Summit Midstream Partners, LP - Quarter Report: 2019 June (Form 10-Q)

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 June 30, 2019

☐ 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.)

1790 Hughes Landing Blvd, Suite 500

The Woodlands, TX

(Address of principal executive offices)

77380

(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 Securities 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 July 31, 2019
Common Units		82,704,891 units

TABLE OF CONTENTS

COMMONLY USED OR DEFINED TERMS		2

PART I	FINANCIAL INFORMATION	4
Item 1.	Financial Statements.	4
	Unaudited Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018	4
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2019 and 2018	5
	Unaudited Condensed Consolidated Statements of Partners' Capital for the three and six months ended June 30, 2019 and 2018	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2019 and 2018	7
	Notes to Unaudited Condensed Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	32
Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	53
Item 4.	Controls and Procedures.	54

PART II	OTHER INFORMATION	55
Item 1.	Legal Proceedings.	55
Item 1A.	Risk Factors.	55
Item 6.	Exhibits.	56

SIGNATURES		57

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
5.5% Senior Notes	Summit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August 2022
5.75% 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; also referred to as DPPO
DFW Midstream	DFW Midstream Services LLC
DJ Basin	Denver-Julesburg Basin
Double E	Double E Pipeline, LLC
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; also known as the Sponsor
Epping	Epping Transmission Company, LLC
EPU	earnings or loss per unit
Equity Restructuring	A series of transactions consummated on March 22, 2019, pursuant to which the Partnership cancelled its IDRs and converted its 2% economic GP interest to a non-economic GP interest in exchange for 8,750,000 SMLP common units, which were issued to SMP Holdings
FASB	Financial Accounting Standards Board
Finance Corp.	Summit Midstream Finance Corp.
GAAP	accounting principles generally accepted in the United States of America
GP	general partner
General Partner	Summit Midstream GP, LLC
Guarantor Subsidiaries	Bison Midstream and its subsidiaries, Grand River and its subsidiary, DFW Midstream, Summit Marketing, Summit Permian, Permian Finance, Summit Niobrara, OpCo, Summit Utica, Meadowlark Midstream, Summit Permian II and Summit Permian Transmission
Grand River	Grand River Gathering, LLC
IDR	incentive distribution rights
LIBOR	London Interbank Offered Rate
Mbbl	one thousand barrels
Mbbl/d	one thousand barrels per day
Mcf	one thousand cubic feet
MD&A	Management's Discussion and Analysis of Financial Condition and Results of Operations
Meadowlark Midstream	Meadowlark Midstream Company, LLC
MMcf	one million cubic feet
MMcf/d	one million cubic feet per day
Mountaineer Midstream	Mountaineer Midstream gathering system
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.
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
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
Project	In June 2019, we announced a final investment decision to proceed with 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
Red Rock Gathering	Red Rock Gathering Company, LLC
Remaining Consideration	the consideration to be paid to SMP Holdings in 2020 in connection with the 2016 Drop Down, the present value of which is reflected on our balance sheets as the Deferred Purchase Price Obligation
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 and by the Second Amendment to Third Amended and Restated Credit Agreement dated as of June 26, 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) the change in the Deferred Purchase Price Obligation fair value, (viii) impairments and (ix) other noncash expenses or losses, less other noncash income or gains
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 LTIP	SMLP Long-Term Incentive Plan
SMP Holdings	Summit Midstream Partners Holdings, LLC
Sponsor	Energy Capital Partners II, LLC and its parallel and co-investment funds; also known as Energy Capital Partners
Summit Holdings	Summit Midstream Holdings, LLC
Summit Investments	Summit Midstream Partners, LLC
Summit Niobrara	Summit Midstream Niobrara, 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
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

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,		December 31,
	2019		2018
	(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents	$	535	$	4,345
Accounts receivable		84,125		97,936
Other current assets		2,011		3,971
Total current assets		86,671		106,252
Property, plant and equipment, net		1,878,851		1,963,713
Intangible assets, net		251,250		273,416
Goodwill		16,211		16,211
Investment in equity method investees		653,807		649,250
Other noncurrent assets		10,912		11,720
Total assets	$	2,897,702	$	3,020,562

Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	25,252	$	38,414
Accrued expenses		8,759		21,963
Due to affiliate		387		240
Deferred revenue		12,325		11,467
Ad valorem taxes payable		6,737		10,550
Accrued interest		12,381		12,286
Accrued environmental remediation		2,561		2,487
Other current liabilities		11,949		12,645
Deferred Purchase Price Obligation		292,073		—
Total current liabilities		372,424		110,052
Long-term debt		1,365,564		1,257,731
Noncurrent Deferred Purchase Price Obligation		—		383,934
Noncurrent deferred revenue		40,201		39,504
Noncurrent accrued environmental remediation		2,841		3,149
Other noncurrent liabilities		9,557		4,968
Total liabilities		1,790,587		1,799,338
Commitments and contingencies (Note 16)

Series A Preferred Units (300,000 units issued and outstanding at June 30, 2019 and December 31, 2018)		293,616		293,616
Common limited partner capital (82,704,891 units issued and outstanding at June 30, 2019 and 73,390,853 units issued and outstanding at December 31, 2018)		813,499		902,358
General Partner interests (zero units issued and outstanding at June 30, 2019 and 1,490,999 units issued and outstanding at December 31, 2018)		—		25,250
Total partners' capital		1,107,115		1,221,224
Total liabilities and partners' capital	$	2,897,702	$	3,020,562

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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	75,107		$	89,585		$	162,071		$	173,946
Natural gas, NGLs and condensate sales		18,291			31,891			56,219			58,008
Other revenues		6,288			6,707			12,804			13,549
Total revenues		99,686			128,183			231,094			245,503
Costs and expenses:
Cost of natural gas and NGLs		11,571			24,384			43,330			44,670
Operation and maintenance		23,718			24,466			47,940			49,070
General and administrative		10,214			13,484			27,495			27,926
Depreciation and amortization		26,800			26,784			54,527			53,461
Transaction costs		—			—			950			—
(Gain) loss on asset sales, net		(287	)		62			(1,248	)		(12	)
Long-lived asset impairment		70			587			45,021			587
Total costs and expenses		72,086			89,767			218,015			175,702
Other income		83			27			292			20
Interest expense		(17,941	)		(14,837	)		(35,468	)		(29,959	)
Deferred Purchase Price Obligation		(3,712	)		(69,305	)		(8,139	)		(90,963	)
Income (loss) before income taxes and loss from equity method investees		6,030			(45,699	)		(30,236	)		(51,101	)
Income tax expense		(1,142	)		(294	)		(1,349	)		(123	)
Loss from equity method investees		(79	)		(3,920	)		(520	)		(2,534	)
Net income (loss)	$	4,809		$	(49,913	)	$	(32,105	)	$	(53,758	)
Less:
Net income attributable to noncontrolling interest		—			58			—			143
Net income (loss) attributable to SMLP		4,809			(49,971	)		(32,105	)		(53,901	)
Net income attributable to General Partner, including IDRs		—			1,140			12			3,198
Net income (loss) attributable to limited partners		4,809			(51,111	)		(32,117	)		(57,099	)
Net income attributable to Series A Preferred Units		7,125			7,125			14,250			14,250
Net loss attributable to common limited partners	$	(2,316	)	$	(58,236	)	$	(46,367	)	$	(71,349	)

Loss per limited partner unit:
Common unit – basic	$	(0.03	)	$	(0.79	)	$	(0.58	)	$	(0.97	)
Common unit – diluted	$	(0.03	)	$	(0.79	)	$	(0.58	)	$	(0.97	)

Weighted-average limited partner units outstanding:
Common units – basic		82,700			73,356			79,266			73,245
Common units – diluted		82,700			73,356			79,266			73,245

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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

	Partners' capital
	Limited partners
	Series A Preferred Units			Common			General Partner			Total
	(In thousands)
Partners' capital, January 1, 2019	$	293,616		$	902,358		$	25,250		$	1,221,224
Net income (loss)		7,125			(44,051	)		12			(36,914	)
Conversion of General Partner economic interests		—			22,222			(22,222	)		—
Distributions to unitholders		—			(42,241	)		(3,040	)		(45,281	)
Unit-based compensation		—			2,526			—			2,526
Tax withholdings on vested SMLP LTIP awards		—			(2,522	)		—			(2,522	)
Partners' capital, March 31, 2019		300,741			838,292			—			1,139,033
Net income (loss)		7,125			(2,316	)		—			4,809
Distributions to unitholders		(14,250	)		(23,775	)		—			(38,025	)
Unit-based compensation		—			1,393			—			1,393
Tax withholdings on vested SMLP LTIP awards		—			(95	)		—			(95	)
Partners' capital, June 30, 2019	$	293,616		$	813,499		$	—		$	1,107,115

	Partners' capital
	Limited partners
	Series A Preferred Units			Common			General Partner			Noncontrolling interest		Total
	(In thousands)
Partners' capital, December 31, 2017, as reported	$	294,426		$	1,056,510		$	27,920		$	10,813	$	1,389,669
January 1, 2018 impact of Topic 606 day 1 adoption		—			4,130			84			—		4,214
Partners' capital, January 1, 2018		294,426			1,060,640			28,004			10,813		1,393,883
Net income (loss)		7,125			(13,113	)		2,058			85		(3,845	)
Distributions to unitholders		—			(42,024	)		(3,029	)		—		(45,053	)
Unit-based compensation		—			1,979			—			—		1,979
Tax withholdings on vested SMLP LTIP awards		—			(1,943	)		—			—		(1,943	)
Other		(810	)		(130	)		—			—		(940	)
Partners' capital, March 31, 2018		300,741			1,005,409			27,033			10,898		1,344,081
Net income (loss)		7,125			(58,236	)		1,140			58		(49,913	)
Distributions to unitholders		(14,250	)		(42,180	)		(3,036	)		—		(59,466	)
Unit-based compensation		—			2,004			—			—		2,004
Tax withholdings on vested SMLP LTIP awards		—			103			—			—		103
Other		—			(1	)		—			—		(1	)
Partners' capital, June 30, 2018	$	293,616		$	907,099		$	25,137		$	10,956	$	1,236,808

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

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six months ended June 30,
	2019			2018
	(In thousands)
Cash flows from operating activities:
Net loss	$	(32,105	)	$	(53,758	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		55,279			53,160
Noncash lease expense		1,530			—
Amortization of debt issuance costs		2,175			2,086
Deferred Purchase Price Obligation		8,139			90,963
Unit-based and noncash compensation		4,079			4,223
Loss from equity method investees		520			2,534
Distributions from equity method investees		18,217			17,124
Gain on asset sales, net		(1,248	)		(12	)
Long-lived asset impairment		45,021			587
Changes in operating assets and liabilities:
Accounts receivable		13,237			(6,265	)
Trade accounts payable		(1,463	)		(3,483	)
Accrued expenses		(12,537	)		6,934
Due from (to) affiliate		147			(997	)
Deferred revenue, net		2,007			3,281
Ad valorem taxes payable		(3,265	)		(1,825	)
Accrued interest		95			(51	)
Accrued environmental remediation, net		(1,001	)		(1,805	)
Other, net		(2,581	)		(2,647	)
Net cash provided by operating activities		96,246			110,049
Cash flows from investing activities:
Capital expenditures		(111,092	)		(90,394	)
Proceeds from asset sale (net of cash of $1,475 for the six months ended June 30, 2019)		89,761			496
Distribution from equity method investment		7,252			—
Investment in equity method investee		(5,921	)		—
Other, net		(160	)		(306	)
Net cash used in investing activities		(20,160	)		(90,204	)

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)

	Six months ended June 30,
	2019			2018
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders		(69,056	)		(90,269	)
Distributions to Series A Preferred unitholders		(14,250	)		(14,250	)
Borrowings under Revolving Credit Facility		233,000			148,000
Repayments under Revolving Credit Facility		(126,000	)		(53,000	)
Repayment of Deferred Purchase Price Obligation		(100,000	)		—
Debt issuance costs		(56	)		(121	)
Other, net		(3,534	)		(3,423	)
Net cash used in financing activities		(79,896	)		(13,063	)
Net change in cash and cash equivalents		(3,810	)		6,782
Cash and cash equivalents, beginning of period		4,345			1,430
Cash and cash equivalents, end of period	$	535		$	8,212

Supplemental cash flow disclosures:
Cash interest paid	$	37,506		$	30,962
Less capitalized interest		4,361			3,085
Interest paid (net of capitalized interest)	$	33,145		$	27,877

Cash paid for taxes	$	150		$	175

Noncash investing and financing activities
Capital expenditures in trade accounts payable (period-end accruals)	$	22,051		$	20,598
Asset contribution to an equity method investment		23,643			—
Capital expenditures relating to contributions in aid of construction for Topic 606 day 1 adoption		—			33,123
Right-of-use assets relating to Topic 842		5,448			—

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

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 growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of 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.

The General Partner, a Delaware limited liability company, manages our operations and activities. Summit Investments, a Delaware limited liability company, is the ultimate owner of our General Partner and has the right to appoint the entire Board of Directors. Summit Investments is controlled by Energy Capital Partners.

Summit Investments owned an approximate 2% general partner interest in SMLP (including the IDRs) until March 22, 2019. On March 22, 2019, we executed an equity restructuring agreement with the General Partner and SMP Holdings pursuant to which the IDRs and the 2% general partner interest were converted into a non-economic general partner interest in exchange for 8,750,000 common units which were issued to SMP Holdings (the “Equity Restructuring”). As of June 30, 2019, SMP Holdings, a wholly owned subsidiary of Summit Investments, beneficially owned 34,604,581 SMLP common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 SMLP common units.

Neither SMLP nor its subsidiaries have any employees. All of the personnel that conduct our business are employed by Summit Investments, but these individuals are sometimes referred to as our employees.

Business Operations. We provide 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 our customers. Our results are primarily driven by the volumes of natural gas that we gather, compress, treat and/or process as well as by the volumes of crude oil and produced water that we gather. We are the owner-operator of, or have significant ownership interests in, the following gathering systems:

•

Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;

•

Ohio Gathering, a natural gas gathering system and a condensate stabilization facility operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;

•

Polar and Divide, a crude oil and produced water gathering system and transmission pipeline operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

•

Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

•

Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado and southern Wyoming;

•

Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico;

•

Grand River, a natural gas gathering and processing system operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah;

•

DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and

•

Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.

Additionally, until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota. Refer to Note 17 for details on the sale of Tioga Midstream.

In June 2019, in conjunction with the Project, Summit Permian Transmission entered into a definitive joint venture agreement (the “Agreement”) with an affiliate of Double E’s foundation shipper (the “JV Partner”) to fund the capital expenditures associated with the Project. Refer to Note 8 for additional details.

Other than our investments in Double E and Ohio Gathering, all of our business activities are conducted through wholly owned operating subsidiaries.

Presentation and Consolidation. We prepare our unaudited condensed consolidated financial statements in accordance with GAAP as established by the FASB. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenue and expense and the disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and the regulations of the SEC. Certain information and note disclosures normally included in the annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information not misleading. In the opinion of management, the unaudited condensed consolidated financial statements contain all adjustments which are necessary to fairly present the unaudited condensed consolidated balance sheet as of June 30, 2019, the unaudited condensed consolidated statements of operations and statements of partners’ capital for the three and six months ended June 30, 2019 and 2018 and the unaudited condensed consolidated statements of cash flows for the six months ended June 30, 2019 and 2018. The balance sheet at December 31, 2018 included herein was derived from our audited financial statements, but does not include all disclosures required by GAAP. See Note 2 for the impact relating to the adoption of the new lease standard. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto that are included in our annual report on Form 10-K for the year ended December 31, 2018, as filed with the SEC on February 26, 2019 (the "2018 Annual Report"). The results of operations for an interim period are not necessarily indicative of results expected for a full year.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Except for the changes below, there have been no changes to our significant accounting policies since December 31, 2018.

Recent Accounting Pronouncements. Accounting standard setters frequently issue new or revised accounting rules. We review new pronouncements to determine the impact, if any, on our financial statements. Accounting standards that have or could possibly have a material effect on our financial statements are discussed below.

Recently Adopted Accounting Pronouncements. We have recently adopted the following accounting pronouncement:

•

ASU No. 2016-02 Leases (“Topic 842"). We adopted Topic 842 with a date of initial application of January 1, 2019. We applied Topic 842 by recognizing (i) a $5.4 million right-of-use (“ROU”) asset which represents the right to use, or to control the use of, specified assets for a lease term. The ROU asset is included in the Property, plant and equipment, net caption on the unaudited condensed consolidated balance sheet; and (ii) a $5.4 million lease liability for the obligation to make lease payments arising from the leases. The lease liability is included in the Other current liabilities and Other noncurrent liabilities captions on the unaudited condensed consolidated balance sheet. The comparative information has not been adjusted and is reported under the accounting standards in effect for those periods.

Refer to Note 16 for additional information.

Accounting Pronouncements Pending Adoption. We have not yet adopted the following accounting pronouncement as of June 30, 2019:

•

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. We are currently evaluating the provisions of ASU 2018-13 to determine its impact on our financial statements and related disclosures and will adopt its provisions effective January 1, 2020.

3. REVENUE

The majority of our revenue is derived from long-term, fee-based contracts with our customers, which include original terms of up to 25 years. We recognize revenue earned from fee-based gathering, compression, treating and processing services in gathering services and related fees. We also earn revenue in the Williston Basin and Permian Basin reporting segments from the sale of physical natural gas purchased from our customers under certain percent-of-proceeds arrangements. Under ASC Topic 606, these gathering contracts are presented net within cost of natural gas and NGLs. We sell natural gas that we retain from certain customers in the Barnett Shale reporting segment to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate retained from certain of our gathering services in the Piceance Basin reporting segment. Revenues from the sale of natural gas and condensate are recognized in natural gas, NGLs and condensate sales; the associated expense is included in operation and maintenance expense. Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in Other revenues.

The transaction price in our contracts is primarily based on the volume of natural gas, crude oil or produced water transferred by our gathering systems to the customer’s agreed upon delivery point multiplied by the contractual rate. For contracts that include MVCs, variable consideration up to the MVC will be included in the transaction price. For contracts that do not include MVCs, we do not estimate variable consideration because the performance obligations are completed and settled on a daily basis. For contracts containing noncash consideration such as fuel received in-kind, we measure the transaction price at the point of sale when the volume, mix and market price of the commodities are known.

We have contracts with MVCs that are variable and constrained. Contracts with greater than monthly MVCs are reviewed on a quarterly basis and adjustments to those estimates are made during each respective reporting period, if necessary.

The transaction price is allocated if the contract contains more than one performance obligation such as contracts that include MVCs. The transaction price allocated is based on the MVC for the applicable measurement period.

Performance obligations. The majority of our contracts have a single performance obligation which is either to provide gathering services (an integrated service) or sell natural gas, NGLs and condensate, which are both satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. We also have certain contracts with multiple performance obligations. They include an option for the customer to acquire additional services such as contracts containing MVCs. These performance obligations would also be satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. In these instances, we allocate the contract’s transaction price to each performance obligation using our best estimate of the standalone selling price of each service in the contract.

Performance obligations for gathering services are generally satisfied over time. We utilize either an output method (i.e., measure of progress) for guaranteed, stand-ready service contracts or an asset/system delivery time estimate for non-guaranteed, as-available service contracts.

Performance obligations for the sale of natural gas, NGLs and condensate are satisfied at a point in time. There are no significant judgments for these transactions because the customer obtains control based on an agreed upon delivery point.

Certain of our gathering and/or processing agreements provide for monthly, annual or multi-year MVCs. Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its contractual MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period.

We recognize customer obligations under their MVCs as revenue and contract assets when (i) we consider it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right.

Our services are typically billed on a monthly basis and we do not offer extended payment terms. We do not have contracts with financing components.

The following table presents estimated revenue expected to be recognized during the remainder of 2019 and over the remaining contract period related to performance obligations that are unsatisfied and are comprised of estimated MVC shortfall payments.

We applied the practical expedient in paragraph 606-10-50-14 of Topic 606 for certain arrangements that we consider optional purchases (i.e., there is no enforceable obligation for the customer to make purchases) and those amounts are excluded from the table.

	2019		2020		2021		2022		2023		Thereafter
	(In thousands)
Gathering services and related fees	$	60,217	$	120,941	$	100,117	$	83,673	$	70,971	$	114,043

Revenue by Category. In the following table, revenue is disaggregated by geographic area and major products and services. Ohio Gathering is excluded from the tables below due to equity method accounting. For more detailed information about reportable segments, see Note 4.

	Reportable Segments
	Three months ended June 30, 2019
	Utica Shale		Williston Basin		DJ Basin		Permian Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	7,591	$	15,685	$	4,021	$	586	$	30,555	$	11,428	$	5,897	$	75,763	$	(656	)	$	75,107
Natural gas, NGLs and condensate sales		—		3,768		101		2,406		2,104		6,273		—		14,652		3,639			18,291
Other revenues		—		2,670		1,034		49		945		1,646		—		6,344		(56	)		6,288
Total	$	7,591	$	22,123	$	5,156	$	3,041	$	33,604	$	19,347	$	5,897	$	96,759	$	2,927		$	99,686

	Reportable Segments
	Six months ended June 30, 2019
	Utica Shale		Williston Basin		DJ Basin		Permian Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	15,086	$	41,391	$	7,745	$	952	$	62,395	$	24,453	$	12,094	$	164,116	$	(2,045	)	$	162,071
Natural gas, NGLs and condensate sales		—		9,353		186		6,627		4,406		6,877		—		27,449		28,770			56,219
Other revenues		—		5,578		2,041		81		2,083		3,302		—		13,085		(281	)		12,804
Total	$	15,086	$	56,322	$	9,972	$	7,660	$	68,884	$	34,632	$	12,094	$	204,650	$	26,444		$	231,094

	Reportable Segments
	Three months ended June 30, 2018
	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	10,422	$	23,106	$	2,509	$	33,661	$	14,080	$	8,050	$	91,828	$	(2,243	)	$	89,585
Natural gas, NGLs and condensate sales		—		7,350		79		4,596		381		—		12,406		19,485			31,891
Other revenues		—		2,960		969		1,178		1,694		—		6,801		(94	)		6,707
Total	$	10,422	$	33,416	$	3,557	$	39,435	$	16,155	$	8,050	$	111,035	$	17,148		$	128,183

	Reportable Segments
	Six months ended June 30, 2018
	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total reportable segments		All other segments			Total
	(In thousands)
Major products / services lines
Gathering services and related fees	$	20,463	$	40,772	$	4,688	$	66,776	$	27,717	$	15,875	$	176,291	$	(2,345	)	$	173,946
Natural gas, NGLs and condensate sales		—		15,196		159		8,841		926		—		25,122		32,886			58,008
Other revenues		—		5,872		1,726		2,389		3,682		—		13,669		(120	)		13,549
Total	$	20,463	$	61,840	$	6,573	$	78,006	$	32,325	$	15,875	$	215,082	$	30,421		$	245,503

Contract balances. Contract assets relate to our rights to consideration for work completed but not billed at the reporting date and consist of the estimated MVC shortfall payments expected from our 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:

	June 30, 2019			December 31, 2018
	(In thousands)
Contract assets, beginning of period	$	8,755		$	—
Additions		14,602			26,403
Transfers out		(5,550	)		(17,648	)
Contract assets, end of period	$	17,807		$	8,755

As of June 30, 2019, receivables with customers totaled $59.0 million and contract assets totaled $17.8 million which were included in the Accounts receivable caption on the unaudited condensed consolidated balance sheet.

As of December 31, 2018, receivables with customers totaled $82.9 million and contract assets totaled $8.8 million which were included in the Accounts receivable caption on the unaudited condensed consolidated balance sheet.

Contract liabilities (deferred revenue) relate to the advance consideration received from customers primarily for contributions in aid of construction. We recognize contract liabilities under these arrangements in revenue over the contract period. For the three months ended June 30, 2019 and 2018, we recognized $2.7 million and $3.9 million of gathering services and related fees which was included in the contract liability balance as of the beginning of the period. For the six months ended June 30, 2019 and 2018, we recognized $5.4 million and $5.0 million of gathering services and related fees which was included in the contract liability balance as of the beginning of the period. See Note 9 for additional details.

4. SEGMENT INFORMATION

As of June 30, 2019, our 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 and Bison 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.

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.

The Ohio Gathering reportable segment includes our investment in OGC and OCC. Income or loss from equity method investees, as reflected on the statements of operations, relates to Ohio Gathering and is recognized and disclosed on a one-month lag (see Note 8).

For the three and six months ended June 30, 2019, other than the investment activity described in Note 8 below, Double E did not have any results of operations given that the Project is currently under development. The Project is expected to be operational in the third 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 our reportable segments for the purpose of evaluating their performance, including certain general and administrative expense items, natural gas and crude oil marketing services and transaction costs.

Assets by reportable segment follow.

	June 30,2019		December 31, 2018
	(In thousands)
Assets (1):
Utica Shale	$	206,911	$	207,357
Ohio Gathering		630,513		649,250
Williston Basin		439,026		526,819
DJ Basin		167,329		166,580
Permian Basin		174,964		145,702
Piceance Basin		672,664		699,638
Barnett Shale		358,997		376,564
Marcellus Shale		204,252		208,790
Total reportable segment assets		2,854,656		2,980,700
Corporate and Other		43,046		44,181
Eliminations		—		(4,319	)
Total assets	$	2,897,702	$	3,020,562

(1) At June 30, 2019, Corporate and Other included $23.3 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, 2018, Corporate and Other included $9.6 million of capital expenditures relating to our investment in Double E.

Revenues by reportable segment follow.

	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
	(In thousands)
Revenues (1):
Utica Shale	$	7,591		$	10,422		$	15,086		$	20,463
Williston Basin		22,123			33,416			56,322			61,840
DJ Basin		5,156			3,557			9,972			6,573
Permian Basin		3,041			—			7,660			—
Piceance Basin		33,604			39,435			68,884			78,006
Barnett Shale		19,347			16,155			34,632			32,325
Marcellus Shale		5,897			8,050			12,094			15,875
Total reportable segments revenue		96,759			111,035			204,650			215,082
Corporate and Other		3,824			19,422			30,662			33,598
Eliminations		(897	)		(2,274	)		(4,218	)		(3,177	)
Total revenues	$	99,686		$	128,183		$	231,094		$	245,503

(1) Excludes revenues earned by Ohio Gathering due to equity method accounting.

Counterparties accounting for more than 10% of total revenues were as follows:

	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
Percentage of total revenues (1):
Counterparty A - Piceance Basin		12	%		10	%		11	%		11	%
Counterparty B - Williston Basin		11	%	*				10	%	*
Counterparty C - Barnett Shale		14	%		11	%		12	%	*

(1) Excludes revenues earned by Ohio Gathering due to equity method accounting.

* Less than 10%

Depreciation and amortization, including the amortization expense associated with our favorable and unfavorable (for 2018) gas gathering contracts as reported in other revenues, by reportable segment follows.

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(In thousands)
Depreciation and amortization (1):
Utica Shale	$	1,923	$	2,033	$	3,831	$	3,886
Williston Basin		4,734		5,622		10,170		11,231
DJ Basin		464		784		1,263		1,565
Permian Basin		1,163		—		2,235		—
Piceance Basin		11,810		11,666		23,601		23,440
Barnett Shale (2)		4,167		3,759		8,497		7,516
Marcellus Shale		2,286		2,274		4,569		4,546
Total reportable segment depreciation and amortization		26,547		26,138		54,166		52,184
Corporate and Other		616		496		1,113		976
Total depreciation and amortization	$	27,163	$	26,634	$	55,279	$	53,160

(1) Excludes depreciation and amortization recognized by Ohio Gathering due to equity method accounting.

(2) Includes the amortization expense associated with our favorable and unfavorable (for 2018) gas gathering contracts as reported in other revenues.

Cash paid for capital expenditures by reportable segment follow.

	Six months ended June 30,
	2019			2018
	(In thousands)
Cash paid for capital expenditures (1):
Utica Shale	$	1,065		$	1,846
Williston Basin		14,230			10,966
DJ Basin		50,373			21,415
Permian Basin		28,163			50,773
Piceance Basin		1,497			3,412
Barnett Shale (2)		(37	)		349
Marcellus Shale		108			545
Total reportable segment capital expenditures		95,399			89,306
Corporate and Other		15,693			1,088
Total cash paid for capital expenditures	$	111,092		$	90,394

(1) Excludes cash paid for capital expenditures by Ohio Gathering due to equity method accounting.

(2) For the six months ended June 30, 2019, the amount includes sales tax reimbursements of $1.1 million.

During the six months ended June 30, 2019, Corporate and Other included cash paid of $0.3 million for corporate purposes; the remainder represents capital expenditures relating to the Project.

We assess the performance of our reportable segments based on segment adjusted EBITDA. We define segment adjusted EBITDA as 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) change in the Deferred Purchase Price Obligation fair value, (viii) impairments and (ix) other noncash expenses or losses, less other noncash income or gains. We define proportional adjusted EBITDA for our equity method investees as the product of (i) total revenues less total expenses, excluding impairments and other noncash income or expense items and (ii) amortization for deferred contract costs; multiplied by our ownership interest in Ohio Gathering during the respective period.

For the purpose of evaluating segment performance, we exclude the effect of Corporate and Other revenues and expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees), natural gas and crude oil marketing services, transaction costs, interest expense, change in the Deferred Purchase Price Obligation fair value and income tax expense or benefit from segment adjusted EBITDA.

Segment adjusted EBITDA by reportable segment follows.

	Three months ended June 30,					Six months ended June 30,
	2019			2018		2019			2018
	(In thousands)
Reportable segment adjusted EBITDA
Utica Shale	$	6,640		$	9,223	$	12,833		$	17,938
Ohio Gathering		9,939			8,935		19,149			19,412
Williston Basin		16,650			19,030		35,384			35,000
DJ Basin		2,816			959		5,489			2,280
Permian Basin		(656	)		—		(1,206	)		—
Piceance Basin		24,584			26,714		50,583			54,628
Barnett Shale		11,208			11,093		22,582			20,952
Marcellus Shale		4,635			6,543		9,777			13,219
Total of reportable segments' measures of profit or loss	$	75,816		$	82,497	$	154,591		$	163,429

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 or loss follows.

	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
	(In thousands)
Reconciliation of income (loss) before income taxes and loss from equity method investees to total of reportable segments' measures of profit:
Income (loss) before income taxes and loss from equity method investees	$	6,030		$	(45,699	)	$	(30,236	)	$	(51,101	)
Add:
Corporate and Other expense		7,208			9,002			21,367			19,625
Interest expense		17,941			14,837			35,468			29,959
Deferred Purchase Price Obligation		3,712			69,305			8,139			90,963
Depreciation and amortization		27,163			26,634			55,279			53,160
Proportional adjusted EBITDA for equity method investees		9,939			8,935			19,149			19,412
Adjustments related to MVC shortfall payments		3,533			(3,542	)		(666	)		(3,542	)
Adjustments related to capital reimbursement activity		(1,046	)		115			(1,761	)		155
Unit-based and noncash compensation		1,553			2,261			4,079			4,223
(Gain) loss on asset sales, net		(287	)		62			(1,248	)		(12	)
Long-lived asset impairment		70			587			45,021			587
Total of reportable segments' measures of profit	$	75,816		$	82,497		$	154,591		$	163,429

Adjustments related to MVC shortfall payments recognize the earnings from MVC shortfall payments ratably over the term of the associated MVC (see Note 3). Contributions in aid of construction are recognized over the remaining term of the respective contract. We include adjustments related to capital reimbursement activity in our calculation of segment adjusted EBITDA to account for revenue recognized from contributions in aid of construction.

Adjustments related to MVC shortfall payments by reportable segment follow.

	Three months ended June 30, 2019
	Williston Basin		Piceance Basin		Barnett Shale		Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	2,081	$	—	$	1,452	$	3,533

	Three months ended June 30, 2018
	Williston Basin			Piceance Basin			Barnett Shale			Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	(3,386	)	$	(93	)	$	(63	)	$	(3,542	)

	Six months ended June 30, 2019
	Williston Basin			Piceance Basin			Barnett Shale		Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	(3,468	)	$	(103	)	$	2,905	$	(666	)

	Six months ended June 30, 2018
	Williston Basin			Piceance Basin			Barnett Shale			Total
	(In thousands)
Adjustments related to expected MVC shortfall payments:	$	(3,386	)	$	(93	)	$	(63	)	$	(3,542	)

5. PROPERTY, PLANT AND EQUIPMENT, NET

Details on property, plant and equipment follow.

	June 30, 2019		December 31, 2018
	(In thousands)
Gathering and processing systems and related equipment	$	2,136,209	$	2,155,325
Construction in progress		76,086		137,920
Land and line fill		9,823		11,748
Other		61,045		45,853
Total		2,283,163		2,350,846
Less accumulated depreciation		404,312		387,133
Property, plant and equipment, net	$	1,878,851	$	1,963,713

In the DJ Basin, we determined that certain processing plant assets related to our existing 20 MMcf/d plant would no longer be utilized due to our 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, we recorded an impairment charge of $34.7 million related to these assets in the first quarter of 2019.

In the Barnett Shale, we determined, in the first quarter of 2019, that certain compressor station assets would be shut down and decommissioned. As a result, we recorded an impairment charge of $9.7 million related to these assets in the first quarter of 2019. See Note 6 for additional details.

Depreciation expense and capitalized interest follow.

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(In thousands)
Depreciation expense	$	18,829	$	18,657	$	38,612	$	37,214
Capitalized interest		2,446		1,863		4,361		3,085

6. AMORTIZING INTANGIBLE ASSETS

Details regarding our intangible assets, all of which are subject to amortization, follow:

	June 30, 2019
	Gross carrying amount		Accumulated amortization			Net
	(In thousands)
Favorable gas gathering contracts	$	24,195	$	(14,657	)	$	9,538
Contract intangibles		278,448		(156,755	)		121,693
Rights-of-way		159,734		(39,715	)		120,019
Total intangible assets	$	462,377	$	(211,127	)	$	251,250

	December 31, 2018
	Gross carrying amount		Accumulated amortization			Net
	(In thousands)
Favorable gas gathering contracts	$	24,195	$	(13,905	)	$	10,290
Contract intangibles		278,448		(143,962	)		134,486
Rights-of-way		166,209		(37,569	)		128,640
Total intangible assets	$	468,852	$	(195,436	)	$	273,416

In March 2019, certain events, facts and circumstances occurred which indicated that certain long-lived assets relating to the Barnett Shale reporting segment could be impaired (see Note 5). In connection with this evaluation, we evaluated the related intangible assets associated therewith for impairment consisting of rights-of-way intangible assets. We concluded the rights-of-way intangible assets were also impaired and, as a result, we recorded an impairment charge of $0.5 million in the first quarter of 2019.

We recognized amortization expense in other revenues as follows:

	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
	(In thousands)
Amortization expense – favorable gas gathering contracts	$	(363	)	$	(388	)	$	(752	)	$	(777	)

We recognized amortization expense in costs and expenses as follows:

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(In thousands)
Amortization expense – contract intangibles	$	6,397	$	6,535	$	12,794	$	13,070
Amortization expense – rights-of-way		1,574		1,592		3,121		3,177

The estimated aggregate annual amortization expected to be recognized for the remainder of 2019 and each of the four succeeding fiscal years follows.

	Intangible assets
	(In thousands)
2019	$	15,971
2020		32,049
2021		28,357
2022		25,290
2023		25,236

7. GOODWILL

We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill. There have been no impairments of goodwill during the three and six months ended June 30, 2019.

Fair Value Measurement. Our impairment determinations, in the context of (i) our annual impairment evaluations and (ii) our other-than-annual impairment evaluations involved significant assumptions and judgments, as discussed in the 2018 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. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

8. EQUITY METHOD INVESTMENTS

Double E

In June 2019, we formed Double E in connection with the Project. Effective June 26, 2019, Summit Permian Transmission, a wholly owned and consolidated subsidiary of the Partnership, and our JV Partner executed the Agreement whereby Double E will provide natural gas transportation services from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas. In connection with the Agreement and the related Project, the Partnership contributed total assets of approximately $23.6 million in exchange for a 70% ownership interest in Double E and our JV Partner contributed $7.3 million of cash in exchange for a 30% ownership interest in Double E. Concurrent with these contributions, and in accordance with the Agreement, Double E distributed $7.3 million to the Partnership. Subsequent to the formation of Double E, we also made additional cash investments of $5.9 million during June 2019.

Double E is deemed to be a variable interest entity as defined in GAAP. As of the date of the Agreement, Summit Permian Transmission is not deemed to be the primary beneficiary due to the JV Partner’s voting rights on significant matters. We account for our ownership interest in Double E as an equity method investment because we have significant influence over Double E. Our portion of Double E’s net assets, which was $23.3 million at June 30, 2019, is reported under the caption Investment in equity method investees on the unaudited condensed consolidated balance sheet.

For the three and six months ended June 30, 2019, other than the investment activity noted above, Double E did not have any results of operations given that the Project is currently under development.

Ohio Gathering

Ohio Gathering owns, operates and is currently developing midstream infrastructure consisting of a liquids-rich natural gas gathering system, a dry natural gas gathering system and a condensate stabilization facility in the Utica Shale in southeastern Ohio. Ohio Gathering provides gathering services pursuant to primarily long-term, fee-based gathering agreements, which include acreage dedications.

As a result of our joint venture partner funding a disproportionate amount of the capital calls during the six months ended June 30, 2019, our ownership interest in Ohio Gathering decreased from 40.0% at December 31, 2018, to 39.0% at June 30, 2019.

A reconciliation of our 39.0% ownership interest in Ohio Gathering to our investment per Ohio Gathering's books and records follows (in thousands).

Investment in Ohio Gathering, June 30, 2019	$	630,513
June cash distributions		3,273
Basis difference		(110,156	)
Investment in Ohio Gathering, net of basis difference, May 31, 2019	$	523,630

Summarized statements of operations information for OGC and OCC follow (amounts represent 100% of investee financial information).

	Three months ended May 31, 2019					Three months ended May 31, 2018
	OGC		OCC			OGC			OCC
	(In thousands)
Total revenues	$	35,262	$	2,073		$	34,123		$	2,070
Total operating expenses		26,336		2,691			35,518			1,958
Net income (loss)		8,926		(619	)		(1,396	)		(59	)

	Six months ended May 31, 2019					Six months ended May 31, 2018
	OGC		OCC			OGC		OCC
	(In thousands)
Total revenues	$	68,728	$	4,339		$	69,083	$	4,559
Total operating expenses		51,823		5,664			62,293		4,099
Net income (loss)		16,898		(1,326	)		6,784		121

9. DEFERRED REVENUE

A rollforward of current deferred revenue follows.

	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total current
	(In thousands)
Current deferred revenue, January 1, 2019	$	18	$	1,414	$	739	$	7,616	$	1,642	$	38	$	11,467
Additions		9		1,227		909		10,513		817		19		13,494
Less revenue recognized		9		790		475		10,528		815		19		12,636
Current deferred revenue, June 30, 2019	$	18	$	1,851	$	1,173	$	7,601	$	1,644	$	38	$	12,325

A rollforward of noncurrent deferred revenue follows.

	Utica Shale		Williston Basin		DJ Basin		Piceance Basin		Barnett Shale		Marcellus Shale		Total noncurrent
	(In thousands)
Noncurrent deferred revenue, January 1, 2019	$	21	$	4,393	$	7,284	$	17,942	$	9,628	$	236	$	39,504
Additions		—		1,940		1,841		3,372		760		—		7,913
Less reclassification to current deferred revenue		9		1,665		909		3,797		817		19		7,216
Noncurrent deferred revenue, June 30, 2019	$	12	$	4,668	$	8,216	$	17,517	$	9,571	$	217	$	40,201

10. DEBT

Debt consisted of the following:

	June 30, 2019			December 31, 2018
	(In thousands)
Summit Holdings' variable rate senior secured Revolving Credit Facility (4.91% at June 30, 2019 and 5.03% at December 31, 2018) due May 2022	$	573,000		$	466,000
Summit Holdings' 5.5% senior unsecured notes due August 2022		300,000			300,000
Less unamortized debt issuance costs (1)		(2,024	)		(2,362	)
Summit Holdings' 5.75% senior unsecured notes due April 2025		500,000			500,000
Less unamortized debt issuance costs (1)		(5,412	)		(5,907	)
Total long-term debt	$	1,365,564		$	1,257,731

(1) Issuance costs are being amortized over the life of the notes.

Revolving Credit Facility. Summit Holdings has a senior secured revolving credit facility which allows for revolving loans, letters of credit and swing line loans. The Revolving Credit Facility has a $1.25 billion borrowing capacity, matures in May 2022, and includes a $250.0 million accordion feature. As of June 30, 2019, SMLP and the Guarantor Subsidiaries fully and unconditionally and jointly and severally guarantee, and pledge substantially all of their assets in support of, the indebtedness outstanding under the Revolving Credit Facility. In June 2019, we executed the second amendment to the third amended and restated credit agreement that, among other things, made accommodations for the Agreement, and the transactions contemplated thereby, and designated Double E as an unrestricted subsidiary under the Revolving Credit Facility.

Borrowings under the Revolving Credit Facility bear interest, at the election of Summit Holdings, at a rate based on the alternate base rate (as defined in the credit agreement) plus an applicable margin ranging from 0.75% to 1.75% or the adjusted Eurodollar rate (the LIBOR rate), as defined in the credit agreement, plus an applicable margin ranging from 1.75% to 2.75%, with the commitment fee ranging from 0.30% to 0.50% in each case based on our relative leverage at the time of determination. At June 30, 2019, the applicable margin under LIBOR borrowings was 2.50% and the interest rate was 4.91%. The unused portion of the Revolving Credit Facility totaled $667.9 million, subject to a commitment fee of 0.50%, after giving effect to the issuance thereunder of a $9.1 million outstanding but undrawn irrevocable standby letter of credit. See Note 16 for additional information on our letter of credit.

As of June 30, 2019, we had $7.2 million of debt issuance costs attributable to our Revolving Credit Facility and related amendments which are included in noncurrent assets on the unaudited condensed consolidated balance sheet.

As of and during the six months ended June 30, 2019, we were in compliance with the Revolving Credit Facility's financial covenants. There were no defaults or events of default during the six months ended June 30, 2019.

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers") co-issued $300.0 million of 5.5% senior unsecured notes maturing August 15, 2022 (the "5.5% Senior Notes" and, together with the 5.75% Senior Notes (defined below), the “Senior Notes”).

In February 2017, the Co-Issuers completed a public offering of $500.0 million of 5.75% senior unsecured notes (the "5.75% Senior Notes") as described in the 2018 Annual Report.

The Guarantor Subsidiaries are 100% owned by a subsidiary of SMLP. The Guarantor Subsidiaries and SMLP fully and unconditionally and jointly and severally guarantee the 5.5% Senior Notes and the 5.75% Senior Notes. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan. Finance Corp. has had no assets or operations since inception in 2013. We have no other independent assets or operations. At no time have the Senior Notes been guaranteed by the Co-Issuers.

As of and during the six months ended June 30, 2019, we were in compliance with the covenants governing our Senior Notes. There were no defaults or events of default during the six months ended June 30, 2019.

11. FINANCIAL INSTRUMENTS

Concentrations of Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk consist of cash and cash equivalents and accounts receivable. We maintain our cash and cash equivalents in bank deposit accounts that frequently exceed federally insured limits. We have not experienced any losses in such accounts and do not believe we are exposed to any significant risk.

Accounts receivable primarily comprise amounts due for the gathering, compression, treating and processing services we provide to our customers and also the sale of natural gas liquids resulting from our processing services. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of our counterparties and can require letters of credit or other forms of credit assurance for receivables from counterparties that are judged to have substandard credit, unless the credit risk can otherwise be mitigated. Our top five customers or counterparties accounted for 50% of total accounts receivable as of June 30, 2019, compared with 39% as of December 31, 2018.

Fair Value. The carrying amount of cash and cash equivalents, accounts receivable and trade accounts payable reported on the balance sheet approximates fair value due to their short-term maturities.

The Deferred Purchase Price Obligation's carrying value is its fair value because carrying value represents the present value of the payment expected to be made in 2020. In March 2019, the Partnership amended the Contribution Agreement related to the 2016 Drop Down and fixed the Remaining Consideration at $303.5 million, with such amount to be paid by the Partnership in one or more payments over the period from March 1, 2020 through December 31, 2020, in (i) cash, (ii) the Partnership’s common units or (iii) a combination of cash and the Partnership’s common units, at the discretion of the Partnership. At least 50% of the Remaining Consideration must be paid on or before June 30, 2020 and interest will accrue at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020 (see Note 17 for additional information).

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

	June 30, 2019				December 31, 2018
	Carrying value		Estimated fair value (Level 2)		Carrying value		Estimated fair value (Level 2)
	(In thousands)
Summit Holdings 5.5% Senior Notes ($300.0 million principal)	$	297,976	$	287,750	$	297,638	$	286,625
Summit Holdings 5.75% Senior Notes ($500.0 million principal)		494,588		437,500		494,093		455,208

The carrying value on the balance sheet of the Revolving Credit Facility is its fair value due to its floating interest rate. The estimated fair value for the Senior Notes is based on an average of nonbinding broker quotes as of June 30, 2019 and December 31, 2018. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the Senior Notes.

12. PARTNERS' CAPITAL

A rollforward of the number of common limited partner, preferred limited partner and General Partner units follows.

	Limited partners
	Series A Preferred Units		Common		General Partner
Units, January 1, 2019		300,000		73,390,853		1,490,999
Conversion of General Partner economic interests		—		8,750,000		(1,490,999	)
Net units issued under the SMLP LTIP		—		564,038		—
Units, June 30, 2019		300,000		82,704,891		—

GP/IDR Exchange. On March 22, 2019, we cancelled our IDRs and converted our 2% economic GP interest to a non-economic GP interest in exchange for 8,750,000 SMLP common units which were issued to SMP Holdings in the Equity Restructuring. These units had a fair value of $84.5 million as of the transaction date (March 22, 2019). As a result of the Equity Restructuring, the general partner units and IDRs were eliminated, are no longer outstanding, and no longer participate in distributions of cash from SMLP. ECP continues to control the non-economic GP interest in SMLP.

Immediately following the Equity Restructuring, SMP Holdings directly owned a 41.8% limited partner interest in SMLP and an affiliate of Energy Capital Partners II, LLC directly owned a 7.2% limited partner interest in SMLP.

For the three and six months ended June 30, 2018, our general partner held IDRs that entitled it to receive increasing percentage allocations, up to a maximum of 50%, of the cash we distributed from operating surplus in excess of $0.46 per unit per quarter.

Our payment of IDRs as reported in distributions to unitholders – general partner in the statement of partners' capital during the three and six months ended June 30 follow.

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(In thousands)
IDR payments	$	—	$	2,136	$	2,139	$	4,264

For the purposes of calculating net income attributable to General Partner in the statements of operations and partners' capital, the financial impact of IDRs was recognized in respect of the quarter for which the distributions were declared. For the purposes of calculating distributions to unitholders in the statements of partners' capital and cash flows, IDR payments were recognized in the quarter in which they are paid.

At-the-market Program. In 2017, we executed an equity distribution agreement and filed a prospectus and a prospectus supplement with the SEC for the issuance and sale from time to time of SMLP common units having an aggregate offering price of up to $150.0 million (the "ATM Program"). These sales will be made (i) pursuant to the terms of the equity distribution agreement between us and the sales agents named therein and (ii) by means of ordinary brokers' transactions at market prices, in block transactions or as otherwise agreed between us and the sales agents. Sales of our common units may be made in negotiated transactions or transactions that are deemed to be at-the-market offerings as defined by SEC rules.

During the three and six months ended June 30, 2019, there were no transactions under the ATM Program. Following the effectiveness of the ATM Program registration statement and after taking into account the aggregate sales price of common units sold under the ATM Program through June 30, 2019, we have the capacity to issue additional common units under the ATM Program up to an aggregate $132.3 million.

Series A Preferred Units. In 2017, we issued 300,000 Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “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 2018 Annual Report.

Cash Distributions Paid and Declared. We paid the following per-unit distributions during the three and six months ended June 30:

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
Per-unit distributions to unitholders	$	0.2875	$	0.575	$	0.8625	$	1.150

On July 25, 2019, the Board of Directors of our General Partner declared a distribution of $0.2875 per unit for the quarterly period ended June 30, 2019. This distribution, which totaled $23.8 million, will be paid on August 14, 2019 to unitholders of record at the close of business on August 7, 2019.

13. EARNINGS PER UNIT

The following table details the components of EPU.

	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
	(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	$	4,809		$	(51,111	)	$	(32,117	)	$	(57,099	)
Less net income attributable to Series A Preferred Units		7,125			7,125			14,250			14,250
Net loss attributable to common limited partners	$	(2,316	)	$	(58,236	)	$	(46,367	)	$	(71,349	)

Denominator for basic and diluted EPU:
Weighted-average common units outstanding – basic and diluted		82,700			73,356			79,266			73,245

Loss per limited partner unit:
Common unit – basic	$	(0.03	)	$	(0.79	)	$	(0.58	)	$	(0.97	)
Common unit – diluted	$	(0.03	)	$	(0.79	)	$	(0.58	)	$	(0.97	)

Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU		—			1			17			3

14. UNIT-BASED AND NONCASH COMPENSATION

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

•

In March 2019, we granted 639,522 phantom units and associated distribution equivalent rights to employees in connection with our annual incentive compensation award cycle. These awards had a grant date fair value of $9.78 and vest ratably over a three-year period.

•

In March 2019, we also issued 16,358 common units to our two independent directors in connection with their annual compensation plan. In May 2019, we issued an additional 9,580 units to an independent director in conjunction with his appointment to our Board of Directors.

•

During the six months ended June 30, 2019, 562,660 phantom units vested.

•

As of June 30, 2019, approximately 2.6 million common units remained available for future issuance under the SMLP LTIP.

15. RELATED-PARTY TRANSACTIONS

Acquisitions. See Notes 12 and 17 of the 2018 Annual Report.

Reimbursement of Expenses from General Partner. Our General Partner and its affiliates do not receive a management fee or other compensation in connection with the management of our business, but will be reimbursed for expenses incurred on our behalf. Under our Partnership Agreement, we reimburse our General Partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our General Partner's employees and executive officers who perform services necessary to run our business. Our Partnership Agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. The "Due to affiliate" line item on the consolidated balance sheet represents the payables to our General Partner for expenses incurred by it and paid on our behalf.

Expenses incurred by the General Partner and reimbursed by us under our Partnership Agreement were as follows:

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(In thousands)
Operation and maintenance expense	$	7,560	$	7,114	$	15,445	$	14,737
General and administrative expense		6,135		7,481		16,965		15,598

16. LEASES, COMMITMENTS AND CONTINGENCIES

Leases. We account for leases in accordance with Topic 842, which we adopted on January 1, 2019, using the modified retrospective method. Under the modified retrospective method, the comparative information is not adjusted and is reported under the accounting standards in effect for those periods. See Note 2 for further discussion of the adoption.

We and Summit Investments lease certain office space and equipment under operating leases. We lease office space for our corporate headquarters as well as for offices in and around our gathering systems for terms of between 3 and 10 years. We lease the office space to limit exposure to risks related to ownership, such as fluctuations in real estate prices. In addition, we lease equipment primarily to support our operations in response to the needs of our gathering systems for terms of between 3 and 4 years. We and Summit Investments also lease vehicles under finance leases to support our operations in response to the needs of our gathering systems for a term of 3 years. We only lease from reputable companies and our leased assets are not specialized in our industry.

Some of our leases are subject to annual changes relating to the Consumer Price Index (“CPI”). While lease liabilities are not remeasured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred.

We have options to extend the lease term of certain office space in Texas, Colorado and West Virginia. The beginning of the noncancelable lease period for these leases range from 2014 to 2018 and the lease period ends between 2019 and 2021. These lease agreements contain between one and three options to renew the lease for a period of between two and five years. As of June 30, 2019, the exercise of the renewal options for these leases are not reasonably certain and, as a result, the payments associated with these renewals are not included in the measurement of the lease liability and ROU asset.

We also have options to extend the lease term of certain compression equipment used at the Summit Utica gathering system. The beginning of the noncancelable lease period for these leases is 2017 and the lease period ends in 2020. Upon expiration of the noncancelable lease period, we have the option to renew the leases on a month-to-month basis; we therefore have not included any amounts attributable to renewals in the measurement.

Our leases do not contain residual value guarantees.

In accordance with the provisions in our Revolving Credit Facility, our aggregate finance lease obligations cannot exceed the greater of $50 million or 5.5% of consolidated total assets in any period of twelve consecutive calendar months during the life of such leases.

In March 2019, we entered into an agreement with a third party vendor to construct a transmission line to deliver electric power to the new 60 MMcf/d processing plant under development in the DJ Basin. The project was expected to cost approximately $7.8 million and we made an up-front payment of $3.0 million which is included in the Property, plant and equipment, net caption on the unaudited condensed consolidated balance sheet. During the second quarter of 2019, we exercised an option to increase the capacity of the transmission line for an additional cost of $4.3 million and we issued an irrevocable standby letter of credit payable to the vendor with an initial term of one year totaling $9.1 million, which reflects the expected remaining cost of the project. The letter of credit will automatically renew for successive twelve month periods following the initial term, subject to certain adjustments. Once construction is complete, the letter of credit will be adjusted to reflect the final construction cost. We determined the contract contained a lease based on the right to use the constructed transmission line to power the processing plant in the DJ Basin. The project is expected to be completed and the commencement date of the ROU asset will be on or before July 1, 2020.

Our significant assumptions or judgments include the determination of whether a contract contains a lease and the discount rate used in our lease liabilities.

The rate implicit in our lease contracts is not readily determinable. In determining the discount rate used in our lease liabilities, we analyzed certain factors in our incremental borrowing rate, including collateral assumptions and the term used. Our incremental borrowing rate on the Revolving Credit Facility was 5.03% at December 31, 2018, which reflects the fixed rate at which we could borrow a similar amount, for a similar term and with similar collateral as in the lease contracts at the commencement date.

We adopted the following practical expedients in Topic 842 for all asset classes, which included (i) not being required to reassess whether any expired or existing contracts are or contain leases; (ii) not being required to reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will be classified as finance leases); (iii) not being required to reassess initial direct costs for any existing leases; (iv) not recognizing ROU assets and lease liabilities that arise from short-term leases of twelve months or less for any class of underlying asset; (v) not allocating consideration in a contract between lease and nonlease (e.g., maintenance services) components for our leased office space and equipment; and (vi) not evaluating existing or expired land easements that were not previously accounted for as leases under Topic 840.

ROU assets (included in the Property, plant and equipment, net caption on our unaudited condensed consolidated balance sheet) and lease liabilities (included in the Other current liabilities and Other noncurrent liabilities captions on our unaudited condensed consolidated balance sheet) follow:

	June 30,
	2019
	(In thousands)

ROU assets
Operating	$	5,136
Finance		4,061
	$	9,197
Lease liabilities, current
Operating	$	2,337
Finance		1,627
	$	3,964
Lease liabilities, noncurrent
Operating	$	2,996
Finance		1,194
	$	4,190

Lease cost and Other information follow:

	Three months ended		Six months ended
	June 30, 2019		June 30, 2019
	(In thousands)
Lease cost
Finance lease cost:
Amortization of ROU assets (included in depreciation and amortization)	$	407	$	775
Interest on lease liabilities (included in interest expense)		30		53
Operating lease cost (included in general and administrative expense)		745		1,577
	$	1,182	$	2,405

	Six months ended
	June 30, 2019
	(In thousands)
Other information
Cash paid for amounts included in the measurement of lease liabilities
Operating cash outflows from operating leases	$	1,678
Operating cash outflows from finance leases		53
Financing cash outflows from finance leases		915
ROU assets obtained in exchange for new operating lease liabilities		1,218
ROU assets obtained in exchange for new finance lease liabilities		1,292
Weighted-average remaining lease term (years) - operating leases		4.9
Weighted-average remaining lease term (years) - finance leases		2.0
Weighted-average discount rate - operating leases		5	%
Weighted-average discount rate - finance leases		4	%

We recognize total lease expense incurred or allocated to us in general and administrative expenses. Lease expense related to operating leases, including lease expense incurred on our behalf and allocated to us, was as follows:

	Three months ended June 30,				Six months ended June 30,
	2019		2018		2019		2018
	(In thousands)
Lease expense	$	986	$	956	$	1,930	$	1,978

Future minimum lease payments due under noncancelable leases for the remainder of 2019 and each of the five succeeding fiscal years and thereafter, were as follows:

	June 30, 2019
	(In thousands)
	Operating		Finance
2019	$	1,738	$	898
2020		1,606		1,348
2021		1,001		621
2022		538		70
2023		400		—
2024		240		—
Thereafter		895		—
Total future minimum lease payments	$	6,418	$	2,937

Future minimum lease payments due under noncancelable operating leases (under ASC 840) at December 31, 2018, were as follows:

	December 31,
	2018
	(In thousands)
2019	$	3,133
2020		1,018
2021		550
2022		506
2023		373
Thereafter		621
Total future minimum lease payments	$	6,201

Future payments due under finance leases (under ASC 840) at December 31, 2018, were as follows:

	December 31,
	2018
	(In thousands)
2019	$	1,473
2020		902
2021		174
Total finance lease obligations		2,549
Less: Amounts representing interest		(104	)
Net present value of finance lease obligations		2,445
Less: Amount representing current portion (included in Other current liabilities)		(1,406	)
Finance lease obligations, less current portion (included in Other noncurrent liabilities)	$	1,039

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

As described in the 2018 Annual Report, in 2015, Summit Investments 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 Summit Investments' insurance policies, was subject 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. Summit Investments exhausted the $25.0 million pollution liability policy in 2015.

A rollforward of the aggregate accrued environmental remediation liabilities follows.

	Total
	(In thousands)
Accrued environmental remediation, January 1, 2019	$	5,636
Payments made		(1,001	)
Additional accruals		767
Accrued environmental remediation, June 30, 2019	$	5,402

As of June 30, 2019, we have 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 and fines expected to be incurred subsequent to June 30, 2020. Each of these amounts represent our best estimate for costs expected to be incurred. Neither of these amounts has been discounted to its present value.

While we cannot predict the ultimate outcome of this matter with certainty for Summit Investments or Meadowlark Midstream, especially as it relates to any material liability as a result of any governmental proceeding related to the incident, we believe at this time that it is unlikely that SMLP or its General Partner will be subject to any material liability as a result of any governmental proceeding related to the rupture.

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.

17. DISPOSITIONS, ACQUISITIONS AND DROP DOWN TRANSACTIONS

Tioga Midstream Disposition. In February 2019, Tioga Midstream, LLC, a subsidiary of SMLP, and certain affiliates of SMLP (collectively, “Summit”) 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 Summit 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, Summit 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 our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019.

2016 Drop Down. In 2016, SMLP acquired a controlling interest in OpCo, the entity which owns the 2016 Drop Down Assets. These assets include certain natural gas, crude oil and produced water gathering systems located in the Utica Shale, the Williston Basin and the DJ Basin, as well as ownership interests in Ohio Gathering.

The net consideration paid and recognized in connection with the 2016 Drop Down (i) consisted of a cash payment to SMP Holdings of $360.0 million funded with borrowings under our Revolving Credit Facility and a $0.6 million working capital adjustment received in June 2016 (the “Initial Payment”) and (ii) includes the Deferred Purchase Price Obligation payment due in 2020.

In March 2019, the Partnership amended the Contribution Agreement related to the 2016 Drop Down and fixed the Remaining Consideration at $303.5 million, with such amount to be paid by the Partnership in one or more payments over the period from March 1, 2020 through December 31, 2020, in (i) cash, (ii) the Partnership’s common units or (iii) a combination of cash and the Partnership’s common units, at the discretion of the Partnership. At least 50% of the Remaining Consideration must be paid on or before June 30, 2020 and interest will accrue at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020.

The present value of the Deferred Purchase Price Obligation is reflected as a liability on our balance sheet until paid. As of June 30, 2019, the Remaining Consideration, which reflects the net present value of the $303.5 million Deferred Purchase Price Obligation, was $292.1 million on the unaudited condensed consolidated balance sheet using a discount rate of 5.25%.

18. SUBSEQUENT EVENTS

We have evaluated subsequent events for recognition or disclosure in the unaudited condensed consolidated financial statements and no events have occurred that require recognition or disclosure.

Item 2. 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, 2018. 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 2018 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 growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States.

We classify our midstream energy infrastructure assets into two categories:

•

Core Focus Areas – production 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 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 moderate 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.

We are the owner-operator of or have significant ownership interests in the following gathering systems, which comprise our Core Focus Areas:

•

Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;

•

Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

•

Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico.

We are the owner-operator of the following gathering systems, which comprise our Legacy Areas:

•

DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and

•

Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.

For additional information on our organization and systems, see Notes 1 and 4 to the unaudited condensed consolidated financial statements.

Our financial results are driven primarily by volume throughput and 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 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, Summit Permian and Grand River 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 months ended June 30, 2019, these additional activities accounted for approximately 18% of total revenues including marketing transactions, and approximately 15% of total revenues excluding marketing transactions. During the six months ended June 30, 2019, these additional activities accounted for approximately 24% of total revenues including marketing transactions, and approximately 13% of total revenues excluding marketing transactions.

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 Six Months Ended June 30, 2019 and 2018" section herein.

	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
	(In thousands)
Net income (loss)	$	4,809		$	(49,913	)	$	(32,105	)	$	(53,758	)
Reportable segment adjusted EBITDA
Utica Shale	$	6,640		$	9,223		$	12,833		$	17,938
Ohio Gathering		9,939			8,935			19,149			19,412
Williston Basin		16,650			19,030			35,384			35,000
DJ Basin		2,816			959			5,489			2,280
Permian Basin		(656	)		—			(1,206	)		—
Piceance Basin		24,584			26,714			50,583			54,628
Barnett Shale		11,208			11,093			22,582			20,952
Marcellus Shale		4,635			6,543			9,777			13,219

Net cash provided by operating activities	$	43,535		$	58,839		$	96,246		$	110,049
Capital expenditures (1)		50,244			49,616			111,092			90,394

Distributions to common unitholders	$	23,775		$	45,216		$	69,056		$	90,269
Distributions to Series A Preferred unitholders		14,250			14,250			14,250			14,250
Net borrowings under Revolving Credit Facility		139,000			55,000			107,000			95,000

(1) See "Liquidity and Capital Resources" herein and Note 4 to the unaudited condensed consolidated financial statements for additional information on capital expenditures.

Three and six months ended June 30, 2019. The following items are reflected in our financial results:

•

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. Double E filed its Section 7(c) application with the Federal Energy Regulatory Commission on July 31, 2019.

In connection with the Project, Summit Permian Transmission contributed total assets of approximately $23.6 million for a 70% ownership interest in Double E. We expect to own a majority interest in the Project, to lead the development, permitting and construction of the Project and to operate the pipeline upon commissioning. We estimate that our share of the capital expenditures required to develop the Project will total approximately $350.0 million, and that more than 90% of those capital expenditures will be incurred in 2020 and 2021. Assuming timely receipt of the requisite regulatory approvals, we expect that the Project will be placed into service in the third quarter of 2021.

•

Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering systems operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota. Refer to Note 17 for details on the sale of Tioga Midstream. On March 22, 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.

•

In February 2019, we signed an amendment to the Contribution Agreement (the “Amendment”) related to the 2016 Drop Down pursuant to which, in April 2019, the Partnership made a cash payment of $100 million to SMP Holdings in partial settlement of the Deferred Purchase Price Obligation. Following the payment, the Remaining Consideration was fixed at $303.5 million, with such amount being payable by the Partnership in one or more payments over the period from March 1, 2020 through December 31, 2020, in (i) cash, (ii) the Partnership’s common units or (iii) a combination of cash and the Partnership’s common units, at the discretion of the Partnership. At least 50% of the Remaining Consideration must be paid on or before June 30, 2020 and interest will accrue at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020.

The present value of the Deferred Purchase Price Obligation is reflected as a liability on our balance sheet. As of June 30, 2019, the Remaining Consideration, which reflects the net present value of the $303.5 million Deferred Purchase Price Obligation, was $292.1 million on the unaudited condensed consolidated balance sheet using a discount rate of 5.25%. We have presented the Deferred Purchase Price Obligation as a current liability based on the expected settlement on or before June 30, 2020.

•

On March 22, 2019, pursuant to an equity restructuring agreement with the General Partner and SMP Holdings, we cancelled our IDRs and converted our 2% economic GP interest into a non-economic GP interest in exchange for 8,750,000 SMLP common units, which were issued to SMP Holdings in the Equity Restructuring. As a result of the Equity Restructuring, the general partner units and IDRs were eliminated, are no longer outstanding, and no longer participate in distributions of cash from SMLP. ECP continues to control the non-economic GP interest in SMLP.

•

In March 2019, certain events, facts and circumstances occurred which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, we performed a 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 would be shut down and de-commissioned and we recorded an impairment charge of $10.2 million related to these assets.

Three and six months ended June 30, 2018. The following items are reflected in our financial results:

•

During the three and six months ended June 30, 2018, we recognized $6.0 million and $8.4 million, respectively in gathering services and related fees from MVC shortfall adjustments. Under Topic 606, we recognize customer obligations under their MVCs as revenue and contract assets when (i) we consider it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right.

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 activity and cost of capital; and

•

Shifts in operating costs and inflation.

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 2018 Annual Report.

How We Evaluate Our Operations

We conduct and report our operations in the midstream energy industry through eight reportable segments:

•

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 and Bison 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.

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 six months ended June 30, 2019.

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 2018 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the unaudited condensed consolidated financial statements.

Results of Operations

Consolidated Overview for the Three and Six Months Ended June 30, 2019 and 2018

The following table presents certain consolidated and operating data.

	Three months ended June 30,						Six months ended June 30,
	2019			2018			2019			2018
	(In thousands)
Revenues:
Gathering services and related fees	$	75,107		$	89,585		$	162,071		$	173,946
Natural gas, NGLs and condensate sales		18,291			31,891			56,219			58,008
Other revenues		6,288			6,707			12,804			13,549
Total revenues		99,686			128,183			231,094			245,503
Costs and expenses:
Cost of natural gas and NGLs		11,571			24,384			43,330			44,670
Operation and maintenance		23,718			24,466			47,940			49,070
General and administrative		10,214			13,484			27,495			27,926
Depreciation and amortization		26,800			26,784			54,527			53,461
Transaction costs		—			—			950			—
(Gain) loss on asset sales, net		(287	)		62			(1,248	)		(12	)
Long-lived asset impairment		70			587			45,021			587
Total costs and expenses		72,086			89,767			218,015			175,702
Other income		83			27			292			20
Interest expense		(17,941	)		(14,837	)		(35,468	)		(29,959	)
Deferred Purchase Price Obligation		(3,712	)		(69,305	)		(8,139	)		(90,963	)
Income (loss) before income taxes and loss from equity method investees		6,030			(45,699	)		(30,236	)		(51,101	)
Income tax expense		(1,142	)		(294	)		(1,349	)		(123	)
Loss from equity method investees		(79	)		(3,920	)		(520	)		(2,534	)
Net income (loss)	$	4,809		$	(49,913	)	$	(32,105	)	$	(53,758	)

Volume throughput (1):
Aggregate average daily throughput - natural gas (MMcf/d)		1,368			1,797			1,419			1,767
Aggregate average daily throughput - liquids (Mbbl/d)		94.3			88.9			98.6			86.9

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

Volumes – Gas. Natural gas throughput volumes decreased 429 MMcf/d compared to the three months ended June 30, 2018, primarily reflecting:

•

a volume throughput decrease of 177 MMcf/d for the Marcellus Shale segment.

•

a volume throughput decrease of 155 MMcf/d for the Utica Shale segment.

•

a volume throughput decrease of 98 MMcf/d for the Piceance Basin segment.

Natural gas throughput volumes decreased 348 MMcf/d compared to the six months ended June 30, 2018, primarily reflecting:

•

a volume throughput decrease of 160 MMcf/d for the Marcellus Shale segment.

•

a volume throughput decrease of 113 MMcf/d for the Utica Shale segment.

•

a volume throughput decrease of 89 MMcf/d for the Piceance Basin segment.

Volumes – Liquids. Crude oil and produced water throughput volumes in the Williston Basin segment increased 5.4 Mbbl/d and 11.7 Mbbl/d, respectively, compared to the three and six months ended June 30, 2018.

For additional information on volumes, see the "Segment Overview for the Three and Six Months Ended June 30, 2019 and 2018" section herein.

Revenues. Total revenues decreased $28.5 million compared to the three months ended June 30, 2018 primarily comprised of a $14.5 million decrease in gathering services and related fees and a $13.6 million decrease in natural gas, NGLs and condensate sales.

Gathering Services and Related Fees. Gathering services and related fees decreased $14.5 million compared to the three months ended June 30, 2018, primarily reflecting:

•

a $7.4 million decrease in gathering services and related fees in the Williston Basin primarily reflecting (i) $5.4 million in lower MVC shortfall revenue attributable to the timing of revenue recognition and (ii) a $3.0 million decrease in gathering services and related fees attributable to the sale of the Tioga Midstream system on March 22, 2019, whose 2019 financial results are included for the period from January 1, 2019 through March 22, 2019. This was partially offset by an increase relating to higher liquids volume throughput in the Williston Basin due to increased drilling activity.

•

a $3.1 million decrease in gathering services and related fees in the Piceance Basin relating to lower volume throughput due to lower drilling activity and natural production declines.

•

a $2.8 million decrease in gathering services and related fees in the Utica Shale due to natural production declines on existing wells partially offset by the completion of new wells at the end of the fourth quarter of 2018 and in the first half of 2019.

•

a $1.5 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting lower volume throughput and lower gathering rate mix. Also impacting 2019 revenues was the presentation of $1.2 million of gathering services as a reduction to cost of natural gas and NGLs due to the transfer of certain marketing arrangements from Corporate and Other to our DFW Midstream operations.

•

a $2.2 million decrease in gathering services and related fees in the Marcellus Shale relating to lower volume throughput due to natural production declines.

•

a $1.5 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 mix from customers, partially offset by natural production declines.

•

$0.6 million in gathering services and related fees in the Permian Basin (commissioned in the fourth quarter of 2018).

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $13.6 million compared to the three months ended June 30, 2018, primarily reflecting lower natural gas, NGL and crude oil marketing services.

Total revenues decreased $14.4 million compared to the six months ended June 30, 2018 primarily comprised of an $11.9 million decrease in gathering services and related fees and a $1.8 million decrease in natural gas, NGLs and condensate sales.

Gathering Services and Related Fees. Gathering services and related fees decreased $11.9 million compared to the six months ended June 30, 2018, primarily reflecting:

•

a $5.4 million decrease in gathering services and related fees in the Utica Shale due to a combination of natural production declines on existing wells together with increased temporary production curtailments associated with infill drilling, completion activity and other operational downtime associated with customers on existing pad sites, partially offset by the completion of new wells at the end of the fourth quarter of 2018 and in the first half of 2019.

•

a $4.4 million decrease in gathering services and related fees in the Piceance Basin relating to lower volume throughput due to lower drilling activity and natural production declines.

•

a $3.8 million decrease in gathering services and related fees in the Marcellus Shale relating to lower volume throughput due to natural production declines.

•

a $2.1 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting lower volume throughput and lower gathering rate mix. Also impacting 2019 revenues was the presentation of $1.2 million of gathering services as a reduction to cost of natural gas and NGLs due to the transfer of certain marketing arrangements from Corporate and Other to our DFW Midstream operations.

•

a $3.1 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 mix from customers, partially offset by natural production declines.

•

$1.0 million in gathering services and related fees in the Permian Basin (commissioned in the fourth quarter of 2018).

•

a $0.6 million increase in gathering services and related fees in the Williston Basin primarily reflecting higher liquids volume throughput due to increased drilling activity. This was partially offset by a $4.4 million decrease in gathering services and related fees attributable to the sale of the Tioga Midstream system on March 22, 2019, whose 2019 financial results are included for the period from January 1, 2019 through March 22, 2019.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $1.8 million compared to the six months ended June 30, 2018, primarily reflecting lower natural gas, NGL and crude oil marketing services.

Costs and Expenses. Total costs and expenses decreased $17.7 million, compared to the three months ended June 30, 2018 primarily reflecting:

•

a $12.8 million decrease in natural gas, NGLs and condensate purchases primarily driven by lower natural gas, NGL and crude oil marketing activity.

•

a $3.3 million decrease in general and administrative expense due to a $2.0 million decrease in compensation expense and a $1.3 million decrease in professional service fees.

•

a $0.7 million decrease in operation and maintenance expense.

Total costs and expenses increased $42.3 million, compared to the six months ended June 30, 2018 primarily reflecting:

•

the recognition of $34.7 million of certain long-lived asset impairments in the DJ Basin.

•

the recognition of $10.2 million of certain long-lived asset impairments in the Barnett Shale.

•

a $1.1 million increase in depreciation and amortization, which was primarily driven by the assets placed into service in the Permian Basin.

•

a $0.4 million decrease in general and administrative expense primarily due to a $1.7 million decrease in compensation expense and a $1.6 million decrease in professional service fees, partially offset by the recognition of $3.4 million in severance expense relating to our former Chief Executive Officer.

•

a $1.3 million decrease in natural gas, NGLs and condensate purchases primarily driven by lower natural gas, NGL and crude oil marketing activity.

•

a $1.1 million decrease in operation and maintenance expense.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs decreased $12.8 million and $1.3 million compared to the three and six months ended June 30, 2018, primarily driven by lower natural gas, NGL and crude oil marketing activity.

Operation and Maintenance. Operation and maintenance expense decreased $0.7 million and $1.1 million compared to the three and six months ended June 30, 2018.

General and Administrative. General and administrative expense decreased $3.3 million compared to the three months ended June 30, 2018 due to a $2.0 million decrease in compensation expense and a $1.3 million decrease in professional service fees.

General and administrative expense decreased $0.4 million compared to the six months ended June 30, 2018 primarily due to a $1.7 million decrease in compensation expense and a $1.6 million decrease in professional service fees, partially offset by the recognition of $3.4 million in severance expense relating to our former Chief Executive Officer.

Depreciation and Amortization. Depreciation and amortization expense increased $1.1 million compared to the six months ended June 30, 2018, primarily due to the assets placed into service in the Permian Basin.

Transaction Costs. Transaction costs recognized during the six months ended June 30, 2019 relate to financial advisory costs primarily associated with the Equity Restructuring.

Interest Expense. Interest expense increased $3.1 million and $5.5 million compared to the three and six months ended June 30, 2018, primarily as a result of a higher average outstanding balance on the Revolving Credit Facility.

Deferred Purchase Price Obligation. Deferred Purchase Price Obligation recognized during the three and six months ended June 30, 2019 represents the change in present value to Remaining Consideration in connection with the 2016 Drop Down (see Note 17 to the unaudited condensed consolidated financial statements).

For additional information, see the "Segment Overview for the Three and Six Months Ended June 30, 2019 and 2018" and "Corporate and Other Overview for the Three and Six Months Ended June 30, 2019 and 2018" sections herein.

Segment Overview for the Three and Six Months Ended June 30, 2019 and 2018

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 June 30,					Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change
Average daily throughput (MMcf/d)		260		415	(37%)		273		386	(29%)

Volume throughput declined compared to the three and six months ended June 30, 2018 due to natural production declines from existing wells on pad sites connected to the Summit Utica, partially offset by the completion of new wells at the end of the fourth quarter of 2018 and in the first half of 2019. For the six months ended June 30, 2019, volume throughput was impacted by an increase in temporary production curtailments associated with infill drilling, completion activity and other operational downtime associated with customers on existing pad sites.

Financial data for our Utica Shale reportable segment follows.

	Utica Shale
	Three months ended June 30,							Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	7,591		$	10,422		(27%)	$	15,086		$	20,463		(26%)
Total revenues		7,591			10,422		(27%)		15,086			20,463		(26%)
Costs and expenses:
Operation and maintenance		871			1,090		(20%)		2,087			2,309		(10%)
General and administrative		76			105		(28%)		157			207		(24%)
Depreciation and amortization		1,923			2,033		(5%)		3,831			3,886		(1%)
Total costs and expenses		2,870			3,228		(11%)		6,075			6,402		(5%)
Add:
Depreciation and amortization		1,923			2,033				3,831			3,886
Adjustments related to capital reimbursement activity		(4	)		(4	)			(9	)		(9	)
Segment adjusted EBITDA	$	6,640		$	9,223		(28%)	$	12,833		$	17,938		(28%)

Three and Six months ended June 30, 2019. Segment adjusted EBITDA decreased $2.6 million and $5.1 million compared to the three and six months ended June 30, 2018 primarily due to volume throughput declines discussed above.

Ohio Gathering. The Ohio Gathering reportable segment includes OGC and OCC. We account for our investment in Ohio Gathering using the equity method. 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.

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

	Ohio Gathering
	Three months ended June 30,					Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change
Average daily throughput (MMcf/d)		713		727	(2%)		712		749	(5%)

Volume throughput for Ohio Gathering decreased compared to the three and six months ended June 30, 2018 as a result of natural production declines on existing wells on the system, partially offset by the completion of new wells.

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

	Ohio Gathering
	Three months ended June 30,					Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change
	(Dollars in thousands)
Proportional adjusted EBITDA for equity method investees	$	9,939	$	8,935	11%	$	19,149	$	19,412	(1%)
Segment adjusted EBITDA	$	9,939	$	8,935	11%	$	19,149	$	19,412	(1%)

Segment adjusted EBITDA for Ohio Gathering increased $1.0 million compared to the three months ended June 30, 2018 primarily as a result of lower expenses.

Segment adjusted EBITDA for Ohio Gathering decreased $0.3 million compared to the six months ended June 30, 2018.

Williston Basin. The Polar and Divide, Bison Midstream and Tioga Midstream (through March 22, 2019; refer to Note 17 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 June 30,					Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change
Aggregate average daily throughput - natural gas (MMcf/d)		11		18	(39%)		13		18	(28%)

Aggregate average daily throughput - liquids (Mbbl/d)		94.3		88.9	6%		98.6		86.9	13%

Natural gas. Natural gas volume throughput decreased compared to the three and six months ended June 30, 2018 primarily reflecting natural production declines, the sale of Tioga Midstream and operational downtime on the Bison Midstream system.

Liquids. The increase in liquids volume throughput compared to the three and six months ended June 30, 2018, primarily reflected well completion activity by existing customers on our Polar and Divide system in 2018 and in the first half of 2019 as well as the addition of new customers, partially offset by the sale of Tioga Midstream and natural production declines.

Financial data for our Williston Basin reportable segment follows.

	Williston Basin
	Three months ended June 30,							Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	15,685		$	23,106		(32%)	$	41,391		$	40,772		2%
Natural gas, NGLs and condensate sales		3,768			7,350		(49%)		9,353			15,196		(38%)
Other revenues		2,670			2,960		(10%)		5,578			5,872		(5%)
Total revenues		22,123			33,416		(34%)		56,322			61,840		(9%)
Costs and expenses:
Cost of natural gas and NGLs		1,052			4,200		(75%)		3,761			8,808		(57%)
Operation and maintenance		5,706			5,885		(3%)		12,222			12,710		(4%)
General and administrative		371			597		(38%)		712			1,364		(48%)
Depreciation and amortization		4,734			5,622		(16%)		10,170			11,231		(9%)
(Gain) loss on asset sales, net		(175	)		62		*		(1,143	)		62		*
Long-lived asset impairment		8			—		*		18			—		*
Total costs and expenses		11,696			16,366		(29%)		25,740			34,175		(25%)
Add:
Depreciation and amortization		4,734			5,622				10,170			11,231
Adjustments related to MVC shortfall payments		2,081			(3,386	)			(3,468	)		(3,386	)
Adjustments related to capital reimbursement activity		(425	)		(318	)			(775	)		(572	)
(Gain) loss on asset sales, net		(175	)		62				(1,143	)		62
Long-lived asset impairment		8			—				18			—
Segment adjusted EBITDA	$	16,650		$	19,030		(13%)	$	35,384		$	35,000		1%

* Not considered meaningful

Three months ended June 30, 2019. Segment adjusted EBITDA decreased $2.4 million compared to the three months ended June 30, 2018 primarily reflecting:

•

$2.3 million of segment adjusted EBITDA contributed by the Tioga Midstream system for the three months ended June 30, 2018 with no corresponding contribution in the three months ended June 30, 2019 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower natural gas volume throughput primarily reflecting natural production declines and operational downtime on the Bison Midstream system. The operational downtime was due to third party maintenance on infrastructure located downstream of the Bison Midstream system, which created an operational disruption on the Bison Midstream system for approximately 15 days during the quarter. This was partially offset by higher liquids volume throughput on our Polar and Divide system due to increased drilling activity in 2018 and in the first half of 2019.

Six months ended June 30, 2019. Segment adjusted EBITDA increased $0.4 million compared to the six months ended June 30, 2018 primarily reflecting:

•

Higher liquids volume throughput on our Polar and Divide system due to increased drilling activity in 2018 and in the first half of 2019. This was partially offset by a decrease of $3.4 million of segment adjusted EBITDA contributed by the Tioga Midstream system compared to the six months ended June 30, 2018 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower natural gas volume throughput primarily reflecting natural production declines and operational downtime on the Bison Midstream system. The operational downtime was due to third party maintenance on infrastructure located downstream of the Bison Midstream system, which created an operational disruption on the Bison Midstream system for approximately 15 days during the quarter.

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 June 30,					Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change
Average daily throughput (MMcf/d)		20		16	25%		21		15	40%

Volume throughput increased during the three and six months ended June 30, 2018, compared to the prior periods, primarily as a result of ongoing drilling and completion activity across our service area partially offset by natural production declines.

Financial data for our DJ Basin reportable segment follows.

	DJ Basin
	Three months ended June 30,							Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	4,021		$	2,509		60%	$	7,745		$	4,688		65%
Natural gas, NGLs and condensate sales		101			79		28%		186			159		17%
Other revenues		1,034			969		7%		2,041			1,726		18%
Total revenues		5,156			3,557		45%		9,972			6,573		52%
Costs and expenses:
Cost of natural gas and NGLs		—			7		*		10			14		(29%)
Operation and maintenance		2,028			1,630		24%		3,877			3,106		25%
General and administrative		60			835		(93%)		132			957		(86%)
Depreciation and amortization		464			784		(41%)		1,263			1,565		(19%)
Long-lived asset impairment		38			—		*		34,759			—		*
Total costs and expenses		2,590			3,256		(20%)		40,041			5,642		610%
Add:
Depreciation and amortization		464			784				1,263			1,565
Adjustments related to capital reimbursement activity		(252	)		(126	)			(464	)		(216	)
Long-lived asset impairment		38			—				34,759			—
Segment adjusted EBITDA	$	2,816		$	959		194%	$	5,489		$	2,280		141%

* Not considered meaningful

Three months ended June 30, 2019. Segment adjusted EBITDA increased $1.9 million compared to the three months ended June 30, 2018, primarily reflecting:

•

A $1.5 million increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity and a more favorable volume mix from customers, partially offset by natural production declines.

•

a $0.8 million decrease in general and administrative expense primarily due to lower professional service fees.

•

a $0.4 million increase in operation and maintenance expense primarily due to higher costs to support increased volumes.

Six months ended June 30, 2019. Segment adjusted EBITDA increased $3.2 million compared to the six months ended June 30, 2018, primarily reflecting:

•

A $3.1 million increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity and a more favorable volume mix from customers, partially offset by natural production declines.

•

a $0.8 million decrease in general and administrative expense primarily due to lower professional service fees.

•

a $0.8 million increase in operation and maintenance expense primarily due to higher costs to support volume growth.

Other items to note:

•

During the quarter ended March 31, 2019, we impaired certain long-lived assets in the DJ Basin (see Note 5 to the unaudited condensed consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the three and six months ended June 30, 2019.

Permian Basin. The Summit Permian system provides our midstream services for the Permian Basin reportable segment, which commenced operations late in the fourth quarter of 2018.

Average daily volume throughput during the three and six months ended June 30, 2019 totaled 17 MMcf/d and 16 MMcf/d, respectively.

Financial data for our Permian Basin reportable segment follows.

	Permian Basin
	Three months ended June 30, 2019			Six months ended June 30, 2019
	(In thousands)
Revenues:
Gathering services and related fees	$	586		$	952
Natural gas, NGLs and condensate sales		2,406			6,627
Other revenues		49			81
Total revenues		3,041			7,660
Costs and expenses:
Cost of natural gas and NGLs		1,882			6,127
Operation and maintenance		1,733			2,624
General and administrative		82			115
Depreciation and amortization		1,163			2,235
Gain on asset sales, net		(120	)		(120	)
Long-lived asset impairment		8			8
Total costs and expenses		4,748			10,989
Add:
Depreciation and amortization		1,163			2,235
Gain on asset sales, net		(120	)		(120	)
Long-lived asset impairment		8			8
Segment adjusted EBITDA	$	(656	)	$	(1,206	)

Three and Six months ended June 30, 2019. Segment adjusted EBITDA totaled ($0.7) million and ($1.2) million for the three and six months ended June 30, 2019, respectively, primarily reflecting fixed operating costs associated with commissioning and operating the Lane processing plant and certain inefficiencies and higher fuel costs associated with lower plant utilization and initial production volumes.

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 June 30,					Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change
Aggregate average daily throughput (MMcf/d)		462		560	(18%)		473		562	(16%)

Volume throughput decreased compared to the three and six months ended June 30, 2018, primarily as a result of natural production declines and operational downtime, partially offset by drilling and completion activity that occurred across our service area through the third quarter of 2018.

Financial data for our Piceance Basin reportable segment follows.

	Piceance Basin
	Three months ended June 30,							Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	30,555		$	33,661		(9%)	$	62,395		$	66,776		(7%)
Natural gas, NGLs and condensate sales		2,104			4,596		(54%)		4,406			8,841		(50%)
Other revenues		945			1,178		(20%)		2,083			2,389		(13%)
Total revenues		33,604			39,435		(15%)		68,884			78,006		(12%)
Costs and expenses:
Cost of natural gas and NGLs		1,280			2,952		(57%)		2,753			5,513		(50%)
Operation and maintenance		7,108			9,538		(25%)		14,407			17,382		(17%)
General and administrative		302			383		(21%)		596			709		(16%)
Depreciation and amortization		11,810			11,666		1%		23,601			23,440		1%
Loss on asset sales, net		3			—		*		3			—		*
Total costs and expenses		20,503			24,539		(16%)		41,360			47,044		(12%)
Add:
Depreciation and amortization		11,810			11,666				23,601			23,440
Loss on asset sales, net		3			—				3			—
Adjustments related to MVC shortfall payments		—			(93	)			(103	)		(93	)
Adjustments related to capital reimbursement activity		(330	)		245				(442	)		319
Segment adjusted EBITDA	$	24,584		$	26,714		(8%)	$	50,583		$	54,628		(7%)

*Not considered meaningful

Three months ended June 30, 2019. Segment adjusted EBITDA decreased $2.1 million compared to the three months ended June 30, 2018, primarily reflecting:

•

a $3.1 million decrease in gathering services and related fees as a result of natural production declines and operational downtime.

•

a $0.8 million decrease in natural gas, NGLs and condensate activity (sales and purchases) as a result of lower volume throughput and lower commodity prices associated with the sale of NGLs and condensate.

•

a $2.4 million decrease in operation and maintenance expense primarily due to a $1.6 million reduction in planned compressor overhaul maintenance costs and $0.5 million in lower compensation expense.

Six months ended June 30, 2019. Segment adjusted EBITDA decreased $4.0 million compared to the six months ended June 30, 2018, primarily reflecting:

•

a $4.4 million decrease in gathering services and related fees as a result of natural production declines and operational downtime.

•

a $1.7 million decrease in natural gas, NGLs and condensate activity (sales and purchases) as a result of lower volume throughput and lower commodity prices associated with the sale of NGLs and condensate.

•

a $3.0 million decrease in operation and maintenance expense primarily due to a $1.8 million reduction in planned compressor overhaul maintenance costs, $0.7 million in lower compensation expense and $0.3 million in lower property taxes.

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 June 30,					Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change
Average daily throughput (MMcf/d)		251		264	(5%)		260		263	(1%)

Volume throughput declined compared to the three and six months ended June 30, 2018 reflecting natural production declines, partially offset by new volumes from well completion activity during the first quarter of 2019.

Financial data for our Barnett Shale reportable segment follows.

	Barnett Shale
	Three months ended June 30,							Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	11,428		$	14,080		(19%)	$	24,453		$	27,717		(12%)
Natural gas, NGLs and condensate sales		6,273			381		1546%		6,877			926		643%
Other revenues (1)		1,646			1,694		(3%)		3,302			3,682		(10%)
Total revenues		19,347			16,155		20%		34,632			32,325		7%
Costs and expenses:
Cost of natural gas and NGLs		4,574			—		*		4,574			—		*
Operation and maintenance		5,116			4,942		4%		10,614			11,115		(5%)
General and administrative		238			235		1%		466			546		(15%)
Depreciation and amortization		3,804			3,909		(3%)		7,745			7,817		(1%)
Loss (gain) on asset sales, net		—			—		*		7			(74	)	(109%)
Long-lived asset impairment		16			—		*		10,236			—		*
Total costs and expenses		13,748			9,086		51%		33,642			19,404		73%
Add:
Depreciation and amortization		4,167			3,759				8,497			7,516
Adjustments related to MVC shortfall payments		1,452			(63	)			2,905			(63	)
Adjustments related to capital reimbursement activity		(26	)		328				(53	)		652
Loss (gain) on asset sales, net		—			—				7			(74	)
Long-lived asset impairment		16			—				10,236			—
Segment adjusted EBITDA	$	11,208		$	11,093		1%	$	22,582		$	20,952		8%

*Not considered meaningful

(1) Includes the amortization expense associated with our favorable and unfavorable (in 2018) gas gathering contracts as reported in other revenues.

Three months ended June 30, 2019. Segment adjusted EBITDA was flat compared to the three months ended June 30, 2018 primarily reflecting:

•

a $1.5 million increase in adjustments related to MVC shortfall payments attributable to an expected cumulative shortfall payment from a certain customer due in the fourth quarter of 2019, offset by a $1.5 million decrease in gathering services and related fees primarily reflecting lower volume throughput and lower gathering rate mix. Also impacting 2019 revenues was the presentation of $1.2 million of gathering services as a reduction to cost of natural gas and NGLs due to the transfer of certain marketing arrangements from Corporate and Other to our DFW Midstream operations.

Six months ended June 30, 2019. Segment adjusted EBITDA increased $1.6 million compared to the six months ended June 30, 2018 primarily reflecting:

•

a $2.9 million increase in adjustments related to MVC shortfall payments attributable to an expected cumulative shortfall payment from a certain customer due in the fourth quarter of 2019, partially offset by a $2.1 million decrease in gathering services and related fees primarily reflecting lower volume throughput and lower gathering rate mix. Also impacting 2019 revenues was the presentation of $1.2 million of gathering services as a reduction to cost of natural gas and NGLs due to the transfer of certain marketing arrangements from Corporate and Other to our DFW Midstream operations.

•

a $0.5 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 5 to the unaudited condensed consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the three and six months ended June 30, 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 June 30,					Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change
Average daily throughput (MMcf/d)		347		524	(34%)		363		523	(31%)

Volume throughput decreased compared to the three and six months ended June 30, 2018 primarily due to natural production declines.

Financial data for our Marcellus Shale reportable segment follows.

	Marcellus Shale
	Three months ended June 30,							Six months ended June 30,
	2019			2018			Percentage Change	2019			2018			Percentage Change
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	5,897		$	8,050		(27%)	$	12,094		$	15,875		(24%)
Total revenues		5,897			8,050		(27%)		12,094			15,875		(24%)
Costs and expenses:
Operation and maintenance		1,155			1,400		(18%)		2,109			2,426		(13%)
General and administrative		97			97		*		189			211		(10%)
Depreciation and amortization		2,286			2,274		1%		4,569			4,546		1%
Total costs and expenses		3,538			3,771		(6%)		6,867			7,183		(4%)
Add:
Depreciation and amortization		2,286			2,274				4,569			4,546
Adjustments related to capital reimbursement activity		(10	)		(10	)			(19	)		(19	)
Segment adjusted EBITDA	$	4,635		$	6,543		(29%)	$	9,777		$	13,219		(26%)

*Not considered meaningful

Three months ended June 30, 2019. Segment adjusted EBITDA decreased $1.9 million compared to the three months ended June 30, 2018 primarily reflecting:

•

a $2.2 million decrease in gathering services and related fees as a result of volume declines.

•

a $0.2 million decrease in operation and maintenance expense.

Six months ended June 30, 2019. Segment adjusted EBITDA decreased $3.4 million compared to the six months ended June 30, 2018 primarily reflecting:

•

a $3.8 million decrease in gathering services and related fees as a result of volume declines.

•

a $0.3 million decrease in operation and maintenance expense.

Corporate and Other Overview for the Three and Six Months Ended June 30, 2019 and 2018

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, transaction costs, interest expense and the change in the Deferred Purchase Price Obligation.

	Corporate and Other
	Three months ended June 30,					Six months ended June 30,
	2019		2018		Percentage Change	2019		2018		Percentage Change
	(Dollars in thousands)
Revenues:
Total revenues		2,927		17,148	(83%)	$	26,444	$	30,421	(13%)
Costs and expenses:
Cost of natural gas and NGLs		2,783		17,225	(84%)		26,105		30,334	(14%)
General and administrative		8,988		11,233	(20%)		25,128		23,933	5%
Transaction costs		—		—	*		950		—	*
Interest expense		17,941		14,837	21%		35,468		29,959	18%
Deferred Purchase Price Obligation		3,712		69,305	*		8,139		90,963	*

* 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 $14.2 million and $4.0 million for the three and six months ended June 30, 2019, respectively, 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 $14.4 million and $4.2 million for the three and six months ended June 30, 2019, respectively, was attributable to lower marketing activity.

General and Administrative. General and administrative expense decreased $2.2 million, compared to the three months ended June 30, 2018 primarily due to a $2.0 million decrease in compensation expense and a $0.4 million decrease in professional service fees.

General and administrative expense increased $1.2 million, compared to the six months ended June 30, 2018 primarily due to the recognition of $3.4 million in severance expense relating to our former Chief Executive Officer partially offset by a $1.7 million decrease in compensation expense.

Transaction costs. Transaction costs recognized during the six months ended June 30, 2019 relate to financial advisory costs primarily associated with the Equity Restructuring.

Interest Expense. Interest expense increased $3.1 million and $5.5 million compared to the three and six months ended June 30, 2018, respectively, primarily as a result of a higher average outstanding balance on the Revolving Credit Facility.

Liquidity and Capital Resources

Based on the terms of our Partnership Agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flows generated from our operations, borrowings under our Revolving Credit Facility, future issuances of debt, equity and preferred equity securities and proceeds from potential asset divestitures.

Capital Markets Activity

We had no capital markets activity during the six months ended June 30, 2019. For additional information, see the "Liquidity and Capital Resources—Capital Markets Activity" section of MD&A included in the 2018 Annual Report.

Debt

Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility. As of June 30, 2019, the outstanding balance of the Revolving Credit Facility was $573.0 million and the unused portion totaled $667.9 million, after giving effect to the issuance thereunder of a $9.1 million outstanding but undrawn irrevocable standby letter of credit. There were no defaults or events of default during the six months ended June 30, 2019, and, as of June 30, 2019, we were in compliance with the financial covenants in the Revolving Credit Facility. In June 2019, we executed the second amendment to the third amended and restated credit agreement that, among other things, made accommodations for the Agreement, and the transactions contemplated thereby, and designated Double E as an unrestricted subsidiary under the Revolving Credit Facility. See Notes 10 and 16 to the unaudited condensed consolidated financial statements for more information on the Revolving Credit Facility and the issuance of the $9.1 million letter of credit, respectively. A copy of the amendment is filed as Exhibit 10.2 to this report on Form 10-Q.

Senior Notes. In February 2017, the Co-Issuers co-issued $500.0 million 5.75% Senior Notes. In July 2014, the Co-Issuers co-issued $300.0 million of 5.50% Senior Notes. There were no defaults or events of default as of and for the six months ended June 30, 2019 on either series of senior notes.

For additional information on our long-term debt, see Note 10 to the unaudited condensed consolidated financial statements.

Deferred Purchase Price Obligation

In March 2016, we entered into an agreement with a subsidiary of Summit Investments to fund a portion of the 2016 Drop Down whereby we have recognized the Deferred Purchase Price Obligation (see Note 17 to the unaudited condensed consolidated financial statements and the “Contractual Obligations Update” section below).

Cash Flows

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

	Six months ended June 30,
	2019			2018
	(In thousands)
Net cash provided by operating activities	$	96,246		$	110,049
Net cash used in investing activities		(20,160	)		(90,204	)
Net cash used in financing activities		(79,896	)		(13,063	)
Net change in cash and cash equivalents	$	(3,810	)	$	6,782

Operating activities. Cash flows from operating activities for the six months ended June 30, 2019 primarily reflected:

•

a $6.5 million increase in cash interest payments; and

•

other changes in working capital.

Investing activities. Cash flows used in investing activities during the six months ended June 30, 2019 primarily reflected:

•

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

•

$111.1 million of capital expenditures primarily attributable to the ongoing development of the DJ Basin of $50.4 million, Summit Permian of $28.2 million, Corporate and Other, which includes $15.4 million of capital expenditures relating to the Project, and the Williston Basin of $14.2 million;

•

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

•

$5.9 million for an investment in an equity method investee.

Cash flows used in investing activities during the six months ended June 30, 2018 primarily reflected $90.4 million of capital expenditures attributable to the development of the Summit Permian system as well as the continued development in the DJ Basin.

Financing activities. Cash flows used in financing activities during the six months ended June 30, 2019 primarily reflected:

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$83.3 million of distributions;

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$107.0 million of net borrowings under our Revolving Credit Facility; and

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$100.0 million payment on the Deferred Purchase Price Obligation.

Cash flows used in financing activities during the six months ended June 30, 2018 primarily reflected:

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$95.0 million of net borrowings under our Revolving Credit Facility; and

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$104.5 million of distributions.

Contractual Obligations Update

In March 2016, we recognized the Deferred Purchase Price Obligation in connection with the 2016 Drop Down. Pursuant to the Equity Restructuring, in April 2019, the Partnership made a cash payment of $100 million to SMP Holdings in partial settlement of the Deferred Purchase Price Obligation. Following the payment, the Remaining Consideration was fixed at $303.5 million with such amount being payable by the Partnership in one or more payments over the period from March 1, 2020 through December 31, 2020, in (i) cash, (ii) the Partnership’s common units or (iii) a combination of cash and the Partnership’s common units, at the discretion of the Partnership. At least 50% of the Remaining Consideration must be paid on or before June 30, 2020 and interest will accrue at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020.

For additional information, see Note 17 to the unaudited condensed consolidated financial statements.

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:

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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

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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 six months ended June 30, 2019, cash paid for capital expenditures totaled $111.1 million (see Note 4 to the unaudited condensed consolidated financial statements) which included $7.0 million of maintenance capital expenditures. For the six months ended June 30, 2019, there were no contributions to Ohio Gathering and we contributed $5.3 million to Double E (see Note 8 to the unaudited condensed consolidated financial statements).

Our growth strategy has required and will continue to require significant expenditures by us. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. 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 agreement 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 sources such as our Sponsor and Summit Investments, among other factors.

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, to fund our capital expenditures. We believe that our Revolving Credit Facility, together with internally generated cash flow and financial support from our Sponsor and/or access to debt or equity capital markets, will be adequate to finance our growth objectives for the foreseeable future without adversely impacting our liquidity or our ability to make quarterly cash distributions to our unitholders.

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 customer, who was not meeting its MVCs, 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.

For additional information, see Notes 4, 9 and 11 to the unaudited condensed consolidated financial statements.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the six months ended June 30, 2019.

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, 2018 except for the adoption of Topic 842 (see Note 2 to the unaudited condensed consolidated financial statements).

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, our subsidiaries, Summit Investments or our Sponsor, 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:

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our ability to grow, or maintain, our current rate of cash distributions;

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fluctuations in natural gas, NGLs and crude oil prices;

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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;

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

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

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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;

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our ability to acquire assets owned by third parties, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets and our ability to obtain financing on acceptable terms;

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the ability to attract and retain key management personnel;

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

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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;

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

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

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

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

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

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

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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;

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our ability to finance our obligations related to the capital expenditures required for our projects, including potential asset divestitures and the impact any such divestitures could have on our results;

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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;

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changes in tax status;

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the effects of litigation;

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changes in general economic conditions; and

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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 June 30, 2019, we had $800.0 million principal of fixed-rate Senior Notes and $573.0 million outstanding under our variable rate Revolving Credit Facility (see Note 10 to the unaudited condensed consolidated financial statements). 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, 2018. For additional information, see the "Interest Rate Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2018 Annual Report.

Commodity Price Risk

We currently generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, many of which include MVCs and 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 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 Henry Hub Index and/or the Atmos Zone 3 Index. By basing the power prices on an index and basin-relevant market, 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, 2018. For additional information, see the "Commodity Price Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2018 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 June 30, 2019 and (ii) no change in internal control over financial reporting occurred during the quarter ended June 30, 2019, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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, except as noted below. 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 16 to our unaudited condensed consolidated financial statements “Commitments and Contingencies” and in the 2018 Annual Report, which is incorporated herein by reference.

Item 1A. Risk Factors.

The risk factors contained in the Item 1A. Risk Factors of (i) the 2018 Annual Report and (ii) the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2019 as filed with the SEC on May 10, 2019 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.

Item 6. Exhibits.

Exhibit number		Description
3.1		Third Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated as of March 22, 2019 (Incorporated herein by reference to Exhibit 3.1 to SMLP's Current Report on Form 8-K dated March 22, 2019 (Commission File No. 001-35666))
3.2		Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K filed October 4, 2012 (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	†	Form of Retention Bonus Agreement (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated June 11, 2019 (Commission File Number 001-35666))
10.2	*	Second Amendment to Third Amended and Restated Credit Agreement dated as of June 26, 2019
31.1		Rule 13a-14(a)/15d-14(a) Certification, executed by Leonard W. Mallett, 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 Leonard W. Mallett, President, Chief Executive Officer and Director, and Marc D. Stratton, Executive Vice President and Chief Financial Officer
101.INS	**	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	**	XBRL Taxonomy Extension Schema
101.CAL	**	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	**	XBRL Taxonomy Extension Definition Linkbase
101.LAB	**	XBRL Taxonomy Extension Label Linkbase
101.PRE	**	XBRL Taxonomy Extension Presentation Linkbase
104	**	Cover Page Interactive Data File – the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

† Management contract or compensatory plan or arrangement that is incorporated by reference pursuant to Item 9.01(d) of SMLP’s Form 8-K filed June 11, 2019 (Commission File Nos. 001-35666).

* 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.

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)

August 9, 2019	/s/ Marc D. Stratton

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