SUMMIT MIDSTREAM PARTNERS, LP MD&A is intended to inform the reader about matters affecting the financial condition and results of operations of the Partnership and its subsidiaries. As a result, the following discussion for the year endedDecember 31, 2020 should be read in conjunction with the consolidated financial statements and notes thereto included in this Annual Report. Among other things, the consolidated 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. The discussion of our financial condition and results of operations for the years endedDecember 31, 2019 andDecember 31, 2018 included in Exhibit 99.2, Updated 2019 Annual Report on Form 10-K - Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, of our Form 8-K datedAugust 7, 2020 , is incorporated by reference into this MD&A. 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
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
Williston Basin ,DJ Basin andPermian 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
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 year ended December 31, 2020 , these
additional activities accounted for approximately 13% 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.
70--------------------------------------------------------------------------------
Table of Contents
The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the "Segment Overview for the Years EndedDecember 31, 2020 and 2019" section herein. Year ended December 31, 2020 2019 (In thousands) Net income (loss)$ 189,078 $ (393,726 ) Reportable segment adjusted EBITDA Utica Shale$ 32,783 $ 29,292 Ohio Gathering 31,056 39,126 Williston Basin 52,060 69,437 DJ Basin 19,449 18,668 Permian Basin 4,426 (879 ) Piceance Basin 88,820 98,765 Barnett Shale 32,093 43,043 Marcellus Shale 22,015 20,051 Net cash provided by operating activities$ 198,589 $
161,741
Capital expenditures(1) 43,128
182,291
Investment inDouble E equity method investee 99,927
18,316
Net cash distributions to noncontrolling interest
SMLP unitholders$ 6,037 $
68,874
Series A Preferred Unit distributions -
28,500
Net borrowings under Revolving
Credit Facility 180,000
211,000
Repayments on SMPH term loan (6,300 ) (65,250 ) Open Market Repurchases of 2022 and 2025 Senior Notes (Note 9) (145,567 )
-
Tender Offers of 2022 and 2025 Senior Notes (Note 9) (47,530 )
-
TL Restructuring (Note 9) (26,500 )
-
Proceeds from issuance of Subsidiary Series A preferred units, net of issuance costs 48,710 27,392 Preferred Tender (Note 9) (25,000 ) -
Purchase of common units in GP Buy-In
Transaction (41,778 ) -
(1) See "Liquidity and Capital Resources" herein and Note 20 to the consolidated financial statements for additional information on capital expenditures.
71--------------------------------------------------------------------------------
Table of Contents
• GP Buy-In Transaction. In
Transaction whereby the Partnership acquired from its then private equity
sponsor, ECP, (i) Summit Investments, which indirectly owned the
Partnership's
3,415,646 of its common units and (iii) a deferred purchase price obligation
receivable owed by the Partnership. Consideration paid to ECP included a
units. In connection with the closing of the GP Buy-In Transaction, ECP's
management resigned from the Board of Directors and fully exited its
investment in the Partnership (other than retaining the aforementioned
warrants). Refer to Note 1 - Organization, Business Operations and
Presentation and Consolidation for details.
• Suspension of common and preferred unit distributions. In
conjunction with the GP Buy-In Transaction, the Partnership suspended
distributions to holders of its common units and its Series A Preferred
Units, commencing with respect to the quarter ending
suspension of distributions enabled the Partnership to retain an incremental
cash to indebtedness reduction, liability management transactions and other
corporate initiatives. The unpaid cash distributions on the Series A
Preferred Units continue to accrue semi-annually, until paid.
•
completed the Preferred Exchange Offer, whereby it issued 837,547 SMLP
common units in exchange for 62,816 Series A Preferred Units. Upon closing
the Preferred Exchange Offer, it eliminated
Preferred Unit liquidation preference amount, inclusive of
accrued distributions due as of the settlement date.
• Open Market Repurchase of Senior Notes. Throughout 2020, the Partnership
completed its Open Market Repurchases, which resulted in the extinguishment
of
of face value of the 2025 Senior Notes. Total cash consideration paid to
repurchase the principal amounts outstanding of the 2022 Senior Notes and
2025 Senior Notes, plus accrued interest totaled $150.3 million and the
Partnership recognized a $86.4 million gain on the extinguishment of debt
related to these Open Market Repurchases during 2020.
• Debt Tender Offers. In
Tender Offers to purchase a portion of their 2022 Senior Notes and 2025
Senior Notes. Upon completion of the Debt Tender Offers, the Co-Issuers
repurchased $33.5 million principal amount of the 2022 Senior Notes
and $38.7 million principal amount of the 2025 Senior Notes. Total cash
consideration paid to repurchase the principal amounts outstanding of the
2022 and 2025 Senior Notes, plus accrued interest, totaled
and the Partnership recognized a
debt related to the Debt Tender Offers during 2020.
• TL Restructuring. InNovember 2020 , the Partnership completed the TL Restructuring. All of the Term Loan Lenders participated in the TL Restructuring. As part of the TL Restructuring, the Partnership paid SMP
Holdings
purchase price obligation, which
Lenders. In addition, the Term Loan Lenders executed the Strict Foreclosure
on the 2,306,972 common units pledged as collateral under the SMPH Term Loan
in full satisfaction of
Term Loan.
•
Partnership completed the Preferred Tender Offer, whereby it accepted 75,075
Series A Preferred Units for a purchase price of $333.00 per Series A
Preferred Unit and an aggregate purchase price of $25.0 million . Upon
closing the Preferred Tender Offer, it eliminated $82.7 million of theSeries A Preferred Unit liquidation preference due as of the settlement
date, inclusive of
•
proportionate share of capital calls due in 2020 totaled
which includes
million of Subsidiary Series A Preferred Units.
• 2020 Restructuring Costs. In the fourth quarter of 2020, we completed an
internal initiative to evaluate and transform our cost structure, enhance
margins and improve our competitive position in response to COVID-19 and the
related weakening of the economy. For the year ended
incurred approximately
initiative (included in general and administrative expense).
72
--------------------------------------------------------------------------------
Table of Contents
• 2020 Impairments. In the fourth quarter of 2020, we recorded
impairments related to certain long-lived assets, of which
related to a January 2021 sale of compressor equipment for a total cash
purchase price of $8.0 million .
• Equity Method Investment Impairment. In
triggering events which indicated that our equity method investment in
Gathering could be impaired. We completed an other-than-temporary impairment
analysis to determine the potential equity method impairment charge to be
recorded on our consolidated financial statements. As a result, an
impairment charge of approximately
from equity method investees caption on the consolidated statement of
operations.
• Goodwill Impairment. In
impairment evaluation, we determined that the fair value of the Mountaineer
Midstream reporting unit did not exceed its carrying value and we recognized
a goodwill impairment charge of
• Disposition. In
indicated that certain long-lived assets in the
reporting segments could be impaired. Consequently, we performed a
recoverability assessment of certain assets within these reporting segments.
In the
our 20 MMcf/d plant would no longer be operational due to our expansion
plans for the Niobrara G&P system and we recorded an impairment charge of
certain compressor station assets would be shut down and de-commissioned and
we recorded an impairment charge of
•
Project after securing firm 10-year commitments under binding precedent
agreements for a substantial majority of the pipeline's initial throughput
capacity of 1.35 Bcf of gas per day and executing the joint venture
agreement (described below) with an affiliate of
shipper.
mainline and related facilities, will provide interstate natural gas
transportation service from the Delaware Basin production area to the Waha
Hub in Texas .
• Summit Permian Transmission. In connection with the
Permian Transmission contributed total assets of approximately
for a 70% ownership interest in
• Double E Financing. In
subsidiary of SMLP that indirectly owns SMLP's 70% interest in
connection with the formation of Permian Holdco, we entered into an
agreement with
2019 to fund up to
associated with the
Permian
net proceeds of
• Red Rock. In
SMLP (collectively, "the Red Rock Parties") entered into a Purchase and Sale
Agreement (the "Red Rock PSA") pursuant to which the Red Rock Parties agreed
to sell certain
of
impairment charge of
the carrying value for the
2019, we closed the Red
Long-lived asset impairment caption on the consolidated statement of
operations. The financial contribution of these assets (a component of the
Piceance Basin reportable segment) are included in our consolidated financial statements and footnotes for the period fromJanuary 1, 2019 throughDecember 1, 2019 .
• Tioga Midstream. Until
oil, produced water and associated natural gas gathering system in the
affiliates of
price of approximately
million based on the difference between the consideration received and the
carrying value for Tioga Midstream at closing. The gain is included in the
Gain on asset sales, net caption on the consolidated statement of
operations. The financial results of Tioga Midstream (a component of the
Williston Basin reportable segment) are included in our consolidatedfinancial statements and footnotes for the historical periods through March
22, 2019. Refer to Note 18 to the consolidated financial statements for
details on the sale of Tioga Midstream.
73
--------------------------------------------------------------------------------
Table of Contents
• 2019 Restructuring Costs. In the third quarter of 2019, we began an internal
initiative to evaluate and transform our cost structure, enhance margins and
improve our competitive position in response to a weakening commodity price
backdrop. For the year ended
general and administrative expense). For the year ended
we incurred an additional
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.
Ongoing impact of the COVID-19 pandemic and reduced demand and prices for oil. We are closely monitoring the impact of the outbreak of COVID-19 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. Given the dynamic nature of the COVID-19 pandemic and related market conditions, we cannot reasonably estimate the period of time that these events will persist or the full extent of the impact they will have on our business. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including changes in the severity of the pandemic, countermeasures taken by governments, businesses and individuals to slow the spread of the pandemic, and the development and availability of treatments and vaccines and the extent to which these treatments and vaccines may remain effective as potential new strains of the coronavirus emerge. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown. 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. Many of our suppliers, vendors and service providers have made similar modifications. The resources available to employees working remotely may not enable them to maintain the same level of productivity and efficiency, and these and other employees may face additional demands on their time. 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. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus, in which case our employees may become sick, our ability to perform critical functions could be impaired, and we may be unable to respond to the needs of our business. The resumption of normal business operations after such interruptions may be delayed or constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers. 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 ofOPEC 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 several months, 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
74--------------------------------------------------------------------------------
Table of Contents
continued volatility in market conditions since
Natural gas, NGL and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand inthe United States . The average spot price of natural gas decreased by approximately 21% from 2020 to 2019, primarily due to natural gas supply exceeding demand. The average daily Henry Hub Natural Gas Spot Price was$2.03 per MMBtu during 2020, compared with$2.56 per MMBtu during 2019.Henry Hub closed at$2.36 per MMBtu onDecember 31, 2020 . As ofFebruary 18, 2021 ,Henry Hub 12-month strip pricing closed at$3.11 per MMBtu. Natural gas prices continue to trade at lower-than-average historical prices due in part to increased natural gas production and an elevated level of natural gas in storage in the continentalUnited States . The average amount of working natural gas in underground storage in the continentalU.S. was 3.05 Tcfe in 2020, which was 23.4% higher than in 2019. In the near term, we believe that until the supply of natural gas in storage has been reduced, natural gas prices are likely to remain constrained. Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven primarily by global population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation. However, we note that over the last several years there has been an increasing societal opposition to the production of hydrocarbons generally, which may be reflected in legislation, executive orders or regulations that may significantly restrict the domestic production of fossil fuels, including natural gas. In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics. Crude oil prices decreased in 2020, with the average dailyCushing, Oklahoma West Texas Intermediate crude oil spot price decreasing from an average$56.99 per barrel during 2019 to an average of$39.16 per barrel during 2020, representing a 31.3% decrease, reflecting broader market concerns for global oil supply and demand dynamics. In response to the general decrease in crude oil prices, the number of active crude oil drilling rigs in the continentalUnited States decreased from 677 inDecember 2019 to 267 inDecember 2020 , according toBaker Hughes . Over the next several years, we expect that crude oil prices will support continued drilling activity and increasing production in theWilliston Basin ,Permian Basin and, given the current regulatory environment inColorado , in rural parts of theDJ Basin . Growth in production fromU.S. shale plays. Over the past several years, natural gas production from unconventional shale resources has increased significantly due to advances in technology that allow producers to extract significant volumes of natural gas from unconventional shale plays on favorable economic terms relative to most conventional plays. In recent years, a number of producers and their joint venture partners, including large international operators, industrial manufacturers and private equity sponsors, have committed significant capital to the development of these unconventional resources, including the Piceance, Barnett, Bakken, Marcellus,Utica andPermian Basin shale plays in which we operate, and we believe that these long-term capital investments will support drilling activity in unconventional shale plays over the long term. Rate of growth in production fromU.S. shale plays. Some of our producer customers have adjusted their drilling and completion activities and schedules to manage drilling and completion costs at levels that are achievable using internally generated cash flow from their underlying operations. Historically, as part of a strategy to accelerate production growth, these producers would raise external capital to fund drilling and completion costs in excess of the cash flows generated from their underlying assets. In general, we expect our producer customers to maintain moderate completion and production activities across many of our systems relative to our previous expectations as a result of the commodity price environment and a continuation of the general trend of producers constraining drilling and completion activity to levels that can be satisfied with internally generated cash flow. Capital markets availability and cost of capital. Credit markets were volatile throughout 2019, as borrowing costs increased and investors assessed the impact of rising rates on broader economic activity. Capital markets conditions, including but not limited to availability and higher borrowing costs, could affect our ability to access the debt capital markets to the extent necessary, to fund our future growth. Furthermore, market demand for equity issued by master limited partnerships has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures with the issuance of additional equity. We announced the elimination of our common unit distribution inMay 2020 beginning with the distribution paid in respect of the second quarter of 2020, and this action may further reduce demand for our common units. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. 75
--------------------------------------------------------------------------------
Table of Contents
Shifts in operating costs and inflation. Throughout most of the last five years, high levels of crude oil and natural gas exploration, development and production activities acrossthe United States resulted in increased competition for personnel and equipment as well as higher prices for labor, supplies, equipment and other services. Beginning in 2015, this dynamic began to shift as prices for crude oil and natural gas-related services decreased in line with overall decline in demand for these goods and services. While we expect lower service-related costs in the near term, we expect that over the longer term, these costs will continue to have a high correlation to changes in the prevailing price of crude oil and natural gas. 76
--------------------------------------------------------------------------------
Table of Contents
How We Evaluate Our Operations
We conduct and report our operations in the midstream energy industry through eight reportable segments:Utica Shale , Ohio Gathering,Williston Basin ,DJ Basin ,Permian Basin ,Piceance Basin ,Barnett Shale , andMarcellus Shale . Each of our reportable segments provides midstream services in a specific geographic area and 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 (see Note 20 to the consolidated financial statements). Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance and we view these metrics as important factors in evaluating our profitability. These metrics include (i) throughput volume, (ii) revenues, (iii) operation and maintenance expenses, and (iv) segment adjusted EBITDA.
Throughput Volume
The volume of (i) natural gas that we gather, compress, treat and/or process and (ii) crude oil and produced water that we gather depends on the level of production from natural gas or crude oil wells connected to our gathering systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity. Furthermore, because the production rate of natural gas and crude oil wells decline over time, production can only be maintained or increased by new drilling or other activity. As a result, we must continually obtain new supplies of production to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new supplies of throughput is impacted by:
• successful drilling activity within our AMIs;
• the level of work-overs and recompletions of wells on existing pad sites to
which our gathering systems are connected;
• the number of new pad sites in our AMIs awaiting connections;
• our ability to compete for volumes from successful new wells in the areas in
which we operate outside of our existing AMIs; and
• our ability to gather, treat and/or process production that has been
released from commitments with our competitors.
We report volumes gathered for natural gas in cubic feet per day. We aggregate crude oil and produced water gathering and report volumes gathered in barrels per day. Revenues Our revenues are primarily attributable to the volumes that we gather, compress, treat and/or process and the rates we charge for those services. A majority of our gathering and processing agreements are fee-based, which limits our direct exposure to fluctuations in commodity prices. We also have percent-of-proceeds arrangements with certain customers under which the gathering and processing revenues that we earn correlate directly with the fluctuating price of natural gas, condensate and NGLs. Certain of our gathering and processing agreements contain MVCs pursuant to which our customers agree to ship or process a minimum volume of production on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. These MVCs help us generate stable revenues and serve to mitigate the financial impact associated with declining volumes.
Operation and Maintenance Expenses
We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period.
Segment Adjusted EBITDA
Segment adjusted EBITDA is a supplemental financial measure used by management
and by external users of our financial statements such as investors, commercial
banks, research analysts and others.
77--------------------------------------------------------------------------------
Table of Contents
Segment adjusted EBITDA is used to assess:
• the ability of our assets to generate cash sufficient to make cash
distributions and support our indebtedness;
• the financial performance of our assets without regard to financing methods,
capital structure or historical cost basis;
• our operating performance and return on capital as compared to other
companies in the midstream energy sector, without regard to financing or
capital structure;
• the attractiveness of capital projects and acquisitions and the overall
rates of return on alternative investment opportunities; and
• the financial performance of our assets without regard to (i) income or loss
from equity method investees, (ii) the impact of the timing of MVC shortfall
payments under our gathering agreements or (iii) the timing of impairments
or other noncash income or expense items.
Additional Information. For additional information, see the "Results of
Operations" section herein and the notes to the consolidated financial
statements. For information on pending accounting changes that are expected to
materially impact our financial results reported in future periods, see Note 2
to the consolidated financial statements.
78--------------------------------------------------------------------------------
Table of Contents Results of Operations
Consolidated Overview for the Years Ended
The following table presents certain consolidated data and volume throughput for
the years ended
Year ended December 31,
Percentage
2020 2019 change
(In thousands)
Revenues:
Gathering services and related fees $ 302,792 $ 326,747 (7%)
Natural gas, NGLs and condensate sales 49,319 86,994 (43%)
Other revenues 31,362 29,787 5%
Total revenues 383,473 443,528 (14%)
Costs and expenses:
Cost of natural gas and NGLs 36,653 63,438 (42%)
Operation and maintenance 86,030 98,719 (13%)
General and administrative 73,438 55,947 31%
Depreciation and amortization 118,132 110,354 7%
Transaction costs 2,993 3,017 (1%)
Gain on asset sales, net (307 ) (1,536 ) (80%)
Long-lived asset impairment 13,089 60,507 (78%)
Goodwill impairment - 16,211 *
Total costs and expenses 330,028 406,657 (19%)
Other income 48 451 (89%)
Interest expense (78,894 ) (91,966 )
Gain on early extinguishment of debt 203,062 - *
Income (loss) before income taxes and
equity method investment income (loss) 177,661 (54,644 ) *
Income tax benefit (expense) 146 (1,231 ) *
Income (loss) from equity method investees 11,271 (337,851 ) *
Net income (loss) $ 189,078 $ (393,726 ) *
Volume throughput (1):
Aggregate average daily throughput - natural
gas (MMcf/d) 1,375 1,397 (2%)
Aggregate average daily throughput - liquids
(Mbbl/d) 79 105 (25%)
* Not considered meaningful
(1) Exclusive of volume throughput for Ohio Gathering. For additional information, see the "Ohio Gathering" section herein.
Volumes - Gas. Natural gas throughput volumes decreased 22 MMcf/d for the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 , primarily reflecting:
• a volume throughput increase of 5 MMcf/d for the
• a volume throughput decrease of 88 MMcf/d for the
• a volume throughput increase of 85 MMcf/d for the
• a volume throughput increase of 14 MMcf/d for the
• a volume throughput decrease of 39 MMcf/d for the
Volumes - Liquids. Crude oil and produced water throughput volumes at the
For additional information on volumes, see the "Segment Overview for the Years
Ended
79--------------------------------------------------------------------------------
Table of Contents
Revenues. Total revenues decreased$60.1 million during the year endedDecember 31, 2020 compared to the prior year primarily comprised of a$24.0 million decrease in gathering services and related fees and a$37.7 million decrease in natural gas, NGLs and condensate sales.
Gathering services and related fees. Gathering services and related fees
decreased
• a
revenue attributable to a MVC with a customer in 2019 that expired in 2020.
• a $14.7 million decrease in gathering services and related fees in theand completion activity and natural production declines.
• a
Shale primarily due to the completion of new wells throughout 2019, and in
2020, and a more favorable volume and gathering rate mix from customers,
partially offset by natural production declines from existing wells.
• a
related fees attributable to the sale of the Tioga Midstream system on March
22, 2019, whose 2019 financial results are included for the period from
throughput, partially offset by the completion of new wells through 2019 and
2020.
• a
Basin primarily as a result of ongoing drilling and completion activity
across our service area, a more favorable volume and gathering rate mix from
customers and the commissioning of our new natural gas processing plant in
production curtailments associated with a significant reduction in crude oil
prices as a result of a decrease in demand attributable to the COVID-19
pandemic.
• a
partially offset by natural production declines from wells previously put in
service.
Costs and expenses. Total costs and expenses decreased
• a
2019.
• a
Mountaineer Midstream system in the
• a
sale of certain
2019.
Cost of natural gas and NGLs. Cost of natural gas and NGLs decreased
Operation and maintenance. Operation and maintenance expense decreased$12.7 million for the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 . Depreciation and amortization. The increase in depreciation and amortization expense during 2020 compared to the year endedDecember 31, 2019 was primarily due to the assets placed into service in thePermian Basin . Interest Expense. The decrease in interest expense in the year endedDecember 31, 2020 compared to the year endedDecember 31, 2019 , was primarily a result of our liability management initiatives which included our Open Market Repurchases and Tender Offers, partially offset by a higher outstanding balance on the Revolving Credit Facility. Gain on early extinguishment of debt. The$203.1 million gain on the early extinguishment of debt is primarily related to liability management initiatives undertaken during 2020 that resulted in a$86.4 million gain from the Open Market Repurchases, a$23.3 million gain from the Debt Tender Offers, and a$93.9 million gain from our TL Restructuring. Further details of our liability management results are summarized below. 80
--------------------------------------------------------------------------------
Table of Contents
ECP Loan Open Market Tender TL
Repayment Repurchases Offers Restructuring Total
2022 2025 2022 2025
Senior Notes Senior Notes Senior Notes Senior Notes
(in thousands)
Gain on Repurchases
of Senior Notes and
TL Restructuring $ - $ 11,554 $ 76,789 $ 9,223 $ 15,479 $ 99,175 $ 212,220
Debt issue costs (361 ) (143 ) (1,541 ) (125 ) (351 ) (2,724 ) (5,245 )
Transaction cost (249 ) (105 ) (105 ) (467 ) (467 ) (2,520 ) (3,913 )
Gain (loss) on debt
extinguishment $ (610 ) $ 11,306 $ 75,143 $ 8,631 $ 14,661 $ 93,931 $ 203,062
81
--------------------------------------------------------------------------------
Table of Contents
Segment Overview for the Years Ended
Utica Shale
Year ended December 31,
Percentage
2020 2019 Change
Average daily throughput (MMcf/d) 358 273 31%
Volume throughput increased compared to the year endedDecember 31, 2020 primarily due to new wells that came online in the fourth quarter of 2019 and through the first three quarters of 2020. In addition, volume throughput was impacted by an increase in temporary production curtailments, completion activity and other operational downtime associated with customers on existing pad sites.
Financial data for our
Utica Shale
Year ended December 31,
Percentage
2020 2019 Change
(Dollars in thousands)
Revenues:
Gathering services and related fees $ 36,509 $ 31,926 14%
Other revenues - $ 2,065
Total revenues 36,509 33,991 7%
Costs and expenses:
Operation and maintenance 3,396 4,151 (18%)
General and administrative 301 530 (43%)
Depreciation and amortization 7,696 7,659 0%
Gain on asset sales, net (35 ) - *
Total costs and expenses 11,358 12,340 (8%)
Add:
Depreciation and amortization 7,696 7,659
Adjustments related to capital
reimbursement activity (29 ) (18 ) Gain on asset sales, net (35 ) - Segment adjusted EBITDA$ 32,783 $ 29,292 12% * Not considered meaningful
Year ended
Ohio Gathering. The Ohio Gathering reportable segment includes OGC and OCC. We account for our investment in Ohio Gathering using the equity method. 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
Year ended December 31,
Percentage
2020 2019 Change
Average daily throughput (MMcf/d) 571 732 (22%)
* Not considered meaningful
Volume throughput for the Ohio Gathering system in 2020 decreased compared to
the year ended December 31, 2019 as a result of natural production declines on
existing wells on the system, fewer well connections, temporary production
shut-ins and was partially offset by the completion of new wells.
82--------------------------------------------------------------------------------
Table of Contents
Financial data for our Ohio Gathering reportable segment, based on a one-month
lag follows.
Ohio Gathering
Year ended December 31,
Percentage
2020 2019 Change
(Dollars in thousands)Proportional adjusted EBITDA for equity
method investees$ 31,056 $ 39,126 (21%) Segment adjusted EBITDA$ 31,056 $ 39,126 (21%)
Year ended
83
--------------------------------------------------------------------------------
Table of Contents
Williston Basin . The Polar and Divide, Tioga Midstream (throughMarch 22, 2019 ; refer to Note 18 to the consolidated financial statements for details on the sale of Tioga Midstream) and Bison Midstream systems provide our midstream services for theWilliston Basin reportable segment. Volume throughput for ourWilliston Basin reportable segment follows. Williston Basin Year ended December 31, Percentage 2020 2019 Change
Aggregate average daily throughput -
natural gas (MMcf/d) 14 12
17%
Aggregate average daily throughput -
liquids (Mbbl/d) 79 105
(25%)
Natural gas. Natural gas volume throughput in 2020 increased compared to the year endedDecember 31, 2019 , primarily reflecting the completion of new wells behind the Bison Midstream system in the fourth quarter of 2019 and through 2020 partially offset by natural production declines and the sale of Tioga Midstream. Liquids. Liquids volume throughput in 2020 decreased compared to the year endedDecember 31, 2019 , primarily associated with natural production declines, deferral of completion activities, shut-ins and temporary production curtailments associated with a significant reduction in crude oil prices as a result of a decrease in demand attributable to the COVID-19 pandemic, partially offset by the completion of new wells throughout 2019 and 2020.
Financial data for our
Williston Basin
Year ended December 31,
Percentage
2020 2019 Change
(Dollars in thousands)
Revenues:
Gathering services and related fees
22% Other revenues 13,438 11,564 16% Total revenues 92,695 105,651 (12%) Costs and expenses: Cost of natural gas and NGLs 12,741 5,821 119% Operation and maintenance 23,793 27,172 (12%) General and administrative 1,738 1,493 16% Depreciation and amortization 25,911 19,829 31% Gain on asset sales, net (50 ) (1,177 ) (96%) Long-lived asset impairment 2,421 10 * Total costs and expenses 66,554 53,148 25% Add: Depreciation and amortization 25,911 19,829
Adjustments related to capital
reimbursement activity (2,363 ) (1,728 ) Gain on asset sales, net (50 ) (1,177 ) Long-lived asset impairment 2,421 10 Segment adjusted EBITDA$ 52,060 $ 69,437 (25%) * Not considered meaningful Year endedDecember 31, 2020 . Segment adjusted EBITDA decreased$17.4 million compared to the year endedDecember 31, 2019 primarily associated with the decreased liquid volume throughput described above, and the sale ofTioga Midstream in March of 2019. The decrease was partially offset by the increased natural gas volume throughput described above. 84
--------------------------------------------------------------------------------
Table of Contents
DJ Basin . The Niobrara G&P system provides midstream services for theDJ Basin reportable segment. Volume throughput for ourDJ Basin reportable segment follows. DJ Basin Year ended December 31, Percentage 2020 2019 Change Average daily throughput (MMcf/d) 26 27 (4%)
Volume throughput in 2020 decreased compared to the year ended
Financial data for our
DJ Basin
Year ended December 31,
Percentage
2020 2019 Change
(Dollars in thousands)
Revenues:
Gathering services and related fees
9%
Natural gas, NGLs and condensate sales 245 389 (37%) Other revenues 3,957 3,721 6% Total revenues 28,070 26,050 8% Costs and expenses: Cost of natural gas and NGLs 67 34 97% Operation and maintenance 9,579 7,616 26% General and administrative 1,088 315 245% Depreciation and amortization 6,146 3,732 65% Loss on asset sales, net 20 - * Long-lived asset impairment 3,692 34,913 (89%) Total costs and expenses 20,592 46,610 (56%) Add: Depreciation and amortization 6,146 3,732
Adjustments related to capital
reimbursement activity 2,113 583 Loss on asset sales, net 20 - Long-lived asset impairment 3,692 34,913 Segment adjusted EBITDA$ 19,449 $ 18,668 4% * Not considered meaningful Year endedDecember 31, 2020 . Segment adjusted EBITDA increased$0.8 million compared to the year endedDecember 31, 2019 , primarily associated with a more favorable volume and gathering rate mix from customers. 85
--------------------------------------------------------------------------------
Table of Contents
Permian Basin . The Summit Permian system provides our midstream services for thePermian Basin reportable segment. Volume throughput for ourPermian Basin reportable segment follows. Permian Basin Year ended December 31, Percentage 2020 2019 Change Average daily throughput (MMcf/d) 33 19
74%
Volume throughput in 2020 increased compared to the year ended
Financial data for our
Permian Basin
Year ended December 31,
Percentage
2020 2019 Change
(Dollars in thousands)
Revenues:
Gathering services and related fees
180%
Natural gas, NGLs and condensate sales 18,857 16,383
15% Other revenues 585 310 89% Total revenues 29,533 20,303 45% Costs and expenses: Cost of natural gas and NGLs 18,785 15,113 24% Operation and maintenance 6,038 5,755 5% General and administrative 284 314 (10%) Depreciation and amortization 5,455 4,868 12% Gain on asset sales, net - (148 ) * Long-lived asset impairment 324 1,327 (76%) Total costs and expenses 30,886 27,229 13% Add: Depreciation and amortization 5,455 4,868 Gain on asset sales, net - (148 ) Long-lived asset impairment 324 1,327 Segment adjusted EBITDA$ 4,426 $ (879 ) * * Not considered meaningful Year endedDecember 31, 2020 . Segment adjusted EBITDA increased$5.3 million compared to the year endedDecember 31, 2019 , primarily as a result of higher volumes throughput described above. 86
--------------------------------------------------------------------------------
Table of Contents
Piceance Basin .The Grand River system provides midstream services for thePiceance Basin reportable segment. Volume throughput for ourPiceance Basin reportable segment follows. Piceance Basin Year ended December 31, Percentage 2020 2019 Change
Aggregate average daily throughput
(MMcf/d) 364 452
(19%)
Volume throughput decreased in 2020 compared to the year ended
Financial data for our
Piceance Basin
Year ended December 31,
Percentage
2020 2019 Change
(Dollars in thousands)
Revenues:
Gathering services and related fees
sales 2,612 7,954 (67%) Other revenues 4,621 4,327 7% Total revenues 113,890 133,638 (15%) Costs and expenses: Cost of natural gas and NGLs 1,717 5,612 (69%) Operation and maintenance 21,064 27,306 (23%) General and administrative 1,053 1,009 4% Depreciation and amortization 45,203 47,018 (4%) (Gain) loss on asset sales, net (190 ) 104 * Long-lived asset impairment 7 14,162 * Total costs and expenses 68,854 95,211
(28%)
Add:
Depreciation and amortization 45,203 47,018
Adjustments related to MVC
shortfall payments - (103 )
Adjustments related to capital
reimbursement activity (1,236 ) (843 ) (Gain) loss on asset sales, net (190 ) 104 Long-lived asset impairment 7 14,162 Segment adjusted EBITDA$ 88,820 $ 98,765 (10%)
* Not considered meaningful
Year endedDecember 31, 2020 . Segment adjusted EBITDA decreased$9.9 million compared to the year endedDecember 31, 2019 , primarily associated with the volume throughput decrease described above, and a decrease in operations and maintenance expense primarily due to lower compensation expense associated with lower headcount from our cost cutting initiatives. 87
--------------------------------------------------------------------------------
Table of Contents
Volume throughput for our
Barnett Shale
Year ended December 31,
Percentage
2020 2019 Change
Average daily throughput (MMcf/d) 212 251 (16%)
Volume throughput decreased in 2020 compared to the year ended December 31, 2019
reflecting natural production declines partially offset by new volumes from well
recompletion and workover activity throughout 2020.
Financial data for our
Barnett Shale
Year ended December 31,
Percentage
2020 2019 Change
(Dollars in thousands)
Revenues:
Gathering services and related fees $ 40,687 $ 47,862 (15%)
Natural gas, NGLs and condensate sales 7,587 17,147 (56%)
Other revenues (1) 6,185 6,793 (9%)
Total revenues 54,459 71,802 (24%)
Costs and expenses:
Cost of natural gas and NGLs 3,341 10,751 (69%)
Operation and maintenance 18,814 21,729 (13%)
General and administrative 1,306 968 35%
Depreciation and amortization 15,174 15,354 (1%)
Gain on asset sales, net (19 ) (325 ) (94%)
Long-lived asset impairment 4,902 10,095 (51%)
Total costs and expenses 43,518 58,572 (26%)
Add:
Depreciation and amortization 16,112 16,575Adjustments related to MVC shortfall
payments - 3,579
Adjustments related to capital
reimbursement activity 157 (111 ) Gain on asset sales, net (19 ) (325 ) Long-lived asset impairment 4,902 10,095 Segment adjusted EBITDA$ 32,093 $ 43,043 (25%) *Not considered meaningful
(1) Includes the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues.
Year endedDecember 31, 2020 . Segment adjusted EBITDA decreased$10.9 million compared to the year endedDecember 31, 2019 primarily related to the decreased volume throughput described above. 88
--------------------------------------------------------------------------------
Table of Contents
Volume throughput for the
Marcellus Shale
Year ended December 31,
Percentage
2020 2019 Change
Average daily throughput (MMcf/d) 368 363 1%
Volume throughput increased in 2020 compared to the year ended
Financial data for our
Marcellus Shale
Year ended December 31,
Percentage
2020 2019 Change
(Dollars in thousands)
Revenues:
Gathering services and related fees $ 25,741 $ 24,471 5%
Total revenues 25,741 24,471 5%
Costs and expenses:
Operation and maintenance 3,343 3,861 (13%)
General and administrative 345 521 (34%)
Depreciation and amortization 9,195 9,141 1%
Gain on asset sales, net (8 ) - *
Goodwill impairment - 16,211 *
Total costs and expenses 12,875 29,734 (57%)
Add:
Depreciation and amortization 9,195 9,141
Goodwill impairment - 16,211
Adjustments related to capital
reimbursement activity (38 ) (38 ) Gain on asset sales, net (8 ) - Segment adjusted EBITDA$ 22,015 $ 20,051 10% *Not considered meaningful
Year ended
89--------------------------------------------------------------------------------
Table of Contents
Corporate and Other Overview for the Years Ended
Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, natural gas and crude oil marketing services, transaction costs, interest expense and early extinguishment of debt.
Corporate and Other
Year ended December 31,
Percentage
2020 2019 Change
(Dollars in thousands)
Revenues:
Total revenues $ 2,575 $ 27,622 (91%)
Costs and expenses:
Cost of natural gas and NGLs - 26,107 *
General and administrative 67,324 50,797 33%
Transaction costs 2,993 3,017 (1%)
Interest expense 78,894 91,966 (14%)
Gain on asset sales or disposals (21 ) - *
Long-lived asset impairment 1,740 - *
Gain on early extinguishment of debt (203,062 ) - *
* Not considered meaningful
Total Revenues. Total revenues attributable to Corporate and Other was due to gathering services, natural gas, and condensate sales. The decrease of$25.0 million compared to the year endedDecember 31, 2019 was primarily attributable to the wind down of our marketing group in 2020 as well as lower natural gas activity. Cost of Natural Gas and NGLs. Cost of natural gas and NGLs attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services in 2019. The decrease of$26.1 million compared to the year endedDecember 31, 2019 was attributable to the wind down of our marketing group in 2020. General and administrative. General and administrative expense attributable to Corporate and Other increased by$16.5 million , primarily related to a$17.0 million loss contingency accrual in 2020, see note 11 of the consolidated financial statements for additional information. Transaction costs. Transaction costs recognized during the year endedDecember 31, 2020 are primarily related to costs associated with our liability management initiatives.
Interest Expense. Interest expense decreased
Gain on Early Extinguishment of Debt. The gain on the early extinguishment of debt is primarily related to liability management initiatives undertaken during 2020 that resulted in a$86.4 million gain from the Open Market Repurchases, a$23.3 million gain from the Debt Tender Offers, and a$93.9 million gain from our TL Restructuring.
Liquidity and Capital Resources
We depend primarily on funds generated from our operations, our Revolving Credit Facility, our cash and cash equivalents balance, and capital markets as our primary sources of liquidity. Looking forward to 2021, we will seek to reduce indebtedness and extend our indebtedness maturities. As a result, we expect to fund future expenditures from cash generated by our operations, our Revolving Credit Facility, our cash equivalents on hand. If optimal, we may also consider accessing the capital markets, opportunistic divestitures or joint ventures involving our existing midstream assets.
Debt
Revolving Credit Facility. We have a
90--------------------------------------------------------------------------------
Table of Contents
outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as ofDecember 31, 2020 was approximately$105 million . There were no defaults or events of default during 2020, and as ofDecember 31, 2020 , we were in compliance with the financial covenants in the Revolving Credit Facility. Our total leverage ratio and senior secured leverage ratio (as defined in the Revolving Credit Agreement) was 5.1 to 1.0 and 3.2 to 1.0, respectively, relative to maximum threshold limits of 5.75 to 1.0 and 3.5 to 1.0. 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 senior secured 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. See Note 9 to the consolidated financial statements for more information on the Revolving Credit Facility and the issuance of the$4.1 million letter of credit. 2022 Senior Notes. InJuly 2014 ,Summit Holdings and its 100% owned finance subsidiary,Finance Corp. (together withSummit Holdings , the "Co-Issuers") co-issued$300.0 million of 5.5% senior unsecured notes maturingAugust 15, 2022 (the "2022 Senior Notes" and, together with the 2025 Senior Notes (defined below), the "Senior Notes"). As ofDecember 31, 2020 , the outstanding balance of the 2022 Senior Notes is$234.0 million . We pay interest on the 2022 Senior Notes semi-annually in cash in arrears onFebruary 15 andAugust 15 of each year. The 2022 Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 2022 Senior Notes are effectively subordinated in right of payment to all secured indebtedness, to the extent of the collateral securing such indebtedness. The Co-Issuers may redeem all or part of the 2022 Senior Notes at a redemption price of 100.000%, plus accrued and unpaid interest, if any. Debt issuance costs of$5.1 million are being amortized over the life of the 2022 Senior Notes. As of and during the year endedDecember 31, 2020 , we were in compliance with the financial covenants governing our 2022 Senior Notes. 2025 Senior Notes. InFebruary 2017 , the Co-Issuers co-issued$500.0 million of 5.75% senior unsecured notes maturingApril 15, 2025 (the "2025 Senior Notes"). As ofDecember 31, 2020 , the outstanding balance of the 2025 Senior Notes was$259.5 million . We pay interest on the 2025 Senior Notes semi-annually in cash in arrears onApril 15 andOctober 15 of each year. The 2025 Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 2025 Senior Notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. The Co-Issuers may redeem all or part of the 2025 Senior Notes at a redemption price of 104.313% (with the redemption price declining ratably eachApril 15 to 100.000% onApril 15, 2023 ), plus accrued and unpaid interest, if any, to, but not including, the redemption date. Debt issuance costs of$7.7 million are being amortized over the life of the 2025 Senior Notes. As of and during the year endedDecember 31, 2020 , we were in compliance with the financial covenants governing our 2025 Senior Notes. For additional information on our long-term debt, see Note 9 to the consolidated financial statements. Cash Flows Year ended December 31, 2020 2019 (In thousands) Net cash provided by operating activities$ 198,589 $ 161,741 Net cash used in investing activities (140,569 ) (90,870 ) Net cash provided by (used in) financing activities (79,398 ) (50,122 ) Net change in cash, cash equivalents and restricted cash$ (21,378 )
The components of the net change in cash, cash equivalents and restricted cash were as follows:
Operating activities. Details of cash flows from operating activities follow.
Cash flows from operating activities for the year ended
• net income of
items; and
• $50.0 million increase in working capital accounts.
Cash flows from operating activities for the year ended
91--------------------------------------------------------------------------------
Table of Contents • a$7.3 million increase in cash interest payments; and • other changes in working capital.
Investing activities. Details of cash flows from investing activities follow.
Cash flows used in investing activities during the year ended
•
•
development of our
Cash flows used in investing activities during the year ended
•
development of the
million, the
includes $17.7 million of capital expenditures relating to the Double E
Project ;
•
•
million of proceeds from the Red Rock Gathering sale; and
• $7.3 million for a distribution from an equity method investment.
Financing activities. Details of cash flows from financing activities follow.
Cash flows used in financing activities during the year ended
•
•$47.5 million paid for tender offer of 2022 and 2025 Senior Notes;
•
•$35.0 million for the repayment of the ECP Loan; •$26.5 million for cash paid in connection with the TL Restructuring;
•
•$6.3 million of cash repayments on the SMPH Term loan; and •$6.0 million of distributions offset by;
•
Facility;
•
Preferred Units and;
• $35.0 million in proceeds from the ECP Loan.
Cash flows used in financing activities during the year ended
•$218.1 million of distributions; •$211.0 million of net borrowings under our Revolving Credit Facility; •$65.3 million payment on Term Loan B; and
•
Units.
Contractual Obligations Update
The Partnership's cash flows generated from operations are also the primary
source for funding various contractual obligations. The table below summarizes
the Partnership's major commitments as of
Total 2021 2022 2023 2024 2025
Revolving Credit Facility, due
May 2022 (2) $ 892,208 $ 24,853 $ 867,355 $ - $ - $ -
2022 Senior Notes, due August
2022 (2) 255,502 12,873 242,629 - - -
2025 Senior Notes, due April
2025 (2) 309,193 14,919 14,919 14,919 14,919 264,436
Capital contributions to Double
E equity method
investment(1) 172,410 147,710 24,700 - - -
Lease obligations 5,772 2,405 1,434 896 573 464
Total $ 1,635,085 $ 202,760 $ 1,151,037 $ 15,815 $ 15,492 $ 264,900
92
--------------------------------------------------------------------------------
Table of Contents
(1) The Partnership issued a parental guaranty on behalf of its wholly owned
subsidiary to fund the subsidiary's pro rata share of required
construction project capital calls. As of
represents the Partnership's best estimate of its remaining obligation to
fund
(2) For the purposes of calculating future interest payments we assumed no
change in balance or rate from December 31, 2020 . See Note 9 to the
consolidated financial statements.
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 year endedDecember 31, 2020 , cash paid for capital expenditures totaled$43.1 million which included$14.1 million of maintenance capital expenditures. For the year endedDecember 31, 2020 , we contributed$99.9 million toDouble E . 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 asset divestitures to fund our capital expenditures. We believe that our Revolving 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. With the completion of our 60MMcf/d DJ Basin processing plant and compression expansions in thePermian Basin , capital expenditures began to decline in the third and fourth quarter of 2019 and continued throughout 2020. We will remain disciplined with respect to future capital expenditures, which will be primarily concentrated on theDouble E Project and accretive expansions of our existing systems in our Core Focus Areas. We continue to advance our financing plans for our equity interest inDouble E , which we intend to be credit positive to Summit. We are currently targeting a financing structure that limits cash payments by us during 2021, and which shifts a substantial majority of ourDouble E capital commitments to third parties, including commercial banks. OnDecember 24, 2019 , we entered into an agreement with TPG to fund up to$80.0 million of Permian Holdco's future capital calls associated with theDouble E Project . For the years endedDecember 31, 2020 and 2019, Permian Holdco issued 55,251 and 30,000 Subsidiary Series A Preferred Units to TPG for net proceeds of$48.7 million and$27.4 million , respectively.
We estimate that our 2021 capital program will range from
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 agreement with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and NGL industries and markets and (iii) our ability to obtain financing from commercial banks, the capital markets, or other financing sources.
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.
93--------------------------------------------------------------------------------
Table of Contents
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 customer, who was not meeting its MVCs, does 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. As ofDecember 31, 2020 , our material off-balance sheet arrangements and transactions include (i) a parental guaranty issued on behalf of a wholly owned subsidiary to fund the subsidiary's pro rata share of requiredDouble E Project construction related capital calls, with the wholly owned subsidiary having an estimated$172.4 million of remaining capital calls due for construction based on the Partnership's best estimate atDecember 31, 2020 , (ii) letters of credit outstanding against our Revolving Credit Facility aggregating to$4.1 million , and (iii) outstanding surety bonds aggregating to$7.1 million . There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources.
Summarized Financial Information
OnMarch 2, 2020 , theSEC issued Final Rule Release No. 33-10762, Financial Disclosures about Guarantors and Issuers ofGuaranteed Securities and Affiliates Whose Securities Collateralize a Registrant's Securities ("Release 33-10762"), that amends the disclosure requirements related to certain registered securities that are guaranteed and those that are collateralized by the securities of an affiliate. Under Release 33-10762, anSEC registrant may continue to omit separate financial statements of subsidiary issuers and guarantors when (1) the subsidiary issuer is consolidated with the parent company and its security is either (a) co-issued jointly and severally with the parent company's security or (b) the subsidiary issuer's security is fully and unconditionally guaranteed by the parent company and (2) the parent company provides supplemental financial and non-financial disclosure about the subsidiary issuers and/or guarantors and the guarantees. The rules become effectiveJanuary 4, 2021 , with voluntary compliance permitted immediately. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by SMLP and the Guarantor Subsidiaries (see Note 9 - Debt). SMLP has concluded that it is eligible to provide Alternative Disclosures under the amended disclosure requirements and has early adopted Release 33-10762. 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 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 Non-Guarantor Subsidiaries, who 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. 94
--------------------------------------------------------------------------------
Table of Contents
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 Annual Report.
Summarized Balance Sheet Information. Summarized balance sheet information as of
© Edgar Online, source
