UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): February 25, 2022
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Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Item 2.02 Results of Operations and Financial Condition.
On February 25, 2022, Summit Midstream Partners, LP (the “Partnership,” “we” and “our”) issued a press release announcing its results of operations for the three months and year ended December 31, 2021. A copy of the press release is furnished as Exhibit 99.1 to this Current Report on Form 8-K.
The information furnished in this Item 2.02 shall not be deemed “filed” for purposes of the Securities Exchange Act of 1934, as amended (the “1934 Act”), and shall not be deemed incorporated by reference in any filing with the Securities and Exchange Commission, whether or not filed under the Securities Act of 1933 or the 1934 Act, regardless of any general incorporation language in such document.
Use of Non-GAAP Financial Measures
In addition to reporting financial results in accordance with accounting principles generally accepted in the United States of America ("GAAP"), the Partnership presents certain non-GAAP financial measures. Specifically, the Partnership presents adjusted EBITDA and distributable cash flow. We define adjusted EBITDA as net income or loss, plus interest expense, income tax expense, depreciation and amortization, our proportional adjusted EBITDA for equity method investees, adjustments related to MVC shortfall payments, adjustments related to capital reimbursement activity, unit-based and noncash compensation, impairments, items of income or loss that we characterize as unrepresentative of our ongoing operations and other noncash expenses or losses, less interest income, income tax benefit, income (loss) from equity method investees and other noncash income or gains. We define distributable cash flow as adjusted EBITDA plus cash interest received and cash taxes received, less cash interest paid, senior notes interest adjustment, adjusted Series A Preferred Units cash distribution, cash taxes paid and maintenance capital expenditures.
We exclude these items because they are considered unusual and not indicative of our ongoing operations. Our definitions of these non-GAAP financial measures may differ from the definitions of similar measures used by other companies, thereby diminishing the utility of these measures. Management uses these non-GAAP financial measures in making financial, operating and planning decisions and in evaluating the Partnership’s financial performance. Furthermore, management believes that these non-GAAP financial measures may provide users of the Partnership’s financial statements with additional meaningful comparisons between current results and results of prior periods as they are expected to be reflective of our core ongoing business. These measures have limitations, and investors should not consider them in isolation or as a substitute for analysis of the Partnership’s results as reported under GAAP.
We do not provide the GAAP financial measures of net income or loss or net cash provided by operating activities on a forward-looking basis because we are unable to predict, without unreasonable effort, certain components thereof including, but not limited to, (i) income or loss from equity method investees and (ii) asset impairments. These items are inherently uncertain and depend on various factors, many of which are beyond our control. As such, any associated estimate and its impact on our GAAP performance and cash flow measures could vary materially based on a variety of acceptable management assumptions.
Reconciliations of GAAP to non-GAAP financial measures are included as attachments to the press release which has been posted to the “Investors” section of our website at www.summitmidstream.com.
Item 9.01 Financial Statements and Exhibits.
(d) Exhibits
| Exhibit Number | Description | |||||||
| 99.1 | ||||||||
| 104 | Cover Page Interactive Data File – the cover page XBRL tags are embedded within the Inline XBRL document | |||||||
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| Summit Midstream Partners, LP | |||||||||||
| (Registrant) | |||||||||||
| By: | Summit Midstream GP, LLC (its general partner) | ||||||||||
| Dated: | February 25, 2022 | /s/ WILLIAM J. MAULT | |||||||||
William J. Mault, Executive Vice President and Chief Financial Officer (Principal Financial Officer) | |||||||||||
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EXHIBIT 99.1
 | Summit Midstream Partners, LP 910 Louisiana Street, Suite 4200 Houston, TX 77002 | ||||
Summit Midstream Partners, LP Reports Fourth Quarter and Full Year 2021
Financial and Operating Results & Provides Full Year 2022 Guidance
•Fourth quarter 2021 net loss of $16.2 million, adjusted EBITDA of $54.7 million and cash flow available for distributions ("Distributable Cash Flow" or “DCF”) of $29.9 million
•Full year 2021 adjusted EBITDA of $238 million relative to $225 million to $240 million guidance range and capital expenditures of $25 million, excluding Double E, relative to $20 million to $35 million guidance range
•Refinanced all near-term debt maturities with proceeds from a new $400 million ABL Revolver and $700 million 8.5% Senior Secured Second Lien Notes due 2026 (the "2026 Secured Notes") that closed concurrently in November 2021
•In January 2022, exchanged $94.6 million of Series A Preferred Units, inclusive of $16.6 million of accrued and unpaid distributions, for approximately 2.9 million SMLP common units
•Commenced operations on the Double E Pipeline in November 2021, on schedule, while maintaining top tier safety, environmental and compliance record, and approximately 20% below the original budget
•Providing 2022 adjusted EBITDA guidance of $195 million to $220 million based on 75 to 110 new well connections and total capital expenditure guidance of $20 million to $35 million, excluding $10 million of Double E capex
Houston, Texas (February 25, 2022) – Summit Midstream Partners, LP (NYSE: SMLP) (“Summit”, “SMLP” or the “Partnership”) announced today its financial and operating results for the three months ended December 31, 2021, including net loss of $16.2 million, adjusted EBITDA of $54.7 million and DCF of $29.9 million. Operated natural gas throughput from wholly owned assets averaged 1,307 million cubic feet per day (“MMcf/d”) and liquids throughput averaged 62 thousand barrels per day (“Mbbl/d”). Operated natural gas volumes from wholly owned assets decreased 2.0% relative to the third quarter of 2021, largely due to natural production declines, which was partially offset by volumes from 25 new wells that were turned-in-line primarily towards the latter half of the fourth quarter, including four new Utica wells that were connected in the Northeast segment in late November with initial production of nearly 100 MMcf/d. Fourth quarter 2021 liquids volume decreased modestly relative to the third quarter of 2021, primarily as a result of natural production declines, partially offset by crude volumes gathered from 16 new Williston wells that were turned-in-line in November and December of 2021.
Heath Deneke, President, Chief Executive Officer and Chairman, commented, “Summit's fourth quarter financial and operating results were in-line with our expectations. For full year 2021, adjusted EBITDA of $238 million was near the top of our $225 million to $240 million revised guidance range and almost $20 million above the midpoint of our initial guidance. In 2021, we spent $25 million on capital expenditures, which was towards the low end of our $20 million to $35 million guidance range. Well connect activity from our upstream customers during the fourth quarter of 2021 represented a significant increase versus the first three quarters of 2021, with 45 of the 95 wells turned-in-line behind our systems during the last quarter of the year. We also successfully placed the Double E Pipeline in-service during the fourth quarter of 2021. Double E is a very important new pipeline system for the northern Delaware Basin, with the initial capacity to transport an incremental 1.35 Bcf/d of natural gas from growing production in Eddy and Lea counties, New Mexico to multiple Gulf Coast oriented pipelines originating out of Waha, TX. The pipeline is anchored by 1.0 Bcf/d of long term take-or-pay contracts from some of the largest producers in the Permian Basin and is well positioned for a highly efficient expansion to 2.0 Bcf/d as production continues to increase in the region. We are very proud of the team for delivering this important project on time, approximately 20% below the original $500 million budget, all while maintaining an outstanding safety, environmental and compliance record. We expect Double E to be a significant growth catalyst for Summit as our initial 1.0 Bcf/d of sculpted take-or-pay contracts ramp up between 2022 and 2024 and as we secure new contracts from Northern Delaware customers that need incremental gas takeaway capacity."
"As previously announced, we also achieved a critical milestone for Summit during the fourth quarter with the successful refinancing of our 2022 debt maturities which provided an extended, multi-year runaway to continue our focus on maximizing free cash flow and further de-levering the balance sheet. During the quarter, we also launched
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EXHIBIT 99.1
a cash-less preferred for common equity exchange transaction which closed in January of 2022, whereby holders of nearly $95 million of our Series A Preferred Equity, including accrued and unpaid distributions, exchanged into approximately 2.9 million SMLP common units. This transaction enabled Summit to continue its efforts to simplify and improve the balance sheet by further reducing our outstanding fixed capital obligations while preserving cash for debt repayment. The transaction also eliminated nearly $17 million of unpaid preferred distributions that have accrued on the balance sheet since June of 2020, while reducing the remaining amount of Series A Preferred Equity to which distributions are expected to continue to accrue by more than half. Additionally, with the reduction in the face value of the remaining Series A Preferred Equity to a level below $100 million, SMLP is now able to issue or assume a separate class of parity preferred equity, which further enhances our strategic and financial flexibility as we continue to evaluate long-term value enhancing opportunities in the future."
"Our 2022 guidance includes an adjusted EBITDA range of $195 million to $220 million based on approximately 75 to 110 new well connections. Given the current commodity price environment and the momentum in activity that we experienced in the second half of 2021, we are disappointed and frankly surprised by the limited amount of new wells that our customers’ most recent plans are indicating will be turned on-line behind our systems in 2022. As a point of reference, between 2017 and 2019, we averaged over 260 new well connects per year at a time when Henry Hub prices averaged below $3.00 MMbtu and WTI averaged below $60 per barrel. At current strip pricing levels, we believe that nearly all of the remaining inventory behind our gas and crude systems would be economic to develop. Furthermore, through a combination of industry consolidation and capital discipline, our customers have significantly improved their balance sheets and financial capability to responsibly increase development activity on the high-quality acreage behind our systems as economic conditions warrant. While our current 2022 guidance levels do not indicate the beginning of the U-shape recovery that we have been anticipating, we continue to expect that drilling activity behind our systems will increase as our customers gain further confidence that the fundamentals underlying the current commodity price outlook will hold in the future. Last year is a good example of how customer plans can change throughout the year. Initially we expected approximately 60 new wells based on customer plans as of February 2021, and by the end of the second quarter, those plans increased to approximately 95 new wells, which was a key driver for increasing our 2021 guidance range in June of last year. Similar to last year, we plan to provide updated 2022 guidance if we expect the outlook to be materially different than our initial guidance range. In the meantime, we will continue to focus on maximizing free cash flow and reducing debt, providing safe, efficient and reliable operations for our customers and a positive and safe work environment for our employees."
New Business Segments
As previously announced, during the fourth quarter of 2021 we implemented changes to our reportable segments. The new segment reporting resulted from changes enacted to optimize commercial efforts and our geographic workforce in order to better align our commercial, engineering and operational capabilities. The five reportable segments we will utilize going forward are described below, along with a management categorization of the commodity that has the most influence on customer drilling and completion decisions:
•Natural gas price driven: Our cash flows in the Northeast, Piceance and Barnett segments are significantly influenced by the price of natural gas because the drilling, completion and recompletion decisions by our customers in these segments are based on well economics most heavily impacted by the price of natural gas and natural gas liquids. Increased upstream activity by our customers in these basins therefore result in higher throughput and cash flows for those segments in which we collect fees for gathering natural gas or natural gas liquids.
◦Northeast – Includes our wholly owned midstream assets located in the Utica and Marcellus shale plays and our equity method investment in Ohio Gathering that is focused on the Utica Shale
◦Piceance – Includes our wholly owned midstream assets located in the Piceance Basin
◦Barnett – Includes our wholly owned midstream assets located in the Barnett Shale
•Oil price driven: Customer activity and our cash flows in the Permian and Rockies segments are significantly influenced by the price of oil because the drilling and completion decisions by our customers in these segments are based on well economics most heavily impacted by the price of oil. Decisions to drill and complete wells in these basins therefore result in higher throughput and cash flows for our midstream assets in which we collect fees for gathering or processing hydrocarbons, gathering produced water, or transporting natural gas.
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EXHIBIT 99.1
◦Permian – Includes our wholly owned midstream assets located in the Permian Basin and our equity method investment in the Double E Pipeline
◦Rockies – Includes our wholly owned midstream assets located in the Williston Basin and the DJ Basin
A comparison of prior and current reportable segments is listed in the table below for illustrative purposes.
| Prior Reportable Segment(s) | New Reportable Segment | ||||
| Utica Shale, Ohio Gathering, Marcellus Shale | Northeast | ||||
| Piceance Basin | Piceance | ||||
| Barnett Shale | Barnett | ||||
| Permian Basin, Double E (new) | Permian | ||||
| Williston Basin, DJ Basin | Rockies | ||||
2022 Guidance
SMLP is releasing guidance for 2022, which is summarized in the table below. These projections are subject to risks and uncertainties as described in the "Forward-Looking Statements" section at the end of the release.
We have taken a similar approach to our 2022 guidance range that we did with our 2021 guidance range. If our producer customers hit their production targets and upper end of planned well connects, as they did in 2021, we would expect to be near the high end of our 2022 guidance range. We believe the midpoint of our guidance range reflects a conservative, yet appropriate, level of risking to the most recent drill schedules and volume forecasts provided by our customers.
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EXHIBIT 99.1
| ($ in millions) | 2022 Guidance Range | |||||||||||||||||||
| Low | High | |||||||||||||||||||
| Well Connections | Average (2017 - 2019) | |||||||||||||||||||
| Northeast (includes OGC) | 61 | 31 | 44 | |||||||||||||||||
| Piceance | 50 | 17 | 17 | |||||||||||||||||
| Barnett | 9 | 4 | 11 | |||||||||||||||||
| Permian | 8 | 4 | 6 | |||||||||||||||||
| Rockies | 134 | 20 | 30 | |||||||||||||||||
| Total | 262 | 76 | 108 | |||||||||||||||||
| Natural Gas Throughput (MMcf/d) | ||||||||||||||||||||
| Northeast (excludes OGC) | 636 | 700 | ||||||||||||||||||
| Piceance | 299 | 303 | ||||||||||||||||||
| Barnett | 188 | 200 | ||||||||||||||||||
| Permian (excludes Double E) | 17 | 32 | ||||||||||||||||||
| Rockies | 32 | 35 | ||||||||||||||||||
| Total | 1,172 | 1,270 | ||||||||||||||||||
| Rockies Liquids Throughput (Mbbl/d) | 60 | 63 | ||||||||||||||||||
| OGC Natural Gas Throughput (MMcf/d, gross) | 602 | 681 | ||||||||||||||||||
| Double E Natural Gas Throughput (MMcf/d, gross) | 195 | 265 | ||||||||||||||||||
| Adjusted EBITDA | ||||||||||||||||||||
| Northeast | $68 | $77 | ||||||||||||||||||
| Piceance | 60 | 63 | ||||||||||||||||||
| Barnett | 26 | 28 | ||||||||||||||||||
| Permian | 18 | 25 | ||||||||||||||||||
| Rockies | 53 | 57 | ||||||||||||||||||
| Unallocated G&A, Other | (30) | (30) | ||||||||||||||||||
| Total | $195 | $220 | ||||||||||||||||||
| Capital Expenditures | ||||||||||||||||||||
| Growth | $10 | $20 | ||||||||||||||||||
| Maintenance | $10 | $15 | ||||||||||||||||||
| Total | $20 | $35 | ||||||||||||||||||
| Investment in Double E equity method investee | $10 | $10 | ||||||||||||||||||
We expect approximately 75 to 110 well connections in 2022, which remains significantly below pre-COVID levels averaging 262 well connections per year from 2017 through 2019 in a less favorable commodity price environment. The current commodity price environment should support increasing development activity and we believe if prices remain strong, we will begin to see producers increase activity behind our systems. We continue to see producers drill longer laterals, with several 2022 well connections expected to have 15,000’ laterals, which helps mitigate the impact of limited well connections. We are encouraged by the level of activity we expect in the Barnett and Piceance, as customers in these areas take advantage of the favorable commodity price environment. Of our
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EXHIBIT 99.1
expected 2022 well connections, 34 wells are either online, DUCs or have a rig present. The remaining new wells expected in our 2022 forecast are permitted and have been recently affirmed by our customers.
We expect our wholly owned natural gas gathering system throughput to range from approximately 1,172 MMcf/d to 1,270 MMcf/d, as compared to 1,356 MMcf/d in 2021. The year-over-year expected decline is primarily due to natural production declines and limited expected well connections in the Northeast, Permian and Rockies. OGC gross volume throughput is expected to range from approximately 602 MMcf/d to 681 MMcf/d, as compared to 526 MMcf/d in 2021, representing over 20% year-over-year growth at the mid-point. With the commercial operation of Double E commencing in November 2021, we expect Double E throughput to increase throughout the course of 2022, with average annual gross throughput ranging from approximately 195 MMcf/d to 265 MMcf/d. Given nearly 90 active rigs in New Mexico, we are optimistic about overall volume growth in the basin and the potential for additional firm take-or-pay contracts. Double E benefits from existing take-or-pay contracts of 585 MMcf/d currently, contractually increasing to 810 MMcf/d beginning in November 2022, 985 MMcf/d beginning in November 2023 and 1.0 Bcf/d beginning in November 2024, leaving only 350 MMcf/d of remaining long-term capacity on the pipeline before an expansion is required. Liquids volumes are expected to remain relatively flat year-over-year, ranging from 60 Mbbl/d to 63 Mbbl/d, despite no well connections from certain key customers to whom we provide both crude oil and produced water gathering services.
Adjusted EBITDA is expected to range from $195 million to $220 million, a decrease from 2021 primarily due to limited drilling and completion activity, an approximately $12 million reduction in MVC shortfall payments that expired in 2021, $7 million in energy management and COVID-19 related tax credits in 2021 and approximately $5 million of one-time operating expenses expected in 2022. We are optimistic that we will find ways to mitigate the increasing pressure of inflation on our operating costs and believe that the approximately $5 million of expected one-time operating expenses in 2022 will mitigate operating expenses beginning in 2023.
Our 2022 capital expenditure guidance of $20 million to $35 million, excluding Double E, is presented on a gross basis and does not include asset sales or capital reimbursements related to specific development projects with certain customers. We do expect to continue to monetize latent inventory, or other underutilized assets, which is not reflected in our financial guidance. In 2021, we sold approximately $8 million of such assets and have sold approximately $2 million to date in 2022. Our full year 2022 growth capex guidance range of $10 million to $20 million, excluding Double E, is dependent on new well connect activity and is expected to be directed towards new pad connections in our Northeast and Rockies segments. All other expected well connections are either on existing pad sites, or will be delivered to our gathering systems. We also expect that the vast majority, if not all, of the remaining $10 million investment in Double E will be funded with cash-on-hand at our unrestricted subsidiaries, or through Double E distributions generated from operations. We expect approximately $10 million to $15 million of maintenance capex, an increase relative to our 2021 maintenance capex of $8 million, primarily due to approximately $6 million of expected one-time capital expenditures related to certain asset integrity initiatives and modifications to assets for emission reductions.
In 2022, we expect to generate cash flow after interest expense, capital expenditures, investments in Double E and other cash expenditures of $65 million to $85 million, which we plan to utilize to further reduce our indebtedness.
Fourth Quarter 2021 Business Highlights
In the fourth quarter of 2021, SMLP’s average daily natural gas throughput for its wholly owned operated systems decreased by 2.0% to 1,307 MMcf/d, and liquids volumes decreased by 1.6% to 62 Mbbl/d, relative to the third quarter of 2021. In November 2021, Double E Pipeline commenced operations and began transporting residue gas from the Northern Delaware Basin to the Waha hub in Texas, resulting in an average of 124 MMcf/d of gross volumes transported since commissioning and approximately $1.9 million of adjusted EBITDA net to SMLP for the fourth quarter of 2021. SMLP’s customers are currently operating four drilling rigs on acreage behind SMLP's gathering systems, and there are approximately 34 new wells that were already connected to the system, have been drilled or are currently under development.
Natural gas price driven segments:
•Natural gas price driven segments had combined quarterly segment adjusted EBITDA of $45.1 million and combined capital expenditures of $5.1 million in the fourth quarter of 2021.
•Northeast segment adjusted EBITDA totaled $19.0 million, an 8.2% decrease relative to the third quarter of 2021 driven by natural production declines of approximately 35 MMcf/d behind our SMU system, partially offset by 16 new wells, of which the majority were connected during the second half of the fourth quarter of
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EXHIBIT 99.1
2021. These new well connects included a new four well pad behind our SMU system, as well as four well connects behind our Mountaineer system in the Marcellus shale. The new four well pad behind the SMU system was connected in late November 2021 and averaged 96 MMcf/d while online, or approximately 75 MMcf/d for the fourth quarter of 2021. The Northeast segment has 15 wells that are either online, have been drilled, or are under development, which represents 48% of the midpoint for Northeast segment well connects in our 2022 guidance.
•Piceance segment adjusted EBITDA of $15.9 million decreased by 16.1% from the third quarter of 2021, primarily due to the expiration of an MVC at the end of September 2021 that contributed $3.4 million of adjusted EBITDA to the segment in the third quarter of 2021 and natural production declines, partially offset by volumes from 9 new wells that were connected during the quarter by one of our larger customers. These 9 wells represented the first new wells connected to our Piceance system since the third quarter of 2018 and contributed approximately 9.1 MMcf/d while online, averaging 7.6 MMcf/d for the fourth quarter of 2021. Based on its 2022 capital program, this same customer is planning to connect 17 wells, which have all been permitted towards the middle to latter part of 2022. This customer also has plans for another 74 wells behind our system in the 2023 to 2024 timeframe and has entered into a capital reimbursement agreement with SMLP so that planning activities for those well connections can be undertaken.
•Barnett segment adjusted EBITDA of $10.2 million increased by 5.7% from the third quarter of 2021, primarily due to a 21 MMcf/d increase in volume throughput driven by continued strong performance from the 7 wells that were turned-in-line in September of 2021. These wells continue to be some of the largest natural gas wells ever drilled in the Barnett Shale and averaged 47 MMcf/d during the fourth quarter of 2021. The low end of our 2022 guidance range includes four new well connects, of which all have been drilled.
Oil price driven segments
•Oil price driven segments generated $17.5 million of combined segment adjusted EBITDA in the fourth quarter of 2021 and had combined capital expenditures of $8.1 million.
•Permian segment EBITDA totaled $2.6 million in the fourth quarter of 2021, a $2.0 million increase relative to the third quarter of 2021 primarily due to the commencement of operations at Double E in mid-November 2021. Double E is an equity method investment, so the Permian segment is allocated SMLP's proportionate share of Double E EBITDA. There were no new wells connected behind the Permian gathering and processing system during the fourth quarter of 2021 and the 4 well pad that was expected to come online in December 2021 was delayed until 2022. In 2022, we currently expect limited activity behind our Permian gathering and processing system from our existing customers and for the majority of adjusted EBITDA for the segment to come from offloads and our proportionate share of Double E.
•Rockies segment EBITDA of $14.9 million decreased by 20.4% from the prior quarter primarily due to a one-time $1.8 million benefit from the settlement of a legal matter in the third quarter of 2021. In the Williston Basin, 16 new wells were connected to our crude gathering infrastructure; however, all of these wells were connected in November and December, resulting in limited impact to fourth quarter of 2021 performance. The Rockies segment has 11 wells that are either online, have been drilled or are under development, which represents approximately 55% of the midpoint for Rockies segment well connects in our 2022 guidance. We currently expect limited new well connect activity in the DJ Basin from our existing customers in 2022, but may benefit from additional volumes related to an offload agreement we are actively negotiating.
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EXHIBIT 99.1
The following table presents average daily throughput by reportable segment for the periods indicated:
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| Average daily throughput (MMcf/d): | |||||||||||||||||||||||
Northeast (2) | 710 | 813 | 765 | 726 | |||||||||||||||||||
| Rockies | 34 | 39 | 35 | 40 | |||||||||||||||||||
Permian (2) | 24 | 33 | 26 | 33 | |||||||||||||||||||
| Piceance | 317 | 347 | 326 | 364 | |||||||||||||||||||
| Barnett | 222 | 204 | 204 | 212 | |||||||||||||||||||
| Aggregate average daily throughput | 1,307 | 1,436 | 1,356 | 1,375 | |||||||||||||||||||
| Average daily throughput (Mbbl/d): | |||||||||||||||||||||||
| Rockies | 62 | 71 | 63 | 79 | |||||||||||||||||||
| Aggregate average daily throughput | 62 | 71 | 63 | 79 | |||||||||||||||||||
Ohio Gathering average daily throughput (MMcf/d) (1) | 530 | 621 | 526 | 571 | |||||||||||||||||||
Double E average daily throughput (MMcf/d) (3) | 58 | – | 15 | – | |||||||||||||||||||
(1)Gross basis, represents 100% of volume throughput for Ohio Gathering, subject to a one-month lag.
(2)Exclusive of Ohio Gathering and Double E due to equity method accounting.
(3)Gross, basis, represents 100% of volume throughput for Double E.
The following table presents adjusted EBITDA by reportable segment for the periods indicated:
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| (In thousands) | (In thousands) | ||||||||||||||||||||||
Reportable segment adjusted EBITDA (1): | |||||||||||||||||||||||
Northeast (2) | $ | 19,013 | $ | 22,969 | $ | 83,287 | $ | 85,854 | |||||||||||||||
| Rockies | 14,911 | 15,861 | 64,517 | 71,509 | |||||||||||||||||||
Permian (3) | 2,600 | (62) | 6,614 | 5,744 | |||||||||||||||||||
| Piceance | 15,865 | 22,026 | 76,131 | 88,820 | |||||||||||||||||||
| Barnett | 10,187 | 7,617 | 36,729 | 32,093 | |||||||||||||||||||
| Total | $ | 62,576 | $ | 68,411 | $ | 267,278 | $ | 284,020 | |||||||||||||||
Less: Corporate and Other (4) | 7,870 | 6,620 | 28,855 | 31,905 | |||||||||||||||||||
| Adjusted EBITDA | $ | 54,706 | $ | 61,791 | $ | 238,423 | $ | 252,115 | |||||||||||||||
__________
(1)We define segment adjusted EBITDA as total revenues less total costs and expenses, plus (i) other income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit-based and noncash compensation, (vii) impairments and (viii) other noncash expenses or losses, less other noncash income or gains.
(2)Includes our proportional share of adjusted EBITDA for Ohio Gathering, subject to a one-month lag. We define proportional adjusted EBITDA for our equity method investees as the product of (i) total revenues less total expenses, excluding impairments and other noncash income or expense items and (ii) amortization for deferred contract costs; multiplied by our ownership interest during the respective period.
(3)Includes our proportional share of adjusted EBITDA for Double E. We define proportional adjusted EBITDA for our equity method investees as the product of total revenues less total expenses, excluding impairments and other noncash income or expense items; multiplied by our ownership interest during the respective period.
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EXHIBIT 99.1
(4)Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items and natural gas and crude oil marketing services.
Capital Expenditures
Capital expenditures totaled $13.3 million in the fourth quarter of 2021, inclusive of maintenance capital expenditures of $3.2 million. Capital expenditures in the fourth quarter of 2021 were primarily related to growth projects to connect new pad sites in our Northeast, Rockies and Permian segments.
| Year Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
Cash paid for capital expenditures (1): | |||||||||||
| Northeast | $ | 11,237 | $ | 7,657 | |||||||
| Rockies | 9,875 | 21,596 | |||||||||
| Permian | 2,042 | 7,014 | |||||||||
| Piceance | 579 | 1,370 | |||||||||
| Barnett | 766 | 1,878 | |||||||||
| Total reportable segment capital expenditures | $ | 24,499 | $ | 39,515 | |||||||
| Corporate and Other | 531 | 3,613 | |||||||||
| Total cash paid for capital expenditures | $ | 25,030 | $ | 43,128 | |||||||
__________
(1)Excludes cash paid for capital expenditures by Ohio Gathering and Double E due to equity method accounting.
Capital & Liquidity
As of December 31, 2021, SMLP had $267 million drawn under its $400 million ABL Revolver and $109.1 million of borrowing availability, after accounting for $23.9 million of issued, but undrawn letters of credit. As of December 31, 2021, SMLP's gross availability based on the borrowing base calculation in the credit agreement was $691 million, which is $291 million greater than the $400 million of lender commitments to the ABL Revolver. As of December 31, 2021 SMLP was in compliance with all financial covenants, including interest coverage of 4.3x relative to a minimum interest coverage covenant of 2.0x and first lien leverage ratio of 1.1x relative to a maximum first lien leverage ratio of 2.5x. As of December 31, 2021, SMLP reported a total leverage ratio of 5.16x and is no longer subject to a total leverage ratio covenant.
As of December 31, 2021, the Permian Transmission Credit Facility was fully drawn and $160 million was outstanding. In January 2022, the Permian Transmission Credit Facility was converted to a term loan and mandatory quarterly amortization will commence in March of 2022. The Permian Transmission Term Loan remains non-recourse to SMLP.
MVC Shortfall Payments
SMLP billed its customers $16.7 million in the fourth quarter of 2021 related to MVC shortfalls. For those customers that do not have MVC shortfall credit banking mechanisms in their gathering agreements, the MVC shortfall payments are accounted for as gathering revenue in the period in which they are earned. In the fourth quarter of 2021, SMLP recognized $10.3 million of gathering revenue associated with MVC shortfall payments. SMLP had no adjustments to MVC shortfall payments in the fourth quarter of 2021. SMLP’s MVC shortfall payment mechanisms contributed $10.3 million of total adjusted EBITDA in the fourth quarter of 2021 and $51.1 million of total adjusted EBITDA for full year 2021.
8
EXHIBIT 99.1
| Three Months Ended December 31, 2021 | |||||||||||||||||||||||
| MVC Billings | Gathering revenue | Adjustments to MVC shortfall payments | Net impact to adjusted EBITDA | ||||||||||||||||||||
Net change in deferred revenue related to MVC shortfall payments: | |||||||||||||||||||||||
| Piceance Basin | $ | 300 | $ | 300 | $ | — | $ | 300 | |||||||||||||||
| Total net change | $ | 300 | $ | 300 | $ | — | $ | 300 | |||||||||||||||
| MVC shortfall payment adjustments: | |||||||||||||||||||||||
| Rockies | $ | 8,580 | $ | 2,145 | $ | — | $ | 2,145 | |||||||||||||||
| Piceance | 6,335 | 6,335 | — | 6,335 | |||||||||||||||||||
| Northeast | 1,470 | 1,470 | — | 1,470 | |||||||||||||||||||
| Total MVC shortfall payment adjustments | $ | 16,385 | $ | 9,950 | $ | — | $ | 9,950 | |||||||||||||||
Total (1) | $ | 16,685 | $ | 10,250 | $ | — | $ | 10,250 | |||||||||||||||
__________
(1)Exclusive of Ohio Gathering and Double E due to equity method accounting.
| Year Ended December 31, 2021 | |||||||||||||||||||||||
| MVC Billings | Gathering revenue | Adjustments to MVC shortfall payments | Net impact to adjusted EBITDA | ||||||||||||||||||||
Net change in deferred revenue related to MVC shortfall payments: | |||||||||||||||||||||||
| Piceance | $ | 11,307 | $ | 11,307 | $ | — | $ | 11,307 | |||||||||||||||
| Total net change | $ | 11,307 | $ | 11,307 | $ | — | $ | 11,307 | |||||||||||||||
| MVC shortfall payment adjustments: | |||||||||||||||||||||||
| Rockies | $ | 8,580 | $ | 8,580 | $ | — | $ | 8,580 | |||||||||||||||
| Piceance | 24,923 | 24,923 | — | 24,923 | |||||||||||||||||||
| Northeast | 6,248 | 6,248 | — | 6,248 | |||||||||||||||||||
| Total MVC shortfall payment adjustments | $ | 39,751 | $ | 39,751 | $ | — | $ | 39,751 | |||||||||||||||
Total (1) | $ | 51,058 | $ | 51,058 | $ | — | $ | 51,058 | |||||||||||||||
__________
(1)Exclusive of Ohio Gathering and Double E due to equity method accounting.
Quarterly Distribution
The board of directors of SMLP’s general partner continued to suspend cash distributions payable on its common units and on its 9.50% Series A fixed-to-floating rate cumulative redeemable perpetual preferred units (the "Series A Preferred Units") for the period ended December 31, 2021. Unpaid distributions on the Series A Preferred Units will continue to accumulate. Subsequent to year end, SMLP closed a preferred-for-common unit exchange that eliminated $16.6 million of accumulated distributions.
Fourth Quarter 2021 Earnings Call Information
SMLP will host a conference call at 10:00 a.m. Eastern on Friday, February 25, 2022, to discuss its quarterly operating and financial results. Interested parties may participate in the call by dialing 847-585-4405 or toll-free
9
EXHIBIT 99.1
888-771-4371 and entering the passcode 50277720. The conference call, live webcast and archive of the call can be accessed through the Investors section of SMLP's website at www.summitmidstream.com.
Use of Non-GAAP Financial Measures
We report financial results in accordance with U.S. generally accepted accounting principles (“GAAP”). We also present adjusted EBITDA and Distributable Cash Flow, non-GAAP financial measures.
Adjusted EBITDA
We define adjusted EBITDA as net income or loss, plus interest expense, income tax expense, depreciation and amortization, our proportional adjusted EBITDA for equity method investees, adjustments related to MVC shortfall payments, adjustments related to capital reimbursement activity, unit-based and noncash compensation, impairments, items of income or loss that we characterize as unrepresentative of our ongoing operations and other noncash expenses or losses, income tax benefit, income (loss) from equity method investees and other noncash income or gains. Because adjusted EBITDA may be defined differently by other entities in our industry, our definition of this non-GAAP financial measure may not be comparable to similarly titled measures of other entities, thereby diminishing its utility.
Management uses adjusted EBITDA in making financial, operating and planning decisions and in evaluating our financial performance. Furthermore, management believes that adjusted EBITDA may provide external users of our financial statements, such as investors, commercial banks, research analysts and others, with additional meaningful comparisons between current results and results of prior periods as they are expected to be reflective of our core ongoing business.
Adjusted EBITDA is used as a supplemental financial measure to assess:
•the ability of our assets to generate cash sufficient to make future potential cash distributions and support our indebtedness;
•the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•our operating performance and return on capital as compared to those of other entities in the midstream energy sector, without regard to financing or capital structure;
•the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities; and
•the financial performance of our assets without regard to (i) income or loss from equity method investees, (ii) the impact of the timing of minimum volume commitments shortfall payments under our gathering agreements or (iii) the timing of impairments or other income or expense items that we characterize as unrepresentative of our ongoing operations.
Adjusted EBITDA has limitations as an analytical tool and investors should not consider it in isolation or as a substitute for analysis of our results as reported under GAAP. For example:
•certain items excluded from adjusted EBITDA are significant components in understanding and assessing an entity's financial performance, such as an entity's cost of capital and tax structure;
•adjusted EBITDA does not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
•adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital needs; and
•although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and adjusted EBITDA does not reflect any cash requirements for such replacements.
We compensate for the limitations of adjusted EBITDA as an analytical tool by reviewing the comparable GAAP financial measures, understanding the differences between the financial measures and incorporating these data points into our decision-making process.
10
EXHIBIT 99.1
Distributable Cash Flow
We define Distributable Cash Flow as adjusted EBITDA, as defined above, less cash interest paid, cash paid for taxes, net interest expense accrued and paid on the senior notes, and maintenance capital expenditures.
We do not provide the GAAP financial measures of net income or loss or net cash provided by operating activities on a forward-looking basis because we are unable to predict, without unreasonable effort, certain components thereof including, but not limited to, (i) income or loss from equity method investees and (ii) asset impairments. These items are inherently uncertain and depend on various factors, many of which are beyond our control. As such, any associated estimate and its impact on our GAAP performance and cash flow measures could vary materially based on a variety of acceptable management assumptions.
About Summit Midstream Partners, LP
SMLP is a value-driven limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States. SMLP provides natural gas, crude oil and produced water gathering, processing and transportation services pursuant to primarily long-term, fee-based agreements with customers and counterparties in six unconventional resource basins: (i) the Appalachian Basin, which includes the Utica and Marcellus shale formations in Ohio and West Virginia; (ii) the Williston Basin, which includes the Bakken and Three Forks shale formations in North Dakota; (iii) the Denver-Julesburg Basin, which includes the Niobrara and Codell shale formations in Colorado and Wyoming; (iv) the Permian Basin, which includes the Bone Spring and Wolfcamp formations in New Mexico; (v) the Fort Worth Basin, which includes the Barnett Shale formation in Texas; and (vi) the Piceance Basin, which includes the Mesaverde formation as well as the Mancos and Niobrara shale formations in Colorado. SMLP has an equity method investment in Double E Pipeline, LLC, which provides interstate natural gas transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas. SMLP also has an equity method investment in Ohio Gathering, which operates extensive natural gas gathering and condensate stabilization infrastructure in the Utica Shale in Ohio. SMLP is headquartered in Houston, Texas.
Forward-Looking Statements
This press release includes certain statements concerning expectations for the future that are forward-looking within the meaning of the federal securities laws. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words "expect," "intend," "plan," "anticipate," "estimate," "believe," "will be," "will continue," "will likely result," and similar expressions, or future conditional verbs such as "may," "will," "should," "would," and "could." In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies and possible actions taken by us or our subsidiaries are also forward-looking statements. Forward-looking statements also contain known and unknown risks and uncertainties (many of which are difficult to predict and beyond management’s control) that may cause SMLP’s actual results in future periods to differ materially from anticipated or projected results. An extensive list of specific material risks and uncertainties affecting SMLP is contained in its 2020 Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “SEC”) on March 4, 2021, as amended and updated from time to time. Any forward-looking statements in this press release are made as of the date of this press release and SMLP undertakes no obligation to update or revise any forward-looking statements to reflect new information or events.
11
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
| December 31, 2021 | December 31, 2020 | ||||||||||
| (In thousands) | |||||||||||
| ASSETS | |||||||||||
| Cash and cash equivalents | $ | 7,349 | $ | 15,544 | |||||||
| Restricted cash | 12,223 | — | |||||||||
| Accounts receivable | 62,121 | 61,932 | |||||||||
| Other current assets | 5,676 | 4,623 | |||||||||
| Total current assets | 87,369 | 82,099 | |||||||||
| Property, plant and equipment, net | 1,726,082 | 1,813,810 | |||||||||
| Intangible assets, net | 172,927 | 199,566 | |||||||||
| Investment in equity method investees | 523,196 | 392,740 | |||||||||
| Other noncurrent assets | 12,888 | 11,602 | |||||||||
| TOTAL ASSETS | $ | 2,522,462 | $ | 2,499,817 | |||||||
| LIABILITIES AND CAPITAL | |||||||||||
| Trade accounts payable | $ | 10,498 | $ | 11,878 | |||||||
| Accrued expenses | 14,462 | 13,036 | |||||||||
| Deferred revenue | 10,374 | 9,988 | |||||||||
| Ad valorem taxes payable | 8,570 | 9,086 | |||||||||
| Accrued compensation and employee benefits | 11,019 | 9,658 | |||||||||
| Accrued interest | 12,737 | 8,007 | |||||||||
| Accrued environmental remediation | 3,068 | 1,392 | |||||||||
| Accrued settlement payable | 4,833 | — | |||||||||
| Other current liabilities | 3,676 | 5,363 | |||||||||
| Total current liabilities | 79,237 | 68,408 | |||||||||
| Long-term debt, net | 1,355,072 | 1,347,326 | |||||||||
| Noncurrent deferred revenue | 42,570 | 48,250 | |||||||||
| Noncurrent accrued environmental remediation | 2,538 | 1,537 | |||||||||
| Other noncurrent liabilities | 32,357 | 21,747 | |||||||||
| Total liabilities | 1,511,774 | 1,487,268 | |||||||||
Commitments and contingencies | |||||||||||
| Mezzanine Capital | |||||||||||
| Subsidiary Series A Preferred Units | 106,325 | 89,658 | |||||||||
| Partners' Capital | |||||||||||
| Series A Preferred Units | 169,769 | 174,425 | |||||||||
| Common limited partner capital | 734,594 | 748,466 | |||||||||
Total partners' capital | 904,363 | 922,891 | |||||||||
TOTAL LIABILITIES AND CAPITAL | $ | 2,522,462 | $ | 2,499,817 | |||||||
12
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| (In thousands, except per-unit amounts) | |||||||||||||||||||||||
| Revenues: | |||||||||||||||||||||||
| Gathering services and related fees | $ | 66,201 | $ | 73,125 | $ | 281,705 | $ | 302,792 | |||||||||||||||
| Natural gas, NGLs and condensate sales | 23,467 | 14,073 | 82,768 | 49,319 | |||||||||||||||||||
| Other revenues | 9,546 | 9,212 | 36,145 | 31,362 | |||||||||||||||||||
Total revenues | 99,214 | 96,410 | 400,618 | 383,473 | |||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||
| Cost of natural gas and NGLs | 23,795 | 13,708 | 81,969 | 36,653 | |||||||||||||||||||
| Operation and maintenance | 19,297 | 20,899 | 74,178 | 86,030 | |||||||||||||||||||
General and administrative (1) | 9,752 | 33,530 | 58,166 | 73,438 | |||||||||||||||||||
| Depreciation and amortization | 31,210 | 29,331 | 119,076 | 118,132 | |||||||||||||||||||
| Transaction costs | 401 | 1,049 | 1,677 | 2,993 | |||||||||||||||||||
| Gain on asset sales, net | (17) | (37) | (369) | (307) | |||||||||||||||||||
| Long-lived asset impairment | 8,378 | 8,614 | 10,151 | 13,089 | |||||||||||||||||||
Total costs and expenses | 92,816 | 107,094 | 344,848 | 330,028 | |||||||||||||||||||
| Other income (expense), net | 919 | (596) | (613) | 48 | |||||||||||||||||||
| Loss on ECP Warrants | — | — | (13,634) | — | |||||||||||||||||||
| Interest expense | (21,171) | (14,058) | (66,156) | (78,894) | |||||||||||||||||||
Gain on early extinguishment of debt (2) | (3,523) | 124,137 | (3,523) | 203,062 | |||||||||||||||||||
Income (loss) before income taxes and equity method investment income | (17,377) | 98,799 | (28,156) | 177,661 | |||||||||||||||||||
| Income tax benefit (expense) | (14) | 42 | 327 | 146 | |||||||||||||||||||
| Income from equity method investees | 1,186 | 4,125 | 7,880 | 11,271 | |||||||||||||||||||
Net income (loss) | $ | (16,205) | $ | 102,966 | $ | (19,949) | $ | 189,078 | |||||||||||||||
| Net income (loss) per limited partner unit: | |||||||||||||||||||||||
| Common unit – basic | $ | (3.42) | $ | 30.45 | $ | (6.57) | $ | 73.22 | |||||||||||||||
| Common unit – diluted | $ | (3.42) | $ | 29.73 | $ | (6.57) | $ | 71.19 | |||||||||||||||
| Weighted-average limited partner units outstanding: | |||||||||||||||||||||||
| Common units – basic | 7,170 | 4,894 | 6,741 | 3,592 | |||||||||||||||||||
| Common units – diluted | 7,170 | 5,013 | 6,741 | 3,694 | |||||||||||||||||||
__________
(1)For the year ended December 31, 2021, the amount includes a $22.4 million loss related to the Blacktail Release. For the three months ended December 31, 2020, the amount includes a $17.0 loss related to the Blacktail Release and $5.6 million of restructuring expenses. For the year ended December 31, 2020, the amount includes a $17.0 million loss related to the Blacktail Release and $9.0 million of restructuring expenses.
(2)For the year ended December 31, 2020, the amount includes early extinguishment of debt, primarily related to liability management initiatives undertaken during 2020 that resulted in a $86.4 million gain from the Open Market Repurchases, a $23.3 million gain from the Debt Tender Offers, and a $93.9 million gain from our TL Restructuring.
13
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED OTHER FINANCIAL AND OPERATING DATA
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Other financial data: | |||||||||||||||||||||||
| Net income (loss) | $ | (16,205) | $ | 102,966 | $ | (19,949) | $ | 189,078 | |||||||||||||||
| Net cash provided by operating activities | 37,368 | 51,782 | 165,099 | 198,589 | |||||||||||||||||||
| Capital expenditures | 13,250 | 7,816 | 25,030 | 43,128 | |||||||||||||||||||
| Contributions to equity method investees | 46,590 | 7,855 | (148,699) | (99,927) | |||||||||||||||||||
| Adjusted EBITDA | 54,706 | 61,791 | 238,423 | 252,115 | |||||||||||||||||||
Cash flow available for distributions (1) | $ | 29,924 | $ | 44,755 | $ | 168,288 | $ | 162,835 | |||||||||||||||
Distributions (2) | n/a | n/a | n/a | n/a | |||||||||||||||||||
| Operating data: | |||||||||||||||||||||||
Aggregate average daily throughput – natural gas (MMcf/d) | 1,307 | 1,436 | 1,356 | 1,375 | |||||||||||||||||||
| Aggregate average daily throughput – liquids (Mbbl/d) | 62 | 71 | 63 | 79 | |||||||||||||||||||
Ohio Gathering average daily throughput (MMcf/d) (3) | 530 | 621 | 526 | 571 | |||||||||||||||||||
Double E average daily throughput (MMcf/d) (4) | 58 | – | 15 | – | |||||||||||||||||||
__________
(1)Cash flow available for distributions is also referred to as Distributable Cash Flow, or DCF.
(2)Represents distributions declared and ultimately paid or expected to be paid to preferred and common unitholders in respect of a given period. On May 3, 2020, the board of directors of SMLP’s general partner announced an immediate suspension of the cash distributions payable on its preferred and common units.
(3)Gross basis, represents 100% of volume throughput for Ohio Gathering, subject to a one-month lag.
(4)Gross, basis, represents 100% of volume throughput for Double E.
14
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
Reconciliations of net income or loss to adjusted EBITDA and Distributable Cash Flow: | |||||||||||||||||||||||
| Net income | $ | (16,205) | $ | 102,966 | $ | (19,949) | $ | 189,078 | |||||||||||||||
| Add: | |||||||||||||||||||||||
| Interest expense | 21,171 | 14,058 | 66,156 | 78,894 | |||||||||||||||||||
| Income tax (benefit) expense | 14 | (42) | (327) | (146) | |||||||||||||||||||
| Depreciation and amortization (1) | 31,425 | 29,565 | 119,995 | 119,070 | |||||||||||||||||||
Proportional adjusted EBITDA for equity method investees (2) | 8,619 | 8,474 | 29,022 | 31,056 | |||||||||||||||||||
Adjustments related to MVC shortfall payments (3) | — | 859 | — | — | |||||||||||||||||||
Adjustments related to capital reimbursement activity (4) | (1,552) | (619) | (6,571) | (1,395) | |||||||||||||||||||
| Unit-based and noncash compensation | 861 | 1,920 | 4,744 | 8,111 | |||||||||||||||||||
| (Gain) loss on early extinguishment of debt | 3,523 | (124,137) | 3,523 | (203,062) | |||||||||||||||||||
| Gain on asset sales, net | (17) | (37) | (369) | (307) | |||||||||||||||||||
| Long-lived asset impairment | 8,378 | 8,614 | 10,151 | 13,089 | |||||||||||||||||||
| Other, net (5) | (325) | 24,295 | 39,928 | 28,998 | |||||||||||||||||||
| Less: | |||||||||||||||||||||||
| Income from equity method investees | 1,186 | 4,125 | 7,880 | 11,271 | |||||||||||||||||||
| Adjusted EBITDA | $ | 54,706 | $ | 61,791 | $ | 238,423 | $ | 252,115 | |||||||||||||||
| Less: | |||||||||||||||||||||||
| Cash interest paid | 17,302 | 17,009 | 57,655 | 79,450 | |||||||||||||||||||
| Cash paid for taxes | — | — | 191 | 190 | |||||||||||||||||||
| Senior notes interest adjustment (6) | 4,245 | (3,091) | 4,757 | (4,487) | |||||||||||||||||||
| Maintenance capital expenditures | 3,235 | 3,118 | 7,532 | 14,127 | |||||||||||||||||||
| Cash flow available for distributions (7) | $ | 29,924 | $ | 44,755 | $ | 168,288 | $ | 162,835 | |||||||||||||||
__________
(1)Includes the amortization expense associated with our favorable gas gathering contracts as reported in other revenues.
(2)Reflects our proportionate share of Double E and Ohio Gathering (subject to a one-month lag) adjusted EBITDA.
(3)Adjustments related to MVC shortfall payments are recognized ratably over the term of the associated MVC.
(4)Adjustments related to capital reimbursement activity represent contributions in aid of construction revenue recognized in accordance with Accounting Standards Update No. 2014-09 Revenue from Contracts with Customers (“Topic 606”).
(5)Represents items of income or loss that we characterize as unrepresentative of our ongoing operations. For the year ended December 31, 2021, the amount includes $22.2 million of losses related to the Blacktail Release and a $13.6 million loss related to the ECP Warrants. For the three months ended December 31, 2020, the amount includes a $17.0 million loss related to the Blacktail Release, $5.6 million of restructuring expenses and $1.0 million of transaction costs associated with the GP Buy-In Transaction. For the year ended December 31, 2020, the amount includes a $17.0 million loss related to the Blacktail Release, $9.0 million of restructuring expenses and $3.2 million of transaction costs associated with the GP Buy-In Transaction.
(6)Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. Interest on the 5.5% senior notes was paid in cash semi-annually in arrears on February 15 and August 15. Interest on the 5.75% senior notes is paid in cash semi-annually in arrears on April 15 and October 15 until maturity in April 2025. Interest on the 8.5% senior notes is paid in cash semi-annually in arrears on April 15 and October 15 until maturity in October 2026.
15
(7)Represents cash flow available for distribution to preferred and common unitholders. Common distributions cannot be paid unless all accrued preferred distributions are paid. Cash flow available for distributions is also referred to as Distributable Cash Flow, or DCF.
16
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED RECONCILIATIONS TO NON-GAAP FINANCIAL MEASURES
| Year Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
Reconciliation of net cash provided by operating activities to adjusted EBITDA and distributable cash flow: | |||||||||||
| Net cash provided by operating activities | $ | 165,099 | $ | 198,589 | |||||||
| Add: | |||||||||||
| Interest expense, excluding amortization of debt issuance costs | 59,139 | 72,286 | |||||||||
| Income tax (benefit) expense | (327) | (146) | |||||||||
| Gain (loss) on ECP warrants and unsettled interest rate swaps | (14,414) | 259 | |||||||||
| Transaction costs | 1,677 | 3,913 | |||||||||
| Changes in operating assets and liabilities | (5,867) | (50,018) | |||||||||
| Proportional adjusted EBITDA for equity method investees (1) | 29,022 | 31,056 | |||||||||
| Adjustments related to capital reimbursement activity (2) | (6,571) | (1,395) | |||||||||
| Other, net (3) | 38,529 | 28,998 | |||||||||
| Less: | |||||||||||
| Distributions from equity method investees | 26,760 | 28,185 | |||||||||
| Noncash lease expense | 1,104 | 3,242 | |||||||||
| Adjusted EBITDA | $ | 238,423 | $ | 252,115 | |||||||
| Less: | |||||||||||
| Cash interest paid | 57,655 | 79,450 | |||||||||
| Cash paid for taxes | 191 | 190 | |||||||||
| Senior notes interest adjustment (4) | 4,757 | (4,487) | |||||||||
| Maintenance capital expenditures | 7,532 | 14,127 | |||||||||
| Cash flow available for distributions (5) | $ | 168,288 | $ | 162,835 | |||||||
__________
(1)Reflects our proportionate share of Double E and Ohio Gathering adjusted EBITDA, subject to a one-month lag.
(2)Adjustments related to capital reimbursement activity represent contributions in aid of construction revenue recognized in accordance with Accounting Standards Update No. 2014-09 Revenue from Contracts with Customers (“Topic 606”).
(3)Represents items of income or loss that we characterize as unrepresentative of our ongoing operations. For the year ended December 31, 2021, the amount includes $22.2 million of losses related to the Blacktail Release and a $13.6 million loss related to the ECP Warrants. For the year ended December 31, 2020, the amount includes a $17.0 million loss related to the Blacktail Release, $9.0 million of restructuring expenses and $3.2 million of transaction costs associated with the GP Buy-In Transaction.
(4)Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. Interest on the 5.5% senior notes is paid in cash semi-annually in arrears on February 15 and August 15 until maturity in August 2022. Interest on the 5.75% senior notes is paid in cash semi-annually in arrears on April 15 and October 15 until maturity in April 2025.
(5)Represents cash flow available for distribution to preferred and common unitholders. Common distributions cannot be paid unless all accrued preferred distributions are paid. Cash flow available for distributions is also referred to as Distributable Cash Flow, or DCF.
Contact: Ross Wong, Sr. Director, Corporate Development & Finance, 832-930-7512, ir@summitmidstream.com
SOURCE: Summit Midstream Partners, LP
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