Summit Midstream Partners, LP Reports Fourth Quarter and Full Year 2021 Financial and Operating Results & Provides Full Year 2022 Guidance

Rhea-AI Summary

Summit Midstream Partners (SMLP) reported a net loss of $16.2 million for Q4 2021 but achieved an adjusted EBITDA of $54.7 million. Natural gas throughput averaged 1,307 MMcf/d, with a slight decrease from Q3, while liquids throughput averaged 62 Mbbl/d. The company connected 25 new wells in Q4, contributing to output stability. The new Double E Pipeline is expected to enhance capacity and growth, anchored by long-term contracts. However, anticipated new well connections in 2022 are disappointingly low, leading to a cautious outlook despite strong price fundamentals.

Positive

• Adjusted EBITDA for 2021 reached $238 million, exceeding guidance.
• Successfully placed the Double E Pipeline in service, enhancing capacity by 1.35 Bcf/d.
• Reduction of Series A Preferred Equity by over 50%, improving financial flexibility.
• Operational expenses were kept low with capital expenditures at $25 million, in line with guidance.

Negative

• Net loss of $16.2 million in Q4 2021 indicates financial challenges.
• Natural gas throughput declined by 2.0% from Q3 2021, reflecting production declines.
• 2022 guidance anticipates only 75 to 110 new well connections, significantly lower than historical averages.

HOUSTON, Feb. 25, 2022 /PRNewswire/ -- Summit Midstream Partners, LP (NYSE: SMLP) ("Summit", "SMLP" or the "Partnership") announced today its financial and operating results for the three months ended December 31, 2021, including net loss of $16.2 million, adjusted EBITDA of $54.7 million and DCF of $29.9 million.  Operated natural gas throughput from wholly owned assets averaged 1,307 million cubic feet per day ("MMcf/d") and liquids throughput averaged 62 thousand barrels per day ("Mbbl/d").  Operated natural gas volumes from wholly owned assets decreased 2.0% relative to the third quarter of 2021, largely due to natural production declines, which was partially offset by volumes from 25 new wells that were turned-in-line primarily towards the latter half of the fourth quarter, including four new Utica wells that were connected in the Northeast segment in late November with initial production of nearly 100 MMcf/d.  Fourth quarter 2021 liquids volume decreased modestly relative to the third quarter of 2021, primarily as a result of natural production declines, partially offset by crude volumes gathered from 16 new Williston wells that were turned-in-line in November and December of 2021.

Heath Deneke, President, Chief Executive Officer and Chairman, commented, "Summit's fourth quarter financial and operating results were in-line with our expectations.  For full year 2021, adjusted EBITDA of $238 million was near the top of our $225 million to $240 million revised guidance range and almost $20 million above the midpoint of our initial guidance.  In 2021, we spent $25 million on capital expenditures, which was towards the low end of our $20 million to $35 million guidance range.  Well connect activity from our upstream customers during the fourth quarter of 2021 represented a significant increase versus the first three quarters of 2021, with 45 of the 95 wells turned-in-line behind our systems during the last quarter of the year.  We also successfully placed the Double E Pipeline in-service during the fourth quarter of 2021.  Double E is a very important new pipeline system for the northern Delaware Basin, with the initial capacity to transport an incremental 1.35 Bcf/d of natural gas from growing production in Eddy and Lea counties, New Mexico to multiple Gulf Coast oriented pipelines originating out of Waha, TX.  The pipeline is anchored by 1.0 Bcf/d of long term take-or-pay contracts from some of the largest producers in the Permian Basin and is well positioned for a highly efficient expansion to 2.0 Bcf/d as production continues to increase in the region. We are very proud of the team for delivering this important project on time, approximately 20% below the original $500 million budget, all while maintaining an outstanding safety, environmental and compliance record.  We expect Double E to be a significant growth catalyst for Summit as our initial 1.0 Bcf/d of sculpted take-or-pay contracts ramp up between 2022 and 2024 and as we secure new contracts from Northern Delaware customers that need incremental gas takeaway capacity."

"As previously announced, we also achieved a critical milestone for Summit during the fourth quarter with the successful refinancing of our 2022 debt maturities which provided an extended, multi-year runaway to continue our focus on maximizing free cash flow and further de-levering the balance sheet.  During the quarter, we also launched a cash-less preferred for common equity exchange transaction which closed in January of 2022, whereby holders of nearly $95 million of our Series A Preferred Equity, including accrued and unpaid distributions, exchanged into approximately 2.9 million SMLP common units.  This transaction enabled Summit to continue its efforts to simplify and improve the balance sheet by further reducing our outstanding fixed capital obligations while preserving cash for debt repayment.  The transaction also eliminated nearly $17 million of unpaid preferred distributions that have accrued on the balance sheet since June of 2020, while reducing the remaining amount of Series A Preferred Equity to which distributions are expected to continue to accrue by more than half.  Additionally, with the reduction in the face value of the remaining Series A Preferred Equity to a level below $100 million, SMLP is now able to issue or assume a separate class of parity preferred equity, which further enhances our strategic and financial flexibility as we continue to evaluate long-term value enhancing opportunities in the future."

"Our 2022 guidance includes an adjusted EBITDA range of $195 million to $220 million based on approximately 75 to 110 new well connections.  Given the current commodity price environment and the momentum in activity that we experienced in the second half of 2021, we are disappointed and frankly surprised by the limited amount of new wells that our customers' most recent plans are indicating will be turned on-line behind our systems in 2022.  As a point of reference, between 2017 and 2019, we averaged over 260 new well connects per year at a time when Henry Hub prices averaged below $3.00 MMbtu and WTI averaged below $60 per barrel.  At current strip pricing levels, we believe that nearly all of the remaining inventory behind our gas and crude systems would be economic to develop.  Furthermore, through a combination of industry consolidation and capital discipline, our customers have significantly improved their balance sheets and financial capability to responsibly increase development activity on the high-quality acreage behind our systems as economic conditions warrant.  While our current 2022 guidance levels do not indicate the beginning of the U-shape recovery that we have been anticipating, we continue to expect that drilling activity behind our systems will increase as our customers gain further confidence that the fundamentals underlying the current commodity price outlook will hold in the future. Last year is a good example of how customer plans can change throughout the year. Initially we expected approximately 60 new wells based on customer plans as of February 2021, and by the end of the second quarter, those plans increased to approximately 95 new wells, which was a key driver for increasing our 2021 guidance range in June of last year. Similar to last year, we plan to provide updated 2022 guidance if we expect the outlook to be materially different than our initial guidance range.  In the meantime, we will continue to focus on maximizing free cash flow and reducing debt, providing safe, efficient and reliable operations for our customers and a positive and safe work environment for our employees."

New Business Segments

As previously announced, during the fourth quarter of 2021 we implemented changes to our reportable segments.  The new segment reporting resulted from changes enacted to optimize commercial efforts and our geographic workforce in order to better align our commercial, engineering and operational capabilities.  The five reportable segments we will utilize going forward are described below, along with a management categorization of the commodity that has the most influence on customer drilling and completion decisions:

• Natural gas price driven: Our cash flows in the Northeast, Piceance and Barnett segments are significantly influenced by the price of natural gas because the drilling, completion and recompletion decisions by our customers in these segments are based on well economics most heavily impacted by the price of natural gas and natural gas liquids. Increased upstream activity by our customers in these basins therefore result in higher throughput and cash flows for those segments in which we collect fees for gathering natural gas or natural gas liquids.
• Northeast – Includes our wholly owned midstream assets located in the Utica and Marcellus shale plays and our equity method investment in Ohio Gathering that is focused on the Utica Shale
• Piceance – Includes our wholly owned midstream assets located in the Piceance Basin
• Barnett – Includes our wholly owned midstream assets located in the Barnett Shale
• Oil price driven: Customer activity and our cash flows in the Permian and Rockies segments are significantly influenced by the price of oil because the drilling and completion decisions by our customers in these segments are based on well economics most heavily impacted by the price of oil. Decisions to drill and complete wells in these basins therefore result in higher throughput and cash flows for our midstream assets in which we collect fees for gathering or processing hydrocarbons, gathering produced water, or transporting natural gas.
• Permian – Includes our wholly owned midstream assets located in the Permian Basin and our equity method investment in the Double E Pipeline
• Rockies – Includes our wholly owned midstream assets located in the Williston Basin and the DJ Basin

A comparison of prior and current reportable segments is listed in the table below for illustrative purposes.

Prior Reportable Segment(s)	New Reportable Segment
Utica Shale, Ohio Gathering, Marcellus Shale	Northeast
Piceance Basin	Piceance
Barnett Shale	Barnett
Permian Basin, Double E (new)	Permian
Williston Basin, DJ Basin	Rockies

2022 Guidance

SMLP is releasing guidance for 2022, which is summarized in the table below.  These projections are subject to risks and uncertainties as described in the "Forward-Looking Statements" section at the end of the release.

We have taken a similar approach to our 2022 guidance range that we did with our 2021 guidance range. If our producer customers hit their production targets and upper end of planned well connects, as they did in 2021, we would expect to be near the high end of our 2022 guidance range.  We believe the midpoint of our guidance range reflects a conservative, yet appropriate, level of risking to the most recent drill schedules and volume forecasts provided by our customers. 

($ in millions)				2022 Guidance Range
				Low		High
Well Connections		Average (2017 - 2019)
Northeast (includes OGC)		61		31		44
Piceance		50		17		17
Barnett		9		4		11
Permian		8		4		6
Rockies		134		20		30
Total		262		76		108
Natural Gas Throughput (MMcf/d)
Northeast (excludes OGC)				636		700
Piceance				299		303
Barnett				188		200
Permian (excludes Double E)				17		32
Rockies				32		35
Total				1,172		1,270
Rockies Liquids Throughput (Mbbl/d)				60		63
OGC Natural Gas Throughput (MMcf/d, gross)				602		681
Double E Natural Gas Throughput (MMcf/d, gross)				195		265
Adjusted EBITDA
Northeast				$68		$77
Piceance				60		63
Barnett				26		28
Permian				18		25
Rockies				53		57
Unallocated G&A, Other				(30)		(30)
Total				$195		$220
Capital Expenditures
Growth				$10		$20
Maintenance				$10		$15
Total				$20		$35
Investment in Double E equity method investee				$10		$10

We expect approximately 75 to 110 well connections in 2022, which remains significantly below pre-COVID levels averaging 262 well connections per year from 2017 through 2019 in a less favorable commodity price environment. The current commodity price environment should support increasing development activity and we believe if prices remain strong, we will begin to see producers increase activity behind our systems. We continue to see producers drill longer laterals, with several 2022 well connections expected to have 15,000' laterals, which helps mitigate the impact of limited well connections. We are encouraged by the level of activity we expect in the Barnett and Piceance, as customers in these areas take advantage of the favorable commodity price environment. Of our expected 2022 well connections, 34 wells are either online, DUCs or have a rig present. The remaining new wells expected in our 2022 forecast are permitted and have been recently affirmed by our customers.

We expect our wholly owned natural gas gathering system throughput to range from approximately 1,172 MMcf/d to 1,270 MMcf/d, as compared to 1,356 MMcf/d in 2021. The year-over-year expected decline is primarily due to natural production declines and limited expected well connections in the Northeast, Permian and Rockies. OGC gross volume throughput is expected to range from approximately 602 MMcf/d to 681 MMcf/d, as compared to 526 MMcf/d in 2021, representing over 20% year-over-year growth at the mid-point. With the commercial operation of Double E commencing in November 2021, we expect Double E throughput to increase throughout the course of 2022, with average annual gross throughput ranging from approximately 195 MMcf/d to 265 MMcf/d. Given nearly 90 active rigs in New Mexico, we are optimistic about overall volume growth in the basin and the potential for additional firm take-or-pay contracts. Double E benefits from existing take-or-pay contracts of 585 MMcf/d currently, contractually increasing to 810 MMcf/d beginning in November 2022, 985 MMcf/d beginning in November 2023 and 1.0 Bcf/d beginning in November 2024, leaving only 350 MMcf/d of remaining long-term capacity on the pipeline before an expansion is required. Liquids volumes are expected to remain relatively flat year-over-year, ranging from 60 Mbbl/d to 63 Mbbl/d, despite no well connections from certain key customers to whom we provide both crude oil and produced water gathering services.

Adjusted EBITDA is expected to range from $195 million to $220 million, a decrease from 2021 primarily due to limited drilling and completion activity, an approximately $12 million reduction in MVC shortfall payments that expired in 2021, $7 million in energy management and COVID-19 related tax credits in 2021 and approximately $5 million of one-time operating expenses expected in 2022. We are optimistic that we will find ways to mitigate the increasing pressure of inflation on our operating costs and believe that the approximately $5 million of expected one-time operating expenses in 2022 will mitigate operating expenses beginning in 2023.

Our 2022 capital expenditure guidance of $20 million to $35 million, excluding Double E, is presented on a gross basis and does not include asset sales or capital reimbursements related to specific development projects with certain customers.  We do expect to continue to monetize latent inventory, or other underutilized assets, which is not reflected in our financial guidance. In 2021, we sold approximately $8 million of such assets and have sold approximately $2 million to date in 2022. Our full year 2022 growth capex guidance range of $10 million to $20 million, excluding Double E, is dependent on new well connect activity and is expected to be directed towards new pad connections in our Northeast and Rockies segments. All other expected well connections are either on existing pad sites, or will be delivered to our gathering systems.  We also expect that the vast majority, if not all, of the remaining $10 million investment in Double E will be funded with cash-on-hand at our unrestricted subsidiaries, or through Double E distributions generated from operations.   We expect approximately $10 million to $15 million of maintenance capex, an increase relative to our 2021 maintenance capex of $8 million, primarily due to approximately $6 million of expected one-time capital expenditures related to certain asset integrity initiatives and modifications to assets for emission reductions.

In 2022, we expect to generate cash flow after interest expense, capital expenditures, investments in Double E and other cash expenditures of $65 million to $85 million, which we plan to utilize to further reduce our indebtedness.

Fourth Quarter 2021 Business Highlights

In the fourth quarter of 2021, SMLP's average daily natural gas throughput for its wholly owned operated systems decreased by 2.0% to 1,307 MMcf/d, and liquids volumes decreased by 1.6% to 62 Mbbl/d, relative to the third quarter of 2021.  In November 2021, Double E Pipeline commenced operations and began transporting residue gas from the Northern Delaware Basin to the Waha hub in Texas, resulting in an average of 124 MMcf/d of gross volumes transported since commissioning and approximately $1.9 million of adjusted EBITDA net to SMLP for the fourth quarter of 2021.  SMLP's customers are currently operating four drilling rigs on acreage behind SMLP's gathering systems, and there are approximately 34 new wells that were already connected to the system, have been drilled or are currently under development.

Natural gas price driven segments:

• Natural gas price driven segments had combined quarterly segment adjusted EBITDA of $45.1 million and combined capital expenditures of $5.1 million in the fourth quarter of 2021.
• Northeast segment adjusted EBITDA totaled $19.0 million, an 8.2% decrease relative to the third quarter of 2021 driven by natural production declines of approximately 35 MMcf/d behind our SMU system, partially offset by 16 new wells, of which the majority were connected during the second half of the fourth quarter of 2021. These new well connects included a new four well pad behind our SMU system, as well as four well connects behind our Mountaineer system in the Marcellus shale. The new four well pad behind the SMU system was connected in late November 2021 and averaged 96 MMcf/d while online, or approximately 75 MMcf/d for the fourth quarter of 2021. The Northeast segment has 15 wells that are either online, have been drilled, or are under development, which represents 48% of the midpoint for Northeast segment well connects in our 2022 guidance.
• Piceance segment adjusted EBITDA of $15.9 million decreased by 16.1% from the third quarter of 2021, primarily due to the expiration of an MVC at the end of September 2021 that contributed $3.4 million of adjusted EBITDA to the segment in the third quarter of 2021 and natural production declines, partially offset by volumes from 9 new wells that were connected during the quarter by one of our larger customers. These 9 wells represented the first new wells connected to our Piceance system since the third quarter of 2018 and contributed approximately 9.1 MMcf/d while online, averaging 7.6 MMcf/d for the fourth quarter of 2021. Based on its 2022 capital program, this same customer is planning to connect 17 wells, which have all been permitted towards the middle to latter part of 2022. This customer also has plans for another 74 wells behind our system in the 2023 to 2024 timeframe and has entered into a capital reimbursement agreement with SMLP so that planning activities for those well connections can be undertaken.
• Barnett segment adjusted EBITDA of $10.2 million increased by 5.7% from the third quarter of 2021, primarily due to a 21 MMcf/d increase in volume throughput driven by continued strong performance from the 7 wells that were turned-in-line in September of 2021. These wells continue to be some of the largest natural gas wells ever drilled in the Barnett Shale and averaged 47 MMcf/d during the fourth quarter of 2021. The low end of our 2022 guidance range includes four new well connects, of which all have been drilled.

Oil price driven segments

• Oil price driven segments generated $17.5 million of combined segment adjusted EBITDA in the fourth quarter of 2021 and had combined capital expenditures of $8.1 million.
• Permian segment EBITDA totaled $2.6 million in the fourth quarter of 2021, a $2.0 million increase relative to the third quarter of 2021 primarily due to the commencement of operations at Double E in mid-November 2021. Double E is an equity method investment, so the Permian segment is allocated SMLP's proportionate share of Double E EBITDA. There were no new wells connected behind the Permian gathering and processing system during the fourth quarter of 2021 and the 4 well pad that was expected to come online in December 2021 was delayed until 2022. In 2022, we currently expect limited activity behind our Permian gathering and processing system from our existing customers and for the majority of adjusted EBITDA for the segment to come from offloads and our proportionate share of Double E.
• Rockies segment EBITDA of $14.9 million decreased by 20.4% from the prior quarter primarily due to a one-time $1.8 million benefit from the settlement of a legal matter in the third quarter of 2021. In the Williston Basin, 16 new wells were connected to our crude gathering infrastructure; however, all of these wells were connected in November and December, resulting in limited impact to fourth quarter of 2021 performance. The Rockies segment has 11 wells that are either online, have been drilled or are under development, which represents approximately 55% of the midpoint for Rockies segment well connects in our 2022 guidance. We currently expect limited new well connect activity in the DJ Basin from our existing customers in 2022, but may benefit from additional volumes related to an offload agreement we are actively negotiating.

The following table presents average daily throughput by reportable segment for the periods indicated:

	Three Months Ended December 31,				Year Ended December 31,
	2021		2020		2021		2020
Average daily throughput (MMcf/d):
Northeast (2)	710		813		765		726
Rockies	34		39		35		40
Permian (2)	24		33		26		33
Piceance	317		347		326		364
Barnett	222		204		204		212
Aggregate average daily throughput	1,307		1,436		1,356		1,375
Average daily throughput (Mbbl/d):
Rockies	62		71		63		79
Aggregate average daily throughput	62		71		63		79
Ohio Gathering average daily throughput (MMcf/d) (1)	530		621		526		571
Double E average daily throughput (MMcf/d) (3)	58		–		15		–

(1)	Gross basis, represents 100% of volume throughput for Ohio Gathering, subject to a one-month lag.
(2)	Exclusive of Ohio Gathering and Double E due to equity method accounting.
(3)	Gross, basis, represents 100% of volume throughput for Double E.

 

The following table presents adjusted EBITDA by reportable segment for the periods indicated:

	Three Months Ended December 31,				Year Ended December 31,
	2021		2020		2021		2020
	(In thousands)				(In thousands)
Reportable segment adjusted EBITDA (1):
Northeast (2)	$         19,013		$        22,969		$        83,287		$        85,854
Rockies	14,911		15,861		64,517		71,509
Permian (3)	2,600		(62)		6,614		5,744
Piceance	15,865		22,026		76,131		88,820
Barnett	10,187		7,617		36,729		32,093
Total	$         62,576		$        68,411		$       267,278		$       284,020
Less:  Corporate and Other (4)	7,870		6,620		28,855		31,905
Adjusted EBITDA	$         54,706		$        61,791		$       238,423		$       252,115

__________

(1)	We define segment adjusted EBITDA as total revenues less total costs and expenses, plus (i) other income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit-based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains.
(2)	Includes our proportional share of adjusted EBITDA for Ohio Gathering, subject to 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 during the respective period.
(3)	Includes our proportional share of adjusted EBITDA for Double E.  We define proportional adjusted EBITDA for our equity method investees as the product of total revenues less total expenses, excluding impairments and other noncash income or expense items; multiplied by our ownership interest during the respective period.
(4)	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 and natural gas and crude oil marketing services.

Capital Expenditures

Capital expenditures totaled $13.3 million in the fourth quarter of 2021, inclusive of maintenance capital expenditures of $3.2 million.  Capital expenditures in the fourth quarter of 2021 were primarily related to growth projects to connect new pad sites in our Northeast, Rockies and Permian segments.

	Year Ended December 31,
	2021		2020
	(In thousands)
Cash paid for capital expenditures (1):
Northeast	$        11,237		$          7,657
Rockies	9,875		21,596
Permian	2,042		7,014
Piceance	579		1,370
Barnett	766		1,878
Total reportable segment capital expenditures	$        24,499		$        39,515
Corporate and Other	531		3,613
Total cash paid for capital expenditures	$        25,030		$        43,128

__________

(1)	Excludes cash paid for capital expenditures by Ohio Gathering (after June 2019) and Double E due to equity method accounting.

Capital & Liquidity

As of December 31, 2021, SMLP had $267 million drawn under its $400 million ABL Revolver and $109.1 million of borrowing availability, after accounting for $23.9 million of issued, but undrawn letters of credit.  As of December 31, 2021, SMLP's gross availability based on the borrowing base calculation in the credit agreement was $691 million, which is $291 million greater than the $400 million of lender commitments to the ABL Revolver.  As of December 31, 2021 SMLP was in compliance with all financial covenants, including interest coverage of 4.3x relative to a minimum interest coverage covenant of 2.0x and first lien leverage ratio of 1.1x relative to a maximum first lien leverage ratio of 2.5x. As of December 31, 2021, SMLP reported a total leverage ratio of 5.16x and is no longer subject to a total leverage ratio covenant.

As of December 31, 2021, the Permian Transmission Credit Facility was fully drawn and $160 million was outstanding.  In January 2022, the Permian Transmission Credit Facility was converted to a term loan and  mandatory quarterly amortization will commence in March of 2022.  The Permian Transmission Term Loan remains non-recourse to SMLP.

MVC Shortfall Payments

SMLP billed its customers $16.7 million in the fourth quarter of 2021 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 2021, SMLP recognized $10.3 million of gathering revenue associated with MVC shortfall payments.  SMLP had no adjustments to MVC shortfall payments in the fourth quarter of 2021.  SMLP's MVC shortfall payment mechanisms contributed $10.3 million of total adjusted EBITDA in the fourth quarter of 2021 and $51.1 million of total adjusted EBITDA for full year 2021.

	Three Months Ended December 31, 2021
	MVC Billings		Gathering revenue		Adjustments to MVC shortfall payments		Net impact to adjusted EBITDA
Net change in deferred revenue related to MVC    shortfall payments:
Piceance Basin	$          300		$          300		$            —		$         300
Total net change	$          300		$          300		$            —		$         300
MVC shortfall payment adjustments:
Rockies	$        8,580		$        2,145		$            —		$       2,145
Piceance	6,335		6,335		—		6,335
Northeast	1,470		1,470		—		1,470
Total MVC shortfall payment adjustments	$      16,385		$        9,950		$            —		$       9,950
Total (1)	$      16,685		$      10,250		$            —		$     10,250

__________

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

	Year Ended December 31, 2021
	MVC Billings		Gathering revenue		Adjustments to MVC shortfall p ayments		Net impact to adjusted EBITDA
Net change in deferred revenue related to MVC    shortfall payments:
Piceance	$     11,307		$     11,307		$            —		$     11,307
Total net change	$     11,307		$     11,307		$            —		$     11,307
MVC shortfall payment adjustments:
Rockies	$       8,580		$       8,580		$            —		$       8,580
Piceance	24,923		24,923		—		24,923
Northeast	6,248		6,248		—		6,248
Total MVC shortfall payment adjustments	$     39,751		$     39,751		$            —		$     39,751
Total (1)	$     51,058		$     51,058		$            —		$     51,058

__________

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

Quarterly Distribution

The board of directors of SMLP's general partner continued to suspend cash distributions payable on its common units and on its 9.50% Series A fixed-to-floating rate cumulative redeemable perpetual preferred units (the "Series A Preferred Units") for the period ended December 31, 2021.  Unpaid distributions on the Series A Preferred Units will continue to accumulate.  Subsequent to year end, SMLP closed a preferred-for-common unit exchange that eliminated $16.6 million of accumulated distributions. 

Fourth Quarter 2021 Earnings Call Information

SMLP will host a conference call at 10:00 a.m. Eastern on Friday, February 25, 2022, 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 50277720.  The conference call, live webcast and archive of the call can be accessed through the Investors section of SMLP's website at www.summitmidstream.com.

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, non-GAAP financial measures.

Adjusted EBITDA

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, impairments, items of income or loss that we characterize as unrepresentative of our ongoing operations and other noncash expenses or losses, income tax benefit, income (loss) from equity method investees and other noncash income or gains.   Because adjusted EBITDA may be defined differently by other entities in our industry, our definition of this non-GAAP financial measure may not be comparable to similarly titled measures of other entities, thereby diminishing its utility.

Management uses adjusted EBITDA in making financial, operating and planning decisions and in evaluating our financial performance. Furthermore, management believes that adjusted EBITDA 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 is used as a supplemental financial measure to assess:

• the ability of our assets to generate cash sufficient to make future potential 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 income or expense items that we characterize as unrepresentative of our ongoing operations.
• Adjusted EBITDA has limitations as an analytical tool and investors should not consider it in isolation or as a substitute for analysis of our results as reported under GAAP. For example:
• certain items excluded from adjusted EBITDA 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 does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
• adjusted EBITDA does 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 does not reflect any cash requirements for such replacements.

We compensate for the limitations of adjusted EBITDA as an analytical tool by reviewing the comparable GAAP financial measures, understanding the differences between the financial measures and incorporating these data points into our decision-making process.

Distributable Cash Flow

We define Distributable Cash Flow as adjusted EBITDA, as defined above, less cash interest paid, cash paid for taxes, net interest expense accrued and paid on the senior notes, and maintenance capital expenditures.

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 and (ii) 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 value-driven 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, processing and transportation services pursuant to primarily long-term, fee-based 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.  SMLP has an equity method investment in Double E Pipeline, LLC, which provides interstate natural gas  transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas.  SMLP also has an equity method investment in Ohio Gathering, which operates extensive natural gas gathering and condensate stabilization infrastructure in the Utica Shale in Ohio.  SMLP is headquartered in Houston, Texas.

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 include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words "expect," "intend," "plan," "anticipate," "estimate," "believe," "will be," "will continue," "will likely result," and similar expressions, or future conditional verbs such as "may," "will," "should," "would," and "could."  In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies and possible actions taken by us or our subsidiaries are also forward-looking statements.  Forward-looking statements also 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 2020 Annual Report on Form 10-K filed with the Securities and Exchange Commission (the "SEC") on March 4, 2021, as amended and updated from time to time. Any forward-looking statements in this press release 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.

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
	December 31, 2021		December 31, 2020
	(In thousands)
ASSETS
Cash and cash equivalents	$          7,349		$        15,544
Restricted cash	12,223		—
Accounts receivable	62,121		61,932
Other current assets	5,676		4,623
Total current assets	87,369		82,099
Property, plant and equipment, net	1,726,082		1,813,810
Intangible assets, net	172,927		199,566
Investment in equity method investees	523,196		392,740
Other noncurrent assets	12,888		11,602
TOTAL ASSETS	$   2,522,462		$   2,499,817
LIABILITIES AND CAPITAL
Trade accounts payable	$        10,498		$        11,878
Accrued expenses	14,462		13,036
Deferred revenue	10,374		9,988
Ad valorem taxes payable	8,570		9,086
Accrued compensation and employee benefits	11,019		9,658
Accrued interest	12,737		8,007
Accrued environmental remediation	3,068		1,392
Accrued settlement payable	4,833		—
Other current liabilities	3,676		5,363
Total current liabilities	79,237		68,408
Long-term debt, net	1,355,072		1,347,326
Noncurrent deferred revenue	42,570		48,250
Noncurrent accrued environmental remediation	2,538		1,537
Other noncurrent liabilities	32,357		21,747
Total liabilities	1,511,774		1,487,268
Commitments and contingencies
Mezzanine Capital
Subsidiary Series A Preferred Units	106,325		89,658
Partners' Capital
Series A Preferred Units	169,769		174,425
Common limited partner capital	734,594		748,466
Total partners' capital	904,363		922,891
TOTAL LIABILITIES AND CAPITAL	$   2,522,462		$   2,499,817

 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
	Three Months Ended December 31,				Year Ended December 31,
	2021		2020		2021		2020
	(In thousands, except per-unit amounts)
Revenues:
Gathering services and related fees	$         66,201		$         73,125		$       281,705		$       302,792
Natural gas, NGLs and condensate sales	23,467		14,073		82,768		49,319
Other revenues	9,546		9,212		36,145		31,362
Total revenues	99,214		96,410		400,618		383,473
Costs and expenses:
Cost of natural gas and NGLs	23,795		13,708		81,969		36,653
Operation and maintenance	19,297		20,899		74,178		86,030
General and administrative (1)	9,752		33,530		58,166		73,438
Depreciation and amortization	31,210		29,331		119,076		118,132
Transaction costs	401		1,049		1,677		2,993
Gain on asset sales, net	(17)		(37)		(369)		(307)
Long-lived asset impairment	8,378		8,614		10,151		13,089
Total costs and expenses	92,816		107,094		344,848		330,028
Other income (expense), net	919		(596)		(613)		48
Loss on ECP Warrants	—		—		(13,634)		—
Interest expense	(21,171)		(14,058)		(66,156)		(78,894)
Gain on early extinguishment of debt (2)	(3,523)		124,137		(3,523)		203,062
Income (loss) before income taxes and equity method investment income	(17,377)		98,799		(28,156)		177,661
Income tax benefit (expense)	(14)		42		327		146
Income from equity method investees	1,186		4,125		7,880		11,271
Net income (loss)	$        (16,205)		$       102,966		$        (19,949)		$       189,078
Net income (loss) per limited partner unit:
Common unit – basic	$           (3.42)		$           30.45		$           (6.57)		$           73.22
Common unit – diluted	$           (3.42)		$           29.73		$           (6.57)		$           71.19
Weighted-average limited partner units outstanding:
Common units – basic	7,170		4,894		6,741		3,592
Common units – diluted	7,170		5,013		6,741		3,694

__________

(1)	For the year ended December 31, 2021, the amount includes a $22.4 million loss related to the Blacktail Release. For the three months ended December 31, 2020, the amount includes a $17.0 loss related to the Blacktail Release and $5.6 million of restructuring expenses. For the year ended December 31, 2020, the amount includes a $17.0 million loss related to the Blacktail Release and $9.0 million of restructuring expenses.
(2)	For the year ended December 31, 2020, the amount includes early extinguishment of debt, primarily related to liability management initiatives undertaken during 2020 that resulted in a $86.4 million gain from the Open Market Repurchases, a $23.3 million gain from the Debt Tender Offers, and a $93.9 million gain from our TL Restructuring.

 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES UNAUDITED OTHER FINANCIAL AND OPERATING DATA
	Three Months Ended December 31,				Year Ended December 31,
	2021		2020		2021		2020
	(In thousands)
Other financial data:
Net income (loss)	$        (16,205)		$       102,966		$        (19,949)		$       189,078
Net cash provided by operating activities	37,368		51,782		165,099		198,589
Capital expenditures	13,250		7,816		25,030		43,128
Contributions to equity method investees	46,590		7,855		(148,699)		(99,927)
Adjusted EBITDA	54,706		61,791		238,423		252,115
Cash flow available for distributions (1)	$         29,924		$         44,755		$       168,288		$       162,835
Distributions (2)	n/a		n/a		n/a		n/a
Operating data:
Aggregate average daily throughput – natural     gas (MMcf/d)	1,307		1,436		1,356		1,375
Aggregate average daily throughput – liquids (Mbbl/d)	62		71		63		79
Ohio Gathering average daily throughput (MMcf/d) (3)	530		621		526		571
Double E average daily throughput (MMcf/d) (4)	58		–		15		–

__________

(1)	Cash flow available for distributions is also referred to as Distributable Cash Flow, or DCF.
(2)	Represents distributions declared and ultimately paid or expected to be paid to preferred and common unitholders in respect of a given period. On May 3, 2020, the board of directors of SMLP's general partner announced an immediate suspension of the cash distributions payable on its preferred and common units.
(3)	Gross basis, represents 100% of volume throughput for Ohio Gathering, subject to a one-month lag.
(4)	Gross, basis, represents 100% of volume throughput for Double E.

 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES UNAUDITED RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
	Three Months Ended December 31,				Year Ended December 31,
	2021		2020		2021		2020
	(In thousands)
Reconciliations of net income or loss to     adjusted EBITDA and Distributable     Cash Flow:
Net income	$        (16,205)		$       102,966		$        (19,949)		$       189,078
Add:
Interest expense	21,171		14,058		66,156		78,894
Income tax (benefit) expense	14		(42)		(327)		(146)
Depreciation and amortization (1)	31,425		29,565		119,995		119,070
Proportional adjusted EBITDA for equity     method investees (2)	8,619		8,474		29,022		31,056
Adjustments related to MVC shortfall     payments (3)	—		859		—		—
Adjustments related to capital reimbursement     activity (4)	(1,552)		(619)		(6,571)		(1,395)
Unit-based and noncash compensation	861		1,920		4,744		8,111
(Gain) loss on early extinguishment of debt	3,523		(124,137)		3,523		(203,062)
Gain on asset sales, net	(17)		(37)		(369)		(307)
Long-lived asset impairment	8,378		8,614		10,151		13,089
Other, net (5)	(325)		24,295		39,928		28,998
Less:
Income from equity method investees	1,186		4,125		7,880		11,271
Adjusted EBITDA	$         54,706		$         61,791		$       238,423		$       252,115
Less:
Cash interest paid	17,302		17,009		57,655		79,450
Cash paid for taxes	—		—		191		190
Senior notes interest adjustment (6)	4,245		(3,091)		4,757		(4,487)
Maintenance capital expenditures	3,235		3,118		7,532		14,127
Cash flow available for distributions (7)	$         29,924		$         44,755		$       168,288		$       162,835

__________

(1)	Includes the amortization expense associated with our favorable gas gathering contracts as reported in other revenues.
(2)	Reflects our proportionate share of Double E and Ohio Gathering (subject to a one-month lag) adjusted EBITDA.
(3)	Adjustments related to MVC shortfall payments are recognized ratably over the term of the associated MVC.
(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)	Represents items of income or loss that we characterize as unrepresentative of our ongoing operations. For the year ended December 31, 2021, the amount includes $22.2 million of losses related to the Blacktail Release and a $13.6 million loss related to the ECP Warrants. For the three months ended December 31, 2020, the amount includes a $17.0 million loss related to the Blacktail Release, $5.6 million of restructuring expenses and $1.0 million of transaction costs associated with the GP Buy-In Transaction. For the year ended December 31, 2020, the amount includes a $17.0 million loss related to the Blacktail Release, $9.0 million of restructuring expenses and $3.2 million of transaction costs associated with the GP Buy-In Transaction.
(6)	Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. Interest on the 5.5% senior notes was paid in cash semi-annually in arrears on February 15 and August 15. Interest on the 5.75% senior notes is paid in cash semi-annually in arrears on April 15 and October 15 until maturity in April 2025. Interest on the 8.5% senior notes is paid in cash semi-annually in arrears on April 15 and October 15 until maturity in October 2026.
(7)	Represents cash flow available for distribution to preferred and common unitholders. Common distributions cannot be paid unless all accrued preferred distributions are paid. Cash flow available for distributions is also referred to as Distributable Cash Flow, or DCF.

 

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES UNAUDITED RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
	Year Ended December 31,
	2021		2020
	(In thousands)
Reconciliation of net cash provided by operating activities to adjusted     EBITDA and distributable cash flow:
Net cash provided by operating activities	$      165,099		$      198,589
Add:
Interest expense, excluding amortization of debt issuance costs	59,139		72,286
Income tax (benefit) expense	(327)		(146)
Gain (loss) on ECP warrants and unsettled  interest rate swaps	(14,414)		259
Transaction costs	1,677		3,913
Changes in operating assets and liabilities	(5,867)		(50,018)
Proportional adjusted EBITDA for equity method investees (1)	29,022		31,056
Adjustments related to capital reimbursement activity (2)	(6,571)		(1,395)
Other, net (3)	38,529		28,998
Less:
Distributions from equity method investees	26,760		28,185
Noncash lease expense	1,104		3,242
Adjusted EBITDA	$      238,423		$      252,115
Less:
Cash interest paid	57,655		79,450
Cash paid for taxes	191		190
Senior notes interest adjustment (4)	4,757		(4,487)
Maintenance capital expenditures	7,532		14,127
Cash flow available for distributions (5)	$      168,288		$      162,835

__________

(1)	Reflects our proportionate share of Double E and Ohio Gathering adjusted EBITDA, subject to a one-month lag.
(2)	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").
(3)	Represents items of income or loss that we characterize as unrepresentative of our ongoing operations. For the year ended December 31, 2021, the amount includes $22.2 million of losses related to the Blacktail Release and a $13.6 million loss related to ECP Warrants. For the year ended December 31, 2020, the amount includes a $17.0 million loss related to the Blacktail Release, $9.0 million of restructuring expenses and $3.2 million of transaction costs associated with the GP Buy-In Transaction.
(4)	Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. Interest on the 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 5.75% senior notes is paid in cash semi-annually in arrears on April 15 and October 15 until maturity in April 2025.
(5)	Represents cash flow available for distribution to preferred and common unitholders. Common distributions cannot be paid unless all accrued preferred distributions are paid. Cash flow available for distributions is also referred to as Distributable Cash Flow, or DCF.

 

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SOURCE Summit Midstream Partners, LP

FAQ

What were Summit Midstream's Q4 2021 results?

Summit Midstream reported a net loss of $16.2 million and adjusted EBITDA of $54.7 million for Q4 2021.

How much natural gas throughput did SMLP achieve in Q4 2021?

SMLP's natural gas throughput averaged 1,307 million cubic feet per day in Q4 2021.

What is the expected impact of the Double E Pipeline for SMLP?

The Double E Pipeline is expected to enhance capacity by 1.35 Bcf/d and serve as a significant growth catalyst.

What is SMLP's guidance for new well connections in 2022?

For 2022, SMLP anticipates only 75 to 110 new well connections, which is a decline from previous years.