smlp-ex991

The Woodlands, Texas (February 26, 2019) – In addition to the strategic actions and leadership changes announced earlier today in a separate press release, Summit Midstream Partners, LP (NYSE: SMLP) is announcing its financial and operating results for the three months and year ended December 31, 2018. SMLP reported net income of $38.7 million for the fourth quarter of 2018, compared to a net loss of $18.3 million for the prior-year period. Net income in the fourth quarter of 2018 included $32.8 million of non-cash income related to a decrease in the present value of the estimated Deferred Purchase Price Obligation (“DPPO”). Net cash provided by operations totaled $61.4 million for the fourth quarter of 2018, compared to $41.3 million for the prior-year period. Adjusted EBITDA totaled $76.9 million and distributable cash flow (“DCF”) totaled $44.4 million for the fourth quarter of 2018, compared to $72.9 million and $49.2 million, respectively, for the prior-year period. Compared to the prior-year period, fourth quarter of 2018 DCF included $3.9 million of higher maintenance capital expenditures related to increased compressor overhauls, right-of-way improvements, and measurement software upgrades, and $3.6 million of higher net distributions to Series A Preferred unitholders.

Leonard Mallett, interim President and Chief Executive Officer, commented, “SMLP finished 2018 with a strong quarter of operating and financial results, and full year adjusted EBITDA exceeded the midpoint of our 2018 guidance. The outlook for our business in 2019 is strong, and contemplates year-over-year adjusted EBITDA growth of approximately 7% at the midpoint, as adjusted for the sale of Tioga Midstream. We expect that adjusted EBITDA growth in 2019 will be driven primarily by increased utilization of our two major processing facility investments in the Permian and DJ basins together with growing volumes across our Utica Shale and Williston Basin segments, partially offset by a decline in customer activity on our Piceance Basin and Marcellus Shale segments.

“The sale of Tioga Midstream represents the first step in SMLP’s strategy to evaluate and execute sales of non-core assets, and is occurring at an attractive value to SMLP. The net proceeds from the sale will be used to repay outstanding indebtedness under our revolver. We intend to continue focusing on streamlining our asset portfolio in 2019 and expanding our presence in our core focus areas, including the Utica, Williston, DJ and Permian.”

SMLP reported net income of $42.4 million for the full year 2018, compared to net income of $86.1 million for the prior-year period. Net cash provided by operations totaled $227.9 million for the full year 2018, compared to $237.8 million in the prior-year period. SMLP reported adjusted EBITDA of $294.1 million and DCF of $179.3 million for the full year 2018, compared to $290.4 million and $205.0 million, respectively, for the prior-year period.

SMLP has executed definitive agreements with affiliates of Hess Infrastructure Partners LP (“HIP”) related to the sale of Tioga Midstream, LLC (“Tioga”) for cash consideration of $90.0 million, subject to customary closing adjustments. Tioga owns and operates natural gas, crude oil, and produced water gathering infrastructure in Williams County, North Dakota and provides related gathering services, primarily for affiliates of Hess Corporation, in the Williston Basin. SMLP is also eligible to earn up to $10.0 million of contingency payments from HIP in future periods, subject to certain future performance metrics. The transaction is subject to certain customary closing conditions and is expected to close before the end of the first quarter of 2019.

The Double E Pipeline Project is expected to provide natural gas transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub. SMLP continues to make progress with a number of counterparties to finalize volume commitments such that its final investment decision can be completed once these negotiations have concluded. SMLP is on schedule to file its 7(c) application with the Federal Energy Regulatory Commission by the end of the first quarter of 2019, an important next step toward achieving the previously announced expected in-service date of the second quarter of 2021.

SMLP is updating its 2019 financial guidance, which is summarized in the table below:

SMLP’s 2019 financial guidance has been modified to account for the sale of Tioga Midstream, which is expected to close by the end of the first quarter of 2019. SMLP’s 2019 financial guidance also includes the establishment of a new distribution policy through the reduction of SMLP’s distribution per common unit to $0.2875 per quarter, beginning with the distribution to be paid in respect to the first quarter of 2019.

Our 2019 adjusted EBITDA guidance incorporates current production expectations from our customers, which in some cases have been reduced relative to our prior expectations, primarily due to the decrease in crude oil prices that occurred late in the fourth quarter of 2018. Despite a lower commodity price backdrop, we have a strong growth outlook for our gathering systems that are located in crude oil-focused production basins, with approximately 215 new wells expected to be commissioned in 2019 for our systems serving the Williston, DJ and Permian basin segments. Relative to our preliminary 2019 financial guidance issued in November 2018, our outlook for 2019 reflects a four-month delay in the commissioning of our 60 MMcf/d DJ Basin processing plant, together with well commissioning delays expected in the Utica Shale, Ohio Gathering, and Williston Basin segments.

Capital expenditures in 2019 will be primarily focused in the Williston, DJ and Permian basins and include the development of a second 60 MMcf/d processing plant in the DJ Basin, which will increase SMLP’s DJ Basin processing capacity to 120 MMcf/d and is expected to be operational by the third quarter of 2020.

	Three months ended December 31,				Year ended December 31,
	2018		2017		2018		2017
Average daily throughput (MMcf/d):
Utica Shale		309		369		359		365
Williston Basin		18		19		18		19
DJ Basin		21		14		17		13
Permian Basin		3		—		1		—
Piceance Basin		526		561		551		582
Barnett Shale		255		258		253		267
Marcellus Shale		401		540		474		502
Aggregate average daily throughput		1,533		1,761		1,673		1,748

Average daily throughput (Mbbl/d):
Williston Basin		108.9		74.1		94.9		75.2
Aggregate average daily throughput		108.9		74.1		94.9		75.2

Ohio Gathering average daily throughput (MMcf/d) (1)		780		825		769		766

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

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 fourth quarter of 2018 totaled $5.8 million, a decrease of 28.6% from $8.2 million in the prior-year period and a decrease of 10.7% from $6.5 million in the third quarter of 2018, primarily due to lower volume throughput, partially offset by lower operating expense. Total volume throughput averaged 309 MMcf/d in the fourth quarter of 2018, a decrease of 16.3% from 369 MMcf/d in the prior-year period and a decrease of 13.4% from 357 MMcf/d in the third quarter of 2018. Volumes were lower in the fourth quarter of 2018 compared to both the prior-year and prior-quarter periods, primarily due to natural production declines, partially offset by four new wells that were commissioned at the end of the fourth quarter of 2018. Volume throughput on the TPL-7 Connector project, which generates a lower gathering margin compared to volumes gathered directly from a pad site, totaled 142 MMcf/d in the fourth quarter of 2018, compared to 48 MMcf/d in the prior-year period and 148 MMcf/d in the third quarter of 2018.

We estimate that approximately 36 MMcf/d of temporary volume curtailments occurred in the fourth quarter of 2018 as a result of infill drilling and completion activities from customers on existing pad sites. Drilling and completion activity is expected to increase in the near-term with approximately 15 new wells projected for 2019 from pad sites directly connected to the SMU system, compared to four new wells in 2018. These completions are expected to generate annualized segment adjusted EBITDA in the second half of 2019 that is approximately 50% higher than the annualized segment adjusted EBITDA generated in the fourth quarter of 2018.

The Ohio Gathering reportable segment includes our 40% ownership interest in the Ohio Gathering system, 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, as well as our 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 fourth quarter of 2018 totaled $10.4 million, a decrease of 13.8% from $12.0 million in the prior-year period and an increase of 2.1% from $10.2 million in the third quarter of 2018. Volume throughput on the Ohio Gathering system averaged 780 MMcf/d, gross, in the fourth quarter of 2018, compared to 825 MMcf/d, gross, in the prior-year period and 797 MMcf/d, gross, in the third quarter of 2018. Volumes were lower in the fourth

quarter of 2018 compared to both the prior-year and prior-quarter periods, primarily due to natural production declines from existing wells connected to the system, partially offset by three new wells that were commissioned in the fourth quarter of 2018.

Our customers are currently operating one drilling rig upstream of the Ohio Gathering system. We expect drilling and completion activity to remain consistent in 2019 relative to 2018, and to remain focused on the condensate and liquids-rich windows of the play, with approximately 50 new wells projected for 2019, compared to 43 new wells in 2018.

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 $21.9 million for the fourth quarter of 2018, an increase of 43.4% compared to $15.2 million in the prior-year period, and an increase of 10.1% from $19.8 million in the third quarter of 2018.

Liquids volumes averaged 108.9 Mbbl/d in the fourth quarter of 2018, an increase of 47.0% from 74.1 Mbbl/d in the prior-year period and an increase of 12.4% compared to 96.9 Mbbl/d in the third quarter of 2018. Liquids volumes increased as a result of 18 new wells commissioned on our system in the fourth quarter of 2018. We estimate that approximately 13 Mbbl/d of volume throughput did not flow in the fourth quarter of 2018 as a result of (i) certain customers initiating temporary production curtailments on existing wells for nearby drilling and completion activities or (ii) produced water capacity constraints at third party disposal wells.

Associated natural gas volumes averaged 18 MMcf/d in the fourth quarter of 2018, a decrease of 5.3% from 19 MMcf/d in both the prior-year period and the third quarter of 2018. Five new associated natural gas wells were connected to our Williston gathering systems in the fourth quarter of 2018.

Our Williston Basin customers are currently operating two drilling rigs upstream of our gathering systems. We expect drilling activity to remain consistent in 2019 with completion activities expected to be more heavily weighted towards the second half of the year. We expect that our customers will commission approximately 70 new wells in 2019, compared to 79 new wells in 2018.

The DJ Basin reportable segment includes the Niobrara Gathering & Processing system (“Niobrara G&P”), an associated natural gas gathering and processing system located in the DJ Basin in northeastern Colorado. Niobrara G&P delivers residue gas to the Colorado Interstate Gas pipeline and processed NGLs to the Overland Pass Pipeline.

Segment adjusted EBITDA for the fourth quarter of 2018 totaled $3.0 million, an increase of 56.9% from $1.9 million in the prior-year period and an increase of 34.8% from $2.2 million in the third quarter of 2018. Volume throughput averaged 21 MMcf/d in the fourth quarter of 2018, an increase of 50.0% from 14 MMcf/d in the prior-year period and an increase of 16.7% from 18 MMcf/d in the third quarter of 2018. Volumes were higher compared to both the prior-year and prior-quarter periods, primarily due to 28 new wells that were commissioned upstream of the Niobrara G&P system in the fourth quarter of 2018.

Our DJ Basin segment customers are currently operating five drilling rigs upstream of our Niobrara G&P system, and we expect a consistent level of drilling and completion activity in the near-term, with approximately 130 new well connections projected for 2019, compared to 61 new well connections in 2018.

We expect to commission our 60 MMcf/d processing plant expansion in the second quarter of 2019, which will facilitate increased volume throughput, beginning in the second quarter of 2019. In 2019, we expect to begin construction on a second 60 MMcf/d processing plant, which will increase total processing capacity for our Niobrara G&P system from 60 MMcf/d to 120 MMcf/d in the third quarter of 2020.

The Permian Basin reportable segment includes Summit Midstream Permian (“Summit Permian”), an associated natural gas gathering and processing system located in the northern Delaware Basin in southeastern New Mexico. Summit Permian operates the 60 MMcf/d Lane Gathering & Processing system (“Lane G&P”), which delivers residue gas to the Transwestern Pipeline and processed NGLs to the Lone Star Express pipeline.

Summit Permian commissioned the Lane G&P system late in the fourth quarter of 2018. Segment adjusted EBITDA for the fourth quarter of 2018 totaled ($0.3) million, an increase of 44.4% from ($0.7) million in the third quarter of 2018. Summit Permian did not have material operations in the prior-year period. Volume throughput averaged 3 MMcf/d in the fourth quarter of 2018 and was based on approximately 20 days of operations.

Our Permian Basin customers are currently operating two drilling rigs upstream of the Lane G&P system. Volume throughput is expected to increase throughout 2019 based on our customers commissioning approximately 15 new wells over the course of the year.

The Grand River system provides our midstream services for the Piceance Basin reportable segment. This system provides natural gas gathering and processing services for producers operating in the Piceance Basin located in western Colorado and eastern Utah.

Segment adjusted EBITDA totaled $28.8 million for the fourth quarter of 2018, a decrease of 2.4% from $29.6 million in the prior-year period and an increase of 4.5% from $27.6 million in the third quarter of 2018, primarily due to lower volume throughput, partially offset by lower operating expense. Fourth quarter 2018 volume throughput averaged 526 MMcf/d, a decrease of 6.2% from 561 MMcf/d in the prior-year period and a decrease of 5.1% from 554 MMcf/d in the third quarter of 2018. No new wells were connected in the fourth quarter of 2018. Volume throughput was lower in the fourth quarter of 2018 compared to the prior-quarter period due to natural production declines, primarily related to 93 new wells that were commissioned in the first three quarters of 2018.

There are no drilling rigs currently operating upstream of the Grand River system, and we do not anticipate a significant level of drilling or completion activity from our Piceance Basin customers in 2019.

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 $11.5 million in the fourth quarter of 2018, a 11.5% increase from $10.3 million in the prior-year period and a 6.3% increase from $10.8 million in the third quarter of 2018. Compared to the prior-year period, segment adjusted EBITDA in the fourth quarter of 2018 was negatively impacted by a two-month shutdown to repair our CO₂ treating facility, which was returned to normal operations in early January 2019. This was partially offset by approximately $1.5 million of adjustments to MVC shortfall payments, related to a customer’s estimated MVC deficiency payment due in the fourth quarter of 2019.

Volume throughput in the fourth quarter of 2018 averaged 255 MMcf/d, which was down 1.2% compared to 258 MMcf/d in the prior-year period and up 9.9% from 232 MMcf/d in the third quarter of 2018. Volume throughput in the fourth quarter of 2018 was positively impacted by five new wells that were commissioned at the end of the third quarter of 2018.

There are no rigs currently operating upstream of the DFW Midstream system; four new wells were commissioned on the system in January 2019 and another three wells are expected in the third quarter of 2019.

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 $5.5 million for the fourth quarter of 2018, a decrease of 10.1% from $6.1 million in the prior-year period and a decrease of 0.9% from $5.6 million in the third quarter of 2018, primarily due to lower volume throughput, partially offset by lower operating expense. Volume

throughput in the fourth quarter of 2018 averaged 401 MMcf/d, which was down 25.7% compared to the prior-year period of 540 MMcf/d and down 10.9% from 450 MMcf/d in the third quarter of 2018. Volume throughput was lower in the fourth quarter of 2018 compared to both the prior-year and prior-quarter periods due to natural production declines, primarily related to 36 new wells that were commissioned in 2017 and the first quarter 2018.

No new wells were connected in the fourth quarter of 2018. We expect drilling activity to resume in mid-2019, and we expect volume throughput growth beginning in the fourth quarter of 2019.

SMLP billed its customers $23.3 million in the fourth quarter of 2018 related to MVC shortfalls. For those customers that do not have MVC shortfall credit banking mechanisms in their gathering agreements, the MVC shortfall payments are accounted for as gathering revenue in the period in which they are earned. In the fourth quarter of 2018, SMLP recognized $14.5 million of gathering revenue associated with MVC shortfall payments. SMLP also recognized $2.9 million of adjustments to MVC shortfall payments in the fourth quarter of 2018, primarily related to future expected shortfall payments from customers in the Williston Basin segment and the Barnett Shale segment. SMLP’s MVC shortfall payment mechanisms contributed $17.5 million of total adjusted EBITDA in the fourth quarter of 2018.

	Three months ended December 31, 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 Basin		3,364		3,364		—		3,364
Barnett Shale		—		—		—		—
Marcellus Shale		—		—		—		—
Total net change	$	3,364	$	3,364	$	—	$	3,364

MVC shortfall payment adjustments:
Utica Shale	$	—	$	—	$	—	$	—
Williston Basin		8,907		1,459		1,354		2,813
Piceance Basin		9,464		8,503		103		8,606
Barnett Shale		393		1		1,452		1,453
Marcellus Shale		1,220		1,220		—		1,220
Total MVC shortfall payment adjustments	$	19,984	$	11,183	$	2,909	$	14,092

Total (1)	$	23,348	$	14,547	$	2,909	$	17,456

	Year ended December 31, 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 Basin		13,726		13,726		—			13,726
Barnett Shale		—		—		—			—
Marcellus Shale		—		—		—			—
Total net change	$	13,726	$	13,726	$	—		$	13,726

MVC shortfall payment adjustments:
Utica Shale	$	49	$	49	$	—		$	49
Williston Basin		11,157		11,157		—			11,157
Piceance Basin		30,230		30,230		10			30,240
Barnett Shale		393		6,393		(3,642	)		2,751
Marcellus Shale		4,332		4,332		—			4,332
Total MVC shortfall payment adjustments	$	46,161	$	52,161	$	(3,632	)	$	48,529

Total (1)	$	59,887	$	65,887	$	(3,632	)	$	62,255

Capital expenditures totaled $63.6 million in the fourth quarter of 2018, including maintenance capital expenditures of $7.9 million. Contributions to equity method investees in the fourth quarter of 2018 totaled $4.9 million. Development activities during the fourth quarter of 2018 were primarily related to the ongoing construction and development of associated natural gas gathering and processing infrastructure in the Permian and DJ basins. Maintenance capital expenditures in the fourth quarter of 2018 included higher costs associated with compressor overhauls, right-of-way improvements, and measurement software upgrades.

As of December 31, 2018, SMLP had $784.0 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 $1.27 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 December 31, 2018, were 4.23 to 1.0 and 1.55 to 1.0, respectively.

SMLP lowered the estimated undiscounted amount of the Deferred Purchase Price Obligation related to the 2016 Drop Down transaction from $470.9 million at September 30, 2018, to $423.9 million at December 31, 2018. The decrease is primarily related to a decrease in the expected number of well connections together with a delay in the timing of certain well connections upstream of the SMU and Ohio Gathering systems in 2019. In addition, the decrease accounts for a delay in the start-up of the new 60 MMcf/d Hereford processing plant from late in the fourth quarter of 2018 to the second quarter of 2019.

The consideration for the 2016 Drop Down consisted of (i) an initial $360.0 million cash payment on March 3, 2016, which was subsequently adjusted by a $0.6 million working capital adjustment received from a subsidiary of Summit Midstream Partners, LLC (“Summit Investments”) in June 2016 and (ii) the DPPO, which will be paid no later than December 31, 2020. At the discretion of the board of directors of SMLP’s general partner, the DPPO can be made in either cash or SMLP common units, or a combination thereof.

In February 2019, the Contribution Agreement associated with the 2016 Drop Down was amended to account for (i) a $100.0 million prepayment of the DPPO, which is expected to occur by the end of the first quarter of 2019 and (ii) an agreement to fix the remaining obligation due in 2020 at $303.5 million.

On January 24, 2019, 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 December 31, 2018. This quarterly distribution remains unchanged from the previous quarter and from the quarter ended December 31, 2017. This distribution was paid on February 14, 2019, to unitholders of record as of the close of business on February 7, 2019.

In a separate press release issued on February 26, 2019, SMLP announced that it is undertaking a series of strategic actions to reposition the Company to better serve its customers and create value for its unitholders by enhancing its ability to fund attractive growth opportunities and maintain a prudent capital structure. These actions include (i) the elimination of SMLP’s economic General Partner interest and incentive distribution rights (“IDRs”) in exchange for 8.75 million SMLP common units and (ii) the establishment of a new distribution policy through the reduction of SMLP’s distribution per common unit to $0.2875 per quarter, beginning with the distribution to be paid in respect of the first quarter of 2019.

SMLP will host a conference call at 9:00 a.m. Eastern on Tuesday, February 26, 2019, to discuss its quarterly operating and financial results, as well as the strategic actions announced on February 26, 2019. Interested parties may participate in the call by dialing 847-585-4405 or toll-free 888-771-4371 and entering the passcode 48142406. 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 March 12, 2019, at 11:59 p.m. Eastern, and can be accessed by dialing 888-843-7419 and entering the replay passcode 48142406#. An archive of the conference call will also be available on SMLP's website.

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, items of income or loss that we characterize as unrepresentative of our ongoing operations 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.

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:

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.

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 six unconventional resource basins: (i) the Appalachian Basin, which includes the Utica and Marcellus shale formations in Ohio and West Virginia; (ii) the Williston Basin, which includes the Bakken and Three Forks shale formations in North Dakota; (iii) the Denver-Julesburg Basin, which includes the Niobrara and Codell shale formations in Colorado and Wyoming; (iv) the Permian Basin, which includes the Bone Spring and Wolfcamp formations in New Mexico; (v) the Fort Worth Basin, which includes the Barnett Shale formation in Texas; and (vi) the Piceance Basin, which includes the Mesaverde formation as well as the Mancos and Niobrara shale formations in Colorado and Utah. SMLP also owns 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.

Summit Midstream Partners, LLC (“Summit Investments”) beneficially owns a 42.1% limited partner interest in SMLP, pro forma for the strategic actions announced on February 26, 2019, and indirectly owns and controls the non-

economic 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 7.2% limited partner interest in SMLP, pro forma for the strategic actions announced on February 26, 2019.

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 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 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.

	December 31,		December 31,
	2018		2017
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	4,345	$	1,430
Accounts receivable		97,936		72,301
Other current assets		3,971		4,327
Total current assets		106,252		78,058
Property, plant and equipment, net		1,963,713		1,795,129
Intangible assets, net		273,416		301,345
Goodwill		16,211		16,211
Investment in equity method investees		649,250		690,485
Other noncurrent assets		11,720		13,565
Total assets	$	3,020,562	$	2,894,793

Liabilities and Partners' Capital
Current liabilities:
Trade accounts payable	$	38,414	$	16,375
Accrued expenses		21,963		12,499
Due to affiliate		240		1,088
Deferred revenue		11,467		4,000
Ad valorem taxes payable		10,550		8,329
Accrued interest		12,286		12,310
Accrued environmental remediation		2,487		3,130
Other current liabilities		12,645		11,258
Total current liabilities		110,052		68,989
Long-term debt		1,257,731		1,051,192
Deferred Purchase Price Obligation		383,934		362,959
Noncurrent deferred revenue		39,504		12,707
Noncurrent accrued environmental remediation		3,149		2,214
Other noncurrent liabilities		4,968		7,063
Total liabilities		1,799,338		1,505,124

Series A Preferred Units		293,616		294,426
Common limited partner capital		902,358		1,056,510
General Partner interests		25,250		27,920
Noncontrolling interest		-		10,813
Total partners' capital		1,221,224		1,389,669
Total liabilities and partners' capital	$	3,020,562	$	2,894,793

	Three months ended December 31,						Year ended December 31,
	2018			2017			2018			2017
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$	84,243		$	95,543		$	344,616		$	394,427
Natural gas, NGLs and condensate sales		42,809			23,804			134,834			68,459
Other revenues		6,619			6,852			27,203			25,855
Total revenues		133,671			126,199			506,653			488,741
Costs and expenses:
Cost of natural gas and NGLs		36,112			20,909			107,661			57,237
Operation and maintenance		23,426			23,871			96,878			93,882
General and administrative		13,211			14,311			52,877			54,681
Depreciation and amortization		26,896			29,291			107,100			115,475
Transaction costs		—			(46	)		—			73
Loss (gain) on asset sales, net		6			(3	)		—			527
Long-lived asset impairment		5,059			187,125			7,186			188,702
Total costs and expenses		104,710			275,458			371,702			510,577
Other (expense) income		(247	)		84			(169	)		298
Interest expense		(15,714	)		(16,248	)		(60,535	)		(68,131	)
Early extinguishment of debt		—			(19	)		—			(22,039	)
Deferred Purchase Price Obligation		32,784			145,648			(20,975	)		200,322
Income (loss) before income taxes and (loss) income from equity method investees		45,784			(19,794	)		53,272			88,614
Income tax income (expense)		55			76			(33	)		(341	)
(Loss) income from equity method investees		(7,185	)		1,468			(10,888	)		(2,223	)
Net income (loss)	$	38,654		$	(18,250	)	$	42,351		$	86,050

Earnings (loss) per limited partner unit:
Common unit – basic	$	0.39		$	(0.32	)	$	0.06		$	0.99
Common unit – diluted	$	0.39		$	(0.32	)	$	0.06		$	0.98

Weighted-average limited partner units outstanding:
Common units – basic		73,369			73,068			73,304			72,705
Common units – diluted		73,767			73,068			73,615			73,047

	Three months ended December 31,					Year ended December 31,
	2018		2017			2018		2017
	(Dollars in thousands)
Other financial data:
Net income (loss)	$	38,654	$	(18,250	)	$	42,351	$	86,050
Net cash provided by operating activities	$	61,437	$	41,335		$	227,929	$	237,832
Capital expenditures	$	63,553	$	38,009		$	200,586	$	124,215
Contributions to equity method investees	$	4,924	$	3,932		$	4,924	$	25,513
Adjusted EBITDA	$	76,865	$	72,923		$	294,085	$	290,387
Distributable cash flow	$	44,361	$	49,173		$	179,302	$	205,010
Distributions declared (1)	$	45,280	$	45,054		$	180,932	$	179,705
Distribution coverage ratio (2)	0.98x		1.09x			0.99x		1.14x

Operating data:
Aggregate average daily throughput – natural gas (MMcf/d)		1,533		1,761			1,673		1,748
Aggregate average daily throughput – liquids (Mbbl/d)		108.9		74.1			94.9	75.2

Ohio Gathering average daily throughput (MMcf/d) (3)		780		825			769		766

(1) Represents distributions declared to common unitholders in respect of a given period. For example, for the three months ended December 31, 2018, represents the distributions paid in February 2019.

(2) Distribution coverage ratio calculation for the three months ended December 31, 2018 and 2017 is based on distributions declared to common unitholders in respect of the fourth 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.

	Three months ended December 31,					Year ended December 31,
	2018			2017		2018			2017
	(In thousands)
Reportable segment adjusted EBITDA (1):
Utica Shale	$	5,826		$	8,154	$	30,285		$	34,011
Ohio Gathering (2)		10,386			12,045		39,969			41,246
Williston Basin		21,852			15,237		76,701			66,413
DJ Basin		3,030			1,931		7,558			6,624
Permian Basin		(309	)		-		(1,200	)		-
Piceance Basin		28,832			29,550		111,042			111,113
Barnett Shale		11,498			10,308		43,268			46,232
Marcellus Shale		5,498			6,113		24,267			23,888
Total	$	86,613		$	83,338	$	331,890		$	329,527
Less Corporate and Other (3)		9,748			10,415		37,805			39,140
Adjusted EBITDA	$	76,865		$	72,923	$	294,085		$	290,387

(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.

	Three months ended December 31,						Year ended December 31,
	2018			2017			2018			2017
	(In thousands)
Reconciliations of net income or loss to adjusted EBITDA and distributable cash flow:
Net income (loss)	$	38,654		$	(18,250	)	$	42,351		$	86,050
Add:
Interest expense		15,714			16,248			60,535			68,131
Income tax (benefit) expense		(55	)		(76	)		33			341
Depreciation and amortization (1)		27,015			29,140			106,767			114,872
Proportional adjusted EBITDA for equity method investees (2)		10,386			12,045			39,969			41,246
Adjustments related to MVC shortfall payments (3)		2,909			(8,187	)		(3,632	)		(41,373	)
Adjustments related to capital reimbursement activity (4)		(476	)		—			(427	)		—
Unit-based and noncash compensation		2,140			1,978			8,328			7,951
Deferred Purchase Price Obligation (5)		(32,784	)		(145,648	)		20,975			(200,322	)
Early extinguishment of debt (6)		—			19			—			22,039
Loss (gain) on asset sales, net		6			(3	)		—			527
Long-lived asset impairment		5,059			187,125			7,186			188,702
Other, net (7)		1,112			—			1,112			—
Less:
Income (loss) from equity method investees		(7,185	)		1,468			(10,888	)		(2,223	)
Adjusted EBITDA	$	76,865		$	72,923		$	294,085		$	290,387
Less:
Cash interest paid		20,552			24,078			64,678			71,488
Cash paid for taxes		—			—			175			—
Senior notes interest adjustment (8)		(3,063	)		(7,855	)		—			(5,261	)
Distributions to Series A Preferred unitholders (9)		14,250			2,375			28,500			2,375
Series A Preferred units distribution adjustment (10)		(7,125	)		1,188			—			1,188
Maintenance capital expenditures		7,890			3,964			21,430			15,587
Distributable cash flow	$	44,361		$	49,173		$	179,302		$	205,010

Distributions declared (11)	$	45,280		$	45,054		$	180,932		$	179,705

Distribution coverage ratio (12)	0.98x			1.09x			0.99x			1.14x

(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 months and year ended December 31, 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 months and year ended December 31, 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) Represents items of income or loss that we characterize as unrepresentative of our ongoing operations, including, in the three months and year ended December 31, 2018, $1.1 million of severance compensation expense associated with the resignation of our Chief Financial Officer in December 2018.

(8) 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.

(9) 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.

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

(11) Represents distributions declared to common unitholders in respect of a given period. For example, for the three months ended December 31, 2018, represents the distributions paid in February 2019.

(12) Distribution coverage ratio calculation for the three months ended December 31, 2018 and 2017 is based on distributions declared in respect of the fourth quarter of 2018 and 2017. Represents the ratio of distributable cash flow to distributions declared.

	Year ended December 31,
	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	$	227,929		$	237,832
Add:
Interest expense, excluding amortization of debt issuance costs		56,250			63,973
Income tax expense		33			341
Changes in operating assets and liabilities		8,122			28,890
Proportional adjusted EBITDA for equity method investees (1)		39,969			41,246
Adjustments related to MVC shortfall payments (2)		(3,632	)		(41,373	)
Adjustments related to capital reimbursement activity (3)		(427	)		—
Other, net (4)		1,112			—
Less:
Distributions from equity method investees		35,271			40,220
Write-off of debt issuance costs		—			302
Adjusted EBITDA	$	294,085		$	290,387
Less:
Cash interest paid		64,678			71,488
Cash paid for taxes		175			—
Senior notes interest adjustment (5)		—			(5,261	)
Distributions to Series A Preferred unitholders (6)		28,500			2,375
Series A Preferred units distribution adjustment (7)		—			1,188
Maintenance capital expenditures		21,430			15,587
Distributable cash flow	$	179,302		$	205,010

(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 year ended December 31, 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 year ended December 31, 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) Represents items of income or loss that we characterize as unrepresentative of our ongoing operations, including, in the three months and year ended December 31, 2018, $1.1 million of severance compensation expense associated with the resignation of our Chief Financial Officer in December 2018.

(5) 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.

(6) 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.

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

Contact: Blake Motley, Vice President of Strategy and Head of Investor Relations, 832-930-7539, ir@summitmidstream.com


	2019 Financial Guidance Range
($ in millions)	Low		High
Adjusted EBITDA	$295.0	-	$315.0
Capital Expenditures ⁽¹⁾	$150.0	-	$175.0
Maintenance Capital Expenditures	$15.0	-	$25.0
Distribution Coverage Ratio	1.75x	-	1.95x