SUMMIT MIDSTREAM PARTNERS, LP
This Management's Discussion and Analysis of Financial Condition and Results of
Operations ("MD&A") is intended to inform the reader about matters affecting the
financial condition and results of operations of the Partnership and its
subsidiaries for the periods since December 31, 2020 . As a result, the following
discussion should be read in conjunction with the unaudited condensed
consolidated financial statements and notes thereto included in this report and
the MD&A and the audited consolidated financial statements and related notes
that are included in the Partnership's Annual Report on Form 10-K for the year
ended December 31, 2020 (the "2020 Annual Report"). Among other things, those
financial statements and the related notes include more detailed information
regarding the basis of presentation for the following information. This
discussion contains forward-looking statements that constitute our plans,
estimates and beliefs. These forward-looking statements involve numerous risks
and uncertainties, including, but not limited to, those discussed in
Forward-Looking Statements. Actual results may differ materially from those
contained in any forward-looking statements.
Overview
We are a value-driven limited partnership focused on developing, owning and
operating midstream energy infrastructure assets that are strategically located
in unconventional resource basins, primarily shale formations, in the
continental United States .
We classify our midstream energy infrastructure assets into two categories, our
Core Focus Areas and our Legacy Areas. Further details on our Focus Areas and
Legacy Areas are summarized below.
•Core Focus Areas. Core producing areas of basins in which we expect our
gathering systems to experience greater long-term growth, driven by our
customers' ability to generate more favorable returns and support sustained
drilling and completion activity in varying commodity price environments. In the
near-term, we expect to concentrate the majority of our capital expenditures in
our Core Focus Areas. Our Utica Shale , Ohio Gathering, Williston Basin , DJ Basin
and Permian Basin reportable segments (as described below) comprise our Core
Focus Areas.
•Legacy Areas. Production basins in which we expect volume throughput on our
gathering systems to experience relatively lower long-term growth compared to
our Core Focus Areas, given that our customers require relatively higher
commodity prices to support drilling and completion activities in these basins.
Upstream production served by our gathering systems in our Legacy Areas is
generally more mature, as compared to our Core Focus Areas, and the decline
rates for volume throughput on our gathering systems in the Legacy Areas are
typically lower as a result. We expect to continue to decrease our near-term
capital expenditures in these Legacy Areas. Our Piceance Basin , Barnett Shale
and Marcellus Shale reportable segments (as described below) comprise our Legacy
Areas.
Our financial results are driven primarily by volume throughput across our
gathering systems and by expense management. We generate the majority of our
revenues from the gathering, compression, treating and processing services that
we provide to our customers. A majority of the volumes that we gather, compress,
treat and/or process have a fixed-fee rate structure which enhances the
stability of our cash flows by providing a revenue stream that is not subject to
direct commodity price risk. We also earn a portion of our revenues from the
following activities that directly expose us to fluctuations in commodity
prices: (i) the sale of physical natural gas and/or NGLs purchased under
percentage-of-proceeds or other processing arrangements with certain of our
customers in the Williston Basin , Piceance Basin , and Permian Basin segments,
(ii) the sale of natural gas we retain from certain Barnett Shale customers and
(iii) the sale of condensate we retain from our gathering services in the
Piceance Basin segment. During the three and six months ended June 30, 2021 ,
these additional activities accounted for approximately 16% and 19% of total
revenues, respectively.
We also have indirect exposure to changes in commodity prices in that
persistently low commodity prices may cause our customers to delay and/or cancel
drilling and/or completion activities or temporarily shut-in production, which
would reduce the volumes of natural gas and crude oil (and associated volumes of
produced water) that we gather. If certain of our customers cancel or delay
drilling and/or completion activities or temporarily shut-in production, the
associated MVCs, if any, ensure that we will earn a minimum amount of revenue.
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The following table presents certain consolidated and reportable segment
financial data. For additional information on our reportable segments, see the
"Segment Overview for the Three and Six Months Ended June 30, 2021 and 2020"
section included herein.
Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(In thousands)
Net income (loss) $ (19,738) $ 56,721 $ (10,750) $ 60,483
Reportable segment adjusted EBITDA
Utica Shale $ 10,652 $ 10,693 $ 18,372 $ 16,621
Ohio Gathering 6,841 7,514 13,713 15,453
Williston Basin 9,626 12,727 20,431 28,919
DJ Basin 5,106 4,339 10,453 10,250
Permian Basin 461 1,828 1,170 3,409
Piceance Basin 20,324 21,734 41,358 45,291
Barnett Shale 8,889 8,510 16,905 17,270
Marcellus Shale 5,868 4,888 11,469 10,208
Net cash provided by operating
activities $ 34,787 $ 35,170 $ 86,217 $ 105,371
Capital expenditures (1) 3,352 8,843 5,962 27,426
Investment in Double E equity method
investee (2) 43,324 21,695 48,943 79,728
Borrowings under Revolving Credit
Facility - 35,000 - 90,000
Repayments on Revolving Credit Facility (40,000) - (95,000) (34,000)
Repayment of SMP Holdings Term Loan - (5,500) - (6,300)
Borrowings under Permian Transmission
Credit Facility 36,000 - 53,500
Repurchase of Senior Notes - (76,707) - (76,707)
Proceeds from issuance of Subsidiary
Series A preferred units, net of
issuance costs - 14,764 - 47,810
Purchase of common units in GP Buy-In
Transaction - (41,778) - (41,778)
(1)See "Liquidity and Capital Resources" herein to the unaudited condensed
consolidated financial statements for additional information on capital
expenditures.
(2)Inclusive of $0.6 million and nil of capitalized interest for the three
months ended June 30, 2021 and 2020 respectively, and $1.6 million and $0.3
million for the six months ended June 30, 2021 and 2020 respectively.
Trends and Outlook
Our business has been, and we expect our future business to continue to be,
affected by the following key trends:
•Ongoing impact of the COVID-19 pandemic and its effect on demand and prices for
oil;
•Natural gas, NGL and crude oil supply and demand dynamics;
•Production from U.S. shale plays;
•Capital markets availability and cost of capital; and
•Shifts in operating costs and inflation.
Our expectations are based on assumptions made by us and information currently
available to us. To the extent our underlying assumptions about, or
interpretations of, available information prove to be incorrect, our actual
results may vary materially from our expected results. For additional
information, see the "Trends and Outlook" section of MD&A included in the 2020
Annual Report.
Ongoing impact of the COVID-19 pandemic and its effect on demand and prices for
oil. We continue to closely monitor the impact of the COVID-19 pandemic on all
aspects of our business, including how it has impacted and will impact our
customers,
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employees, supply chain and distribution network. We are unable to predict the
ultimate impact that COVID-19, and related factors may have on our business,
future results of operations, financial position or cash flows.
In response to the COVID-19 pandemic, we have modified our business practices,
including restricting employee travel, utilizing COVID-19 pandemic tax relief
(as allowed by the Consolidated Appropriations Act, 2021, the "ERC Tax Credit"),
modifying employee work locations, implementing social distancing and enhancing
sanitary measures in our facilities. Our increased reliance on remote access to
our information systems increases our exposure to potential cybersecurity
breaches. We may take further actions as government authorities require or
recommend or as we determine to be in the best interests of our employees,
customers, partners and suppliers. In addition to the significant reduction in
global demand for oil and natural gas caused by the economic effects of the
COVID-19 pandemic, we also experienced more oil price volatility during 2020,
largely due to a macro supply and demand imbalance and actions by members of
OPEC and other foreign, oil-exporting countries. This disrupted the oil and
natural gas exploration and production industry and other industries that serve
exploration and production companies. These industry conditions, coupled with
those resulting from the COVID-19 pandemic, could lead to significant global
economic contraction generally and in our industry in particular.
Over the past year, we have collaborated extensively with our customer base
regarding production reductions and delays to drilling and completion activities
in light of the current commodity price backdrop and COVID-19 pandemic. Given
continued volatility in market conditions since March 2020 , and based on
recently updated production forecasts and revised 2021 development plans from
our customers, we currently expect our 2021 results to continue to be affected
by more moderated drilling and completion activity, relative to historical
periods.
Winter Storm Uri. Due to the diverse geographic footprint of our operations
outside of Texas , the extreme winter weather event that occurred in February
2021 ("Winter Storm Uri") did not have a material impact on our aggregate volume
throughput during the six months ended June 30, 2021 . Some of the steps taken
during or prior to Winter Storm Uri to mitigate the storm's financial impact
remain subject to risks, including counterparty financial risk, potential
disputed transactions and potential legislative or regulatory action in response
to, or litigation arising out of, the unprecedented circumstances of the winter
storm, which could affect our future earnings, cash flows and financial
condition.
Debt maturities. The Partnership's wholly owned subsidiary, Summit Holdings , has
a senior secured revolving credit facility due May 13, 2022 (the "Revolving
Credit Facility"). The 2022 maturity date of our Revolving Credit Facility
resulted in the inclusion of this outstanding indebtedness balance into our
going concern assessment for the quarterly period ended June 30, 2021 . As a
result, the lack of sufficient available liquidity to satisfy amounts due under
our Revolving Credit Facility has raised substantial doubt about our ability to
continue as a going concern.
How We Evaluate Our Operations
Each of our reportable segments provides midstream services in a specific
geographic area. Our reportable segments reflect the way in which we internally
report the financial information used to make decisions and allocate resources
in connection with our operations. For additional information see Note 15 -
Segment Information.
Our management uses a variety of financial and operational metrics to analyze
our consolidated and segment performance. We view these metrics as important
factors in evaluating our profitability and determining the amounts of cash
distributions to pay to our unitholders. These metrics include:
•throughput volume;
•revenues;
•operation and maintenance expenses; and
•segment adjusted EBITDA.
We review these metrics on a regular basis for consistency and trend analysis.
There have been no changes in the composition or characteristics of these
metrics during the three and six months ended June 30, 2021 .
Additional Information. For additional information, see the "Results of
Operations" section herein and the notes to the unaudited condensed consolidated
financial statements. For additional information on how these metrics help us
manage our business, see the "How We Evaluate Our Operations" section of MD&A
included in the 2020 Annual Report. For information on impending accounting
changes that are expected to materially impact our financial results reported in
future periods, see Note 2 - Summary of Significant Accounting Policies and
Recently Issued Accounting Standards applicable to the Partnership.
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Results of Operations
Consolidated Overview for the Three and Six Months Ended June 30, 2021 and 2020
The following table presents certain consolidated financial and operating data.
Three Months Ended June 30, Six Months Ended June 30,
2021 2020 2021 2020
(In thousands) (In thousands)
Revenues:
Gathering services and related fees
16,416 10,683 37,180 24,463
Other revenues 9,392 7,413 17,599 14,744
Total revenues 100,041 92,007 199,359 196,910
Costs and expenses:
Cost of natural gas and NGLs 16,626 6,088 37,102 14,313
Operation and maintenance 17,507 21,152 34,100 42,963
General and administrative (2) 29,360 12,786 39,938 29,347
Depreciation and amortization 28,364 29,630 56,875 59,296
Transaction costs 450 1,207 217 1,218
Gain on asset sales, net (4) (281) (140) (166)
Long-lived asset impairment 33 654 1,525 4,475
Total costs and expenses 92,336 71,236 169,617 151,446
Other income (expense), net (2,334) 276 (2,284) (151)
Loss on ECP Warrants (12,159) - (13,634) -
Interest expense (15,502) (21,990) (29,455) (45,818)
Gain on early extinguishment of debt - 54,235 - 54,235
Income (loss) before income taxes and
equity method investment income (22,290) 53,292 (15,631) 53,730
Income tax benefit 248 389 262 402
Income from equity method investees 2,304 3,040 4,619 6,351
Net income (loss) $ (19,738) $
56,721
Volume throughput (1): Aggregate average daily throughput - natural gas (MMcf/d) 1,441 1,391 1,393 1,336 Aggregate average daily throughput - liquids (Mbbl/d) 63 76 64 87 (1)Exclusive of volume throughput for Ohio Gathering. For additional information, see the "Ohio Gathering" section herein. (2)Inclusive of a$19.3 million incremental loss contingency accrual during the three months endedJune 30, 2021 related to the 2015 Blacktail Release (See Note 13 - Commitments and Contingencies for additional information). Volumes - Gas. Natural gas throughput volumes increased 50 MMcf/d for the three months endedJune 30, 2021 compared to the three months endedJune 30, 2020 , primarily reflecting: •a volume throughput increase of 80 MMcf/d for theUtica Shale segment; •a volume throughput decrease of 41 MMcf/d for thePiceance Basin segment; •a volume throughput decrease of 5 MMcf/d for theBarnett Shale segment; •a volume throughput increase of 18 MMcf/d for theMarcellus Shale segment; and 27 -------------------------------------------------------------------------------- Table of Contents •a volume throughput decrease of 3 MMcf/d for thePermian Basin segment. Natural gas throughput volumes increased 57 MMcf/d for the six months endedJune 30, 2021 compared to the six months endedJune 30, 2020 , primarily reflecting: •a volume throughput increase of 134 MMcf/d for theUtica Shale segment; •a volume throughput decrease of 41 MMcf/d for thePiceance Basin segment; •a volume throughput decrease of 23 MMcf/d for theBarnett Shale segment; •a volume throughput decrease of 4 MMcf/d for theMarcellus Shale segment; and •a volume throughput decrease of 4 MMcf/d for thePermian Basin segment. Volumes - Liquids. Crude oil and produced water throughput volumes at the Williston segment decreased 13 Mbbl/d and 23 Mbbl/d, respectively, for the three and six months endedJune 30, 2021 , compared to the three and six months endedJune 30, 2020 , primarily as a result of natural production declines as well as a lower number of new well connects. For additional information on volumes, see the "Segment Overview for the Three and Six Months EndedJune 30, 2021 and 2020" section herein. Revenues. Total revenues increased$8.0 million during the three months endedJune 30, 2021 compared to the prior year period, comprised of a$5.7 million increase in natural gas, NGLs and condensate sales, a$0.3 million increase in gathering services and related fees and a$2.0 million increase in Other Revenues. Gathering Services and Related Fees. Gathering services and related fees increased$0.3 million compared to the three months endedJune 30, 2020 . Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate revenues increased$5.7 million compared to the three months endedJune 30, 2020 , reflecting: •a$5.1 million increase in revenues in theWilliston Basin ; •a$2.7 million increase in revenues in thePermian Basin ; offset by •a$2.8 million decrease in revenues in theBarnett Shale . Total revenues increased$2.4 million during the six months endedJune 30, 2021 compared to the prior year period, primarily comprised of a$12.7 million increase in natural gas, NGLs and condensate sales, a$2.9 million increase in Other Revenues, offset by a$13.1 million decrease in gathering services and related fees. Gathering Services and Related Fees. Gathering services and related fees decreased$13.1 million compared to the six months endedJune 30, 2020 , primarily reflecting: •an$11.1 million decrease in gathering services and related fees in theWilliston Basin , primarily due to lower liquids volume throughput and the expiration of a customer's minimum volume commitment. Lower volumes are primarily associated with natural production declines as well as a lower number of new well connects during the period; •a$3.1 million decrease in gathering services and related fees in thePiceance Basin related to lower volume throughput due to a lack of drilling and completion activity and natural production declines; and •a partially offsetting$1.4 million increase in gathering services and related fees in theUtica Shale , primarily as a result of the completion of new wells that were commissioned inMarch 2021 , partially offset by natural production declines on existing wells. Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate revenues increased$12.7 million compared to the six months endedJune 30, 2020 , reflecting: •a$13.0 million increase in revenues in theWilliston Basin ; •a$4.7 million increase in revenues in thePermian Basin ; and •a$1.5 million increase in revenues in thePiceance Basin ; partially offset by •a$6.7 million decrease in revenues in theBarnett Shale . Costs and Expenses. Total costs and expenses increased$21.1 million during the three months endedJune 30, 2021 compared to the three months endedJune 30, 2020 . 28 -------------------------------------------------------------------------------- Table of Contents Total costs and expenses increased$18.2 million during the six months endedJune 30, 2021 compared to the six months endedJune 30, 2020 . Cost of Natural Gas and NGLs. Cost of natural gas and NGLs increased$10.5 million for the three months endedJune 30, 2021 compared to the three months endedJune 30, 2020 , primarily driven by an increase in commodity prices. Cost of natural gas and NGLs increased$22.8 million for the six months endedJune 30, 2021 compared to the six months endedJune 30, 2020 , primarily driven by an increase in commodity prices. Operation and Maintenance. Operation and maintenance expense decreased$3.6 million and$8.9 million for the three and six months endedJune 30, 2021 , respectively, compared to the three and six months endedJune 30, 2020 , primarily due to reduced employee headcount as a result of restructuring activities implemented in the fourth quarter of 2020. The Partnership realized$5.6 million of benefits during the six months endedJune 30, 2021 , that are not otherwise expected to occur in 2022 and future periods, as a result of commercial settlements and the ERC Tax Credit. General and Administrative. General and administrative expense increased$16.6 million for the three months endedJune 30, 2021 compared to the three months endedJune 30, 2020 , primarily due to a$19.3 million loss contingency accrual related to the 2015 Blacktail Release (see Note 13 - Commitments and Contingencies for additional information), partially offset by the prior period in 2020 reflecting higher restructuring and deal costs as well as a decrease in salaries and benefits associated with lower headcount from our restructuring of operations in late 2020 (the "2020 Restructuring Plan") and other cost-cutting initiatives which were realized in the three months endedJune 30, 2021 . General and administrative expense increased$10.6 million for the six months endedJune 30, 2021 compared to the six months endedJune 30, 2020 , primarily due to the aforementioned loss contingency recognized for the 2015 Blacktail Release, partially offset by the prior period in 2020 reflecting restructuring and deal costs as well as a decrease in salaries and benefits associated with lower headcount from our 2020 Restructuring Plan and other cost-cutting initiatives which were realized in the six months endedJune 30, 2021 . The Partnership realized$1.0 million of ERC Tax Credit benefits during the six months endedJune 30, 2021 , that are not otherwise expected to occur in future periods. Depreciation and Amortization. Depreciation and amortization expense decreased$1.3 million for the three months endedJune 30, 2021 compared to the three months endedJune 30, 2020 . Depreciation and amortization expense decreased$2.4 million for the six months endedJune 30, 2021 compared to the six months endedJune 30, 2020 . Interest Expense. The decrease in interest expense for the three and six months endedJune 30, 2021 , compared to the three and six months endedJune 30, 2020 , was primarily due to lower debt balances associated with the Partnership's liability management initiatives completed during 2020 which included (i) open market repurchases of its Senior Notes totaling$234.2 million face value, (ii) cash tender offers of its Senior Notes totaling$72.2 million , and (iii) the consensual debt discharge and restructuring of our$155.2 SMPH Term Loan (the "TL Restructuring"). The decrease in interest expense was partially offset by a higher outstanding balance on the Revolving Credit Facility and a higher interest rate on the Revolving Credit Facility. 29
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Segment Overview for the Three and Six Months Ended
Utica Shale
Three Months Ended June 30, Six Months Ended June 30,
Percentage Percentage
2021 2020 Change 2021 2020 Change
Average daily throughput
(MMcf/d) 496 416 19% 453 319 42%
Volume throughput increased compared to the three and six month periods ended
June 30, 2021 , as a result of the commissioning of new wells in 2020 which
resulted in a greater number of well connects during the three month period
ended March 31, 2021 , compared to the same period in 2020, together with the
commencement of production from a new 4-well pad site during the three months
ended March 31, 2021 . This increase was partially offset by natural production
declines from existing wells.
Financial data for our
Utica Shale
Three Months Ended June 30, Six Months Ended June 30,
Percentage Percentage
2021 2020 Change 2021 2020 Change
(Dollars in thousands) (Dollars in thousands)
Revenues:
Gathering services and related
fees $ 11,349 $ 11,538 (2)% $ 19,920 $ 18,500 8%
Total revenues 11,349 11,538 (2)% 19,920 18,500 8%
Costs and expenses:
Operation and maintenance 658 757 (13%) 1,436 1,698 (15%)
General and administrative 28 84 (67%) 89 172 (48%)
Depreciation and amortization 1,928 1,920 - 3,854 3,847 -
Gain on asset sales, net - (42) * - (26) *
Total costs and expenses 2,614 2,719 (4%) 5,379 5,691 (5%)
Add:
Depreciation and amortization 1,928 1,920 3,854 3,847
Adjustments related to capital
reimbursement activity (11) (4) (23) (9)
Gain on asset sales, net - (42) - (26)
Segment adjusted EBITDA $ 10,652 $ 10,693 0% $ 18,372 $ 16,621 11%
________
* Not considered meaningful
Three and six months ended June 30, 2021 . Segment adjusted EBITDA remained
consistent and increased $1.8 million , respectively, compared to the three and
six months ended June 30, 2020 primarily as a result of the increased volume
throughput described above, partially offset by a higher mix of lower-margin
volumes on the system in the three months ended June 30, 2021 .
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Ohio Gathering. The Ohio Gathering reportable segment includes OGC and OCC. We
account for our investment in Ohio Gathering using the equity method and we
recognize our proportionate share of earnings or loss in net income on a
one-month lag based on the financial information available to us during the
reporting period.
Gross volume throughput for Ohio Gathering, based on a one-month lag follows.
Ohio Gathering
Three Months Ended June 30, Six Months Ended June 30,
Percentage Percentage
2021 2020 Change 2021 2020 Change
Average daily throughput
(MMcf/d) 514 540 (5)% 536 575 (7)%
Volume throughput for the Ohio Gathering system decreased compared to the three
and six month periods ended June 30, 2020 as a result of natural production
declines on existing wells on the system.
Financial data for our Ohio Gathering reportable segment, based on a one-month
lag follows.
Ohio Gathering
Three Months Ended June 30, Six Months Ended June 30,
Percentage Percentage
2021 2020 Change 2021 2020 Change
(Dollars in thousands) (Dollars in thousands)
Proportional adjusted EBITDA for
equity
method investees $ 6,841 $ 7,514 (9%) $ 13,713 $ 15,453 (11%)
Segment adjusted EBITDA $ 6,841 $ 7,514 (9%) $ 13,713 $ 15,453 (11%)
Segment adjusted EBITDA for equity method investees decreased $0.7 million and
$1.7 million compared to the three and six months ended June 30, 2020 primarily
as a result of the lower volume throughput described above.
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Williston Basin . The Polar and Divide, Bison Midstream and Meadowlark Midstream
systems provide our midstream services for the Williston Basin reportable
segment. Volume throughput for our Williston Basin reportable segment follows.
Williston Basin
Three Months Ended June 30, Six Months Ended June 30,
Percentage Percentage
2021 2020 Change 2021 2020 Change
Aggregate average daily
throughput -
natural gas (MMcf/d) 12 14 (14%) 12 14 (14%)
Aggregate average daily
throughput -
liquids (Mbbl/d) 63 76 (17%) 64 87 (26%)
Natural gas. Natural gas volume throughput decreased compared to the three and
six months ended June 30, 2020 , primarily reflecting natural production
declines.
Liquids. Liquids volume throughput decreased compared to the three and six
months ended June 30, 2020 , primarily associated with natural production
declines as well as a lower number of new well connects.
Financial data for our Williston Basin reportable segment follows.
Williston Basin
Three Months Ended June 30, Six Months Ended June 30,
Percentage Percentage
2021 2020 Change 2021 2020 Change
(Dollars in thousands) (Dollars in thousands)
Revenues:
Gathering services and related
fees $ 12,516 $ 12,407 1% $ 25,149 $ 36,204 (31%)
Natural gas, NGLs and condensate
sales 8,201 3,131 162% 20,428 7,455 174%
Other revenues 4,242 2,776 53% 8,749 5,918 48%
Total revenues 24,959 18,314 36% 54,326 49,577 10%
Costs and expenses:
Cost of natural gas and NGLs 8,548 941 808% 20,873 2,604 702%
Operation and maintenance 5,483 5,827 (6%) 10,407 12,549 (17%)
General and administrative 332 492 (33%) 686 1,030 (33%)
Depreciation and amortization 5,915 6,487 (9%) 11,837 12,982 (9%)
Gain on asset sales, net - (96) * (15) (47) *
Long-lived asset impairment 41 9 * 41 9 *
Total costs and expenses 20,319 13,660 49% 43,829 29,127 50%
Add:
Depreciation and amortization 5,915 6,487 11,837 12,982
Adjustments related to MVC
shortfall payments - 2,124 - (3,541)
Adjustments related to capital
reimbursement activity (970) (451) (1,929) (934)
Gain on asset sales, net - (96) (15) (47)
Long-lived asset impairment 41 9 41 9
Segment adjusted EBITDA $ 9,626 $ 12,727 (24%) $ 20,431 $ 28,919 (29%)
_______
* Not considered meaningful
Three and six months ended June 30, 2021 . Segment adjusted EBITDA decreased $3.1
million and $8.5 million respectively, compared to the three and six months
ended June 30, 2020 primarily due to lower liquids volume throughput on our
systems as previously discussed, partially offset by lower operating expenses
associated with our 2020 Restructuring Plan and other cost-cutting initiatives
and lower general operating expenses.
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DJ Basin . The Niobrara G&P systems provide midstream services for the DJ Basin
reportable segment. Volume throughput for our DJ Basin reportable segment
follows.
DJ Basin
Three Months Ended June 30, Six Months Ended June 30,
Percentage Percentage
2021 2020 Change 2021 2020 Change
Average daily throughput
(MMcf/d) 23 20 15% 23 26 (12%)
Volume throughput increased compared to the three months ended June 30, 2020 ,
and increased compared to the six months ended June 30, 2020 , primarily as a
result of natural production declines and a decreased number of wells that were
commissioned during 2021, together with temporarily shut-in production that our
customers initiated in the prior-year period.
Financial data for our DJ Basin reportable segment follows.
DJ Basin
Three Months Ended June 30, Six Months Ended June 30,
Percentage Percentage
2021 2020 Change 2021 2020 Change
(Dollars in thousands) (Dollars in thousands)
Revenues:
Gathering services and related
fees $ 5,891 $ 5,228 13% $ 12,154 $ 12,083 1%
Natural gas, NGLs and condensate
sales 305 71 330% 415 141 194%
Other revenues 1,856 993 87% 2,560 2,027 26%
Total revenues 8,052 6,292 28% 15,129 14,251 6%
Costs and expenses:
Cost of natural gas and NGLs 214 2 * 230 11 *
Operation and maintenance 1,882 2,354 (20%) 3,794 4,870 (22%)
General and administrative 1,350 141 857% 1,669 223 648%
Depreciation and amortization 1,544 1,502 3% 3,096 3,029 2%
(Gain) loss on asset sales, net (5) 20 * (7) 20 *
Long-lived asset impairment - 57 * 95 3,692 *
Total costs and expenses 4,985 4,076 - 8,877 11,845 (25%)
Add:
Depreciation and amortization 1,544 1,502 3,096 3,029 Adjustments related to capital reimbursement activity 500 544 994 1,103 (Gain) loss on asset sales, net (5) 20 (7) 20 Long-lived asset impairment - 57 95 3,692 Other - - 23 - Segment adjusted EBITDA$ 5,106 $ 4,339 18%$ 10,453 $ 10,250 2%
________
* Not considered meaningful Three and six months endedJune 30, 2021 . Segment adjusted EBITDA increased$0.8 million and$0.2 million respectively, compared to the three and six months endedJune 30, 2020 , primarily due to temporarily shut-in production that our customers initiated in the prior-year period, together with lower operating expenses associated with our 2020 Restructuring Plan and other cost-cutting initiatives and lower general operating expenses partially offset by lower volumes associated with natural declines. 33 -------------------------------------------------------------------------------- Table of ContentsPermian Basin . The Summit Permian system provides our midstream services for thePermian Basin reportable segment. Volume throughput for ourPermian Basin reportable segment follows. Permian Basin Three Months Ended June 30, Six Months Ended June 30, Percentage Percentage 2021 2020 Change 2021 2020 Change Average daily throughput (MMcf/d) 29 32 (9%) 29 33 (12%) Volume throughput decreased compared to the three and six months endedJune 30, 2020 , primarily as a result of natural production declines from wells previously put in service. Financial data for ourPermian Basin reportable segment follows. Permian Basin Three Months Ended June 30, Six Months Ended June 30, Percentage Percentage 2021 2020 Change 2021 2020 Change (Dollars in thousands) (Dollars in thousands) Revenues: Gathering services and related fees$ 2,262 $ 2,711 (17%)$ 4,461 $ 5,022 (11%) Natural gas, NGLs and condensate sales 6,875 4,222 63% 13,393 8,734 53% Other revenues 121 126 (4%) 237 313 (24%) Total revenues 9,258 7,059 31% 18,091 14,069 29% Costs and expenses: Cost of natural gas and NGLs 7,167 3,691 94% 14,182 7,840 81% Operation and maintenance 1,527 1,456 5% 2,519 2,643 (5%) General and administrative 118 84 40% 235 177 33% Depreciation and amortization 1,464 1,387 6% 2,933 2,732 7% Gain on asset sales, net - (17) * - (13) * Long-lived asset impairment - - - 182 * Total costs and expenses 10,276 6,601 56% 19,869 13,561 47%
Add:
Depreciation and amortization 1,464 1,387 2,933 2,732 Gain on asset sales, net - (17) - (13) Long-lived asset impairment - - - 182 Other 15 - 15 - Segment adjusted EBITDA$ 461 $ 1,828 (75)%$ 1,170 $ 3,409 (66)% ________ *Not considered meaningful Three and six months endedJune 30, 2021 . Segment adjusted EBITDA decreased$1.4 million and$2.2 million respectively, compared to the three and six months endedJune 30, 2020 , primarily reflecting lower volume throughput across the system associated with natural production declines, together with an increase in the cost of natural gas and NGLs, partially offset by increased sales of natural gas, NGLs and condensate. 34
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Table of
Piceance Basin
Three Months Ended June 30, Six Months Ended June 30,
Percentage Percentage
2021 2020 Change 2021 2020 Change
Aggregate average daily
throughput
(MMcf/d) 326 367 (11%) 334 375 (11%)
Volume throughput decreased compared to the three and six months ended June 30,
2020 , primarily as a result of natural production declines and an absence of new
well connects in 2021.
Financial data for our Piceance Basin reportable segment follows.
Piceance Basin
Three Months Ended June 30, Six Months Ended June 30,
Percentage Percentage
2021 2020 Change 2021 2020 Change
(Dollars in thousands) (Dollars in thousands)
Revenues:
Gathering services and related fees
(3%)$ 50,311 $ 53,411
(6%)
Natural gas, NGLs and condensate sales 1,025 401 156% 2,878 1,404 105% Other revenues 1,233 1,096 13% 2,409 2,161 11% Total revenues 27,785 27,719 0% 55,598 56,976 (2%) Costs and expenses: Cost of natural gas and NGLs 697 320 118% 1,816 777 134% Operation and maintenance 5,367 5,267 2% 10,309 10,205 1% General and administrative 345 276 25% 643 561 15% Depreciation and amortization 10,757 11,306 (5%) 21,631 22,604 (4%) (Gain) loss on asset sales, net 4 (83) * (53) (96) * Long-lived asset impairment - - * 970 - * Total costs and expenses 17,170 17,086 0% 35,316 34,051 4% Add: Depreciation and amortization 10,757 11,306 21,631 22,604 Adjustments related to MVC shortfall payments - 167 - 390 Adjustments related to capital reimbursement activity (1,403) (289) (1,831) (532) (Gain) loss on asset sales, net 4 (83) (53) (96) Long-lived asset impairment - - 970 - Other 351 - 359 - Segment adjusted EBITDA$ 20,324 $ 21,734 (6%)$ 41,358 $ 45,291 (9%) ________ *Not considered meaningful Three and six months endedJune 30, 2021 . Segment adjusted EBITDA decreased$1.4 million and$3.9 million compared to the three and six months endedJune 30, 2020 , primarily reflecting a decrease in volume throughput as a result of natural production declines as discussed above. 35 -------------------------------------------------------------------------------- Table of ContentsBarnett Shale . The DFW Midstream system provides our midstream services for theBarnett Shale reportable segment. Volume throughput for ourBarnett Shale reportable segment follows. Barnett Shale Three Months Ended June 30, Six Months Ended June 30, Percentage Percentage 2021 2020 Change 2021 2020 Change Average daily throughput (MMcf/d) 198 203 (2%) 195 218 (11%) Volume throughput decreased compared to the three and six months endedJune 30, 2020 reflecting an absence of new well connections in 2021 together with natural production declines, partially offset by workovers and recompletions. Financial data for ourBarnett Shale reportable segment follows. Barnett Shale Three Months Ended June 30, Six Months Ended June 30, Percentage Percentage 2021 2020 Change 2021 2020 Change (Dollars in thousands) (Dollars in thousands) Revenues: Gathering services and related fees$ 10,076 $ 9,877 2%$ 19,772 $ 20,320 (3%) Natural gas, NGLs and condensate sales 10 2,858 (100%) 66 6,729 (99%) Other revenues (1) 1,012 1,778 (43%) 2,072 3,038 (32%) Total revenues 11,098 14,513 (24%) 21,910 30,087 (27%) Costs and expenses: Cost of natural gas and NGLs - 1,134 (100%) - 3,081 (100%) Operation and maintenance 1,852 4,564 (59%) 4,316 9,259 (53%) General and administrative 260 513 (49%) 495 891 (44%) Depreciation and amortization 3,798 3,788 - 7,596 7,585 - (Gain) loss on asset sales, net (11) (42) * (11) 17 * Long-lived asset impairment - - * 289 4 * Total costs and expenses 5,899 9,957 (41%) 12,685 20,837 (39%)
Add:
Depreciation and amortization 4,032 4,023 8,064 8,055 Adjustments related to capital reimbursement activity (331) (27) (662) (56) (Gain) loss on asset sales, net (11) (42) (11) 17 Long-lived asset impairment - - 289 4 Segment adjusted EBITDA$ 8,889 $ 8,510 4%$ 16,905 $ 17,270 (2)%
________
*Not considered meaningful (1)Includes the amortization expense associated with our favorable gas gathering contracts as reported in Other revenues. Three and six months endedJune 30, 2021 . Segment adjusted EBITDA increased$0.4 million compared to the three months endedJune 30, 2020 , primarily as a result of lower operating expenses associated with our 2020 Restructuring Plan together with other cost-cutting initiatives and lower general operating expenses, including lower compression operating costs, partially offset by lower volume throughput. 36 -------------------------------------------------------------------------------- Table of ContentsMarcellus Shale . The Mountaineer Midstream system provides our midstream services for theMarcellus Shale reportable segment. Volume throughput for theMarcellus Shale reportable segment follows. Marcellus Shale Three Months Ended June 30, Six Months Ended June 30, Percentage Percentage 2021 2020 Change 2021 2020 Change Average daily throughput (MMcf/d) 357 339 5% 347 351 (1)% Volume throughput increased compared to the three and six months endedJune 30, 2020 primarily due to nine new wells that were commissioned behind our gathering system in the three months endedJune 30, 2021 , partially offset by natural production declines. Financial data for ourMarcellus Shale reportable segment follows. Marcellus Shale Three Months Ended June 30, Six Months Ended June 30, Percentage Percentage 2021 2020 Change 2021 2020 Change (Dollars in thousands) (Dollars in thousands) Revenues: Gathering services and related fees$ 6,612 $ 5,928 12%$ 12,813 $ 12,163 5% Total revenues 6,612 5,928 12% 12,813 12,163 5% Costs and expenses: Operation and maintenance 658 933 (29%) 1,160 1,746 (34%) General and administrative 76 97 (22%) 165 190 (13%) Depreciation and amortization 2,301 2,300 0% 4,605 4,600 0% (Gain) loss on asset sales, net 8 - * (54) - * Long-lived asset impairment (8) - * 130 - * Total costs and expenses 3,035 3,330 (9%) 6,006 6,536 (8%)
Add:
Depreciation and amortization 2,301 2,300 4,605 4,600 Adjustments related to capital reimbursement activity (10) (10) (19) (19) (Gain) loss on asset sales, net 8 - (54) - Long-lived asset impairment (8) - 130 - Segment adjusted EBITDA$ 5,868 $ 4,888 20%$ 11,469 $ 10,208 12% ________ *Not considered meaningful Three and six months endedJune 30, 2021 . Segment adjusted EBITDA increased$1.0 million and$1.3 million , respectively, compared to the three and six months endedJune 30, 2020 , as a result of higher volume throughput discussed above together with lower operating expenses associated with our 2020 Restructuring Plan and other cost-cutting initiatives and lower general operating expenses. 37
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Table of Contents
Corporate and Other Overview for the Three and Six Months EndedJune 30, 2021 and 2020 Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, natural gas and crude oil marketing services, construction management fees related to theDouble E Project , transaction costs and interest expense. Corporate and Other Three Months Ended June 30, Six Months Ended June 30, Percentage Percentage 2021 2020 Change 2021 2020 Change (Dollars in thousands) (Dollars in thousands) Revenues: Total revenues $ 928$ 644 44%$ 1,572 $ 1,287 22% Costs and expenses: General and administrative (1) 26,850 11,099 142% 35,957 26,103 38% Transaction costs 450 1,207 * 217 1,218 * Interest expense 15,502 21,990 (30)% 29,455 45,818 (36)% Gain on early extinguishment of debt - (54,235) * - (54,235) * ________ * Not considered meaningful (1)Inclusive of a$19.3 million incremental loss contingency accrual during the three months endedJune 30, 2021 related to the 2015 Blacktail Release (See Note 13 - Commitments and Contingencies for additional information). Total Revenues. Total revenues attributable to Corporate and Other was primarily due to construction management fee revenue associated with theDouble E Project . General and Administrative. General and administrative expense increased$15.8 million and$9.9 million , respectively, compared to the three and six months endedJune 30, 2020 , primarily as a result of a$19.3 million loss contingency accrual related to the 2015 Blacktail Release (see Note 13 - Commitments and Contingencies for additional information), partially offset by increased restructuring and deal costs in the comparative prior year period, as well as a decrease in salaries and benefits associated with lower headcount from our 2020 Restructuring Plan and other cost-cutting initiatives. Interest Expense. The decrease in interest expense for the three and six months endedJune 30, 2021 , compared to the three and six months endedJune 30, 2020 , was primarily due to lower outstanding debt balances associated with the Partnership's liability management initiatives completed during 2020 which included (i) open market repurchases of its Senior Notes totaling$234.2 million face value, (ii) cash tender offers of its Senior Notes totaling$72.2 million , and (iii) the TL Restructuring that eliminated the Partnership's$155.2 million SMPH Term Loan. The decrease in interest expense was partially offset by a higher outstanding balance and a higher interest rate on the Partnership's Revolving Credit Facility. Liquidity and Capital Resources COVID-19 Impact. We are closely monitoring the continuing impact of the outbreak of COVID-19 on all aspects of our business, including how it will impact our liquidity and capital resources. Considering the current commodity price backdrop and COVID-19 pandemic, we have collaborated extensively with our customer base over the past year. Given continued volatility in market conditions sinceMarch 2020 , and based on recently updated production forecasts and revised development plans from our customers, we currently expect our results to continue to be affected by decreased drilling activity, the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in theWilliston Basin ,DJ Basin andUtica Shale reportable segments. We expect 2021 total capital expenditures to range from$20.0 million to$35.0 million . As we cannot predict the duration or scope of the COVID-19 pandemic and its impact on our customers and suppliers, the potential negative financial impact to our results cannot be reasonably estimated but could be material. Indebtedness Compliance. We are currently in compliance with all covenants contained in the Revolving Credit Facility, the Permian Transmission Credit Facility and the Senior Notes. Our total leverage ratio and first lien leverage ratio (as defined in the Revolving Credit Agreement) were 5.0 to 1.0 and 3.0 to 1.0, respectively, relative to maximum threshold limits of 5.75 to 1.0 and 3.5 to 1.0, for the trailing 12-month period endedJune 30, 2021 . Given further deterioration of market conditions, 38 -------------------------------------------------------------------------------- Table of Contents decreased drilling activity, the deferral of well completions from customers, limitations on our ability to access the capital markets at a competitive cost to fund our capital expenditures and, on a limited scale, temporary production curtailments, we could have total leverage and first lien leverage ratios in the future that are higher than the levels prescribed in the applicable indebtedness agreements. Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations and cash flows. The 2022 maturity date for our Revolving Credit Facility resulted in the inclusion of this outstanding indebtedness balance into our going concern assessment for the quarterly period endedJune 30, 2021 . As a result, the lack of sufficient available liquidity to satisfy amounts due under our Revolving Credit Facility has raised substantial doubt about our ability to continue as a going concern. We are in the process of negotiating a new 4.5-year asset-based revolving credit facility (the "ABL Revolver") that is expected to (i) have a borrowing capacity of$400.0 million to$500.0 million and (ii) be conditioned on the successful completion of a$700.0 million to$750.0 million offering of high yield notes (the "High Yield Notes Offering"). It is our goal to consummate both financings concurrently during the quarter endingSeptember 30, 2021 . The proceeds of the ABL Revolver and the High Yield Notes Offering would be used to repay the Revolving Credit Facility and redeem the senior unsecured notes dueAugust 15, 2022 (the "2022 Senior Notes) issued bySummit Holdings andFinance Corp. , another of our wholly-owned subsidiaries. However, there can be no assurance that we will be able to arrange an ABL Revolver or consummate the High Yield Notes Offering on terms acceptable to us prior toSeptember 30, 2021 or at all. If we are unable to meet our debt service and principal repayment obligations, or if we fail to comply with the leverage ratios in the documents governing our debt, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to become immediately due and payable (which would in turn trigger cross-acceleration or cross-default rights among our debt agreements). The lenders under our Revolving Credit Facility could also terminate their commitments to extend credit, the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. If the amounts outstanding under our Revolving Credit Facility or our Senior Notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to our creditors. For additional information, see the risk factor titled "We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful." included in Part II. Item 1A. Risk Factors in this report. Credit Arrangements and Financing Activities Revolving Credit Facility. We have a$1.1 billion senior secured Revolving Credit Facility that matures onMay 13, 2022 . As ofJune 30, 2021 , the outstanding balance of the Revolving Credit Facility was$762.0 million and the unused portion totaled$314.9 million , after giving effect to the issuance thereunder of$23.1 million of outstanding but undrawn irrevocable standby letters of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility, as ofJune 30, 2021 , was approximately$137.6 million . There were no defaults or events of default during the three months endedJune 30, 2021 , and, as ofJune 30, 2021 , we were in compliance with the financial covenants in the Revolving Credit Facility. Permian Transmission Credit Facility. OnMarch 8, 2021 , we entered into the Permian Transmission Credit Facility which allows for$175.0 million of senior secured credit facilities, including a$160.0 million term loan facility and a$15.0 million working capital facility. As ofJune 30, 2021 , the outstanding balance of the Permian Transmission Credit Facility was$53.5 million , and the unused portion totaled$121.5 million . Our available borrowing capacity under the Permian Transmission Credit Facility as ofJune 30, 2021 was approximately$119.5 million . There were no defaults or events of default during the three months endedJune 30, 2021 , and, as ofJune 30, 2021 , we were in compliance with the financial covenants in the Permian Transmission Credit Facility. Exchange Offer. InApril 2021 , we completed an offer to exchange 18,662 Series A Preferred Units for 538,715 newly issued SMLP common units, which is net of units withheld for withholding taxes. We may in the future use a combination of cash, secured or unsecured borrowings and issuances of our common units or other securities and the proceeds from asset sales to retire or refinance our outstanding debt or Series A Preferred Units through privately negotiated transactions, open market repurchases, redemptions, exchange offers, tender offers or otherwise, but we are under no obligation to do so. For additional information on our long-term debt, see Note 9. Partners' Capital and Mezzanine Capital. LIBOR Transition LIBOR is the basic rate of interest widely used as a reference for setting the interest rates on loans globally. In 2017, theUnited Kingdom's Financial Conduct Authority , which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. TheU.S. Federal Reserve , in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of largeU.S. financial institutions, is considering replacingU.S. dollar LIBOR with a new index, the Secured Overnight Financing Rate ("SOFR"), calculated using short-term repurchase agreements backed byTreasury securities. We are 39 -------------------------------------------------------------------------------- Table of Contents evaluating the potential impact of the eventual replacement of the LIBOR benchmark interest rate, however, we are not able to predict whether LIBOR will cease to be available after 2021, whether SOFR will become a widely accepted benchmark in place of LIBOR, or what the impact of such a possible transition to SOFR may be on our business, financial condition and results of operations. We will need to renegotiate our Revolving Credit Facility to determine the interest rate to replace LIBOR with the new standard that is established, assuming that it is not refinanced. The potential effect of any such event on interest expense cannot yet be determined. Cash Flows The components of the net change in cash and cash equivalents were as follows: Six Months Ended June 30, 2021 2020 (In thousands) Net cash provided by operating activities$ 86,217 $ 105,371 Net cash used in investing activities (46,905) (106,937) Net cash provided by (used in) financing activities (47,331) 6,263
Net change in cash, cash equivalents and restricted cash
Operating activities. Cash flows provided by operating activities for the six months endedJune 30, 2021 primarily reflected: •net loss of$10.8 million plus adjustments of$90.5 million for non-cash items; and •$6.4 million increase in working capital accounts. Cash flows provided by operating activities for the six months endedJune 30, 2020 primarily reflected: •a$7.0 million increase in accounts receivable related to the timing of invoicing and cash collections; •a$2.9 million increase in accounts payable due to the timing of payment obligations; •a$3.5 million increase in deferred revenue for cash receipts not yet recognized as revenue; •a$11.8 million decrease in accrued expenses primarily due to the timing of accrued payment obligations; and •other changes in working capital Investing activities. Cash flows used in investing activities during the six months endedJune 30, 2021 primarily reflected: •$48.9 million for investments in theDouble E joint venture relating to theDouble E Project ; •$6.0 million cash outflow for capital expenditures; •offset by an$8.0 million cash inflow from proceeds for the sale of compressor equipment; Cash flows used in investing activities during the six months endedJune 30, 2020 primarily reflected: •$79.7 million for investments in theDouble E joint venture relating to theDouble E Project ; and •$27.4 million of capital expenditures primarily attributable to theDJ Basin of$8.4 million , theWilliston Basin of$7.4 million and Summit Permian of$4.9 million . Financing activities. Cash flows used in financing activities during the six months endedJune 30, 2021 primarily reflected: •$95.0 million of cash outflow for repayments on the Revolving Credit Facility; •$5.2 million of cash payments related to debt issuance costs; and •partially offset by$53.5 million from borrowings under the Permian Transmission Credit Facility. Cash flows used in financing activities during the six months endedJune 30, 2020 primarily reflected: •$56.0 million of net borrowings under our Revolving Credit Facility; 40 -------------------------------------------------------------------------------- Table of Contents •$48.7 million of net proceeds from the issuance of Subsidiary Series A Preferred Units; •$35.0 million of net borrowings under ECP Loans; •$76.7 million repurchase of Senior Notes; •$41.8 million to purchase common units in the GP Buy-In Transaction; and •$6.0 million of distributions to noncontrolling interest SMLP unitholders. Contractual Obligations Update We are leading the development, permitting and construction of theDouble E Project and will operate the pipeline upon its commissioning. At our current 70% interest, we estimate that our share of the capital expenditures required to develop theDouble E Project will total approximately$300.0 million . Assuming timely receipt of the required regulatory approvals and no material delays in construction, we expect that theDouble E Project will be placed into service in the fourth quarter of 2021. OnMarch 8, 2021 , we entered into the Permian Transmission Credit Facility to finance the vast majority of our remaining capital calls associated with theDouble E Project , debt services and other general corporate purposes. OnAugust 4, 2021 , the Partnership and several of its subsidiaries entered into the Global Settlement to resolve the legal matters resulting from the 2015 Blacktail Release. As a result, the Partnership increased its loss contingency for the 2015 Blacktail Release during the quarterly reporting period endingJune 30, 2021 by$19.3 million , resulting in an accrued loss liability for this matter atJune 30, 2021 of$36.3 million . Key financial terms of the Global Settlement include payment of penalties and fines totaling$36.3 million over six years, with interest applied to unpaid amounts and$3.1 million owed within the next twelve months. Between 2021 and 2027, the Partnership expects to make payments of principal and interest of$3.1 million ,$5.4 million ,$7.2 million ,$7.1 million ,$7.0 million ,$6.8 million , and$1.7 million , respectively, in connection with the penalties and fines included in the Global Settlement. We believe that the Global Settlement will have minimal impact on the Partnership's strategic plans or day-to-day operations due to the ability to pay fines and penalties over multiple years and expected manageable size of installments. See Part II. Item 1. "Legal Proceedings" in this report for additional information. Capital Requirements Our business is capital intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our Partnership Agreement requires that we categorize our capital expenditures as either: •maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or •expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. For the six months endedJune 30, 2021 , cash paid for capital expenditures totaled$6.0 million which included$2.1 million of maintenance capital expenditures. For the six months endedJune 30, 2021 , there were no contributions to Ohio Gathering and we contributed$48.9 million toDouble E (see Note 5 - Equity Method Investments). We expect 2021 total capital expenditures to range from$20.0 million to$35.0 million . We rely primarily on internally generated cash flow as well as external financing sources, including commercial bank borrowings and the issuance of debt, equity and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures. We believe that our Revolving Credit Facility and Permian Transmission Credit Facility, together with internally generated cash flow and access to debt or equity capital markets, will be adequate to finance our operations for the next twelve months without adversely impacting our liquidity. Our Revolving Credit Facility became current onMay 13, 2021 . We are in the process of negotiating the ABL Revolver that will be conditioned on the High Yield Notes Offering. It is our goal to consummate both financings concurrently during the quarter endingSeptember 30, 2021 . The proceeds of the ABL Revolver and the High Yield Notes Offering would be used to repay the Revolving Credit Facility and redeem the 2022 Senior Notes. However, there can be no assurance that we will be able to arrange an ABL Revolver or consummate the High Yield Notes Offering on terms acceptable to us prior toSeptember 30, 2021 or at all. Considering the current commodity price backdrop and continued uncertainty regarding impacts from the COVID-19 pandemic, we will remain disciplined with respect to future capital expenditures, which will be primarily concentrated on accretive bolt-on opportunities of our existing systems in our Core Focus Areas. 41 -------------------------------------------------------------------------------- Table of Contents There are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach new commercial agreements with third parties and (ii) prevailing conditions and outlook in the natural gas, crude oil and NGLs and markets. Credit and Counterparty Concentration Risks We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. Certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customers' wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers' commodities flow and, in many cases, the only way for our customers to get their production to market. We have exposure due to nonperformance under our MVC contracts whereby a potential customer, may not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period. Off-Balance Sheet Arrangements During the six months endedJune 30, 2021 , there were no material changes to the off-balance sheet obligations disclosed in our 2020 Annual Report other than the existence of a wholly owned marketing subsidiary's ten-year firm transportation agreement withDouble E , an equity method investment of the Partnership, that will be utilized to advantageously market natural gas for the Partnership and its customers in and around our assets in thePermian Basin . The agreement becomes effective upon the in-service date of theDouble E Project and requires the Partnership to payDouble E on average$3.1 million per year, over the next ten years, for access to firm transportation on theDouble E Project pipeline. Summarized Financial Information The supplemental summarized financial information below reflects SMLP's separate accounts, the combined accounts of theSummit Holdings andFinance Corp. (together, the "Co-Issuers") and its guarantor subsidiaries (the "Guarantor Subsidiaries" and together with the Co-Issuers, the "Obligor Group ") for the dates and periods indicated. The financial information of theObligor Group is presented on a combined basis and intercompany balances and transactions between the Co-Issuers and Guarantor Subsidiaries have been eliminated. There were no reportable transactions between theCo-Issuers and Obligor Group and the subsidiaries that were not issuers or guarantors of the Senior Notes. Payments to holders of the Senior Notes are affected by the composition of and relationships among the Co-Issuers, the Guarantor Subsidiaries and PermianHoldco and Summit Permian Transmission, both of which are unrestricted subsidiaries of SMLP and are not issuers or guarantors of the Senior Notes. The assets of our unrestricted subsidiaries are not available to satisfy the demands of the holders of the Senior Notes. In addition, our unrestricted subsidiaries are subject to certain contractual restrictions related to the payment of dividends, and other rights in favor of their non-affiliated stakeholders, that limit their ability to satisfy the demands of the holders of the Senior Notes. A list of each of SMLP's subsidiaries that is a guarantor, issuer or co-issuer of our registered securities subject to the reporting requirements in Release 33-10762 is filed as Exhibit 22.1 to this report. Summarized Balance Sheet Information. Summarized balance sheet information as ofJune 30, 2021 andDecember 31, 2020 follow. 42
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Table of Contents
June 30, 2021
SMLP Obligor Group
(In thousands)
Assets
Current assets $ 3,156 $ 74,542
Noncurrent assets 5,561 2,207,593
Liabilities
Current liabilities $ 26,491 $ 814,684
Noncurrent liabilities 35,537 538,339
December 31, 2020
SMLP Obligor Group
(In thousands)
Assets
Current assets $ 2,265 $ 78,304
Noncurrent assets 6,952 2,277,807
Liabilities
Current liabilities $ 13,339 $ 50,192
Noncurrent liabilities 19,987 1,398,872
Summarized Statements of Operations Information. For the purposes of the
following summarized statements of operations, we allocate a portion of general
and administrative expenses recognized at the SMLP parent to the Obligor Group
to reflect what those entities' results would have been had they operated on a
stand-alone basis. Summarized statements of operations for the three months
ended June 30, 2021 and for the year ended December 31, 2020 follow.
Six Months Ended June 30, 2021
SMLP Obligor Group
(In thousands)
Total revenues $ - $ 199,359
Total costs and expenses 20,669 149,152
Income (loss) before income taxes and income from
equity method investees (34,298) 21,213
Income from equity method investees $ - $ 5,765
Net income (loss) (34,036) 26,978
Year Ended December 31, 2020
SMLP Obligor Group
(In thousands)
Total revenues $ - $ 383,473
Total costs and expenses 26,169 302,989
Income (loss) before income taxes and loss from
equity method investees (26,000) 122,108
Income from equity method investees - 13,073
Net income (loss) $
(26,016)
Critical Accounting Estimates We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. There have been no changes to our significant accounting policies sinceDecember 31, 2020 . 43 -------------------------------------------------------------------------------- Table of Contents Forward-Looking Statements Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officers and employees during our presentations are "forward-looking" statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words "expect," "intend," "plan," "anticipate," "estimate," "believe," "will be," "will continue," "will likely result," and similar expressions, or future conditional verbs such as "may," "will," "should," "would," and "could." In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us or our subsidiaries are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this report. Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph. These risks and uncertainties include, among others: •our decision whether to pay, or our ability to grow, our cash distributions; •fluctuations in natural gas, NGLs and crude oil prices, including as a result of political or economic measures taken by various countries orOPEC ; •the extent and success of our customers' drilling efforts, as well as the quantity of natural gas, crude oil and produced water volumes produced within proximity of our assets; •the current and potential future impact of the COVID-19 pandemic on our business, results of operations, financial position or cash flows; •failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects; •competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems; •actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers; •our ability to divest of certain of our assets to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets; •the ability to attract and retain key management personnel; •commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets; •changes in the availability and cost of capital and the results of our financing efforts, including availability of funds in the credit and/or capital markets; •our ability to refinance near-term maturities on favorable terms or at all and the related impact on our ability to continue as a going concern; •restrictions placed on us by the agreements governing our debt and preferred equity instruments; •the availability, terms and cost of downstream transportation and processing services; •natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control; •operational risks and hazards inherent in the gathering, compression, treating and/or processing of natural gas, crude oil and produced water; •our ability to comply with the terms of the agreements comprising the Global Settlement (as defined herein), which is still subject to court approval; •weather conditions and terrain in certain areas in which we operate; 44 -------------------------------------------------------------------------------- Table of Contents •any other issues that can result in deficiencies in the design, installation or operation of our gathering, compression, treating and processing facilities; •timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule; •our ability to finance our obligations related to capital expenditures, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results; •the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation; •changes in tax status; •the effects of litigation; •changes in general economic conditions; and •certain factors discussed elsewhere in this report. Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common units, preferred units and senior notes. The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law. Information About Us Investors should note that we make available, free of charge on our website at www.summitmidstream.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, theSEC . We also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. We may use the Investors section of our website to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. Documents and information on our website are not incorporated by reference herein. TheSEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with theSEC . 45
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