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Dynamic quotes 
OFFON

SUMMIT MIDSTREAM PARTNERS, LP

(SMLP)
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SUMMIT MIDSTREAM PARTNERS LP : Management's Discussion and Analysis of Financial Condition and Results of Operations. (form 10-Q)

05/07/2021 | 04:02pm EDT

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 months ended March 31, 2021, these additional activities accounted for approximately 21% of total revenues.

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 Months Ended March 31, 2021 and 2020" section
included herein.

                                                         Three Months Ended March 31,
                                                          2021                  2020
                                                                (In thousands)
Net income                                           $         8,988       $        3,762
Reportable segment adjusted EBITDA
Utica Shale                                          $         7,719       $        5,928
Ohio Gathering                                                 6,872                7,939
Williston Basin                                               10,805               16,192
DJ Basin                                                       5,347                5,911
Permian Basin                                                    709                1,581
Piceance Basin                                                21,034               23,557
Barnett Shale                                                  8,016                8,760
Marcellus Shale                                                5,602                5,320

Net cash provided by operating activities            $        51,430       $       70,201
Capital expenditures(1)                                        2,610               18,583
Investment in Double E equity method investee                  5,619               58,033

Net cash distributions to noncontrolling interest

  SMLP unitholders                                   $             -       $        6,037

Net borrowings under Revolving

  Credit Facility                                                  -               21,000
Repayments on Revolving Credit Facility                      (55,000 )                  -
Borrowings under Permian Transmission Credit
Facility                                                      17,500                    -
Repayments on SMPH term loan                                       -                 (750 )
Proceeds from issuance of Subsidiary Series A
preferred units,
  net of issuance costs                                            -               33,946


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



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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 reduced 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 reduced demand and prices for oil. We are closely monitoring the impact of the COVID-19 pandemic on all aspects of our business, including how it has impacted and will impact our customers, 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, 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, there were also volatile oil prices during 2020 largely due to a 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 2020 development plans from our customers, we currently expect our 2021 results to continue to be affected by decreased drilling activity.

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 to our aggregate volume throughput during the quarterly period ended March 31, 2021. Some of the transactions completed by us during 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 unpreceded circumstances of the winter storm, which could affect our future earnings, cash flows and financial condition.

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.


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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 months ended March 31, 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.


                             Results of Operations

Consolidated Overview for the Three Months Ended March 31, 2021 and 2020

The following table presents certain consolidated financial and operating data.


                                                  Three Months Ended March 31,
                                                    2021                 2020
                                                         (In thousands)

Revenues:

Gathering services and related fees            $       70,348       $       83,792
Natural gas, NGLs and condensate sales                 20,763               13,780
Other revenues                                          8,207                7,331
Total revenues                                         99,318              104,903
Costs and expenses:
Cost of natural gas and NGLs                           20,476                8,225
Operation and maintenance                              16,593               21,811
General and administrative                             10,344               16,561
Depreciation and amortization                          28,511               29,666
Transaction costs                                           -                   11
(Gain) loss on asset sales, net                          (136 )                115
Long-lived asset impairment                             1,492                3,821
Total costs and expenses                               77,280               80,210
Other income (expense), net                                55                 (427 )
Interest expense                                      (13,953 )            (23,828 )
Loss on ECP Warrants and other                         (1,481 )                  -

Income before income taxes and

  equity method investment income                       6,659                  438
Income tax benefit                                         14                   13
Income from equity method investees                     2,315                3,311
Net income                                     $        8,988       $        3,762

Volume throughput (1):
Aggregate average daily throughput - natural
  gas (MMcf/d)                                          1,346                1,281

Aggregate average daily throughput - liquids

  (Mbbl/d)                                                 65                   98


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


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Volumes - Gas. Natural gas throughput volumes increased 65 MMcf/d for the three months ended March 31, 2021 compared to the three months ended March 31, 2020, primarily reflecting:

  • a volume throughput increase of 188 MMcf/d for the Utica Shale segment.


  • a volume throughput decrease of 43 MMcf/d for the Piceance Basin segment.


  • a volume throughput decrease of 38 MMcf/d for the Barnett Shale segment.


  • a volume throughput decrease of 27 MMcf/d for the Marcellus Shale segment.


  • a volume throughput decrease of 4 MMcf/d for the Permian Basin segment.

Volumes - Liquids. Crude oil and produced water throughput volumes at the Williston segment decreased 33 Mbbl/d for the three months ended March 31, 2021, compared to the three months ended March 31, 2020.

For additional information on volumes, see the "Segment Overview for the Three Months Ended March 31, 2021 and 2020" section herein.

Revenues. Total revenues decreased $5.6 million during the three months ended March 31, 2021 compared to the prior year period, primarily comprised of a $13.4 million decrease in gathering services and related fees offset by a $7.0 million increase in natural gas, NGLs and condensate sales.

Gathering Services and Related Fees. Gathering services and related fees decreased $13.4 million compared to the three months ended March 31, 2020, primarily reflecting:

   •  a $11.2 million decrease in gathering services and related fees in the
      Williston Basin due to lower volumes throughput primarily liquids 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.


   •  a $2.4 million decrease in gathering services and related fees in the
      Piceance Basin related to lower volume throughput due to a lack of drilling
      and completion activity and natural production declines.


   •  a $0.6 million decrease in gathering services and related fees in the DJ
      Basin primarily as a result of decreased volume throughput as the result of
      natural production declines and a decreased number of wells that came
      online.


   •  partially offset by a $1.6 million increase in gathering services and
      related fees in the Utica Shale as a result of the completion of new wells
      that came online in March 2021, partially offset by natural production
      declines on existing wells.

Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales increased $7.0 million compared to the three months ended March 31, 2020, primarily reflecting increased sales in the Williston Basin.

Costs and Expenses. Total costs and expenses decreased $2.9 million during the three months ended March 31, 2021 compared to the three months ended March 31, 2020.

Cost of Natural Gas and NGLs. Cost of natural gas and NGLs increased $12.3 million for the three months ended March 31, 2021 compared to the three months ended Mach 31, 2020, primarily driven by an increase in commodity prices.

Operation and Maintenance. Operation and maintenance expense decreased $5.2 million for the three months ended March 31, 2021 compared to the three months ended March 31, 2020, primarily due to a decrease in salaries and benefits costs associated with lower headcount from our cost-cutting initiatives and a decrease in general operating expenses.

General and Administrative. General and administrative expense decreased $6.2 million for the three months ended March 31, 2021 compared to the three months ended March 31, 2020, primarily due to 2020 having higher restructuring and deal costs as well as a 2021 decrease in salaries and benefits associated with lower headcount from our cost-cutting initiatives.

Depreciation and Amortization. Depreciation and amortization expense decreased $1.2 million for the three months ended March 31, 2021 compared to the three months ended March 31, 2020.


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Interest Expense. The decrease in interest expense for the three months ended March 31, 2021, compared to the three months ended March 31, 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 TL Restructuring that eliminated the Partnership's $155.2 SMPH Term Loan. The decrease in interest expense was partially offset by a higher outstanding balance on the Partnership's Revolving Credit Facility.

Long-lived asset impairment. For the three months ended March 31, 2021, long-lived asset impairments were primarily related to a $1.0 million charge for certain assets in the Piceance Basin.

Segment Overview for the Three Months Ended March 31, 2021 and 2020

Utica Shale. The Utica Shale reportable segment includes the Summit Utica system. Volume throughput for our Summit Utica system follows.


                                                       Utica Shale
                                       Three Months Ended March 31,
                                                                            Percentage
                                        2021                  2020            Change
Average daily throughput (MMcf/d)             410                   222        85%


Volume throughput increased compared to the three months ended March 31, 2020, as a result of the completion 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 reportable segment follows.

                                                        Utica Shale
                                        Three Months Ended March 31,
                                                                            Percentage
                                          2021                2020            Change
                                           (Dollars in thousands)
Revenues:

Gathering services and related fees $ 8,572 $ 6,962 23% Total revenues

                                8,572               6,962        23%
Costs and expenses:
Operation and maintenance                       778                 941       (17%)
General and administrative                       63                  88       (28%)
Depreciation and amortization                 1,927               1,927         -
Loss on asset sales, net                          -                  16         *
Total costs and expenses                      2,768               2,972        (7%)

Add:

Depreciation and amortization                 1,927               1,927

Adjustments related to capital

  reimbursement activity                        (12 )                (5 )
Loss on asset sales, net                          -                  16
Segment adjusted EBITDA               $       7,719       $       5,928        30%


________

* Not considered meaningful

Three months ended March 31, 2021. Segment adjusted EBITDA increased $1.8 million compared to the three months ended March 31, 2020 primarily as a result of the increased volume throughput described above.



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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 March 31,
                                                                            Percentage
                                        2021                  2020            Change
Average daily throughput (MMcf/d)             558                   610        (9%)


Volume throughput for the Ohio Gathering system decreased compared to the three months ended March 31, 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 March 31,
                                                                                    Percentage
                                                  2021                2020            Change
                                                   (Dollars in thousands)

Proportional adjusted EBITDA for equity

  method investees                            $       6,872       $       7,939        (13%)
Segment adjusted EBITDA                       $       6,872       $       7,939        (13%)


Segment adjusted EBITDA for equity method investees decreased $1.1 million compared to the three months ended March 31, 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 March 31,
                                                                               Percentage
                                           2021                   2020           Change

Aggregate average daily throughput -

  natural gas (MMcf/d)                        12                     14          (14%)

Aggregate average daily throughput -

  liquids (Mbbl/d)                            65                     98          (34%)


Natural gas. Natural gas volume throughput decreased compared to the three months ended March 31, 2020, primarily reflecting natural production declines.

Liquids. The decrease in liquids volume throughput compared to the three months ended March 31, 2020, is 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 March 31,
                                                                                     Percentage
                                                  2021                 2020            Change
                                                   (Dollars in thousands)
Revenues:

Gathering services and related fees $ 12,633 $ 23,797 (47%) Natural gas, NGLs and condensate sales

               12,227                4,324        183%
Other revenues                                        4,506                3,142         43%
Total revenues                                       29,366               31,263        (6%)
Costs and expenses:
Cost of natural gas and NGLs                         12,325                1,663        641%
Operation and maintenance                             4,924                6,722        (27%)
General and administrative                              354                  538        (34%)
Depreciation and amortization                         5,922                6,495        (9%)
(Gain) loss on asset sales, net                         (15 )                 49          *
Total costs and expenses                             23,510               15,467         52%

Add:

Depreciation and amortization                         5,922                6,495

Adjustments related to MVC

  shortfall payments                                      -               (5,665 )

Adjustments related to capital

  reimbursement activity                               (958 )               (483 )
(Gain) loss on asset sales, net                         (15 )                 49
Segment adjusted EBITDA                      $       10,805       $       16,192        (33%)


_______

* Not considered meaningful

Three months ended March 31, 2021. Segment adjusted EBITDA decreased $5.4 million compared to the three months ended March 31, 2020 primarily due to lower liquids volume throughput on our systems as previously discussed together with lower operating expenses associated with our 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 March 31,
                                                                   Percentage
                               2021                   2020           Change
Average daily throughput
  (MMcf/d)                           23                     32       (28%)

Volume throughput decreased compared to the three months ended March 31, 2020, primarily as a result of decreased volume throughput as the result of natural production declines and a decreased number of wells that came online during 2021.

Financial data for our DJ Basin reportable segment follows.

                                                             DJ Basin
                                           Three Months Ended March 31,
                                                                               Percentage
                                             2021                2020            Change
                                              (Dollars in thousands)
Revenues:

Gathering services and related fees $ 6,263 $ 6,855 (9%) Natural gas, NGLs and condensate sales

             110                  70        57%
Other revenues                                     704               1,034       (32%)
Total revenues                                   7,077               7,959       (11%)
Costs and expenses:
Cost of natural gas and NGLs                        17                   9         *
Operation and maintenance                        1,912               2,516       (24%)
General and administrative                         318                  82        288%
Depreciation and amortization                    1,551               1,527         2%
Gain on asset sales, net                            (2 )                 -         *
Long-lived asset impairment                         95               3,635         *
Total costs and expenses                         3,891               7,769       (50%)

Add:

Depreciation and amortization                    1,551               1,527

Adjustments related to capital

  reimbursement activity                           494                 559
Gain on asset sales, net                            (2 )                 -
Long-lived asset impairment                         95               3,635
Other                                               23                   -
Segment adjusted EBITDA                  $       5,347       $       5,911       (10%)


________

* Not considered meaningful

Three months ended March 31, 2021. Segment adjusted EBITDA decreased $0.6 million compared to the three months ended March 31, 2020, primarily due to lower volumes associated with natural declines, partially offset by lower operating expenses associated with our cost-cutting initiatives and lower general operating expenses.




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Permian Basin. The Summit Permian system provides our midstream services for the
Permian Basin reportable segment. Volume throughput for our Permian Basin
reportable segment follows.

                                                      Permian Basin
                                       Three Months Ended March 31,
                                                                            Percentage
                                        2021                   2020           Change
Average daily throughput (MMcf/d)             29                     33       (12%)


Volume throughput decreased compared to the three months ended March 31, 2020, primarily as a result of natural production declines from wells previously put in service.

Financial data for our Permian Basin reportable segment follows.

                                                          Permian Basin
                                           Three Months Ended March 31,
                                                                               Percentage
                                             2021                2020            Change
                                              (Dollars in thousands)
Revenues:

Gathering services and related fees $ 2,199 $ 2,311 (5%) Natural gas, NGLs and condensate sales

           6,518               4,512        44%
Other revenues                                     116                 187       (38%)
Total revenues                                   8,833               7,010        26%
Costs and expenses:
Cost of natural gas and NGLs                     7,016               4,149        69%
Operation and maintenance                          992               1,187       (16%)
General and administrative                         116                  93        25%
Depreciation and amortization                    1,469               1,345         9%
Loss on asset sales, net                             -                   4         *
Long-lived asset impairment                          -                 182         *
Total costs and expenses                         9,593               6,960        38%
Add:
Depreciation and amortization                    1,469               1,345
Loss on asset sales, net                             -                   4
Long-lived asset impairment                          -                 182
Segment adjusted EBITDA                  $         709       $       1,581         *


________

*Not considered meaningful

Three months ended March 31, 2021. Segment adjusted EBITDA decreased $0.9 million compared to the three months ended March 31, 2020, primarily reflecting an increase in the cost of natural gas and NGLs partially offset by increased sales of natural gas, NGLs and condensate.



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Piceance Basin. The Grand River system provides midstream services for the
Piceance Basin reportable segment. Volume throughput for our Piceance Basin
reportable segment follows.

                                                       Piceance Basin
                                        Three Months Ended March 31,
                                                                             Percentage
                                         2021                  2020            Change

Aggregate average daily throughput

  (MMcf/d)                                     340                   383       (11%)


Volume throughput decreased compared to the three months ended March 31, 2020, primarily as a result of natural production declines.

Financial data for our Piceance Basin reportable segment follows.



                                                        Piceance Basin
                                         Three Months Ended March 31,
                                                                              Percentage
                                           2021                 2020            Change
                                            (Dollars in thousands)
Revenues:

Gathering services and related fees $ 24,784 $ 27,189 (9%) Natural gas, NGLs and condensate

  sales                                        1,853                1,003        85%
Other revenues                                 1,177                1,065        11%
Total revenues                                27,814               29,257        (5%)
Costs and expenses:
Cost of natural gas and NGLs                   1,119                  457        145%
Operation and maintenance                      4,942                4,938         0%
General and administrative                       298                  285         5%
Depreciation and amortization                 10,873               11,298        (4%)
Gain on asset sales, net                         (57 )                (13 )       *
Long-lived asset impairment                      970                    -         *
Total costs and expenses                      18,145               16,965         7%

Add:

Depreciation and amortization                 10,873               11,298

Adjustments related to MVC

  shortfall payments                               -                  223

Adjustments related to capital

  reimbursement activity                        (427 )               (243 )
Gain on asset sales, net                         (57 )                (13 )
Long-lived asset impairment                      970                    -
Other                                              6                    -
Segment adjusted EBITDA               $       21,034       $       23,557       (11%)


________

*Not considered meaningful

Three months ended March 31, 2021. Segment adjusted EBITDA decreased $2.5 million compared to the three months ended March 31, 2020, primarily reflecting a $2.4 million decrease in gathering services and related fees as a result of natural production declines as discussed above.



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Barnett Shale. The DFW Midstream system provides our midstream services for the
Barnett Shale reportable segment. Volume throughput for our Barnett Shale
reportable segment follows.

                                                      Barnett Shale
                                       Three Months Ended March 31,
                                                                            Percentage
                                        2021                  2020            Change
Average daily throughput (MMcf/d)             195                   233       (16%)


Volume throughput decreased compared to the three months ended March 31, 2020 reflecting natural production declines, partially offset by workovers and recompletions.

Financial data for our Barnett Shale reportable segment follows.

                                                                Barnett Shale
                                                Three Months Ended March 31,
                                                                                     Percentage
                                                  2021                 2020            Change
                                                   (Dollars in thousands)
Revenues:

Gathering services and related fees $ 9,696 $ 10,443 (7%) Natural gas, NGLs and condensate sales

                   55                3,871        (99%)
Other revenues (1)                                    1,061                1,260        (16%)
Total revenues                                       10,812               15,574        (31%)
Costs and expenses:
Cost of natural gas and NGLs                              -                1,947       (100%)
Operation and maintenance                             2,464                4,695        (48%)
General and administrative                              235                  378        (38%)
Depreciation and amortization                         3,797                3,797          -
Loss on asset sales, net                                  -                   59          *
Long-lived asset impairment                             289                    4          *
Total costs and expenses                              6,785               10,880        (38%)

Add:

Depreciation and amortization                         4,031                4,032

Adjustments related to capital

  reimbursement activity                               (331 )                (29 )
Loss on asset sales, net                                  -                   59
Long-lived asset impairment                             289                    4
Segment adjusted EBITDA                      $        8,016       $        8,760        (8%)


________

*Not considered meaningful

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

Three months ended March 31, 2021. Segment adjusted EBITDA decreased $0.7 million compared to the three months ended March 31, 2020 with lower volume throughput partially offset by lower operating expenses associated with our cost-cutting initiatives and lower general operating expenses, including lower compression operating costs.



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Marcellus Shale. The Mountaineer Midstream system provides our midstream services for the Marcellus Shale reportable segment. Volume throughput for the Marcellus Shale reportable segment follows.


                                                     Marcellus Shale
                                       Three Months Ended March 31,
                                                                            Percentage
                                        2021                  2020            Change
Average daily throughput (MMcf/d)             337                   364        (7%)


Volume throughput decreased compared to the three months ended March 31, 2020 primarily due to natural production declines.

Financial data for our Marcellus Shale reportable segment follows.



                                                      Marcellus Shale
                                        Three Months Ended March 31,
                                                                            Percentage
                                          2021                2020            Change
                                           (Dollars in thousands)
Revenues:

Gathering services and related fees $ 6,201 $ 6,235 (1%) Total revenues

                                6,201               6,235        (1%)
Costs and expenses:
Operation and maintenance                       502                 813       (38%)
General and administrative                       88                  93        (5%)
Depreciation and amortization                 2,304               2,300         0%
Gain on asset sales, net                        (62 )                 -         *
Long-lived asset impairment                     138                   -         *
Total costs and expenses                      2,970               3,206        (7%)

Add:

Depreciation and amortization                 2,304               2,300

Adjustments related to capital

  reimbursement activity                         (9 )                (9 )
Gain on asset sales, net                        (62 )                 -
Long-lived asset impairment                     138                   -
Segment adjusted EBITDA               $       5,602       $       5,320         5%


________

*Not considered meaningful

Three months ended March 31, 2021. Segment adjusted EBITDA increased $0.3 million compared to the three months ended March 31, 2020, with lower volume throughput partially offset by lower operating expenses associated with our cost-cutting initiatives and lower general operating expenses.




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Corporate and Other Overview for the Three Months Ended March 31, 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 the Double E Project, transaction costs and interest expense.

                                                Corporate and Other
                                    Three Months Ended March 31,
                                                                         Percentage
                                      2021                 2020            Change
                                               (Dollars in thousands)
Revenues:
Total revenues                   $          643       $          643         -
Costs and expenses:
Operation and maintenance                    79                    -         *
General and administrative                8,873               15,004       (41%)
Transaction costs                             -                   11       (100%)
Interest expense                         13,953               23,828       (41%)
Loss on ECP Warrants and other            1,481                    -


________

* Not considered meaningful

Total Revenues. Total revenues attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services (primarily natural gas sales).

General and Administrative. General and administrative expense decreased $6.1 million compared to the three months ended March 31, 2020, primarily as a result of 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 cost-cutting initiatives.

Interest Expense. The decrease in interest expense for the three months ended March 31, 2021, compared to the three months ended March 31, 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 SMPH Term Loan. The decrease in interest expense was partially offset by a higher outstanding balance on the Partnership's Revolving Credit Facility.




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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 since March 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 the Williston Basin, DJ Basin and Utica 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. We are actively managing the business to maintain cash flow and we have sufficient available liquidity. We believe that these factors will allow us to meet our anticipated funding requirements.

Indebtedness Compliance. We are currently in compliance with all covenants contained in the Revolving Credit Facility, 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 3.1 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 ended March 31, 2021. Given further deterioration of market conditions, 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 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.

2022 Maturities. We are actively pursuing opportunities to refinance our Revolving Credit Facility and our 2022 Senior Notes. If the Revolving Credit Facility is not refinanced to extend its May 13, 2022 maturity date prior to the release of our financial statements for the quarterly period ended June 30, 2021, any current amount outstanding under the Revolving Credit Facility will be required to be included in our going concern assessment under FAS ASC 205-40, Going Concern.

Credit Arrangements and Financing Activities

Revolving Credit Facility. We have a $1.1 billion senior secured Revolving Credit Facility that matures on May 13, 2022. As of March 31, 2021, the outstanding balance of the Revolving Credit Facility was $802.0 million and the unused portion totaled $275.9 million, after giving effect to the issuance thereunder of $22.1 million of outstanding but undrawn irrevocable standby letters of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility, as of March 31, 2021, was approximately $115.0 million. There were no defaults or events of default during the three months ended March 31, 2021, and, as of March 31, 2021, we were in compliance with the financial covenants in the Revolving Credit Facility.

Permian Transmission Credit Facility. On March 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 of March 31, 2021, the outstanding balance of the Permian Transmission Credit Facility was $17.5 million, and the unused portion totaled $157.5 million. Our available borrowing capacity under the Permian Transmission Credit Facility as of March 31, 2021 was approximately $155.5 million. There were no defaults or events of default during the three months ended March 31, 2021, and, as of March 31, 2021, we were in compliance with the financial covenants in the Permian Transmission Credit Facility.

Exchange Offer. In March 2021, we commenced the 2021 Exchange Offer. On April 15, 2021, we completed the Exchange Offer and accepted 18,662 Series A Preferred Units and exchanged those units for 538,715 SMLP common units, net of units withheld for withholding taxes.

We may 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


                                       35

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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, the United Kingdom's Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of large U.S. financial institutions, is considering replacing U.S. dollar LIBOR with a new index, the Secured Overnight Financing Rate ("SOFR"), calculated using short-term repurchase agreements backed by Treasury securities. We are 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. 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:


                                                              Three Months Ended March 31,
                                                                2021                 2020
                                                                     (In thousands)
Net cash provided by operating activities                  $       51,430       $       70,201
Net cash used in investing activities                                (229 )            (76,399 )
Net cash provided by (used in) financing activities               (42,445 )             46,657

Net change in cash, cash equivalents and restricted cash $ 8,756 $ 40,459

Operating activities.

Cash flows provided by operating activities for the three months ended March 31, 2021 primarily reflected:

   •  net income of $9.0 million plus adjustments of $39.5 million for non-cash
      items; and


  • $2.9 million increase in working capital accounts.



Cash flows provided by operating activities for the three months ended March 31, 2020 primarily reflected:



   •  a $13.8 million increase in accounts receivable related to the timing of
      invoicing and cash collections;


   •  a $3.7 million increase in accounts payable due to the timing of payment
      obligations; and


   •  a $2.8 million increase in deferred revenue for cash receipts not yet
      recognized as revenue.


Investing activities.

Cash flows used in investing activities during the three months ended March 31, 2021 primarily reflected:

$5.6 million for investments in the Double E joint venture relating to the
      Double E Project;


  • $2.6 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 three months ended March 31, 2020 primarily reflected:

$58.0 million for investments in the Double E joint venture relating to the
      Double E Project; and;


   •  $18.6 million of capital expenditures primarily attributable to the DJ Basin
      of $6.3 million, the Williston Basin of $4.9 million and Summit Permian of
      $3.3 million.


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Financing activities.

Cash flows used in financing activities during the three months ended March 31, 2021 primarily reflected:

$55.0 million of cash outflow for repayments on the Revolving Credit
      Facility;


  • $4.9 million of cash payments related to debt issuance costs;


   •  partially offset by $17.5 million from borrowings under the Permian
      Transmission Credit Facility.

Cash flows used in financing activities during the three months ended March 31, 2020 primarily reflected:

$33.9 million of net proceeds from the issuance of Subsidiary Series A
      Preferred Units


  • $21.0 million of net borrowings under our Revolving Credit Facility; and


  • $6.0 million of distributions.

Contractual Obligations Update

We are leading the development, permitting and construction of the Double 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 the Double 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 the Double E Project will be placed into service in the fourth quarter of 2021. On March 8, 2021, we entered into the Permian Transmission Credit Facility to finance capital calls associated with the Double E Project, debt services and other general corporate purposes.

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 three months ended March 31, 2021, cash paid for capital expenditures totaled $2.6 million which included $0.9 million of maintenance capital expenditures. For the three months ended March 31, 2021, there were no contributions to Ohio Gathering and we contributed $5.6 million to Double E (see Note 5 - Equity Method Investments).

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 business for the next twelve months without adversely impacting our liquidity. Our Revolving Credit Facility and 2022 Senior Notes become current on May 13, 2021 and August 15, 2021, respectively. We continue to explore multiple alternatives to address these near-term maturities. If we are unable to refinance these debts, our ability to continue as a going concern may be materially and adversely affected in future periods.

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. In March 2021, we secured the Permian Transmission Credit Facility which will be used to finance our portion of capital calls associated with the Double E Project.

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 agreements with third parties and (ii) prevailing conditions and outlook in the natural gas, crude oil and NGLs and markets.


                                       37

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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

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. During the three months ended March 31,2020, there were no material changes to the off-balance sheet obligations disclosed in our 2020 Annual Report.

Summarized Financial Information

The supplemental summarized financial information below reflects SMLP's separate accounts, the combined accounts of the Co-Issuers and the Guarantor Subsidiaries (the Co-Issuers and, together with the Guarantor Subsidiaries, the "Obligor Group") for the dates and periods indicated. The financial information of the Obligor 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 the Co-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, Permian Holdco 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 Quarterly Report on Form 10-Q.

Summarized Balance Sheet Information. Summarized balance sheet information as of March 31, 2021 and December 31, 2020 follow.

                                March 31, 2021
                           SMLP        Obligor Group
                                (In thousands)
Assets
Current assets           $  2,622     $        77,829
Noncurrent assets           6,257           2,237,430

Liabilities
Current liabilities      $ 10,107     $        59,921
Noncurrent liabilities     19,861           1,343,355




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                               December 31, 2020
                           SMLP         Obligor Group
                                (In thousands)
Assets
Current assets           $   2,311     $       109,664
Noncurrent assets            9,572           2,389,032

Liabilities
Current liabilities      $   9,662     $        73,877
Noncurrent liabilities     184,088           1,514,250



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 March 31, 2021 and for the year ended December 31, 2020 follow.

                                                         Three Months Ended March 31, 2021
                                                          SMLP                  Obligor Group
                                                                  (In thousands)
Total revenues                                      $               -         $          99,318
Total costs and expenses                                            -                    77,420

Income (loss) before income taxes and income from

 equity method investees                                       (1,456 )                   8,052
Income from equity method investees                                 -                     2,811
Net income (loss)                                   $          (1,442 )       $          10,863




                                                     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
Loss from equity method investees                              -               13,073
Net income (loss)                                 $      (26,016 )     $      135,181




Critical Accounting Estimates

We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. There have been no changes to our significant accounting policies since December 31, 2020.

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


                                       39

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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 or OPEC;


   •  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;


   •  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;


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


   •  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.


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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, the SEC. 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.

The SEC 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 the SEC.

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