(17) Discontinued Operations

The Predecessor’s historical assets comprised all of Devon’s U.S. midstream assets and operations. However, only its assets serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as contractual rights to the economic benefits and burdens associated with Devon's 38.75% interest in GCF, were contributed to Midstream Holdings in connection with the business combination on March 7, 2014. All operations activity related to the non-contributed assets prior to March 7, 2014 are classified as discontinued operations.

The following schedule summarizes net income from discontinued operations (in millions):
 
 
Nine Months Ended 
 September 30,
 
 
2014
Revenues:
 
 
Revenues
 
$
6.8

Revenues - affiliates
 
10.5

Total revenues
 
17.3

 
 
 
Operating costs and expenses:
 
 
Operating expenses
 
15.7

Total operating costs and expenses
 
15.7

 
 
 
Income before income taxes
 
1.6

Income tax provision
 
0.6

Net income
 
$
1.0


(18) Supplemental Cash Flow Information

The following schedule summarizes the Partnership's non-cash financing activities for the period presented.
 
 
Nine Months Ended 
 September 30,
 
 
2015
 
 
(In millions)
Non-cash financing activities:
 
 
     Non-cash issuance of common units (1)
 
$
180.0

     Non-cash issuance of Class C Common Units (1)
 
$
180.0


37

ENLINK MIDSTREAM, LLC
 
Notes to Condensed Consolidated Financial Statements-(Continued)
(Unaudited)


(1) Non-cash common units and Class C Common Units were issued as partial consideration for the Coronado acquisition. See Note 3 - Acquisitions for further discussion.

Also, see Note 5 - Affiliate Transactions for non-cash activities related to Predecessor operations with Devon prior to March 7, 2014.

(19) Other Information

The following tables present additional detail for certain balance sheet captions.

Other Current Liabilities

Other current liabilities consisted of the following:
 
September 30, 2015
 
December 31, 2014
 
(in millions)
Accrued interest
$
54.7

 
$
16.9

Accrued wages and benefits, including taxes
29.9

 
19.7

Accrued ad valorem taxes
30.2

 
23.2

Capital expenditure accruals
18.4

 
22.6

Suspense producer payments
17.5

 
—

Other
54.8

 
69.9

Other current liabilities
$
205.5

 
$
152.3


(20) Subsequent Events

Acquisition of Natural Gas Gathering and Processing Assets. On October 1, 2015, the Partnership acquired all of the voting interests in DLK Wolf Midstream, LLC, a subsidiary of MRC Energy Company, which owns natural gas gathering and processing assets predominantly located in west Texas for $143.0 million, subject to certain adjustments. The natural gas assets include a cryogenic gas processing plant and approximately 6 miles of high-pressure gathering pipeline within the Delaware Basin. Due to the timing of this acquisition, the Partnership has not yet completed its initial accounting and analysis.

Acquisition of Partnership Common Units. On October 29, 2015, EMI acquired 2,849,100 common units in the Partnership for aggregate consideration of approximately $50.0 million in a private placement transaction.






38

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report.

The historical financial statements included in this report reflect (1) for periods prior to March 7, 2014, the assets, liabilities and operations of EnLink Midstream Holdings, LP Predecessor (the “Predecessor”), the predecessor to EnLink Midstream Holdings, LP (“Midstream Holdings”), which is the historical predecessor of EnLink Midstream, LLC and (2) for periods on or after March 7, 2014, the results of operations of EnLink Midstream, LLC, after giving effect to the business combination discussed under “Devon Energy Transaction” below. The Predecessor was comprised of all of the U.S. midstream assets and operations of Devon Energy Corporation (“Devon”) prior to the business combination, including its 38.75% economic interest in Gulf Coast Fractionators ("GCF"). However, in connection with the business combination, only the Predecessor’s systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales in Texas and Oklahoma, as well as the economic burdens and benefits of the 38.75% economic interest in GCF, were contributed to Midstream Holdings, effective as of March 7, 2014.

You should read this discussion in conjunction with the historical financial statements and accompanying notes included in this report. All references in this section to the "Company", as well as the terms “our,” “we,” “us” and “its” (1) for periods prior to March 7, 2014 refer to the Predecessor and (2) for periods on or after March 7, 2014 refer to EnLink Midstream, LLC, together with its consolidated subsidiaries including the Partnership and Midstream Holdings. All references in this section to the "Partnership" (1) for periods prior to March 7, 2014 refer to the Predecessor and (2) for periods on or after March 7, 2014 refer to EnLink Midstream Partners, LP, together with its consolidated subsidiaries including EnLink Midstream Operating, LP (the "Operating Partnership"), Midstream Holdings and their consolidated subsidiaries.

Overview
 
We are a Delaware limited liability company formed in October 2013. Our assets consist of equity interests in EnLink Midstream Partners, LP, a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs, condensate and crude oil, as well as providing crude oil, condensate and brine services to producers. Our interests in EnLink Midstream Partners, LP, consist of the following as of September 30, 2015:

•85,679,351 common units representing an aggregate 26.1% limited partner interest in the Partnership; and
•100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership,
which owns a 0.5% general partner interest and all of the incentive distribution rights in the Partnership.

On October 29, 2015, EMI acquired approximately 2.8 million common units in the Partnership in a private placement transaction for aggregate consideration of $50.0 million, which the Partnership intends to use for general partnership purposes, including potential strategic growth initiatives. As a result of this acquisition, our interest in the Partnership as of October 29, 2015 includes 88,528,451 common units representing a 26.7% limited partner interest.
The Partnership is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership’s business, or to provide for future distributions.

The incentive distribution rights in the Partnership entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.25 for that quarter, 23.0% of all cash distributed after each unit has received $0.3125 for that quarter and 48.0% of all cash distributed after each unit has received $0.375 for that quarter.

Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries. Since the Partnership controls Midstream Holdings through the ownership of its general partner, the financial results of the Partnership consolidate all of Midstream Holdings' financial results. Our condensed consolidated results of operations are derived from the results of operations of the Partnership and also include our deferred taxes, interest of non-controlling partners in the Partnership’s net income, interest income (expense) and general and administrative expenses not reflected in the Partnership’s results of operations. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of the Partnership and Midstream Holdings.

39


The Partnership primarily focuses on providing midstream energy services, including gathering, processing, transmission, fractionation, condensate stabilization, brine services and marketing, to producers of natural gas, NGLs, crude oil and condensate. The Partnership's midstream energy asset network includes approximately 9,200 miles of pipelines, sixteen natural gas processing plants, seven fractionators, 3.1 million barrels of NGL cavern storage, 11.0 Bcf of natural gas storage, rail terminals, barge terminals, truck terminals and a fleet of approximately 140 trucks. The Partnership manages and reports its activities primarily according to the nature of activity and geography. The Partnership has five reportable segments: (1) Texas, which includes the Partnership's natural gas gathering, processing and transmission activities in north Texas and the Permian Basin in west Texas; (2) Oklahoma, which includes the Partnership's natural gas gathering, processing and transmission activities in Cana-Woodford and Arkoma-Woodford Shale areas; (3) Louisiana, which includes the Partnership's natural gas pipelines, natural gas processing plants and NGL assets located in Louisiana; (4) Crude and Condensate, which includes the Partnership's Ohio River Valley ("ORV") crude oil, condensate and brine disposal activities in the Utica and Marcellus Shales, its equity interests in E2 Energy Services, LLC, E2 Appalachian Compression, LLC and E2 Ohio Compression, LLC (collectively, "E2"), its crude oil operations in the Permian Basin and its crude oil activities associated with the Victoria Express Pipeline and related truck terminal and storage assets ("VEX") located in the Eagle Ford Shale; and (5) Corporate, which includes the Partnership's equity investments in Howard Energy Partners, in the Eagle Ford Shale, its contractual right to the economic burdens and benefits associated with Devon's ownership interest in GCF in south Texas and our general partnership property and expenses.

The Partnership manages its operations by focusing on gross operating margin because the Partnership's business is generally to gather, process, transport or market natural gas, NGLs, crude oil and condensate using its assets for a fee. The Partnership earns its fees through various contractual arrangements, which include stated fixed-fee contract arrangements or arrangements where the Partnership purchases and resells commodities in connection with providing the related service and earns a net margin for its fees. While the Partnership's transactions vary in form, the essential element of each transaction is the use of its assets to transport a product or provide a processed product to an end-user at the tailgate of the plant, barge terminal or pipeline. The Partnership defines gross operating margin as operating revenue minus cost of sales. Gross operating margin is a non-generally accepted accounting principle ("non-GAAP") financial measure and is explained in greater detail under “Non-GAAP Financial Measures” below. Approximately 95% of the Partnership's gross operating margin (revenues less cost of sales) was derived from fee-based services with no direct commodity exposure for the nine months ended September 30, 2015. The Partnership reflects revenue as "Product sales" and "Midstream services" on the Condensed Consolidated Statements of Operations.

The Partnership's gross operating margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities, the volumes of NGLs handled at its fractionation facilities, the volumes of crude oil and condensate handled at its crude terminals, the volumes of crude oil and condensate gathered, transported, purchased and sold and the volume of brine disposed and the volume of condensate stabilized. The Partnership generates revenues from seven primary sources:

•transporting natural gas and NGLs on the pipeline systems it owns;

•processing natural gas at its processing plants;

•fractionating and marketing recovered NGLs;

•providing compression services;

•providing crude oil and condensate transportation and terminal services;

•providing condensate stabilization services; and

•providing brine disposal services.
 
The Partnership typically gathers or transports gas owned by others through its facilities for a fee. The Partnership also buys natural gas from a producer, plant or shipper at either a fixed discount to a market index or a percentage of the market index, then transports and resells the natural gas at the market index. The fixed discount difference to a market index represents the fee for using the Partnership's assets. The Partnership attempts to execute substantially all purchases and sales concurrently, or it enters into a future delivery obligation, thereby establishing the basis for the fee it will receive for each natural gas transaction. The Partnership’s gathering and transportation fee related to a percentage of the index price can be adversely affected by declines in the price of natural gas. The Partnership is also party to certain long-term gas sales commitments that it

40

satisfies through supplies purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time, the supplies that it has under contract may decline due to reduced drilling or other causes and the Partnership may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In the Partnership’s purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased.

On occasion the Partnership has entered into certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and it captures the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as its fee. Changes in the basis spread can increase or decrease margins or potentially result in losses. For example, the Partnership is a party to one contract with a term to 2019 to supply approximately 150,000 MMBtu/d of gas. The Partnership buys gas for this contract on several different production-area indices on its North Texas Pipeline and sells the gas into a different market area index. The Partnership realizes a cash loss on the delivery of gas under this contract each month based on current prices. The fair value of this performance obligation was recorded as a result of the March 7, 2014 business combination and was based on forecasted discounted cash obligations in excess of market prices under this gas delivery contract. As of September 30, 2015, the balance sheet reflects a liability of $67.3 million related to this performance obligation. Reduced supplies and narrower basis spreads in recent periods have increased the cash losses on this contract, and greater losses on this contract could occur in future periods if these conditions persist or become worse.

The Partnership typically transports and fractionates or stores NGLs owned by others for a fee based on the volume of NGLs transported and fractionated or stored. The Partnership also buys mixed NGLs from its suppliers at a fixed discount to market indices for the component NGLs with a deduction for its fractionation fee. The Partnership subsequently sells the fractionated NGL products based on the same index-based prices. The operating results of the Partnership's NGL fractionation business are dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. With the Partnership's fractionation business, it also has the opportunity for product upgrades for each of the discrete NGL products. The fees the Partnership earns on the product upgrade from this fractionation business is higher during periods with higher liquids prices.

The Partnership generally gathers or transports crude oil and condensate owned by others by rail, truck, pipeline and barge facilities for a fee. The Partnership also buys crude oil and condensate from a producer at a fixed discount to a market index, then transports and resells the crude oil and condensate at the same market index.  The Partnership executes substantially all purchases and sales concurrently, thereby establishing the fee it will receive for each crude oil and condensate transaction. Additionally, the Partnership provides crude oil, condensate and brine services on a volume basis.

The Partnership realizes gross operating margins from its processing services primarily through different contract arrangements: processing margins ("margin"), percentage of liquids (“POL”), percentage of proceeds ("POP") or fixed-fee based. Under margin contract arrangements the Partnership's gross operating margins are higher during periods of high liquid prices relative to natural gas prices. Gross operating margin results under POP contracts are impacted only by the value of the natural gas or liquids produced with margins higher during periods of higher natural gas and liquids prices. Under fixed-fee based contracts the Partnership’s gross operating margins are driven by throughput volume. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.” 

Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision, property insurance, property taxes, repair and maintenance expenses, contract services and utilities. These costs are normally fairly stable across broad volume ranges and therefore do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas, liquids, crude oil and condensate moved through or by the asset.

Devon Energy Transaction

On March 7, 2014, ENLC consummated the transactions contemplated by the Agreement and Plan of Merger, dated as of October 21, 2013 (the “Merger Agreement”), among EnLink Midstream, Inc. ("EMI"), Devon, Acacia Natural Gas Corp I, Inc., formerly a wholly-owned subsidiary of Devon (“Acacia”), and certain other wholly-owned subsidiaries of Devon pursuant to which EMI and Acacia each became wholly-owned subsidiaries of ENLC (collectively, the “Mergers”). Upon completion of the merger with Acacia, ENLC indirectly owned a 50% limited partner interest in Midstream Holdings. Also on March 7, 2014, the Partnership consummated the transactions contemplated by the Contribution Agreement, dated as of October 21, 2013 (the “Contribution Agreement”), among the Partnership, EnLink Midstream Operating, Devon and certain of Devon’s wholly-owned subsidiaries.


41

On February 17, 2015, Acacia contributed a 25% interest in Midstream Holdings (the "February Transferred Interests") to the Partnership in a drop down transaction (the "February EMH Drop Down") in exchange for 31,618,311 Class D Common Units in the Partnership, representing an approximate 9.6% limited partner interest in the Partnership as of September 30, 2015. On May 27, 2015, the Acacia contributed the remaining 25% limited partner interest in Midstream Holdings (the "May Transferred Interests") to the Partnership in a drop down transaction (the "May EMH Drop Down" and together with the February EMH Drop Down, the "EMH Drop Downs") in exchange for 36,629,888 Class E Common Units in the Partnership, representing an approximate 11.2% limited partner interest in the Partnership as of September 30, 2015. After giving effect to the EMH Drop-Downs, the Partnership owns 100% of Midstream Holdings. In addition, on April 1, 2015 the Partnership acquired the Victoria Express Pipeline and related truck terminal and storage assets from Devon (the "VEX Interests"). See “Recent Developments.”

As of September 30, 2015, the Partnership units held by Devon represent approximately 28.7% of the outstanding limited partner interests in the Partnership, with approximately 44.8% of the outstanding limited partner interests held by the Partnership’s public unitholders and approximately 26.0% of the outstanding limited partner interests, the approximate 0.5% general partner interest and the incentive distribution rights held indirectly by ENLC.

Recent Developments

Acquisitions

Acquisition of Natural Gas Gathering and Processing Assets. On October 1, 2015, the Partnership acquired all of the voting interests in DLK Wolf Midstream, LLC, a subsidiary of MRC Energy Company ("Matador"), which owns natural gas gathering and processing assets (the "Delaware Basin System") predominantly located in west Texas, for $143.0 million, subject to certain adjustments. The Delaware Basin System consists of a cryogenic gas processing plant with approximately 35 million cubic feet per day ("MMcf/d") of inlet capacity and approximately 6 miles of high-pressure gathering pipeline, which connects a low-pressure gathering system to the processing plant. Matador will be the largest customer on the system and will dedicate approximately 11,000 gross acres currently under development pursuant to a 15-year fixed fee gathering and processing agreement.

Coronado Midstream. On March 16, 2015, the Partnership acquired all of the voting equity interests in Coronado Midstream Holdings LLC, the parent company of Coronado Midstream LLC (“Coronado”), which owns natural gas gathering and processing facilities in the Permian Basin, for approximately $600.2 million in cash and equity, subject to certain adjustments. The purchase price consisted of $240.2 million in cash, 6,704,285 common units and 6,704,285 Class C Common Units in the Partnership.  Coronado operates three cryogenic gas processing plants and a gas gathering system in the North Midland Basin including approximately 270 miles of gathering pipelines, 175 MMcf/d of processing capacity and 35,000 horsepower of compression. The Coronado system is underpinned by long-term contracts, which include the dedication of production from over 190,000 acres. The Coronado assets are included in the Partnership's Texas segment.

LPC Crude Oil Marketing. On January 31, 2015, the Partnership acquired all of the voting equity interests in LPC Crude Oil Marketing LLC (“LPC”), which has crude oil gathering, transportation and marketing operations in the Permian Basin, for approximately $108.1 million. LPC is an integrated crude oil logistics service provider with operations throughout the Permian Basin. LPC's integrated logistics services are supported by 41 tractor trailers, 13 pipeline injection stations and 67 miles of crude oil gathering pipeline. The LPC assets are included in the Partnership's Crude and Condensate segment.

Drop Downs

VEX Pipeline. On April 1, 2015, the Partnership acquired the VEX Interests from Devon, which are located in the Eagle Ford Shale in south Texas. The aggregate consideration paid by the Partnership consisted of $171.0 million in cash, 338,159 common units representing limited partner interests in the Partnership with an aggregate value of approximately $9.0 million and the Partnership’s assumption of up to $40.0 million in certain construction costs related to VEX, subject to certain adjustments set forth in the contribution agreement. The VEX pipeline is a 56-mile multi-grade crude oil pipeline with a current capacity of approximately 50,000 barrels per day ("Bbls/d") and, following completion of currently-underway expansion projects, will have capacity of approximately 90,000 Bbls/d. Other VEX assets at the destination of the pipeline include an eight-bay truck unloading terminal, 200,000 barrels of above-ground storage, of which 50,000 barrels are under construction, and rights to barge loading docks. The VEX assets are included in the Partnership's Crude and Condensate segment.

Midstream Holdings Drop Down. On February 17, 2015, Acacia contributed the February Interests to the Partnership in exchange for 31,618,311 Class D Common Units in the Partnership with an implied value of $925.0 million. The Class D Common Units were substantially similar in all respects to the Partnership’s common units, except that they were only entitled

42

to a pro rata distribution for the fiscal quarter ended March 31, 2015. The Class D Common Units converted into common units on a one-for-one basis on May 4, 2015.

On May 27, 2015, Acacia contributed the May Transferred Interests to the Partnership in exchange for 36,629,888 Class E Common Units in the Partnership with an implied value of $900.0 million. The Class E Common Units were substantially similar in all respects to the Partnership’s common units, except that they were only entitled to a pro rata distribution for the fiscal quarter ended June 30, 2015. The Class E Common Units automatically converted into common units on a one-for-one basis on August 3, 2015. After giving effect to the EMH Drop Downs, the Partnership owns 100% of Midstream Holdings.

Organic Growth

Ohio River Valley Condensate Stabilization Facilities. Through an agreement with Eclipse Resources (the “Eclipse Agreement”), the Partnership expects to own and operate four additional natural gas compression and condensate stabilization facilities in Harrison, Monroe and Guernsey counties in Ohio.  The Partnership took ownership of and began operating the first two of these facilities in the fourth quarter of 2014.  The third compression and condensate stabilization facility began operations in March 2015. The Partnership will begin construction on the fourth facility as needed based on available volumes.

Riptide Plant. The Partnership acquired the Riptide plant located in the Permian Basin as part of the Coronado acquisition. The plant, which is under construction, will provide 100 MMcf/d of processing capacity and be tied to approximately 40 miles of new pipeline that is also under construction. The plant is expected to be completed in the first half of 2016.

Partnership Credit Facility

In 2014, the Partnership entered into a $1.0 billion unsecured revolving credit facility (the "Partnership credit facility"). On February 5, 2015, the Partnership exercised the accordion under the Partnership credit facility, increasing the size of the facility to $1.5 billion, and also exercised an option to extend the maturity date of the Partnership credit facility to March 6, 2020.

Issuance of Partnership Common Units

In November 2014, the Partnership entered into an equity distribution agreement (the "BMO EDA") with BMO Capital Markets Corp. and certain other sales agents to sell up to $350.0 million in aggregate gross sales of the Partnership’s common units from time to time through an “at the market” equity offering program. The Partnership 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. The Partnership has 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 nine months ended September 30, 2015, the Partnership sold an aggregate of 0.7 million common units under the BMO EDA, generating proceeds of approximately $12.9 million (net of approximately $0.1 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of September 30, 2015, approximately $328.7 million remains available to be issued under the agreement.

Non-GAAP Financial Measures

Cash Available for Distribution

We define cash available for distribution as distributions due to us from the Partnership and our interest in Midstream Holdings' adjusted EBITDA (as defined herein), less maintenance capital, our specific general and administrative costs as a separate public reporting entity, the interest costs associated with our debt and current taxes attributable to our earnings. During 2014, we utilized federal net operating loss carryforwards to offset our taxable income generated during 2014. We have $48.2 million of federal net operating loss carryforwards remaining as of December 31, 2014. We anticipate that taxable income during 2015 will be sufficient to utilize our remaining net operating loss carryforwards and that we will begin paying federal income taxes on our taxable income. Cash available for distribution is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Cash available for distribution is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment.


43

Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines and other gathering, compression and processing assets up to their original operating capacity, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

The GAAP measure most directly comparable to cash available for distribution is net income. Cash available for distribution should not be considered as an alternative to GAAP net income. Cash available for distribution is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Because cash available for distribution excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

The following is a calculation of the Company's cash available for distribution (in millions):
 
 
Three Months Ended  
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(unaudited)
 
 
 
 
 
 
 
 
 
Distribution declared by ENLK associated with (1):
 
 
 
 
 
 
 
 
    General partner interest
 
$
0.6

 
$
0.6

 
$
1.8

 
$
1.5

    Incentive distribution rights
 
13.6

 
6.3

 
33.7

 
13.6

    ENLK common units owned
 
33.4

 
6.1

 
70.0

 
14.0

        Total share of ENLK distributions declared
 
$
47.6

 
$
13.0

 
$
105.5

 
$
29.1

Transferred interest EBITDA (2)
 
—

 
59.2

 
53.7

 
132.4

        Total cash available
 
$
47.6

 
$
72.2

 
$
159.2

 
$
161.5

Uses of cash:
 
 
 
 
 
 
 
 
    General and administrative expenses
 
(1.1
)
 
(0.9
)
 
(3.0
)
 
(2.7
)
    Current income taxes (3)
 
1.2

 
(5.9
)
 
—

 
(6.4
)
    Interest expense
 
(0.2
)
 
(0.7
)
 
(0.7
)
 
(1.8
)
    Maintenance capital expenditures (4)
 
—

 
(2.8
)
 
(4.0
)
 
(5.9
)
        Total cash used
 
$
(0.1
)
 
$
(10.3
)
 
$
(7.7
)
 
$
(16.8
)
ENLC cash available for distribution
 
$
47.5

 
$
61.9

 
$
151.5

 
$
144.7

_________________________________________________
(1)
Represents distributions paid to ENLC on May 14, 2015 and August 14, 2015 and distributions declared by ENLK and to be paid to ENLC on November 12, 2015.
(2)
Represents ENLC's interest in Midstream Holdings' adjusted EBITDA prior to the EMH Drop Downs.
(3)
Represents ENLC’s stand-alone current tax expense.
(4)
Represents ENLC's interest in Midstream Holdings' maintenance capital expenditures prior to the EMH Drop Downs which is netted against the monthly disbursement of Midstream Holdings' adjusted EBITDA per (2) above.

44

The following table provides a reconciliation of ENLC net income to ENLC cash available for distribution (in millions):
 
 
Three Months Ended  
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(unaudited)
 
 
 
 
 
 
 
 
 
Net income (loss) of ENLC
 
$
(755.9
)
 
$
64.2

 
$
(688.0
)
 
$
174.1

    Less: Net (income) loss attributable to ENLK
 
754.9

 
(83.4
)
 
665.5

 
(218.8
)
Net income of ENLC excluding ENLK
 
$
(1.0
)
 
$
(19.2
)
 
$
(22.5
)
 
$
(44.7
)
    ENLC's share of distributions from ENLK (1)
 
47.6

 
13.0

 
105.5

 
29.1

    ENLC deferred income tax expense (2)
 
0.5

 
11.8

 
18.3

 
33.3

    Maintenance capital expenditures (3)
 
—

 
(2.8
)
 
(4.0
)
 
(5.9
)
    Transferred interest EBITDA (4)
 
—

 
59.2

 
53.7

 
132.4

    Other items (5)
 
0.4

 
(0.1
)
 
0.5

 
0.5

ENLC cash available for distribution
 
$
47.5

 
$
61.9

 
$
151.5

 
$
144.7

_________________________________________________
(1)
Represents distributions paid to ENLC on May 14, 2015 and August 13, 2015 and distributions declared by ENLK and to be paid to ENLC on November 12, 2015.
(2)
Represents ENLC's stand-alone deferred taxes.
(3)
Represents ENLC's interest in Midstream Holdings' maintenance capital expenditures prior to the EMH Drop Downs, which is netted against the monthly disbursement of Midstream Holdings' adjusted EBITDA.
(4)
Represents ENLC's interest in Midstream Holdings' adjusted EBITDA prior to the EMH Drop Downs.
(5)Represents E2's adjusted EBITDA and other non-cash items not included in cash available for distributions.

Gross Operating Margin

We define gross operating margin, generally, as revenues less cost of sales. We present gross operating margin by segment in “Results of Operations”.  We disclose gross operating margin in addition to total revenue because it is the primary performance measure used by our management. We believe gross operating margin is an important measure because our business is generally to purchase and resell natural gas, NGLs, condensate and crude oil for a margin or to gather, process, transport or market natural gas, NGLs, condensate and crude oil for a fee. Operating expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor and supervision, property insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. We do not deduct operating expenses from total revenue in calculating gross operating margin because these expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. As an indicator of our operating performance, gross operating margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our gross operating margin may not be comparable to similarly titled measures of other companies because other entities may not calculate these amounts in the same manner.


45

The following table provides a reconciliation of gross operating margin to operating income (loss):
 
Three Months Ended  
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Total gross operating margin
$
308.8

 
$
260.2

 
$
898.2

 
$
709.7

 
 
 
 
 
 
 
 
Add (Deduct):
 
 
 
 
 
 
 
Operating expenses
(105.0
)
 
(79.8
)
 
(312.6
)
 
(200.4
)
General and administrative expenses
(34.8
)
 
(24.4
)
 
(105.6
)
 
(66.9
)
Depreciation and amortization
(98.4
)
 
(75.1
)
 
(289.1
)
 
(198.6
)
Loss on disposition of assets
(3.2
)
 
—

 
(3.2
)
 
—

Impairments
(799.2
)
 
—

 
(799.2
)
 
—

Gain on litigation settlement
—

 
6.1

 
—

 
6.1

Operating income (loss)
$
(731.8
)
 
$
87.0

 
$
(611.5
)
 
$
249.9


Results of Operations
 
The table below sets forth certain financial and operating data for the periods indicated. We manage our operations by focusing on gross operating margin which we define as operating revenue less cost of sales as reflected in the table below.

Items Affecting Comparability of Our Financial Results

Our historical financial results discussed below may not be comparable to our future financial results, and our financial results for the nine months ended September 30, 2015 may not be comparable to our financial results for the nine months ended September 30, 2014 for the following reasons:

•
In connection with the business combination, Midstream Holdings entered into new agreements with Devon that were entered into January 1, 2014 pursuant to which Midstream Holdings provides services to Devon under fixed-fee arrangements in which Midstream Holdings does not take title to the natural gas gathered or processed or the NGLs it fractionates. Prior to the effectiveness of these agreements, the Predecessor provided services to Devon under a percent-of-proceeds arrangement in which it took title to the natural gas it gathered and processed and the NGLs it fractionated.
•
Prior to March 7, 2014, our financial results only included the assets, liabilities and operations of our Predecessor. Beginning on March 7, 2014, our financial results also consolidate the assets, liabilities and operations of the legacy business of the Partnership after giving effect to the business combination.
•
Subsequent to March 7, 2014 (and prior to the EMH Drop Downs), we owned a 50% direct ownership interest in Midstream Holdings and indirectly owned an additional interest of approximately 3% of Midstream Holdings (through our ownership in the Partnership which owned the remaining 50% interest in Midstream Holdings) rather than the 100% ownership reflected as part of our Predecessor’s historical financial results. After the February EMH Drop Down on February 17, 2015, we owned a 25% direct ownership interest in Midstream Holdings, and after the May EMH Drop Down on May 27, 2015, we do not own any direct interest in Midstream Holdings. Our financial statements after March 7, 2014 and prior to the EMH Drop Downs consolidate all of Midstream Holdings’ financial results with ours in accordance with GAAP and the Partnership’s interest not owned by us in Midstream Holdings is reflected as a non-controlling interest.
•
Our financial statements for the nine months ended September 30, 2015 and 2014 report financial results according to operating segments based principally upon geographic regions served. The Predecessor had no operations for certain of those reporting segments.
•
All historical affiliated transactions prior to March 7, 2014 related to our continuing operations were net settled within our combined financial statements because these transactions related to Devon and were funded by Devon’s working capital. Beginning on March 7, 2014, all our transactions settle in cash and therefore impact our working capital. This will impact the comparability of our cash flow statements, working capital analysis and liquidity discussion.
    

46


 
Three Months Ended  
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(in millions, except volumes)
Texas Segment
 

 
 

 
 
 
 
Revenues
$
274.1

 
$
213.5

 
$
747.5

 
$
826.4

Cost of sales
(124.5
)
 
(64.2
)
 
(305.1
)
 
(397.6
)
Total gross operating margin
$
149.6

 
$
149.3

 
$
442.4

 
$
428.8

Louisiana Segment
 
 
 
 
 
 
 
Revenues
$
485.0

 
$
503.8

 
$
1,409.8

 
$
1,203.6

Cost of sales
(415.2
)
 
(462.6
)
 
(1,210.4
)
 
(1,104.2
)
Total gross operating margin
$
69.8

 
$
41.2

 
$
199.4

 
$
99.4

Oklahoma Segment
 
 
 
 
 
 
 
Revenues
$
52.4

 
$
45.8

 
$
137.2

 
$
267.5

Cost of sales
(9.4
)
 
—

 
(14.6
)
 
(133.9
)
Total gross operating margin
$
43.0

 
$
45.8

 
$
122.6

 
$
133.6

Crude and Condensate Segment
 
 
 
 
 
 
 
Revenues
$
376.0

 
$
113.1

 
$
1,147.6

 
$
257.6

Cost of sales
(334.8
)
 
(90.2
)
 
(1,020.4
)
 
(207.8
)
Total gross operating margin
$
41.2

 
$
22.9

 
$
127.2

 
$
49.8

Corporate
 
 
 
 
 
 
 
Revenues
$
(16.9
)
 
$
(18.8
)
 
$
(56.5
)
 
$
(47.4
)
Cost of sales
22.1

 
19.8

 
63.1

 
45.5

Total gross operating margin
$
5.2

 
$
1.0

 
$
6.6

 
$
(1.9
)
Total
 
 
 
 
 
 
 
Revenues
$
1,170.6

 
$
857.4

 
$
3,385.6

 
$
2,507.7

Cost of sales
(861.8
)
 
(597.2
)
 
(2,487.4
)
 
(1,798.0
)
Total gross operating margin
$
308.8

 
$
260.2

 
$
898.2

 
$
709.7

 
 
 
 
 
 
 
 
Midstream Volumes:
 
 
 
 
 
 
 
Texas (1)
 
 
 
 
 
 
 
Gathering and Transportation (MMBtu/d)
2,640,300

 
2,975,600

 
2,705,900

 
2,979,000

Processing (MMBtu/d)
1,244,100

 
1,152,400

 
1,214,500

 
1,149,100

Louisiana (2)
 
 
 
 
 
 
 
Gathering and Transportation (MMBtu/d)
1,516,400

 
500,200

 
1,444,700

 
459,300

Processing (MMBtu/d)
509,100

 
499,100

 
488,200

 
557,000

NGL Fractionation (Gals/d)
6,370,600

 
4,073,500

 
5,957,000

 
4,112,500

Oklahoma (3)
 
 
 
 
 
 
 
Gathering and Transportation (MMBtu/d)
391,100

 
494,200

 
411,800

 
472,000

Processing (MMBtu/d)
348,900

 
447,300

 
325,500

 
447,300

Crude and Condensate (2)
 
 
 
 
 
 
 
Crude Oil Handling (Bbls/d)
147,300

 
15,200

 
130,800

 
15,400

Brine Disposal (Bbls/d)
4,200

 
5,000

 
3,900

 
5,300

__________________________________________________
 
(1)
Volumes include volumes per day based on 92- and 273-day periods for the three and nine months ended September 30, 2014, for Midstream Holdings' operations. Volumes include volumes per day based on 92 days for the three months ended

47

September 30, 2014 and volumes based on the 208 day period from March 7 to September 30, 2014 for the nine months ended September 30, 2014 for the Partnership’s legacy operations in Texas.
(2)
Volumes include volumes per day based on 92 days for the three months ended September 30, 2014 and based on the 208-day period from March 7 to September 30, 2014 for the nine months ended September 30, 2014 for the Partnership’s legacy operations. Midstream Holdings does not have any operations in the Louisiana or Crude and Condensate segments. The VEX pipeline did not commence operation until July 2014.
(3)
Volumes include volumes per day based on 92- and 273-day periods for the three and nine months ended September 30, 2014, respectively, for Midstream Holdings' operations. The Partnership did not have any legacy operations in Oklahoma.
Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014
 
Gross Operating Margin. Gross operating margin was $308.8 million for the three months ended September 30, 2015 as compared to $260.2 million for the three months ended September 30, 2014, an increase of $48.6 million, or 18.7%. The overall increase in gross operating margin was primarily due to the acquisition of the LPC assets in January 2015, the acquisition of Coronado assets in March 2015, the start-up of commercial operations of organic projects and an increase in fractionation and marketing activities driven by system expansions. This increase was partially offset by a decline in throughput volumes related to the Partnership's gas processing and transmission activities. The following provides additional details regarding this change in gross operating margin:

•
Texas Segment. The Texas segment had an increase in gross operating margin of $0.3 million for the three months ended September 30, 2015 compared to the three months ended September 30, 2014. This increase was primarily attributable to an increase of $13.5 million in gross operating margin due to the Coronado acquisition in March 2015 and our Bearkat natural gas processing plant and rich gas gathering system which commenced operations in September 2014. This increase was offset by a decrease of $13.6 million attributable to throughput volume declines on our north Texas processing, gathering and transmission assets.

•
Oklahoma Segment. The Oklahoma segment had a decrease in gross operating margin of $2.8 million for the three months ended September 30, 2015 compared to the three months ended September 30, 2014. This decrease is primarily attributable to a reduction in certain fees generated from a third party customer contract and volume declines.

•
Louisiana Segment. The Louisiana segment had an increase in gross operating margin of $28.6 million for the three months ended September 30, 2015 as compared to the three months ended September 30, 2014. This increase was primarily driven by the completion of the Cajun-Sibon expansion in September 2014, which increased gross operating margin by $22.9 million. In addition, the Louisiana natural gas processing, gathering and transmission assets contributed an increase of $6.0 million in gross operating margin primarily related to the Gulf Coast natural gas pipeline assets acquired from Chevron in November 2014. These increases were partially offset by volume and pricing declines in the Partnership's other Louisiana gas assets.

•
Crude & Condensate Segment. The Crude and Condensate segment had an increase in gross operating margin of $18.3 million for the three months ended September 30, 2015 as compared to the three months ended September 30, 2014. This increase is partly attributable to the acquisition of the LPC assets in January 2015, which contributed $13.5 million, and the VEX pipeline, which commenced operations in July 2014 and contributed $3.2 million. In addition, gross operating margin from E2 increased $5.5 million due the commercial start-up of five compression and condensate stabilization stations constructed since the fourth quarter of 2014. These increases are partially offset by a $2.7 million decline in the Partnership's other crude operations related to the termination of a customer contract in June 2015 and a decrease of $1.2 million attributable to a decline in volumes related to our ORV assets.

Operating Expenses. Operating expenses were $105.0 million for the three months ended September 30, 2015 as compared to $79.8 million for the three months ended September 30, 2014, an increase of $25.2 million, or 31.6%. The primary contributors to the total increase are as follows:


48

 
 
Three Months Ended September 30,
 
Change
 
 
2015
 
2014
 
$
 
%
 
 
(in millions)
Texas Segment
 
$
44.3

 
$
37.9

 
$
6.4

 
16.9
%
Louisiana Segment
 
27.2

 
20.3

 
6.9

 
34.0
%
Oklahoma Segment
 
7.2

 
7.0

 
0.2

 
2.9
%
Crude and Condensate Segment
 
26.3

 
14.6

 
11.7

 
80.1
%
Total
 
$
105.0

 
$
79.8

 
$
25.2

 
31.6
%

•
Texas Segment. Operating expenses in the Partnership's Texas segment increased $6.4 million for the three months ended September 30, 2015 as compared to the same three-month period in 2014. Of this increase, $5.0 million is attributable to the acquisition of the Coronado assets in March 2015 and the Partnership's Bearkat natural gas processing plant and rich gas gathering system, which commenced operations in September 2014. The remaining increase of $1.4 million is attributable to a process hazard analysis at the Partnership's Bridgeport plant which is required by federal regulations every five years.

•
Louisiana Segment. Operating expenses in the Partnership's Louisiana segment increased $6.9 million for the three months ended September 30, 2015 as compared to the same three-month period in 2014. Of this increase, $3.8 million is attributable to the acquisition of the Gulf Coast natural gas pipeline assets in November 2014 and $3.5 million is attributable to the Partnership's Cajun-Sibon expansion, which went into service in September 2014.

•
Oklahoma Segment. Operating expenses in the Partnership's Oklahoma segment increased $0.2 million for the three months ended September 30, 2015 as compared to the same three-month period in 2014, remaining relatively consistent for both periods.

•
Crude & Condensate Segment. Operating expenses in the Partnership's Crude and Condensate segment increased $11.7 million for the three months ended September 30, 2015 as compared to the same three-month period in 2014. Of this increase, $9.5 million is attributable to the LPC acquisition in January 2015 and $2.9 million is attributable to E2 compression and stabilization facilities that went into service since the fourth quarter of 2014.

General and Administrative Expenses. General and administrative expenses were $34.8 million for the three months ended September 30, 2015 as compared to $24.4 million for the three months ended September 30, 2014, an increase of $10.4 million, or 42.6%. The primary contributors to the total increase are as follows:

•our unit-based compensation expense increased $1.3 million;
•our bad debt expense increased $1.3 million;
•our salaries and wages increased $2.3 million due to an increase in headcount related to acquisitions;
•our benefits increased $1.8 million primarily due to higher health insurance claim payments under our self-insured health
plans during the 2015 quarter as compared to the same quarter in 2014; and
•
our remaining increase of $3.3 million is attributable to various other general and administrative expenses.

Loss on Disposition of Assets. Loss on disposition of assets was $3.2 million for the three months ended September 30, 2015. The loss on disposition of assets relates to the retirement of a compressor due to fire damage.

Depreciation and Amortization. Depreciation and amortization expenses were $98.4 million for the three months ended September 30, 2015 as compared to $75.1 million for the three months ended September 30, 2014, an increase of $23.3 million, or 31.0%. Of this increase in depreciation and amortization expenses, $8.7 million is attributable to the acquisition of the Coronado assets in March 2015, $1.9 million is attributable to the LPC acquisition in January 2015 and $3.1 million is attributable to the acquisition of the Gulf Coast natural gas pipeline assets in November 2014. The remaining increase in depreciation and amortization expense of $9.6 million primarily relates to new assets placed in service, of which $3.2 million is attributable to E2 assets and $3.0 million is attributable to the Cajun Sibon expansion.

Impairments. Impairment expense was $799.2 million for the three months ended September 30, 2015. During September 2015, the Partnership recognized an impairment of goodwill of $576.1 million related to its Louisiana segment and an impairment on intangible assets in its Crude and Condensate segment of $223.1 million. For more information, see "Critical Accounting Policies-Impairment of Goodwill" below.

49


Gain on Litigation Settlement. The Partnership recognized a gain on the settlement of a lawsuit of $6.1 million for the nine months ended September 30, 2014 due to a partial settlement of its claims against Texas Brine and its insurers. Additional claims related to this matter remain outstanding.

Interest Expense. Interest expense was $30.4 million for the three months ended September 30, 2015 as compared to $13.6 million for the three months ended September 30, 2014, an increase of $16.8 million, or 123.5%. Of the increase in interest expense, $14.2 million is attributable to an increase in average debt in 2015 compared to 2014, $1.9 million is attributable to a decrease in capitalized interest, and $1.3 million is attributable to an increase in non-cash interest expense related to the valuation of our mandatory redeemable non-controlling interest. This increase was partially offset by a $0.9 million decrease due to a decline in average interest rates primarily related to the Partnership credit facility. Net interest expense consists of the following (in millions):

 
Three Months Ended  
 September 30,
 
2015
 
2014
Senior notes
$
30.0

 
$
15.8

Partnership credit facility
1.3

 
2.3

Credit facility
0.1

 
—

Capitalized interest
(2.7
)
 
(4.6
)
Amortization of debt issue cost, discount and premium
0.2

 
(0.2
)
Mandatory redeemable non-controlling interest
1.3

 
—

Other
0.2

 
0.3

Total
$
30.4

 
$
13.6


Income Tax Expense. Income tax expense was $0.2 million for the three months ended September 30, 2015 as compared to income tax expense of $17.3 million for the three months ended September 30, 2014, a decrease of $17.1 million. The decrease in income tax expense is primarily attributable to a decrease in taxable income between periods. Although we realized a loss from continuing operations before income taxes during the three months ended September 30, 2015, we did not realize a tax benefit associated with this loss because substantially all of the loss was the result of a goodwill impairment which is treated as a permanent difference for tax. See Note 7 to the condensed consolidated financial statements titled “Income Taxes” for further details.

Net Income (Loss) Attributable to Non-controlling Interest. Net loss attributable to non-controlling interest was $562.5 million for the three months ended September 30, 2015 as compared to net income of $37.7 million for the three months ended September 30, 2014, a decrease of $600.2 million. Net income (loss) attributable to non-controlling interests decreased due to lower net income in 2015 at the Partnership offset by higher incentive right distributions received.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
 
Gross Operating Margin. Gross operating margin was $898.2 million for the nine months ended September 30, 2015 as compared to $709.7 million for the nine months ended September 30, 2014, an increase of $188.5 million, or 26.6%. Of this increase in gross operating margin, $85.9 million is attributable to the legacy Partnership assets associated with the business combination, $84.5 million is attributable to the LPC, Coronado and Gulf Coast asset acquisitions, $7.4 million is attributable to the VEX pipeline, which commenced operations in July 2014, $10.3 million is attributable to the Partnership's E2 assets due to the commercial start-up of five compression and condensate stabilization stations since the fourth quarter of 2014, and $22.9 million is attributable to the completion of the Cajun-Sibon expansion in September 2014. In addition, $7.6 million of the increase is attributable to the termination of a customer contract in June 2015 in which we received a one-time termination payment. This increase is partially offset by a $35.7 million decrease in gross operating margin related to a decline in volumes on the Partnership's Texas and Oklahoma assets. Also, we had a $14.3 million decrease in gross operating margin related to Midstream Holdings, which is the result of the new fixed-fee arrangements with Devon entered into in connection with the business combination.

Operating Expenses. Operating expenses were $312.6 million for the nine months ended September 30, 2015 as compared to $200.4 million for the nine months ended September 30, 2014, an increase of $112.2 million, or 56.0%. Of this increase in operating expenses, $43.2 million is attributable to legacy Partnership assets, $42.6 million is attributable to direct operating costs of the LPC, Coronado and Gulf Coast asset acquisitions, $7.9 million is due to the Partnership's Cajun-Sibon expansion that occurred in September 2014, $6.4 million is attributable to E2 compression and stabilization facilities that have been placed in service since the fourth quarter of 2014 and $5.2 million is attributable to an increase in Midstream Holdings' operating costs.

50

 
General and Administrative Expenses. General and administrative expenses were $105.6 million for the nine months ended September 30, 2015 as compared to $66.9 million for the nine months ended September 30, 2014, an increase of $38.7 million, or 57.8%. The primary contributors to the increase are as follows:

•$18.8 million is attributable to the legacy Partnership assets;
•$6.0 million is attributable to certain bonuses paid in March 2015 in the form of unit awards that immediately vested;
•the Partnership's transaction costs increased $4.8 million related to LPC, Coronado and Gulf Coast asset acquisitions;
•the Partnership's unit-based compensation expense increased $2.9 million;
•the Partnership's bad debt expense increased $1.7 million; and
•the Partnership's salaries and wages increased $4.8 million due to an increase in headcount related to acquisitions during
the year.

These increases were partially offset by a $2.4 million decrease attributable to Midstream Holdings. Prior to March 7, 2014, general and administrative expenses were allocated to Midstream Holdings by Devon.

Loss on Disposition of Assets. Loss on disposition of assets was $3.2 million for the nine months ended September 30, 2015. The loss on disposition of assets relates to the retirement of a compressor due to fire damage.

Depreciation and Amortization. Depreciation and amortization expenses were $289.1 million for the nine months ended September 30, 2015 as compared to $198.6 million for the nine months ended September 30, 2014, an increase of $90.5 million, or 45.6%. Of this increase in depreciation and amortization expenses, $21.8 million is attributable to the legacy Partnership assets acquired in March 2014, $34.7 million is attributable to the LPC, Coronado and Gulf Coast asset acquisitions and $35.5 million is attributable to new assets placed in service. This increase was partially offset by a decrease of $2.0 million in depreciation and amortization expenses related to Midstream Holdings due to the change in depreciation methodology from the units-of-production method to the straight-line method.

Impairments. Impairment expenses were $799.2 million for the nine months ended September 30, 2015. During September 2015, we recognized an impairment of goodwill of $576.1 million related to the Partnership's Louisiana segment and an impairment on intangible assets in the Partnership's Crude and Condensate segment of $223.1 million. For more information, see "Critical Accounting Policies-Impairment of Goodwill" below.

Gain on Litigation Settlement. The Partnership recognized a gain on the settlement of a lawsuit of $6.1 million for the nine months ended September 30, 2014 due to a partial settlement of its claims against Texas Brine and its insurers. Additional claims related to this matter remain outstanding.


51

Interest Expense. Interest expense was $72.1 million for the nine months ended September 30, 2015 as compared to $33.1 million for the nine months ended September 30, 2014, an increase of $39.0 million, or 117.8%. Of the increase in interest expense, $16.2 million is attributable to the number of days debt was outstanding in 2015 compared to 2014 because Midstream Holdings did not have any borrowings prior to March 7, 2014. Interest expense for the nine months ended September 30, 2015 includes interest expense for 273 days as compared to 208 days for the nine months ended September 30, 2014 (days from March 7, 2014 through September 30, 2014). Further, average debt outstanding increased in 2015 as compared to 2014, which increased interest expense $28.9 million but was partially offset by $4.3 million due to a decrease in average interest rates primarily related to the Partnership credit facility. This increase was partially offset by an increase due to a gain on the settlement of interest rate swaps of $3.6 million and an increase in non-cash interest income of $2.0 million attributable to the valuation of our mandatory redeemable non-controlling interest. Net interest expense consists of the following (in millions):

 
Nine Months Ended 
 September 30,
 
2015
 
2014
Senior notes
$
75.9

 
$
37.5

Partnership credit facility
5.8

 
3.1

Credit facility
0.4

 
1.9

Capitalized interest
(5.6
)
 
(9.9
)
Amortization of debt issue cost, discount and premium
0.2

 
(0.8
)
Cash settlements on interest rate swaps
(3.6
)
 
—

Mandatory redeemable non-controlling interest
(2.0
)
 
—

Other
1.0

 
1.3

Total
$
72.1

 
$
33.1


Income Tax Expense. Income tax expense was $21.1 million for the nine months ended September 30, 2015 as compared to income tax expense of $59.5 million for the nine months ended September 30, 2014, a decrease of $38.4 million. The decrease in income tax expense is primarily attributable to a decrease in taxable income between periods. Although we realized a loss from continuing operations before income taxes during the three months ended September 30, 2015, we did not realize a tax benefit associated with this loss because substantially all of the loss was the result of a goodwill impairment which is treated as a permanent difference for tax. See Note 7 to the condensed consolidated financial statements titled “Income Taxes” for further details.

Net Income (Loss) Attributable to Non-controlling Interest. Net loss attributable to non-controlling interest was $526.1 million for the nine months ended September 30, 2015 as compared to net income of $80.5 million for the nine months ended September 30, 2014, a decrease of $606.6 million. Net income attributable to non-controlling interests decreased due to lower net income in 2015 at the Partnership offset by higher incentive right distributions received.

Critical Accounting Policies

Information regarding the Company’s Critical Accounting Policies is included in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2014.

Impairment of Long-Lived Assets. In accordance with FASB ASC 360-10-05, the Partnership evaluates long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value.

When determining whether impairment of one of our long-lived assets has occurred, the Partnership must estimate the undiscounted cash flows attributable to the asset. The Partnership's estimate of cash flows is based on assumptions regarding the purchase and resale margins on natural gas, NGLs and crude oil, volume of gas, NGLs and crude oil available to the asset, markets available to the asset, operating expenses, and future natural gas, NGL product and crude oil prices. The amount of availability of gas, NGLs and crude oil to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas and crude oil prices. Projections of gas, NGL and crude oil volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:

52

•
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.

Any significant variance in any of the above assumptions or factors could materially affect the Partnership's cash flows, which could require it to record an impairment of an asset.

In the third quarter of 2015, the Partnership reviewed its various assets groups for impairment due to the triggering events described in the goodwill impairment analysis below. The undiscounted cash flows related to one of the Partnership's assets groups in the Crude and Condensate segment were not in excess of its related carrying value. The Partnership estimated the fair value of this reporting unit and determined the fair of the intangible assets was not in excess of their carrying value. This resulted in a $223.1 million impairment of intangible assets in the Partnership's Crude and Condensate segment. The non-cash impairment charge is included in the impairment expense line item of the Condensed Consolidated Statement of Operations. The Partnership utilized Level 3 fair value measurements in its impairment analysis of this definite-lived intangible asset, which included discounted cash flow assumptions by management consistent with those utilized in its goodwill impairment analysis.

Impairment of Goodwill. The Partnership conducts its annual goodwill impairment test in the fourth quarter each year. During the three months ended September 30, 2015, the Partnership recognized a partial goodwill impairment of $576.1 million. Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Partnership evaluates goodwill for impairment annually as of October 31st, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Partnership first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step 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 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 September 2015, the Partnership determined that sustained weakness in the overall energy sector driven by low commodity prices together with a decline in its unit price caused a change in circumstances warranting an interim impairment test.

The Partnership performs its goodwill assessment at the reporting unit level. The Partnership uses a discounted cash flow analysis to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows, including volume forecasts and estimated operating and general and administrative costs. In estimating cash flows, the Partnership incorporates current and historical market information, among other factors.

Using the fair value approaches described above, in step one of the goodwill impairment test, the Partnership determined that the estimated fair value of its Louisiana reporting unit was less than its carrying amount, primarily due to changes in assumptions related to commodity prices and discount rates. 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 the Partnership's Louisiana reporting unit in the amount of $576.1 million was recognized for the three months ended September 30, 2015, which is included in impairment expense in the Condensed Consolidated Statements of Operations.

The Partnership concluded that the fair value of goodwill of the Partnership's Texas and Oklahoma reporting units substantially exceeded their carrying value, and the entire amount of goodwill disclosed on the Condensed Consolidated Balance Sheet associated with these remaining reporting units is recoverable. However, the fair value of the Partnership's Louisiana and Crude and Condensate reporting units is not substantially in excess of its carrying value. The fair value of the Partnership's Crude and Condensate reporting unit exceeded its carrying value by approximately 14.7 percent, and the fair value of the Partnership's Louisiana reporting units approximates its carrying value after considering the impairment above. As of September 30, 2015, the

53

Partnership had $142.1 million and $210.7 million of goodwill allocated to the Crude and Condensate and Louisiana reporting units, respectively.

The Partnership's 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 the Partnership's assumptions and estimates, or its assumptions and estimates change due to new information, the Partnership may be exposed to additional goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value. A continuing prolonged period of lower commodity prices may adversely affect the Partnership's estimates of future operating results, which could result in future goodwill impairment charges for other reporting units due to the potential impact on the cash flows of its operations.

Liquidity and Capital Resources
 
Cash Flows from Operating Activities. Net cash provided by operating activities was $491.6 million for the nine months ended September 30, 2015 compared to $360.0 million for the nine months ended September 30, 2014. Operating cash flows and changes in working capital for comparative periods were as follows (in millions):
 
Nine Months Ended 
 September 30,
 
2015
 
2014
Operating cash flows before working capital
$
456.6

 
$
427.7

Changes in working capital
$
35.0

 
$
(67.7
)
 
The primary reason for the increase in operating cash flows before working capital of $28.9 million from 2014 to 2015 relates to an increase in gross operating margin from the acquired legacy Partnership, Coronado, VEX, LPC, E2 and Gulf Coast assets. Gross operating margin also increased due to start up operations of organic growth projects. The change in working capital for 2015 related to fluctuations in trade receivable and payable balances is due to timing of collection and payments and changes in inventory balances due to normal operating fluctuations. Further, prior to March 7, 2014, all cash receipts for the Predecessor were deposited into Devon’s bank accounts, and all cash disbursements were made from these accounts. Cash transactions handled by Devon were reflected in intercompany advances between Devon and the Predecessor, all of which were settled through an adjustment to equity and reflected in cash flows from financing activities. Subsequent to March 7, 2014, Midstream Holdings handles all of its cash transactions and the changes in working capital are reflected in our cash flows from operating activities.

Cash Flows from Investing Activities. Net cash used in investing activities was $774.3 million for the nine months ended September 30, 2015 and $688.6 million for the nine months ended September 30, 2014. Our primary investing cash flows were acquisition costs and capital expenditures, net of accrued amounts, as follows (in millions):
 
Nine Months Ended 
 September 30,
 
2015

2014
Growth capital expenditures
$
414.4

 
$
516.7

Maintenance capital expenditures
35.9

 
23.4

Acquisition of businesses
330.6

 
126.9

Deposit for acquisition
—

 
23.5

Proceeds from sale of property
(0.4
)
 
—

Investment in equity investment company
8.1

 
5.7

Distribution from equity investment company in excess of earnings
(14.3
)
 
(7.6
)
Total
$
774.3

 
$
688.6

 

54

Growth capital expenditures decreased $102.3 million for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014. The decrease is primarily attributable to a decrease in capital expenditures of $164.0 million related to the Partnership's Cajun Sibon expansion project, which went into service in during the fourth quarter of 2014. This decrease is offset by an increase in capital expenditures of $46.7 million related to the Partnership's E2 and ORV assets.

Maintenance capital expenditures increased $12.5 million for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014. The increase is primarily attributable to compressor overhauls and repairs in the Partnership's Texas and Oklahoma segments.

Acquisition of businesses during the first nine months of 2015 included the LPC and Coronado acquisitions. Acquisition of businesses during the first nine months of 2014 included the VEX Interests. See Note 3 - Acquisitions in the Notes to Condensed Consolidated Financial Statements under Part I, Item 1 of this Form 10-Q.

Cash Flows from Financing Activities. Net cash provided by financing activities was $296.8 million and $368.1 million for the nine months ended September 30, 2015 and 2014, respectively. All Predecessor financing activities from January 1, 2014 through March 6, 2014 totaling $27.2 million are reflected in distributions to Predecessor on the statement of cash flows. Our primary financing activities excluding the period prior to March 7, 2014 consist of the following (in millions):
 
Nine Months Ended 
 September 30,
 
2015
 
2014
Net repayments on Partnership's credit facility
$
(62.1
)
 
$
(6.0
)
Net borrowings on Company's credit facility
—

 
5.3

Senior unsecured notes borrowings
893.3

 
1,190.0

Redemption of 2018 Notes
—

 
(760.3
)
Partial redemption of 2022 Notes
—

 
(36.4
)
Net borrowings on E2 credit facility
—

 
12.5

Net repayments under capital lease obligations
(2.5
)
 
(1.8
)
Debt financing costs
(9.5
)
 
(7.5
)
Proceeds from issuance of Partnership common units
12.9

 
71.9

Distributions to unitholders and Devon also represent a primary use of cash in financing activities. Total cash distributions made during the nine months ended September 30, 2015 and 2014 were as follows (in millions):
 
Nine Months Ended 
 September 30,
 
2015
 
2014
Distributions to members
$
120.6

 
$
51.0

Distribution to non-controlling partners
266.8

 
124.2

Distributions to Devon for net assets acquired
171.0

 
—

 
The Partnership received contributions from Devon of $28.8 million for the nine months ended September 30, 2015 of which $2.2 million related to the reimbursement of employee costs and $26.6 million relates to funding of capital expenditures for the VEX assets.

In order to reduce our interest costs, we do not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our credit facility. We borrow money under our credit facility to fund checks as they are presented. Change in drafts payable for the nine months ended September 30, 2015 and 2014 were as follows (in millions):
 
Nine Months Ended 
 September 30,
 
2015
 
2014
Decrease in drafts payable
$
(12.6
)
 
$
(2.6
)
 
Uncertainties. The Partnership owns and operates 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

55

pipeline and underground storage reservoirs. The Partnership is seeking to recover its losses from responsible parties. The Partnership has sued Texas Brine Company, LLC ("Texas Brine"), the operator of a failed cavern in the area and its insurers, seeking recovery for these losses.  The Partnership has 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. The Partnership also filed a claim with its insurers, which the Partnership's insurers denied. The Partnership disputes the denial and sued its insurers, but has agreed to stay the matter pending resolution of its claims against Texas Brine and its insurers. In August 2014, the Partnership received a partial settlement with respect to the Texas Brine claims in the amount of $6.1 million, but additional claims remain outstanding. The Partnership cannot give assurance that the Partnership will be able to fully recover its losses through insurance recovery or claims against responsible parties.

In June 2014, a group of landowners in Assumption Parish, Louisiana added a subsidiary of the Partnership, EnLink Processing Services, LLC, as a defendant in a pending lawsuit they had filed against Texas Brine, 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 the Partnership's costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case. The Partnership has also filed a claim for defense and indemnity with its insurers.

In October 2014, Williams Olefins, L.L.C. filed a lawsuit against a subsidiary of the Partnership, EnLink NGL Marketing, LP, in the District Court of Tulsa County, Oklahoma. The plaintiff alleges breach of contract and negligent misrepresentation relating to an ethane output contract between the parties and the subsidiary’s termination of ethane production from one of its fractionation plants. The amount of damages is unspecified. The validity of the causes of action, as well as the Partnership’s costs and legal exposure, if any, related to the lawsuit are not currently determinable. The Partnership intends to vigorously defend the case.

Capital Requirements. The Partnership considers a number of factors in determining whether its capital expenditures are growth capital expenditures or maintenance capital expenditures. Growth capital expenditures generally include capital expenditures made for acquisitions or capital improvements that the Partnership expects will increase its asset base, operating income or operating capacity over the long-term. Examples of growth capital expenditures include the acquisition of assets and the construction or development of additional pipeline, storage, gathering or processing assets, in each case to the extent such capital expenditures are expected to expand our asset base, operating capacity or its operating income.

Maintenance capital expenditures include capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. Examples of maintenance capital expenditures are expenditures to refurbish and replace pipelines and other gathering, compression and processing assets up to their original operating capacity, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

During the nine months ended September 30, 2015, growth capital expenditures were $414.4 million, which were funded by internally generated cash flow and borrowings under the Partnership's credit facility. The Partnership's remaining current growth capital spending projection for 2015 is approximately $100.0 million to $150.0 million, mainly related to its Ripdtide plant and Coronado growth. The Partnership expects to fund the growth capital expenditures and the Delaware Basin System acquisition from the proceeds of borrowing under its credit facility and from other debt and equity sources.

The Partnership expects to fund its 2015 maintenance capital expenditures of approximately $5.2 million from operating cash flows. In 2015, it is possible that not all of the planned projects will be commenced or completed. The Partnership's ability to pay distributions to its unitholders and our ability to pay distributions to our unitholders, and the Partnership's ability to fund planned capital expenditures and to make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond its control.

Off-Balance Sheet Arrangements. No off-balance sheet arrangements existed as of September 30, 2015.

56


Total Contractual Cash Obligations. A summary of contractual cash obligations as of September 30, 2015 is as follows (in millions):
 
Payments Due by Period
 
Total
 
 Remainder
 2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
Long-term debt obligations
$
2,662.5

 
$
—

 
$
—

 
$
—

 
$
—

 
$
400.0

 
$
2,262.5

Partnership credit facility
175.0

 
—

 
—

 
—

 
—

 
—

 
175.0

Other debt
0.2

 
—

 
0.1

 
0.1

 
—

 
—

 
—

Interest payable on fixed long-term debt obligations
1,905.0

 
61.7

 
120.0

 
120.0

 
120.0

 
114.6

 
1,368.7

Capital lease obligations
19.6

 
1.3

 
4.9

 
6.9

 
2.9

 
1.6

 
2.0

Operating lease obligations
113.9

 
2.3

 
10.8

 
7.5

 
12.4

 
9.5

 
71.4

Purchase obligations
50.5

 
50.5

 
—

 
—

 
—

 
—

 
—

Delivery contract obligation
67.2

 
4.5

 
17.9

 
17.9

 
17.9

 
9.0

 
—

Pipeline capacity and deficiency agreements (1)
27.4

 
1.7

 
8.1

 
7.0

 
7.3

 
3.3

 
—

Inactive easement commitment (2)
7.0

 
—

 
1.0

 
1.0

 
1.0

 
1.0

 
3.0

Uncertain tax position obligations
1.5

 
—

 
0.5

 
0.6

 
0.3

 
0.1

 
—

Total contractual obligations
$
5,029.8


$
122.0


$
163.3


$
161.0


$
161.8


$
539.1


$
3,882.6

__________________________________________________
(1)
Consists of pipeline capacity payments for firm transportation and deficiency agreements.
(2)
Amounts related to inactive easements paid as utilized by the Partnership with balance due at end of 10 years if not utilized.

The above table does not include any physical or financial contract purchase commitments for natural gas due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

The interest payable under the Partnership’s credit facility is not reflected in the above table because such amounts depend on the outstanding balances and interest rates, which vary from time to time. However, given the same borrowing amount and rates in effect at September 30, 2015, the cash obligation for interest expense on the Partnership’s credit facility would be approximately $2.6 million per year or approximately $0.6 million for the remainder of 2015.


57

Indebtedness
 
As of September 30, 2015 and December 31, 2014, long-term debt consisted of the following (in millions):
 
September 30,
2015
 
December 31,
2014
Partnership credit facility (due 2020), interest based on Prime and/or LIBOR plus an applicable margin, interest rate at September 30, 2015 and December 31, 2014 was 1.5% and 1.9% respectively
$
175.0

 
$
237.0

Company credit facility (due 2019)
—

 
—

The Partnership's senior unsecured notes (due 2019), net of discount of $0.4 million at September 30, 2015 and $0.5 million at December 31, 2014, which bear interest at the rate of 2.70%
399.6

 
399.5

The Partnership's senior unsecured notes (due 2022), including a premium of $19.7 million at September 30, 2015 and $21.9 million at December 31, 2014, which bear interest at the rate of 7.125%
182.2

 
184.4

The Partnership's senior unsecured notes (due 2024), net of premium of $2.9 million at September 30, 2015 and $3.2 million at December 31, 2014, which bear interest at the rate of 4.40%
552.9

 
553.2

Partnership's Senior unsecured notes (due 2025), net of discount of $1.2 million at September 30, 2015, which bear interest at the rate of 4.15%
748.8

 
—

The Partnership's senior unsecured notes (due 2044), net of discount of $0.3 million at September 30, 2015 and December 31, 2014, which bear interest at the rate of 5.60%
349.7

 
349.7

The Partnership's senior unsecured notes (due 2045), net of discount of $6.9 million at September 30, 2015 and $1.7 million at December 31, 2014, which bear interest at the rate of 5.05%
443.1

 
298.3

Other debt
0.2

 
0.4

Debt classified as long-term
$
2,851.5

 
$
2,022.5


Company Credit Facility. On March 7, 2014, the Company entered into a $250.0 million revolving credit facility, which includes a $125.0 million letter of credit subfacility (the “credit facility”). The Company used borrowings under the credit facility to repay outstanding borrowings under the margin loan facility of XTXI Capital, LLC (a former wholly-owned subsidiary of EnLink Midstream, Inc.), which was paid in full and terminated on March 7, 2014. Our obligations under the credit facility are guaranteed by two of our wholly-owned subsidiaries and secured by first priority liens on (i) 17,431,152 Partnership common units and the 100% membership interest in the General Partner indirectly held by us, (ii) the 100% equity interest in each of our wholly-owned subsidiaries held by us and (iii) any additional equity interests subsequently pledged as collateral under the credit facility.

As of September 30, 2015 there were no borrowings under the credit facility, leaving $250.0 million available for future borrowing based on the borrowing capacity of $250.0 million.

Partnership Credit Facility.  As of September 30, 2015, there were $2.8 million in outstanding letters of credit and $175.0 million of outstanding borrowings under the Partnership’s credit facility, leaving approximately $1.3 billion available for future borrowing based on the borrowing capacity of $1.5 billion. The credit facility will mature on March 6, 2020, unless we request, and the requisite lenders agree, to extend it pursuant to its terms.

On May 12, 2015, the Partnership issued $900.0 million aggregate principal amount of unsecured senior notes, consisting of $750.0 million aggregate principal amount of its 4.150% senior notes due 2025 (the “2025 Notes”) and $150.0 million aggregate principal amount of its 5.050% senior notes due 2045 (the “2045 Notes”) at prices to the public of 99.827% and 96.381%, respectively, of their face value. The 2025 Notes mature on June 1, 2025 and the 2045 Notes mature on April 1, 2045. Interest payments on the 2025 Notes are payable on June 1 and December 1 of each year, beginning December 1, 2015. Interest payments on the 2045 Notes are payable on April 1 and October 1 of each year, beginning October 1, 2015.

See Note 6 to the condensed consolidated financial statements titled “Long-Term Debt” for further details.


58

Recent Accounting Pronouncements

 In September 2015 the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments ("ASU 2015-16"), 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. ASU 2015-16 is effective for public business entities for annual periods, including interim periods within those annual periods, beginning after December 15, 2015. For all other entities, ASU 2015-16 is effective for fiscal years beginning after December 15, 2016, and interim periods within fiscal years beginning after December 15, 2017. Early adoption is permitted. The update is effective for us beginning on January 1, 2016.

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 Company'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 consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (Topic 835). The update requires debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability. The standard requires retrospective application and is effective for us beginning on January 1, 2016.

In February 2015, the FASB issued 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. The update is effective for us beginning on January 1, 2016, and we are currently evaluating the impact this standard will have on our consolidated financial statements and related disclosures.
 
Subject to these evaluations, we have reviewed all recently issued accounting pronouncements that became effective during the nine months ended September 30, 2015, and have determined that none would have a material impact on our Condensed Consolidated Financial Statements.
 
Disclosure Regarding Forward-Looking Statements
 
This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of federal securities laws. Statements included in this report which are not historical facts are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. Such statements reflect our current views with respect to future events based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to specific uncertainties discussed elsewhere in this Quarterly Report on Form 10-Q, the risk factors set forth in Part II, “Item 1A. Risk Factors” of this report may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Our primary market risk is the risk related to changes in the prices of natural gas, NGLs, condensate and crude oil. In addition, we are also exposed to the risk of changes in interest rates on floating rate debt.

Comprehensive financial reform legislation was signed into law by the President on July 21, 2010. The legislation calls for the Commodities Futures Trading Commission ("CFTC") to regulate certain markets for derivative products, including over-the-counter

59

(“OTC”) derivatives. The CFTC has issued several new relevant regulations and other rulemakings are pending at the CFTC, the product of which would be rules that implement mandates in new legislation to cause significant portions of derivatives markets to clear through clearinghouses. The legislation and new regulations may also require counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any future new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition and our results of operations.

Commodity Price Risk
 
We are subject to significant risks due to fluctuations in commodity prices. Our exposure to these risks is primarily in the gas processing component of our business. We currently process gas under three main types of contractual arrangements as summarized below. Approximately 87% of our processing margins are from fixed-fee based contracts for the nine months ended September 30, 2015. During March 2015 the Partnership acquired processing plants from Coronado which generate gross operating margins based on percent of proceeds contracts.
 
1.             
 Processing margin contracts: Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and makes a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction or "PTR". The Partnership's margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. However, the Partnership mitigates its risk of processing natural gas when margins are negative primarily through its ability to bypass processing when it is not profitable for the Partnership, or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications.

2.                   Percent of liquids contracts: Under these contracts, the Partnership receives a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, the Partnership's margins from these contracts are greater during periods of high liquids prices. The Partnership's margins from processing cannot become negative under percent of liquids contracts, but do decline during periods of low NGL prices.

3.
Percent of proceeds contracts: Under these contracts, the Partnership receives a fee as a portion of the proceeds of the sale of natural gas and liquids. Therefore, the Partnership's margins from these contracts are greater during periods of high natural gas and liquids prices. The Partnership's margins from processing cannot become negative under percent of proceeds contracts, but do decline during periods of low natural gas and NGL prices.
 
4.                   Fixed-fee based contracts: Under these contracts we have no direct commodity price exposure and are paid a fixed fee per unit of volume that is processed.

The Partnership's primary commodity risk management objective is to reduce volatility in its cash flows. The Partnership maintains a risk management committee, including members of senior management, which oversees all hedging activity. The Partnership enters into hedges for natural gas and NGLs using over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by its risk management committee.

The Partnership has hedged its exposure to fluctuations in prices for natural gas and NGL volumes produced for its account. The Partnership hedges its exposure based on volumes it considers hedgeable (volumes committed under contracts that are long term in nature) versus total volumes that include volumes that may fluctuate due to contractual terms, such as contracts with month to month processing options. Further, the Partnership has tailored its hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of its physical equity volumes. The NGL hedges cover specific NGL products based upon the Partnership's expected equity NGL composition.


60

The following table sets forth certain information related to derivative instruments outstanding at September 30, 2015 mitigating the risks associated with the gas processing and fractionation components of the Partnership's business. The relevant payment index price for liquids is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by OPIS. The relevant index price for Natural Gas is Henry Hub Gas Daily is as defined by the pricing dates in the swap contracts.
Period
 
Underlying
 
Notional Volume
 
We Pay
 
We Receive *
 
Fair Value Asset/(Liability)
 
 
 
 
 
 
 
 
 
 
 
(in millions)
October 2015 - December 2016
 
Ethane
 
817

(MBbls)
 
$0.2780/gal
 
Index
 
$
(2.6
)
October 2015 - December 2016
 
Propane
 
908

(MBbls)
 
Index
 
$0.8762/gal
 
15.5

October 2015 - September 2016
 
Normal Butane
 
74

(MBbls)
 
Index
 
$0.6259/gal
 
0.2

October 2015 - September 2016
 
Natural Gasoline
 
63

(MBbls)
 
Index
 
$1.3026/gal
 
0.9

October 2015 - September 2016
 
Natural Gas
 
2,497

(MMBtu/d)
 
$3.13/MMbtu*
 
Index
 
0.4

October 2015
 
Condensate
 
0.1

(MBbls)
 
$43.07/bbl
 
Index
 
0.1

 
 
 
 
 
 
 
 
 
 
 
$
14.5

__________________________________________________
*weighted average

Another price risk the Partnership faces is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. The Partnership enters each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves the Partnership with short or long positions that must be covered. The Partnership uses financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

The use of financial instruments may expose the Partnership to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that the Partnership engages in hedging activities, it may be prevented from realizing the benefits of favorable price changes in the physical market. However, the Partnership is similarly insulated against unfavorable changes in such prices.

As of September 30, 2015, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value asset of $14.5 million. The aggregate effect of a hypothetical 10% change, increase or decrease, in gas and NGL prices would result in a change of approximately $2.2 million in the net fair value of these contracts as of September 30, 2015. 

Interest Rate Risk

The Company had no outstanding borrowings on its variable rate credit facility as of September 30, 2015.

The Partnership is exposed to interest rate risk on its variable rate credit facility. At September 30, 2015, the Partnership's credit facility had $175.0 million in outstanding borrowings under this facility. A 1% increase or decrease in interest rates would change its annual interest expense by approximately $1.8 million for the year. The Partnership is not exposed to changes in interest rates with respect to its senior unsecured notes due in 2019, 2022, 2024, 2025, 2044, or 2045 as these are fixed-rate obligations. The estimated fair value of the Partnership's senior unsecured notes was approximately $2,488.0 million as of September 30, 2015, based on market prices of similar debt at September 30, 2015. Market risk is estimated as the potential decrease in fair value of the Partnership's long-term debt resulting from a hypothetical increase of 1% in interest rates. Such an increase in interest rates would result in approximately a $218.4 million decrease in fair value of the Partnership's senior unsecured notes at September 30, 2015.

 Item 4. Controls and Procedures
 
(a) Evaluation of Disclosure Controls and Procedures
 
We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of EnLink Midstream Manager, LLC, of the effectiveness of our disclosure controls

61
Table of Contents

and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report (September 30, 2015), our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time period specified in the applicable rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
 
(b) Changes in Internal Control Over Financial Reporting
 
There has been no change in our internal control over financial reporting that occurred in the three months ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
 
PART II—OTHER INFORMATION
 
Item 1. Legal Proceedings
 
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.
 
For a discussion of certain litigation and similar proceedings, please refer to Note 15, “Commitments and Contingencies,” of the Notes to Condensed Consolidated Financial Statements contained in Part I of this Quarterly Report on Form 10-Q, which is incorporated by reference herein.
 
Item 1A. Risk Factors
 
Information about risk factors does not differ materially from that set forth in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.


62

Item 6. Exhibits
 
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
Number
 
Description
3.1
—
Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-4, file No. 333-192419).
3.2
—
Certificate of Amendment to Certificate of Formation of EnLink Midstream, LLC (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-4, file No. 333-192419).
3.3
—
First Amended and Restated Operating Agreement of EnLink Midstream, LLC, dated as of March 7, 2014 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated March 7, 2014, filed with the Commission on March 11, 2014, file No. 001-36336).
3.4
—
Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.12 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
3.5
—
Certificate of Amendment to the Certificate of Formation of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.13 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
3.6
—
First Amended and Restated Limited Liability Company Agreement of EnLink Midstream Manager, LLC (incorporated by reference to Exhibit 3.14 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2014).
3.7
—
Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).
3.8
—
Certificate of Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.2 to EnLink Midstream Partners, LP’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012, file No. 000-50067).
3.9
—
Second Amendment to the Certificate of Limited Partnership of EnLink Midstream Partners, LP (incorporated by reference to Exhibit 3.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 6, 2014, filed with the Commission on March 11, 2014).
3.10
—
Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP dated July 7, 2014 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated July 7, 2014, filed with the Commission on July 7, 2014).
3.11
—
Amendment No. 1 to Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of February 17, 2015 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated February 17, 2015, filed with the Commission on February 17, 2015).
3.12
—
Amendment No. 2 to Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of March 16, 2015 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated March 16, 2015, filed with the Commission on March 16, 2015).
3.13
—
Amendment No. 3 to Seventh Amended and Restated Agreement of Limited Partnership of EnLink Midstream Partners, LP, dated as of May 27, 2015 (incorporated by reference to Exhibit 3.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated May 27, 2015, filed with the Commission on May 27, 2015).
3.14
—
Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.7 to EnLink Midstream Partners, LP’s Registration Statement on Form S-1, file No. 333-97779).
3.15
—
Certificate of Amendment to the Certificate of Formation of EnLink Midstream GP, LLC (incorporated by reference to Exhibit 3.12 to EnLink Midstream Partners, LP’s Registration Statement on Form S-3, file No. 333-194465).
10.1
—
Commitment Increase and Extension Agreement, dated as of February 5, 2015, by and among EnLink Midstream Partners, LP, the Lenders party thereto, and Bank of America, N.A., as an L/C Issuer, as Swing Line Lender, and as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated February 5, 2015, filed with the Commission on February 11, 2015).
10.2†
—
Form of Performance Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.1 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).
10.3†
—
Form of Performance Unit Agreement made under the 2014 LLC Plan (incorporated by reference to Exhibit 10.2 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).
10.4†
—
Form of Restricted Incentive Unit Agreement made under the GP Plan (incorporated by reference to Exhibit 10.3 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).

63

10.5†
—
Form of Restricted Incentive Unit Agreement made under the 2014 LLC Plan (incorporated by reference to Exhibit 10.4 to EnLink Midstream Partners, LP’s Current Report on Form 8-K dated January 30, 2015, filed with the Commission February 5, 2015).
31.1*
—
Certification of the Principal Executive Officer.
31.2*
—
Certification of the Principal Financial Officer.
32.1*
—
Certification of the Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350.
101*
—
The following financial information from EnLink Midstream, LLC's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014, (ii) Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015 and 2014, (iii) Consolidated Statements of Changes in Members’ Equity for the nine months ended September 30, 2015, (iv) Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014, and (v) the Notes to Condensed Consolidated Financial Statements.
__________________________________________________
*     Filed herewith.
**  Pursuant to Item 601(b)(2) of Regulation S-K, the Registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.
† This Exhibit is identified as a management contract or compensatory benefit plan or arrangement.



64

SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
EnLink Midstream, LLC
 
 
 
By:
EnLink Midstream Manager, LLC,
 
 
its managing member
 
 
 
 
By:
/s/ MICHAEL J. GARBERDING
 
 
Michael J. Garberding
 
 
Executive Vice President and Chief Financial Officer
 
November 4, 2015

65