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EX-32.1 - EX-32.1 - EnLink Midstream Partners, LPc060-20160930ex321deb6ea.htm
EX-31.2 - EX-31.2 - EnLink Midstream Partners, LPc060-20160930ex312231d4f.htm
EX-31.1 - EX-31.1 - EnLink Midstream Partners, LPc060-20160930ex3110b1a6b.htm

 

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: 001-36340

 

ENLINK MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)

 

Delaware

16-1616605

(State of organization)

(I.R.S. Employer Identification No.)

 

 

2501 CEDAR SPRINGS RD.

 

DALLAS, TEXAS

75201

(Address of principal executive offices)

(Zip Code)

 

(214) 953-9500

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ 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 339,896,417 common units outstanding.

 

 

 

 


 

TABLE OF CONTENTS

 

 

 

 

 

 

Item

    

Description

    

Page

 

 

 

 

 

 

 

PART I—FINANCIAL INFORMATION

 

 

 

 

 

 

 

1. 

 

Financial Statements

 

 

 

 

 

 

2. 

 

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

 

31 

 

 

 

 

 

3. 

 

Quantitative and Qualitative Disclosures About Market Risk

 

53 

 

 

 

 

 

4. 

 

Controls and Procedures

 

55 

 

 

 

 

 

 

 

PART II—OTHER INFORMATION

 

 

 

 

 

 

 

1. 

 

Legal Proceedings

 

57 

 

 

 

 

 

1A. 

 

Risk Factors

 

57 

 

 

 

 

 

6. 

 

Exhibits

 

58 

 

 

 

2


 

ENLINK MIDSTREAM PARTNERS, LP

Condensed Consolidated Balance Sheets

 

 

 

 

 

 

 

 

 

 

  

September 30, 2016

  

December 31, 2015

 

 

 

(Unaudited)

 

 

 

 

 

 

(In millions, except unit data)

 

ASSETS

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

60.0

 

$

5.9

 

Accounts receivable:

 

 

 

 

 

 

 

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

 

 

47.8

 

 

37.5

 

Accrued revenue and other

 

 

311.9

 

 

268.7

 

Related party

 

 

76.7

 

 

111.1

 

Fair value of derivative assets

 

 

4.3

 

 

16.8

 

Natural gas and NGLs inventory, prepaid expenses and other

 

 

38.1

 

 

32.1

 

Total current assets

 

 

538.8

 

 

472.1

 

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

 

 

422.3

 

 

987.0

 

Investment in unconsolidated affiliates

 

 

266.4

 

 

274.3

 

Other assets, net

 

 

2.4

 

 

2.7

 

Total assets

 

$

9,075.9

 

$

8,092.8

 

 

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS’ 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

 

 

196.2

 

 

174.4

 

Total current liabilities

 

 

762.8

 

 

432.0

 

Long-term debt

 

 

3,222.8

 

 

3,066.8

 

Fair value of derivative liabilities

 

 

 —

 

 

0.1

 

Asset retirement obligations

 

 

13.4

 

 

12.9

 

Installment payable, net of discount of $32.8

 

 

217.2

 

 

 —

 

Other long-term liabilities

 

 

49.6

 

 

65.9

 

Deferred tax liability

 

 

73.2

 

 

73.6

 

 

 

 

 

 

 

 

 

Redeemable non-controlling interest

 

 

6.2

 

 

7.0

 

 

 

 

 

 

 

 

 

Partners’ equity:

 

 

 

 

 

 

 

Common unitholders (339,531,171 and 325,090,624 units issued and outstanding at September 30, 2016 and December 31, 2015, respectively

 

 

3,325.7

 

 

4,055.8

 

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

 

 

 —

 

 

149.4

 

Preferred unitholders (52,076,035 units issued and outstanding at September 30, 2016)

 

 

773.3

 

 

 —

 

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

 

 

209.7

 

 

213.4

 

Non-controlling interest

 

 

422.0

 

 

15.9

 

Total partners’ equity

 

 

4,730.7

 

 

4,434.5

 

Commitments and contingencies (Note 13)

 

 

 

 

 

 

 

Total liabilities and partners’ equity

 

$

9,075.9

 

$

8,092.8

 

 

See accompanying notes to condensed consolidated financial statements.

 

3


 

ENLINK MIDSTREAM PARTNERS, LP

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 data)

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)

 

 

28.3

 

 

33.5

 

 

90.6

 

 

102.3

(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

 

 

566.3

 

 

799.2

Total operating costs and expenses

 

 

1,037.7

 

 

1,901.1

 

 

3,430.1

 

 

3,993.8

Operating income (loss)

 

 

66.9

 

 

(730.5)

 

 

(402.6)

 

 

(608.2)

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net of interest income

 

 

(48.0)

 

 

(30.2)

 

 

(137.9)

 

 

(71.5)

Income (loss) from unconsolidated affiliates

 

 

1.1

 

 

6.4

 

 

(0.5)

 

 

16.1

Other income

 

 

0.1

 

 

0.1

 

 

0.1

 

 

0.7

Total other expense

 

 

(46.8)

 

 

(23.7)

 

 

(138.3)

 

 

(54.7)

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

 

 

20.1

 

 

(754.2)

 

 

(540.9)

 

 

(662.9)

Income tax provision

 

 

(2.6)

 

 

(1.0)

 

 

(1.3)

 

 

(2.9)

Net income (loss)

 

 

17.5

 

 

(755.2)

 

 

(542.2)

 

 

(665.8)

Net loss attributable to the non-controlling interest

 

 

(1.3)

 

 

(0.3)

 

 

(5.6)

 

 

(0.3)

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

 

$

18.8

 

$

(754.9)

 

$

(536.6)

 

$

(665.5)

General partner interest in net income

 

$

10.8

 

$

6.3

 

$

28.8

 

$

50.2

Limited partners’ interest in net loss attributable to EnLink Midstream Partners, LP

 

$

(11.4)

 

$

(745.2)

 

$

(602.1)

 

$

(700.5)

Class C partners’ interest in net loss attributable to EnLink Midstream Partners, LP

 

$

 —

 

$

(16.0)

 

$

(12.5)

 

$

(15.2)

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

 

$

19.4

 

$

 —

 

$

49.2

 

$

 —

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

 

 

 

 

 

 

 

 

 

 

 

 

Basic common unit

 

$

(0.03)

 

$

(2.32)

 

$

(1.82)

 

$

(2.38)

Diluted common unit

 

$

(0.03)

 

$

(2.32)

 

$

(1.82)

 

$

(2.38)

(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 and $0.2 million for the three and nine months ended September 30, 2015, respectively.

 

 

See accompanying notes to condensed consolidated financial statements.

4


 

ENLINK MIDSTREAM PARTNERS, LP

Consolidated Statement of Changes in Partners’ Equity

Nine Months Ended September 30, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Redeemable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

controlling

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General

 

Non-

 

 

 

 

interest

 

 

 

 

 

 

 

Class C

 

 

 

Partner

 

Controlling

 

 

 

 

(Temporary

 

 

Common Units

 

Common Units

 

Preferred Units

 

Interest

 

Interest

 

 

 

 

Equity)

 

    

$

    

Units

    

$

    

Units

    

$

    

Units

    

$

    

Units

    

$

    

Total

    

$

 

 

(Unaudited)

 

 

(In millions)

Balance, December 31, 2015

 

$

4,055.8

 

325.2

 

$

149.4

 

7.1

 

$

 —

 

 —

 

$

213.4

 

1.6

 

$

15.9

 

$

4,434.5

 

$

7.0

Issuance of common units

 

 

110.6

 

6.7

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

110.6

 

 

 —

Issuance of Preferred Units

 

 

 —

 

 —

 

 

 —

 

 —

 

 

724.1

 

50.0

 

 

 —

 

 —

 

 

 —

 

 

724.1

 

 

 —

Contribution from ENLC

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

237.1

 

 

237.1

 

 

 —

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

 

 

(1.2)

 

0.2

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

(1.2)

 

 

 —

Unit-based compensation

 

 

11.3

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

11.2

 

 —

 

 

 —

 

 

22.5

 

 

 —

Contribution from Devon

 

 

1.4

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

1.4

 

 

 —

Distributions

 

 

(387.0)

 

 —

 

 

 —

 

0.4

 

 

 —

 

2.1

 

 

(43.7)

 

 —

 

 

 —

 

 

(430.7)

 

 

 —

Conversion of Class C Common Units to common units

 

 

136.9

 

7.5

 

 

(136.9)

 

(7.5)

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

 —

Non-controlling interest contributions

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

179.4

 

 

179.4

 

 

 —

Distributions to non-controlling interest

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

(4.8)

 

 

(4.8)

 

 

 —

Distributions to redeemable non-controlling interest

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

(0.8)

Net income (loss)

 

 

(602.1)

 

 —

 

 

(12.5)

 

 —

 

 

49.2

 

 —

 

 

28.8

 

 —

 

 

(5.6)

 

 

(542.2)

 

 

 —

Balance, September 30, 2016

 

$

3,325.7

 

339.6

 

$

 —

 

 —

 

$

773.3

 

52.1

 

$

209.7

 

1.6

 

$

422.0

 

$

4,730.7

 

$

6.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

5


 

ENLINK MIDSTREAM PARTNERS, LP

Consolidated Statements of Cash Flows

 

 

 

 

 

 

 

 

 

Nine Months Ended September 30, 

 

    

2016

    

2015

 

 

(Unaudited)

 

 

(In millions)

Cash flows from operating activities:

 

 

 

 

 

 

Net loss

 

$

(542.2)

 

$

(665.8)

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

 

 

 

 

 

 

Impairments

 

 

566.3

 

 

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

Non-cash unit-based compensation

 

 

22.5

 

 

28.6

Deferred tax benefit

 

 

(0.3)

 

 

 —

(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

 

 

2.6

 

 

2.2

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

 

 

(17.6)

 

 

124.3

Natural gas and NGLs inventory, prepaid expenses and other

 

 

3.6

 

 

(18.4)

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

 

 

49.3

 

 

(58.0)

Net cash provided by operating activities

 

 

509.2

 

 

508.0

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

 

 

 

 

 

 

Additions to property and equipment

 

 

(423.7)

 

 

(450.3)

Proceeds from insurance settlement

 

 

0.3

 

 

 —

Acquisition of business, net of cash acquired

 

 

(769.3)

 

 

(330.6)

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

 

 

(1,181.4)

 

 

(774.3)

Cash flows from financing activities:

 

 

 

 

 

 

Proceeds from borrowings

 

 

1,629.3

 

 

2,604.4

Payments on borrowings

 

 

(1,469.2)

 

 

(1,773.2)

Payments on capital lease obligations

 

 

(3.2)

 

 

(2.5)

Decrease in drafts payable

 

 

 —

 

 

(12.6)

Debt financing costs

 

 

(4.6)

 

 

(9.5)

Conversion of restricted units, net of units withheld for taxes

 

 

(1.2)

 

 

(2.5)

Proceeds from issuance of common units

 

 

110.6

 

 

12.9

Proceeds from issuance of Preferred Units

 

 

724.1

 

 

 —

Distributions to non-controlling partners

 

 

(5.6)

 

 

(66.5)

Contributions by non-controlling partners (including contributions from affiliates of $27.9 million)

 

 

179.4

 

 

12.2

Distribution to partners

 

 

(430.7)

 

 

(338.9)

Mandatorily redeemable non-controlling interest

 

 

(4.0)

 

 

 —

Contribution from Devon

 

 

1.4

 

 

28.8

Distributions to Devon for net assets acquired

 

 

 —

 

 

(171.0)

Net cash provided by financing activities

 

 

726.3

 

 

281.6

Net increase in cash and cash equivalents

 

 

54.1

 

 

15.3

Cash and cash equivalents, beginning of period

 

 

5.9

 

 

9.6

Cash and cash equivalents, end of period

 

$

60.0

 

$

24.9

Cash paid for interest

 

$

70.4

 

$

45.5

Cash paid for income taxes

 

$

2.5

 

$

0.4

 

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

 

6


 

ENLINK MIDSTREAM PARTNERS, LP

Notes to Condensed Consolidated Financial Statements

September 30, 2016

(Unaudited)

 

(1) General

 

In this report, the term “Partnership,” as well as the terms “our,” “we,” “us” and “its,” are sometimes used as abbreviated references to EnLink Midstream Partners, LP itself or EnLink Midstream Partners, LP together with its consolidated subsidiaries, including the Operating Partnership (as defined below) and EnLink Oklahoma Gas Processing, LP (“EnLink Oklahoma T.O.”). EnLink Oklahoma T.O. is sometimes used to refer to EnLink Oklahoma Gas Processing, LP itself or EnLink Oklahoma Gas Processing, LP together with its consolidated subsidiaries.

 

(a)  Organization of Business

 

EnLink Midstream Partners, LP is a publicly traded Delaware limited partnership formed in 2002. Our common units are traded on the New York Stock Exchange under the symbol “ENLK.” Our business activities are conducted through our subsidiary, EnLink Midstream Operating, LP, a Delaware limited partnership (the “Operating Partnership”), and the subsidiaries of the Operating Partnership.

 

EnLink Midstream GP, LLC, a Delaware limited liability company, is our general partner. Our general partner manages our operations and activities. Our general partner is an indirect wholly-owned subsidiary of EnLink Midstream, LLC (“ENLC”). ENLC’s units are traded on the New York Stock Exchange under the symbol “ENLC.” Devon Energy Corporation (“Devon”) owns ENLC’s managing member and common units which represent approximately 64% of the outstanding limited liability company interests in ENLC.

 

Effective as of January 7, 2016, the Operating Partnership acquired 84% of the outstanding equity interests in EnLink Oklahoma T.O., and ENLC acquired the remaining 16% equity interests in EnLink Oklahoma T.O. Since we control EnLink Oklahoma T.O., we reflect our ownership in EnLink Oklahoma T.O. on a consolidated basis and ENLC’s ownership is reflected as a non-controlling interest in the respective condensed consolidated financial statements and related disclosures.

 

On August 1, 2016, we formed a joint venture (the “Delaware Basin JV”) with an affiliate of NGP Natural Resources XI, L.P. (“NGP”) to operate and expand our natural gas, natural gas liquids (“NGLs”) and crude oil midstream assets in the liquids-rich Delaware Basin.  The Delaware Basin JV is owned 50.1 percent by us and 49.9 percent by NGP. Since we control the Delaware Basin JV, we reflect our ownership in the Delaware Basin JV on a consolidated basis, and NGP’s ownership is reflected as a non-controlling interest in the respective condensed consolidated financial statements and related disclosures.

 

(b)  Nature of Business

 

We primarily focus on providing midstream energy services, including gathering, transmission, processing, fractionation, brine services and marketing to producers of natural gas, natural gas liquids, crude oil and condensate. We connect the wells of producers in our market areas to our gathering systems, process natural gas to remove NGLs, fractionate NGLs into purity products and market those products for a fee, transport natural gas and ultimately provide natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply sources and sell that natural gas to utilities, industrial consumers, other marketers and pipelines. We operate processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee-based arrangements. We provide a variety of crude oil and condensate services, which include crude oil and condensate gathering and transmission via pipelines, barges, rail and trucks, condensate stabilization and brine disposal. We also have crude oil and condensate terminal facilities that provide access for crude oil and condensate producers to premium markets. Our gas gathering systems consist of networks of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Our transmission pipelines primarily receive natural gas from our gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. We also have transmission lines that transport NGLs from east Texas and from our south Louisiana processing plants to our fractionators in south Louisiana. Our crude oil and condensate gathering and transmission systems consist of trucking facilities, pipelines, rail and barge facilities that, in exchange for a

7


 

fee, transport crude oil from a producer site to an end user. Our processing plants remove NGLs and CO2 from a natural gas stream, and our fractionators separate the NGLs into separate NGL products, including ethane, propane, iso-butane, normal butane and natural gasoline.

 

(2) Significant Accounting Policies

 

(a)  Basis of Presentation

 

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles in the United States of America (“GAAP”) for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year.  All significant intercompany balances and transactions have been eliminated in consolidation.

 

During the first half of 2015, we acquired assets from ENLC and Devon through drop down transactions. Due to ENLC’s control of us through its ownership and control of our general partner and Devon’s control of us through its ownership of the managing member of ENLC, each acquisition from ENLC and Devon was considered a transfer of net assets between entities under common control. As such, we were required to recast our historical financial statements to include the activities of such assets from the date that these entities were under common control.  The condensed consolidated financial statements for periods prior to our acquisition of the assets from ENLC and Devon have been prepared from ENLC’s and Devon’s historical cost-basis accounts for the acquired assets and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the acquired assets during the periods reported. Net income attributable to the assets acquired from ENLC and Devon for periods prior to our acquisition is allocated to our general partner.

 

(b)  Adopted Accounting Standards

 

In January 2016, we adopted Accounting Standards Update (“ASU”) 2015-03, Interest - Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability and requires retrospective application.  The application of this new accounting guidance resulted in the reclassification of $23.0 million of debt issuance costs from “Other Assets, Net” to “Long-term debt” in our accompanying Condensed Consolidated Balance Sheet as of December 31, 2015.

 

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

 

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

 

In January 2016, we adopted ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The update provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The update is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This update had no impact on our condensed consolidated financial statements or related disclosures.

 

In January 2016, we adopted ASU 2015-06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a Consensus of the FASB Emerging Issues Task Force) (“ASU 2015-06”), which requires a master limited partnership (MLP) to allocate earnings (losses) of a transferred business entirely to the general partner when computing earnings per unit (EPU) for periods before the dropdown transaction occurred. The EPU that the limited partners previously reported would not change as a result of the dropdown transaction. ASU 2015-06 also requires an MLP to disclose the effects of the dropdown transaction on EPU for the periods before and after the dropdown

8


 

transaction occurred. ASU 2015-06 is effective for the fiscal years beginning after December 15, 2015, and interim periods within those annual periods. ASU 2015-06 requires retrospective application and early adoption is permitted. The update is effective for us beginning on January 1, 2016 and had no impact on our condensed consolidated financial statements or related disclosures.

 

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 2016-15 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 Accounting Standards Codification (“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 we expect 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 our 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.

 

9


 

(3) Acquisitions

 

Matador Acquisition

 

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

 

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

 

 

 

 

 

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

 

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

 

Deadwood Acquisition

 

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

 

Tall Oak Acquisition

 

On January 7, 2016, we and ENLC acquired an 84% and 16% voting interest, respectively, in EnLink Oklahoma T.O. for approximately $1.4 billion. The first installment of $1.02 billion for the acquisition was paid at closing. The final installment of $500.0 million is due by us no later than the first anniversary of the closing date with the option to defer $250.0 million of the final installment up to 24 months following the closing date. The installment payables are valued net of discount within the total purchase price.

 

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

 

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

 

$

783.6

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

 

 

420.9

Contribution from ENLC

 

 

237.1

Total consideration

 

$

1,441.6

 

 

 

 

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

 

 

(in millions)

Pro forma total revenues

 

$

1,205.9

 

$

3,556.7

Pro forma net loss

 

$

(775.9)

 

$

(727.8)

Pro forma net loss attributable to EnLink Midstream Partners, LP

 

$

(772.7)

 

$

(718.1)

Pro forma net loss per common unit:

 

 

 

 

 

 

Basic

 

$

(2.34)

 

$

(2.49)

Diluted

 

$

(2.34)

 

$

(2.49)

 

 

(4) Goodwill and Intangible Assets

 

Goodwill

 

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of October 31, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. We first assess qualitative

11


 

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

 

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

 

The fair value of goodwill is based on inputs that are not observable in the market and thus represent Level 3 inputs. Using the fair value approaches described above, in step one of the goodwill impairment test, we determined that the estimated fair values of our Texas and Crude and Condensate reporting units were less than their respective carrying amounts, primarily related to increases in our discount rate subsequent to year-end. The second step of the goodwill impairment test measures the amount of impairment loss and involves allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. Through the analysis, a goodwill impairment loss for our Texas and Crude and Condensate reporting units in the amount of $566.3 million was recognized for the three months ended March 31, 2016, which is included in our nine months ended September 30, 2016 impairments line item in the Condensed Consolidated Statements of Operations.

 

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

 

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

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

 

 

    

 

 

    

 

 

    

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

 

$

 

$

987.0

Impairment

 

 

(473.1)

 

 

 —

 

 

 

 

(93.2)

 

 

 

 

(566.3)

Acquisition adjustment

 

 

1.6

 

 

 

 

 

 

 —

 

 

 

 

1.6

Balance, end of period

 

$

232.0

 

$

 —

 

$

190.3

 

$

 —

 

$

 —

 

$

422.3

 

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.

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The following table represents our 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 our 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

 

We engage 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 us. Devon accounted for 18.9% and 19.4% of our 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. We 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, we 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.

 

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. 

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(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

 

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