10-Q 1 c000-20160930x10q.htm 10-Q enlc_Current_Folio_10Q

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Form 10-Q

 

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

for the quarterly period ended September 30, 2016

 

OR

 

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 ☒ No ☐

 

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 ☒ No ☐

 

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 ☒

    

Accelerated filer ☐

 

 

 

Non-accelerated filer ☐

 

Smaller reporting company ☐

(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 ☐ No ☒

 

As of October 24, 2016, the Registrant had 180,048,704 common units outstanding.

 

 

 

 


 

 

 

TABLE OF CONTENTS

 

 

 

 

 

 

Item

    

Description

    

Page

 

 

 

 

 

 

 

PART I—FINANCIAL INFORMATION

 

 

 

 

 

 

 

1. 

 

Financial Statements

 

3

 

 

 

 

 

 

 

 

 

 

2. 

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

32

 

 

 

 

 

3. 

 

Quantitative and Qualitative Disclosures About Market Risk

 

54

 

 

 

 

 

4. 

 

Controls and Procedures

 

56

 

 

 

 

 

 

 

PART II—OTHER INFORMATION

 

 

 

 

 

 

 

1. 

 

Legal Proceedings

 

58

 

 

 

 

 

1A. 

 

Risk Factors

 

58

 

 

 

 

 

6. 

 

Exhibits

 

59

 

 

 

2


 

ENLINK MIDSTREAM, LLC

Condensed Consolidated Balance Sheets

 

 

 

 

 

 

 

 

 

 

 

 

    

September 30, 2016

    

December 31, 2015

 

 

(unaudited)

 

 

 

 

 

(In millions, except unit data)

ASSETS

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

Cash and cash equivalents

 

$

60.1

 

$

18.0

Accounts receivable:

 

 

 

 

 

 

Trade, net of allowance for bad debt of $0.8 and $0.3, respectively

 

 

47.8

 

 

37.5

Accrued revenue and other

 

 

311.8

 

 

268.8

Related party

 

 

76.7

 

 

110.8

Fair value of derivative assets

 

 

4.3

 

 

16.8

Natural gas and NGLs inventory, prepaid expenses and other

 

 

39.5

 

 

41.8

Total current assets

 

 

540.2

 

 

493.7

Property and equipment, net of accumulated depreciation of $2,036.5 and $1,757.6, respectively

 

 

6,195.1

 

 

5,666.8

Intangible assets, net of accumulated amortization of $142.0 and $54.6, respectively

 

 

1,650.9

 

 

689.9

Goodwill

 

 

1,542.2

 

 

2,413.9

Investment in unconsolidated affiliates

 

 

266.4

 

 

274.3

Other assets, net

 

 

2.4

 

 

2.7

Total assets

 

$

10,197.2

 

$

9,541.3

LIABILITIES AND MEMBERS’ EQUITY

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Accounts payable and drafts payable

 

$

44.1

 

 

33.2

Accounts payable to related party

 

 

11.2

 

 

14.8

Accrued gas, NGLs, condensate and crude oil purchases

 

 

262.2

 

 

206.7

Fair value of derivative liabilities

 

 

6.5

 

 

2.9

Installment payable, net of discount of $7.4

 

 

242.6

 

 

 —

Other current liabilities

 

 

196.3

 

 

174.8

Total current liabilities

 

 

762.9

 

 

432.4

Long-term debt

 

 

3,245.2

 

 

3,066.0

Fair value of derivative liabilities

 

 

 —

 

 

0.1

Asset retirement obligations

 

 

13.4

 

 

12.9

Other long-term liabilities

 

 

49.8

 

 

65.9

Installment payable, net of discount of $32.8

 

 

217.2

 

 

 —

Deferred tax liability

 

 

542.8

 

 

532.1

 

 

 

 

 

 

 

Redeemable non-controlling interest

 

 

6.2

 

 

7.0

 

 

 

 

 

 

 

Members’ equity:

 

 

 

 

 

 

Members’ equity (180,048,704 and 164,242,160 units issued and outstanding at September 30, 2016 and December 31, 2015, respectively)

 

 

1,926.0

 

 

2,285.7

Non-controlling interest

 

 

3,433.7

 

 

3,139.2

Total members’ equity

 

 

5,359.7

 

 

5,424.9

Commitments and contingencies (Note 15)

 

 

 

 

 

 

Total liabilities and members’ equity

 

$

10,197.2

 

$

9,541.3

 

 

 

See accompanying notes to condensed consolidated financial statements.

3


 

ENLINK MIDSTREAM, LLC

Condensed Consolidated Statements of Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

`

 

Three Months Ended

 

Nine Months Ended

 

 

September 30,

 

September 30,

 

    

2016

    

2015

    

2016

    

2015

 

 

(Unaudited)

 

 

(In millions, except per unit amounts)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

Product sales

 

$

771.0

 

$

863.5

 

$

2,097.8

 

$

2,488.8

Product sales - affiliates

 

 

43.1

 

 

40.3

 

 

99.3

 

 

89.6

Midstream services

 

 

125.7

 

 

111.3

 

 

348.5

 

 

351.3

Midstream services - affiliates

 

 

165.3

 

 

150.3

 

 

488.5

 

 

449.3

Gain (loss) on derivative activity

 

 

(0.5)

 

 

5.2

 

 

(6.6)

 

 

6.6

Total revenues

 

 

1,104.6

 

 

1,170.6

 

 

3,027.5

 

 

3,385.6

Operating costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Cost of sales (1)

 

 

788.2

 

 

861.8

 

 

2,106.8

 

 

2,487.4

Operating expenses (2)

 

 

98.0

 

 

105.0

 

 

296.3

 

 

312.6

General and administrative (3)

 

 

29.3

 

 

34.8

 

 

94.7

 

 

105.6

(Gain) loss on disposition of assets

 

 

(3.0)

 

 

3.2

 

 

(2.9)

 

 

3.2

Depreciation and amortization

 

 

126.2

 

 

98.4

 

 

373.0

 

 

289.1

Impairments

 

 

 —

 

 

799.2

 

 

873.3

 

 

799.2

Total operating costs and expenses

 

 

1,038.7

 

 

1,902.4

 

 

3,741.2

 

 

3,997.1

Operating income (loss)

 

 

65.9

 

 

(731.8)

 

 

(713.7)

 

 

(611.5)

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net of interest income

 

 

(48.4)

 

 

(30.4)

 

 

(138.9)

 

 

(72.1)

Income (loss) from unconsolidated affiliates

 

 

1.1

 

 

6.4

 

 

(0.5)

 

 

16.1

Other income

 

 

0.1

 

 

0.1

 

 

0.1

 

 

0.6

Total other expense

 

 

(47.2)

 

 

(23.9)

 

 

(139.3)

 

 

(55.4)

Income (loss) before non-controlling interest and income taxes

 

 

18.7

 

 

(755.7)

 

 

(853.0)

 

 

(666.9)

Income tax provision

 

 

(7.6)

 

 

(0.2)

 

 

(6.0)

 

 

(21.1)

Net income (loss)

 

 

11.1

 

 

(755.9)

 

 

(859.0)

 

 

(688.0)

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

 

 

10.4

 

 

(562.5)

 

 

(402.9)

 

 

(526.1)

Net income (loss) attributable to EnLink Midstream, LLC

 

$

0.7

 

$

(193.4)

 

$

(456.1)

 

$

(161.9)

Devon investment interest in net income

 

$

 —

 

$

 —

 

$

 —

 

$

0.7

EnLink Midstream, LLC interest in net income (loss)

 

$

0.7

 

$

(193.4)

 

$

(456.1)

 

$

(162.6)

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

 

 

 

 

 

 

 

 

 

 

 

 

Basic common unit

 

$

 —

 

$

(1.18)

 

$

(2.54)

 

$

(0.99)

Diluted common unit

 

$

 —

 

$

(1.18)

 

$

(2.54)

 

$

(0.99)

(1)

Includes affiliate cost of sales of $33.7 million and $51.9 million for the three months ended September 30, 2016 and 2015, respectively, and $126.0 million and $91.7 million for the nine months ended September 30, 2016 and 2015, respectively.

(2)

Includes affiliate operating expenses of $0.1 million and $0.1 million for the three months ended September 30, 2016 and 2015, respectively, and $0.4 million and $0.3 million for the nine months ended September 30, 2016 and 2015, respectively.

(3)

Includes affiliate general and administrative expenses of $0.1 million and $0.3 million for the three and nine months ended September 30, 2015, respectively.

 

 

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

4


 

ENLINK MIDSTREAM, LLC

Consolidated Statement of Changes in Members’ Equity

Nine Months Ended September 30, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Redeemable

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-

 

 

 

 

 

 

 

 

 

 

 

 

 

controlling

 

 

 

 

 

 

 

Non-

 

 

 

 

Interest

 

 

 

 

 

 

 

Controlling 

 

 

 

 

(Temporary

 

 

Common Units

 

Interest

 

 

 

Equity)

 

    

$

    

Units

    

$

    

Total

    

$

Balance, December 31, 2015

 

$

2,285.7

 

164.2

 

$

3,139.2

 

$

5,424.9

 

$

7.0

Unit-based compensation

 

 

11.2

 

 —

 

 

11.3

 

 

22.5

 

 

 —

Issuance of common units by the Partnership

 

 

 —

 

 —

 

 

110.6

 

 

110.6

 

 

 —

Issuance of Preferred Units by the Partnership

 

 

 —

 

 —

 

 

724.1

 

 

724.1

 

 

 —

Issuance of common units

 

 

214.9

 

15.6

 

 

 —

 

 

214.9

 

 

 —

Conversion of restricted units for common, net of units withheld for taxes

 

 

(1.2)

 

0.2

 

 

 —

 

 

(1.2)

 

 

 —

Non-controlling partner’s impact of conversion of restricted units

 

 

 —

 

 —

 

 

(1.2)

 

 

(1.2)

 

 

 —

Change in equity due to issuance of units by the Partnership

 

 

10.5

 

 —

 

 

(16.8)

 

 

(6.3)

 

 

 —

Non-controlling interest distributions

 

 

 —

 

 —

 

 

(283.5)

 

 

(283.5)

 

 

 —

Non-controlling interest contribution

 

 

 —

 

 —

 

 

151.5

 

 

151.5

 

 

 —

Distributions to members

 

 

(139.0)

 

 —

 

 

 —

 

 

(139.0)

 

 

 —

Distributions to redeemable non-controlling interest

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

(0.8)

Contribution from Devon to the Partnership

 

 

 —

 

 —

 

 

1.4

 

 

1.4

 

 

 —

Net loss

 

 

(456.1)

 

 —

 

 

(402.9)

 

 

(859.0)

 

 

 —

Balance, September 30, 2016

 

$

1,926.0

 

180.0

 

$

3,433.7

 

$

5,359.7

 

$

6.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

5


 

ENLINK MIDSTREAM, LLC

Consolidated Statements of Cash Flows

 

 

 

 

 

 

 

 

 

 

Nine Months Ended September 30, 

 

    

2016

    

2015

 

 

(Unaudited)

 

 

(In millions)

Cash flows from operating activities:

 

 

 

 

 

 

Net loss

 

$

(859.0)

 

$

(688.0)

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

 

 

 

 

 

 

Impairments

 

 

873.3

 

 

799.2

Depreciation and amortization

 

 

373.0

 

 

289.1

Accretion expense

 

 

0.4

 

 

0.4

(Gain) loss on disposition of assets

 

 

(2.9)

 

 

3.2

Deferred tax expense

 

 

4.4

 

 

18.2

Non-cash unit-based compensation

 

 

22.5

 

 

28.9

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

 

 

6.6

 

 

(6.6)

Cash settlements on derivatives

 

 

9.5

 

 

13.0

Amortization of debt issue costs

 

 

2.9

 

 

2.4

Amortization of net (premium) discount on notes

 

 

36.9

 

 

(2.2)

Redeemable non-controlling interest expense

 

 

0.3

 

 

(2.0)

Distribution of earnings from unconsolidated affiliates

 

 

0.7

 

 

17.1

(Income) loss from unconsolidated affiliates

 

 

0.5

 

 

(16.1)

Changes in assets and liabilities net of assets acquired and liabilities assumed:

 

 

 

 

 

 

Accounts receivable, accrued revenue and other

 

 

(17.9)

 

 

124.1

Natural gas and NGLs inventory, prepaid expenses and other

 

 

11.9

 

 

(28.6)

Accounts payable, accrued gas and crude oil purchases and other accrued liabilities

 

 

49.4

 

 

(60.5)

Net cash provided by operating activities

 

 

512.5

 

 

491.6

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

 

 

 

 

 

 

Additions to property and equipment

 

 

(423.7)

 

 

(450.3)

Acquisition of business, net of cash acquired

 

 

(791.5)

 

 

(330.6)

Proceeds from insurance settlement

 

 

0.3

 

 

 —

Proceeds from sale of property

 

 

4.7

 

 

0.4

Investment in unconsolidated affiliates

 

 

(45.0)

 

 

(8.1)

Distribution from unconsolidated affiliates in excess of earnings

 

 

51.6

 

 

14.3

Net cash used in investing activities

 

 

(1,203.6)

 

 

(774.3)

Cash flows from financing activities:

 

 

 

 

 

 

Proceeds from borrowings

 

 

1,667.7

 

 

2,604.4

Payments on borrowings

 

 

(1,484.5)

 

 

(1,773.2)

Payments on capital lease obligations

 

 

(3.2)

 

 

(2.5)

Decrease in drafts payable

 

 

 —

 

 

(12.6)

Debt financing costs

 

 

(4.7)

 

 

(9.5)

Mandatorily redeemable non-controlling interest

 

 

(4.0)

 

 

 —

Conversion of restricted units, net of units withheld for taxes

 

 

(1.2)

 

 

(2.8)

Conversion of Partnership's restricted units, net of units withheld for taxes

 

 

(1.2)

 

 

(2.5)

Proceeds from issuance of Partnership's common units

 

 

110.6

 

 

12.9

Distributions to non-controlling partners

 

 

(284.3)

 

 

(266.8)

Distribution to members

 

 

(139.0)

 

 

(120.6)

Contribution from Devon

 

 

1.4

 

 

28.8

Distributions to Devon for net assets acquired

 

 

 —

 

 

(171.0)

Proceeds from issuance of Partnership Preferred Units

 

 

724.1

 

 

 —

Contributions by non-controlling interest

 

 

151.5

 

 

12.2

Net cash provided by financing activities

 

 

733.2

 

 

296.8

Net increase in cash and cash equivalents

 

 

42.1

 

 

14.1

Cash and cash equivalents, beginning of period

 

 

18.0

 

 

68.4

Cash and cash equivalents, end of period

 

$

60.1

 

$

82.5

Cash paid for interest

 

$

71.2

 

$

46.0

Cash paid (refund) for income taxes

 

$

(5.6)

 

$

13.7

 

 

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

6


 

ENLINK MIDSTREAM, LLC

Notes to Condensed Consolidated Financial Statements

September 30, 2016

(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 EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”). EnLink Oklahoma T.O. is sometimes used to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP together with its consolidated subsidiaries.

(a)Organization of Business

EnLink Midstream, LLC is a Delaware limited liability company formed in October 2013. The Company’s common units are traded on the New York Stock Exchange under the symbol “ENLC.”

Our assets consist of equity interests in the Partnership and EnLink Oklahoma T.O. 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. EnLink Oklahoma T.O. is a partnership held by us and the Partnership, and is engaged in the gathering and processing of natural gas. As of September 30, 2016, our interests in the Partnership and EnLink Oklahoma T.O. consist of the following:

88,528,451 common units representing an aggregate 22.5% limited partner interest in the Partnership;

100.0% ownership interest in EnLink Midstream Partners GP, LLC, the general partner of the Partnership (the “General Partner”), which owns a 0.4% general partner interest and all of the incentive distribution rights in the Partnership; and

16% limited partner interest in EnLink Oklahoma T.O.

(b)Nature of Business

The Partnership primarily focuses on providing midstream energy services, including gathering, transmission, processing, fractionation, brine services and marketing to producers of natural gas, natural gas liquids, crude oil and condensate.  The Partnership connects the wells of producers in its market areas to its gathering systems, processes natural gas to remove NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. The Partnership purchases natural gas from natural gas producers and other supply sources and sells that natural gas to utilities, industrial consumers, other marketers and pipelines. 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 fee-based arrangements.  The Partnership provides a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. The Partnership also has crude oil and condensate terminal facilities that provide access for crude oil and condensate producers to premium markets. 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 from our south Louisiana processing plants to its fractionators in south Louisiana.  The Partnership’s crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a fee, transport crude oil from a producer site to an end user.  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.

7


 

(c)Consolidation of the Partnership

In January 2016, we adopted Accounting Standards Updates (“ASU”) 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU 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.  Due to ENLC’s ownership of the General Partner, the Partnership is considered a variable interest entity as the limited partners lack the ability to exercise kick-out rights over the General Partner and do not have substantive participating rights. Further, ENLC, including the consideration of the Incentive Distribution Rights, is considered the primary beneficiary as it has the power to direct the activities that most significantly impact the Partnership’s economic performance. The adoption of this standard has no impact on our consolidated financial statements as we will continue to consolidate the Partnership.

 

(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.

During the first half of 2015, the Partnership acquired assets from Devon through drop down transactions. Due to our control of the Partnership through our ownership and control of the General Partner and Devon’s control of us through its ownership of our managing member, 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 condensed 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)Adopted Accounting Standards

In January 2016, we adopted ASU 2015-03, Interest - Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability and requires retrospective application.  The application of this new accounting guidance resulted in the reclassification of $23.8 million of debt issuance costs from “Other Assets, Net” to “Long-term debt” in our accompanying Condensed Consolidated Balance Sheet as of December 31, 2015.

In January 2016, we adopted ASU 2015-17, Balance Sheet Classification of Deferred Taxes on a prospective basis. This new standard required that deferred tax assets and liabilities be classified as noncurrent in our Condensed Consolidated Balance Sheet.

In January 2016, we adopted ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, which eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated.

In August 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-15, Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). ASU 2016-15 addresses the classification and presentation of certain cash receipts and cash payments related to debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, distributions received from equity method investees, and other specific cash flow issues. ASU 2016-

8


 

15 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and should be applied using a retrospective transition method to each period presented. Early application is permitted, including adoption in an interim period. In September 2016, we elected to early adopt ASU 2016-15 effective January 1, 2016. The adoption had no impact on our condensed consolidated financial statements or related disclosures.

(c)   Accounting Standards to be Adopted in Future Periods

 

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which amends ASC Topic 718, Compensation – Stock Compensation (“ASU 2016-09”). First, the new standard will require all of the tax effects related to share-based payments at settlement (or expiration) to be recorded through the income statement, and is required to be applied prospectively. Second, the new standard also allows entities to withhold taxes of an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in liability classification of the award, and is required to be adopted using a modified retrospective approach. Third, under the ASU, forfeitures can be estimated, as currently required, or recognized when they occur. If elected, the change to recognize forfeitures when they occur must be adopted using a modified retrospective approach. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016 including interim periods within those annual periods. Early adoption is permitted. We do not expect this standard to materially impact our condensed consolidated financial statements or related disclosures.

 

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) - Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). Lessees will need to recognize virtually all of their leases on the balance sheet, by recording a right-of-use asset and lease liability. Lessor accounting is similar to the current model, but updated to align with certain changes to the lessee model and the new revenue recognition standard.  Existing sale-leaseback guidance is replaced with a new model applicable to both lessees and lessors. Additional revisions have been made to embedded leases, reassessment requirements, and lease term assessments including variable lease payment, discount rate, and lease incentives.  ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018 including interim periods within those annual periods. Early adoption is permitted, and is required to be adopted using a modified retrospective transition. We are currently evaluating the impact this standard will have on our condensed consolidated financial statements and related disclosures.

 

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 will replace existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which the Partnership expects to be entitled in exchange for transferring goods or services to a customer. The new standard will also require significantly expanded disclosures regarding the qualitative and quantitative information of the Partnership’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU 2016-12”),  which updated ASU 2014-09. ASU 2016-12 clarifies certain core recognition principles including collectability, sales tax presentation, noncash consideration, contract modifications and completed contracts at transition and disclosures no longer required if the full retrospective transition method is adopted. ASU 2014-09 and ASU 2016-12 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within those annual periods, and are to be applied retrospectively, with early application permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact the pronouncements will have on our condensed consolidated financial statements and related disclosures.

 

(3) Acquisitions

Matador Acquisition

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

 

9


 

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

 

$

1.1

Property, plant and equipment

 

 

35.5

Intangibles

 

 

98.8

Goodwill

 

 

10.7

Liabilities assumed:

 

 

 

Current liabilities

 

 

(4.8)

Total identifiable net assets

 

$

141.3

 

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 life of approximately 15 years.  Goodwill recognized from the acquisition primarily relates to the value created from additional growth opportunities and greater operating leverage in the Permian Basin.  All such goodwill is allocated to the Partnership’s Texas segment and is non-deductible for tax purposes.

Deadwood Acquisition

Prior to November 2015, the Partnership co-owned the Deadwood natural gas processing plant with a subsidiary of Apache Corporation (“Apache”).  On November 16, 2015, the Partnership acquired Apache’s 50% ownership interest in the Deadwood natural gas processing facility for approximately $40.1 million, all of which is considered property, plant and equipment.  The final working capital settlement paid to Apache was approximately $1.5 million. The transaction was accounted for using the acquisition method.

Tall Oak Acquisition

On January 7, 2016, we and the Partnership acquired a 16% and 84% voting interest, respectively, in EnLink Oklahoma T.O. for approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The final installment of $500.0 million is due by the Partnership no later than the first anniversary of the closing date with the option to defer $250.0 million of the final installment up to 24 months following the closing date. The Partnership’s installment payables are valued net of discount within the total purchase price.

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

10


 

The following table presents the consideration we paid and the fair value of the identified assets received and liabilities assumed at the acquisition date. The purchase price allocation has been prepared on a preliminary basis pending receipt of a final valuation report and is subject to change.

 

 

 

 

Consideration (in millions):

    

 

 

Cash

 

$

805.8

Issuance of common units

 

 

214.9

The Partnership’s total installment payable, net of discount of $79.1 million assuming payments are made on January 7, 2017 and 2018

 

 

420.9

Total consideration

 

$

1,441.6

 

 

 

 

Purchase Price Allocation (in millions):

 

 

 

Assets acquired:

 

 

 

Current assets (including $12.8 million in cash)

 

$

23.0

Property, plant and equipment

 

 

408.5

Intangibles

 

 

1,048.4

Liabilities assumed:

 

 

 

Current liabilities

 

 

(38.3)

Total identifiable net assets

 

$

1,441.6

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

We incurred $3.7 million of direct transaction costs for the nine months ended September 30, 2016. These costs are included in general and administrative costs in the accompanying Condensed Consolidated Statements of Operations.

For the period from January 7, 2016 to September 30, 2016, we recognized $149.5 million of revenues and $27.9 million of net loss related to the assets acquired.

Pro Forma Information

The following unaudited pro forma condensed financial information for the three and nine months ended September 30, 2015 gives effect to the January 2015 LPC acquisition, March 2015 Coronado acquisition, October 2015 Matador acquisition, November 2015 Deadwood acquisition and January 2016 Tall Oak acquisition as if they had occurred on January 1, 2015. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the transactions taken place on the dates indicated and is not intended to be a projection of future results.

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30, 

 

September 30, 

 

 

2015

    

2015

Pro forma total revenues

 

$

1,205.9

 

$

3,556.8

Pro forma net loss

 

$

(775.1)

 

$

(743.6)

Pro forma net loss attributable to EnLink Midstream, LLC

 

$

(199.0)

 

$

(176.1)

Pro forma net loss per common unit:

 

 

 

 

 

 

Basic

 

$

(1.11)

 

$

(0.98)

Diluted

 

$

(1.11)

 

$

(0.98)

 

 

(4) Goodwill and Intangible Assets

Goodwill

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate

11


 

it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value of goodwill to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. During February 2016, we determined that continued further weakness in the overall energy sector driven by low commodity prices together with a further decline in our unit price and the Partnership’s unit price subsequent to year-end caused a change in circumstances warranting an interim impairment test. Based on these triggering events, we performed a goodwill impairment analysis in the first quarter of 2016 on all reporting units.

We and the Partnership perform our goodwill assessments at the reporting unit level for all reporting units. The Partnership uses a discounted cash flow analysis to perform the assessments for the Texas and Crude and Condensate reporting units. We use a market approach to perform the assessment for our Corporate reporting unit. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, control premium and estimated future cash flows including volume and price forecasts and estimated operating and general and administrative costs. In estimating cash flows, the Partnership incorporates current and historical market and financial information, among other factors.

The fair value of goodwill is based on inputs that are not observable in the market and thus represent Level 3 inputs. Using the fair value approaches described above, in step one of the goodwill impairment test, we and the Partnership determined that the estimated fair values of the Partnership’s Texas and Crude and Condensate reporting units and our Corporate reporting unit were less than their respective carrying amounts. At the Partnership’s Texas and Crude and Condensate reporting units, this is primarily related to increases in the discount rate subsequent to year-end. For our Corporate reporting unit, this is due primarily to a further decline in our unit price subsequent to year-end. The second step of the goodwill impairment test at the Partnership 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 Texas, Crude and Condensate, and Corporate reporting units in the amount of $873.3 million was recognized for the three months ended March 31, 2016, which is included in the nine months ended September 30, 2016 impairments line item in the Condensed Consolidated Statements of Operations.

We and the Partnership concluded that the fair value of goodwill of the Oklahoma reporting unit exceeded its carrying value, and the entire amount of goodwill disclosed on the Condensed Consolidated Balance Sheet associated with this remaining reporting unit is recoverable. Therefore, no other goodwill impairment was identified or recorded for this reporting unit as a result of our goodwill impairment analysis.

Our and the Partnership’s respective impairment determinations involved significant assumptions and judgments, as discussed above. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. If actual results are not consistent with our and the Partnership’s assumptions and estimates, or assumptions and estimates change due to new information, we and 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. The estimated fair values of our Corporate reporting unit and the Partnership’s Texas reporting unit may be impacted in the future by a further decline in our unit price or the Partnership’s unit price or a continuing prolonged period of lower commodity prices which may adversely affect the Partnership’s estimate of future cash flows all of which could result in future goodwill impairment charges.

12


 

The table below provides a summary of our change in carrying amount of goodwill, by assigned reporting unit (in millions):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude and 

 

 

 

 

 

 

 

    

Texas

    

Louisiana

    

Oklahoma

    

Condensate

    

Corporate

    

Totals

 

 

(in millions)

Nine Months Ended September 30, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance, beginning of period

 

$

703.5

 

$

 —

 

$

190.3

 

$

93.2

 

$

1,426.9

 

$

2,413.9

Impairment

 

 

(473.1)

 

 

 —

 

 

 —

 

 

(93.2)

 

 

(307.0)

 

 

(873.3)

Acquisition adjustment

 

 

1.6

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

1.6

Balance, end of period

 

$

232.0

 

$

 —

 

$

190.3

 

$

 —

 

$

1,119.9

 

$

1,542.2

Intangible Assets

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

The following table represents the Partnership’s change in carrying value of intangible assets (in millions):

 

 

 

 

 

 

 

 

 

 

 

    

Gross

    

 

 

    

Net

 

 

Carrying

 

Accumulated

 

Carrying

 

 

Amount

 

Amortization

 

Amount

Nine Months Ended September 30, 2016

 

 

 

 

 

 

 

 

 

Customer relationships, beginning of period

 

$

744.5

 

$

(54.6)

 

$

689.9

Acquisitions

 

 

1,048.4

 

 

 —

 

 

1,048.4

Amortization expense

 

 

 —

 

 

(87.4)

 

 

(87.4)

Customer relationships, end of period

 

$

1,792.9

 

$

(142.0)

 

$

1,650.9

The weighted average amortization period for intangible assets is 13.7 years.  Amortization expense for intangibles was approximately $29.9 million and $14.6 million for the three months ended September 30, 2016 and 2015, respectively, and $87.4 million and $44.3 million for the nine months ended September 30, 2016 and 2015, respectively.

The following table summarizes the Partnership’s estimated aggregate amortization expense for the next five years (in millions):

 

 

 

 

2016 (remaining)

 

$

29.4

2017

    

 

117.7

2018

 

 

117.7

2019

 

 

117.7

2020

 

 

117.7

Thereafter

 

 

1,150.7

Total

 

$

1,650.9

 

 

 

(5) Affiliate Transactions

The Partnership engages in various transactions with Devon and other affiliated entities. For the three and nine months ended September 30, 2016 and 2015, Devon was a significant customer to the Partnership. Devon accounted for 18.9% and 19.4% of the Partnership’s revenues for the three and nine months ended September 30, 2016, respectively, and 16.3% and 15.9% for the three and nine months ended September 30, 2015, respectively. The Partnership had an accounts receivable balance related to transactions with Devon of $76.7 million as of September 30, 2016 and $110.8 million as of December 31, 2015. Additionally, the Partnership had an accounts payable balance related to transactions with Devon of $11.2 million as of September 30, 2016 and $14.8 million as of December 31, 2015.  Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with nonaffiliated third parties. The amounts related to affiliate transactions are specified in the accompanying financial statements.

13


 

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

In January 2016, in connection with the Tall Oak acquisition, we acquired a Gas Gathering and Processing Agreement with Devon Energy Production Company, L.P. (“DEPC”) pursuant to which EnLink Oklahoma T.O. provides gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by DEPC. The agreement has a minimum volume commitment that will remain in place during each calendar quarter for the next five years and a remaining overall term of approximately 13 years. Additionally, the agreement provides EnLink Oklahoma T.O. with dedication of all of the natural gas owned or controlled by DEPC and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering land within the acreage dedications, excluding properties previously dedicated to other natural gas gathering systems not owned and operated by DEPC. DEPC is entitled to firm service, meaning a level of gathering and processing service in which DEPC’s reserved capacity may not be interrupted, except due to force majeure, and may not be displaced by another customer or class of service. 

 

(6) Long-Term Debt

As of September 30, 2016 and December 31, 2015, long-term debt consisted of the following (in millions):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30, 2016

 

December 31, 2015

 

    

  

Outstanding Principal

  

Premium (Discount)

  

Long-Term Debt

  

  

Outstanding Principal

  

Premium (Discount)

  

Long-Term Debt

Partnership credit facility, due 2020 (1)

 

$

75.0

$

 —

$

75.0

 

$

414.0

$

 —

$

414.0

Company credit facility, due 2019 (2)

 

 

23.1

 

 —

 

23.1

 

 

 —

 

 —

 

 —

2.70% Senior unsecured notes due 2019

 

 

400.0

 

(0.3)

 

399.7

 

 

400.0

 

(0.4)

 

399.6

7.125% Senior unsecured notes due 2022

 

 

162.5

 

16.7

 

179.2

 

 

162.5

 

18.9

 

181.4

4.40% Senior unsecured notes due 2024

 

 

550.0

 

2.6

 

552.6

 

 

550.0

 

2.9

 

552.9

4.15% Senior unsecured notes due 2025

 

 

750.0

 

(1.1)

 

748.9

 

 

750.0

 

(1.2)

 

748.8

4.85% Senior unsecured notes due 2026

 

 

500.0

 

(0.7)

 

499.3

 

 

 —

 

 —

 

 —

5.60% Senior unsecured notes due 2044

 

 

350.0

 

(0.2)

 

349.8

 

 

350.0

 

(0.2)

 

349.8

5.05% Senior unsecured notes due 2045

 

 

450.0

 

(6.7)

 

443.3

 

 

450.0

 

(6.9)

 

443.1

Other debt

 

 

 —

 

 —

 

 —

 

 

0.2

 

 —

 

0.2

Debt classified as long-term

 

$

3,260.6

$

10.3

$

3,270.9

 

$

3,076.7

$

13.1

$

3,089.8

Debt issuance cost (3)

 

 

 

 

 

 

(25.7)

 

 

 

 

 

 

(23.8)

Long-term debt, net of unamortized issuance cost

 

 

 

 

 

$

3,245.2

 

 

 

 

 

$

3,066.0

(1)

Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 2.2% at September 30, 2016 and 1.8% at December 31, 2015.

(2)

Bears interest based on Prime and/or LIBOR plus an applicable margin. The effective interest rate was 3.0% at September 30, 2016.

(3)

Net of amortization of $8.0 million at September 30, 2016 and $5.1 million at December 31, 2015.

Company Credit Facility

The Company has 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) 88,528,451 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

14


 

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 0.5%, 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.

As of September 30, 2016 there was $23.1 million in outstanding borrowings under the credit facility, leaving approximately $226.9 million available for future borrowing based on the borrowing capacity of $250.0 million. The Company expects to be in compliance with all credit facility covenants for at least the next twelve months.

Partnership Credit Facility

The Partnership has a $1.5 billion unsecured revolving credit facility, which includes a $500.0 million letter of credit subfacility (the “Partnership credit facility”) that matures on March 6, 2020.  Under the Partnership credit facility, 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 $500.0 million and, (2) subject to certain conditions and the consent of the requisite lenders, on two separate occasions extend the maturity date of the 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, and 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, 2016, there were $11.0 million in outstanding letters of credit and $75.0 million in outstanding borrowings under the Partnership’s credit facility, leaving approximately $1.4 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, 2015.  The Partnership expects to be in compliance with all credit facility covenants for at least the next twelve months.

 

Senior Unsecured Notes due 2026

 

On July 14, 2016, the Partnership issued $500.0 million in aggregate principal amount of the Partnership’s 4.850% senior notes due 2026 (the “2026 Notes”) at a price to the public of 99.859% of their face value. The 2026 Notes mature on July 15, 2026. Interest payments on the 2026 Notes are payable on January 15 and July 15 of each year, beginning January 15, 2017. Net proceeds of approximately $495.7 million were used to repay outstanding borrowings under the Partnership’s revolving credit facility and for general partnership purposes.

 

15


 

(7) Income Taxes

Income taxes included in the condensed consolidated financial statements were as follows for the periods presented:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30, 

 

September 30, 

 

    

2016

    

2015

    

2016

    

2015

 

 

(in millions)

 

(in millions)

ENLC income tax expense

 

$

7.6

 

$

0.2

 

$

6.0

 

$

21.1

Total income tax expense

 

$

7.6

 

$

0.2

 

$

6.0

 

$

21.1

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30, 

 

September 30, 

 

    

2016

    

2015

    

2016

    

2015

 

 

(in millions)

 

(in millions)

Tax expense (benefit) at statutory federal rate (35%)

 

$

2.0

 

$

(67.6)

 

$

(158.0)

 

$

(49.5)

State income taxes expense (benefit), net of federal tax benefit

 

 

3.1

 

 

(4.8)

 

 

(11.8)

 

 

(3.5)

Income tax expense from partnership

 

 

2.6

 

 

0.6

 

 

1.3

 

 

1.7

Non-deductible expense related to asset impairment

 

 

(0.1)

 

 

72.3

 

 

173.8

 

 

72.3

Other

 

 

 —

 

 

(0.3)

 

 

0.7

 

 

0.1

Total income tax expense

 

$

7.6

 

$

0.2

 

$

6.0

 

$

21.1

 

 

(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, 2016, the Partnership sold an aggregate of 6.7 million common units under the BMO EDA, generating proceeds of approximately $110.6 million (net of approximately $1.1 million of commissions). The Partnership used the net proceeds for general partnership purposes. As of September 30, 2016, approximately $205.3 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. The Class C Common Units were substantially similar in all respects to the Partnership’s common units, except that distributions paid on the Class C Common Units could be paid in cash or in additional Class C Common Units issued in kind, as determined by the General Partner in its sole discretion. Distributions on the Class C Common Units for the three months ended December 31, 2015 and March 31, 2016 were paid-in-kind through the issuance of 209,044 and 233,107 Class C Common Units on February 11, 2016 and May 12, 2016, respectively. All of the outstanding Class C Common Units converted into common units on a one-for-one basis on May 13, 2016.

(c)Preferred Units

In January 2016, the Partnership issued an aggregate of 50,000,000 Series B Cumulative Convertible Preferred Units (“Preferred Units”) representing the Partnership’s limited partner interests to Enfield Holdings, L.P. (“Enfield”) in a private placement for a cash purchase price of $15.00 per Preferred Unit (the “Issue Price”), resulting in net proceeds of approximately $724.1 million after fees and deductions. Proceeds from the private placement were used to partially

16


 

fund the Partnership’s portion of the purchase price payable in connection with the Tall Oak acquisition. Affiliates of the Goldman Sachs Group, Inc. and affiliates of TPG Global, LLC own interests in the general partner of Enfield. The Preferred Units are convertible into the Partnership’s common units on a one-for-one basis, subject to certain adjustments, at any time after the record date for the quarter ending June 30, 2017 (a) in full, at the Partnership’s option, if the volume weighted average price of a common unit over the 30-trading day period ending two trading days prior to the conversion date (the “Conversion VWAP”) is greater than 150% of the Issue Price or (b) in full or in part, at Enfield’s option. In addition, upon certain events involving a change of control of the General Partner or our managing member, all of the Preferred Units will automatically convert into a number of common units equal to the greater of (i) the number of common units into which the Preferred Units would then convert and (ii) the number of Preferred Units to be converted multiplied by an amount equal to (x) 140% of the Issue Price divided by (y) the Conversion VWAP.

As a holder of Preferred Units, Enfield is entitled to receive a quarterly distribution, subject to certain adjustments, equal to (x) during the quarter ending March 31, 2016 through the quarter ending June 30, 2017, an annual rate of 8.5% on the Issue Price payable in-kind in the form of additional Preferred Units and (y) thereafter, an annual rate of 7.5% on the Issue Price payable in cash (the “Cash Distribution Component”) plus an in-kind distribution equal to the greater of (A) an annual rate of 1.0% of the Issue Price and (B) an amount equal to (i) the excess, if any, of the distribution that would have been payable had the Preferred Units converted into common units over the Cash Distribution Component, divided by (ii) the Issue Price. Distributions on the Preferred Units for the three months ended March 31, 2016 and June 30, 2016, were paid-in kind through the issuance of 992,445 and 1,083,589 Preferred Units on May 12, 2016 and August 11, 2016, respectively. A distribution on the Preferred Units was declared for the three months ended September 30, 2016 which will result in the issuance of 1,106,616 additional Preferred Units on November 11, 2016.

(d)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 Preferred 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, 2016 is provided below:

 

 

 

 

 

 

Declaration period

    

Distribution/unit

    

Date paid/payable

2016

 

 

 

 

 

Fourth Quarter of 2015

 

$

0.39

 

February 11, 2016

First Quarter of 2016

 

$

0.39

 

May 12, 2016

Second Quarter of 2016

 

$

0.39

 

August 11, 2016

Third Quarter of 2016

 

$

0.39

 

November 11, 2016

(e)Allocation of Partnership Income

Net income is allocated to the General Partner in an amount equal to its incentive distributions as described in (d) above. 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

17


 

allocated to the General Partner is as follows for the three and nine months ended September 30, 2016 and 2015 (in millions):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30, 

 

September 30, 

 

    

2016

    

2015

    

2016

    

2015

Income allocation for incentive distributions

 

$

14.4

 

$

13.6

 

$

42.4

 

$

33.7

Unit-based compensation attributable to ENLC’s restricted units

 

 

(3.6)

 

 

(3.7)

 

 

(11.2)

 

 

(14.6)

General Partner share of net income (loss)

 

 

 —

 

 

(3.6)

 

 

(2.4)

 

 

(3.3)

General Partner interest in drop down transactions

 

 

 —

 

 

 —

 

 

 —

 

 

34.4

General Partner interest in net income

 

$

10.8

 

$

6.3

 

$

28.8

 

$

50.2

 

 

(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 (loss) attributable to the drop down interests acquired during 2015 from Devon for periods prior to acquisition is not allocated for purposes of calculating net income (loss) per common unit as they were fully assigned to the general partner interest. The following table reflects the computation of basic and diluted earnings per unit for the three and nine months ended September 30, 2016 and 2015 (in millions, except per unit amounts):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30, 

 

September 30, 

 

    

2016

    

2015

    

2016

    

2015

EnLink Midstream, LLC interest in net income (loss)

 

$

0.7

 

$

(193.4)

 

$

(456.1)

 

$

(162.6)

Distributed earnings allocated to:

 

 

 

 

 

 

 

 

 

 

 

 

Common units (1) (2)

 

$

45.9

 

$

41.9

 

$

137.4

 

$

123.2

Unvested restricted units (1) (2)

 

 

0.6

 

 

0.3

 

 

1.6

 

 

0.9

Total distributed earnings