Summit Midstream Partners (SMLP) 8-K Summit Midstream Partners, LP

EXHIBIT 99.1

Summit Midstream Partners, LP 1790 Hughes Landing Blvd, Suite 500 The Woodlands, TX 77380  

Summit Midstream Partners, LP Reports Third Quarter 2018

Financial Results and Provides Update for Double E Pipeline

- Third quarter 2018 net income of $57.5 million, adj. EBITDA of $73.4 million and DCF of $43.6 million

- Williston liquids volumes up 30.9% over third quarter of 2017 and up 9.0% over second quarter of 2018

- SMLP reaffirms 2018 adj. EBITDA guidance of $285.0 million to $300.0 million and capex guidance of $175.0 million to $225.0 million

- 2019 adj. EBITDA expected to increase by more than 10% over 2018 with distribution coverage exceeding 1.15x by the fourth quarter of 2019

- Commercialization of Double E Pipeline continues to progress with new committed shippers; expect to achieve commercial operation date in second quarter of 2021

The Woodlands, Texas (November 8, 2018) – Summit Midstream Partners, LP (NYSE: SMLP) announced today its financial and operating results for the three and nine months ended September 30, 2018.  SMLP reported net income of $57.5 million for the third quarter of 2018, compared to net income of $93.6 million for the prior-year period.  Net income in the third quarter of 2018 included $37.2 million of non-cash income related to a decrease in the present value of the estimated Deferred Purchase Price Obligation (“DPPO”).  Net income for the prior-year period included $70.5 million of non-cash income related to a decrease in the present value of the estimated DPPO.  Net cash provided by operations totaled $56.4 million for the third quarter of 2018, compared to $75.2 million for the prior-year period.  Adjusted EBITDA totaled $73.4 million and distributable cash flow (“DCF”) totaled $43.6 million for the third quarter of 2018, compared to $73.5 million and $52.9 million, respectively, for the prior-year period.  Relative to the prior-year period, DCF in the third quarter of 2018 included a $7.1 million distribution adjustment associated with our issuance of Series A Preferred units in the fourth quarter of 2017 and $2.9 million of higher maintenance capital expenditures.  

Steve Newby, President and Chief Executive Officer, commented, “SMLP reported another strong quarter of operating and financial results in the third quarter of 2018, primarily reflecting our Williston customers’ robust level of drilling and completion activity, which generated liquids volume growth of nearly 31% compared to the third quarter of 2017.  Our business continues to perform in line with our expectations and as such, we are reaffirming our 2018 adjusted EBITDA guidance of $285.0 million to $300.0 million and full year 2018 distribution coverage of approximately 1.00x.  Producer activity levels in our service areas, amidst a constructive fundamental backdrop, support our volume growth expectations for the balance of 2018 and into 2019.  Additionally, our gathering and processing projects in the northern Delaware and DJ Basin are expected to provide meaningful growth for SMLP upon their commissioning this quarter.  We expect utilization of this new processing capacity to increase significantly throughout 2019.  

We expect to provide formal 2019 financial guidance in February 2019, in accordance with our annual budgeting process, with our fourth quarter of 2018 earnings release.  At this time, we are providing a preliminary view on 2019 adjusted EBITDA, which we expect will be at least 10% higher compared to adjusted EBITDA in 2018.  Our balance sheet and liquidity position remain strong, and we expect that the forecasted growth in adjusted EBITDA and DCF in 2019 will enable us to return our distribution coverage ratio to levels in excess of 1.15x by the fourth quarter of 2019.

Our Double E project continues to represent an important and strategic project for SMLP, enabling us to provide a natural gas transportation solution for XTO and other shippers in the northern Delaware.  We have successfully added additional shippers and continue to engage in discussions with several other prospective shippers on Double E.  We remain on schedule for commercial operation date in the second quarter of 2021.”

SMLP reported net income of $3.7 million for the first nine months of 2018, compared to net income of $104.3 million for the prior-year period.  Net cash provided by operations totaled $166.5 million for the first nine months of 2018, compared to $196.5 million in the prior-year period.  SMLP reported adjusted EBITDA of $217.2 million and DCF of $134.9 million for the nine months ended September 30, 2018, compared to $217.5 million and $155.8 million, respectively, for the prior-year period.

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EXHIBIT 99.1

Double E Pipeline Project Update

In July 2018, SMLP entered into a precedent agreement with XTO Energy Inc. (“XTO”), a wholly owned subsidiary of Exxon Mobil Corporation (“ExxonMobil”), for firm transportation capacity on the Double E Pipeline Project (“Double E” or the “Project”) under a 10-year take-or-pay agreement which increases up to 500,000 dekatherms per day (“dth/d”).  In August and September of 2018, SMLP conducted a binding open season process to gauge market interest in the Project and obtain additional firm transportation commitments on Double E.  As a result of the binding open season, SMLP executed additional precedent agreements with new shippers and is continuing to discuss potential firm volume commitments with other prospective shippers.  SMLP expects to make its final investment decision (“FID”) on Double E once these negotiations have concluded, given that the outcome of these discussions could have a material impact on the scope of the Project.  The Project will provide up to 1.5 Bcf/d of residue natural gas transportation capacity from the northern Delaware Basin to the Waha Hub. 

SMLP remains on schedule for its original target in-service date for the Project of the second quarter of 2021; however, the ultimate in-service date of the Project will be subject to, among other things, the timing of the FID and approval by the Federal Energy Regulatory Commission (“FERC”) and other governmental authorities.

SMLP and ExxonMobil executed an equity option agreement in July 2018, which provides ExxonMobil, or an affiliate, the right to become an equity partner in Double E.  We expect ExxonMobil to make a decision on its equity option agreement by June 30, 2019.  SMLP has also received significant interest from other potential shippers and financial parties regarding equity participation in the Project. 

Third Quarter 2018 Segment Results

Natural gas volume throughput averaged 1,629 million cubic feet per day (“MMcf/d”) in the third quarter of 2018, a decrease of 10.8% compared to 1,826 MMcf/d in the prior-year period, and a decrease of 9.3% compared to 1,797 MMcf/d in the second quarter of 2018.  SMLP’s natural gas volume throughput metrics exclude its proportionate share of volume throughput from its 40% interest in Ohio Gathering, which averaged 797 MMcf/d in the third quarter of 2018, an increase of 4.5% compared to 763 MMcf/d in the prior-year period.  

Crude oil and produced water volume throughput in the third quarter of 2018 averaged 96.9 thousand barrels per day (“Mbbl/d”), an increase of 30.9% compared to 74.0 Mbbl/d in the prior-year period, and an increase of 9.0% compared to 88.9 Mbbl/d in the second quarter of 2018.  

The following table presents average daily throughput by reportable segment:

	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
Average daily throughput (MMcf/d):
Utica Shale		357		403		376		364
Williston Basin		19		21		18		19
Piceance/DJ Basins		571		594		574		601
Barnett Shale		232		254		253		270
Marcellus Shale		450		554		499		490
Aggregate average daily throughput		1,629		1,826		1,720		1,744
Average daily throughput (Mbbl/d):
Williston Basin		96.9		74.0		90.9		74.7
Aggregate average daily throughput		96.9		74.0		90.9		74.7
Ohio Gathering average daily throughput     (MMcf/d) (1)		797		763		765		746

__________

(1) Gross basis, represents 100% of volume throughput for Ohio Gathering, based on a one-month lag.

EX 99.1-2

EXHIBIT 99.1

Utica Shale

The Utica Shale reportable segment includes Summit Midstream Utica (“SMU”), a natural gas gathering system located in Belmont and Monroe counties in southeastern Ohio.  SMU gathers and delivers dry natural gas to interconnections with a third-party intrastate pipeline that provides access to the Clarington Hub.  

Segment adjusted EBITDA for the third quarter of 2018 totaled $6.5 million, a decrease of 22.5% from $8.4 million for the prior-year period and a decrease of 29.3% from $9.2 million in the second quarter of 2018. Total volume throughput averaged 357 MMcf/d in the third quarter of 2018, compared to 403 MMcf/d in the prior-year period and 415 MMcf/d in the second quarter of 2018.  Volumes were lower in the third quarter of 2018 compared to both the prior-year period and the second quarter of 2018 primarily due to natural production declines, together with an estimated 40 MMcf/d of temporary volume curtailments related to infill drilling and completion activities on existing pad sites.  Volume throughput on the TPL-7 Connector project, which generates a lower gathering margin compared to volumes gathered directly from a pad site, totaled 148 MMcf/d in the third quarter of 2018, compared to 74 MMcf/d in the prior year period and 124 MMcf/d in the second quarter of 2018.      

Our customers are currently operating one drilling rig upstream of the SMU system.  One SMU customer has recently communicated its intent to increase drilling activities in the liquids-rich and condensate windows of the Utica Shale in 2018 and 2019, versus SMU’s dry gas service area.  This shift is expected to negatively impact the rate of volume and segment adjusted EBITDA growth in 2019, compared to previous expectations, but should serve as a positive catalyst for SMLP’s Ohio Gathering reportable segment.  Because SMU is an asset that is included in the DPPO calculation, we have reflected such slower 2019 growth expectations in the estimated future value of the DPPO as of September 30, 2018.

Ohio Gathering

The Ohio Gathering reportable segment includes our 40% ownership interest in Ohio Gathering, a natural gas gathering system spanning the condensate, liquids-rich and dry gas windows of the Utica Shale in Harrison, Guernsey, Noble, Belmont and Monroe counties in southeastern Ohio.  This segment also includes our 40% ownership interest in Ohio Condensate, a condensate stabilization facility located in Harrison County, Ohio.  Segment adjusted EBITDA for the Ohio Gathering segment includes our proportional share of adjusted EBITDA from Ohio Gathering and Ohio Condensate, based on a one-month lag.  

Segment adjusted EBITDA for the third quarter of 2018 totaled $10.2 million, a decrease of 3.3% from $10.5 million for the prior-year period and an increase of 13.8% from $8.9 million for the second quarter of 2018.  Volume throughput on the Ohio Gathering system averaged 797 MMcf/d, gross, in the third quarter of 2018, compared to 763 MMcf/d, gross, in the prior-year period and 727MMcf/d, gross, in the second quarter of 2018.  Higher volumes in the third quarter of 2018 were a result of 20 new wells that were connected late in the second quarter of 2018 and 20 new wells that were connected in the third quarter of 2018.  

Producer activity levels on the Ohio Gathering system have steadily increased throughout 2018, particularly in the areas that serve the rich gas and condensate windows of the Utica Shale, which have generated attractive well results as a result of improved drilling and completion techniques and higher commodity prices.  Our customers are currently operating three drilling rigs upstream of the Ohio Gathering system.

Williston Basin

The Polar and Divide, Tioga Midstream and Bison Midstream systems provide our midstream services for the Williston Basin reportable segment.  The Polar and Divide system gathers crude oil in Williams and Divide counties in North Dakota and delivers to third-party intra- and interstate pipelines as well as third-party rail terminals.  The Polar and Divide system also gathers and delivers produced water to various third-party disposal wells in the region.  Tioga Midstream is a crude oil, produced water and associated natural gas gathering system in Williams County, North Dakota.  All crude oil and natural gas gathered on the Tioga Midstream system is delivered to third-party pipelines, and all produced water is delivered to third-party disposal wells.  Bison Midstream gathers associated natural gas production in Mountrail and Burke counties in North Dakota and delivers to third-party pipelines serving a third-party processing plant in Channahon, Illinois.  

Segment adjusted EBITDA for the Williston Basin segment totaled $19.8 million for the third quarter of 2018, an increase of 22.4% compared to $16.2 million for the prior-year period and an increase of 4.3% from $19.0 million for the second quarter of 2018.  The increase over the second quarter of 2018 primarily resulted from 20 new well connections in the period, which generated higher liquids volume throughput, primarily across the Polar and Divide system.  Six of these new wells were drilled by a new customer that executed a gathering agreement with SMLP in the third quarter of 2017.  

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EXHIBIT 99.1

Liquids volumes averaged 96.9 Mbbl/d in the third quarter of 2018, a new quarterly record for SMLP.  Third quarter 2018 volumes represented an increase of 30.9% from 74.0 Mbbl/d in the prior-year period and an increase of 9.0% compared to 88.9 Mbbl/d in the second quarter of 2018.  Segment adjusted EBITDA in the third quarter of 2018 was negatively impacted by an estimated 12.0 Mbbl/d resulting from (i) certain customers initiating temporary production curtailments on existing wells for nearby drilling and completion activities, and (ii) produced water capacity constraints at third party disposal wells, which necessitated third-party trucking service.  

Associated natural gas volumes averaged 19 MMcf/d in the third quarter of 2018, a decrease of 9.5% from the prior-year period, and a 5.6% increase from the second quarter of 2018.  Six new associated natural gas wells were connected to our Williston gathering systems in the third quarter of 2018, four of which were drilled by a new customer that executed a gathering agreement with SMLP in the third quarter of 2018.    

Our Williston Basin segment continues to benefit from consistent drilling activity and improving wells results from our customers.  Currently, our customers are operating three drilling rigs upstream of the systems that comprise our Williston Basin reportable segment.  In addition, our quarterly financial and operating results have been impacted by recent commercial successes and our execution of several new gathering agreements in the last twelve months.  We expect that the combination of these activities will generate continued volume throughput and segment adjusted EBITDA growth for our Williston Basin segment in the near- and intermediate-term.

Piceance/DJ Basins

The Grand River and the Niobrara G&P systems provide our midstream services for the Piceance/DJ Basins reportable segment.  These systems provide natural gas gathering and processing services for producers operating in the Piceance Basin located in western Colorado and eastern Utah and in the Denver-Julesburg (“DJ”) Basin located in northeastern Colorado.  

Segment adjusted EBITDA totaled $29.8 million for the third quarter of 2018, in line with $30.0 million in the prior-year period and an increase of 7.8% from $27.7 million in the second quarter of 2018.  The Piceance/DJ Basins reportable segment generated $1.2 million of lower G&A expense in the third quarter of 2018, compared to the second quarter of 2018, primarily due to certain expense reimbursement activities.  Third quarter 2018 volume throughput averaged 571 MMcf/d, a decrease of 3.9% from 594 MMcf/d in the prior-year period and in line with the 576 MMcf/d in the second quarter of 2018.  Volume declines relative to the prior-year period were partially offset by the completion of 39 new wells in the third quarter of 2018, including 23 new wells upstream of the Niobrara G&P system in the DJ Basin, which generates higher margin revenue compared to the Grand River system.  In the third quarter of 2018, the Niobrara G&P system operated at approximately 85% utilization, including approximately 95% utilization in September 2018.    

Volume throughput on the Niobrara G&P system will be constrained by our current 20 MMcf/d of processing capacity until our new 60 MMcf/d processing plant is commissioned, which is expected to occur in the fourth quarter of 2018.  Currently, our Piceance/DJ segment customers are operating four drilling rigs, all of which are working upstream of the Niobrara G&P system, and we expect significant drilling and completion activity to continue in and around this system’s service area throughout 2019.

Barnett Shale

The DFW Midstream system provides our midstream services for the Barnett Shale reportable segment.  This system gathers and delivers low-pressure natural gas received from pad sites, primarily located in southeastern Tarrant County, Texas, to downstream intrastate pipelines serving various natural gas hubs in the region.  

Segment adjusted EBITDA for the Barnett Shale segment totaled $10.8 million for the third quarter of 2018, in line with $10.8 million in the prior-year period and a 2.5% decrease from $11.1 million in the second quarter of 2018.  Volume throughput in the third quarter of 2018 averaged 232 MMcf/d, which was down 8.7% compared to the prior-year period of 254 MMcf/d and down 12.1% from 264 MMcf/d in the second quarter of 2018.  Volume throughput in the third quarter of 2018 was negatively affected by temporary curtailments associated with simultaneous drilling and completion activities, together with our required annual regulatory system shutdown, which resulted in limited volumes for approximately five days in September.  Collectively, these activities impacted volume throughput in the third quarter of 2018 by an estimated 15 MMcf/d.  In addition, we recognized an approximate $1.0 million net impact to adjusted EBITDA in the third quarter of 2018, related to a customer’s estimated MVC shortfall payment due in October 2019.  

Drilling and well permitting activities in our DFW Midstream system service area have remained relatively steady throughout 2018.  A customer completed five new wells on the DFW Midstream system late in the quarter, which

EX 99.1-4

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increased third quarter exit rate volumes to approximately 260 MMcf/d.  We expect four new well connections by a separate customer by the end of the 2018, which we expect will have a positive impact on volume throughput in the first quarter of 2019.

Marcellus Shale

The Mountaineer Midstream system provides our midstream services for the Marcellus Shale reportable segment. This system gathers high-pressure natural gas received from upstream pipeline interconnections with Antero Midstream Partners, LP and Crestwood Equity Partners LP.  Natural gas on the Mountaineer Midstream system is delivered to the Sherwood Processing Complex located in Doddridge County, West Virginia.  

Segment adjusted EBITDA for the Marcellus Shale segment totaled $5.6 million for the third quarter of 2018, a decrease of 16.9% from $6.7 million for the prior-year period and a decrease of 15.2% from $6.5 million for the second quarter of 2018.  Segment adjusted EBITDA was lower in the third quarter of 2018 primarily due to a decrease in volume throughput, which averaged 450 MMcf/d in the third quarter of 2018, compared to 554 MMcf/d in the prior-year period and 524 MMcf/d in the second quarter of 2018.  Volume throughput was lower in the third quarter of 2018 due to natural production declines, primarily related to the 27 wells that were commissioned upstream of the Mountaineer Midstream system in 2017 and an additional 9 wells commissioned in the first quarter of 2018.  

No new wells were completed in the second or third quarters of 2018, and no new wells are expected for the remainder of 2018.

MVC Shortfall Payments

SMLP billed its customers $12.4million in the third quarter of 2018 related to MVC shortfalls.  For those customers that do not have credit banking mechanisms in their gathering agreements, or do not have the ability to use MVC shortfall payments as credits, the MVC shortfall payments are accounted for as gathering revenue in the period in which they are earned.  

In the third quarter of 2018, SMLP recognized $18.8million of gathering revenue associated with MVC shortfall payments from certain customers in each of its reportable segments.  SMLP also recognized ($3.0) million of adjustments to MVC shortfall payments in the third quarter of 2018, primarily in the Barnett Shale segment, which adjusts downward approximately 70% of a certain customer’s aggregate estimated MVC shortfall payment due in October 2019.  SMLP recognized approximately $6.0 million of this Barnett Shale customer’s estimated aggregate MVC shortfall payment as gathering revenue in the third quarter of 2018, and will continue to recognize MVC shortfall payment gathering revenue associated with this expected MVC shortfall payment, on a ratable basis, until it is due and fully recognized, in the fourth quarter of 2019.  SMLP’s MVC shortfall payment mechanisms contributed $15.8 million of adjusted EBITDA in the third quarter of 2018.

EX 99.1-5

EXHIBIT 99.1

	Three months ended September 30, 2018
	MVC Billings			Gathering revenue			Adjustments to MVC shortfall payments			Net impact to adjusted EBITDA
	(In thousands)
Net change in deferred revenue related to MVC    shortfall payments:
Utica Shale	$	—		$	—		$	—		$	—
Williston Basin		—			—			—			—
Piceance/DJ Basins		3,416			3,416			—			3,416
Barnett Shale		—			—			—			—
Marcellus Shale		—			—			—			—
Total net change	$	3,416		$	3,416		$	—		$	3,416
MVC shortfall payment adjustments:
Utica Shale	$	(82	)	$	(82	)	$	—		$	(82	)
Williston Basin		765			765			2,032			2,797
Piceance/DJ Basins		7,210			7,500			—			7,500
Barnett Shale		—			6,114			(5,031	)		1,083
Marcellus Shale		1,049			1,049			—			1,049
Total MVC shortfall payment adjustments	$	8,942		$	15,346		$	(2,999	)	$	12,347
Total (1)	$	12,358		$	18,762		$	(2,999	)	$	15,763

__________

(1) Exclusive of Ohio Gathering due to equity method accounting.

	Nine months ended September 30, 2018
	MVC Billings		Gathering revenue		Adjustments to MVC shortfall payments			Net impact to adjusted EBITDA
	(In thousands)
Net change in deferred revenue related to MVC    shortfall payments:
Utica Shale	$	—	$	—	$	—		$	—
Williston Basin		—		—		—			—
Piceance/DJ Basins		10,363		10,363		—			10,363
Barnett Shale		—		—		—			—
Marcellus Shale		—		—		—			—
Total net change	$	10,363	$	10,363	$	—		$	10,363
MVC shortfall payment adjustments:
Utica Shale	$	49	$	49	$	—		$	49
Williston Basin		2,250		9,698		(1,354	)		8,344
Piceance/DJ Basins		20,765		21,727		(93	)		21,634
Barnett Shale		—		6,393		(5,094	)		1,299
Marcellus Shale		3,112		3,112		—			3,112
Total MVC shortfall payment adjustments	$	26,176	$	40,979	$	(6,541	)	$	34,438
Total (1)	$	36,539	$	51,342	$	(6,541	)	$	44,801

__________

(1) Exclusive of Ohio Gathering due to equity method accounting.

EX 99.1-6

EXHIBIT 99.1

Capital Expenditures

Capital expenditures totaled $46.6 million in the third quarter of 2018, including maintenance capital expenditures of approximately $6.4 million.  Development activities during the third quarter of 2018 were primarily related to the ongoing construction and development of associated natural gas gathering and processing infrastructure in the Delaware and DJ basins.  We expect the 60 MMcf/d northern Delaware gathering and processing system and the 60 MMcf/d processing plant expansion in the DJ to be commissioned in the fourth quarter of 2018.  

Capital & Liquidity

As of September 30, 2018, SMLP had $866.0 million of available borrowing capacity under its $1.25 billion revolving credit facility, subject to covenant limits.  Based upon the terms of SMLP’s revolving credit facility and total outstanding debt of $1.18 billion (inclusive of $800.0 million of senior unsecured notes), SMLP’s total leverage ratio and senior secured leverage ratio (as defined in the credit agreement) as of September 30, 2018, were 4.02 to 1.0 and 1.31 to 1.0, respectively.

Deferred Purchase Price Obligation

SMLP lowered the estimated undiscounted amount of the Deferred Purchase Price Obligation related to the 2016 Drop Down transaction from $538.4 million at June 30, 2018, to $470.9 million at September 30, 2018.  The decrease is primarily related to a decrease in the number of well connections expected upstream of the SMU gathering system in 2019 from one of our two primary customers, which, relative to our previous estimate, results in lower projected volume throughput and Business Adjusted EBITDA in 2019.  This slower expected pace of activity is expected to be partially offset by the same customer’s decision to shift drilling to the condensate and liquids-rich gas acreage serviced by the Ohio Gathering system.  

Subsequent to September 30, 2018, SMLP received additional information from customers on our Utica Shale, Ohio Gathering and Williston Basin segments.  The impact of this new information would result in a decrease to the calculation of the undiscounted value of the Deferred Purchase Price Obligation of approximately $16.9 million, from $470.9 million to $454.0 million.

The consideration for the 2016 Drop Down consisted of (i) an initial $360.0 million cash payment (the “Initial Payment”) which was funded on March 3, 2016, with borrowings under SMLP’s revolving credit facility and (ii) a deferred payment which will be paid no later than December 31, 2020 (the “Deferred Purchase Price Obligation,” “DPPO” or “Deferred Payment,” as defined below).  At the discretion of the board of directors of SMLP’s general partner, the Deferred Payment can be made in either cash or SMLP common units, or a combination thereof.

The Deferred Payment will be equal to: (a) six-and-one-half (6.5) multiplied by the average Business Adjusted EBITDA of the 2016 Drop Down Assets for 2018 and 2019, less the G&A Adjuster, as defined in the Contribution Agreement; less (b) the Initial Payment; less (c) all capital expenditures incurred for the 2016 Drop Down Assets between March 3, 2016 and December 31, 2019; plus (d) all Business Adjusted EBITDA from the 2016 Drop Down Assets between March 3, 2016 and December 31, 2019, less the Cumulative G&A Adjuster, as defined in the Contribution Agreement. 

The Deferred Payment calculation was designed to ensure that, during the deferral period, all of the EBITDA growth and capex development risk associated with the 2016 Drop Down Assets is held by the GP, Summit Investments.  The Deferred Payment was structured such that SMLP will ultimately pay a 6.5x multiple of the actual average EBITDA generated from the 2016 Drop Down Assets in 2018 and 2019.

SMLP Financial Guidance

SMLP is reaffirming its 2018 adjusted EBITDA financial guidance range of $285.0 million to $300.0 million and capex guidance range, including contributions to equity method investees, of $175.0 million to $225.0 million.  SMLP continues to expect to incur maintenance capex of $15.0 million to $20.0 million in 2018.  SMLP expects to report an average full year 2018 distribution coverage ratio of approximately 1.00x.  

SMLP is also introducing its preliminary view with respect to 2019 financial guidance, including targeted adjusted EBITDA growth of at least 10% over 2018.  SMLP expects its 2019 distribution coverage ratio to expand generally in line with adjusted EBITDA growth throughout 2019 with targeted levels in excess of 1.15x by the fourth quarter of 2019.    

Quarterly Distribution

On October 25, 2018, the board of directors of SMLP’s general partner declared a quarterly cash distribution of $0.575 per unit on all of its outstanding common units, or $2.30 per unit on an annualized basis, for the quarter ended

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EXHIBIT 99.1

September 30, 2018.  This quarterly distribution remains unchanged from the previous quarter and from the quarter ended September 30, 2017.  This distribution will be paid on November 14, 2018, to unitholders of record as of the close of business on November 7, 2018.

Third Quarter 2018 Earnings Call Information

SMLP will host a conference call at 10:00 a.m. Eastern on Friday, November 9, 2018, to discuss its quarterly operating and financial results.  Interested parties may participate in the call by dialing 847-585-4405 or toll-free 888-771-4371 and entering the passcode 47745266.  The conference call will also be webcast live and can be accessed through the Investors section of SMLP's website at www.summitmidstream.com.

A replay of the conference call will be available until November 23, 2018, at 11:59 p.m. Eastern, and can be accessed by dialing 888-843-7419 and entering the replay passcode 47745266#.  An archive of the conference call will also be available on SMLP's website.

Upcoming Investor Conferences

Members of SMLP’s senior management team will participate in RBC Capital Markets’ 2018 Midstream Conference in Dallas, Texas on November 13, 2018 and November 14, 2018, and in the Wells Fargo Pipeline, MLP and Utility Symposium in New York, New York on December 5, 2018 and December 6, 2018.  The presentation materials associated with these events will be accessible through the Investors section of SMLP’s website at www.summitmidstream.com prior to the beginning of each conference.

Use of Non-GAAP Financial Measures

We report financial results in accordance with U.S. generally accepted accounting principles (“GAAP”). We also present adjusted EBITDA and distributable cash flow, each a non-GAAP financial measure.  We define adjusted EBITDA as net income or loss, plus interest expense, income tax expense, depreciation and amortization, our proportional adjusted EBITDA for equity method investees, adjustments related to MVC shortfall payments, adjustments related to capital reimbursement activity, unit-based and noncash compensation, the change in the Deferred Purchase Price Obligation fair value, early extinguishment of debt expense, impairments and other noncash expenses or losses, less interest income, income tax benefit, income (loss) from equity method investees and other noncash income or gains.  We define distributable cash flow as adjusted EBITDA plus cash interest received and cash taxes received, less cash interest paid, senior notes interest adjustment, distributions to Series A Preferred unitholders, Series A Preferred units distribution adjustment, cash taxes paid and maintenance capital expenditures.  Because adjusted EBITDA and distributable cash flow may be defined differently by other entities in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other entities, thereby diminishing their utility.

Management uses these non-GAAP financial measures in making financial, operating and planning decisions and in evaluating our financial performance.  Furthermore, management believes that these non-GAAP financial measures may provide external users of our financial statements, such as investors, commercial banks, research analysts and others, with additional meaningful comparisons between current results and results of prior periods as they are expected to be reflective of our core ongoing business.

Adjusted EBITDA and distributable cash flow are used as supplemental financial measures by external users of our financial statements such as investors, commercial banks, research analysts and others.

Adjusted EBITDA is used to assess:

• the ability of our assets to generate cash sufficient to make cash distributions and support our indebtedness;

• the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

• our operating performance and return on capital as compared to those of other entities in the midstream energy sector, without regard to financing or capital structure;

• the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities; and

• the financial performance of our assets without regard to (i) income or loss from equity method investees, (ii) the impact of the timing of minimum volume commitments shortfall payments under our gathering agreements or (iii) the timing of impairments or other noncash income or expense items.

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EXHIBIT 99.1

Distributable cash flow is used to assess:

• the ability of our assets to generate cash sufficient to make future cash distributions and

• the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

Both of these measures have limitations as analytical tools and investors should not consider them in isolation or as a substitute for analysis of our results as reported under GAAP.  For example:

• certain items excluded from adjusted EBITDA and distributable cash flow are significant components in understanding and assessing an entity's financial performance, such as an entity's cost of capital and tax structure;

• adjusted EBITDA and distributable cash flow do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

• adjusted EBITDA and distributable cash flow do not reflect changes in, or cash requirements for, our working capital needs; and

• although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and adjusted EBITDA and distributable cash flow do not reflect any cash requirements for such replacements.

We compensate for the limitations of adjusted EBITDA and distributable cash flow as analytical tools by reviewing the comparable GAAP financial measures, understanding the differences between the financial measures and incorporating these data points into our decision-making process.  Reconciliations of GAAP to non-GAAP financial measures are attached to this press release.

We do not provide the GAAP financial measures of net income or loss or net cash provided by operating activities on a forward-looking basis because we are unable to predict, without unreasonable effort, certain components thereof including, but not limited to, (i) income or loss from equity method investees, (ii) deferred purchase price obligation and (iii) asset impairments.  These items are inherently uncertain and depend on various factors, many of which are beyond our control.  As such, any associated estimate and its impact on our GAAP performance and cash flow measures could vary materially based on a variety of acceptable management assumptions.

About Summit Midstream Partners, LP

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. SMLP provides natural gas, crude oil and produced water gathering services pursuant to primarily long-term and fee-based gathering and processing agreements with customers and counterparties in five unconventional resource basins: (i) the Appalachian Basin, which includes the Marcellus and Utica shale formations in West Virginia and Ohio; (ii) the Williston Basin, which includes the Bakken and Three Forks shale formations in North Dakota; (iii) the Fort Worth Basin, which includes the Barnett Shale formation in Texas; (iv) the Piceance Basin, which includes the Mesaverde formation as well as the Mancos and Niobrara shale formations in Colorado and Utah; and (v) the Denver-Julesburg Basin, which includes the Niobrara and Codell shale formations in Colorado and Wyoming.  SMLP is in the process of developing new gathering and processing infrastructure in a sixth basin, the Delaware Basin, in New Mexico. SMLP also owns substantially all of a 40% ownership interest in Ohio Gathering, which is developing natural gas gathering and condensate stabilization infrastructure in the Utica Shale in Ohio. SMLP is headquartered in The Woodlands, Texas, with regional corporate offices in Denver, Colorado, Atlanta, Georgia, Pittsburgh, Pennsylvania and Dallas, Texas.

About Summit Midstream Partners, LLC

Summit Midstream Partners, LLC (“Summit Investments”) beneficially owns a 35.2% limited partner interest in SMLP and indirectly owns and controls the general partner of SMLP, Summit Midstream GP, LLC, which has sole responsibility for conducting the business and managing the operations of SMLP. Summit Investments is a privately held company controlled by Energy Capital Partners II, LLC, and certain of its affiliates. An affiliate of Energy Capital Partners II, LLC directly owns an 8.1% limited partner interest in SMLP.

Forward-Looking Statements

This press release includes certain statements concerning expectations for the future that are forward-looking within the meaning of the federal securities laws. Forward-looking statements contain known and unknown risks and

EX 99.1-9

EXHIBIT 99.1

uncertainties (many of which are difficult to predict and beyond management’s control) that may cause SMLP’s actual results in future periods to differ materially from anticipated or projected results. An extensive list of specific material risks and uncertainties affecting SMLP is contained in its 2017 Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 26, 2018, and as amended and updated from time to time. Any forward-looking statements in this press release, including forward-looking statements regarding preliminary 2019 financial guidance or financial or operating expectations for 2019, are made as of the date of this press release and SMLP undertakes no obligation to update or revise any forward-looking statements to reflect new information or events.

We do not provide the GAAP financial measures of net income or loss or net cash provided by operating activities on a forward-looking basis because we are unable to predict, without unreasonable effort, certain components thereof including, but not limited to, (i) income or loss from equity method investees, (ii) deferred purchase price obligation and (iii) asset impairments.  These items are inherently uncertain and depend on various factors, many of which are beyond our control.  As such, any associated estimate and its impact on our GAAP performance and cash flow measures could vary materially based on a variety of acceptable management assumptions.

EX 99.1-10

EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,		December 31,
	2018		2017
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	370	$	1,430
Accounts receivable		85,458		72,301
Other current assets		4,360		4,327
Total current assets		90,188		78,058
Property, plant and equipment, net		1,911,630		1,795,129
Intangible assets, net		281,207		301,345
Goodwill		16,211		16,211
Investment in equity method investees		660,254		690,485
Other noncurrent assets		18,566		13,565
Total assets	$	2,978,056	$	2,894,793
Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	22,569	$	16,375
Accrued expenses		18,347		12,499
Due to affiliate		13		1,088
Deferred revenue		11,152		4,000
Ad valorem taxes payable		8,223		8,329
Accrued interest		15,285		12,310
Accrued environmental remediation		2,702		3,130
Other current liabilities		10,388		11,258
Total current liabilities		88,679		68,989
Long-term debt		1,175,313		1,051,192
Deferred Purchase Price Obligation		416,718		362,959
Noncurrent deferred revenue		39,624		12,707
Noncurrent accrued environmental remediation		1,182		2,214
Other noncurrent liabilities		5,525		7,063
Total liabilities		1,727,041		1,505,124
Series A Preferred Units		300,741		294,426
Common limited partner capital		913,913		1,056,510
General Partner interests		25,380		27,920
Noncontrolling interest		10,981		10,813
Total partners' capital		1,251,015		1,389,669
Total liabilities and partners' capital	$	2,978,056	$	2,894,793

EX 99.1-11

EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	86,427		$	96,070		$	260,373		$	298,884
Natural gas, NGLs and condensate sales		34,017			22,940			92,025			44,655
Other revenues		7,035			5,935			20,584			19,003
Total revenues		127,479			124,945			372,982			362,542
Costs and expenses:
Cost of natural gas and NGLs		26,879			18,177			71,549			36,328
Operation and maintenance		24,382			22,303			73,452			70,011
General and administrative		11,740			13,289			39,666			40,370
Depreciation and amortization		26,743			28,927			80,204			86,184
Transaction costs		—			—			—			119
Loss (gain) on asset sales, net		6			460			(6	)		530
Long-lived asset impairment		1,540			1,290			2,127			1,577
Total costs and expenses		91,290			84,446			266,992			235,119
Other income		58			79			78			214
Interest expense		(14,862	)		(17,614	)		(44,821	)		(51,883	)
Early extinguishment of debt		—			—			—			(22,020	)
Deferred Purchase Price Obligation		37,204			70,499			(53,759	)		54,674
Income before income taxes and (loss)     income from equity method investees		58,589			93,463			7,488			108,408
Income tax benefit (expense)		35			(176	)		(88	)		(417	)
(Loss) income from equity method investees		(1,169	)		350			(3,703	)		(3,691	)
Net income	$	57,455		$	93,637		$	3,697		$	104,300
Earnings (loss) per limited partner unit:
Common unit – basic	$	0.64		$	1.23		$	(0.33	)	$	1.32
Common unit – diluted	$	0.64		$	1.22		$	(0.33	)	$	1.31
Weighted-average limited partner units outstanding:
Common units – basic		73,356			73,059			73,283			72,583
Common units – diluted		73,756			73,433			73,283			72,901

EX 99.1-12

EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED OTHER FINANCIAL AND OPERATING DATA

	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
	(Dollars in thousands)
Other financial data:
Net income	$	57,455	$	93,637	$	3,697	$	104,300
Net cash provided by operating activities	$	56,443	$	75,156	$	166,492	$	196,497
Capital expenditures	$	46,639	$	40,294	$	137,033	$	86,206
Contributions to equity method investees	$	—	$	5,932	$	—	$	21,581
Adjusted EBITDA	$	73,416	$	73,477	$	217,220	$	217,464
Distributable cash flow	$	43,629	$	52,877	$	134,941	$	155,837
Distributions declared (1)	$	45,216	$	45,037	$	135,648	$	134,651
Distribution coverage ratio (2)	0.96x		1.17x		0.99x		1.16x
Operating data:
Aggregate average daily throughput – natural gas     (MMcf/d)		1,629		1,826		1,720		1,744
Aggregate average daily throughput – liquids (Mbbl/d)		96.9		74.0		90.9	74.7
Ohio Gathering average daily throughput (MMcf/d) (3)		797		763		765		746

__________

(1) Represents distributions declared to common unitholders in respect of a given period. For example, for the three months ended September 30, 2018, represents the distributions to be paid in November 2018.  

(2) Distribution coverage ratio calculation for the three months ended September 30, 2018 and 2017 is based on distributions declared to common unitholders in respect of the third quarter of 2018 and 2017. Represents the ratio of distributable cash flow to distributions declared.  

(3) Gross basis, represents 100% of volume throughput for Ohio Gathering, based on a one-month lag.

EX 99.1-13

EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED RECONCILIATION OF REPORTABLE SEGMENT ADJUSTED EBITDA

TO ADJUSTED EBITDA

	Three months ended September 30,				Nine months ended September 30,
	2018		2017		2018		2017
	(In thousands)
Reportable segment adjusted EBITDA (1):
Utica Shale	$	6,521	$	8,412	$	24,459	$	25,857
Ohio Gathering (2)		10,171		10,522		29,583		29,201
Williston Basin		19,849		16,212		54,849		51,176
Piceance/DJ Basins		29,831		30,008		86,739		86,256
Barnett Shale		10,818		10,838		31,770		35,924
Marcellus Shale		5,550		6,682		18,769		17,775
Total	$	82,740	$	82,674	$	246,169	$	246,189
Less Corporate and Other (3)		9,324		9,197		28,949		28,725
Adjusted EBITDA	$	73,416	$	73,477	$	217,220	$	217,464

__________

(1) 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) unit-based and noncash compensation, (vi) change in the Deferred Purchase Price Obligation, (vii) early extinguishment of debt expense, (viii) impairments and (ix) other noncash expenses or losses, less other noncash income or gains.

(2) Represents our proportional share of adjusted EBITDA for Ohio Gathering, based on a one-month lag.  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.

(3) 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, early extinguishment of debt and a change in the Deferred Purchase Price Obligation.

EX 99.1-14

EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES

	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(In thousands)
Reconciliations of net income or loss to adjusted     EBITDA and distributable cash flow:
Net income	$	57,455		$	93,637		$	3,697		$	104,300
Add:
Interest expense		14,862			17,614			44,821			51,883
Income tax (benefit) expense		(35	)		176			88			417
Depreciation and amortization (1)		26,592			28,777			79,752			85,732
Proportional adjusted EBITDA for equity method    investees (2)		10,171			10,522			29,583			29,201
Adjustments related to MVC shortfall payments (3)		(2,999	)		(10,124	)		(6,541	)		(33,186	)
Adjustments related to capital reimbursement activity (4)		(106	)		—			49			—
Unit-based and noncash compensation		1,965			1,974			6,188			5,973
Deferred Purchase Price Obligation (5)		(37,204	)		(70,499	)		53,759			(54,674	)
Early extinguishment of debt (6)		—			—			—			22,020
Loss (gain) on asset sales, net		6			460			(6	)		530
Long-lived asset impairment		1,540			1,290			2,127			1,577
Income (loss) from equity method investees		1,169			(350	)		3,703			3,691
Adjusted EBITDA	$	73,416		$	73,477		$	217,220		$	217,464
Less:
Cash interest paid		13,164			14,028			44,126			47,410
Cash paid for taxes		—			—			175			—
Senior notes interest adjustment (7)		3,063			3,063			3,063			2,594
Distributions to Series A Preferred unitholders (8)		—			—			14,250			—
Series A Preferred units distribution adjustment (9)		7,125			—			7,125			—
Maintenance capital expenditures		6,435			3,509			13,540			11,623
Distributable cash flow	$	43,629		$	52,877		$	134,941		$	155,837
Distributions declared (10)	$	45,216		$	45,037		$	135,648		$	134,651
Distribution coverage ratio (11)	0.96x			1.17x			0.99x			1.16x

__________

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

(2) Reflects our proportionate share of Ohio Gathering adjusted EBITDA, based on a one-month lag.

(3) Adjustments related to MVC shortfall payments for the three and nine months ended September 30, 2017 account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments.  For the three and nine months ended September 30, 2018, adjustments related to MVC shortfall payments are recognized in gathering services and related fees.

(4) Adjustments related to capital reimbursement activity represent contributions in aid of construction revenue recognized in accordance with Accounting Standards Update No. 2014-09 Revenue from Contracts with Customers (“Topic 606”).

(5) Deferred Purchase Price Obligation represents the change in the present value of the Deferred Purchase Price Obligation.

(6) Early extinguishment of debt includes $17.9 million paid for redemption and call premiums, as well as $4.1 million of unamortized debt issuance costs which were written off in connection with the repurchase of the outstanding $300.0 million 7.5% Senior Notes in the first quarter of 2017.

(7) Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. Interest on the $300.0 million 5.5% senior notes is paid in cash semi-annually in arrears on February 15 and August 15 until maturity in August 2022.  Interest on the $500.0 million 5.75% senior notes is paid in cash semi-annually in arrears on April 15 and October 15 until maturity in April 2025.

EX 99.1-15

EXHIBIT 99.1

(8) Distributions on the Series A preferred units are paid in cash semi-annually in arrears on June 15 and December 15 each year, through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year.

(9) Series A Preferred unit distribution adjustment represents the net of distributions paid and accrued on the Series A Preferred units. 

(10) Represents distributions declared to common unitholders in respect of a given period. For example, for the three months ended September 30, 2018, represents the distributions to be paid in November 2018.

(11) Distribution coverage ratio calculation for the three months ended September 30, 2018 and 2017 is based on distributions declared in respect of the third quarter of 2018 and 2017. Represents the ratio of distributable cash flow to distributions declared.  

EX 99.1-16

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

UNAUDITED RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES

	Nine months ended September 30,
	2018			2017
	(In thousands)
Reconciliation of net cash provided by operating activities to adjusted     EBITDA and distributable cash flow:
Net cash provided by operating activities	$	166,492		$	196,497
Add:
Interest expense, excluding amortization of debt issuance costs		41,637			48,766
Income tax expense		88			417
Changes in operating assets and liabilities		12,440			4,786
Proportional adjusted EBITDA for equity method investees (1)		29,583			29,201
Adjustments related to MVC shortfall payments (2)		(6,541	)		(33,186	)
Adjustments related to capital reimbursement activity (3)		49			—
Less:
Distributions from equity method investees		26,528			28,715
Write-off of debt issuance costs		—			302
Adjusted EBITDA	$	217,220		$	217,464
Less:
Cash interest paid		44,126			47,410
Cash paid for taxes		175			—
Senior notes interest adjustment (4)		3,063			2,594
Distributions to Series A Preferred unitholders (5)		14,250			—
Series A Preferred units distribution adjustment (6)		7,125			—
Maintenance capital expenditures		13,540			11,623
Distributable cash flow	$	134,941		$	155,837

__________

(1) Reflects our proportionate share of Ohio Gathering adjusted EBITDA, based on a one-month lag.

(2) Adjustments related to MVC shortfall payments for the nine months ended September 30, 2017 account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments.  For the nine months ended September 30, 2018, adjustments related to MVC shortfall payments are recognized in gathering services and related fees.

(3) Adjustments related to capital reimbursement activity represent contributions in aid of construction revenue recognized in accordance with Accounting Standards Update No. 2014-09 Revenue from Contracts with Customers (“Topic 606”).

(4) Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. Interest on the $300.0 million 5.5% senior notes is paid in cash semi-annually in arrears on February 15 and August 15 until maturity in August 2022.  Interest on the $500.0 million 5.75% senior notes is paid in cash semi-annually in arrears on April 15 and October 15 until maturity in April 2025.

(5) Distributions on the Series A Preferred units are paid in cash semi-annually in arrears on June 15 and December 15 each year, through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year.

(6) Series A Preferred unit distribution adjustment represents the net of distributions paid and accrued on the Series A Preferred units. 

Contact:  Marc Stratton, Senior Vice President and Treasurer, 832-608-6166, ir@summitmidstream.com

SOURCE: Summit Midstream Partners, LP