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smlp:ReverseUnitSplitMember 2020-11-09

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

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: 001-35666

Summit Midstream Partners, LP

(Exact name of registrant as specified in its charter)

 

Delaware

(State or other jurisdiction of

incorporation or organization)

 

45-5200503

(I.R.S. Employer

Identification No.)

 

 

 

910 Louisiana Street, Suite 4200

Houston, TX

(Address of principal executive offices)

 

77002

(Zip Code)

 

(832) 413-4770

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Units

SMLP

New York Stock Exchange

 

Indicate by check mark whether the 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 every Interactive Data File required to be submitted 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 such files).

Yes

No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

 

Accelerated filer

Non-accelerated filer

 

Smaller reporting company

Emerging growth company

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes     No

 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

 

Class

 

As of October 30, 2020

Common Units

 

56,624,887 units

 

 

 


 

TABLE OF CONTENTS

 

COMMONLY USED OR DEFINED TERMS

2

 

 

 

PART I

FINANCIAL INFORMATION

 

Item 1.

Financial Statements.

 

 

Unaudited Condensed Consolidated Balance Sheets.

4

 

Unaudited Condensed Consolidated Statements of Operations.

5

 

Unaudited Condensed Consolidated Statements of Partners' Capital.

6

 

Unaudited Condensed Consolidated Statements of Cash Flows.

8

 

Notes to Unaudited Condensed Consolidated Financial Statements.

9

Item 2.

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

25

Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

51

Item 4.

Controls and Procedures.

52

 

 

 

PART II

OTHER INFORMATION

53

Item 1.

Legal Proceedings.

53

Item 1A.

Risk Factors.

53

Item 5.

Other Information.

55

Item 6.

Exhibits.

56

 

 

 

SIGNATURES

57

 

1


 

COMMONLY USED OR DEFINED TERMS

2016 Drop Down

the Partnership's March 3, 2016 acquisition from SMP Holdings of substantially all

    of (i) the issued and outstanding membership interests in Summit Utica,

    Meadowlark Midstream and Tioga Midstream and (ii) SMP Holdings’ 40%

    ownership interest in Ohio Gathering

2022 Senior Notes

Summit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August

    2022

2025 Senior Notes

Summit Holdings' and Finance Corp.’s 5.75% senior unsecured notes due April

    2025

associated natural gas

a form of natural gas which is found with deposits of petroleum, either dissolved

    in the crude oil or as a free gas cap above the crude oil in the reservoir

ASU

Accounting Standards Update

Bbl

one barrel; used for crude oil and produced water and equivalent to 42 U.S. gallons

Bcf

one billion cubic feet

Bison Midstream

Bison Midstream, LLC

Board of Directors

the board of directors of our General Partner

condensate

a natural gas liquid with a low vapor pressure, mainly composed of propane, butane,

    pentane and heavier hydrocarbon fractions

Deferred Purchase Price

    Obligation

the deferred payment liability recognized in connection with the 2016 Drop Down, as

    subsequently amended, also known as the DPPO

DFW Midstream

DFW Midstream Services, LLC

DJ Basin

Denver-Julesburg Basin

Double E

Double E Pipeline, LLC

Double E Project

the development and construction of a long-haul natural gas pipeline with an

    initial throughput capacity of 1.35 billion cubic feet per day that will provide

    transportation service from multiple receipt points in the Delaware Basin

    to various delivery points in and around the Waha Hub in Texas

dry gas

natural gas primarily composed of methane where heavy hydrocarbons and water

    either do not exist or have been removed through processing or treating

Energy Capital Partners

Energy Capital Partners II, LLC and its parallel and co-investment funds

Epping

Epping Transmission Company, LLC

EPU

earnings or loss per unit

FASB

Financial Accounting Standards Board

Finance Corp.

Summit Midstream Finance Corp.

GAAP

accounting principles generally accepted in the United States of America

General Partner

Summit Midstream GP, LLC

GP

general partner

Grand River

Grand River Gathering, LLC

Guarantor Subsidiaries

Bison Midstream and its subsidiaries, Grand River and its subsidiaries, DFW

    Midstream, Summit Marketing, Summit Permian, Permian Finance, OpCo,

    Summit Utica, Meadowlark Midstream, Summit Permian II and Mountaineer

    Midstream

LIBOR

London Interbank Offered Rate

Mbbl

one thousand barrels

Mbbl/d

one thousand barrels per day

Mcf

one thousand cubic feet

Meadowlark Midstream

Meadowlark Midstream Company, LLC

MMcf

one million cubic feet

MMcf/d

one million cubic feet per day

Mountaineer Midstream

Mountaineer Midstream Company, LLC

MVC

minimum volume commitment

NGLs

natural gas liquids; the combination of ethane, propane, normal butane,

    iso-butane and natural gasolines that when removed from unprocessed

    natural gas streams become liquid under various levels of higher

    pressure and lower temperature

Niobrara G&P

Niobrara Gathering and Processing system

OCC

Ohio Condensate Company, L.L.C.

2


 

OGC

Ohio Gathering Company, L.L.C.

Ohio Gathering

Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C.

OpCo

Summit Midstream OpCo, LP

play

a proven geological formation that contains commercial amounts of hydrocarbons

Permian Finance

Summit Midstream Permian Finance, LLC

Permian Holdco

Summit Permian Transmission Holdco, LLC

Polar and Divide

the Polar and Divide system; collectively Polar Midstream and Epping

Polar Midstream

Polar Midstream, LLC

produced water

water from underground geologic formations that is a by-product of natural gas and

    crude oil production

Red Rock Gathering

Red Rock Gathering Company, LLC

Revolving Credit Facility

the Third Amended and Restated Credit Agreement dated as of May 26, 2017, as

    amended by the First Amendment to Third Amended and Restated Credit

    Agreement dated as of September 22, 2017, the Second Amendment to Third

    Amended and Restated Credit Agreement dated as of June 26, 2019 and

    the Third Amendment to Third Amended and Restated Credit Agreement

    dated as of December 24, 2019

SEC

Securities and Exchange Commission

segment adjusted

    EBITDA

total revenues less total costs and expenses; plus (i) other income excluding interest

    income, (ii) our proportional adjusted EBITDA for equity method investees, (iii)

    depreciation and amortization, (iv) adjustments related to MVC shortfall

    payments, (v) adjustments related to capital reimbursement activity, (vi) unit-

    based and noncash compensation, (vii) impairments and (viii) other noncash

    expenses or losses, less other noncash income or gains

Senior Notes

The 2022 Senior Notes and the 2025 Senior Notes, collectively

Series A Preferred Units

Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

shortfall payment

the payment received from a counterparty when its volume throughput does not

    meet its MVC for the applicable period

SMLP

Summit Midstream Partners, LP

SMLP Holdings

SMLP Holdings, LLC

SMLP LTIP

SMLP Long-Term Incentive Plan

SMP Holdings

Summit Midstream Partners Holdings, LLC, also known as SMPH

SMPH Term Loan

the Term Loan Agreement, dated as of March 21, 2017, among SMP Holdings,

    as borrower, the lenders party thereto and Credit Suisse AG, Cayman Islands

    Branch, as Administrative Agent and Collateral Agent

Subsidiary Series A

    Preferred Units

Series A Fixed Rate Cumulative Redeemable Preferred Units issued by Permian

    Holdco

Summit Holdings

Summit Midstream Holdings, LLC

Summit Investments

Summit Midstream Partners, LLC

Summit Marketing

Summit Midstream Marketing, LLC

Summit Permian

Summit Midstream Permian, LLC

Summit Permian II

Summit Midstream Permian II, LLC

Summit Permian

    Transmission

Summit Permian Transmission, LLC

Summit Utica

Summit Midstream Utica, LLC

the Company

Summit Midstream Partners, LLC and its subsidiaries

the Partnership

Summit Midstream Partners, LP and its subsidiaries

the Partnership

    Agreement

the Fourth Amended and Restated Agreement of Limited Partnership of the

    Partnership dated May 28, 2020

throughput volume

the volume of natural gas, crude oil or produced water gathered, transported or

    passing through a pipeline, plant or other facility during a particular period;

    also referred to as volume throughput

Tioga Midstream

Tioga Midstream, LLC

unconventional resource

    basin

a basin where natural gas or crude oil production is developed from unconventional

    sources that require hydraulic fracturing as part of the completion process, for

    instance, natural gas produced from shale formations and coalbeds; also

    referred to as an unconventional resource play

wellhead

the equipment at the surface of a well, used to control the well's pressure; also, the

    point at which the hydrocarbons and water exit the ground

 

3


 

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

September 30,

 

 

December 31,

 

 

 

2020

 

 

2019

 

 

 

(In thousands, except unit amounts)

 

ASSETS

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

50,272

 

 

$

9,530

 

Restricted cash

 

 

24

 

 

 

27,392

 

Accounts receivable, net

 

 

76,497

 

 

 

97,418

 

Other current assets

 

 

4,559

 

 

 

5,521

 

Total current assets

 

 

131,352

 

 

 

139,861

 

Property, plant and equipment, net

 

 

1,840,284

 

 

 

1,882,489

 

Intangible assets, net

 

 

207,766

 

 

 

232,278

 

Investment in equity method investees

 

 

389,088

 

 

 

309,728

 

Other noncurrent assets

 

 

4,989

 

 

 

9,742

 

TOTAL ASSETS

 

$

2,573,479

 

 

$

2,574,098

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND CAPITAL

 

 

 

 

 

 

 

 

Trade accounts payable

 

$

16,205

 

 

$

24,415

 

Accrued expenses

 

 

11,353

 

 

 

11,339

 

Deferred revenue

 

 

17,827

 

 

 

13,493

 

Ad valorem taxes payable

 

 

6,931

 

 

 

8,477

 

Accrued interest

 

 

12,092

 

 

 

12,346

 

Accrued environmental remediation

 

 

1,553

 

 

 

1,725

 

Other current liabilities

 

 

10,747

 

 

 

12,206

 

Term loan (See TL Restructuring discussion in Note 8)

 

 

155,200

 

 

 

5,546

 

Total current liabilities

 

 

231,908

 

 

 

89,547

 

Long-term debt

 

 

1,390,842

 

 

 

1,622,279

 

Noncurrent deferred revenue

 

 

41,755

 

 

 

38,709

 

Noncurrent accrued environmental remediation

 

 

2,003

 

 

 

2,926

 

Other noncurrent liabilities

 

 

4,536

 

 

 

7,951

 

Total liabilities

 

 

1,671,044

 

 

 

1,761,412

 

Commitments and contingencies (Note 14)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mezzanine Capital

 

 

 

 

 

 

 

 

Subsidiary Series A Preferred Units (83,842 and 30,058 units issued and outstanding at September 30, 2020 and December 31, 2019, respectively)

 

 

85,800

 

 

 

27,450

 

 

 

 

 

 

 

 

 

 

Partners' Capital

 

 

 

 

 

 

 

 

Series A Preferred Units (237,184 and 300,000 units issued and outstanding at September 30, 2020 and December 31, 2019, respectively)

 

 

249,351

 

 

 

293,616

 

Common limited partner capital (56,624,887 and 45,318,866 units issued and outstanding at September 30, 2020 and December 31, 2019, respectively)

 

 

567,284

 

 

 

305,550

 

Noncontrolling interest

 

 

-

 

 

 

186,070

 

Total partners' capital

 

 

816,635

 

 

 

785,236

 

TOTAL LIABILITIES AND CAPITAL

 

$

2,573,479

 

 

$

2,574,098

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

4


 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

Three months ended September 30,

 

 

Nine months ended September 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

 

(In thousands, except per-unit amounts)

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

71,964

 

 

$

80,968

 

 

$

229,667

 

 

$

243,039

 

Natural gas, NGLs and condensate sales

 

 

10,783

 

 

 

12,219

 

 

 

35,246

 

 

 

68,438

 

Other revenues

 

 

7,406

 

 

 

7,000

 

 

 

22,150

 

 

 

19,804

 

Total revenues

 

 

90,153

 

 

 

100,187

 

 

 

287,063

 

 

 

331,281

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and NGLs

 

 

8,632

 

 

 

7,472

 

 

 

22,945

 

 

 

50,802

 

Operation and maintenance

 

 

22,168

 

 

 

26,231

 

 

 

65,131

 

 

 

74,771

 

General and administrative

 

 

10,561

 

 

 

10,029

 

 

 

39,908

 

 

 

38,979

 

Depreciation and amortization

 

 

29,505

 

 

 

27,443

 

 

 

88,801

 

 

 

82,044

 

Transaction costs

 

 

726

 

 

 

129

 

 

 

1,944

 

 

 

2,562

 

Gain on asset sales, net

 

 

(104

)

 

 

(347

)

 

 

(270

)

 

 

(1,595

)

Long-lived asset impairment

 

 

 

 

 

 

 

 

4,475

 

 

 

45,021

 

Goodwill impairment

 

 

 

 

 

16,211

 

 

 

 

 

 

16,211

 

Total costs and expenses

 

 

71,488

 

 

 

87,168

 

 

 

222,934

 

 

 

308,795

 

Other income

 

 

795

 

 

 

12

 

 

 

644

 

 

 

304

 

Interest expense

 

 

(19,018

)

 

 

(23,462

)

 

 

(64,836

)

 

 

(68,547

)

Gain on early extinguishment of debt

 

 

24,690

 

 

 

 

 

 

78,925

 

 

 

 

Income (loss) before income taxes and

   equity method investment income (loss)

 

 

25,132

 

 

 

(10,431

)

 

 

78,862

 

 

 

(45,757

)

Income tax benefit (expense)

 

 

(298

)

 

 

(21

)

 

 

104

 

 

 

(1,427

)

Income (loss) from equity method investees

 

 

795

 

 

 

(677

)

 

 

7,146

 

 

 

(1,197

)

Net income (loss)

 

$

25,629

 

 

$

(11,129

)

 

$

86,112

 

 

$

(48,381

)

Less:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to noncontrolling interest

 

 

 

 

 

(10,340

)

 

 

(3,274

)

 

 

(37,251

)

Net income (loss) attributable to limited partners

 

 

25,629

 

 

 

(789

)

 

 

89,386

 

 

 

(11,130

)

Net income attributable to Series A Preferred Units

 

 

6,481

 

 

 

7,125

 

 

 

20,731

 

 

 

21,375

 

Net income attributable to Subsidiary Series A Preferred Units

 

 

7,298

 

 

 

 

 

 

9,640

 

 

 

 

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deemed contribution on exchange of preferred units

 

 

54,945

 

 

 

 

 

 

54,945

 

 

 

 

Net income (loss) attributable to common limited partners

 

$

66,795

 

 

$

(7,914

)

 

$

113,960

 

 

$

(32,505

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) per limited partner unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common unit – basic

 

$

1.29

 

 

$

(0.17

)

 

$

2.41

 

 

$

(0.72

)

Common unit – diluted

 

$

1.25

 

 

$

(0.17

)

 

$

2.34

 

 

$

(0.72

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted-average limited partner units outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common units – basic

 

 

51,974

 

 

 

45,319

 

 

 

47,331

 

 

 

45,319

 

Common units – diluted

 

 

53,650

 

 

 

45,319

 

 

 

48,782

 

 

 

45,319

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

5


 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Noncontrolling Interest

 

 

Partners' Capital

 

 

 

 

 

 

 

Series A Preferred Units

 

 

Common Noncontrolling Interests (1)

 

 

Series A Preferred Units

 

 

Partners' Capital

 

 

Total

 

 

 

(In thousands)

 

Partners' capital, January 1, 2020

 

$

293,616

 

 

$

186,070

 

 

$

 

 

$

305,550

 

 

$

785,236

 

Net income (loss)

 

 

7,125

 

 

 

(1,881

)

 

 

 

 

 

(2,427

)

 

 

2,817

 

Net cash distributions to SMLP

    unitholders

 

 

 

 

 

(6,037

)

 

 

 

 

 

 

 

 

(6,037

)

Unit-based compensation

 

 

 

 

 

2,723

 

 

 

 

 

 

 

 

 

2,723

 

Effect of common unit issuances under

    SMLP LTIP

 

 

 

 

 

2,322

 

 

 

 

 

 

(2,322

)

 

 

 

Tax withholdings and associated

    payments on vested SMLP LTIP

    awards

 

 

 

 

 

(984

)

 

 

 

 

 

 

 

 

(984

)

Partners' capital, March 31, 2020

 

 

300,741

 

 

 

182,213

 

 

 

 

 

 

300,801

 

 

 

783,755

 

Net income (loss)

 

 

4,750

 

 

 

(1,393

)

 

 

2,375

 

 

 

49,592

 

 

 

55,324

 

Unit-based compensation

 

 

 

 

 

1,331

 

 

 

 

 

 

515

 

 

 

1,846

 

Tax withholdings and associated

    payments on vested SMLP LTIP

    awards

 

 

 

 

 

(34

)

 

 

 

 

 

(28

)

 

 

(62

)

GP Buy-In Transaction assumption of

    noncontrolling interest in SMLP

 

 

(305,491

)

 

 

(182,117

)

 

 

305,491

 

 

 

182,117

 

 

 

 

Repurchase of common units under GP

    Buy-In Transaction

 

 

 

 

 

 

 

 

 

 

 

(44,078

)

 

 

(44,078

)

Other

 

 

 

 

 

 

 

 

 

 

 

(61

)

 

 

(61

)

Partners' capital, June 30, 2020

 

 

 

 

 

 

 

 

307,866

 

 

 

488,858

 

 

 

796,724

 

Net income (loss)

 

 

 

 

 

 

 

 

6,481

 

 

 

11,850

 

 

 

18,331

 

Unit-based compensation

 

 

 

 

 

 

 

 

 

 

 

1,622

 

 

 

1,622

 

Tax withholdings and associated

   payments on vested SMLP LTIP

    awards

 

 

 

 

 

 

 

 

 

 

 

(117

)

 

 

(117

)

Tax withholdings on Series A Preferred

    Unit Exchange

 

 

 

 

 

 

 

 

 

 

 

(237

)

 

 

(237

)

Conversion of Series A Preferred Units to     

    SMLP common units inclusive of a

    $54.9 million deemed contribution to

    common unit holders (Note 10)

 

 

 

 

 

 

 

 

(64,996

)

 

 

64,996

 

 

 

 

Other

 

 

 

 

 

 

 

 

 

 

 

312

 

 

 

312

 

Partners' capital, September 30, 2020

 

$

-

 

 

$

-

 

 

$

249,351

 

 

$

567,284

 

 

$

816,635

 

(1) Prior to the GP Buy-In Transaction, common noncontrolling interests reported by Summit Investments included equity interests in SMLP that were not owned by Summit Investments.

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

 

6


 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

(continued)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Noncontrolling Interest

 

 

 

 

 

 

 

 

 

 

 

Series A Preferred Units

 

 

Common Noncontrolling Interests(1)

 

 

Partners' Capital

 

 

Total

 

 

 

(In thousands)

 

Partners' capital, January 1, 2019

 

$

293,616

 

 

$

554,472

 

 

$

543,479

 

 

$

1,391,567

 

Net income (loss)

 

 

7,125

 

 

 

(25,570

)

 

 

(21,835

)

 

 

(40,280

)

Net cash distributions to SMLP unitholders

 

 

 

 

 

(27,374

)

 

 

 

 

 

(27,374

)

Unit-based compensation

 

 

 

 

 

2,526

 

 

 

 

 

 

2,526

 

Effect of common unit issuances under

    SMLP LTIP

 

 

 

 

 

2,387

 

 

 

(2,387

)

 

 

 

Tax withholdings and associated

    payments on vested SMLP LTIP

    awards

 

 

 

 

 

(2,524

)

 

 

 

 

 

(2,524

)

Conversion of noncontrolling interest related

    to cancellation of subsidiary incentive

    distribution rights

 

 

 

 

 

(48,203

)

 

 

48,203

 

 

 

 

Partners' capital, March 31, 2019

 

 

300,741

 

 

 

455,714

 

 

 

567,460

 

 

 

1,323,915

 

Net income (loss)

 

 

7,125

 

 

 

(1,341

)

 

 

(2,756

)

 

 

3,028

 

Net cash distributions to SMLP unitholders

 

 

(14,250

)

 

 

(13,826

)

 

 

 

 

 

(28,076

)

Net cash distributions to Energy Capital

    Partners

 

 

 

 

 

 

 

 

(68,984

)

 

 

(68,984

)

Unit-based compensation

 

 

 

 

 

1,393

 

 

 

 

 

 

1,393

 

Effect of common unit issuances under

    SMLP LTIP

 

 

 

 

 

40

 

 

 

(40

)

 

 

 

Tax withholdings and associated

    payments on vested SMLP LTIP

    awards

 

 

 

 

 

(93

)

 

 

 

 

 

(93

)

Partners' capital, June 30, 2019

 

 

293,616

 

 

 

441,887

 

 

 

495,680

 

 

 

1,231,183

 

Net income (loss)

 

 

7,125

 

 

 

(10,340

)

 

 

(7,914

)

 

 

(11,129

)

Net cash distributions to SMLP unitholders

 

 

 

 

 

(13,829

)

 

 

 

 

 

(13,829

)

Unit-based compensation

 

 

 

 

 

1,451

 

 

 

 

 

 

1,451

 

Effect of common unit issuances under

    SMLP LTIP

 

 

 

 

 

173

 

 

 

(173

)

 

 

 

Tax withholdings and associated

    payments on vested SMLP LTIP

    awards

 

 

 

 

 

55

 

 

 

 

 

 

55

 

Partners' capital, September 30, 2019

 

$

300,741

 

 

$

419,397

 

 

$

487,593

 

 

$

1,207,731

 

(1) Prior to the GP Buy-In Transaction, common noncontrolling interests reported by Summit Investments included equity interests in SMLP that were not owned by Summit Investments.

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 

7


 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

Nine months ended September 30,

 

 

 

2020

 

 

2019

 

 

 

(In thousands)

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

Net income (loss)

 

$

86,112

 

 

$

(48,381

)

Adjustments to reconcile net income (loss) to net

    cash provided by operating activities:

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

89,505

 

 

 

83,030

 

Noncash lease expense

 

 

1,925

 

 

 

2,299

 

Amortization of debt issuance costs

 

 

4,870

 

 

 

4,719

 

Unit-based and noncash compensation

 

 

6,191

 

 

 

5,370

 

(Income) loss from equity method investees

 

 

(7,146

)

 

 

1,197

 

Distributions from equity method investees

 

 

19,859

 

 

 

28,008

 

Gain on asset sales, net

 

 

(270

)

 

 

(1,595

)

Gain on early extinguishment of debt

 

 

(78,925

)

 

 

 

Gain on fair value of warrants

 

 

(838

)

 

 

 

Long-lived asset impairment

 

 

4,475

 

 

 

45,021

 

Goodwill impairment

 

 

 

 

 

16,211

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

Accounts receivable

 

 

20,922

 

 

 

8,363

 

Trade accounts payable

 

 

470

 

 

 

820

 

Accrued expenses

 

 

(1,078

)

 

 

(11,965

)

Deferred revenue, net

 

 

7,379

 

 

 

1,910

 

Ad valorem taxes payable

 

 

(1,546

)

 

 

(2,061

)

Accrued interest

 

 

2,680

 

 

 

3,065

 

Accrued environmental remediation, net

 

 

(1,368

)

 

 

(2,025

)

Other, net

 

 

(6,410

)

 

 

(6,369

)

Net cash provided by operating activities

 

 

146,807

 

 

 

127,617

 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

Capital expenditures

 

 

(35,312

)

 

 

(151,663

)

Proceeds from asset sale (net of cash of $1,475 for the

    period ended September 30, 2019)

 

 

 

 

 

90,111

 

Distribution from equity method investment

 

 

 

 

 

7,252

 

Investment in equity method investee

 

 

(92,072

)

 

 

(11,330

)

Other, net

 

 

2,486

 

 

 

343

 

Net cash used in investing activities

 

 

(124,898

)

 

 

(65,287

)

Cash flows from financing activities:

 

 

 

 

 

 

 

 

Net cash distributions to noncontrolling interest SMLP unitholders

 

 

(6,037

)

 

 

(55,029

)

Series A Preferred Unit distributions

 

 

 

 

 

(14,250

)

Net cash distributions to Energy Capital Partners

 

 

 

 

 

(68,984

)

Borrowings under Revolving Credit Facility

 

 

165,500

 

 

 

265,000

 

Repayments on Revolving Credit Facility

 

 

(34,000

)

 

 

(131,000

)

Repayments on SMPH Term Loan

 

 

(6,300

)

 

 

(59,500

)

Open Market Repurchases of 2022 and 2025 Senior Notes (Note 8)

 

 

(82,844

)

 

 

 

Tender Offers of 2022 and 2025 Senior Notes (Note 8)

 

 

(48,712

)

 

 

 

Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs

 

 

48,710

 

 

 

 

Borrowings under ECP Loans (Note 8)

 

 

35,000

 

 

 

 

Repayment of ECP Loans (Note 8)

 

 

(35,000

)

 

 

 

Purchase of common units in GP Buy-In Transaction

 

 

(41,778

)

 

 

 

Debt issuance costs

 

 

(835

)

 

 

(584

)

Proceeds from asset sale

 

 

288

 

 

 

 

Other, net

 

 

(2,527

)

 

 

(3,930

)

Net cash provided by (used in) financing activities

 

 

(8,535

)

 

 

(68,277

)

Net change in cash, cash equivalents and restricted cash

 

 

13,374

 

 

 

(5,947

)

Cash, cash equivalents and restricted cash, beginning of period

 

 

36,922

 

 

 

16,173

 

Cash, cash equivalents and restricted cash, end of period

 

$

50,296

 

 

$

10,226

 

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

8


 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

Organization. SMLP, a Delaware limited partnership, was formed in May 2012 and began operations in October 2012. SMLP is a value-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States. Our business activities are conducted through various operating subsidiaries, each of which is owned or controlled by our wholly owned subsidiary holding company, Summit Holdings, a Delaware limited liability company. References to the "Partnership," "we," or "our" refer collectively to SMLP and its subsidiaries.

On May 28, 2020, the Partnership closed the transactions contemplated by the Purchase Agreement (the “Purchase Agreement”), dated May 3, 2020, with affiliates of its then private equity sponsor, Energy Capital Partners II, LLC (“ECP”), to acquire Summit Midstream Partners, LLC (“Summit Investments”). The purchase of Summit Investments resulted in the Partnership acquiring an indirect ownership interest in Summit Midstream Partners Holdings, LLC, a Delaware limited liability company (“SMP Holdings”), which in turn owned (a) 34,604,581 SMLP common units representing limited partner interests in the Partnership (the “common units”) that were pledged as collateral under the SMPH Term Loan, (b) 10,714,285 SMLP common units that were not pledged as collateral under the SMPH Term Loan and (c) a deferred purchase price obligation receivable owed by the Partnership.  In addition, the Partnership acquired 5,915,827 SMLP common units held by an affiliate of ECP. The total purchase price was $35.0 million in cash and warrants to purchase up to 10 million SMLP common units (refer to Note 11 – Partners’ Capital and Mezzanine Capital for additional details). Pursuant to the Purchase Agreement, the Partnership, through its indirect ownership interest of SMP Holdings, will retain any liabilities stemming from the release of produced water from a produced water pipeline operated by Meadowlark Midstream Company, LLC, a subsidiary of the Partnership, that occurred near Williston, North Dakota and was discovered on January 6, 2015. These transactions are collectively referred to as the “GP Buy-In Transaction.”

As a result of the GP Buy-In Transaction, the Partnership indirectly owns its General Partner. Following the closing of the GP Buy-In Transaction, the Partnership retired 16,630,112 SMLP common units it acquired that are not pledged as collateral under the SMPH Term Loan. The 34,604,581 SMLP common units that are pledged as collateral under the SMPH Term Loan are not considered outstanding with respect to voting and distributions under the Partnership Agreement so long as they are held by a subsidiary of the Partnership.

Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although SMLP is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results included herein, prior to the GP Buy-In Transaction are those of Summit Investments. Prior to the GP Buy-In Transaction, Summit Investments controlled SMLP and SMLP’s financial statements were consolidated into Summit Investments.

Business Operations.  The Partnership provides natural gas gathering, compression, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term, fee-based agreements with its customers. The Partnership’s results are primarily driven by the volumes of natural gas that it gathers, compresses, treats and/or processes as well as by the volumes of crude oil and produced water that it gathers.

 

Presentation and Consolidation.  The condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein.

The accompanying condensed consolidated financial statements were prepared using GAAP for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. As permitted under those rules, certain information relating to the Partnership’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted. Therefore, these condensed consolidated financial statements should be read in conjunction with the

9


 

consolidated financial statements and the notes thereto included in the Partnership’s Annual Report for the year ended December 31, 2019 (“2019 Annual Report”). The Partnership believes the disclosures made are adequate to make the information presented not misleading.

Risks and Uncertainties.  The Partnership is closely monitoring the impact of the outbreak of COVID-19 on all aspects of its business, including how it has impacted and will impact its customers, employees, supply chain and distribution network. While COVID-19 did not have a material adverse effect on the Partnership’s reported results for the first nine months of 2020, the Partnership is unable to predict the ultimate impact that COVID-19 may have on its business, future results of operations, financial position or cash flows.

Given the dynamic nature of the COVID-19 pandemic and related market conditions, the Partnership cannot reasonably estimate the period of time that these events will persist or the full extent of the impact they will have on its business. The full extent to which the Partnership’s operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the ability of pharmaceutical companies to develop effective and safe vaccines and therapeutic drugs. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.

2. SUMMARY OF RECENTLY ISSUED ACCOUNTING STANDARDS APPLICABLE TO THE PARTNERSHIP

Recent Accounting Pronouncements. Accounting standard setters frequently issue new or revised accounting rules. The Partnership reviews new pronouncements to determine the impact, if any, on its financial statements. Accounting standards that have or could possibly have a material effect on the Partnership’s financial statements are discussed below.

Recently Adopted Accounting Pronouncements. The Partnership recently adopted the following accounting pronouncements:

 

ASU No. 2018-13 Fair Value Measurement (“ASU 2018-13”). ASU 2018-13 updates the disclosure requirements on fair value measurements including new disclosures for the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. ASU 2018-13 modifies existing disclosures including clarifying the measurement uncertainty disclosure. ASU 2018-13 removes certain existing disclosure requirements including the amount and reasons for transfers between Level 1 and Level 2 fair value measurements and the policy for the timing of transfer between levels. The adoption of ASU 2018-13 on January 1, 2020 did not have a material impact on the Partnership’s condensed consolidated financial statements or disclosures.

 

ASU No. 2016-13 Financial Instruments – Credit Losses (“ASU 2016-13”). ASU 2016-13 requires the use of a current expected loss model for financial assets measured at amortized cost and certain off-balance sheet credit exposures. Under this model, entities will be required to estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied using a modified retrospective approach. The adoption of ASU 2016-13 on January 1, 2020 did not have a material impact on the Partnership’s condensed consolidated financial statements or disclosures.

Accounting Pronouncements Not Yet Adopted. The Partnership has not yet adopted the following accounting pronouncements as of September 30, 2020:

 

ASU No. 2020-06 Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815 – 40) (“ASU 2020-06”). ASU 2020-06 simplifies the

10


 

 

accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. The ASU is part of the FASB’s simplification initiative, which aims to reduce unnecessary complexity in U.S. GAAP. The ASU’s amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within those fiscal years. The Partnership is currently evaluating the provisions of ASU 2020-06 to determine its impact on the Partnership’s condensed consolidated financial statements and disclosures.

 

ASU No. 2020-04 Reference Rate Reform (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform on financial reporting. The amendments in ASU 2020-04 are effective as of March 12, 2020 through December 31, 2022. The Partnership is currently evaluating the provisions of ASU 2020-04 to determine its impact on the Partnership’s condensed consolidated financial statements and disclosures.

3. REVENUE

Performance obligations.  The following table presents estimated revenue expected to be recognized during the remainder of 2020 and over the remaining contract period related to performance obligations that are unsatisfied and are comprised of estimated MVC shortfall payments.

 

 

 

2020

 

 

2021

 

 

2022

 

 

2023

 

 

2024

 

 

Thereafter

 

 

 

(In thousands)

 

Gathering services and related fees

 

$

29,678

 

 

$

102,127

 

 

$

84,736

 

 

$

66,693

 

 

$

50,608

 

 

$

56,912

 

 

Revenue by Category.  In the following table, revenue is disaggregated by geographic area and major products and services.  For more detailed information about reportable segments, see Note 16 – Segment Information.

 

 

 

Three months ended September 30, 2020

 

 

 

Gathering services and related fees

 

 

Natural gas, NGLs and condensate sales

 

 

Other revenues

 

 

Total

 

 

 

(in thousands)

 

Reportable Segments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Utica Shale

 

$

8,385

 

 

$

-

 

 

$

-

 

 

$

8,385

 

Williston Basin

 

 

10,941

 

 

 

4,958

 

 

 

3,136

 

 

 

19,035

 

DJ Basin

 

 

6,051

 

 

 

17

 

 

 

826

 

 

 

6,894

 

Permian Basin

 

 

2,595

 

 

 

4,803

 

 

 

168

 

 

 

7,566

 

Piceance Basin

 

 

26,576

 

 

 

528

 

 

 

1,233

 

 

 

28,337

 

Barnett Shale

 

 

10,545

 

 

 

477

 

 

 

1,399

 

 

 

12,421

 

Marcellus Shale

 

 

6,871

 

 

 

 

 

 

 

 

 

6,871

 

Total reportable segments

 

 

71,964

 

 

 

10,783

 

 

 

6,762

 

 

 

89,509

 

All other segments

 

 

 

 

 

 

 

 

644

 

 

 

644

 

Total

 

$

71,964

 

 

$

10,783

 

 

$

7,406

 

 

$

90,153

 

 

 

 

Three months ended September 30, 2019

 

 

 

Gathering services and related fees

 

 

Natural gas, NGLs and condensate sales

 

 

Other revenues

 

 

Total

 

 

 

(in thousands)

 

Reportable Segments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Utica Shale

 

$

8,865

 

 

$

-

 

 

$

-

 

 

$

8,865

 

Williston Basin

 

 

16,685

 

 

 

1,878

 

 

 

2,555

 

 

 

21,118

 

DJ Basin

 

 

7,039

 

 

 

93

 

 

 

735

 

 

 

7,867

 

Permian Basin

 

 

986

 

 

 

3,797

 

 

 

102

 

 

 

4,885

 

Piceance Basin

 

 

30,120

 

 

 

1,733

 

 

 

1,258

 

 

 

33,111

 

Barnett Shale

 

 

11,286

 

 

 

4,828

 

 

 

1,706

 

 

 

17,820

 

Marcellus Shale

 

 

5,987

 

 

 

 

 

 

 

 

 

5,987

 

Total reportable segments

 

 

80,968

 

 

 

12,329

 

 

 

6,356

 

 

 

99,653

 

All other segments

 

 

 

 

 

(110

)

 

 

644

 

 

 

534

 

Total

 

$

80,968

 

 

$

12,219

 

 

$

7,000

 

 

$

100,187

 

 

11


 

 

 

Nine months ended September 30, 2020

 

 

 

Gathering services and related fees

 

 

Natural gas, NGLs and condensate sales

 

 

Other revenues

 

 

Total

 

 

 

(in thousands)

 

Reportable Segments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Utica Shale

 

$

26,885

 

 

$

-

 

 

$

-

 

 

$

26,885

 

Williston Basin

 

 

47,145

 

 

 

12,413

 

 

 

9,054

 

 

 

68,612

 

DJ Basin

 

 

18,134

 

 

 

158

 

 

 

2,853

 

 

 

21,145

 

Permian Basin

 

 

7,617

 

 

 

13,537

 

 

 

481

 

 

 

21,635

 

Piceance Basin

 

 

79,987

 

 

 

1,932

 

 

 

3,394

 

 

 

85,313

 

Barnett Shale

 

 

30,865

 

 

 

7,206

 

 

 

4,437

 

 

 

42,508

 

Marcellus Shale

 

 

19,034

 

 

 

 

 

 

 

 

 

19,034

 

Total reportable segments

 

 

229,667

 

 

 

35,246

 

 

 

20,219

 

 

 

285,132

 

All other segments

 

 

 

 

 

 

 

 

1,931

 

 

 

1,931

 

Total

 

$

229,667

 

 

$

35,246

 

 

$

22,150

 

 

$

287,063

 

 

 

 

Nine months ended September 30, 2019

 

 

 

Gathering services and related fees

 

 

Natural gas, NGLs and condensate sales

 

 

Other revenues

 

 

Total

 

 

 

(in thousands)

 

Reportable Segments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Utica Shale

 

$

23,951

 

 

$

-

 

 

$

-

 

 

$

23,951

 

Williston Basin

 

 

58,076

 

 

 

11,231

 

 

 

8,133

 

 

 

77,440

 

DJ Basin

 

 

14,784

 

 

 

279

 

 

 

2,776

 

 

 

17,839

 

Permian Basin

 

 

1,938

 

 

 

10,424

 

 

 

183

 

 

 

12,545

 

Piceance Basin

 

 

92,515

 

 

 

6,139

 

 

 

3,341

 

 

 

101,995

 

Barnett Shale

 

 

35,739

 

 

 

11,705

 

 

 

5,008

 

 

 

52,452

 

Marcellus Shale

 

 

18,081

 

 

 

 

 

 

 

 

 

18,081

 

Total reportable segments

 

 

245,084

 

 

 

39,778

 

 

 

19,441

 

 

 

304,303

 

All other segments

 

 

(2,045

)

 

 

28,660

 

 

 

363

 

 

 

26,978

 

Total

 

$

243,039

 

 

$

68,438

 

 

$

19,804

 

 

$

331,281

 

 

Contract balances.  Contract assets relate to the Partnership’s rights to consideration for work completed but not billed at the reporting date and consist of the estimated MVC shortfall payments expected from customers and unbilled activity associated with contributions in aid of construction. Contract assets are transferred to trade receivables when the rights become unconditional. The following table provides information about contract assets from contracts with customers:

 

 

 

September 30, 2020

 

 

 

(In thousands)

 

Contract assets, January 1, 2020

 

$

3,902

 

Additions

 

 

16,442

 

Transfers out

 

 

(2,275

)

Contract assets, September 30, 2020

 

$

18,069

 

As of September 30, 2020, receivables with customers totaled $53.8 million and contract assets totaled $18.1 million and are included in the accounts receivable caption on the unaudited condensed consolidated balance sheets.

As of December 31, 2019, receivables with customers totaled $90.4 million and contract assets totaled $3.9 million and are included in the accounts receivable caption on the unaudited condensed consolidated balance sheets.

Contract liabilities (deferred revenue) relate to the advance consideration received from customers primarily for contributions in aid of construction. The Partnership recognizes contract liabilities under these arrangements in revenue over the contract period. For the three months ended September 30, 2020 and 2019, the Partnership recognized $2.4 million and $2.4 million of gathering services and related fees, respectively, which are included in the contract liability balance as of the beginning of the period. For the nine months ended September 30, 2020 and 2019, the Partnership recognized $7.1 million and $7.8 million of gathering services and related fees, respectively, which

12


 

are included in the contract liability balance at the beginning of the period. See Note 7 – Deferred Revenue for additional details.

 

4. PROPERTY, PLANT AND EQUIPMENT, NET

Details on property, plant and equipment follow.

 

 

 

September 30, 2020

 

 

December 31, 2019

 

 

 

(In thousands)

 

Gathering and processing systems and related equipment

 

$

2,197,087

 

 

$

2,182,950

 

Construction in progress

 

 

78,146

 

 

 

78,716

 

Land and line fill

 

 

10,440

 

 

 

10,137

 

Other

 

 

60,589

 

 

 

54,595

 

Total

 

 

2,346,262

 

 

 

2,326,398

 

Less accumulated depreciation

 

 

(505,978)

 

 

 

(443,909)

 

Property, plant and equipment, net

 

$

1,840,284

 

 

$

1,882,489

 

 

In March 2020, in connection with the cancellation of a compressor station project in the DJ Basin due to delays in customer drilling plans, the Partnership recorded an impairment charge of $3.6 million for the related soft project costs.

In March 2019, certain events occurred which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, in the first quarter of 2019, the Partnership performed a recoverability assessment of certain assets within these reporting segments, the results of which are described below.

In March 2019, the Partnership determined that certain processing plant assets in the DJ Basin related to its existing 20 MMcf/d plant would no longer be utilized due to the Partnership’s expansion plans for the Niobrara G&P system. Based on the results of the recoverability assessment and the conclusion that the carrying value was not fully recoverable, the Partnership recorded an impairment charge of $34.7 million related to these assets in the first quarter of 2019.

In March 2019, the Partnership determined that certain compressor station assets in the Barnett Shale were impaired and recorded an impairment charge of $10.2 million, comprised of a $9.7 million impairment of fixed assets and a $0.5 million impairment of rights-of-way.

 

Depreciation expense and capitalized interest follow.

 

 

 

Three months ended September 30,

 

 

Nine months ended September 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

 

(In thousands)

 

Depreciation expense

 

$

21,537

 

 

$

19,474

 

 

$

64,899

 

 

$

58,160

 

Capitalized interest

 

 

1,449

 

 

 

1,391

 

 

 

2,268

 

 

 

5,752

 

 

13


 

 

5. GOODWILL

Goodwill. The Partnership evaluates goodwill for impairment annually on September 30th. In 2019, the Partnership performed its annual goodwill impairment test for the Mountaineer Midstream reporting unit using a combination of the income and market approaches and determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value, including goodwill. As a result, the Partnership recognized a goodwill impairment charge of $16.2 million for the three and nine months ended September 30, 2019. The Partnership had no goodwill on its balance sheet after September 30, 2019.

Fair Value Measurement. The Partnership’s impairment determinations, in the context of (i) its annual impairment evaluations and (ii) its other-than-annual impairment evaluations, involve significant assumptions and judgments, as discussed in the 2019 Annual Report. Differing assumptions regarding any of these inputs could have a significant effect on the valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources.

6. EQUITY METHOD INVESTMENTS

Double E

The Partnership is responsible for leading the development, permitting and construction of the Double E Project.  During the three and nine month periods ended September 30, 2020, the Partnership made cash investments of $12.4 million and $92.1 million, respectively, in the Double E Project.

For the three and nine months ended September 30, 2020, other than the investment activity noted above, Double E did not have any results of operations given that the Double E Project is currently under development.

Ohio Gathering

As of September 30, 2020 and December 31, 2019, the Partnership’s ownership interest in Ohio Gathering was 38.2% and 38.5%, respectively, and provided below is the September 30, 2020 reconciliation of the difference between the carrying amount of the Partnership’s interest in Ohio Gathering and the Partnership’s underlying investment per Ohio Gathering's books and records (in thousands).

Investment in Ohio Gathering, September 30, 2020

 

$

263,639

 

September cash distributions

 

 

3,870

 

Basis difference

 

 

218,757

 

Investment in Ohio Gathering (Books and records), August 31, 2020

 

$

486,266

 

 

7. DEFERRED REVENUE

A rollforward of current deferred revenue follows.

 

 

Total

 

 

 

(In thousands)

 

Current deferred revenue, January 1, 2020

 

$

13,493

 

Additions

 

 

15,433

 

Less: revenue recognized

 

 

(11,099)

 

Current deferred revenue, September 30, 2020

 

$

17,827

 

A rollforward of noncurrent deferred revenue follows.

 

 

Total

 

 

 

(In thousands)

 

Noncurrent deferred revenue, January 1, 2020

 

$

38,709

 

Additions

 

 

18,402

 

Less: reclassification to current deferred revenue

 

 

(15,356)

 

Noncurrent deferred revenue, September 30, 2020

 

$

41,755

 

 

14


 

8. DEBT

Debt consisted of the following:

 

 

September 30, 2020

 

 

December 31, 2019

 

 

 

(In thousands)

 

Revolving Credit Facility: Summit Holdings' variable rate senior secured Revolving Credit Facility (2.90% at September 30, 2020 and 4.55% at December 31, 2019) due May 2022

 

$

808,500

 

 

$

677,000

 

ECP Loans: Summit Holdings' 8.00% senior secured term loans due March 2021

 

 

 

 

 

 

2022 Senior Notes: Summit Holdings' 5.5% senior unsecured notes due August 2022

 

 

234,047

 

 

 

300,000

 

Less: unamortized debt issuance costs (1)

 

 

(997

)

 

 

(1,686

)

2025 Senior Notes: Summit Holdings' 5.75% senior unsecured notes due April 2025

 

 

355,071

 

 

 

500,000

 

Less: unamortized debt issuance costs (1)

 

 

(3,055

)

 

 

(5,015

)

SMPH Term Loan: SMP Holdings' variable rate senior secured term loan (7.00% at September 30, 2020 and 7.80% at December 31, 2019) due May 2022

 

 

155,200

 

 

 

161,500

 

Less: unamortized debt issuance costs (1)

 

 

(2,724

)

 

 

(3,974

)

Total debt

 

 

1,546,042

 

 

 

1,627,825

 

Less: current portion

 

 

(155,200)

 

 

 

(5,546)

 

Total long-term debt

 

$

1,390,842

 

 

$

1,622,279

 

(1) Issuance costs are being amortized over the life of the SMPH Term Loan and the Senior Notes.

Revolving Credit Facility.  The Partnership’s subsidiary, Summit Holdings, has a senior secured revolving credit facility (the “Revolving Credit Facility”) which allows for revolving loans, letters of credit and swingline loans. The Revolving Credit Facility has a $1.25 billion borrowing capacity, matures in May 2022, and includes a $250.0 million accordion feature. At September 30, 2020, the applicable margin under LIBOR borrowings was 2.75%, the interest rate was 2.90% and the unused portion of the Revolving Credit Facility totaled $437.4 million, subject to a commitment fee of 0.50%, after giving effect to the issuance thereunder of a $4.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of September 30, 2020 was approximately $172.0 million. As of and during the nine months ended September 30, 2020, we were in compliance with the Revolving Credit Facility's financial covenants. There were no defaults or events of default during the nine months ended September 30, 2020.

Significant updates to the Partnership’s indebtedness for the three and nine months ended September 30, 2020 included the following matters.

ECP Loans.  On May 28, 2020, in connection with the closing of the GP Buy-In Transaction, Summit Holdings, entered into (i) a Term Loan Credit Agreement (the “ECP NewCo Term Loan Credit Agreement”), with SMP TopCo, LLC, a Delaware limited liability company and affiliate of ECP (“ECP NewCo”), as lender and administrative agent, and Mizuho Bank (USA) (“Mizuho”), as collateral agent, in a principal amount of $28.2 million (the “ECP NewCo Loan”), and (ii) a Term Loan Credit Agreement (the “ECP Holdings Term Loan Credit Agreement” and together with the ECP NewCo Term Loan Credit Agreement, the “ECP Term Loan Credit Agreements”), with ECP Holdings, as lender, and ECP NewCo, as administrative agent and Mizuho, as collateral agent, in a principal amount of $6.8 million (the “ECP Holdings Loan” and together with the ECP NewCo Loan, the “ECP Loans”). The ECP Loans were set to mature on March 31, 2021 and bore interest at a rate of 8.00% per annum, with the interest payment due at maturity of the ECP Loans. With borrowings under the Partnership’s Revolving Credit Facility, the Partnership fully repaid all amounts outstanding under the ECP Loans ($35 million of principal and $0.6 million of accrued interest) on August 7, 2020.  

SMPH Term Loan.  On April 17, 2020, the Partnership entered into a derivative financial instrument to convert a portion of its variable rate SMPH Term Loan to a fixed rate debt consisting of a 1% LIBOR interest rate cap for a fee of $0.2 million (exclusive of the applicable bank margin charged by our lender) on a $125.0 million notional amount

15


 

beginning April 30, 2020 and ending on April 30, 2022. The Partnership did not designate the interest rate cap for hedge accounting as defined by GAAP and recognized an unsettled gain of $0.1 million on the interest rate cap in the other income line item on our unaudited condensed consolidated statement of operations for the three and nine month periods ended September 30, 2020.

Liability Management Transactions. During the three and nine months ended September 30, 2020, the Partnership completed several liability management transactions, described below, that resulted in the early extinguishment of $210.8 million of the Partnership’s 2022 and 2025 Senior Notes.

Open Market Repurchases. During the nine months ended September 30, 2020, the Partnership made a number of open market repurchases of its 2022 and 2025 Senior Notes that resulted in the extinguishment of $32.4 million of face value of the 2022 Senior Notes and $106.2 million of face value of the 2025 Senior Notes (the “Open Market Repurchases”).  Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest totaled $82.9 million and the Partnership recognized a $56.2 million gain on the extinguishment of debt during the nine months ended September 30, 2020.  

Tender Offers.  In September 2020, the Partnership completed cash tender offers (the “Tender Offers”) to purchase a portion of the 2022 and 2025 Senior Notes. Upon concluding the Tender Offers, the Partnership repurchased $33.5 million principal amount of the 2022 Senior Notes and $38.7 million principal amount of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest, totaled $48.7 million and the Partnership recognized a $23.3 million gain on the extinguishment of debt during the nine months ended September 30, 2020.

SMPH Term Loan Restructuring. On September 29, 2020, SMP Holdings and the Partnership entered into the Transaction Support Agreement (the “TSA”) with an ad hoc group of SMP Holdings’ lenders under the $155.2 million SMPH Term Loan (the “Term Loan Lenders”) that will result in a consensual debt discharge and restructuring transaction (the “TL Restructuring”) of the full amount owed under SMPH Term Loan in exchange for (i) a cash payment of $26.5 million to the Term Loan Lenders, (ii) the execution of a strict foreclosure by the collateral agent under the SMPH Term Loan for the benefit of the Term Loan Lenders on the 34.6 million SMLP common units pledged as collateral under the SMPH Term Loan, and (iii) the payment of certain fees and expenses by the Partnership. Upon consummation of the TL Restructuring, which is expected to occur during the quarterly period ended December 31, 2020, the SMPH Term Loan will be fully satisfied and cease to exist. Upon closing of the TL Restructuring the Partnership will recognize a gain equal to the difference between the face value of the cancelled debt and the fair value of the total consideration transferred, including  unamortized debt issuance costs, and certain direct transaction costs related to the restructuring. As a result of the TL Restructuring, at September 30, 2020 the Partnership classified the SMPH Term Loan as current. Concurrently with the closing of the TL Restructuring, the Partnership will make a $26.5 million cash payment on the Deferred Purchase Price Obligation to SMP Holdings and fully settle the obligation.

Gain on Extinguishment of Debt. The Partnership recognized a $78.9 million gain on extinguishment of debt during the nine months ended September 30, 2020, primarily as the result of the its Open Market Repurchases and its Tender Offers.

 

 

ECP Loan Repayment

 

 

Open Market Repurchases

 

 

Tender Offers

 

 

Total

 

 

 

 

 

 

 

2022

 

2025

 

 

2022

 

2025

 

 

 

 

 

 

 

 

 

 

 

Senior Notes

 

Senior Notes

 

 

Senior Notes

 

Senior Notes

 

 

 

 

 

 

 

(in thousands)

 

Gain on repurchases of Senior Notes

 

$

-

 

 

$

11,554

 

$

46,003

 

 

$

9,223

 

$

15,479

 

 

$

82,259

 

Debt issue costs

 

 

(361

)

 

 

(143

)

 

(965

)

 

 

(125

)

 

(351

)

 

 

(1,945

)

Transaction cost

 

 

(249

)

 

 

(105

)

 

(105

)

 

 

(465

)

 

(465

)

 

 

(1,389

)

Gain (loss) on extinguishment

 

$

(610

)

 

$

11,306

 

$

44,933

 

 

$

8,633

 

$

14,663

 

 

$

78,925

 

 

16


 

9. FINANCIAL INSTRUMENTS

Fair Value.  A summary of the estimated fair value of our debt financial instruments follows.

 

 

 

September 30, 2020

 

 

December 31, 2019

 

 

 

Carrying

Value, Net

 

 

Estimated

fair value

(Level 2)

 

 

Carrying

Value, Net

 

 

Estimated

fair value

(Level 2)

 

 

 

(In thousands)

 

2022 Senior Notes

 

$

233,050

 

 

$

169,684

 

 

$

298,314

 

 

$

266,750

 

2025 Senior Notes

 

 

352,016

 

 

 

204,758

 

 

 

494,985

 

 

 

382,708

 

 

The carrying value on the balance sheet of the Revolving Credit Facility is its fair value due to their floating interest rates. The fair value for the 2022 and 2025 Senior Notes is based on an average of nonbinding broker quotes. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the 2022 and 2025 Senior Notes.

10. PARTNERS' CAPITAL AND MEZZANINE CAPITAL

A rollforward of the number of common units follows.

 

 

Common Units

 

Units, December 31, 2019(1)

 

 

45,318,866

 

Net units issued under the SMLP LTIP

 

 

1,028,654

 

Impact of GP Buy-In Transaction

 

 

(1,990,303

)

Preferred Unit Exchange

 

 

12,267,670

 

Units, September 30, 2020(1)

 

 

56,624,887

 

 

(1) As a result of the GP Buy-In Transaction, the Partnership recast its historical financial statements, which resulted in a recasted SMLP common limited partner unit count of 45.3 million units at December 31, 2019. Prior to the GP Buy-In Transaction, the SMLP common limited partner unit count was 94.5 million units, and after adjusting for (i) the effect of 1.0 million SMLP units issued following the closing of the GP Buy-In transaction through September 30, 2020 for the SMLP LTIP, (ii) the 12.3 million SMLP common units issued in the Exchange Offer, and (iii) the GP Buy-In Transaction which included the Partnership acquiring SMP Holdings which owns the 34.6 million SMLP units pledged under the SMPH Term Loan, the 10.7 million SMLP units not pledged under the SMPH Term Loan, and the 5.9 million SMLP units owned by ECP, the SMLP common limited partner unit count would have been an otherwise identical 56.6 million SMLP common units at September 30, 2020.

GP Buy-In Transaction.  The purchase price for the SMLP common units reflected in the unaudited condensed consolidated statement of partners’ capital for the nine months ended September 30, 2020 is comprised of the (i) the $35.0 million cash payment to ECP, (ii) the $2.3 million fair value for the issuance of 10,000,000 warrants, and (iii) $6.8 million of advisory fees and other direct costs related to closing the GP Buy-In Transaction.  

Series A Preferred Units.  In 2017, the Partnership issued 300,000 Series A Preferred Units representing limited partner interests in the Partnership at a price to the public of $1,000 per unit as described in the 2019 Annual Report. In connection with the GP Buy-In Transaction, the Partnership suspended its distributions to holders of its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. On June 18, 2020, the Partnership, commenced an offer to exchange any and all of its Series A Preferred Units for newly issued SMLP common units (the “Exchange Offer”). On July 28, 2020, the Exchange Offer expired and the Partnership exchanged 62,816 Series A Preferred Units for 12,267,670 SMLP common units, net of units withheld for tax withholdings. As of September 30, 2020, the Partnership had 237,184 Series A Preferred Units outstanding. 

Subsidiary Series A Preferred Units.  The Partnership issued 53,784 Subsidiary Series A Preferred Units during the nine months ended September 30, 2020 at a price of $1,000 per unit and has cumulatively issued 83,842 Subsidiary Series A Preferred Units since the instrument’s initial issuance in December 2019.  Net proceeds received during the nine months ended September 30, 2020 totaled $48.7 million (after deducting underwriting discounts and offering expenses) and were used to fund the Partnership’s share of capital expenditures associated with the Double E Project.  The proceeds associated with the issuance of Subsidiary Series A Preferred Units are restricted for funding the Double E Project and are classified as restricted cash in the accompanying unaudited condensed consolidated balance sheets.

17


 

The Partnership records its Subsidiary Series A Preferred Units at fair value upon issuance, net of issuance costs, and subsequently records an effective interest method accretion amount each reporting period to accrete the carrying value to a most probable redemption value that is based on a predetermined internal rate of return measure.  The Partnership also elected to make payment-in-kind (“PIK”) distributions to holders of the Subsidiary Series A Preferred Units during the nine months ended September 30, 2020 and these PIK distributions increase the liquidation preference on each Subsidiary Series A Preferred Unit. Ultimately, Net Income (Loss) Attributable to common limited partners includes adjustments for PIK distributions and redemption accretion.  

If the Subsidiary Series A Preferred Units were redeemed on September 30, 2020, the redemption amount would be $104.8 million when considering the applicable multiple of invested capital metric and make-whole amount provisions contained in the Subsidiary Series A Preferred Unit agreement. The following table shows the change in our Subsidiary Series A Preferred Unit balance from December 31, 2019 to September 30, 2020:

 

 

September 30, 2020

 

 

 

(in thousands)

 

Balance at December 31, 2019

 

$

27,450

 

New issuances

 

 

50,000

 

PIK distributions

 

 

3,784

 

Issuance costs

 

 

(1,290

)

Redemption accretion

 

 

5,856

 

Balance at September 30, 2020 (1)

 

$

85,800

 

(1)  Amount is net of $3.9 million of issuance costs at September 30, 2020.

Warrants.  On May 28, 2020 and in connection with the GP Buy-In Transaction, the Partnership issued (i) a warrant to purchase up to 8,059,609 SMLP common units to ECP NewCo (the “ECP NewCo Warrant”) and (ii) a warrant to purchase up to 1,940,391 SMLP common units to ECP Holdings (the “ECP Holdings Warrant” and together with the ECP NewCo Warrant, the “ECP Warrants”). The exercise price under the ECP Warrants is $1.023 per SMLP common unit and the Partnership may issue a maximum of 10,000,000 SMLP common units under the ECP Warrants.

Upon exercise of the ECP Warrants, each of ECP NewCo and ECP Holdings may receive, at its election: (i) a number of SMLP common units equal to the number of SMLP common units for which the ECP Warrants are being exercised, if exercising the ECP Warrants by cash payment of the exercise price; (ii) a number of SMLP common units equal to the product of the number of common units being exercised multiplied by (a) the difference between the average of the daily volume-weighted average price (“VWAP”) of the SMLP common units on the New York Stock Exchange (the “NYSE”) on each of the three trading days prior to the delivery of the notice of exercise (the “VWAP Average”) and the exercise price (the “VWAP Difference”), divided by (b) the VWAP Average; and/or (iii) an amount in cash, to the extent that the Partnership’s leverage ratio would be at least 0.5x less than the maximum applicable ratio set forth in the Revolving Credit Facility, equal to the product of (a) the number of SMLP common units exercised and (b) the VWAP Difference, subject to certain adjustments under the ECP Warrants.

The ECP Warrants are subject to standard anti-dilution adjustments for stock dividends, stock splits (including reverse splits) and recapitalizations and are exercisable at any time on or before May 28, 2023. Upon exercise of the ECP Warrants, the proceeds to the holders of the ECP Warrants, whether in the form of cash or common units, will be capped at $2.00 per SMLP common unit above the exercise price.

At issuance the ECP Warrants were valued at $2.3 million using a Black-Scholes model and accounted for as a liability instrument. At September 30, 2020, the ECP Warrants were valued at $1.5 million.

18


 

SMLP General Partner and Incentive Distribution Rights (“IDR”) Exchange.  In March 2019, and prior to the GP Buy-In Transaction, a subsidiary of Summit Investments cancelled its IDR agreement with SMLP and converted its 2% economic general partner interest to a non-economic general partner interest in exchange for 8,750,000 SMLP common units. This exchange is reflected in the Consolidated Statements of Partners’ Capital as a reduction to noncontrolling interest and an increase to Partners’ Capital.

Cash Distributions Paid and Declared.  Prior to the GP Buy-In Transaction, SMLP paid the following per-unit distributions during the three and nine month periods ended September 30 (all payments represent per-unit distributions based on the SMLP common units outstanding prior to the GP Buy-In Transaction):   

 

 

Three months ended September 30,

 

 

Nine months ended September 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

Per-unit distributions to unitholders

 

$

 

 

$

0.2875

 

 

$

0.125

 

 

$

1.1500

 

In connection with the GP Buy-In Transaction, the Partnership suspended its distributions to holders of its common units, commencing with respect to the quarter ending March 31, 2020.

With respect to our Subsidiary Series A Preferred Units relating to the three and nine months ended September 30, 2020, the Partnership declared a PIK of the quarterly distribution, which resulted in the issuance of 45 Subsidiary Series A Preferred Units and 1,442 Subsidiary Series A Preferred Units, respectively. This PIK amount equates to a distribution of $32.1133 and $17.5099 per Subsidiary Series A Preferred Unit for the three and nine months ended September 30, 2020, respectively, or $70 on an annualized basis. In addition, the Partnership issued approximately 38 Subsidiary Series A Preferred Units related to the remaining undrawn commitment (as defined in the underlying agreement with TPG Energy Solutions Anthem, L.P.) as of and for the nine months ended September 30, 2020.

 

11. EARNINGS PER UNIT

The following table details the components of EPU.

 

 

Three months ended September 30,

 

 

Nine months ended September 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

 

(In thousands, except per-unit amounts)

 

Numerator for basic and diluted EPU:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Allocation of net income (loss) among limited partner interests:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) attributable to limited partners

 

$

25,629

 

 

$

(789

)

 

$

89,386

 

 

$

(11,130

)

Less:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to Series A Preferred Units

 

 

6,481

 

 

 

7,125

 

 

 

20,731

 

 

 

21,375

 

Net income attributable to Subsidiary Series A Preferred Units

 

 

7,298

 

 

 

 

 

 

9,640

 

 

 

 

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deemed capital contribution from Series A Preferred Unit Exchange Offer

 

 

54,945

 

 

 

 

 

 

54,945

 

 

 

 

Net income (loss) attributable to common limited partners

 

$

66,795

 

 

$

(7,914

)

 

$

113,960

 

 

$

(32,505

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Denominator for basic and diluted EPU:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted-average common units outstanding – basic(1)

 

 

51,974

 

 

 

45,319

 

 

 

47,331

 

 

 

45,319

 

Effect of nonvested phantom units

 

 

1,676

 

 

 

 

 

 

1,451

 

 

 

 

Weighted-average common units outstanding – diluted

 

 

53,650

 

 

 

45,319

 

 

 

48,782

 

 

 

45,319

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income (Loss) per limited partner unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common unit – basic

 

$

1.29

 

 

$

(0.17

)

 

$

2.41

 

 

$

(0.72

)

Common unit – diluted

 

$

1.25

 

 

$

(0.17

)

 

$

2.34

 

 

$

(0.72

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nonvested anti-dilutive phantom units excluded from the

    calculation of diluted EPU

 

 

4,031

 

 

 

176

 

 

 

3,353

 

 

 

70

 

(1) As a result of the GP Buy-In Transaction, our historical results are those of Summit Investments. The number of common units of 45.3 million as of September 30, 2019 represents those of Summit Investments and has been used for the earnings per unit calculations presented herein.

19


 

As discussed in Note 8 - Debt, the SMPH Term Loan is secured by 34.6 million SMLP common units owned by SMP Holdings. These common units are not included in the calculation of EPU because they are not deemed contingently issuable under GAAP. Upon closing the TL Restructuring, the 34.6 million SMLP common units pledged under the SMPH Term Loan will be considered outstanding and included in the calculation of EPU.

 

12. SUPPLEMENTAL CASH FLOW INFORMATION

 

 

 

Nine months ended September 30,

 

 

 

2020

 

 

2019

 

 

 

(In thousands)

 

Supplemental cash flow information:

 

 

 

 

 

 

 

 

Cash interest paid

 

$

62,441

 

 

$

66,435

 

Less capitalized interest

 

 

2,268

 

 

 

5,752

 

Interest paid (net of capitalized interest)

 

$

60,173

 

 

$

60,683

 

 

 

 

 

 

 

 

 

 

Cash paid for taxes

 

$

 

 

$

150

 

 

 

 

 

 

 

 

 

 

Noncash investing and financing activities:

 

 

 

 

 

 

 

 

Capital expenditures in trade accounts payable (period-end accruals)

 

$

10,233

 

 

$

22,166

 

Warrant issuance for GP Buy-In Transaction

 

 

2,300

 

 

 

 

Asset contribution to an equity method investment

 

 

 

 

 

23,643

 

Right-of-use assets relating to ASC Topic 842

 

 

2,964

 

 

 

5,448

 

Accretion of Subsidiary Series A Preferred Units

 

 

5,856

 

 

 

 

 

13. UNIT-BASED AND NONCASH COMPENSATION

SMLP Long-Term Incentive Plan. The SMLP LTIP provides for equity awards to eligible officers, employees, consultants and directors. Items to note:

 

In March 2020, the Partnership granted 3,811,301 phantom units and associated distribution equivalent rights to employees in connection with the Partnership’s annual incentive compensation award cycle. These awards had a grant date fair value of $0.55 and vest ratably over a three-year period.

 

In March 2020, the Partnership issued 549,450 common units to the Partnership’s three independent directors in connection with their annual compensation plan.

 

In June 2020, the Partnership issued 187,500 common units to three new independent directors in connection with their annual compensation plan.

 

During the nine months ended September 30, 2020, 0.8 million phantom units vested.

 

In March 2020, the Partnership increased the number of common units authorized under the SMLP LTIP to 15,000,000 common units and extended the term of the SMLP LTIP for 10 years.

 

As of September 30, 2020, approximately 6.3 million common units remained available for future issuance under the SMLP LTIP.

14. COMMITMENTS AND CONTINGENCIES

Environmental Matters.  Although the Partnership believes that it is in material compliance with applicable environmental regulations, the risk of environmental remediation costs and liabilities are inherent in pipeline ownership and operation. Furthermore, the Partnership can provide no assurances that significant environmental remediation costs and liabilities will not be incurred by the Partnership in the future. The Partnership is not aware of any material contingent liabilities that exist with respect to environmental matters, except as noted below.

In 2015, the Partnership learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota. The incident, which was covered by insurance policies, was subject

20


 

to maximum coverage of $25.0 million from its pollution liability insurance policy and $200.0 million from its property and business interruption insurance policy. The pollution liability policy was exhausted in 2015.

A rollforward of the Partnership’s undiscounted accrued environmental remediation liabilities follows.

 

 

Total

 

 

 

(In thousands)

 

Accrued environmental remediation, January 1, 2020

 

$

4,651

 

Payments made

 

 

(1,095

)

Accrued environmental remediation, September 30, 2020

 

$

3,556

 

As of September 30, 2020, the Partnership has recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures expected to be incurred subsequent to September 30, 2021. Each of these amounts represent our best estimate for costs expected to be incurred. Neither of these amounts have been discounted to its present value.

Prior to the GP Buy-In Transaction, Summit Investments and SMP Holdings indemnified the Partnership for certain obligations and liabilities related to the incident. As a result of the GP Buy-In Transaction, the Partnership continues to be indemnified by Summit Investments and SMP Holdings, both subsidiaries of the Partnership, but is no longer indemnified for these obligations by a third party that is not a subsidiary of the Partnership.

The U.S. Department of Justice issued grand jury subpoenas to the Partnership requesting certain materials related to the Meadowlark Midstream rupture. Based on information currently available to the Partnership, the Partnership believes a loss for claims and/or actions arising from the Meadowlark Midstream rupture is probable. Due to the complexity surrounding the resolution of the Meadowlark Midstream rupture, the Partnership is not able to reasonably estimate the extent of the Partnership’s loss for this matter, or to express an opinion regarding the ultimate outcome. Any such loss, if incurred, could be material.

Legal Proceedings.  The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims or those arising in the normal course of business would not individually or in the aggregate have a material adverse effect on the Partnership's financial position or results of operations.

15. DISPOSITIONS AND RESTRUCTURING

Tioga Midstream Disposition.  In February 2019, the Partnership entered into two Purchase and Sale Agreements (the “Tioga PSAs”) with Hess Infrastructure Partners LP and Hess North Dakota Pipelines LLC (collectively, “Hess Infrastructure”), pursuant to which the Partnership agreed to sell the Tioga Midstream system to Hess Infrastructure for a combined cash purchase price of $90 million, subject to adjustments as provided in the Tioga PSAs (the “Tioga Midstream Sale”). On March 22, 2019, the Partnership closed the Tioga Midstream Sale and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for Tioga Midstream at closing. The gain is included in the Gain on asset sales, net caption on the unaudited condensed consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in the Partnership’s unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019.

Restructuring Activities.  As of December 31, 2019, the Partnership had $3.3 million of unpaid employee severance costs related to 2019 restructuring initiatives that resulted in certain management, facility and organizational changes. During the three and nine month periods ended September 30, 2020, the Partnership’s 2019 restructuring initiatives resulted in additional restructuring costs of $0.1 million and $3.4 million, respectively. The Partnership paid out $6.4 million of these 2019 restructuring costs during the nine months ended September 30, 2020 and has a $0.3 million current liability for unpaid employee severance costs at September 30, 2020 related to these 2019 restructuring initiatives. The 2019 restructuring activities primarily consisted of employee-related costs and consulting costs in support of the restructuring initiatives.  Restructuring costs are included within the general and administrative expense caption on the condensed consolidated statement of operations.

21


 

16. SEGMENT INFORMATION

As of September 30, 2020, the Partnership’s reportable segments are:

 

the Utica Shale, which is served by Summit Utica;

 

Ohio Gathering, which includes our ownership interest in OGC and OCC;

 

the Williston Basin, which is served by Polar and Divide, Bison Midstream and Meadowlark Midstream;

 

the DJ Basin, which is served by Niobrara G&P;

 

the Permian Basin, which is served by Summit Permian;

 

the Piceance Basin, which is served by Grand River;

 

the Barnett Shale, which is served by DFW Midstream; and

 

the Marcellus Shale, which is served by Mountaineer Midstream.

Until March 22, 2019, the Partnership owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Refer to Note 15 – Dispositions and Restructuring to the unaudited condensed consolidated financial statements for details on the sale of Tioga Midstream.

Each of the Partnership’s reportable segments provide midstream services in a specific geographic area and reflect the way in which the Partnership internally reports the financial information used to make decisions and allocate resources in connection with the Partnership’s operations.

For the three and nine months ended September 30, 2020, other than the investment activity described in Note 6 – Equity Method Investments, Double E did not have any results of operations given that the Double E Project is currently under development. The Double E Project is expected to be operational in the fourth quarter of 2021.

Corporate and Other represents those results that are: (i) not specifically attributable to a reportable segment; (ii) not individually reportable (such as Double E); or (iii) that have not been allocated to the Partnership’s reportable segments for the purpose of evaluating their performance, including certain general and administrative expense items, certain natural gas and crude oil marketing services, construction management fees related to the Double E Project and transaction costs.

Assets by reportable segment follow.

 

 

 

September 30, 2020

 

 

December 31, 2019

 

 

 

(In thousands)

 

Assets(1):

 

 

 

 

 

 

 

 

Utica Shale

 

$

208,090

 

 

$

206,368

 

Ohio Gathering

 

 

263,639

 

 

 

275,000

 

Williston Basin

 

 

443,506

 

 

 

452,152

 

DJ Basin

 

 

204,206

 

 

 

205,308

 

Permian Basin

 

 

167,707

 

 

 

185,708

 

Piceance Basin

 

 

596,148

 

 

 

631,140

 

Barnett Shale

 

 

349,254

 

 

 

350,638

 

Marcellus Shale

 

 

182,900

 

 

 

184,631

 

Total reportable segment assets

 

 

2,415,450

 

 

 

2,490,945

 

Corporate and Other

 

 

158,029

 

 

 

83,153

 

Total assets

 

$

2,573,479

 

 

$

2,574,098

 

 

 

(1)

At September 30, 2020, Corporate and Other included $125.4 million relating to our investment in Double E (included in the Investment in equity method investees caption of the unaudited condensed consolidated balance sheet). At December 31, 2019, Corporate and Other included $34.7 million relating to our investment in Double E.

Segment adjusted EBITDA by reportable segment follows.

 

22


 

 

 

Three months ended September 30,

 

 

Nine months ended September 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

 

(In thousands)

 

Reportable segment adjusted EBITDA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Utica Shale

 

$

7,453

 

 

$

7,864

 

 

$

24,074

 

 

$

20,697

 

Ohio Gathering

 

 

7,129

 

 

 

10,435

 

 

 

22,582

 

 

 

29,584

 

Williston Basin

 

 

11,713

 

 

 

13,840

 

 

 

40,632

 

 

 

49,224

 

DJ Basin

 

 

4,766

 

 

 

6,554

 

 

 

15,016

 

 

 

12,043

 

Permian Basin

 

 

893

 

 

 

210

 

 

 

4,302

 

 

 

(996

)

Piceance Basin

 

 

21,503

 

 

 

24,044

 

 

 

66,794

 

 

 

74,627

 

Barnett Shale

 

 

7,205

 

 

 

10,901

 

 

 

24,475

 

 

 

33,483

 

Marcellus Shale

 

 

6,022

 

 

 

4,958

 

 

 

16,230

 

 

 

14,735

 

Total of reportable segments' measures of profit

 

$

66,684

 

 

$

78,806

 

 

$

214,105

 

 

$

233,397

 

 

 

A reconciliation of income or loss before income taxes and income or loss from equity method investees to total of reportable segments' measures of profit follows.

 

 

 

Three months ended September 30,

 

 

Nine months ended September 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

 

(In thousands)

 

Reconciliation of income (loss) before income taxes

    and income (loss) from equity method investees

    to total of reportable segments' measures of

    profit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) before income taxes and income

    (loss) from equity method investees

 

$

25,132

 

 

$

(10,431

)

 

$

78,862

 

 

$

(45,757

)

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate and Other expense

 

 

6,874

 

 

 

7,119

 

 

 

28,484

 

 

 

32,024

 

Interest expense

 

 

19,018

 

 

 

23,462

 

 

 

64,836

 

 

 

68,547

 

Gain on early extinguishment of debt

 

 

(24,690

)

 

 

 

 

 

(78,925

)

 

 

 

Depreciation and amortization(1)

 

 

29,739

 

 

 

27,677

 

 

 

89,505

 

 

 

83,030

 

Proportional adjusted EBITDA for equity method

   investees

 

 

7,129

 

 

 

10,435

 

 

 

22,582

 

 

 

29,584

 

Adjustments related to MVC shortfall payments

 

 

2,292

 

 

 

3,534

 

 

 

(859

)

 

 

2,868

 

Adjustments related to capital reimbursement activity

 

 

(328

)

 

 

(145

)

 

 

(776

)

 

 

(1,906

)

Unit-based and noncash compensation

 

 

1,622

 

 

 

1,291

 

 

 

6,191

 

 

 

5,370

 

Gain on asset sales, net

 

 

(104

)

 

 

(347

)

 

 

(270

)

 

 

(1,595

)

Long-lived asset impairment

 

 

 

 

 

 

 

 

4,475

 

 

 

45,021

 

Goodwill impairment

 

 

 

 

 

16,211

 

 

 

 

 

 

16,211

 

Total of reportable segments' measures of profit

 

$

66,684

 

 

$

78,806

 

 

$

214,105

 

 

$

233,397

 

 

(1) Includes the amortization expense associated with our favorable gas gathering contracts as reported in other revenues.

17. SUBSEQUENT EVENTS

Open Market Repurchases of 2025 Senior Notes. In October 2020, the Partnership repurchased an additional $95.6 million of the outstanding 2025 Senior Notes for total cash consideration of $64.8 million.

TL Restructuring.  In October 2020, the Partnership obtained consents for the TL Restructuring from 100% of the Term Loan Lenders and subsequently filed a Form S-1 registration statement with the Securities and Exchange Commission on November 3, 2020 to register the 34.6 million SMLP common units to be issued to the lenders of the SMPH Term Loan upon consummation of the TL Restructuring. Once the Form S-1 registration statement becomes effective and administrative procedures are performed, the Partnership will close the TL Restructuring and recognize a gain on early debt extinguishment.

23


 

Reverse Unit Split.  On October 15, 2020, the Board of Directors of the General Partner authorized a reverse unit split (the “Reverse Unit Split”) of the Partnership’s common units.  The exchange ratio of the Reverse Unit Split is 1-for-15 and will be effective on November 9, 2020. The common units will begin trading on a split-adjusted basis on November 10, 2020.  The Reverse Unit Split is intended to, among other things, increase the per unit trading price of the Partnership’s common units to satisfy the $1.00 minimum bid price requirement for continued listing on the NYSE. As a result of the Reverse Unit Split, each 15 pre-split common units will automatically be combined into one issued and outstanding common unit without any action on the part of the unitholder. Any fractional common units issued as a result of the Reverse Unit Split will be rounded to the nearest whole number of common units. Once effective, the number of outstanding shares of common units will be reduced from 56,624,887 common units as of October 30, 2020 to 3,774,992 common units.    

FERC Approval.  In October 2020, Double E received Federal Energy Regulatory Commission ("FERC") approval of its application to construct and operate the Double E Pipeline Project, pursuant to Section 7(c) of the Natural Gas Act.  Upon fulfilling certain remaining requirements, including finalizing a right-of-way grant from the Bureau of Land Management and filing an implementation plan with the FERC, Double E expects to receive FERC's notice to proceed with construction.

 

 

24


 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

This Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiaries for the periods since December 31, 2019. As a result, the following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this report and the MD&A and the audited consolidated financial statements and related notes that are included in the 2019 Annual Report. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements. Actual results may differ materially from those contained in any forward-looking statements.

This MD&A comprises the following sections:

 

Overview

 

Trends and Outlook

 

How We Evaluate Our Operations

 

Results of Operations

 

Liquidity and Capital Resources

 

Critical Accounting Estimates

 

Forward-Looking Statements

Overview

We are a value-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States.

We classify our midstream energy infrastructure assets into two categories:

 

Core Focus Areas – core producing areas of basins in which we expect our gathering systems to experience greater long-term growth, driven by our customers’ ability to generate more favorable returns and support sustained drilling and completion activity in varying commodity price environments. In the near-term, we expect to concentrate the majority of our capital expenditures in our Core Focus Areas. Our Utica Shale, Ohio Gathering, Williston Basin, DJ Basin and Permian Basin reportable segments (as described below) comprise our Core Focus Areas.

 

Legacy Areas – production basins in which we expect volume throughput on our gathering systems to experience relatively lower long-term growth compared to our Core Focus Areas, given that our customers require relatively higher commodity prices to support drilling and completion activities in these basins. Upstream production served by our gathering systems in our Legacy Areas is generally more mature, as compared to our Core Focus Areas, and the decline rates for volume throughput on our gathering systems in the Legacy Areas are typically lower as a result. We expect to continue to reduce our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments (as described below) comprise our Legacy Areas.

Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn revenues from the following activities that directly expose us to

25


 

fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. During the three and nine months ended September 30, 2020, these additional activities accounted for approximately 12% of total revenues.

We also have indirect exposure to changes in commodity prices in that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs, if any, ensure that we will earn a minimum amount of revenue.

The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the "Segment Overview for the Three and Nine Months Ended September 30, 2020 and 2019" section included herein.

 

 

Three months ended September 30,

 

 

Nine months ended September 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

 

(In thousands)

 

Net income (loss)

 

$

25,629

 

 

$

(11,129

)

 

$

86,112

 

 

$

(48,381

)

Reportable segment adjusted EBITDA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Utica Shale

 

$

7,453

 

 

$

7,864

 

 

$

24,074

 

 

$

20,697

 

Ohio Gathering

 

 

7,129

 

 

 

10,435

 

 

 

22,582

 

 

 

29,584

 

Williston Basin

 

 

11,713

 

 

 

13,840

 

 

 

40,632

 

 

 

49,224

 

DJ Basin

 

 

4,766

 

 

 

6,554

 

 

 

15,016

 

 

 

12,043

 

Permian Basin

 

 

893

 

 

 

210

 

 

 

4,302

 

 

 

(996

)

Piceance Basin

 

 

21,503

 

 

 

24,044

 

 

 

66,794

 

 

 

74,627

 

Barnett Shale

 

 

7,205

 

 

 

10,901

 

 

 

24,475

 

 

 

33,483

 

Marcellus Shale

 

 

6,022

 

 

 

4,958

 

 

 

16,230

 

 

 

14,735

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

41,436

 

 

$

43,043

 

 

$

146,807

 

 

$

127,617

 

Capital expenditures (1)

 

 

7,886

 

 

 

40,571

 

 

 

35,312

 

 

 

151,663

 

Investment in equity method investee

 

 

12,344

 

 

 

5,409

 

 

 

92,072

 

 

 

11,330

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash distributions to noncontrolling interest

    SMLP unitholders

 

$

 

 

$

13,829

 

 

$

6,037

 

 

$

55,029

 

Series A Preferred Unit distributions

 

 

 

 

 

 

 

 

 

 

 

14,250

 

Net borrowings under Revolving

    Credit Facility

 

 

75,500

 

 

 

27,000

 

 

 

131,500

 

 

 

134,000

 

Repayments on SMPH term loan

 

 

 

 

 

(5,750

)

 

 

(6,300

)

 

 

(59,500

)

Open Market Repurchases of 2022 and

    2025 Senior Notes (Note 8)

 

 

(6,137

)

 

 

 

 

 

(82,844

)

 

 

 

Tender Offers of 2022 and 2025 Senior Notes (Note 8)

 

 

(48,712

)

 

 

 

 

 

(48,712

)

 

 

 

Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs (2)

 

 

 

 

 

 

 

 

48,710

 

 

 

 

Purchase of common units in GP Buy-In

    Transaction

 

 

 

 

 

 

 

 

(41,778

)

 

 

 

(1) See "Liquidity and Capital Resources" herein to the unaudited condensed consolidated financial statements for additional information on capital expenditures.

(2) Reflects proceeds from the issuance of Subsidiary Series A Preferred Units.

26


 

Key matters for three and nine months ended September 30, 2020.  The following items are reflected in our financial results:

 

GP Buy-In Transaction. On May 28, 2020, we closed the GP Buy-In Transaction. Refer to Note 1 – Organization, Business Operations and Presentation and Consolidation for details.

 

Series A Preferred Unit Exchange Offer.  On June 18, 2020, we commenced an offer to exchange any and all of our Series A Preferred Units for newly issued common units (the “Exchange Offer”). On July 28, 2020 the Exchange Offer expired and the Partnership exchanged 62,816 Series A Preferred Units for 12,267,670 common units, net of units withheld for tax withholdings. 

 

Open Market Repurchase of Senior Notes.  During the nine months ended September 30, 2020, the Partnership made Open Market Repurchases that resulted in the extinguishment of $32.4 million of its outstanding 2022 Senior Notes and $106.2 million of 2025 Senior Notes.  Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest, totaled $82.9 million and the Partnership recognized a $56.2 million gain on the extinguishment of debt during the nine months ended September 30, 2020.    

 

Tender Offers.  In September 2020, the Partnership completed Tender Offers initiated in August 2020 to purchase a portion of the 2022 and 2025 Senior Notes. Upon concluding the Tender Offer, the Partnership repurchased $33.5 million of the 2022 Senior Notes and $38.7 million of the 2025 Senior Notes. Total cash consideration paid to repurchase the principal amounts outstanding of the 2022 and 2025 Senior Notes, plus accrued interest, totaled $48.7 million and the Partnership recognized a $23.3 million gain on the extinguishment of debt during the nine months ended September 30, 2020.

 

TL Restructuring.  On September 29, 2020, we signed the TSA for the TL Restructuring.  Refer to Note 8 – Debt and Note 16 – Subsequent Events for further details on the TL Restructuring. The TL Restructuring had not closed as of September 30, 2020 and our financial results do not include a gain on the extinguishment of debt related to the TL Restructuring.  

Key matters for the three and nine months ended September 30, 2019.  The following items are reflected in our financial results:

 

Goodwill Impairment. In September 2019, in connection with our annual impairment evaluation, we determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value and we recognized a goodwill impairment charge of $16.2 million for the three and nine months ended September 30, 2019.

 

Double E Project. In June 2019, we decided to proceed with the Double E Project after securing firm 10-year take-or-pay commitments for a substantial majority of the pipeline’s initial throughput capacity of 1.35 billion cubic feet of gas per day and executing the JV Agreement with an affiliate of Double E’s foundation shipper.

In connection with the Double E Project, Summit Permian Transmission contributed total assets of approximately $23.6 million for a 70% ownership interest in Double E. We own a majority interest in the Double E Project and are leading efforts to develop, permit and construct the pipeline. Upon commissioning, we will operate the pipeline.

 

Disposition. In March 2019, we sold the Tioga Midstream system to affiliates of Hess Infrastructure Partners LP for a combined cash purchase price of approximately $90 million and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for Tioga Midstream at closing. The gain is included in the Gain on asset sales, net caption on the unaudited condensed consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019.

 

Asset Impairment. In March 2019, certain events occurred which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, we performed a

27


 

 

recoverability assessment of certain assets within these reporting segments. In the DJ Basin, we determined certain processing plant assets related to our existing 20 MMcf/d plant would no longer be operational due to our expansion plans for the Niobrara G&P system and we recorded an impairment charge of $34.7 million related to these assets. In the Barnett Shale, we determined certain compressor station assets were impaired and recorded an impairment charge of $10.2 million.

Trends and Outlook

Our business has been, and we expect our future business to continue to be, affected by the following key trends:

 

Natural gas, NGL and crude oil supply and demand dynamics;

 

Production from U.S. shale plays;

 

Capital markets availability and cost of capital;

 

Shifts in operating costs and inflation; and

 

Ongoing impact of the COVID-19 pandemic and reduced demand and prices for oil.

We are closely monitoring the impact of the outbreak of COVID-19 on all aspects of our business, including how it has impacted and will impact our customers, employees, supply chain and distribution network. While COVID-19 did not have a material adverse effect on our reported results for the first nine months of 2020, we are unable to predict the ultimate impact that COVID-19 and related factors may have on our business, future results of operations, financial position or cash flows. Given the dynamic nature of the COVID-19 pandemic and related market conditions, we cannot reasonably estimate the period of time that these events will persist or the full extent of the impact they will have on our business. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the ability of pharmaceutical companies to develop effective and safe vaccines and therapeutic drugs. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.

In response to the COVID-19 pandemic, we have modified our business practices, including restricting employee travel, modifying employee work locations, implementing social distancing and enhancing sanitary measures in our facilities. Many of our suppliers, vendors and service providers have made similar modifications. The resources available to employees working remotely may not enable them to maintain the same level of productivity and efficiency, and these and other employees may face additional demands on their time. Our increased reliance on remote access to our information systems increases our exposure to potential cybersecurity breaches. We may take further actions as government authorities require or recommend or as we determine to be in the best interests of our employees, customers, partners and suppliers. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus, in which case our employees may become sick, our ability to perform critical functions could be harmed, and we may be unable to respond to the needs of our business. The resumption of normal business operations after such interruptions may be delayed or constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers.

In addition, the COVID-19 pandemic has significantly reduced the global demand for oil and natural gas. This significant decline in demand has been met with a sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries, or OPEC, and other foreign, oil-exporting countries, and subsequent hydrocarbon commodity price declines. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April to cut production, extended cuts again in June and cuts its long-term forecast for oil demand growth in October, there is no assurance that the agreement will continue to be observed by its members and the responses of oil and gas producers to the

28


 

lower demand for, and price of, natural gas, NGLs and crude oil are constantly evolving and remain uncertain. After increasing supply through the summer of 2020, certain OPEC members recently announced price cuts for October, potentially signaling continued pressure on demand. Such responses could cause our pipelines and storage tanks and other third-party storage facilities to reach capacity, thereby forcing producers to experience shut-ins or look to alternative methods of transportation for their products.

Over the past several months, we have collaborated extensively with our customer base regarding production reductions and delays to drilling and completion activities in light of the current commodity price backdrop and COVID-19 pandemic. Given continued volatility in market conditions since March 2020, and based on recently updated production forecasts and revised 2020 development plans from our customers, we currently expect our 2020 results to be affected by decreased drilling activity and the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin, DJ Basin and Utica Shale reportable segments. For example, beginning in June 2020, in the Utica Shale, a customer curtailed in excess of 150 MMcf/d of production which impacted volume throughput across our gathering system and the financial results of that segment through the middle of the third quarter of 2020, when more favorable natural gas prices returned and that customer reversed that particular production curtailment.  We also recently amended gathering contracts with two key Williston Basin customers to extend the terms of the gathering agreement acreage dedications, in exchange for a modest gathering fee concession. We expect 2020 total capital expenditures to range from $55 million to $65 million.

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. For additional information, see the "Trends and Outlook" section of MD&A included in the 2019 Annual Report.

How We Evaluate Our Operations

Each of our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations.  For additional information see Note – 16 Segment Information.

Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance. We view these metrics as important factors in evaluating our profitability and determining the amounts of cash distributions to pay to our unitholders. These metrics include:

 

throughput volume;

 

revenues;

 

operation and maintenance expenses; and

 

segment adjusted EBITDA.

We review these metrics on a regular basis for consistency and trend analysis. There have been no changes in the composition or characteristics of these metrics during the three and nine months ended September 30, 2020.

Additional Information.  For additional information, see the "Results of Operations" section herein and the notes to the unaudited condensed consolidated financial statements. For additional information on how these metrics help us manage our business, see the "How We Evaluate Our Operations" section of MD&A included in the 2019 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 – Summary of Significant Accounting Policies.

29


 

Results of Operations

Consolidated Overview for the Three and Nine Months Ended September 30, 2020 and 2019

The following table presents certain consolidated financial and operating data.

 

 

Three months ended September 30,

 

 

Nine months ended September 30,

 

 

 

2020

 

 

2019

 

 

2020

 

 

2019

 

 

 

(In thousands)

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

71,964

 

 

$

80,968

 

 

$

229,667

 

 

$

243,039

 

Natural gas, NGLs and condensate sales

 

 

10,783

 

 

 

12,219

 

 

 

35,246

 

 

 

68,438

 

Other revenues

 

 

7,406

 

 

 

7,000

 

 

 

22,150

 

 

 

19,804

 

Total revenues

 

 

90,153

 

 

 

100,187

 

 

 

287,063

 

 

 

331,281

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and NGLs

 

 

8,632

 

 

 

7,472

 

 

 

22,945

 

 

 

50,802

 

Operation and maintenance

 

 

22,168

 

 

 

26,231

 

 

 

65,131

 

 

 

74,771

 

General and administrative

 

 

10,561

 

 

 

10,029

 

 

 

39,908

 

 

 

38,979

 

Depreciation and amortization

 

 

29,505

 

 

 

27,443

 

 

 

88,801

 

 

 

82,044

 

Transaction costs

 

 

726

 

 

 

129

 

 

 

1,944

 

 

 

2,562

 

Gain on asset sales, net

 

 

(104

)

 

 

(347

)

 

 

(270

)

 

 

(1,595

)

Long-lived asset impairment

 

 

 

 

 

 

 

 

4,475

 

 

 

45,021

 

Goodwill Impairment

 

 

 

 

 

16,211

 

 

 

 

 

 

16,211

 

Total costs and expenses

 

 

71,488

 

 

 

87,168

 

 

 

222,934

 

 

 

308,795

 

Other income

 

 

795

 

 

 

12

 

 

 

644

 

 

 

304

 

Interest expense

 

 

(19,018

)

 

 

(23,462

)

 

 

(64,836

)

 

 

(68,547

)

Gain on early extinguishment of debt

 

 

24,690

 

 

 

 

 

 

78,925

 

 

 

 

Income (loss) before income taxes and

    equity method investment income (loss)

 

 

25,132

 

 

 

(10,431

)

 

 

78,862

 

 

 

(45,757

)

Income tax benefit (expense)

 

 

(298

)

 

 

(21

)

 

 

104

 

 

 

(1,427

)

Income (loss) from equity method investees

 

 

795

 

 

 

(677

)

 

 

7,146

 

 

 

(1,197

)

Net income (loss)

 

$

25,629

 

 

$

(11,129

)

 

$

86,112

 

 

$

(48,381

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Volume throughput (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Aggregate average daily throughput - natural

    gas (MMcf/d)

 

 

1,392

 

 

 

1,394

 

 

 

1,354

 

 

 

1,410

 

Aggregate average daily throughput - liquids

    (Mbbl/d)

 

 

69

 

 

 

105

 

 

 

81

 

 

 

101

 

(1) Exclusive of volume throughput for Ohio Gathering. For additional information, see the "Ohio Gathering" section herein.

Volumes – Gas.  Natural gas throughput volumes decreased 2 MMcf/d for the three months ended September 30, 2020 compared to the three months ended September 30, 2019, primarily reflecting:

 

a volume throughput increase of 62 MMcf/d for the Utica Shale segment.

 

a volume throughput increase of 47 MMcf/d for the Marcellus Shale segment.

 

a volume throughput increase of 14 MMcf/d for the Permian Basin segment.

 

a volume throughput decrease of 85 MMcf/d for the Piceance Basin segment.

 

a volume throughput decrease of 39 MMcf/d for the Barnett Shale segment.

Natural gas throughput volumes decreased 56 MMcf/d for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019, primarily reflecting:

30


 

 

a volume throughput decrease of 94 MMcf/d for the Piceance Basin segment.

 

a volume throughput decrease of 40 MMcf/d for the Barnett Shale segment.

 

a volume throughput increase of 51 MMcf/d for the Utica Shale segment.

 

a volume throughput increase of 16 MMcf/d for the Permian Basin segment.

 

a volume throughput increase of 8 MMcf/d for the Marcellus Shale segment.

Volumes – Liquids. Crude oil and produced water throughput volumes at the Williston segment decreased 36 Mbbl/d and 20 Mbbl/d for the three and nine months ended September 30, 2020, respectively, compared to the three and nine months ended September 30, 2019.

For additional information on volumes, see the "Segment Overview for the Three and Nine Months Ended September 30, 2020 and 2019" section herein.

Revenues.  Total revenues decreased $10.0 million during the three months ended September 30, 2020 compared to the prior year period primarily comprised of a $9.0 million decrease in gathering services and related fees and a $1.4 million decrease in natural gas, NGLs and condensate sales.

Gathering Services and Related Fees. Gathering services and related fees decreased $9.0 million compared to the three months ended September 30, 2019, primarily reflecting:

 

a $3.5 million decrease in gathering services and related fees in the Piceance Basin related to lower volume throughput due to a lack of drilling and completion activity and natural production declines in addition to the sale of certain assets from our Red Rock Gathering system in December 2019.

 

a $5.7 million decrease in gathering services and related fees in the Williston Basin due to lower liquids throughput associated with natural production declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

 

a $0.7 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting natural production declines partially offset by new volumes from well completion activity through the third quarter of 2019.

 

a $0.5 million decrease in gathering services and related fees in the Utica Shale as a result of natural production declines on existing wells and temporary production curtailments beginning in June 2020, partially offset by the completion of new wells throughout 2019 and in the first half of 2020.

 

a $1.0 million decrease in gathering services and related fees in the DJ Basin as a result of natural production declines and limited drilling and completion activity associated with a reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic, partially offset by higher volume throughput due to increased drilling activity and a more favorable volume and gathering rate mix from customers and the commissioning of our new natural gas processing plant in June 2019.

 

a $1.6 million increase in gathering services and related fees in the Permian Basin due to higher volumes from wells connected in the fourth quarter of 2019 and first quarter of 2020 and a more favorable volume and gathering rate mix from customers.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $1.4 million compared to the three months ended September 30, 2019, primarily reflecting lower natural gas, NGL and crude oil marketing services.

Total revenues decreased $44.2 million during the nine months ended September 30, 2020 compared to the prior year period primarily comprised of a $33.2 million decrease in natural gas, NGLs and condensate sales and a $13.4 million decrease in gathering services and related fees.

Gathering Services and Related Fees. Gathering services and related fees decreased $13.4 million compared to the nine months ended September 30, 2019, primarily reflecting:

31


 

 

a $12.5 million decrease in gathering services and related fees in the Piceance Basin related to lower volume throughput due to a lack of drilling and completion activity and natural production declines in addition to the sale of certain assets from our Red Rock Gathering system in December 2019.

 

a $10.9 million decrease in gathering services and related fees in the Williston Basin primarily due to lower liquids throughput associated with natural production declines and, beginning in the second quarter of 2020, temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic. The decrease was also due to a $1.5 million decrease in gathering services and related fees attributable to the sale of the Tioga Midstream system on March 22, 2019, the 2019 financial results of which are included for the period from January 1, 2019 through March 22, 2019.

 

a $4.9 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting natural production declines partially offset by new volumes from well completion activity through the third quarter of 2019. Also impacting 2020 revenues was the presentation of gathering services as a reduction to cost of natural gas and NGLs due to the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations that occurred in June 2019, which decreased gathering services and related fees by $1.7 million.

 

a $3.4 million increase in gathering services and related fees in the DJ Basin relating to higher volume throughput due to increased drilling activity and a more favorable volume and gathering rate mix from customers and the commissioning of our new natural gas processing plant in June 2019, partially offset by natural production declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

 

a $5.7 million increase in gathering services and related fees in the Permian Basin due to higher volume growth from ongoing drilling and completion activity and a more favorable volume and gathering rate mix from customers.

 

a $2.9 million increase in gathering services and related fees in the Utica Shale as a result of the completion of new wells throughout 2019 and in the first nine months of 2020, and a more favorable volume and gathering rate mix from customers partially offset by natural production declines on existing wells.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $33.2 million compared to the nine months ended September 30, 2019, primarily reflecting lower natural gas, NGL and crude oil marketing services. The majority of the decrease in revenue is offset by a $27.9 million decrease in natural gas, NGL and condensate purchases.

Costs and Expenses. Total costs and expenses decreased $15.7 million during the three months ended September 30, 2020 compared to the three months ended September 30, 2019, primarily due to a $16.2 million decrease from a noncash goodwill impairment charge in 2019 and a $4.1 million decrease in operation and maintenance expense partially offset by a $2.1 million increase in depreciation and amortization expense and a $1.2 million increase in natural gas, NGLs and condensate purchases.

Total costs and expenses decreased $85.7 million during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019, primarily due to the impact of: (i) the March 2019 recognition of a $34.9 million and $10.2 million long-lived asset impairment in the DJ Basin and Barnett Shale, respectively, (ii) the September of 2019 recognition of a $16.2 million noncash goodwill impairment charge in the Marcellus Shale, (iii) a $27.9 million decrease in natural gas, NGLs and condensate purchases and (iv) a $9.6 million decrease in operating and maintenance expense, partially offset by (v) the March 2020 recognition of a $3.6 million long-lived asset impairment in the DJ Basin and (vi) a $6.8 million increase in depreciation and amortization expense.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs increased $1.2 million for the three months ended September 30, 2020 and decreased $27.9 million for the nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019, primarily driven by lower natural gas, NGL and crude oil marketing activity.

32


 

Operation and Maintenance. Operation and maintenance expense decreased $4.1 million for the three months ended September 30, 2020 compared to the three months ended September 30, 2019, primarily due to a $1.4 million decrease in salaries and benefits costs associated with lower headcount from our cost cutting initiatives and a $2.0 million decrease in general operating expenses.

Operation and maintenance expense decreased $9.6 million for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019, primarily due to a $4.1 million decrease in salaries and benefits costs associated with lower headcount from our cost cutting initiatives, a $1.5 million decrease in property taxes and a $2.8 million decrease in remediation expense.

General and Administrative. General and administrative expense increased $0.5 million for the three months ended September 30, 2020 compared to the three months ended September 30, 2019, primarily due to a $0.3 million increase in professional service fees and a $0.1 million increase in restructuring expenses.

General and administrative expense increased $0.9 million compared to the nine months ended September 30, 2019, primarily due to a $3.4 million increase in restructuring expenses, $1.5 million increase in deal costs and a $2.0 million increase in professional service fees, partially offset by a $6.1 million decrease in compensation expense primarily associated with lower headcount from our cost cutting initiatives.

Depreciation and Amortization. The increase in depreciation and amortization expense during the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019 was primarily due to the acceleration of depreciation on certain Williston Basin assets.

Transaction Costs. The increase in transaction costs recognized during the three months ended September 30, 2020 compared to the three months ended September 30, 2019 was primarily due to costs associated with the GP Buy-In Transaction.

The decrease in transaction costs recognized during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 was due to financial advisory costs incurred in 2019.

Interest Expense. The decrease in interest expense for the three and nine months ended September 30, 2020 compared to the three and nine months ended September 30, 2019 was primarily due to our liability management initiatives which included our Open Market Repurchases and Tender Offers, partially offset by a higher outstanding balance on the Revolving Credit Facility.

Gain on early extinguishment of debt. The gain on early extinguishment of debt is primarily a result of our Open Market Repurchases and Tender Offers that resulted in a $78.9 million gain on extinguishment of debt during the nine months ended September 30, 2020 (Details below).  

 

 

ECP Loan Repayment

 

 

Open Market Repurchases

 

 

Tender Offers

 

 

Total

 

 

 

 

 

 

 

2022

 

2025

 

 

2022

 

2025

 

 

 

 

 

 

 

 

 

 

 

Senior Notes

 

Senior Notes

 

 

Senior Notes

 

Senior Notes

 

 

 

 

 

 

 

(in thousands)

 

Gain/(loss) on face value of 2022 and 2025 Senior Notes

 

$

-

 

 

$

11,554

 

$

46,003

 

 

$

9,223

 

$

15,479

 

 

$

82,259

 

Debt issue costs

 

 

(361

)

 

 

(143

)

 

(965

)

 

 

(125

)

 

(351

)

 

 

(1,945

)

Transaction cost

 

 

(249

)

 

 

(105

)

 

(105

)

 

 

(465

)

 

(465

)

 

 

(1,389

)

Gain (loss) on extinguishment

 

$

(610

)

 

$

11,306

 

$

44,933

 

 

$

8,633

 

$

14,663

 

 

$

78,925

 

 

33


 

Segment Overview for the Three and Nine Months Ended September 30, 2020 and 2019

Utica Shale. The Utica Shale reportable segment includes the Summit Utica system. Volume throughput for our Summit Utica system follows.

 

 

Utica Shale

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

Average daily throughput (MMcf/d)

 

 

352

 

 

 

290

 

 

21%

 

 

330

 

 

 

279

 

 

18%

Volume throughput increased compared to the three months ended September 30, 2019, as a result of the completion of new wells throughout 2019, and in the first half of 2020, partially offset by natural production declines from existing wells and temporary production curtailments beginning in June 2020.

Volume throughput increased compared to the nine months ended September 30, 2019, as a result of the completion of new wells throughout 2019, and in the first half of 2020, and a more favorable volume and gathering rate mix from customers, partially offset by natural production declines from existing wells.

Financial data for our Utica Shale reportable segment follows.

 

 

Utica Shale

 

 

 

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

 

 

(Dollars in thousands)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

8,385

 

 

$

8,865

 

 

(5%)

 

$

26,885

 

 

$

23,951

 

 

12%

Total revenues

 

 

8,385

 

 

 

8,865

 

 

(5%)

 

 

26,885

 

 

 

23,951

 

 

12%

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operation and maintenance

 

 

877

 

 

 

911

 

 

(4%)

 

 

2,575

 

 

 

2,998

 

 

(14%)

General and administrative

 

 

50

 

 

 

85

 

 

(41%)

 

 

222

 

 

 

242

 

 

(8%)

Depreciation and amortization

 

 

1,918

 

 

 

1,913

 

 

0%

 

 

5,765

 

 

 

5,744

 

 

0%

Gain on asset sales, net

 

 

(9

)

 

 

 

 

*

 

 

(35

)

 

 

 

 

*

Total costs and expenses

 

 

2,836

 

 

 

2,909

 

 

(3%)

 

 

8,527

 

 

 

8,984

 

 

(5%)

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

1,918

 

 

 

1,913

 

 

 

 

 

5,765

 

 

 

5,744

 

 

 

Adjustments related to capital

    reimbursement activity

 

 

(5

)

 

 

(5

)

 

 

 

 

(14

)

 

 

(14

)

 

 

Gain on asset sales, net

 

 

(9

)

 

 

 

 

 

 

 

(35

)

 

 

 

 

 

Segment adjusted EBITDA

 

$

7,453

 

 

$

7,864

 

 

(5%)

 

$

24,074

 

 

$

20,697

 

 

16%

________

* Not considered meaningful

Three months ended September 30, 2020. Segment adjusted EBITDA decreased $0.4 million compared to the three months ended September 30, 2019.

Nine months ended September 30, 2020.  Segment adjusted EBITDA increased $3.4 million compared to the nine months ended September 30, 2019 primarily due to the increase in volume throughput previously discussed.

 

Ohio Gathering.  The Ohio Gathering reportable segment includes OGC and OCC. We account for our investment in Ohio Gathering using the equity method and we recognize our proportionate share of earnings or loss in net income on a one-month lag based on the financial information available to us during the reporting period.

34


 

Gross volume throughput for Ohio Gathering, based on a one-month lag follows.

 

 

Ohio Gathering

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

Average daily throughput (MMcf/d)

 

 

512

 

 

 

777

 

 

(34%)

 

 

554

 

 

 

734

 

 

(25%)

Volume throughput for the Ohio Gathering system decreased compared to the three and nine months ended September 30, 2019 as a result of natural production declines on existing wells on the system and temporary production curtailments beginning in the second quarter of 2020, partially offset by the completion of new wells throughout 2019.

Financial data for our Ohio Gathering reportable segment, based on a one-month lag follows.

 

 

Ohio Gathering

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

 

 

(Dollars in thousands)

Proportional adjusted EBITDA for equity

    method investees

 

$

7,129

 

 

$

10,435

 

 

(32%)

 

$

22,582

 

 

$

29,584

 

 

(24%)

Segment adjusted EBITDA

 

$

7,129

 

 

$

10,435

 

 

(32%)

 

$

22,582

 

 

$

29,584

 

 

(24%)

Segment adjusted EBITDA for equity method investees decreased $3.3 million and $7.0 million compared to the three and nine months ended September 30, 2019 primarily as a result of the lower volume throughput described above.

Williston Basin.  The Polar and Divide, Bison Midstream, Meadowlark Midstream and Tioga Midstream (through March 22, 2019; refer to Note 15 – Dispositions and Restructuring for details on the sale of Tioga Midstream) systems provide our midstream services for the Williston Basin reportable segment. Volume throughput for our Williston Basin reportable segment follows.

 

 

Williston Basin

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

Aggregate average daily throughput -

   natural gas (MMcf/d)

 

 

14

 

 

 

9

 

 

56%

 

 

14

 

 

 

12

 

 

17%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Aggregate average daily throughput -

   liquids (Mbbl/d)

 

 

69

 

 

 

105

 

 

(34%)

 

 

81

 

 

 

101

 

 

(20%)

Natural gas. Natural gas volume throughput increased compared to the three and nine months ended September 30, 2019, primarily reflecting the completion of new wells behind the Bison Midstream system in the fourth quarter of 2019 and 2020 partially offset by natural production declines and the sale of Tioga Midstream.

Liquids. The decrease in liquids volume throughput compared to the three and nine months ended September 30, 2019, primarily associated with natural production declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic, partially offset by the completion of new wells throughout 2019 and 2020.

35


 

Financial data for our Williston Basin reportable segment follows.

 

 

Williston Basin

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

 

 

(Dollars in thousands)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

10,941

 

 

$

16,685

 

 

(34%)

 

$

47,145

 

 

$

58,076

 

 

(19%)

Natural gas, NGLs and condensate sales

 

 

4,957

 

 

 

1,878

 

 

164%

 

 

12,412

 

 

 

11,231

 

 

11%

Other revenues

 

 

3,137

 

 

 

2,555

 

 

23%

 

 

9,055

 

 

 

8,133

 

 

11%

Total revenues

 

 

19,035

 

 

 

21,118

 

 

(10%)

 

 

68,612

 

 

 

77,440

 

 

(11%)

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and NGLs

 

 

2,968

 

 

 

(93

)

 

(3291%)

 

 

5,572

 

 

 

3,668

 

 

52%

Operation and maintenance

 

 

5,658

 

 

 

8,578

 

 

(34%)

 

 

18,207

 

 

 

20,800

 

 

(12%)

General and administrative

 

 

351

 

 

 

405

 

 

(13%)

 

 

1,381

 

 

 

1,117

 

 

24%

Depreciation and amortization

 

 

6,481

 

 

 

4,788

 

 

35%

 

 

19,463

 

 

 

14,958

 

 

30%

(Gain) loss on asset sales, net

 

 

(12

)

 

 

1

 

 

*

 

 

(50

)

 

 

(1,142

)

 

*

Long-lived asset impairment

 

 

 

 

 

 

 

*

 

 

 

 

 

18

 

 

*

Total costs and expenses

 

 

15,446

 

 

 

13,679

 

 

13%

 

 

44,573

 

 

 

39,419

 

 

13%

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

6,481

 

 

 

4,788

 

 

 

 

 

19,463

 

 

 

14,958

 

 

 

Adjustments related to MVC shortfall

    payments

 

 

2,125

 

 

 

2,081

 

 

 

 

 

(1,416

)

 

 

(1,387

)

 

 

Adjustments related to capital

    reimbursement activity

 

 

(470

)

 

 

(469

)

 

 

 

 

(1,404

)

 

 

(1,244

)

 

 

(Gain) loss on asset sales, net

 

 

(12

)

 

 

1

 

 

 

 

 

(50

)

 

 

(1,142

)

 

 

Long-lived asset impairment

 

 

 

 

 

 

 

 

 

 

 

 

 

18

 

 

 

Segment adjusted EBITDA

 

$

11,713

 

 

$

13,840

 

 

(15%)

 

$

40,632

 

 

$

49,224

 

 

(17%)

_______

* Not considered meaningful

Three months ended September 30, 2020. Segment adjusted EBITDA decreased $2.1 million compared to the three months ended September 30, 2019 primarily due to lower liquids volume throughput on our systems as previously discussed.

Nine months ended September 30, 2020. Segment adjusted EBITDA decreased $8.6 million compared to the nine months ended September 30, 2019 primarily reflecting:

 

a decrease of $0.9 million of segment adjusted EBITDA contributed by the Tioga Midstream system compared to the nine months ended September 30, 2019 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower liquids volume throughput on our systems as previously discussed.

Other items to note:

 

On March 22, 2019, we sold the Tioga Midstream system and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the then carrying value for Tioga Midstream at closing. The financial results of Tioga Midstream are included in our unaudited condensed consolidated financial statements for the period from January 1, 2019 through March 22, 2019.

DJ Basin.  The Niobrara G&P systems provide midstream services for the DJ Basin reportable segment. Volume throughput for our DJ Basin reportable segment follows.

 

 

DJ Basin

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

Average daily throughput

    (MMcf/d)

 

 

27

 

 

 

33

 

 

(18%)

 

 

26

 

 

 

25

 

 

4%

36


 

Volume throughput increased compared to the nine months ended September 30, 2019, primarily as a result of ongoing drilling and completion activity across our service area and a more favorable volume and gathering rate mix from customers and the commissioning of our new natural gas processing plant in June 2019, partially offset by natural production declines and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

Financial data for our DJ Basin reportable segment follows.

 

 

DJ Basin

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

 

 

(Dollars in thousands)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

6,051

 

 

$

7,039

 

 

(14%)

 

$

18,134

 

 

$

14,784

 

 

23%

Natural gas, NGLs and condensate sales

 

 

17

 

 

 

93

 

 

(82%)

 

 

158

 

 

 

279

 

 

(43%)

Other revenues

 

 

826

 

 

 

735

 

 

12%

 

 

2,853

 

 

 

2,776

 

 

3%

Total revenues

 

 

6,894

 

 

 

7,867

 

 

(12%)

 

 

21,145

 

 

 

17,839

 

 

19%

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and NGLs

 

 

46

 

 

 

11

 

 

*

 

 

57

 

 

 

21

 

 

*

Operation and maintenance

 

 

2,352

 

 

 

1,781

 

 

32%

 

 

7,222

 

 

 

5,658

 

 

28%

General and administrative

 

 

245

 

 

 

54

 

 

354%

 

 

468

 

 

 

186

 

 

152%

Depreciation and amortization

 

 

1,558

 

 

 

775

 

 

101%

 

 

4,587

 

 

 

2,038

 

 

125%

Loss on asset sales, net

 

 

 

 

 

 

 

*

 

 

20

 

 

 

 

 

*

Long-lived asset impairment

 

 

 

 

 

 

 

*

 

 

3,692

 

 

 

34,759

 

 

*

Total costs and expenses

 

 

4,201

 

 

 

2,621

 

 

60%

 

 

16,046

 

 

 

42,662

 

 

(62%)

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

1,558

 

 

 

775

 

 

 

 

 

4,587

 

 

 

2,038

 

 

 

Adjustments related to capital

    reimbursement activity

 

 

515

 

 

 

533

 

 

 

 

 

1,618

 

 

 

69

 

 

 

Loss on asset sales, net

 

 

 

 

 

 

 

 

 

 

20

 

 

 

 

 

 

Long-lived asset impairment

 

 

 

 

 

 

 

 

 

 

3,692

 

 

 

34,759

 

 

 

Segment adjusted EBITDA

 

$

4,766

 

 

$

6,554

 

 

(27%)

 

$

15,016

 

 

$

12,043

 

 

25%

 

* Not considered meaningful

Three months ended September 30, 2020. Segment adjusted EBITDA decreased $1.8 million compared to the three months ended September 30, 2019, primarily reflecting:

 

a $1.0 million decrease in gathering services and related fees primarily due to natural production declines and limited drilling and completion activity associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic.

Nine months ended September 30, 2020. Segment adjusted EBITDA increased $3.0 million compared to the nine months ended September 30, 2019, primarily reflecting:

 

a $3.4 million increase in gathering services and related fees primarily due to the increase in volume throughput discussed above.

Other items to note:

 

During the nine months ended September 30, 2020 and 2019, we impaired certain long-lived assets in the DJ Basin (see Note 4 – Property, Plant and Equipment, Net). The impairment had no impact on segment adjusted EBITDA for the nine months ended September 30, 2020 and 2019.

 

Permian Basin.  The Summit Permian system provides our midstream services for the Permian Basin reportable segment. Volume throughput for our Permian Basin reportable segment follows.

37


 

 

 

Permian Basin

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

Average daily throughput (MMcf/d)

 

 

34

 

 

 

20

 

 

70%

 

 

33

 

 

 

17

 

 

94%

Volume throughput increased compared to the three months ended September 30, 2019, primarily as a result of an uptick in customer volumes, partially offset by natural production declines from wells previously put in service.

Financial data for our Permian Basin reportable segment follows.

 

 

Permian Basin

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

 

 

(In thousands)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

2,595

 

 

$

986

 

 

163%

 

$

7,617

 

 

$

1,938

 

 

293%

Natural gas, NGLs and condensate sales

 

 

4,803

 

 

 

3,797

 

 

26%

 

 

13,537

 

 

 

10,424

 

 

30%

Other revenues

 

 

168

 

 

 

102

 

 

65%

 

 

481

 

 

 

183

 

 

163%

Total revenues

 

 

7,566

 

 

 

4,885

 

 

55%

 

 

21,635

 

 

 

12,545

 

 

72%

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and NGLs

 

 

4,958

 

 

 

3,242

 

 

53%

 

 

12,798

 

 

 

9,369

 

 

37%

Operation and maintenance

 

 

1,658

 

 

 

1,338

 

 

24%

 

 

4,301

 

 

 

3,962

 

 

9%

General and administrative

 

 

57

 

 

 

95

 

 

(40%)

 

 

234

 

 

 

210

 

 

11%

Depreciation and amortization

 

 

1,370

 

 

 

1,312

 

 

4%

 

 

4,102

 

 

 

3,547

 

 

16%

(Gain) loss on asset sales, net

 

 

14

 

 

 

 

 

*

 

 

1

 

 

 

(120

)

 

*

Long-lived asset impairment

 

 

 

 

 

 

 

*

 

 

182

 

 

 

8

 

 

*

Total costs and expenses

 

 

8,057

 

 

 

5,987

 

 

35%

 

 

21,618

 

 

 

16,976

 

 

27%

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

1,370

 

 

 

1,312

 

 

 

 

 

4,102

 

 

 

3,547

 

 

 

(Gain) loss on asset sales, net

 

 

14

 

 

 

 

 

 

 

 

1

 

 

 

(120

)

 

 

Long-lived asset impairment

 

 

 

 

 

 

 

 

 

 

182

 

 

 

8

 

 

 

Segment adjusted EBITDA

 

$

893

 

 

$

210

 

 

*

 

$

4,302

 

 

$

(996

)

 

*

________

*Not considered meaningful

Three months ended September 30, 2020. Segment adjusted EBITDA increased $0.7 million compared to the three months ended September 30, 2019.

Nine months ended September 30, 2020. Segment adjusted EBITDA increased $5.3 million compared to the nine months ended September 30, 2019, primarily reflecting a $5.7 million increase in gathering services and related fees as a result of volume growth from ongoing drilling and completion activity and a more favorable volume and gathering rate mix from customers.

Piceance Basin.  The Grand River system provides midstream services for the Piceance Basin reportable segment. Volume throughput for our Piceance Basin reportable segment follows.

 

 

Piceance Basin

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

Aggregate average daily throughput

    (MMcf/d)

 

 

361

 

 

 

446

 

 

(19%)

 

 

370

 

 

 

464

 

 

(20%)

Volume throughput decreased compared to the three and nine months ended September 30, 2019, as a result of a natural production declines.

38


 

Financial data for our Piceance Basin reportable segment follows.

 

 

Piceance Basin

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

 

 

(Dollars in thousands)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

26,576

 

 

$

30,120

 

 

(12%)

 

$

79,987

 

 

$

92,515

 

 

(14%)

Natural gas, NGLs and condensate

    sales

 

 

528

 

 

 

1,733

 

 

(70%)

 

 

1,932

 

 

 

6,139

 

 

(69%)

Other revenues

 

 

1,233

 

 

 

1,258

 

 

(2%)

 

 

3,394

 

 

 

3,341

 

 

2%

Total revenues

 

 

28,337

 

 

 

33,111

 

 

(14%)

 

 

85,313

 

 

 

101,995

 

 

(16%)

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and NGLs

 

 

399

 

 

 

1,502

 

 

(73%)

 

 

1,176

 

 

 

4,255

 

 

(72%)

Operation and maintenance

 

 

6,073

 

 

 

7,273

 

 

(16%)

 

 

16,278

 

 

 

21,680

 

 

(25%)

General and administrative

 

 

196

 

 

 

128

 

 

53%

 

 

757

 

 

 

724

 

 

5%

Depreciation and amortization

 

 

11,305

 

 

 

11,798

 

 

(4%)

 

 

33,909

 

 

 

35,399

 

 

(4%)

(Gain) loss on asset sales, net

 

 

(94

)

 

 

 

 

*

 

 

(190

)

 

 

3

 

 

*

Total costs and expenses

 

 

17,879

 

 

 

20,701

 

 

(14%)

 

 

51,930

 

 

 

62,061

 

 

(16%)

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

11,305

 

 

 

11,798

 

 

 

 

 

33,909

 

 

 

35,399

 

 

 

Adjustments related to MVC

    shortfall payments

 

 

167

 

 

 

 

 

 

 

 

557

 

 

 

(103

)

 

 

Adjustments related to capital

    reimbursement activity

 

 

(333

)

 

 

(164

)

 

 

 

 

(865

)

 

 

(606

)

 

 

(Gain) loss on asset sales, net

 

 

(94

)

 

 

 

 

 

 

 

(190

)

 

 

3

 

 

 

Segment adjusted EBITDA

 

$

21,503

 

 

$

24,044

 

 

(11%)

 

$

66,794

 

 

$

74,627

 

 

(10%)

________

*Not considered meaningful

Three months ended September 30, 2020. Segment adjusted EBITDA decreased $2.5 million compared to the three months ended September 30, 2019, primarily reflecting:

 

 

a $3.5 million decrease in gathering services and related fees as a result of natural production declines.

 

a $1.2 million decrease in operation and maintenance expense primarily due to $0.8 million in lower compensation expense associated with lower headcount from our cost cutting initiatives.

Other items to note:

 

In December 2019, we sold certain assets from our Red Rock Gathering system for approximately $12 million. The financial contribution of these assets are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019.

Nine months ended September 30, 2020. Segment adjusted EBITDA decreased $7.8 million compared to the nine months ended September 30, 2019, primarily reflecting:

 

 

a $12.5 million decrease in gathering services and related fees as a result of natural production declines.

 

a $5.4 million decrease in operation and maintenance expense primarily due to $3.0 million in lower compensation expense associated with lower headcount from our cost cutting initiatives and a $1.3 million decrease in property taxes.

Other items to note:

 

In December 2019, we sold certain assets from our Red Rock Gathering system for $12 million. The financial contribution of these assets are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019.

39


 

Barnett Shale. The DFW Midstream system provides our midstream services for the Barnett Shale reportable segment. Volume throughput for our Barnett Shale reportable segment follows.

 

 

Barnett Shale

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

Average daily throughput (MMcf/d)

 

 

208

 

 

 

247

 

 

(16%)

 

 

215

 

 

 

255

 

 

(16%)

Volume throughput decreased compared to the three and nine months ended September 30, 2019 reflecting natural production declines, partially offset by new volumes from well completion activity through the third quarter of 2019.

Financial data for our Barnett Shale reportable segment follows.

 

 

Barnett Shale

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

 

 

(Dollars in thousands)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

10,545

 

 

$

11,286

 

 

(7%)

 

$

30,865

 

 

$

35,739

 

 

(14%)

Natural gas, NGLs and condensate sales

 

 

477

 

 

 

4,828

 

 

(90%)

 

 

7,206

 

 

 

11,705

 

 

(38%)

Other revenues (1)

 

 

1,399

 

 

 

1,706

 

 

(18%)

 

 

4,437

 

 

 

5,008

 

 

(11%)

Total revenues

 

 

12,421

 

 

 

17,820

 

 

(30%)

 

 

42,508

 

 

 

52,452

 

 

(19%)

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and NGLs

 

 

261

 

 

 

2,810

 

 

(91%)

 

 

3,342

 

 

 

7,384

 

 

(55%)

Operation and maintenance

 

 

4,810

 

 

 

5,567

 

 

(14%)

 

 

14,069

 

 

 

16,181

 

 

(13%)

General and administrative

 

 

351

 

 

 

201

 

 

75%

 

 

1,242

 

 

 

667

 

 

86%

Depreciation and amortization

 

 

3,795

 

 

 

3,810

 

 

(0%)

 

 

11,380

 

 

 

11,555

 

 

(2%)

(Gain) loss on asset sales, net

 

 

 

 

 

(350

)

 

*

 

 

17

 

 

 

(343

)

 

*

Long-lived asset impairment

 

 

 

 

 

 

 

*

 

 

4

 

 

 

10,236

 

 

*

Total costs and expenses

 

 

9,217

 

 

 

12,038

 

 

(23%)

 

 

30,054

 

 

 

45,680

 

 

(34%)

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

4,030

 

 

 

4,045

 

 

 

 

 

12,085

 

 

 

12,542

 

 

 

Adjustments related to MVC shortfall

    payments

 

 

 

 

 

1,453

 

 

 

 

 

 

 

 

4,358

 

 

 

Adjustments related to capital

    reimbursement activity

 

 

(29

)

 

 

(29

)

 

 

 

 

(85

)

 

 

(82

)

 

 

(Gain) loss on asset sales, net

 

 

 

 

 

(350

)

 

 

 

 

17

 

 

 

(343

)

 

 

Long-lived asset impairment

 

 

 

 

 

 

 

 

 

 

4

 

 

 

10,236

 

 

 

Segment adjusted EBITDA

 

$

7,205

 

 

$

10,901

 

 

(34%)

 

$

24,475

 

 

$

33,483

 

 

(27%)

________

*Not considered meaningful

(1) Includes the amortization expense associated with our favorable gas gathering contracts as reported in Other revenues.

Three months ended September 30, 2020. Segment adjusted EBITDA decreased $3.7 million compared to the three months ended September 30, 2019 primarily reflecting:

 

a $1.5 million decrease in adjustments related to MVC shortfall payments attributable to an MVC that expired in 2019, and a $2.9 million decrease in total revenues, less cost of natural gas and NGLs which primarily reflects lower volume throughput.

Other items to note:

 

Also impacting total revenues and cost of natural gas and NGLs for the three months ended September 30, 2020, was the presentation of certain gathering services as a reduction to cost of natural gas and NGLs and the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations that occurred in June 2019.

40


 

Nine months ended September 30, 2020. Segment adjusted EBITDA decreased $9.0 million compared to the nine months ended September 30, 2019 primarily reflecting:

 

a $4.4 million decrease in adjustments related to MVC shortfall payments attributable to an MVC that expired in 2019 and a $5.9 million decrease in total revenues less cost of natural gas and NGLs which primarily reflects lower volume throughput.

 

a $2.1 million decrease in various operation and maintenance expenses.

Other items to note:

 

 

In March 2019, we impaired certain long-lived assets in the Barnett Shale (see Note 4 – Property, Plant and Equipment, Net). The noncash impairment expense had no impact on segment adjusted EBITDA for the nine months ended September 30, 2019.

 

Also impacting total revenues and cost of natural gas and NGLs for the nine months ended September 30, 2020, was the presentation of certain gathering services as a reduction to cost of natural gas and NGLs and the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations that occurred in June 2019.

Marcellus Shale.  The Mountaineer Midstream system provides our midstream services for the Marcellus Shale reportable segment. Volume throughput for the Marcellus Shale reportable segment follows.

 

 

Marcellus Shale

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

Average daily throughput (MMcf/d)

 

 

396

 

 

 

349

 

 

13%

 

 

366

 

 

 

358

 

 

2%

Volume throughput increased compared to the three and nine months ended September 30, 2019 primarily due to additional drilling and completion activities, partially offset by natural production declines.

Financial data for our Marcellus Shale reportable segment follows.

 

 

Marcellus Shale

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

 

 

(Dollars in thousands)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

6,871

 

 

$

5,987

 

 

15%

 

$

19,034

 

 

$

18,081

 

 

5%

Total revenues

 

 

6,871

 

 

 

5,987

 

 

15%

 

 

19,034

 

 

 

18,081

 

 

5%

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operation and maintenance

 

 

771

 

 

 

783

 

 

(2%)

 

 

2,517

 

 

 

2,892

 

 

(13%)

General and administrative

 

 

69

 

 

 

237

 

 

(71%)

 

 

259

 

 

 

426

 

 

(39%)

Depreciation and amortization

 

 

2,298

 

 

 

2,286

 

 

1%

 

 

6,898

 

 

 

6,855

 

 

1%

Gain on asset sales, net

 

 

(8

)

 

 

 

 

*

 

 

(8

)

 

 

 

 

*

Goodwill impairment

 

 

 

 

 

16,211

 

 

*

 

 

 

 

 

16,211

 

 

*

Total costs and expenses

 

 

3,130

 

 

 

19,517

 

 

(84%)

 

 

9,666

 

 

 

26,384

 

 

(63%)

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

2,298

 

 

 

2,286

 

 

 

 

 

6,898

 

 

 

6,855

 

 

 

Goodwill impairment

 

 

 

 

 

16,211

 

 

 

 

 

 

 

 

16,211

 

 

 

Adjustments related to capital

    reimbursement activity

 

 

(9

)

 

 

(9

)

 

 

 

 

(28

)

 

 

(28

)

 

 

Gain on asset sales, net

 

 

(8

)

 

 

 

 

 

 

 

(8

)

 

 

 

 

 

Segment adjusted EBITDA

 

$

6,022

 

 

$

4,958

 

 

21%

 

$

16,230

 

 

$

14,735

 

 

10%

________

*Not considered meaningful

Three and nine months ended September 30, 2020. Segment adjusted EBITDA increased $1.1 million and $1.5

41


 

million compared to the three and nine months ended September 30, 2019.

Corporate and Other Overview for the Three and Nine Months Ended September 30, 2020 and 2019

Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, natural gas and crude oil marketing services, construction management fees related to the Double E Project, transaction costs and interest expense.

 

 

Corporate and Other

 

 

Three months ended September 30,

 

 

 

 

Nine months ended September 30,

 

 

 

 

 

2020

 

 

2019

 

 

Percentage

Change

 

2020

 

 

2019

 

 

Percentage

Change

 

 

(Dollars in thousands)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

$

644

 

 

 

534

 

 

21%

 

$

1,931

 

 

$

26,978

 

 

(93%)

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and NGLs

 

 

 

 

 

 

 

*

 

 

 

 

 

26,105

 

 

*

General and administrative

 

 

9,241

 

 

 

8,822

 

 

5%

 

 

35,344

 

 

 

35,404

 

 

(0%)

Transaction costs

 

 

726

 

 

 

129

 

 

463%

 

 

1,944

 

 

 

2,562

 

 

(24%)

Interest expense

 

 

19,018

 

 

 

23,462

 

 

(19%)

 

 

64,836

 

 

 

68,547

 

 

(5%)

Gain on early extinguishment of debt

 

 

(24,690

)

 

 

 

 

*

 

 

(78,925

)

 

 

 

 

*

________

* Not considered meaningful

Total Revenues. Total revenues attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services (primarily natural gas sales). The decrease of $25.0 million compared to nine months ended September 30, 2019, was attributable to lower natural gas, NGL and crude oil marketing activity.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services. The decrease of $26.1 million compared to nine months ended September 30, 2019, was attributable to lower marketing activity.

General and Administrative. General and administrative expense increased $0.4 million, compared to the three months ended September 30, 2019 and remained flat compared to the three and nine months ended September 30, 2019.

Transaction costs. The increase in transaction costs recognized during the three months ended September 30, 2020 compared to the three months ended September 30, 2019 was primarily due to costs associated with the GP Buy-In Transaction.

The decrease in transaction costs recognized during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 was due to financial advisory costs incurred in 2019.

Interest Expense. Interest expense decreased $4.4 million and $3.7 million, respectively, compared to the three and nine months ended September 30, 2019, primarily due to our liability management initiatives which included our Open Market Repurchases and Tender Offer Repurchases, partially offset by a higher outstanding balance on the Revolving Credit Facility.

Summarized Financial Information

On March 2, 2020, the SEC issued Final Rule Release No. 33-10762, Financial Disclosures about Guarantors and Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize a Registrant’s Securities (“Release 33-10762”), that amends the disclosure requirements related to certain registered securities that are guaranteed and those that are collateralized by the securities of an affiliate.

Under Release 33-10762, an SEC registrant may continue to omit separate financial statements of subsidiary issuers and guarantors when (1) the subsidiary issuer is consolidated with the parent company and its security is either (a) co-issued jointly and severally with the parent company’s security or (b) the subsidiary issuer’s security is fully and

42


 

unconditionally guaranteed by the parent company and (2) the parent company provides supplemental financial and non-financial disclosure about the subsidiary issuers and/or guarantors and the guarantees.

The rules become effective January 4, 2021, with voluntary compliance permitted immediately. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by SMLP and the Guarantor Subsidiaries (see Note 8 - Debt). SMLP has concluded that it is eligible to provide Alternative Disclosures under the amended disclosure requirements and has early adopted Release 33-10762 as of and for the nine months ended September 30, 2020.

The supplemental summarized financial information below reflects SMLP's separate accounts, the combined accounts of Summit Holdings and its 100% owned finance subsidiary, Finance Corp (the “Co-Issuers”) and the Guarantor Subsidiaries (the Co-Issuers and, together with the Guarantor Subsidiaries, the “Obligor Group”) for the dates and periods indicated. The financial information of the Obligor Group is presented on a combined basis and intercompany balances and transactions between the Co-Issuers and Guarantor Subsidiaries have been eliminated. There were no reportable transactions between the Co-Issuers and Obligor Group and the subsidiaries that were not issuers or guarantors of the Senior Notes.

Payments to holders of the Senior Notes are affected by the composition of and relationships among the Co-Issuers, the Guarantor Subsidiaries and Permian Holdco and Summit Permian Transmission, who are unrestricted subsidiaries of SMLP and are not issuers or guarantors of the Senior Notes. The assets of our unrestricted subsidiaries are not available to satisfy the demands of the holders of the Senior Notes. In addition, our unrestricted subsidiaries are subject to certain contractual restrictions related to the payment of dividends, and other rights in favor of their non-affiliated stakeholders, that limit their ability to satisfy the demands of the holders of the Senior Notes.

A list of each of SMLP’s subsidiaries that is a guarantor, issuer or co-issuer of our registered securities subject to the reporting requirements in Release 33-10762 is filed as Exhibit 22.1 to this Quarterly Report on Form 10-Q.

Summarized Balance Sheet Information. Summarized balance sheet information as of September 30, 2020 and December 31, 2019 follow.

 

 

September 30, 2020

 

 

 

SMLP

 

 

Obligor Group

 

 

 

(In thousands)

 

Assets

 

 

 

 

 

 

 

 

Current assets

 

$

5,719

 

 

$

124,603

 

Noncurrent assets

 

 

7,886

 

 

 

2,308,461

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

Current liabilities

 

$

10,173

 

 

$

60,721

 

Noncurrent liabilities

 

 

2,931

 

 

 

1,438,929

 

 

 

 

December 31, 2019

 

 

 

SMLP

 

 

Obligor Group

 

 

 

(In thousands)

 

Assets

 

 

 

 

 

 

 

 

Current assets

 

$

7,396

 

 

$

104,964

 

Noncurrent assets

 

 

9,835

 

 

 

2,389,032

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

Current liabilities

 

$

14,527

 

 

$

69,177

 

Noncurrent liabilities

 

 

163,163

 

 

 

1,514,250

 

Summarized Statements of Operations Information. For the purposes of the following summarized statements of operations, we allocate a portion of general and administrative expenses recognized at the SMLP parent to the Obligor Group to reflect what those entities' results would have been had they operated on a stand-alone basis. Summarized statements of operations for the nine months ended September 30, 2020 and for the year ended December 31, 2019 follow.

43


 

 

 

Nine months ended September 30, 2020

 

 

 

SMLP

 

 

Obligor Group

 

 

 

(In thousands)

 

Total revenues

 

$

 

 

$

287,063

 

Total costs and expenses

 

 

5,289

 

 

 

216,715

 

(Loss) income before income taxes and income from

  equity method investees

 

 

(5,120

)

 

 

95,818

 

Income from equity method investees

 

 

 

 

 

8,498

 

Net (loss) income

 

$

(6,612

)

 

$

104,316

 

 

 

 

Year ended December 31, 2019

 

 

 

SMLP

 

 

Obligor Group

 

 

 

(In thousands)

 

Total revenues

 

$

 

 

$

443,528

 

Total costs and expenses

 

 

8,719

 

 

 

397,939

 

Loss before income taxes and loss from

  equity method investees

 

 

(25,805

)

 

 

(28,840

)

Loss from equity method investees (1)

 

 

 

 

 

(336,950

)

Net loss

 

$

(27,036

)

 

$

(365,790

)

(1)

Amount includes a $329.7 million impairment of our equity method investment in Ohio Gathering and a $6.3 million impairment of long-lived assets in OCC.

44


 

Liquidity and Capital Resources

Distribution Suspension. On May 3, 2020, we suspended distributions to holders of our common units and suspended payments of distributions to holders of our Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020, to enable us to retain an incremental approximately $76 million of cash in the business annually, which we plan to use to de-lever the balance sheet, enhance liquidity and increase financial flexibility. The unpaid distributions on the Series A Preferred Units will continue to accrue. We expect to fund future capital expenditures with cash and cash equivalents on hand, cash flows generated from our operations, borrowings under our Revolving Credit Facility, future issuances of debt and equity securities and proceeds from potential asset divestitures. As of October 31, 2020, the amount of accrued and unpaid distributions on the Series A Preferred Units was $19.7million.

Exchange Offer. On June 18, 2020, the Partnership commenced the Exchange Offer. The Exchange Offer expired on July 28, 2020 and resulted in the Partnership exchanging 62,816 Series A Preferred Units for a total of 12,267,670 common units, net of units withheld for tax withholdings. Upon completion of the Exchange Offer, the Partnership has 237,184 Series A Preferred Units outstanding and holders of Series A Preferred Units who did not tender into the Exchange Offer retained their Series A Preferred Units with all the preferences and rights thereunder.

Term Loan Restructuring. On September 29, 2020, SMP Holdings and the Partnership entered into the TSA with an ad hoc group of the Term Loan Lenders that will result in the TL Restructuring, which includes (i) the Partnership’s cash payment of $26.5 million to the Term Loan Lenders, (ii) the execution of a strict foreclosure by the collateral agent under the SMPH Term Loan for the benefit of the Term Loan Lenders on the 34.6 million common units pledged as collateral to the SMPH Term Loan, and (iii) the payment of certain fees and expenses by the Partnership.  At the closing of the TL Restructuring, which is expected to occur during the quarterly period ended December 31, 2020, the SMPH Term Loan will be fully satisfied and cease to exist. Upon closing of the TL Restructuring we will recognize a gain equal to the difference between the face value of the cancelled debt and the fair value of the total consideration transferred, including unamortized debt issuance costs, and certain direct transaction costs related to the restructuring.  At September 30, 2020, the Partnership classified the SMPH Term Loan as current.  

Indebtedness Compliance. We are currently in compliance with all covenants contained in our Revolving Credit Facility and Senior Notes at September 30, 2020.  The Partnership’s total leverage ratio and senior secured leverage ratio (as defined in the Revolving Credit Agreement) were 4.9 to 1.0 and 2.7 to 1.0, respectively, relative to maximum threshold limits of 5.50 to 1.0 and 3.75 to 1.0. Given further deterioration of market conditions, decreased drilling activity, the deferral of well completions from customers, limitations on our ability to access the capital markets at a competitive cost to fund our capital expenditures and, on a limited scale, temporary production curtailments, we could have total leverage and senior secured leverage ratios that are higher than the levels prescribed in the applicable indebtedness agreements. Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations and cash flows.  

COVID-19 Impact. We are closely monitoring the impact of the outbreak of COVID-19 on all aspects of our business, including how it will impact our liquidity and capital resources. Considering the current commodity price backdrop and COVID-19 pandemic, we have collaborated extensively with our customer base over the past several months. Given continued volatility in market conditions since March 2020 and based on recently updated production forecasts and revised 2020 development plans from our customers, we currently expect our 2020 results to be affected by decreased drilling activity, the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin, DJ Basin and Utica Shale reportable segments. For example, beginning in June 2020, in the Utica Shale, a customer curtailed in excess of 150 MMcf/d of production which impacted volume throughput across our gathering system and the financial results of that segment through the middle of the third quarter of 2020, when more favorable natural gas prices returned and that customer reversed that particular production curtailment.  We also recently amended gathering contracts with two key Williston Basin customers to extend the terms of the gathering agreement acreage dedications, in exchange for a modest gathering fee concession. We expect 2020 total capital expenditures to range from $55 million to $65 million.

45


 

As we cannot predict the duration or scope of the COVID-19 pandemic and its impact on our customers and suppliers, the potential negative financial impact to our results cannot be reasonably estimated but could be material. We are actively managing the business to maintain cash flow and we have sufficient available liquidity. We believe that these factors will allow us to meet our anticipated funding requirements.

Capital Markets Activity

We had no capital markets activity resulting in new capital issuances during the nine months ended September 30, 2020. For additional information, see the "Liquidity and Capital Resources—Capital Markets Activity" section of MD&A included in the 2019 Annual Report.

Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility that matures in May 2022. As of September 30, 2020, the outstanding balance of the Revolving Credit Facility was $808.5 million and the unused portion totaled $437.4 million, after giving effect to the issuance thereunder of a $4.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of September 30, 2020 was approximately $191 million. There were no defaults or events of default during the nine months ended September 30, 2020, and, as of September 30, 2020, we were in compliance with the financial covenants in the Revolving Credit Facility.

Open Market Repurchases of Senior Notes. During the nine months ended September 30, 2020, the Partnership made Open Market Repurchases that resulted in the extinguishment of $32.4 million face value of the outstanding 2022 Senior Notes and $106.2 million face value of the 2025 Senior Notes. Total cash consideration paid to complete the Open Market Repurchases totaled $82.9 million and the Partnership recognized a $56.2 million gain on the extinguishment of debt during the nine months ended September 30, 2020.  

Tender Offers. In September 2020, the Co-Issuers completed the Tender Offers to purchase a portion of the 2022 and 2025 Senior Notes. Upon concluding the Tender Offers, the Partnership repurchased $33.5 million principal amount of the 2022 Senior Notes and $38.7 million principal amount of the 2025 Senior Notes. Total cash consideration paid to complete the Tender Offers totaled $48.7 million and the Partnership recognized a $23.3 million gain on the extinguishment of debt during the nine months ended September 30, 2020.

 ECP Loans. On August 7, 2020, we repaid all amounts outstanding under the ECP Loans which included $35 million of principal and $0.6 million of accrued interest. The ECP Loan repayment was financed in full with borrowings under our Revolving Credit Facility. We repaid the ECP Loans in order to eliminate certain restrictive covenants associated with the credit agreement and to take advantage of more favorable terms under the Revolving Credit Facility.

For additional information on our long-term debt, see Note 8 – Debt.

LIBOR Transition

LIBOR is the basic rate of interest widely used as a reference for setting the interest rates on loans globally. In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of large U.S. financial institutions, is considering replacing U.S. dollar LIBOR with a new index, the Secured Overnight Financing Rate (“SOFR”), calculated using short-term repurchase agreements backed by Treasury securities. We are evaluating the potential impact of the eventual replacement of the LIBOR benchmark interest rate, however, we are not able to predict whether LIBOR will cease to be available after 2021, whether SOFR will become a widely accepted benchmark in place of LIBOR, or what the impact of such a possible transition to SOFR may be on our business, financial condition and results of operations.

We will need to renegotiate our Revolving Credit Facility to determine the interest rate to replace LIBOR with the new standard that is established. The potential effect of any such event on interest expense cannot yet be determined.

46


 

Cash Flows

The components of the net change in cash and cash equivalents were as follows:

 

 

Nine months ended September 30,

 

 

 

2020

 

 

2019

 

 

 

(In thousands)

 

Net cash provided by operating activities

 

$

146,758

 

 

$

127,617

 

Net cash used in investing activities

 

 

(124,898

)

 

 

(65,287

)

Net cash provided by (used in) financing activities

 

 

(8,486

)

 

 

(68,277

)

Net change in cash, cash equivalents and restricted cash

 

$

13,374

 

 

$

(5,947

)

Operating activities. Cash flows from operating activities for the nine months ended September 30, 2020 primarily reflected:

 

a $12.5 million increase in accounts receivable related to the timing of invoicing and cash collections;

 

a $5.5 million increase in deferred revenue for cash receipts not yet recognized as revenue;

 

a $10.8 million decrease in accrued expenses primarily due to the timing of accrued payment obligations; and

 

other changes in working capital.

Investing activities. Cash flows used in investing activities during the nine months ended September 30, 2020 primarily reflected:

 

$92.1 million for investments in the Double E joint venture relating to the Double E Project; and

 

$35.3 million of capital expenditures primarily attributable to the DJ Basin of $11.3 million, the Williston Basin of $8.4 million and Summit Permian of $6.3 million.

Cash flows used in investing activities during the nine months ended September 30, 2019 primarily reflected:

 

$151.7 million of capital expenditures primarily attributable to the ongoing development of the DJ Basin of $66.8 million, Summit Permian of $43.4 million, the Williston Basin of $20.3 million and Corporate and Other, which includes $15.4 million of capital expenditures relating to the Double E Project;

 

$89.5 million of net proceeds from the Tioga Midstream sale;

 

$7.3 million for a distribution from an equity method investment; and

 

$11.3 million for an investment in an equity method investee.

Financing activities. Cash flows used in financing activities during the nine months ended September 30, 2020 primarily reflected:

 

$165.5 million of borrowings under our Revolving Credit Facility;

 

$48.7 million of net proceeds from the issuance of Subsidiary Series A Preferred Units;

 

$35.0 million of net borrowings under ECP Loans;

 

$82.8 million for Open Market Repurchases;

 

$48.7 million for Tender Offers;

 

$41.8 million to purchase common units in the GP Buy-In Transaction;

 

$35.0 million for the repayment of ECP Loans;

 

$34.0 million for repayments under our Revolving Credit Facility;

 

$6.3 million for repayments on the SMPH Term Loan; and

47


 

 

$6.0 million of distributions to noncontrolling interest SMLP unitholders.

Cash flows used in financing activities during the nine months ended September 30, 2019 primarily reflected:

 

$149.7 million of distributions; and

 

$126.0 million of borrowings under our Revolving Credit Facility; and

 

$131.0 million for repayments under our Revolving Credit Facility.

Contractual Obligations Update

Double E Project

We are leading the development, permitting and construction of the Double E Project and will operate the pipeline upon its commissioning. At our current 70% interest, we estimate that our share of the capital expenditures required to develop the Double E Project will total approximately $300 million. Assuming timely receipt of the required regulatory approvals and no material delays in construction, we expect that the Double E Project will be placed into service in the fourth quarter of 2021.

Capital Requirements

Our business is capital intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our Partnership Agreement requires that we categorize our capital expenditures as either:

 

maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or

 

expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

For the nine months ended September 30, 2020, cash paid for capital expenditures totaled $35.3 million and included $11.0 million of maintenance capital expenditures. For the nine months ended September 30, 2020, there were no contributions to Ohio Gathering and we contributed $92.1 million to Double E (see Note 6 – Equity Method Investments).

We rely primarily on internally generated cash flow as well as external financing sources, including commercial bank borrowings and the issuance of debt, equity and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures. We believe that our Revolving Credit Facility, together with internally generated cash flow and access to debt or equity capital markets, will be adequate to finance our business for the foreseeable future without adversely impacting our liquidity.

Considering the current commodity price backdrop and COVID-19 pandemic, we will remain disciplined with respect to future capital expenditures, which will be primarily concentrated on the Double E Project and accretive expansions of our existing systems in our Core Focus Areas. We continue to advance our financing plans for our equity interest in Double E, which we intend to be credit positive to SMLP. We are currently targeting a financing structure that limits additional cash investments made by SMLP beyond 2020, and which shifts a substantial majority of our Double E capital commitments to third parties.

There are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach agreements with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and natural gas liquids industries and markets and (iii) our ability to obtain financing from commercial banks, the capital markets, or other financing sources.

48


 

Credit and Counterparty Concentration Risks

We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.

Certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customers’ wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers’ commodities flow and, in many cases, the only way for our customers to get their production to market.

We have exposure due to nonperformance under our MVC contracts whereby a potential customer, does not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the nine months ended September 30, 2020.

Critical Accounting Estimates

We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. There have been no changes to our significant accounting policies since December 31, 2019.

49


 

Forward-Looking Statements

Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officers and employees during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this report.

Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph. These risks and uncertainties include, among others:

 

our decision whether to pay, or our ability to grow, our cash distributions;

 

fluctuations in natural gas, NGLs and crude oil prices, including as of a result of political or economic measures taken by various countries or OPEC;

 

the extent and success of our customers' drilling efforts, as well as the quantity of natural gas, crude oil and produced water volumes produced within proximity of our assets;

 

the current and potential future impact of the COVID-19 pandemic on our business, results of operations, financial position or cash flows;

 

failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects;

 

competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems;

 

actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers;

 

our ability to divest of certain of our assets or joint ventures to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets;

 

the effectiveness of the Reverse Unit Split for regaining and maintaining compliance with the continued listing standards of the NYSE;

 

the ability to attract and retain key management personnel;

 

commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets;

 

changes in the availability and cost of capital and the results of our financing efforts, including availability of funds in the credit and/or capital markets;

 

restrictions placed on us by the agreements governing our debt and preferred equity instruments;

 

the availability, terms and cost of downstream transportation and processing services;

 

natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control;

50


 

 

operational risks and hazards inherent in the gathering, compression, treating and/or processing of natural gas, crude oil and produced water;

 

weather conditions and terrain in certain areas in which we operate;

 

any other issues that can result in deficiencies in the design, installation or operation of our gathering, compression, treating and processing facilities;

 

timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule;

 

our ability to finance our obligations related to capital expenditures, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results;

 

the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation;

 

the ability to meet obligations under the SMPH Term Loan;

 

changes in tax status;

 

the effects of litigation;

 

changes in general economic conditions; and

 

certain factors discussed elsewhere in this report.

Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common units, preferred units and senior notes.

The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

Our current interest rate risk exposure is largely related to our debt portfolio. As of September 30, 2020, we had approximately $589.1 million principal of fixed-rate Senior Notes, $808.5 million outstanding under our variable rate Revolving Credit Facility and $155.2 million principal of variable rate debt on the SMPH Term Loan (see Note 8 - Debt). While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our Revolving Credit Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. Our current interest rate risk exposure has not changed materially since December 31, 2019. For additional information, see the "Interest Rate Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2019 Annual Report.

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Commodity Price Risk

We currently generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, some of which include MVCs and most of which include areas of mutual interest. Our direct commodity price exposure relates to (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds and other processing arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. Our gathering agreements with certain DFW Midstream customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. Our gathering agreements with our Grand River customers permit us to retain condensate volumes from the Grand River system gathering lines. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 Index. By basing the power prices on a system and basin-relevant market, like the Henry Hub Index, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales. We do not enter into risk management contracts for speculative purposes. Our current commodity price risk exposure has not changed materially since December 31, 2019. For additional information, see the "Commodity Price Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2019 Annual Report.

Item 4. Controls and Procedures.

Under the direction of our General Partner's Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and internal control over financial reporting and concluded that (i) our disclosure controls and procedures were effective as of September 30, 2020 and (ii) no change in internal control over financial reporting occurred during the quarter ended September 30, 2020, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any significant legal or governmental proceedings. In addition, we are not aware of any significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protection statutes to which we are subject, except as noted in Note 14 – Commitments and Contingencies and in the 2019 Annual Report, which is incorporated herein by reference.

Item 1A. Risk Factors.

The risk factors contained in the Item 1A. Risk Factors of the 2019 Annual Report, the Item 1A. Risk Factors of our quarterly report on Form 10-Q for the three months ended March 31, 2020, as filed with the SEC on May 8, 2020, and the Item 1A. Risk Factors of our quarterly report on Form 10-Q for the three months ended June 30, 2020, as filed with the SEC on August 7, 2020 are incorporated herein by reference except to the extent they address risks arising from or relating to the failure of events described therein to occur, which events have since occurred.

Risks Relating to COVID-19

The COVID-19 pandemic, coupled with other current pressures on oil and gas prices resulting from the OPEC price war, has had, and is expected to continue to have, an adverse impact on our business, results of operations, financial position and cash flows.

The ongoing coronavirus (COVID-19) outbreak continues to be a rapidly evolving situation. As of November 3, 2020, the CDC had recorded over 9.2 million cases in the United States and over 230,000 deaths, and the pandemic has resulted in a massive increase in the U.S. unemployment rate. The pandemic has resulted in widespread adverse impacts on the global economy and on our business, including our customers, employees, supply chain, and distribution network. We are currently unable to predict the ultimate impact that it may have on our business, future results of operations, financial position or cash flows. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the ability of pharmaceutical companies to develop effective and safe vaccines and therapeutic drugs. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.

In response to the COVID-19 pandemic, we have modified our business practices, including restricting employee travel, modifying employee work locations, implementing social distancing and enhancing sanitary measures in our facilities. Many of our suppliers, vendors and service providers have made similar modifications. The resources available to employees working remotely may not enable them to maintain the same level of productivity and efficiency, and these and other employees may face additional demands on their time. Our increased reliance on remote access to our information systems increases our exposure to potential cybersecurity breaches. We may take further actions as government authorities require or recommend or as we determine to be in the best interests of our employees, customers, partners and suppliers. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus, in which case our employees may become sick, our ability to perform critical functions could be harmed, and we may be unable to respond to the needs of our business. The resumption of normal business operations after such interruptions may be delayed or constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers.

In the midst of the ongoing COVID-19 pandemic, oil prices declined significantly due to potential increases in supply emanating from a disagreement on production cuts among members of OPEC and certain non-OPEC, oil-producing countries and subsequent hydrocarbon commodity price declines. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. For example, we have experienced a $5.2 million decrease in gathering services and related fees in the Williston Basin primarily due to lower liquids throughput associated in part with a decrease in demand resulting from the COVID-19 pandemic. These industry conditions, coupled with those resulting

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from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April to cut production, extend cuts again in June and cut its long-term forecast for oil demand growth in October, there is no assurance that the agreement will continue to be observed by its members, and the responses of oil and gas producers to the lower demand for, and price of, natural gas, NGLs and crude oil are constantly evolving and remain uncertain. After increasing supply through the summer of 2020, certain OPEC members recently announced price cuts for October, potentially signaling continued pressure on demand. Such responses could cause our pipelines and storage tanks to reach capacity, thereby forcing producers to experience shut-ins or look to alternative methods of transportation for their products. In addition, the dramatic decrease in oil and gas prices could have substantial negative implications for our revenue sources that are related to or underpinned by commodity prices. As a result, these factors could have a material adverse effect on our business, future results of operations, financial position or cash flows. At this point, we cannot accurately predict what effects current market conditions due to the COVID-19 pandemic and failed OPEC negotiations will have on our business, which will depend on, among other factors, the ultimate geographic spread of the virus, the duration of the outbreak and the extent and overall economic effects of the governmental response to the pandemic.

The impact of COVID-19 and the OPEC price war may also exacerbate other risks discussed in Item 1A of the 2019 Annual Report, any of which could have a material effect on us. This situation is changing rapidly, and additional impacts may arise that we are not aware of currently.

Risks Related to Our Business

If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common units, which would have an adverse impact on the trading volume, liquidity and market price of our common units.

We received a formal notice from the NYSE on April 10, 2020 indicating noncompliance with the continued listing standard set forth in Rule 802.01C of the NYSE Listed Company Manual because the average closing price of our common units had fallen below $1.00 per unit over a period of 30 consecutive trading days, which is the minimum average unit price for continued listing on the NYSE. We have until December 19, 2020 to regain compliance with the minimum unit price requirement, with the possibility of extension at the discretion of the NYSE. In order to regain compliance, on the last trading day in any calendar month during the cure period, the common units must have: (i) a closing price of at least $1.00 per unit and (ii) an average closing price of at least $1.00 per unit over the 30 trading day period ending on the last trading day of such month. On October 15, 2020 the Board approved a 1-for-15 reverse split of the Partnership’s common units, effective as of 6:01 p.m., New York City time, on November 9, 2020 in order to, among other things, increase the per-unit trading price of the Partnership’s common units to satisfy the $1.00 minimum bid price requirement for continued listing on the NYSE.

If we fail to regain compliance with Section 802.01C of the NYSE Listed Company Manual by the end of the cure period, the common units will be subject to the NYSE’s suspension and delisting procedures. If the common units ultimately were to be delisted for any reason, it could negatively impact us as it would likely reduce the liquidity and market price of the common units, reduce the number of investors willing to hold or acquire the common units and negatively impact our ability to access equity markets and obtain financing.

Our Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.

The Series A Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future.

In addition, (i) prior to December 15, 2022, distributions on the Series A Preferred Units accumulate and are cumulative at the rate of 9.50% per annum of $1,000, the liquidation preference of the Series A Preferred Units and (ii) on and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of $1,000 equal to the three-month LIBOR plus a spread of 7.43%. On May 3, 2020, we announced the suspension of distributions payable on both our common units and our Series A Preferred Units. We did not make a distribution on our common units with respect to the first quarter of 2020, nor did we make a distribution on our Series A Preferred Units on June 15, 2020. As of October 30, 2020, the amount of accrued and

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unpaid distributions on the Series A Preferred Units was $19.7 million. Unpaid distributions on the Series A Preferred Units will continue to accrue.

In addition, our Subsidiary Series A Preferred Units issued by Permian Holdco have priority over the common unitholders with respect to the cash flow from Permian Holdco. The distribution rate of the Subsidiary Series A Preferred Units is 7.00% per annum of the $1,000 issue amount per outstanding Subsidiary Series A Preferred Unit. Permian Holdco has the option to pay this distribution in-kind until the earlier of June 30, 2022 or the first full quarter following the date the Double E pipeline is placed in service.

Our obligation to pay distributions on our Series A Preferred Units and Permian Holdco’s obligation to pay the distributions on the Subsidiary Series A Preferred Units could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Our obligations to the holders of the Series A Preferred Units and Permian Holdco’s obligations to the holders of the Subsidiary Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to an organization that is exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income (“UBTI”) and will be taxable to the exempt organization as UBTI on the exempt organization’s tax return in the year the exempt organization is allocated the income. Under the Tax Cuts and Jobs Act (the “Tax Reform Legislation”), an exempt organization is required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and applicable state tax returns and pay tax on their share of our taxable income.

Under the Tax Reform Legislation, if a unitholder sells or otherwise disposes of a common unit, the transferee is required to withhold 10.0% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the U.S. Treasury and the IRS have suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our common units, that occur before January 1, 2022. Under recently finalized Treasury Regulations, such withholding will be required on open market transactions, but in the case of a transfer made through a broker, a partner’s share of liabilities will be excluded from the amount realized. In addition, the obligation to withhold will be imposed on the broker instead of the transferee (and we will generally not be required to withhold from the transferee amounts that should have been withheld by the transferee but were not withheld). These withholding obligations will apply to transfers of our common units occurring on or after January 1, 2022.

 

Item 5. Other Information.

None.

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Item 6. Exhibits.

 

Exhibit number

 

Description

  3.1

 

Fourth Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated May 28, 2020 (Incorporated herein by reference to Exhibit 3.1 to SMLP’s Current Report on Form 8-K dated June 2, 2020 (Commission File No. 001-35666))

  3.2

 

Second Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated May 28, 2020 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K filed June 2, 2020 (Commission File No. 001-35666))

   3.3

 

Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))

   3.4

 

Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))

10.1

 

Amendment to Warrants to Purchase Common Units, dated August 7, 2020, by and among Summit Midstream Partners, LP, SMP TopCo, LLC and SMLP Holdings, LLC (Incorporated herein by reference to Exhibit 10.11 to SMLP’s Quarterly Report on Form 10-Q dated August 7, 2020 (Commission File No. 001-34666))

10.2

***

Transaction Support Agreement, dated September 29, 2020, by and among Summit Midstream Partners Holdings, LLC, Summit Midstream Partners, LLC, Summit Midstream Partners, LP and the Initial Directing Lenders listed therein (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated September 30, 2020 (Commission File No. 001-34666))

10.3

*

Separation and General Release Agreement, effective as of August 7, 2020, by and between Summit Midstream Partners, LP and Brock Degeyter

10.4

*

Employment Agreement, effective as of September 4, 2020, by and between Summit Midstream Partners, LP and James Johnston

22.1

 

Summit Midstream Partners, LP Subsidiary Issuers and Guarantors of Registered Securities (Incorporated herein by reference to Exhibit 22.1 to SMLP's Report on Form 10-Q filed May 8, 2020 (Commission File No. 001-35666)

31.1

 

Rule 13a-14(a)/15d-14(a) Certification, executed by Heath Deneke, President, Chief Executive Officer and Director

31.2

 

Rule 13a-14(a)/15d-14(a) Certification, executed by Marc D. Stratton, Executive Vice President and Chief Financial Officer

32.1

 

Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Heath Deneke, President, Chief Executive Officer and Director, and Marc D. Stratton, Executive Vice President and Chief Financial Officer

101.INS

**

Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH

**

Inline XBRL Taxonomy Extension Schema

101.CAL

**

Inline XBRL Taxonomy Extension Calculation Linkbase

101.DEF

**

Inline XBRL Taxonomy Extension Definition Linkbase

101.LAB

**

Inline XBRL Taxonomy Extension Label Linkbase

101.PRE

**

Inline XBRL Taxonomy Extension Presentation Linkbase

104

**

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* Filed herewith.

** Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. The financial information contained in the XBRL (eXtensible Business Reporting Language)-related documents is unaudited and unreviewed.

*** Certain portions of this exhibit have been omitted pursuant to Item 601(b)(10) of Regulation S-K. The Partnership agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

Summit Midstream Partners, LP

 

 

 

(Registrant)

 

 

 

By: Summit Midstream GP, LLC (its General Partner)

 

 

November 6, 2020

/s/ Marc D. Stratton

 

 

 

Marc D. Stratton, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

 

 

57

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