ITEM 1. BUSINESS
Summit Midstream Partners, LP, a Delaware limited partnership (including its subsidiaries, collectively, “we”, “our”, “us”, "SMLP", or “the Partnership”), is a value-driven limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States. Our common units are listed and traded on the NYSE under the ticker symbol “SMLP.”
The Partnership was formed in May 2012. The Partnership’s executive offices are located at 910 Louisiana Street, Suite 4200, Houston, Texas 77002, and can be reached by phone at 832-413-4770. The Partnership also maintains regional field offices in close proximity to our areas of operation to support the operation and development of our midstream assets.
As a result of the GP Buy-In Transaction (as described below), the Partnership indirectly owns its General Partner, and the General Partner’s Board of Directors is comprised of a majority of independent directors. The Partnership’s Fourth Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) provides the Partnership’s common unitholders with voting rights in the election of the members of the Board of Directors on a staggered basis beginning in 2022.
Our Business Strategies
We operate a differentiated midstream platform that is built for long-term, sustainable value creation. Our integrated assets are strategically located in premier production basins and core demand centers, including the Williston Basin, DJ Basin, Utica Shale, Marcellus Shale, and Permian Basin. Our primary business objective is to provide cash flow stability for our stakeholders while growing prudently and profitably. We intend to accomplish this objective by executing the following strategies:
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Liability management. We seek to maximize unitholder value by reducing and extending, where appropriate, the Partnership’s indebtedness and other fixed capital obligations through a combination of opportunistic liability management transactions, operating cash flow, and other corporate transactions.
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Portfolio management. We seek to maximize unitholder value by strategically managing our portfolio of midstream assets and allocating capital based on appropriate risk-informed cash flow assumptions. This may include opportunistic divestitures, re-allocation of capital to new or existing areas, and development of joint ventures involving our existing midstream assets or new investment opportunities.
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Maintaining our focus on fee-based revenue with minimal direct commodity price exposure. We intend to maintain our focus on providing midstream services under primarily long-term and fee-based contracts. We believe that our focus on fee-based revenues with minimal direct commodity price exposure is essential to maintaining stable cash flows.
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Maintaining strong producer relationships to maximize utilization of all of our midstream assets. We have cultivated strong producer relationships by focusing on customer service, reliable project execution and by operating our assets safely and reliably over time. We believe that our strong producer relationships will create future opportunities to optimize the utilization of the gathering systems in our Legacy Areas and develop new midstream infrastructure in our Core Focus Areas.
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Continuing to prioritize safe and reliable operations. We believe that providing safe, reliable and efficient operations is a key component of our business strategy. We place a strong emphasis on employee training, operational procedures and enterprise technology, and we intend to continue promoting a high standard with respect to the efficiency of our operations and the safety of all of our constituents.
Recent Developments and Highlights
The following is a brief listing of significant developments since December 31, 2019. Additional information regarding these items may be found elsewhere in this Annual Report.
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GP Buy-In Transaction. In May 2020, the Partnership completed a simplification transaction (the “GP Buy-In Transaction”) whereby the Partnership acquired from its then private equity sponsor, Energy Capital Partners (“ECP”), (i) Summit Midstream Partners, LLC (“Summit Investments”), which owned the Partnership’s General Partner, (ii) through its indirect ownership of Summit Midstream Partners Holdings, LLC (“SMP Holdings”), 3,415,646 of its common units and (iii) the Deferred Purchase Price obligation receivable owed by the Partnership. Consideration paid to ECP included a $35.0 million cash payment and the issuance of warrants to purchase up to 666,667 common units. In connection with the closing of the GP Buy-In Transaction, ECP’s management resigned from the Board of Directors and ECP fully exited its investment in the Partnership (other than retaining the aforementioned warrants).
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Suspension of common and preferred unit distributions. In May 2020, and 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 March 31, 2020. The suspension of distributions enabled the Partnership to retain an incremental $76.0 million per annum of operating cash flow and reallocate this retained 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.
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Liability Management - Open Market Repurchases. Throughout 2020, the Partnership completed multiple open market repurchases of the 2022 Senior Notes and 2025 Senior Notes that resulted in the extinguishment of $32.4 million of face value of the 2022 Senior Notes and $201.8 million of face value of the 2025 Senior Notes (the “Open Market Repurchases”). 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 an $86.5 million gain on the extinguishment of debt related to these Open Market Repurchases during 2020.
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Liability Management - Debt Tender Offers. In September 2020, Summit Holdings and Finance Corp. (together with Summit Holdings, the “Co-Issuers”) completed cash tender offers (the “Debt 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 $48.7 million, and the Partnership recognized a $23.3 million gain on the extinguishment of debt related to the Debt Tender Offers during 2020.
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Liability Management - SMPH Term Loan Restructuring. In November 2020, the Partnership completed a consensual debt discharge and restructuring (the “TL Restructuring”) of SMP Holdings’ $155.2 million term loan (“SMPH Term Loan”). All of the lenders under the SMPH Term Loan (the “Term Loan Lenders”) participated in the TL Restructuring. As part of the TL Restructuring, the Partnership paid SMP Holdings $26.5 million in cash as consideration to fully settle the deferred purchase price obligation, which SMP Holdings then paid to the Term Loan Lenders. In addition, the Term Loan Lenders executed a strict foreclosure (the “Strict Foreclosure”) on the 2,306,972 common units pledged as collateral under the SMPH Term Loan in full satisfaction of SMP Holdings’ outstanding obligations under the SMPH Term Loan.
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Reverse Unit Split. On November 9, 2020, after the close of trading on the NYSE, the Partnership effected a 1-for-15 reverse unit split (the “Reverse Unit Split”) of its common units. The common units began trading on a split-adjusted basis on November 10, 2020. Pursuant to the Reverse Unit Split, common unitholders received one common unit for every 15 common units owned at the close of business on November 9, 2020. Immediately prior to the
Reverse Unit Split, there were 56,624,887 common units issued and outstanding and immediately after the Reverse Unit Split, the number of issued and outstanding common units decreased to 3,774,992.
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July 2020 Series A Preferred Unit Exchange. In July 2020, the Partnership completed an offer to exchange its Series A Preferred Units for newly issued common units (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 $66.5 million of the Series A Preferred Unit liquidation preference amount due as of the settlement date.
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December 2020 Series A Preferred Unit Tender. In December 2020, the Partnership completed a cash tender offer for its Series A Preferred Units (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 the Series A Preferred Unit liquidation preference amount due as of the settlement date.
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Double E Project FERC approval. In January 2021, Double E, a joint venture focused on the development of an interstate natural gas pipeline in which the Partnership indirectly owns a 70% equity interest and serves as the pipeline's operator and construction manager, received its Notice to Proceed (“NTP”) with construction, as well as approval of its implementation plan, from FERC. Prior to this, in October 2020, Double E received FERC approval of its application to construct and operate the Double E Project, pursuant to Section 7(c) of the Natural Gas Act. With the receipt of the 7(c) certificate and the NTP, construction on the Double E pipeline commenced in February 2021, and the pipeline is expected to be in-service by the end of 2021.
Our Midstream Assets
Our systems gather natural gas from pad sites, wells and central receipt points connected to our systems. Gathered natural gas volumes are then compressed, dehydrated, treated and/or processed for delivery to downstream pipelines serving processing plants and/or end users. We also contract with producers to gather crude oil and produced water from wells connected to our systems for delivery to downstream pipelines and third-party rail terminals in the case of crude oil and to third-party disposal wells in the case of produced water. We generally refer to all of the services our systems provide as gathering services.
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.
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Core Focus Areas. Core producing areas of basins in which we expect our gathering systems to experience greater long-term growth, driven by our customers’ ability to generate more favorable returns and support sustained drilling and completion activity in varying commodity price environments. In the near-term, we expect to concentrate the majority of our capital expenditures in our Core Focus Areas. Our Utica Shale, Ohio Gathering, Williston Basin, DJ Basin and Permian Basin reportable segments comprise our Core Focus Areas.
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Legacy Areas. Production basins in which we expect volume throughput on our gathering systems to experience relatively lower long-term growth compared to our Core Focus Areas, given that our customers require relatively higher commodity prices to support drilling and completion activities in these basins. Upstream production served by our gathering systems in our Legacy Areas is generally more mature, as compared to our Core Focus Areas, and the decline rates for volume throughput on our gathering systems in the Legacy Areas are typically lower as a result. We expect to continue to decrease our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments comprise our Legacy Areas.
Industry Overview and Commercial Arrangements
We compete with other midstream companies, producers and intrastate and interstate pipelines. Competition for volumes is primarily based on reputation, commercial terms, service levels, access to end-use markets, geographic proximity of existing assets to a producer's acreage and available capacity. We may also face competition to gather production outside of our AMIs and attract producer volumes to our gathering systems. Additionally, we could face incremental competition to the extent we make acquisitions.
We earn revenue by providing gathering, compression, treating and/or processing services pursuant to primarily long-term and fee-based gathering and processing agreements with some of the largest and most active producers in North America. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.
The significant features of our gathering and processing agreements and the gathering systems to which they relate are discussed in more detail below. For additional operating and financial performance information, on a consolidated basis and by reportable segment, see the "Results of Operations" section in Item 7. MD&A.
Areas of Mutual Interest. The vast majority of our gathering and processing agreements contain AMIs, some of which extend through 2036. The AMIs generally require that any production by our customers within the AMIs will be shipped on and/or processed by our assets. In general, our customers have not leased acreage that cover our entire AMIs but, to the extent that they have leased acreage, or lease additional acreage in the future, within our AMIs, any production from wells drilled by them within that AMI will be dedicated to our systems.
Under certain of our gathering agreements, we have agreed to construct pipeline laterals to connect our gathering systems to producer pad sites located within the AMI. However, in certain circumstances we may choose not to fund a pad connection opportunity presented by a customer or we may choose not to fund capital calls in Ohio Gathering if we believe that the investment would not meet our internal return expectations. Under this scenario, the customer may, in certain circumstances, construct the infrastructure itself and sell it to us at a price equal to their cost plus an applicable profit margin, or, in some cases, we may release the relevant acreage dedication from the AMI. For Ohio Gathering, our joint venture partner may elect to fund 100% of the capital calls, if we choose not to fund our proportionate share of a given capital call, which could reduce our ownership interests in OGC and/or OCC. For example, in 2020, we chose not to fund capital calls at OGC and OCC, and as a result, our ownership interest in those ventures was reduced from 40% to 38.2% and 40% to 38.2%, respectively, as of December 31, 2020.
Minimum Volume Commitments. Certain of our gathering and/or processing agreements contain MVCs which, like AMIs, benefit the development and ongoing operation of a gathering system because they provide a minimum contracted monthly or annual revenue stream. As of December 31, 2020, we had remaining MVCs totaling 1.4 Tcfe. Our MVCs had a weighted-average remaining life of 4.9 years (assuming contracted MVCs for the remainder of the term) and average approximately 0.9 Bcfe/d through 2023. In addition, certain of our customers have an aggregate MVC, which is a total amount of volume throughput that the customer has agreed to ship and/or process on our systems (or an equivalent monetary amount) over the MVC term. In these cases, once a customer achieves its aggregate MVC, any remaining future MVCs will terminate and the customer will then simply pay the applicable gathering or processing rate multiplied by the actual throughput volumes shipped or processed, pursuant to the contract. As a result of this mechanism, in many cases, the weighted-average remaining period for which our MVCs apply is less than the weighted-average of the remaining contract life. For additional information on our MVCs, see Notes 3 and 8 to the consolidated financial statements.
Our financial results are primarily driven by volume throughput across our gathering systems and by expense management. During 2020, aggregate natural gas volume throughput averaged 1,375 MMcf/d and crude oil and produced water volume throughput averaged 79 Mbbl/d. 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 or volatility. 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.
In addition, the vast majority of our gathering and/or processing agreements in both our Core Focus Areas and our Legacy Areas include AMIs. Our AMIs cover approximately 2.8 million surface acres in the aggregate, which includes more than 0.8 million surface acres associated with Ohio Gathering. Certain of our gathering and processing agreements also include MVCs. To the extent the customer does not meet its MVC, it is contractually obligated to make an MVC shortfall payment to cover the shortfall of required volume throughput not shipped or processed, either on a monthly or annual basis. We have designed our MVC provisions to ensure that we will generate a minimum amount of revenue from each customer over the life of the associated gathering and/or processing agreement, by collecting gathering or processing fees on actual throughput or from cash payments to cover any MVC shortfall. As of December 31, 2020, we had remaining MVCs totaling 1.4 Tcfe. Our MVCs have a weighted-average remaining life of 4.9 years (assuming contracted MVCs for the remainder of the term) and average approximately 0.9 Bcfe/d through 2023.
We use a variety of financial and operational metrics to analyze our performance, including among others, throughput volume, revenues, operation and maintenance expenses and segment adjusted EBITDA. We view each of these operational and/or GAAP metrics as important factors in evaluating our profitability and determining whether, and what amount of cash distributions, we pay to our unitholders. For additional information on our results of operations, see the “Results of Operations” section included in Item 7. MD&A.
Overview of Core Focus Areas and Legacy Areas
Utica Shale (Core Focus Area).
The following table provides operating information regarding our Utica Shale reportable segment as of December 31, 2020.
The Summit Utica system is a natural gas gathering system located in Belmont and Monroe counties in southeastern Ohio and serves producers targeting the dry gas window of the Utica and Point Pleasant shale formations. The Summit Utica system gathers and delivers natural gas, primarily under long-term, fee-based gathering agreements, which include acreage dedications. XTO and Ascent are the key customers of Summit Utica.
We have connected a substantial number of our customers’ pad sites to our gathering system and we expect to benefit in the near-term from incremental volumes arising from drilling and completion activity that is occurring and will continue to occur on previously connected pad sites. Over time, we intend to expand our midstream service offering for the Summit Utica system to connect additional customer pad sites and install centralized compression facilities. Centralized compression services have been dedicated to us in our gathering agreements and will eventually constitute a new revenue stream from our customers; however, to date, this service has not been required given the relatively high downhole pressures exhibited by dry gas wells in the Utica Shale compared to other unconventional shale plays.
The Summit Utica system interconnects with the Ohio River System pipeline, which provides access to the Clarington Hub and Rover Pipeline. The Summit Utica system currently provides natural gas midstream services for the Utica Shale reportable segment.
Ohio Gathering (Core Focus Area).
Ohio Gathering comprises a natural gas gathering system and condensate stabilization facility located in the core of the Utica Shale in southeastern Ohio. The gathering system spans the condensate, liquids-rich and dry gas windows of the Utica Shale for multiple producers that are targeting production from the Utica and Point Pleasant shale formations across Belmont, Monroe, Guernsey, Harrison and Noble counties in southeastern Ohio and is operated by our partner, MPLX LP (“MPLX”). Substantially all gathering services on the Ohio Gathering system are provided pursuant to long-term, fee-based gathering agreements. Ascent and Gulfport are Ohio Gathering's key customers. AMIs for Ohio Gathering total approximately 825,000 surface acres in the aggregate.
Condensate and liquids-rich natural gas production is gathered, compressed, dehydrated and delivered to the Cadiz and Seneca processing complexes, which offer approximately 1.3 Bcf/d of processing capacity and are owned by a joint venture between MPLX and The Energy and Minerals Group. Dry gas production is gathered, dehydrated, compressed, and delivered to third-party pipelines serving the northeast and midwest markets.
As of December 31, 2020, we owned a 38.2% ownership interest in Ohio Gathering, which includes our ownership in OGC and OCC. For additional information, see Note 7 to the consolidated financial statements.
Williston Basin (Core Focus Area).
The following table provides operating information regarding our Williston Basin reportable segment as of December 31, 2020.
(1) Contract terms related to MVCs are presented for liquids and natural gas on a combined basis.
(2) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).
AMIs for the Williston Basin reportable segment total approximately 1.2 million surface acres in the aggregate.
Polar and Divide. The Polar and Divide system, which is located primarily in Williams and Divide counties in northwestern North Dakota, owns, operates and is currently developing crude oil and produced water gathering systems and transmission pipelines serving multiple customers that are targeting crude oil production from the Bakken and Three Forks shale formations. The Polar and Divide system is underpinned by long-term, fee-based gathering agreements, which include acreage dedications. Whiting, Zavanna and Bruin are the key customers of the Polar and Divide system.
Crude oil that is gathered by the Polar and Divide system is delivered to interconnects with (i) the Dakota Access Pipeline, (ii) the COLT Hub rail facility, (iii) Enbridge Inc’s North Dakota Pipeline System and (iv) Global Partners LP's Basin Transload rail terminal. Produced water is delivered to third-party disposal facilities.
The Polar and Divide system currently provides crude oil and produced water midstream services for the Williston Basin reportable segment.
Bison Midstream. The Bison Midstream system is located in Mountrail and Burke counties in northwestern North Dakota. Bison Midstream gathers, compresses and treats associated natural gas that exists in the crude oil stream produced from the Bakken and Three Forks shale formations. Our gathering agreements for the Bison Midstream system include long-term, fee-based or percent-of-proceeds contracts. Volume throughput on the Bison Midstream system is underpinned by acreage dedications and MVCs from its key customers. A large U.S. independent crude oil and natural gas company and Oasis are the key customers of Bison Midstream.
Natural gas gathered on the Bison Midstream system is delivered to Aux Sable Midstream LLC's (“Aux Sable”) Palermo Conditioning Plant in Palermo, North Dakota and then delivered to downstream pipelines serving Aux Sable’s 2.1 Bcf/d natural gas processing plant in Channahon, Illinois.
The Bison Midstream system currently provides associated natural gas midstream services for the Williston Basin reportable segment.
DJ Basin (Core Focus Area).
The following table provides operating information regarding our DJ Basin reportable segment as of December 31, 2020.
(1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).
AMIs for the DJ Basin reportable segment total approximately 185,000 surface acres in the aggregate.
The Niobrara G&P system is located near Hereford, Colorado, in Weld County, the largest crude oil and natural gas producing county in the state. Gathering and processing services on the Niobrara G&P system are provided pursuant to long-term, fee-based gathering agreements with producers that are primarily targeting crude oil production from the Niobrara and Codell shale formations. HighPoint and a large U.S. independent crude oil and natural gas company are the key customers of the Niobrara G&P system and have underpinned our volume throughput with acreage dedications and MVCs.
The Niobrara G&P system operates a low-pressure associated natural gas gathering system, and a cryogenic natural gas processing plant with processing capacity of 60 MMcf/d. The Niobrara G&P system also processes liquids-rich natural gas that is produced by a customer in Laramie County, Wyoming and is delivered to the inlet of our processing plant by a third-party gathering system.
Residue gas is delivered to the Colorado Interstate Gas and Trailblazer Pipeline and processed NGLs are delivered to the Overland Pass Pipeline.
The Niobrara G&P system currently provides midstream services for the DJ Basin reportable segment.
Permian Basin (Core Focus Area).
The following table provides operating information regarding our Permian Basin reportable segment as of December 31, 2020.
(1) Contract terms related to MVCs are excluded for confidentiality purposes.
AMIs for the Permian Basin reportable segment total approximately 89,000 surface acres in the aggregate.
The Summit Permian system is an associated natural gas gathering and processing system operating in the northern Delaware Basin in Eddy and Lea counties in New Mexico. Gathering and processing services on the Summit Permian system are provided pursuant to long-term, fee-based gathering agreements with producers that are primarily targeting crude oil production from the Bone Spring and Wolfcamp shale formations. XTO is the key customer of the Summit Permian system.
The Summit Permian system operates a low-pressure natural gas gathering system and a 60 MMcf/d cryogenic processing plant. Residue natural gas is delivered to the Transwestern Pipeline and processed NGLs are delivered to the Lone Star NGL Pipeline. Summit Permian provides services for the Permian Basin reportable segment.
Double E (Core Focus Area).
Double E is a 1.35 Bcf/d interstate natural gas transmission pipeline that is under development and will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas. The Partnership owns 70% of Double E, is leading the development, permitting and construction of the pipeline, and will operate Double E upon commissioning. In January 2021, Double E received its Notice to Proceed with construction, as well as approval of its implementation plan, from FERC and expects the pipeline will be in-service by the end of 2021. Due to Double E’s early development status, its assets and operations are not included in a reportable segment.
Piceance Basin (Legacy Area).
The following table provides operating information regarding our Piceance Basin reportable segment as of December 31, 2020.
(1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).
AMIs for the Piceance Basin reportable segment total approximately 654,000 surface acres in the aggregate.
Grand River is primarily located in Garfield County, one of the largest natural gas producing counties in Colorado. The Grand River system provides natural gas gathering services pursuant to primarily long-term and fee-based agreements with multiple producers, including its key customers, Caerus Oil and Gas and Terra Energy Partners. Volume throughput on the Grand River system is underpinned with acreage dedications and MVCs.
The Grand River system is primarily a low-pressure gathering system located in western Colorado that gathers natural gas produced from directional wells targeting the liquids-rich Mesaverde formation. The Grand River system also gathers natural gas produced from the Mancos and Niobrara shale formations.
Natural gas gathered and/or processed on the Grand River system is compressed, dehydrated, processed and/or discharged to downstream pipelines serving (i) the Meeker Processing Complex, (ii) the Williams Processing Complex and (iii) the TransColorado Pipeline system. Processed NGLs from Grand River are injected into the Mid-America Pipeline system or delivered to local markets. In addition, certain of our gathering agreements with our customers on the Grand River system permit us to retain, and monetize for our own account, condensate volumes that naturally discharge from the liquids-rich natural gas as it moves across our system.
The Grand River system currently provides midstream services for the Piceance Basin reportable segment.
Barnett Shale (Legacy Area).
The following table provides operating information regarding our Barnett Shale reportable segment as of December 31, 2020.
(1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).
AMIs for the Barnett Shale reportable segment total approximately 124,000 surface acres.
The DFW Midstream system is primarily located in southeastern Tarrant County, in north-central Texas. We consider this area to be the core of the core of the Barnett Shale because of the quality of the geology and the high production profile of the wells drilled to date. The DFW Midstream system is underpinned by a long-term, fee-based gathering agreement with Total and additional customers.
The DFW Midstream system includes natural gas gathering pipelines located under both private and public property and is partially located along existing electric transmission corridors. Compression on the system is powered by electricity. To offset the costs we incur to operate the system's electric-drive compressors, we either pass through a portion of the power expense to our customers or retain a fixed percentage of the natural gas that we gather.
The DFW Midstream system currently has six primary interconnections with third-party, primarily intrastate pipelines. These interconnections enable us to connect our customers, directly or indirectly, with the major natural gas market hubs in Texas and Louisiana. Total Gas & Power North America, Inc. ("Total") is the key customer for DFW Midstream.
The DFW Midstream system currently provides midstream services for the Barnett Shale reportable segment.
Marcellus Shale (Legacy Area).
The following table provides operating information regarding our Marcellus Shale reportable segment as of December 31, 2020.
(1) Contract terms related to MVCs are excluded for confidentiality purposes.
The Mountaineer Midstream system is located in Doddridge and Harrison counties in West Virginia where it gathers natural gas under a long-term, fee-based contract with Antero, which is targeting liquids-rich natural gas production from the Marcellus Shale formation in the Appalachian Basin. Volume throughput on the Mountaineer Midstream system is underpinned by minimum revenue commitments from Antero.
The Mountaineer Midstream system consists of a high-pressure natural gas gathering system and two compressor stations. This system gathers high-pressure natural gas received from upstream pipeline interconnections with Antero Midstream Corporation and Crestwood Equity Partners LP. Mountaineer Midstream serves as a critical inlet to the Sherwood Processing Complex, a primary destination for liquids-rich natural gas in northern West Virginia and one of the largest natural gas processing facilities in the United States.
The Mountaineer Midstream system currently provides midstream services for the Marcellus Shale reportable segment.
For additional information relating to our business and gathering systems, see the "Trends and Outlook" and "Results of Operations" sections in Item 7. MD&A.
Our Customers
The systems that we operate and/or have significant ownership interests in have a diverse group of customers and counterparties comprising affiliates and/or subsidiaries of some of the largest natural gas and crude oil producers in North America.
We believe that our gathering systems in the Core Focus Areas are positioned for long-term growth through further development by our customers and increased utilization of our gathering systems. We intend to continue expanding our operations and creating additional scale in our Core Focus Areas through the execution of new, and the expansion of existing, strategic partnerships with our existing and prospective customers.
We believe that our customers in our Legacy Areas will pursue a slower pace of drilling and completion activity than customers in our Core Focus Areas. As a result, volume throughput in our Legacy Areas could decline or experience a lower rate of growth than our gathering systems in our Core Focus Areas. In general, our gathering systems in our Legacy Areas have a more mature base of connected wells, larger and longer-lived MVCs and experience lower volume throughput decline rates as compared to our gathering systems in our Core Focus Areas. We will continue to evaluate divestitures or joint ventures of certain of our gathering systems included in our Core Focus Areas or our Legacy Areas, which could result in a reallocation of capital or other resources to repay outstanding debt and other liabilities and fixed capital obligations, or re-invest in our Core Focus Areas.
Regulation of the Natural Gas and Crude Oil Industries
General. Sales by producers of natural gas, crude oil, condensate and NGLs are currently made at market prices. However, gathering and transportation services are subject to various types of regulation, which may affect certain aspects of our business and the market for our services. FERC regulates the transportation of natural gas in interstate commerce and the interstate transportation of crude oil, petroleum products and NGLs. FERC regulation includes reviewing and accepting or approving rates and other terms and conditions for such transportation services and authorizing and regulating the construction and operation of interstate natural gas pipelines. FERC is also authorized to prevent and sanction market manipulation in natural gas markets while the FTC is authorized to prevent and sanction market manipulation in petroleum markets and the CFTC is authorized to prevent and sanction fraud and price manipulations in the commodity and futures markets, including the energy futures markets. State and municipal regulations may apply to the production and gathering of certain natural gas, the construction and operation of natural gas and crude oil facilities and the rates and practices of gathering systems and intrastate pipelines.
Regulation of Crude Oil and Natural Gas Exploration, Production and Sales. Sales of crude oil and NGLs are not currently regulated and are transacted at market prices. In 1989, the U.S. Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. FERC, which has the authority under the NGA to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to the resale of gas in interstate commerce), however, could re-impose price controls in the future.
Exploration and production operations are subject to various types of federal, state and local regulation, including, but not limited to, permitting, well location, methods of drilling, well operations and conservation of resources. While these regulations do not directly apply to our business, they may affect our customers' ability to produce natural gas.
Regulation of the Gathering and Transportation of Natural Gas and Crude Oil. We believe that the majority of our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC. Our Epping Pipeline interstate crude oil pipeline in North Dakota, which is owned and operated by Epping, is subject to FERC’s jurisdiction and oversight pursuant to FERC's authority under the ICA, and Epping has on file with FERC a tariff for interstate movements of crude oil on the pipeline. Additionally, in October 2020, Double E received FERC approval of its application to construct and operate the Double E Project, pursuant to Section 7(c) of the Natural Gas Act. The Double E Project is anticipated to provide interstate natural gas transmission service from the Delaware Basin in southeastern New Mexico to delivery points in and around the Waha Hub in Texas, will be subject to FERC jurisdiction. In 2018, FERC solicited public comment on its current policy on the certification of construction of new pipeline facilities, although it has not made any determinations yet on whether to make any changes to that policy. In addition to approving and regulating the construction and operation of interstate natural gas pipelines, FERC also regulates such pipelines’ rates and terms and conditions of service, including transportation service agreements and negotiated rate agreements.
Under FERC’s ICA jurisdiction, rates for interstate movements of liquids by pipeline are currently regulated primarily through an annual indexing methodology, under which pipelines increase or decrease their existing rates in accordance with a FERC-specified adjustment that sets a rate ceiling. This adjustment, which may be positive or negative in a given year, is subject to review every five years. For the five-year period beginning on July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. In 2016, FERC proposed a policy change that would deny proposed index increases for pipelines under certain circumstances where revenues exceed cost-of-service by a certain percentage or where the proposed index increases exceed certain annual cost changes reported to FERC. FERC terminated this rulemaking on February 20, 2020 without adopting any part of the proposal. FERC completed its five-year review of its index adjustment by issuing an order on December 17, 2020 adopting a new annual index adjustment of the producer price index for finished goods plus 0.78% to become effective starting July 1, 2021. FERC’s order is subject to rehearing and possible judicial review.
Under current FERC regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through the indexing methodology by using a cost-of-service approach, but a pipeline must establish that a substantial divergence exists between its actual costs and the rates resulting from the indexing methodology. The rates charged by Epping may also be affected by FERC’s March 15, 2018 announcement of a revised policy eliminating the recovery of an income tax allowance in cost-of-service-based rates by FERC-jurisdictional crude oil and natural gas pipelines owned by master limited partnerships. FERC has not required oil pipelines on an industry-wide basis to decrease their rates to implement the new policy, but FERC has stated that the effects of the revised policy statement must be incorporated in annual FERC financial reports made by oil pipelines. The effect of the elimination of the income tax allowance for MLP pipelines, as well as the reduction in the corporate income tax rate resulting from the Tax Cuts and Jobs Act of 2017 (the “Tax Reform Legislation”), was considered in FERC’s five-year review of index rate adjustments which resulted in the December 17, 2020 order adopting a new annual index adjustment for the five-year period starting July 1, 2021.
The ICA permits interested persons to challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months and investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Under certain circumstances, FERC could limit
Epping’s ability to set rates based on costs or could order reduced rates and reparations to complaining shippers for up to two years prior to the date of a complaint. FERC also has the authority to change terms and conditions of service if it determines that they are unjust and unreasonable or unduly discriminatory or preferential. The ICA also imposes potential criminal liability for certain violations of the statute.
Intrastate pipelines, which may include some pipelines that perform gathering functions, may be subject to safety regulation by the DOT, although typically state regulatory authorities (operating under a federal certification) perform this function. State regulatory authorities also have jurisdiction over the rates and practices of intrastate pipelines and gathering systems, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of gathering systems and intrastate pipelines varies from state to state. In Texas, we are regulated as a gas utility and have filed tariffs with the Railroad Commission of Texas to establish rates and terms of service for our DFW Midstream system assets. We have not been required to file tariffs in the other states in which we operate, although we are required to submit shape files and other information regarding the location and construction of underground gathering pipelines in North Dakota. The states in which we operate have adopted complaint-based regulation that allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve access issues and rate grievances, among other matters. State authorities in the states in which we operate generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in the absence of a complaint. State regulation of intrastate pipelines continues to evolve and may become more stringent in the future. For example, the North Dakota Industrial Commission (“NDIC”) recently adopted rule changes that resulted in additional construction and monitoring requirements for all pipelines, including, but not limited to, those that transport produced water, and has recently adopted reclamation bonding requirements for certain underground gathering pipelines in North Dakota.
Natural gas, crude oil and produced water production, gathering and transportation, including the construction of new gathering facilities and expansion of existing gathering facilities may also be subject to local regulation, such as approval and permit requirements.
Anti-Market Manipulation Rules. We are subject to the anti-market manipulation provisions in the NGA and the NGPA, as amended by the Energy Policy Act of 2005, which authorize FERC to impose fines of up to $1,307,164 per day per violation of the NGA, the NGPA, or their implementing regulations, subject to future adjustments for inflation. In addition, the FTC holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,246,249 per violation, subject to future adjustment for inflation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The CFTC is directed under the CEA to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,227,202 per day per violation, subject to future adjustment for inflation, or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.
Safety and Maintenance. We are subject to regulation by the DOT, which establishes federal safety standards for the design, construction, operation and maintenance of natural gas and crude oil pipeline facilities. In the Pipeline Safety Act of 1992, Congress expanded the DOT's regulatory authority to include regulated gathering lines that had previously been exempt from federal jurisdiction. Additional legislation has been passed over the years to reauthorize federal funding for federal pipeline programs, increase penalties for safety violations and establish additional safety requirements. For example, in December 2020, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 became law, reauthorizing PHMSA for funding through 2023 and requiring, among other things, rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines.
The DOT has delegated the implementation of pipeline safety requirements to PHMSA, which has adopted and enforces safety standards and procedures applicable to a limited number of our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing PHMSA regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management
programs for certain pipelines located in high consequence areas, which include high-population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is located. While the majority of our pipelines meet the DOT definition of gathering lines and are thus currently exempt from the integrity management requirements of PHMSA, we also operate a limited number of pipelines that are subject to the integrity management requirements. Those regulations require operators, including us, to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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maintain processes for data collection, integration and analysis;
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repair and remediate pipelines as necessary;
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adopt and maintain procedures, standards and training programs for control room operations; and
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implement preventive and mitigating actions.
In October 2019, the PHMSA issued three new final rules. One rule, which became effective in December 2019, establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows the PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules, which became effective in July 2020, impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond “high consequence areas” (“HCAs”) to pipelines in “moderate consequence areas” (“MCAs”). It also includes requirements to reconfirm Maximum Allowable Operating Pressure (“MAOP”), report MAOP exceedances, consider seismicity as a risk factor in integrity management, and use certain safety features on in-line inspection equipment. PHMSA modified the rule in July 2020, in response to a petition for reconsideration, to limit the rule’s recordkeeping requirement related to class location changes to gas transmission pipelines (not gas distribution pipelines) and to clarify that the rule’s reconfirmation requirements related to MAOP is limited to segments without traceable, verifiable and complete pressure test records. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events, and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years.
Gathering systems like ours are also subject to a number of federal and state laws and regulations, including the Federal Occupational Safety and Health Act and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the Occupational Safety and Health Administration hazard communication standard, EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and the public.
Environmental Matters
General. Our operation of pipelines and other assets for the gathering, treating and/or processing of natural gas and the gathering of crude oil and produced water is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these assets, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
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requiring the installation of pollution-control equipment or otherwise restricting the way we operate;
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limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;
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delaying system modification or upgrades during permit reviews;
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requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and
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enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or imposed by such environmental laws and regulations.
Failure to comply with these laws and regulations may trigger administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
The trend in environmental regulation is to place more stringent requirements, resulting in more restrictions and limitations, on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing and future regulations.
The following is a discussion of the material environmental laws and regulations that relate to our business.
Hazardous Substances and Waste. Our operations are subject to environmental laws and regulations relating to the management and release of solid and hazardous wastes and other substances, including hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. Furthermore, the Toxic Substances Control Act and analogous state laws, impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
We also generate industrial wastes that are subject to the requirements of the RCRA and comparable state statutes. While the RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Although we generate minimal hazardous waste, it is possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designated as hazardous wastes and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes.
We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although we believe that the previous operators utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal, without our knowledge. These properties and the wastes disposed thereon may be subject to CERCLA, the RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.
Air Emissions. Our operations are subject to the federal CAA and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and also impose various monitoring, control and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and criminal enforcement actions. Furthermore, we may be required to incur certain capital expenditures in the future to obtain and maintain operating permits and approvals for air pollutant emitting sources.
In October 2015, the EPA issued a new lower NAAQS for ozone. The previous ozone standard was set at 75 parts per billion ("ppb"). The revised standard has been lowered to 70 ppb. The lowered ozone NAAQS could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs. Impacts from the 2015 standard have not yet been determined, as states are still in the process of incorporating the new standard into their respective state implementation plans. We will continue to monitor developments to determine if any adverse effects on our operations can be expected.
On June 3, 2016, the EPA finalized revisions to its 2012 New Source Performance Standard ("NSPS") OOOO for the oil and gas industry, to reduce emissions of greenhouse gases - most notably methane - along with smog-forming VOCs. The revisions, which are published in the Federal Register under Subpart OOOOa, included the addition of methane to the pollutants covered by the rule, along with requirements for detecting and repairing leaks at gathering and boosting stations. The revised rule applies to sources that have been modified, constructed, or reconstructed after September 18, 2015. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of NSPS OOOO and OOOOa applicable to sources in the production and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. Court of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directed EPA to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules, as well as to consider establishing methane and VOC emission standards for existing sources in the oil and gas sector, including the transportation and storage segments.
On November 16, 2016 the Bureau of Land Management ("BLM") issued a final rule to reduce venting and flaring of natural gas on public and Indian lands. The final rule mirrors many of the requirements found in NSPS OOOOa, with additional natural gas royalty requirements for flared volumes at sites already connected to gas capture infrastructure. In September 2018, the BLM published a final rule that rescinded several requirements of this rule. However, in July 2020, the U.S. District Court for the Northern District of California vacated BLM’s 2018 revision rule. In addition, in October 2020, a Wyoming federal district judge vacated the 2016 venting and flaring rule. Environmental groups appealed the October 2020 decision in December 2020 and litigation is ongoing. While the rule, if implemented, is expected to have little or no direct impact on our operations, our customers that are primarily upstream wellhead operators may be impacted by the requirements in this rule.
In recent years, the EPA has also demonstrated an increased focus on CAA compliance for natural gas gathering operations. For example, in September 2019, EPA issued an enforcement alert noting that EPA identified CAA noncompliance caused by unauthorized and/or excess emissions from depressurizing pig launchers and receivers in natural gas gathering operations. The alert discussed engineering, design, operations, and maintenance practices that EPA found that can cause noncompliance and summarizes engineering solutions to reduce emissions. This increased focus on natural gas gathering operations and any resulting enforcement actions by EPA or state agencies could subject us to monetary penalties, injunctions, conditions or restrictions on operations.
Water Discharges. The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into regulated waters, which impacts our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits require us to control storm water runoff from some of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Except as otherwise disclosed in this annual report, we believe that we are in substantial compliance with all applicable requirements of the CWA and analogous state laws and regulations relating to water discharges.
Oil Pollution Control Act. The OPA requires the preparation of an SPCC plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations
(intrafacility piping), inspections and records, security and training. Certain of our facilities are classified as SPCC-regulated facilities. We believe that they are in substantial compliance with all applicable requirements of OPA.
Hydraulic Fracturing. Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations and is primarily presently regulated by state agencies. However, Congress has in the past and may in the future consider legislation to regulate hydraulic fracturing by federal agencies or limit the ability of companies to engage in hydraulic fracturing. Many states have already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing. A number of states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure and well construction requirements on oil and/or natural gas drilling activities. For example, a Colorado ballot initiative, Proposition 112, would have substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and gas development in the state. Although Proposition 112 was defeated in the November 2018 elections, similar ballot initiatives have been circulated by interested groups for potential consideration in elections. Further, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the Colorado Oil and Gas Conservation Commission (“COGCC”), the state’s oil and gas regulator from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state and reduced the oil and gas representation on the COGCC. Further, in November 2020, the COGCC adopted new regulations that increase oil and gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibit routine venting and flaring, increase wildlife protections, and alter certain aspects of the permitting process. These regulations and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. States also could elect to prohibit hydraulic fracturing altogether, as New York, Maryland, and Vermont have done. In addition, certain local governments have adopted, and additional local governments may adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.
The EPA has also moved forward with various regulatory actions, including approving new regulations requiring green completions of hydraulically-fractured wells and corresponding reporting requirements that went into effect in 2015. Revisions to the green completion regulations were finalized in June 2016 and include additional requirements to reduce methane and VOCs. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of these regulations applicable to sources in the production and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. Court of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directed EPA to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules as well as to consider establishing methane and VOC emission standards for existing sources in the oil and gas sector, including the transportation and storage segments. The BLM has also asserted regulatory authority over aspects of the hydraulic fracturing process, and issued a final rule in March 2015 that established more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The U.S. District Court for the Northern District of California upheld the December 2017 rescission rule in a March 2020 decision. The State of California and environmental plaintiffs then appealed the decision in June 2020. Litigation is currently ongoing.
Further, several federal governmental agencies have conducted reviews and studies on the environmental aspects of hydraulic fracturing, including the EPA. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.
State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. Some state regulatory agencies, including those in Colorado, Ohio, and Texas, have modified their regulations or guidance to account for induced seismicity. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers.
Additionally, certain of our customers produce oil and gas on federal lands. On January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices.
If new or more stringent federal, state or local legal restrictions relating to drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and/or crude oil that our customers produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business.
Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species.
National Environmental Policy Act. The NEPA establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. Major projects having the potential to significantly impact the environment require review under NEPA. Many of our activities are covered under categorical exclusions which results in an expedited NEPA review process. Large upstream and downstream projects with significant cumulative impacts may be subject to longer NEPA review processes, which could impact the timing of those projects and our services associated with them.
Climate Change. The EPA has adopted regulations under the CAA that, among other things, establish GHG emission limits from motor vehicles as well as establish PSD construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis.
EPA rules also require the reporting of GHG emissions from specified large GHG-emitting sources in the United States, including onshore and offshore oil and natural gas systems. We are required to report under these rules for our assets that have GHG emissions above the reporting thresholds. In October 2015, the EPA issued revisions to Subpart W of the GHG reporting rule to include reporting requirements for gathering and booster stations, onshore natural gas transmission pipelines, and completions and workovers of oil wells with hydraulic fracturing. This development resulted in increased monitoring and reporting for our operations and for upstream producers for whom we provide midstream services.
In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that certain components of our operations, such as our gas-fired compressors, could become subject to state-level GHG-related regulation.
Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions. The agreement entered into force in November 2016, after over 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement. In November 2019, the United States submitted formal notification to the United Nations that it intended to withdraw from the agreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States of America” that reversed the prior withdrawal, and the United States officially rejoined the Paris Agreement on February 19, 2021. In addition, shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change. Reentry into the Paris Agreement and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations, which could have a material adverse effect on our business and that of our customers.
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG-emitting energy sources, our products would become more desirable in the market with more stringent limitations on GHG emissions. Conversely, to the extent that our products are competing with lower GHG-emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions.
Other Information
Human Capital Resources. We recognize that our continued ability to attract, retain and motivate exceptional employees is vital to ensuring our long-term competitive advantage and the ability to create value for our unitholders. Our employees are critical to our long-term success and are essential to helping us meet our goals. Among other things, we support and incentivize our employees in the following ways:
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Talent development, compensation and retention - We strive to provide our employees with a rewarding work environment, including the opportunity for success and a platform for personal and professional development. We provide a competitive benefits package designed to attract and retain a skilled and diverse workforce. We offer our employees a comprehensive benefits package, which includes company funded health plan options, vision and dental coverage, healthcare savings account, paid time off, parental leave and flexible spending accounts. We also provide professional training and development opportunities as well as education reimbursement. We also offer employees immediate eligibility in our 401(k) plan with company matching program.
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Health and safety - Employee health and safety in the workplace is one of our core values. Some of the ways in which we support the health and safety of our employees include wellness programs with incentives and employee assistance programs.
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Inclusion and diversity - We are committed to efforts to increase diversity and foster an inclusive work environment that supports our workforce.
In addition to the variety of support services we provide to our employees under normal circumstances, our top priority during the ongoing COVID-19 pandemic remains protecting the health and well-being of our employees, customers, partners and communities. Since the onset of the COVID-19 pandemic, we have maintained a work-from-home policy for substantially all our employees, significantly limited business travel, and we have taken an integrated approach to helping our employees manage their work and personal responsibilities, with a strong focus on employee physical and mental health.
As of December 31, 2020, the Partnership employed 220 people who provide direct, full-time support to our operations. None of our employees are covered by collective bargaining agreements, and we have never experienced any business interruption as a result of any labor disputes.
Availability of Reports. We make certain filings with the SEC, including, among other filings, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through our website, www.summitmidstream.com, as soon as reasonably practicable after the date they are filed with, or furnished to, the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC through the SEC’s website, http://www.sec.gov. Our press releases and recent investor presentations are also available on our website.
Item 1A.
Item 1A. Risk Factors.
You should carefully consider the following risk factors in addition to the other information included in this Annual Report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common units:
Risks Related to COVID-19
The COVID-19 pandemic, coupled with other current pressures on oil and gas prices resulting from the OPEC price war, has had, and is expected to continue to have, an adverse impact on our business, results of operations, financial position and cash flows.
The ongoing COVID-19 outbreak continues to be a rapidly evolving situation. As of February 20, 2021, the CDC had recorded over 27.8 million cases in the United States and over 490,000 deaths. The pandemic has resulted in widespread adverse impacts on the global economy and on our business, including our customers, employees, supply chain, and distribution network. We are currently unable to predict the ultimate impact that it may have on our business, future results of operations, financial position or cash flows. 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 the first half of 2020, oil prices declined significantly due to increases in supply emanating from a disagreement on production cuts among members of OPEC and certain non-OPEC, oil-producing countries and subsequent hydrocarbon commodity price declines. The resulting supply and demand imbalance 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. Although OPEC agreed in April 2020 to cut oil production and extended such production cuts through December 2020, there is no assurance that the agreement will continue to be observed by its members, and the responses of oil and gas producers to the lower demand for, and price of, natural gas, NGLs and crude oil are constantly evolving and remain uncertain. Continued pressure on demand. Such responses could cause our pipelines and storage tanks to reach capacity, thereby forcing producers to experience shut-ins or look to alternative methods of transportation for their products. In addition, the dramatic decrease in oil and gas prices could have substantial negative implications for our revenue sources that are related to or underpinned by commodity prices. As a result, these factors could have a material adverse effect on our business, future results of operations, financial position or cash flows. At this point, we cannot accurately predict the long-term effects current market conditions due to the COVID-19 pandemic and failed OPEC negotiations will have on our business, which will depend on, among other factors, the duration of the outbreak and the extent and overall economic effects of the governmental response to the pandemic.
The impact of COVID-19 and the OPEC price war may also exacerbate other risks discussed below, any of which could have a material effect on us. This situation is changing rapidly, and additional impacts may arise that we are not aware of currently.
Risks Related to Our Operations
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, to enable us to pay distributions to holders of our common units.
We may not have sufficient available cash from operating surplus each quarter to pay the distributions to holders of our common units. In May 2020, we suspended distributions to holders of our common units and our Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. We did not make a distribution on our common units with respect to any quarter in 2020, nor did we make a distribution on our Series A Preferred Units on June 15, 2020 or December 15, 2020. Further, we may not pay distributions on the common units or Series A Preferred Units in the foreseeable future, and there are restrictions on our ability to pay distributions under our outstanding indebtedness that restrict our ability to pay cash distributions on any of our equity securities. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
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the volumes we gather, treat and process;
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the level of production of natural gas and crude oil (and associated volumes of produced water) from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, crude oil, natural gas and NGLs;
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damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters, accidents and acts of terrorism;
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leaks or accidental releases of hazardous materials into the environment;
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weather conditions and seasonal trends;
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changes in the fees we charge for our services;
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changes in contractual MVCs and our customer’s capacity to make MVC shortfall payments when due;
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the level of competition from other midstream energy companies in our areas of operation;
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changes in the level of our operating, maintenance and general and administrative expenses;
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regulatory action affecting the supply of, or demand for, crude oil, natural gas and NGLs, the fees we can charge, how we contract for services, our existing contracts, our operating and maintenance costs or our operating flexibility; and
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prevailing economic and market conditions.
In addition, the actual amount of cash we have available for distribution to our common unitholders depends on other factors, some of which are beyond our control, including:
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the level and timing of capital expenditures we make;
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the level of our operating, maintenance and general and administrative expenses, including reimbursements of expenses incurred on our behalf by our General Partner;
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the cost of acquisitions, if any;
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our ability to sell assets, if any, and the price that we may receive for such assets;
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our debt service requirements and other liabilities;
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fluctuations in our working capital needs;
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our ability to borrow funds and access the debt and equity capital markets;
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restrictions contained in our debt agreements;
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the amount of cash reserves established by our General Partner;
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not receiving anticipated shortfall payments from our customers;
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adverse legal judgments, fines and settlements;
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distributions paid on our Series A Preferred Units, if any, or on the preferred stock of our subsidiaries; and
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other business risks affecting our cash levels.
We depend on a relatively small number of customers for a significant portion of our revenues. For example, Caerus, a customer on our Piceance Basin gathering system accounts for over 10% of our aggregated revenue. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of our customers could materially adversely affect our revenues, cash flows and ability to make cash distributions to our unitholders.
Certain of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our customers could have a material adverse effect on our revenues and cash flows and our ability to make cash distributions to our unitholders. We expect our exposure to concentrated risk of nonpayment or nonperformance to continue as long as we remain substantially dependent on a relatively small number of customers for a significant portion of our revenues.
If any of our customers curtail or reduce production in our areas of operation, it could reduce throughput on our systems and, therefore, materially adversely affect our revenues, cash flows and ability to make cash distributions to our unitholders.
Further, we are subject to the risk of non-payment or non-performance by our larger customers. We cannot predict the extent to which our customers’ businesses would be impacted if conditions in the energy industry deteriorate, nor can we estimate the impact such conditions would have on any of our customers’ abilities to execute their drilling and development programs or perform under our gathering and processing agreements. The low commodity price environment has negatively impacted natural gas producers causing some producers in the industry significant economic stress, including, in certain cases, to file for bankruptcy protection or to renegotiate contracts. To the extent that any customer is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material non-payment or non-performance by our customers could adversely affect our business and operating results.
We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties and any material nonpayment or nonperformance by one or more of these parties could materially adversely affect our financial and operating results.
Although we attempt to assess the creditworthiness and associated liquidity of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. In addition, there can be no assurance that our contract counterparties will perform or adhere to existing or future contractual arrangements, including making any required shortfall payments or other payments due under their respective contracts.
The policies and procedures we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, if necessary, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our policies and procedures prove to be inadequate, our financial and operational results may be negatively impacted.
Some of our counterparties may be highly leveraged, have limited financial resources and/or have recently experienced a rating agency downgrade and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. In addition, volatility in commodity prices could have a negative impact on our counterparties, which, in turn, could have a negative impact on their ability to meet their obligations to us.
Any material nonpayment or nonperformance by any of our counterparties or suppliers could require us to pursue substitute counterparties or suppliers for the affected operations or reduce our operations. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.
Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.
Our operations are focused on gathering, treating and processing services in the following unconventional resource basins, primarily shale formations: the Utica Shale, the Williston Basin, the DJ Basin, the Permian Basin, the Piceance Basin, the Barnett Shale and the Marcellus Shale. Due to our limited industry diversity, adverse developments in the natural gas and crude oil industries or in our existing areas of operation could have a significantly greater impact on our financial condition, results of operations and cash flows than if we did not have such limited diversity.
Significant prolonged weakness in natural gas, NGL and crude oil prices could reduce throughput on our systems and materially adversely affect our revenues and cash available to make cash distributions to our unitholders.
Lower natural gas, NGL and crude oil prices could negatively impact exploration, development and production of natural gas and crude oil, thereby resulting in reduced throughput on our gathering systems. Additionally, certain of our customers in each of our areas of operations have reduced, and others could reduce, drilling activity and capital expenditure budgets. If natural gas, NGL and/or crude oil prices remain at current levels or decrease, it could cause sustained reductions in exploration or production activity in our areas of operation and result in a further reduction in throughput on our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.
Because of the natural decline in production from our customers' existing wells, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes that we gather and process could materially adversely affect our business and operating results.
The customer volumes that support our business depend on the level of production from natural gas and crude oil wells connected to our systems, the production from which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our systems, we must obtain new sources of volume throughput. The primary factors affecting our ability to obtain new sources of volume throughput include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for new volumes on our systems.
We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling and production decisions, which are affected by, among other things:
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the availability and cost of capital;
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prevailing and projected hydrocarbon commodity prices;
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demand for crude oil, natural gas and other hydrocarbon products, including NGLs;
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levels of reserves;
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geological considerations;
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environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and
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the availability of drilling rigs and other costs of production and equipment.
Fluctuations in energy prices can also greatly affect the development of new crude oil and natural gas reserves. Drilling and production activities generally decrease as commodity prices decrease. In general terms, the prices of crude oil, natural gas and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
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worldwide economic and geopolitical conditions;
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global or national health concerns, including the outbreak of pandemic or contagious disease, such as COVID-19, which may continue to reduce demand for crude oil, natural gas and NGLs because of reduced global or national economic activity;
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weather conditions and seasonal trends;
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the levels of domestic production and consumer demand;
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the availability of imported liquefied natural gas (“LNG”);
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the ability to export LNG;
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the availability of transportation and storage systems with adequate capacity;
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the volatility and uncertainty of regional pricing differentials and premiums;
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the price and availability of alternative fuels, including alternative fuels that benefit from government subsidies;
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the effect of energy conservation measures;
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the nature and extent of governmental regulation and taxation; and
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the anticipated future prices of crude oil, natural gas and other hydrocarbon products, including NGLs.
Because of these factors, even if new crude oil or natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenues and cash flows and materially adversely affect our ability to make cash distributions to our unitholders.
In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins and may have steeper production decline curves than initially anticipated. Should we determine that the economics of our gathering, treating and processing assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time, which will reduce our cash available for distribution.
Many of our costs are fixed and do not vary with our throughput. These costs will not decline ratably or at all should we experience a reduction in throughput, which could result in a decline in our revenues and cash flows and materially adversely affect our ability to make cash distributions to our unitholders.
Any significant decrease in the demand for natural gas and crude oil could reduce the volumes of natural gas and crude oil that we gather and process, which could adversely affect our business and operating results.
The volumes of natural gas and crude oil that we gather and process depend on the supply and demand for natural gas and crude oil and other hydrocarbon products in the areas served by our assets. Natural gas and crude oil compete with other forms of energy available to users, including electricity, coal, other fuels and alternative energy sources. Increased demand for such forms of energy at the expense of natural gas and crude oil could lead to a reduction in demand for our services. Any such reduction could result in a decline in our revenues and cash flows and materially adversely affect our ability to make cash distributions to our unitholders.
If our customers do not increase the volumes they provide to our gathering systems, our ability to make cash distributions to our unitholders may be materially adversely affected.
If we are unsuccessful in attracting new customers and/or new gathering opportunities with existing customers, our ability to make cash distributions to our unitholders will be impaired. Our customers are not obligated to provide additional volumes to our gathering systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. Reductions by our customers in our areas of mutual interest could result in reductions in throughput on our systems and materially adversely impact our ability to make cash distributions to our unitholders.
Certain of our gathering and processing agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.
We designed those gathering and processing agreements that contain MVC provisions to generate stable cash flows for us over the life of the MVC contract term while also minimizing our direct commodity price risk. Under certain of these MVCs, our customers agree to ship a minimum volume on our gathering systems or send a minimum volume to our processing plants or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. In addition, our gathering and processing agreements may also include an aggregate MVC, which represents the total amount that the customer must flow on our gathering system or send to our processing plants (or an equivalent monetary amount) over the MVC term. If such customer’s actual throughput volumes are less than its MVC for the contracted measurement period, it must make a shortfall payment to us at the end of the applicable measurement period. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped or processed for the applicable period and the MVC for the applicable period, multiplied by the applicable fee. To the extent that a customer’s actual throughput volumes are above or below its MVC for the applicable contracted measurement period, certain of our gathering agreements contain provisions that allow the customer to use the excess volumes or the shortfall payment to credit against future excess volumes or future shortfall payments, which could have a material adverse effect on our results of operations, financial condition and cash flows and our ability to make cash distributions to our unitholders.
We have not obtained independent evaluations of all of the reserves connected to our gathering systems; therefore, in the future, customer volumes on our systems could be less than we anticipate.
We do not routinely obtain or update independent evaluations of the reserves connected to our systems. Moreover, even if we did obtain independent evaluations of all of the reserves connected to our systems, such evaluations may prove to be incorrect. Crude oil and natural gas reserve engineering requires subjective estimates of underground accumulations of crude oil and natural gas and assumptions concerning future crude oil and natural gas prices, future production levels and operating and development costs.
Accordingly, we may not have accurate estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional volumes, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results.
We compete with other midstream companies in our areas of operations, some of which are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors may have assets in closer proximity to natural gas and crude oil supplies and may have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering systems that would create additional competition for the services we provide to our customers. Because our customers do not have leases that cover the entirety of our areas of mutual interest, non-customer producers that lease acreage within any of our areas of mutual interest may choose to use one of our competitors for their gathering and/or processing service needs.
In addition, our customers may develop their own gathering systems outside of our areas of mutual interest. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be materially adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.
Our gathering, treating and processing contracts have terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing customers or enter into new contracts with other customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain areas of mutual interest from new customers in the future, and we may be unable to renew existing areas of mutual interest with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
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the level of existing and new competition to provide gathering and/or processing services in our areas of operation;
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the macroeconomic factors affecting gathering, treating and processing economics for our current and potential customers;
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the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
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the extent to which the customers in our areas of operation are willing to contract on a long-term basis; and
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the effects of federal, state or local regulations on the contracting practices of our customers.
To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline and our ability to make cash distributions to our unitholders could be materially adversely affected.
If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our revenues and cash flows and our ability to make cash distributions to our unitholders could be materially adversely affected.
Our gathering systems connect to third-party pipelines and other midstream facilities, such as processing plants, rail terminals and produced water disposal facilities. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable due to issues including, but not limited to, testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other hazards. In addition, we do not have interconnect agreements with all of these pipelines and other facilities and the agreements we do have may be terminated in certain circumstances and/or on short notice. If any of these pipelines or other midstream facilities become unavailable for any reason, or, if these third parties are otherwise unwilling to receive or transport the natural gas, crude oil and produced water that we gather and/or process, our revenues, cash flows and ability to make cash distributions to our unitholders could be materially adversely affected.
We have a relatively limited ownership history with respect to certain of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines and/or processing facilities that could have a material adverse effect on our business and operating results.
We have a relatively limited history of operating certain of our assets. There may be historical occurrences or latent issues regarding certain of our pipeline systems of which we may be unaware and that may have a material adverse effect on our business and results of operations. Any significant increase in maintenance and repair expenditures or loss of revenue due to the condition of our pipeline systems could materially adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.
Crude oil and natural gas production and gathering may be adversely affected by weather conditions and terrain, which in turn could negatively impact the operations of our gathering, treating and processing facilities and our construction of additional facilities.
Extended periods of below freezing weather and unseasonably wet weather conditions, especially in North Dakota, Ohio and West Virginia, can be severe and can adversely affect crude oil and natural gas operations due to the potential shut-in of producing wells or decreased drilling activities. These types of interruptions could result in a decrease in the volumes supplied to our gathering systems. Further, delays and shutdowns caused by severe weather may have a material negative impact on the
continuous operations of our gathering, treating and processing systems, including interruptions in service. These types of interruptions could negatively impact our ability to meet our contractual obligations to our customers and thereby give rise to certain termination rights and/or the release of dedicated acreage. Any resulting terminations or releases could materially adversely affect our business and results of operations.
We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their locations and surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly. For example, certain of our pipeline facilities are located in mountainous areas such as our Utica Shale and Marcellus Shale operations, which may require specially designed facilities and special installation considerations. If such facilities are not designed or installed correctly, do not perform as intended, or fail, we may be required to incur significant expenditures to correct or repair the deficiencies, or may incur significant damages to or loss of facilities, and our operations may be interrupted as a result of deficiencies or failures. In addition, such deficiencies may cause damage to the surrounding environment, including slope failures, stream impacts and other natural resource damages, and we may as a result also be subject to increased operating expenses or environmental penalties and fines.
Interruptions in operations at any of our facilities may adversely affect our operations and cash flows available for distribution to our unitholders.
Our operations depend upon the infrastructure that we have developed and constructed. Any significant interruption at any of our gathering, treating or processing facilities, or in our ability to provide gathering, treating or processing services, could adversely affect our operations and cash flows available for distribution to our unitholders. Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:
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unscheduled turnarounds or catastrophic events at our physical plants or pipeline facilities;
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restrictions imposed by governmental authorities or court proceedings;
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labor difficulties that result in a work stoppage or slowdown;
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a disruption in the supply of resources necessary to operate our midstream facilities;
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damage to our facilities resulting from production volumes that do not comply with applicable specifications; and
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inadequate transportation and/or market access to support production volumes, including lack of pipeline, rail terminals, produced water disposal facilities and/or third-party processing capacity.
Any significant interruption at any of our gathering, treating or processing facilities, or in our ability to provide gathering, treating or processing services, could adversely affect our operations and cash flows available for distribution to our unitholders.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant incident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant incidents or events for which we are insured, our operations and financial results could be materially adversely affected.
Our operations are subject to all of the risks and hazards inherent in the operation of gathering, treating and processing systems, including:
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damage to pipelines, processing plants, compression assets, related equipment and surrounding properties caused by tornadoes, floods, fires and other natural disasters and acts of terrorism;
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inadvertent damage from construction, vehicles, farm and utility equipment;
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leaks or losses resulting from the malfunction of equipment or facilities;
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ruptures, fires and explosions; and
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other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from such events.
These events may also result in curtailment or suspension of our operations. A natural disaster or any event such as those described above affecting the areas in which we and our customers operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on portions or all of our gathering systems. Potential customer impacts arising from service interruptions on segments of our gathering systems could include limitations on our ability to satisfy customer requirements, obligations to temporarily waive MVCs during times of constrained capacity, temporary or permanent release of production dedications, and solicitation of existing customers by others for potential new projects that would compete directly with our existing services. Such circumstances could materially adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business and results of operations and our ability to make cash distributions to our unitholders.
Although we have a range of insurance programs providing varying levels of protection for public liability, damage to property, loss of income and certain environmental hazards, we may not be insured against all causes of loss, claims or damage that may occur. If a significant incident or event occurs for which we are not fully insured, it could materially adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of industry or market conditions, some of which are beyond our control, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, with regard to the assets we have acquired, we have limited indemnification rights to recover from the seller of the assets in the event of any potential environmental liabilities.
We may fail to successfully integrate gathering system acquisitions into our existing business in a timely manner, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders, or fail to realize all of the expected benefits of the acquisitions, which could negatively impact our future results of operations.
Integration of future gathering system acquisitions could be a complex, time-consuming and costly process, particularly if the acquired assets significantly increase our size and/or (i) diversify the geographic areas in which we operate or (ii) the service offerings that we provide.
The failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. If any of the risks described above or in the immediately preceding risk factor or unanticipated liabilities or costs were to materialize with respect to future acquisitions or if the acquired assets were to perform at levels below the forecasts we used to evaluate them, then the anticipated benefits from the acquisition may not be fully realized, if at all, and our future results of operations and ability to make cash distributions to unitholders could be negatively impacted.
Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could materially adversely affect our results of operations and financial condition.
The construction of new assets, including for example Double E, involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control.
Such construction projects may also require the expenditure of significant amounts of capital, and financing, traditional or otherwise, may not be available on economically acceptable terms or at all. If we undertake these projects, our revenue may not increase immediately upon the expenditure of funds for a particular project and they may not be completed on schedule, at the budgeted cost, or at all.
Moreover, we could construct facilities to capture anticipated future production growth in a region where such growth does not materialize or only materializes over a period materially longer than expected. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate due to the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput
to achieve our expected investment return, which could materially adversely affect our results of operations and financial condition.
In addition, the construction of additions or modifications to our existing gathering, treating and processing assets and the construction of new midstream assets may require us to obtain federal, state and local regulatory environmental or other authorizations. The approval process for gathering, treating and processing activities has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering, treating and processing activities in new production areas. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions. As a result, we may be unable to obtain such authorizations and may, therefore, be unable to connect new volumes to our systems or capitalize on other attractive expansion opportunities. A future government shutdown could delay the receipt of any federal regulatory approvals. Additionally, it may become more expensive for us to obtain authorizations or to renew existing authorizations. If the cost of renewing or obtaining new authorizations increases materially, our cash flows could be materially adversely affected.
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or if our pipelines are not properly located within the boundaries of such rights-of-way. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies either perpetually or for a specific period of time. If we were to be unsuccessful in renegotiating rights-of-way, we might have to relocate our facilities. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Our ability to operate our business effectively could be impaired if we fail to attract and retain key personnel.
Our ability to operate our business and implement our strategies depends on our continued ability to attract and retain highly skilled personnel with midstream energy industry experience and competition for these persons in the midstream energy industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.
A shortage of skilled labor in the midstream energy industry could reduce employee productivity and increase costs, which could have a material adverse effect on our business and results of operations.
The operation of gathering, treating and processing systems requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our General Partner's employees, our business and results of operations and our ability to make cash distributions to our unitholders could be materially adversely affected.
Risks Related to Our Finances
Limited access to and/or availability of the debt and equity capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.
To expand our asset base, whether through acquisitions or organic growth, we will need to make expansion capital expenditures. We also frequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gathering and processing agreements also require us to spend significant amounts of capital, over a short period of time, to construct and develop additional midstream assets to support our customers' development projects. Depending on our customers' future development plans, it is possible that the capital required to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under our Revolving Credit Facility.
We plan to use cash from operations, incur borrowings and/or sell additional common units or other securities to fund our future expansion capital expenditures. Using cash from operations to fund expansion capital expenditures will directly reduce any cash available for distribution to unitholders. Our ability to obtain financing or to access the capital markets for future debt or equity offerings may be limited by (i) our financial condition at the time of any such financing or offering, (ii) covenants in our debt agreements, (iii) restrictions imposed by our Series A Preferred Units, (iv) general economic conditions and contingencies, (v) increasing disfavor among many investors towards investments in fossil fuel companies and (vi) general weakness in the debt and equity capital markets and other uncertainties that are beyond our control. In addition, lenders are facing increasing pressure to curtail their lending activities to companies in the oil and natural gas industry. 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 expansion capital expenditures and acquisition capital expenditures with the issuance of additional equity. We did not make a distribution on our common units with respect to any quarter in 2020, nor did we make a distribution on our Series A Preferred Units on June 15, 2020 or December 15, 2020, and these suspensions of distributions may further reduce demand for our common units or Series A Preferred Units. Further, we may not pay distributions on the common units or Series A Preferred Units in the foreseeable future, and there are restrictions on our ability to pay distributions under our outstanding indebtedness that restrict our ability to pay cash distributions on any of our equity securities. As such, if we are unable to raise expansion capital, we may lose the opportunity to make acquisitions, pursue new organic development projects, or to gather, treat and process new production volumes from our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining external funds for expansion capital expenditures through the capital markets, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional units representing limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to pay distributions to our unitholders, which could materially decrease our ability to pay such distributions.
We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and may limit our flexibility to obtain financing and to pursue other business opportunities.
At December 31, 2020, we had $1.3 billion of indebtedness outstanding and the unused portion of our $1.1 billion Revolving Credit Facility totaled $238.9 million, subject to an issued but undrawn letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of December 31, 2020 was approximately $105 million. See Note 9 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our debt obligations, including debt maturities for the next five years and thereafter. Our existing and future debt services obligations could have significant consequences, including among other things:
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limiting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes and/or obtaining such financing on favorable terms;
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reducing our funds available for operations, future business opportunities and cash distributions to unitholders by that portion of our cash flow required to make interest payments on our debt;
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increasing our vulnerability to competitive pressures or a downturn in our business or the economy generally; and
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limiting our flexibility in responding to changing business and economic conditions.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control, such as commodity prices and governmental regulation.
Restrictions in our Revolving Credit Facility and Senior Notes indentures could materially adversely affect our business, financial condition, results of operations, ability to make cash distributions to unitholders and value of our common units.
We are dependent upon the earnings and cash flows generated by our operations to meet our debt service obligations and to make cash distributions to our unitholders, if any. The operating and financial restrictions and covenants in our Revolving Credit Facility, our Senior Notes indentures and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders. For example, our Revolving Credit Facility and Senior Notes indentures, taken together, restrict our ability to, among other things:
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incur or guarantee certain additional debt;
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make certain cash distributions on or redeem or repurchase certain units;
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make certain investments and acquisitions;
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make certain capital expenditures;
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incur certain liens or permit them to exist;
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enter into certain types of transactions with affiliates;
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enter into sale and lease-back transactions and certain operating leases;
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merge or consolidate with another company or otherwise engage in a change of control transaction; and
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transfer, sell or otherwise dispose of certain assets.
Our Revolving Credit Facility and Senior Notes indentures also contain covenants requiring us to maintain certain financial ratios and meet certain tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot guarantee that we will meet those ratios and tests. Based upon the terms of our Revolving Credit Facility and total outstanding debt of $1.3 billion (inclusive of $494 million of senior unsecured notes, net of debt issuance costs), our total leverage ratio first lien secured leverage ratio (as defined in the credit agreement) as of December 31, 2020, were 5.1 to 1.0 and 3.2 to 1.0, respectively, relative to maximum threshold limits of 5.75x and 3.5x.
The provisions of our Revolving Credit Facility and Senior Notes indentures may affect our ability to obtain future financing and pursue attractive business opportunities as well as affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our Revolving Credit Facility or Senior Notes indentures could result in a default or an event of default that could enable our lenders and/or senior noteholders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, the lenders under our Revolving Credit Facility could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. The Revolving Credit Facility also has cross default provisions that apply to any other indebtedness we may have and the Senior Notes indentures have cross default provisions that apply to certain other indebtedness. Any of these restrictions in our Revolving Credit Facility and Senior Notes indentures could materially adversely affect our business, financial condition, cash flows and results of operations.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful.
Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including our Revolving Credit Facility and our Senior Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our operating cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to adopt alternative financing strategies, such as reducing or delaying investments and capital expenditures, selling assets, seeking additional capital or restructuring or refinancing our indebtedness, some or all of which may not be available to us on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness.
Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets, including the market for senior unsecured notes, and our financial condition at the time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our Revolving Credit Facility and the indentures governing our Senior Notes place certain restrictions on our ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions on terms acceptable to us, if at all, and the proceeds of any such dispositions may not be adequate to meet any debt service obligations then due.
Further, if for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our Revolving Credit Facility could terminate their commitments to extend credit, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. If the amounts outstanding under our Revolving Credit Facility or our Senior Notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to our creditors.
A downgrade of our credit rating could impact our liquidity, access to capital and our costs of doing business, and independent third parties determine our credit ratings outside of our control.
A downgrade of our credit rating could increase our cost of borrowing under our Revolving Credit Facility and could require us to post collateral with third parties, including our hedging arrangements, which could negatively impact our available liquidity and increase our cost of debt. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when we are experiencing significant working capital requirements or otherwise lacking liquidity, our results of operations, financial condition and cash flows could be adversely affected.
We have in the past and may in the future incur losses due to impairment in the carrying value of our long-lived assets or equity method investments.
We recorded long-lived asset impairments of $13.1 million and $60.5 million in 2020 and 2019, respectively. In 2019, we also recorded an impairment of our equity method investment in Ohio Gathering of $329.7 million and a loss of $6.3 million related to a long-lived asset impairment on OCC. When evidence exists that we will not be able to recover a long-lived asset's carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test long-lived assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. With respect to property, plant and equipment and our amortizing intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset's use and eventual disposal. In this situation, we recognize an impairment loss equal to the amount by which the carrying value exceeds the asset's fair value. We determine fair value using either a market-based approach, an income-based approach in which we discount the asset's expected future cash flows to reflect the risk associated with achieving the underlying cash flows, or a mixture of both market- and income-based approaches. We evaluate our equity method investment for impairment whenever events or circumstances indicate that a decline in fair value is other than temporary. Any impairment determinations involve significant assumptions and judgments. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to impairment charges. Adverse changes in our business or the overall operating environment, such as lower commodity prices, may affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.
A portion of our revenues are directly exposed to changes in crude oil, natural gas and NGL prices, and our exposure may increase in the future.
During the year ended December 31, 2020, we derived 13% of our revenues from (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Williston Basin, Piceance Basin, and Permian Basin segments, (ii) natural gas and crude oil marketing services in and around our gathering systems, (iii) the sale of natural gas we retain from certain Barnett Shale customers and (iv) the sale of condensate we retain from our gathering services in the Piceance Basin segment. Consequently, our existing operations and cash flows have direct exposure to commodity price risk. Although we will seek to limit our commodity price exposure with new customers in the future, our efforts to obtain fee-based contractual terms may not be successful or the local market for our services may not support fee-based gathering and processing agreements. For example, we have percent-of-proceeds contracts with certain natural gas producer customers and we may, in the future, enter into additional percent-of-proceeds contracts with these customers or other customers or enter into keep-whole arrangements, which would increase our exposure to commodity price risk, as the revenues generated from those contracts directly correlate with the fluctuating price of the underlying commodities.
Furthermore, we may acquire or develop additional midstream assets in the future that have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of natural gas and crude oil prices could have a material adverse effect on our business, results of operations and financial condition. For example, for a small portion of the natural gas gathered on our systems, we purchase natural gas from producers prior to delivering the natural gas to pipelines where we typically resell the natural gas under arrangements including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices. If we expand the implementation of such natural gas purchase and sale arrangements within our business, such fluctuations could materially affect our business.
If we fail to maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
As a publicly traded partnership, we are subject to the public reporting requirements of the Exchange Act, including the rules thereunder that will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP. Our efforts to maintain our internal controls may not be successful and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002.
Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our or our independent registered public accounting firm’s future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls over financial reporting could subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
Regulatory and Environmental Policy Risks
We are under investigation by federal and state regulatory agencies over a pipeline rupture and release of produced water by one of our subsidiaries. The resolution of this matter could have a material adverse effect on our results of operations or cash flows.
As further described in Item 3. Legal Proceedings, an incident involving a produced water disposal pipeline owned by Meadowlark Midstream that resulted in a discharge of materials into the environment is under investigation by federal and state agencies pursuant to various laws that may give rise to criminal and civil liability. A loss arising from this incident is probable, and the ultimate outcome could have a material ‎adverse effect on our results of operations or cash flows. We have accrued a loss contingency for this incident but cannot predict whether any actual loss, if one were to occur, would be materially higher or lower than such accrual.
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. As a result, we may be required to expend significant funds for legal defense or to settle claims. Any such loss, if incurred, could be material.
Expenditures made by the Partnership for the payment of litigation related costs, including legal defense costs and settlement payments, if any, reduce our cash flows available for debt service and distributions to our unitholders, if any. Any such expenditures, if incurred, could be material. See Item 3. Legal Proceedings for additional disclosure by the Partnership regarding its ongoing litigation and claims.
A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase.
Various aspects of our operations are subject to regulation by the various federal, state and local departments and agencies that have jurisdiction over participants in the energy industry. The regulation of our activities and the natural gas and crude oil industries frequently change as they are reviewed by legislators and regulators. In 2016, the NDIC adopted rule changes that resulted in additional construction and monitoring requirements for certain underground gathering pipelines, including, but not limited to, those that transport produced water. The NDIC also adopted reclamation bonding requirements for certain underground gathering pipelines. At the federal level, PHMSA has issued new proposed and final rules concerning pipeline safety in recent years. To that extent these proposed or final rules create additional requirements for our pipelines, they could have a material adverse effect on our operations, operating and maintenance expenses and revenues. For additional information on the potential risks associated with PHMSA requirements, see the “We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements” section of Item 1.A. Risk Factors.
In addition, the adoption of proposals for more stringent legislation, regulation or taxation of drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services. For example, in 2018 the Colorado state ballot included a proposed 2,500 foot setback for oil and gas development from occupied structures and certain other areas. While the proposal did not pass, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the COGCC from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state. Further, in November 2020, the COGCC adopted new regulations that increase oil and gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibit routine venting and flaring, increase wildlife protections, and alter certain aspects of the permitting process. These regulations and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. Regulatory agencies establish and, from time to time, change priorities, which may result in additional burdens on us, such as additional reporting requirements and more frequent audits of operations. Our operations and the markets in which we participate are affected by these laws, regulations and interpretations and may be affected by changes to them or their implementation, which may cause us to realize materially lower revenues or incur materially increased operation and maintenance costs or both.
Increased regulation of hydraulic fracturing could result in reductions or delays in customer production, which could materially adversely impact our revenues.
Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations, and is primarily regulated by state agencies. However, Congress has in the past, and may in the future consider legislation to regulate hydraulic fracturing by federal agencies. Many states have already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing. A number of states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure and well construction requirements on crude oil and/or natural gas drilling activities. For example, a Colorado ballot initiative, Proposition 112, would have substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and gas development in the state. Although Proposition 112 was defeated in the November 2018 elections, similar ballot initiatives have been circulated by interested groups for potential consideration in elections. Further, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the COGCC from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state. Further, in November 2020, the COGCC adopted new regulations that increase oil and gas setbacks to a minimum of 2,000 feet from schools and childcare facilities, prohibit routine venting and flaring, increase wildlife protections, and alter certain aspects of the permitting process. These regulations and similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. States also could elect to prohibit hydraulic fracturing altogether, as New York, Maryland, and Vermont have done. In addition, certain local governments have adopted, and additional local governments may adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.
The EPA has also moved forward with various regulatory actions, including approving regulations requiring green completions of hydraulically-fractured wells and corresponding reporting requirements (NSPS OOOO) that went into effect in 2015. Revisions to the green completion regulations (NSPS OOOOa) were finalized in June 2016 and include additional requirements to reduce methane and VOCs. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of NSPS OOOO and OOOOa applicable to sources in the production and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. Court of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directed EPA to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules, as well as to consider establishing methane and VOC emission standards for existing sources in the oil and gas sector, including the transportation and storage segments. The BLM has also asserted regulatory authority over aspects of the hydraulic fracturing process, and issued a final rule in March 2015 that established more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The U.S. District Court for the Northern District of California upheld the December 2017 rescission rule in a March 2020 decision. The State of California and environmental plaintiffs then appealed the decision in June 2020. Litigation is currently ongoing.
Further, several federal governmental agencies have conducted reviews and studies on the environmental aspects of hydraulic fracturing, including the EPA. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.
State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. Some state regulatory agencies, including those in Colorado, Ohio, and Texas, have modified their regulations or guidance to account for induced seismicity. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers.
Additionally, certain of our customers produce oil and gas on federal lands. On January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices.
If new or more stringent federal, state or local legal restrictions relating to drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and/or crude oil that our customers produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business.
We are subject to FERC jurisdiction, federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements and state and local regulation and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.
We believe that our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC under the NGA and the NGPA. Interstate movements of crude oil on the Epping Pipeline in North Dakota are subject to FERC jurisdiction under the ICA, and the rates, terms and conditions of service, and practices on the pipeline are subject to review and challenge before FERC. Additionally, our proposed Double E Project, for which FERC approved the implementation plan in January 2021, and which is anticipated to provide natural gas transmission service from southeastern New Mexico to the Waha Hub in Texas, will be subject to FERC jurisdiction once completed. FERC may include conditions on its issuance of the certificate that make a project impracticable or too costly, or may ultimately determine not to issue the certificate required for us to pursue the project. Typically, a pipeline project requires review by a number of governmental agencies, including FERC, and other federal, state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any delay or refusal by an agency to issue authorizations or permits as requested for the project may mean that they will be constructed in a manner or with capital requirements that we did not anticipate or that we will not be able to pursue the project. Such delay, modification or refusal could materially and negatively impact the additional revenues expected from the project. In addition to approving and regulating the construction and operation of interstate natural gas pipelines, FERC also regulates such pipelines’ rates and terms and conditions of service, including transportation service agreements and negotiated rate agreements.
We are also generally subject to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, and to FERC’s regulations thereunder, which authorize FERC to impose fines of up to $1,307,164 per day per violation of the NGA or its implementing regulations, subject to future adjustment for inflation. In addition, the FTC holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in oil markets, and has adopted broad rules and regulations prohibiting fraud and market manipulation. The FTC is also authorized to seek fines of up to $1,246,249 per violation, subject to future adjustment for inflation. The CFTC is directed under the CEA to prevent price manipulation in the commodity, futures and swaps markets, including the energy markets. Pursuant to the Dodd-Frank Act, and other authority, the CFTC has adopted additional anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity, futures and swaps markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,227,202 per violation, subject to future adjustment for inflation, or triple the monetary gain to the violator for each violation of the anti-market manipulation provisions of the CEA.
The distinction between federally unregulated natural gas and crude oil pipelines and FERC-regulated natural gas and crude oil pipelines has been the subject of extensive litigation and is determined by FERC on a case-by-case basis. FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC, Congress or the courts. If our natural gas gathering operations or crude oil operations beyond the Epping Pipeline become subject to FERC jurisdiction under the NGA, the NGPA or the ICA, the result may materially adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, the NGPA or the ICA, this could result in the imposition of civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC.
We are subject to state and local regulation regarding the construction and operation of our gathering, treating and processing systems, as well as state ratable take statutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or build new facilities and such regulation may cause us to incur additional operating costs or limit the quantities of natural gas and crude oil we may gather, treat and process. Ratable take statutes and regulations generally require gatherers to take natural gas and crude oil production that may be tendered for gathering without undue discrimination. These requirements restrict our right to decide whose production we gather, treat and process. Many states have adopted complaint-based regulation of gathering, treating and processing activities, which allows producers and shippers to file
complaints with state regulators in an effort to resolve access issues, rate grievances and other matters. Other state and municipal regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas and crude oil for gathering, treating and processing, including state regulation of production rates, maximum daily production allowable from wells, and other activities related to drilling and operating wells. While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs and revenues.
Recent actions by the FERC may affect rates on Epping Pipeline and other future FERC-regulated pipelines.
On March 15, 2018, FERC announced a revised policy prohibiting FERC-jurisdictional natural gas and liquids pipelines owned by master limited partnerships from including an allowance for income taxes in the cost of service used to calculate tariff rates. Most of our pipelines are not subject to FERC regulation and so will not be affected by the revised policy statement. However, rates for interstate movements of crude oil on our Epping Pipeline in North Dakota and any future FERC-regulated pipelines may be affected by the application of the revised policy statement in subsequent FERC proceedings.
FERC has not required regulated interstate oil pipelines to decrease their rates on an industry-wide basis to implement the new policy. However, FERC stated that the effects of the revised policy statement must be incorporated in annual FERC financial reports made by regulated interstate oil pipelines. These reports, which also reflected the impact of the corporate income tax reduction enacted as part of the Tax Reform Legislation, were considered by FERC in its five-year review and determination of the index rate adjustment, which resulted in the December 17, 2020 order adopting a new annual index adjustment for the five-year period starting July 1, 2021. FERC ultimately removed the effect of the income tax allowance policy change from its index calculation, although the December 17, 2020 order is subject to rehearing and possible judicial review. The impact of these future proceedings on Epping Pipeline and any future FERC-regulated pipelines is uncertain at this time.
Until FERC sets the next index rate adjustment, Epping Pipeline and any future FERC-regulated pipelines may face an increased risk of shipper complaints seeking FERC review of its rates. FERC can also initiate review of rates on its own initiative. We could also propose new cost-of-service rates or changes to our existing rates that would be subject to review by FERC under its new policy. No such proceedings have occurred at this time, however, and the potential outcome of any such proceedings, should any materialize, is uncertain. As a result of any such proceedings, Epping Pipeline and any future FERC-regulated pipelines may be required to modify their rates, which could affect the revenues we generate with our Epping Pipeline and any future FERC-regulated pipelines. At this time, we do not expect any such proceedings would have a material adverse effect, but we intend to monitor FERC developments and provide updated disclosure, as necessary.
We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
Our gathering, treating and processing operations are subject to stringent and complex federal, state and local environmental laws and regulations, including laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection, including, for example, the CAA, CERCLA, the CWA, the OPA, the RCRA, the Endangered Species Act and the Toxic Substances Control Act.
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. For additional information on specific laws and regulations, see the "Environmental Matters " section of Item 1. Business. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and requisite permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.
There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and
discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass, and on which certain of our facilities are located, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance.
The new presidential administration and Democratic control of Congress resulting from the 2020 elections may result in increased restrictions on oil and gas production activities, which could materially adversely affect our industry and our financial condition and results of operations.
We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.
The DOT, through PHMSA, has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is located. While the majority of our pipelines meet the DOT definition of gathering lines and are thus currently exempt from PHMSA's integrity management requirements, we also operate a limited number of pipelines that are subject to the integrity management requirements. The regulations require operators, including us, to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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maintain processes for data collection, integration and analysis;
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repair and remediate pipelines as necessary;
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adopt and maintain procedures, standards and training programs for control room operations; and
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implement preventive and mitigating actions.
For additional information on PHMSA regulations relating to pipeline safety, see the "Regulation of the Natural Gas and Crude Oil Industries-Safety and Maintenance" section of Item 1. Business.
In July 2018, the PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. The associated notice of proposed rulemaking, issued October 14, 2020, proposes to amend the requirements for gas transmission pipeline segments that experience a change in class location by offering an alternative set of requirements operators could use, based on implementing integrity management principles and pipe eligibility criteria, to manage certain pipeline segments where the class location has changed from a Class 1 location to a Class 3 location. In October 2019, the PHMSA issued three new final rules. One rule, which became effective in December 2019, establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows the PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules, which became effective in July 2020, impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond “high consequence areas” (HCAs) to pipelines in “moderate consequence areas” (MCAs). It also includes requirements to reconfirm Maximum Allowable Operating Pressure (MAOP), report MAOP exceedances, consider seismicity as a risk factor in integrity management, and use certain safety features on in-line inspection equipment. The
rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events, and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. Further, in December 2020, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 became law, reauthorizing PHMSA for funding through 2023 and requiring, among other things, rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. While we believe that we are in compliance with existing safety laws and regulations, increased penalties for safety violations and potential regulatory changes could have a material adverse effect on our operations, operating and maintenance expenses and revenues.
Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the services we provide.
In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of GHGs, such as carbon dioxide and methane that may be contributing to global warming and energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. For example, the revisions to the NSPS found in 40 CFR 60 subpart OOOO (and OOOOa) include emission reduction requirements. In August 2020, the EPA issued two final rules that rescinded the methane-specific requirements of NSPS OOOO and OOOOa applicable to sources in the production and processing segments and removed the transmission and storage segment from the source category. However, these 2020 rules are being challenged in the U.S. Court of Appeals for the D.C. Circuit. In addition, President Biden’s January 20, 2021 Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” directed EPA to consider publishing a proposed rule suspending, revising, or rescinding the 2020 rules, as well as to consider establishing methane and VOC emission standards for existing sources in the oil and gas sector, including the transportation and storage segments.
In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). It is possible that certain components of our operations, such as our gas-fired compressors, could become subject to state-level GHG-related regulation. For example, in January 2019, the governor of New Mexico signed an executive order that includes a goal of reducing statewide GHG emissions by at least 45% by 2030. The executive order directs the New Mexico Energy, Minerals and Natural Resources Department (“EMNRD”) and the New Mexico Environment Department (“NMED”) to jointly develop a statewide, enforceable regulatory framework to secure reductions in oil and gas sector methane emissions. The executive order also creates a Climate Change Task Force to evaluate and develop regulatory strategies to reach the 45% reduction goal. In July 2020, NMED released draft rules that would establish emissions standards for VOCs and nitrogen oxides for oil and gas production and processing sources located in certain areas of the state with high ozone concentrations. Similarly, EMNRD released draft rules concerning venting and flaring of natural gas. Neither agency has yet issued a final rule. Although we cannot currently determine the effect of the proposed regulations developed by the EMNRD and the NMED or other potential regulatory strategies that may be suggested by the Climate Change Task Force, if implemented they could be material to the business, reputation, financial condition or results of operations of our Summit Permian system.
Independent of Congress, the EPA has adopted regulations under its existing CAA authority. In 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources of GHG emissions. For additional information on EPA regulations adopted under the CAA, see the "Environmental Matters-Climate Change" section of Item 1. Business. Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions. The agreement entered into force in November 2016 after over 70
countries, including the United States, ratified or otherwise consented to be bound by the agreement. In November 2019, the United States submitted formal notification to the United Nations that it intended to withdraw from the agreement. However, on January 20, 2021, President Biden signed an “Acceptance on Behalf of the United States of America” that, reversed the prior withdrawal, and the United States officially rejoined the Paris Agreement on February 19, 2021. In addition, shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change. Reentry into the Paris Agreement and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations, which could have a material adverse effect on our business and that of our customers.
Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal or state laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could materially adversely affect demand for our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of GHG could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions, adhere to alternative energy requirements and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates we charge, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations. Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. We cannot predict with any certainty at this time how these possibilities may affect our operations.
The implementation of statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.
Congress adopted comprehensive financial reform legislation under the Dodd-Frank Act that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. This legislation requires the CFTC and the SEC and other regulatory authorities to promulgate certain rules and regulations, including rules and regulations relating to the regulation of certain swaps market participants, such as swap dealers, the clearing of certain swaps through central counterparties, the execution of certain swaps on designated contract markets or swap execution facilities, mandatory margin requirements for uncleared swaps, and the reporting and recordkeeping of swaps. While most of the regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing. Moreover, CFTC continues to refine its initial rulemakings under the Dodd-Frank Act. As a result, we cannot yet predict the ultimate effect of the rules and regulations on our business and while most of the regulations have been adopted, any new regulations or modifications to existing regulations could increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties.
The CFTC has proposed federal position limits on certain core futures and equivalent swaps contracts in the major energy and other markets, with exceptions for certain bona fide hedging transactions provided that various conditions are satisfied. If finalized, the position limits rule and its companion rule on aggregation among entities under common ownership or control may have an impact on our ability to hedge our exposure to certain enumerated commodities.
In 2013, the CFTC implemented final rules regarding mandatory clearing of certain classes of interest rate swaps and certain classes of index credit default swaps. Mandatory trading on designated contract markets or swap execution facilities of certain interest rate swaps and index credit default swaps also began in 2014. At this time, the CFTC has not proposed any rules designating other classes of swaps, including physical commodity swaps, for mandatory clearing. The CFTC and prudential banking regulators also recently adopted mandatory margin requirements on uncleared swaps between swap dealers and certain other counterparties. Although we may qualify for a commercial end-user exception from the mandatory clearing, trade execution and uncleared swaps margin requirements, mandatory clearing and trade execution requirements and uncleared swaps margin requirements applicable to other market participants, such as swap dealers, may affect the cost and availability of the swaps that we use for hedging.
Under the Dodd-Frank Act, the CFTC is also directed generally to prevent price manipulation and fraud in the following two markets: (a) physical commodities traded in interstate commerce, including physical energy and other commodities, as well as (b) financial instruments, such as futures, options and swaps. Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-market manipulation, anti-fraud and disruptive trading practices regulations that prohibit, among other things, fraud and price manipulation in the physical commodities, futures, options and swaps markets. Should we violate these laws and regulations, we could be subject to CFTC enforcement action and material penalties, and sanctions.
We currently enter into forward contracts with third parties to buy power and sell natural gas in an attempt to mitigate our exposure to fluctuations in the price of natural gas with respect to those volumes. The CFTC has finalized an interpretation clarifying whether certain forwards with volumetric optionality are regulated as forwards or qualify as options on commodities and therefore swaps. This interpretation may have an impact on our ability to enter into certain forwards or may impose additional requirements with respect to certain transactions.
In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make any transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more costly to satisfy regulatory obligations.
We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from various groups.
We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from environmental groups, landowners, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or other facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our unitholders and, accordingly, have a material adverse effect on our business, financial condition and results of operations. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.
For example, in an April 15, 2020 ruling, amended May 11, 2020, the U.S. District Court for the District of Montana issued an order invalidating the U.S. Army Corps of Engineers (“Corps”) 2017 reissuance of Nationwide Permit 12 (“NWP 12”), the general permit governing dredge-and-fill activities for pipeline and other utility line construction projects, to the extent it was used to authorize construction of new oil and gas pipelines. Environmental groups had alleged that the Corps failed to consult with federal wildlife agencies as required by the Endangered Species Act. The court’s decision vacated NWP 12 until the Corps completes consultation with the applicable federal wildlife agencies. On July 6, 2020, the U.S. Supreme Court granted in part the Corps’ request to stay the U.S. District Court’s decision to allow the use of NWP 12 for utility line activities, including new oil and gas pipelines, pending the outcome of the appeal to the U.S. Court of Appeals for the Ninth Circuit and any subsequent petition for review to the U.S. Supreme Court. Litigation is currently ongoing. In addition, in January 2021, the EPA and Corps reissued NWP 12 as a general permit specific to oil and gas pipelines, moving other utility line activities into separate general permits. However, the NWP reissuance is among the agency actions listed for review in accordance with the January 20, 2021 Executive Order: “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.” Limitations on the use of NWP 12 may make it more difficult to permit our projects, require consideration of alternative construction or siting, which may impose additional costs and delays, and could cause us to lose potential and current customers and limit our growth and revenue.
In addition, on July 6, 2020, the U.S. District Court for the District of Columbia issued an order vacating a Corps Mineral Leasing Act easement for the Dakota Access Pipeline in a lawsuit filed by American Indian Tribes. The court’s decision requires the pipeline to shut down operations by August 5, 2020, but was stayed by the U.S. Court of Appeals for the District of Columbia Circuit. On January 26, 2021, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision affirming the district court’s holding that the easement should be vacated, but reversing the requirement to shut down the pipeline. The Court of Appeals left it to the Corps to determine how to proceed after the loss of the easement, and the District Court has received briefing on whether to enjoin the operation of the pipeline as a result. The Dakota Access Pipeline continues to operate pending the District Court’s ruling or a decision by the Corps to order the pipeline to shut down. If the Dakota Access Pipeline is forced to shut down, this could have a material adverse effect on our business, financial condition and results of operations associated with the Polar and Divide System, which interconnects with the Dakota Access Pipeline.
Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds, individual investors and other sources of capital restricting or eliminating their investment in fossil fuel-related activities. In addition, financial institutions have begun to screen companies such as ours for sustainability performance, including practices related to GHGs and climate change, before providing loans or investing in our common units. There is also a risk that financial institutions may adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, such as the adoption of net zero financed emissions targets. Such policies may be hastened by actions under the Biden Administration, including the implementation by the Federal Reserve of any recommendations made by the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Ultimately, this could make it more difficult to secure funding for exploration and production activities or energy infrastructure related projects, and consequently could both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to maintain access to capital or perform services for certain customers.
Our business is subject to complex and evolving U.S. and International laws and regulations regarding privacy and data protection (“data protection laws”). Many of these laws and regulations are subject to change and uncertain interpretation, and could result in claims, increased cost of operations or otherwise harm our business.
Along with our own data and information in the normal course of our business, we and our partners collect and retain significant volumes of certain types of data, some of which are subject to specific laws and regulations. The transfer and use of this data both domestically and across international borders is becoming increasingly complex. The regulatory environment surrounding and the transfer and protection of such data is constantly evolving and can be subject to significant change. New data protection laws at the federal, state, international, national, provincial and local levels, including recent Colorado legislation, the European Union General Data Protection Regulation (“GDPR”) and the California Consumer Privacy Act (“CCPA”), pose increasingly complex compliance challenges and potentially elevate our costs.
Complying with these jurisdictional requirements could increase the costs and complexity of compliance, and violations of applicable data protection laws can result in significant penalties. For example, the GDPR applies to activities regarding personal data that may be conducted by us, directly or indirectly through vendors and subcontractors, from an establishment in the European Union. Failure to comply could result in significant penalties of up to a maximum of 4% of our global turnover that may materially adversely affect our business, reputation, results of operations, and cash flows. Similarly, the CCPA, which came into effect on January 1, 2020, gives California residents specific rights in relation to their personal information, requires that companies take certain actions, including notifications for security incidents and may apply to activities regarding personal information that is collected by us, directly or indirectly, from California residents. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, which could cause us to change our business practices, with the possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows.
As noted above, we are also subject to the possibility of information security breaches, which themselves may result in a violation of these laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.
Risks Inherent in an Investment in Us
Because our common units are yield-oriented securities, increases in interest rates could materially adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions to our unitholders.
Interest rates are generally near historic lows and may increase in the future. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have a material adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
The amount of cash we have available for distribution to holders of our units depends primarily on our cash flows rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flows and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we report net losses for GAAP purposes and may not make cash distributions during periods when we report net income for GAAP purposes.
The market price of our common units may fluctuate significantly and, due to limited daily trading volumes, an investor could lose all or part of its investment in us.
An investor may not be able to resell its common units at or above its acquisition price. Additionally, limited liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.
The market price of our common units may decline and be influenced by many factors, some of which are beyond our control, including among others:
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our quarterly distributions, if any;
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our quarterly or annual earnings or those of other companies in our industry;
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the loss of a large customer;
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announcements by our customers or others regarding our customers or changes in our customers’ credit ratings, liquidity position, leverage profile and/or other financial or credit-related metrics;
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announcements by our competitors of significant contracts or acquisitions;
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changes in accounting standards, policies, guidance, interpretations or principles;
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general economic and geopolitical conditions;
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the failure of securities analysts to cover our common units or changes in financial estimates by analysts; and
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other factors described in these Risk Factors.
Our Partnership Agreement replaces our General Partner’s fiduciary duties to unitholders and those of our officers and directors with contractual standards governing their duties.
Our Partnership Agreement contains provisions that eliminate fiduciary duties to which our General Partner and its officers and directors would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards.
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the Partnership Agreement, including the provisions discussed above.
Our Partnership Agreement limits the liabilities of our General Partner and its officers and directors and the rights of our unitholders with respect to actions taken by our General Partner and its officers and directors that might otherwise constitute breaches of fiduciary duty.
Our Partnership Agreement contains provisions that limit the liability of our General Partner and the rights of our unitholders with respect to actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement provides that:
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whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;
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our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as such decisions are made in good faith;
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our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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our General Partner will not be in breach of its obligations under the Partnership Agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:
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approved by the Conflicts Committee, although our General Partner is not obligated to seek such approval;
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approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates;
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on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
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fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our General Partner or the Conflicts Committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the Conflicts Committee and the Board of Directors determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the final two subclauses above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders' voting rights are further restricted by a provision of our Partnership Agreement providing that any person or group that owns 20% or more of any class of units then outstanding cannot vote on any matter, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors.
We may issue additional units without unitholder approval, which would dilute existing ownership interests.
Except in the case of the issuance of units that rank equal to or senior to the Series A Preferred Units, our Partnership Agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units that we may issue at any time without the approval of our unitholders.
We may issue additional Series A Preferred Units and any securities in parity with the Series A Preferred Units without any vote of the holders of the Series A Preferred Units (except where the cumulative distributions on the Series A Preferred Units or any parity securities are in arrears and in certain other circumstances) and without the approval of our common unitholders.
The issuance by us of additional common units or other equity securities of equal or senior rank will decrease our existing unitholders' proportionate ownership interest in us. In addition, the issuance by us of additional common units or other equity securities of equal or senior rank may have the following effects:
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decreasing the amount of cash available for distribution on each unit;
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increasing the ratio of taxable income to distributions;
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diminishing the relative voting strength of each previously outstanding unit; and
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causing the market price of the common units to decline.
Future issuances and sales of parity securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for our common units and the Series A Preferred Units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.
Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, including units issued to third parties at a subsidiary level, their issuance will increase the uncertainty of the payment of distributions on our common units.
Holders of Series A Preferred Units have limited voting rights, which may be diluted.
Although holders of the Series A Preferred Units are entitled to limited voting rights with respect to certain matters, the Series A Preferred Units generally vote separately as a class along with any other series of our parity securities that we may issue upon which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Series A Preferred Units may be significantly diluted, and the holders of such other series of parity securities that we may issue may be able to control or significantly influence the outcome of any vote.
Our General Partner has a limited call right that may require an investor to sell its units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 80% of our outstanding common units, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our Partnership Agreement. As a result, an investor may be required to sell its common units at an undesirable time or price and may not receive any return on its investment. An investor may also incur a tax liability upon a sale of its units.
An investor's liability may not be limited if a court finds that unitholder action constitutes control of our business.
A General Partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the General Partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. An investor could be liable for any and all of our obligations as if it was a General Partner if a court or government agency were to determine that:
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we were conducting business in a state but had not complied with that particular state's partnership statute; or
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an investor's right to act with other unitholders to remove or replace our General Partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute control of our business.
Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which limits our unitholders’ ability to choose the judicial forum for disputes with us or our General Partner’s directors, officers or other employees.
Our Partnership Agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware is the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our Partnership Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our Partnership Agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty (including a fiduciary duty) owed by any of our, or our General Partner’s, directors, officers, or other employees, or owed by our General Partner, to us or our partners, (4) asserting a claim against us arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act or (5) asserting a claim against us governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in our common units is deemed to have received notice of and consented to the foregoing provisions. This exclusive forum provision does not apply to a cause of action brought under federal or state securities laws. Although management believes this choice of forum provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against us and our General Partner’s directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings and it is possible that in connection with any action a court could find the choice of forum provisions contained in our Partnership Agreement to be inapplicable or unenforceable in such action. If a court were to find this choice of forum provision inapplicable
to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the Partnership Agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
If an investor is not an eligible holder, it may not receive distributions or allocations of income or loss on those common units and those common units will be subject to redemption.
We have adopted certain requirements regarding those investors who may own our common units and Series A Preferred Units. Eligible holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity's owners are U.S. individuals or entities subject to such taxation. If an investor is not an eligible holder, our General Partner may elect not to make distributions or allocate income or loss on that investor's units, and it runs the risk of having its units redeemed by us at the lower of purchase price cost or the then-current market price. The redemption price may be paid in cash or by delivery of a promissory note, as determined by our General Partner.
Our Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.
The Series A Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units or could make it more difficult for us to sell our common units in the future.
In addition, (i) prior to December 15, 2022, distributions on the Series A Preferred Units accumulate and are cumulative at the rate of 9.50% per annum of $1,000, the liquidation preference of the Series A Preferred Units and (ii) on and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of $1,000 equal to the three-month LIBOR plus a spread of 7.43%. On May 3, 2020, we announced the suspension of distributions payable on both our common units and our Series A Preferred Units. We did not make a distribution on our common units with respect to any quarter in 2020, nor did we make a distribution on our Series A Preferred Units on June 15, 2020 or December 15, 2020. As of December 31, 2020, the amount of accrued and unpaid distributions on the Series A Preferred Units was $15.8 million. Unpaid distributions on the Series A Preferred Units will continue to accrue.
In addition, our Subsidiary Series A Preferred Units issued by Permian Holdco have priority over the common unitholders with respect to the cash flow from Permian Holdco. The distribution rate of the Subsidiary Series A Preferred Units is 7.00% per annum of the $1,000 issue amount per outstanding Subsidiary Series A Preferred Unit. Permian Holdco has the option to pay this distribution in-kind until the earlier of June 30, 2022 or the first full quarter following the date the Double E pipeline is placed in service.
Our obligation to pay distributions on our Series A Preferred Units and Permian Holdco’s obligation to pay the distributions on the Subsidiary Series A Preferred Units could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Our obligations to the holders of the Series A Preferred Units and Permian Holdco’s obligations to the holders of the Subsidiary Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.
Our Series A Preferred Units contain covenants that may limit our business flexibility.
Our Series A Preferred Units contain covenants preventing us from taking certain actions without the approval of the holders of 66 2/3% of the Series A Preferred Units. The need to obtain the approval of holders of the Series A Preferred Units before taking these actions could impede our ability to take certain actions that management or the Board of Directors may consider to be in the best interests of our unitholders. The affirmative vote of 66 2/3% of the outstanding Series A Preferred Units, voting as a single class, is necessary to amend the Partnership Agreement in any manner that would have a material adverse effect on the existing preferences, rights, powers, duties or obligations of the Series A Preferred Units. The affirmative vote of 66 2/3% of the outstanding Series A Preferred Units and any outstanding series of other preferred units, voting as a single class, is necessary to (A) under certain circumstances, create or issue certain equity securities that are senior to our common units, (B) declare or pay any distribution to common unitholders out of capital surplus or (C) take any action that would result in an event of default for failure to comply with any covenant in the indentures governing the 5.5% Senior Notes or the 2025 Senior Notes co-issued by Summit Holdings and its 100% owned finance subsidiary, Finance Corp.
Although holders of the Series A Preferred Units are entitled to limited voting rights with respect to certain matters, the Series A Preferred Units generally vote as a class, separate from our common unitholders, along with any other series of our parity securities that we may issue upon which like voting rights have been conferred and are exercisable.
Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21%, and would likely pay state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reductions in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units. This could adversely affect our financial position, results of operations and ability to make distributions to our unitholders.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships.
Any modification to the U.S. federal income tax laws and interpretations could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our units.
Our unitholders are required to pay income taxes on their share of our taxable income even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law and may be substantially different from any estimate we make in connection with a unit offering.
A unitholder’s allocable share of our taxable income will be taxable to it, which may require the unitholder to pay federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives cash distributions from us that are less than the actual tax liability that results from that income or no cash distributions at all.
A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage. For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt, or an actual or deemed satisfaction of our indebtedness for an amount less than the adjusted issue price of the debt. A unitholder’s ratio of its share of taxable income to the cash received by it may also be affected by changes in law. For instance, under Tax Reform Legislation, the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity’s “adjusted taxable income,” which is generally taxable income with certain modifications. If the limit applies, a unitholder’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.
From time to time, in connection with an offering of our common units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of common units in that offering may receive in a given period. These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other common units will be different, and in many cases less favorable, than these estimates. Moreover, even in the case of common units purchased in the offering to which the estimate relates, the estimate may be incorrect, due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt, or other factors. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units.
We have engaged in recent transactions that generated substantial COD income on a per unit basis relative to the trading price of our common units. We may engage in other transactions that result in substantial COD income or other gains in the future, and such events may cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to the unitholder.
A unitholder’s share of our taxable income will include any COD income recognized upon the satisfaction of our outstanding indebtedness for total consideration less than the adjusted issue price (and any accrued but unpaid interest) of such indebtedness. In 2020, we engaged in various liability management transactions that resulted in substantial COD income. We may engage in other transactions that result in substantial COD income or other gains, such as gains upon assets sales, in the future. Depending upon the net amount of other items related to our loss (or income) allocable to a unitholder, any COD income or other gains may cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to the unitholder. Furthermore, such COD income event or other gain event may not be fully offset, either now or in the future, by capital losses, which are subject to significant limitations, or other losses. Accordingly, a COD income event or other gain event could cause a unitholder to realize taxable income without corresponding future economic benefits or offsetting tax deductions.
If the IRS contests the federal income tax positions we take, the market for our units may be adversely impacted and the cost of any IRS contest would likely reduce our cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the conclusions of our counsel expressed in a prospectus or from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse effect on the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS would be borne indirectly by our unitholders because the costs would likely reduce our cash available for distribution.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Reform Legislation, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years, beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. For our 2020 taxable year, the Coronavirus Aid, Relief, and Economic Security Act increases the 30% adjusted taxable income limitation to 50%, unless we elect not to apply such increase, and for purposes of determining our 50% adjusted taxable income limitation, we may elect to substitute our 2020 adjusted taxable income with our 2019 adjusted taxable income.
Tax gain or loss on the disposition of our units could be more or less than expected.
If a unitholder sells its units, a gain or loss will be recognized for federal income tax purposes equal to the difference between the amount realized and the unitholder's tax basis in those units. Because distributions in excess of a unitholder's allocable share of its net taxable income decrease its tax basis in its units, the amount, if any, of such prior excess distributions with respect to the units it sells will, in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price it receives is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of a unitholder's units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if a unitholder sells its units, it may incur a tax liability in excess of the amount of cash it receives from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to an organization that is exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income (“UBTI”) and will be taxable to the exempt organization as UBTI on the exempt organization’s tax return in the year the exempt organization is allocated the income. Under the Tax Reform Legislation, an exempt organization is required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and applicable state tax returns and pay tax on their share of our taxable income.
Under the Tax Reform Legislation, if a unitholder sells or otherwise disposes of a unit, the transferee is required to withhold 10.0% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the U.S. Treasury and the IRS have suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our common units, that occur before January 1, 2022. Under recently finalized Treasury Regulations, such withholding will be required on open market transactions, but in the case of a transfer made through a broker, a partner’s share of liabilities will be excluded from the amount realized. In addition, the obligation to withhold will be imposed on the broker instead of the transferee (and we will generally not be required to withhold from the transferee amounts that should have been withheld by the transferee but were not withheld). These withholding obligations will apply to transfers of our common units occurring on or after January 1, 2022.
We treat each holder of our common units as having the same tax benefits without regard to the actual common units held. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. A successful IRS challenge also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.
Treatment of distributions on our Series A Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of our Series A Preferred Units than the holders of our common units and such distributions are not eligible for the 20% deduction for qualified publicly traded partnership income.
The tax treatment of distributions on our Series A Preferred Units is uncertain. We will treat the holders of Series A Preferred Units as partners for tax purposes and will treat distributions on the Series A Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Series A Preferred Units as ordinary income. Although a holder of Series A Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions semi-annually on the 15th day of June and December through December 15, 2022, and quarterly on the 15th day of March, June, September and December thereafter. Because the guaranteed payment for each unit must accrue as income to a holder during the taxable year of the accrual, the guaranteed payment attributable to the period beginning December 15th and ending December 31st will accrue to the holder of record of a Series A Preferred Unit on December 31st for such period. Otherwise, except in the case of our liquidation, the holders of Series A Preferred Units are generally not anticipated to share in our items of income, gain, loss or deduction. We will not allocate any share of its nonrecourse liabilities to the holders of Series A Preferred Units.
Treasury Regulations provide that a guaranteed payment for the use of capital generally is not taken into account for purposes of computing qualified business income for purposes of the 20% deduction for qualified publicly traded partnership will not constitute an allocable or distributive share of such income. As a result, the guaranteed payment for use of capital received by holders of our Series A Preferred Units may not be eligible for the 20% deduction for qualified publicly traded partnership income.
A holder of Series A Preferred Units will be required to recognize gain or loss on a sale of units equal to the difference between the holder’s amount realized and tax basis in the units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such Series A Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Series A Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the holder to acquire such Series A Preferred Unit. Gain or loss recognized by a holder on the sale or exchange of a Series A Preferred Unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of Series A Preferred Units will not generally be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.
Investment in the Series A Preferred Units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. Although the issue is not free from doubt, we will treat distributions to non-U.S. holders of the Series A Preferred Units as “effectively connected income” (which will subject holders to U.S. net income taxation and possibly the branch profits tax) that are subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. holders. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders may be required to file U.S. federal income tax returns in order to seek a refund of such excess. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes.
All holders of our Series A Preferred Units are urged to consult a tax advisor with respect to the consequences of owning our Series A Preferred Units.
We prorate our items of income, gain, loss and deduction for U.S, federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations allow a similar monthly simplifying convention, but do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method, or if new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units.
We have adopted certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction among our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of units and could have a negative impact on the value of the units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.
If the IRS makes audit adjustments to our income tax returns, the IRS (and some states) may collect any resulting taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders could be substantially reduced.
If the IRS makes audit adjustments to our income tax returns, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If, we make payments of taxes, penalties and interest resulting from audit adjustments, we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders could be substantially reduced. Additionally, we may be required to allocate an adjustment disproportionately among our unitholders, causing the publicly traded units to have different capital accounts, unless the IRS issues further guidance.
In the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of our unitholders (without any compensation from us to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.
As a result of investing in our units, our unitholders will likely be subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. Some of the states in which we conduct business currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is the unitholder's responsibility to file all federal, state and local tax returns.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.
Risks Related to Terrorism and Cyberterrorism
Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or results of operations.
Terrorist attacks and threats, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or
military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Our insurance may not protect us against such occurrences.
Our operations depend on the use of information technology (“IT”) systems that could be the target of a cyberattack.
The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines.
Our operations depend on the use of sophisticated IT systems. Our IT systems and networks, as well as those of our customers, vendors and counterparties, may become the target of cyber-attacks or information security breaches, which in turn could result in the unauthorized release and misuse of sensitive or proprietary information as well as disrupt our operations, damage our reputation or damage our facilities or those of third parties, which could have a material adverse effect on our revenues and increase our operating and capital costs, which could reduce the amount of cash otherwise available for distribution. In addition, certain cyber-incidents, such as surveillance, may remain undetected for an extended period. We may be required to incur additional costs to modify or enhance our IT systems or to prevent or remediate any such attacks.
A cyber-incident involving our IT systems and related infrastructure, or that of our customers, venders and counterparties, could disrupt our business plans and negatively impact our operations in the following ways, among others:
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a cyber-attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;
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a cyber-attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;
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a cyber-attack on a communications network or power grid could cause operational disruption, resulting in loss of revenues;
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a deliberate corruption of our financial or operational data could result in events of non-compliance, which could lead to regulatory fines or penalties; and
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business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our units.
Item 1B.
Item 1B. Unresolved Staff Comments.
Not applicable.
Item 2.
Item 2. Properties.
A description of our properties is included in Item 1. Business, and is incorporated herein by reference. For additional information on our midstream assets and their capacities, see Item 1. Business.
Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our gathering systems and other major facilities are located are owned by us in fee title, and we believe that we have valid title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to long-term leases or easements between us and the underlying fee owner or permits with governmental authorities. We believe that we have valid leasehold estates or fee ownership in such lands or valid permits with governmental authorities. We have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or license. We believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses with the
exception of certain ordinary course encumbrances and permits with governmental entities that have been applied for, but not yet issued.
In addition, we lease various office space under leases to support our operations.
Item 3.
Item 3. Legal Proceedings.
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any significant legal or governmental proceedings, except as noted below. In addition, we are not aware of any significant legal or governmental proceeding contemplated to be brought against us, under the various environmental protection statutes to which we are subject, except as noted below.
Beginning in 2015, the U.S. Department of Justice (“DOJ”) issued grand jury subpoenas to Summit Investments, the Partnership, our General Partner and Meadowlark Midstream requesting certain materials related to an incident involving a produced water disposal pipeline owned by Meadowlark Midstream that resulted in a discharge of materials into the environment (“Meadowlark Rupture”). On June 19, 2015, Meadowlark Midstream and Summit Investments received a complaint from the North Dakota Industrial Commission seeking approximately $2.5 million in fines and other fees related to the incident. This matter is also under investigation by the U.S. Environmental Protection Agency, the North Dakota Office of the Attorney General, the North Dakota Department of Environmental Quality, and the North Dakota Game and Fish Department. The government’s investigation is still ongoing. During this time, the Partnership has entered ‎into tolling agreements with both the DOJ and the North Dakota attorney general, which ‎were most recently extended to May 7, 2021. There can be no assurance that these tolling agreements will be extended. Discussions with the DOJ and other agencies regarding a resolution of this matter are ongoing. Liability for this incident could arise under civil and misdemeanor and felony criminal statutes, including under the Clean Water Act. In accordance with GAAP, the Partnership has accrued a $17.0 million loss contingency for this matter as of December 31, 2020. While the Partnership believes a loss for claims and/or actions arising from the Meadowlark Rupture, whether in a negotiated settlement or as a result of litigation, is probable, due to the complexity of resolving the numerous issues surrounding this matter, at this time we cannot reasonably predict whether any actual loss, if incurred, would be materially higher or lower than the accrued amount.
The following additional matters are disclosed pursuant to requirements of Item 103 of the SEC’s Regulation S-K. We do not currently believe that the eventual outcome of such matters could have a material adverse effect on our business, financial condition, results of operations or cash flows. A petition was filed in the District Court of Arapahoe County, Colorado, by Samuel Engineering, Inc. against Meadowlark Midstream and Summit Niobrara. The matter was later transferred to the District Court of Denver County, Colorado, where it is currently pending. The plaintiff was a contractor hired to perform engineering, procurement, and construction services for Summit Niobrara’s gas processing plant located in Weld County, Colorado. The plaintiff is seeking damages for alleged non-payment for such services. Separately, a demand for arbitration was filed in Houston, Texas by Moore Control Systems, Inc. against Summit Permian. The claimant in that matter was a contractor hired to perform engineering, procurement, and construction services for Summit Permian’s gas processing plant located in Eddy County, New Mexico. The claimant is seeking damages for alleged non-payment for such services.
We previously disclosed a legal proceeding initiated in the District Court of Tarrant County, Texas by Sage Natural Resources, LLC against us and certain of our affiliates. That legal proceeding was terminated by the court’s dismissal of the lawsuit with prejudice.
Item 4.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our limited partner common units, ticker symbol “SMLP,” trade on the NYSE. As of December 31, 2020, there were approximately 8,489 common unitholders, including beneficial owners of common units held in street name.
On January 29, 2020, the Board of Directors declared a distribution of $0.125 per unit (an amount before giving effect to the Reverse Unit Split) for the quarterly period ended December 31, 2019. The distribution, which totaled $11.7 million, was paid on February 14, 2020, prior to the GP Buy-In Transaction, to unitholders of record at the close of business on February 7, 2020. In May 2020, the Partnership suspended distributions to holders of its common units and its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. We did not make a distribution on our common units with respect to any quarter in 2020, nor did we make a distribution on our Series A Preferred Units on June 15, 2020 or December 15, 2020.
Our Cash Distribution Policy and Restrictions on Distributions
General
Suspension of Distributions. In May 2020, the Partnership suspended distributions to holders of its common units and suspended payments of distributions to holders of its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020. Because our Series A Preferred Units rank senior to our common units with respect to distribution rights, any accrued amounts on our Series A Preferred Units must first be paid prior to our resumption of distributions to our common unitholders. As of December 31, 2020, the amount of accrued and unpaid distributions on the Series A Preferred Units totaled $15.8 million. At this time, the Partnership is unable to forecast when it will resume distributions to holders of its common units and Series A Preferred Units.
Our Cash Distribution Policy. Our Partnership Agreement requires us to distribute all of our available cash quarterly, subject to reserves established by our General Partner. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.
Upon a resumption of the Partnership’s distributions, we will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about seven days prior to such distribution date. We make the distribution on the business day immediately preceding the indicated distribution date if the distribution date falls on a holiday or non-business day.
The Board of Directors plans on making decisions with respect to payment of distributions on the common units and Series A Preferred Units on a semi-annual or quarterly basis, as applicable, based on the required payment date. We may not pay distributions on the common units or Series A Preferred Units in the foreseeable future, and there are restrictions on our ability to pay distributions under our outstanding indebtedness that restrict our ability to pay cash distributions on any of our equity securities.
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay any distribution except to the extent we have available cash as defined in our Partnership Agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:
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Our cash distribution policy is subject to restrictions on distributions under our Revolving Credit Facility. Our Revolving Credit Facility contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy.
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Our cash distribution policy is subject to restrictions on distributions under our Series A Preferred Units. Our Series A Preferred Units contain covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy.
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Our General Partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our General Partner in good faith will be binding on our unitholders.
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Although our Partnership Agreement requires us to distribute all of our available cash, our Partnership Agreement, including the provisions requiring us to distribute all of our available cash, may be amended. We can amend our Partnership Agreement with the consent of our General Partner and the approval of a majority of the outstanding common units.
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Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement.
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Under Delaware law, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.
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We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase.
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If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution rate to service or repay our debt or fund expansion capital expenditures.
Preferred Unit Distributions
Series A Preferred Units
In November 2017, we issued 300,000 Series A Preferred Units at a price to the public of $1,000. During the year ended December 31, 2020, we exchanged 62,816 Series A Preferred Units for 837,547 SMLP common units and completed a cash tender offer whereby we tendered 75,075 Series A Preferred Units for $25.0 million in cash. As of December 31, 2020, we have 162,109 Series A Preferred Units outstanding.
In May 2020, the Partnership suspended payments of distributions to holders of its Series A Preferred Units, and we did not make a distribution on our Series A Preferred Units on June 15, 2020 or December 15, 2020.
Distributions on the Series A Preferred Units are cumulative and compounding and are payable semi-annually in arrears on the 15th day of each June and December through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year (each, a “Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Distribution Payment Date, in each case, when, as, and if declared by the General Partner out of legally available funds for such purpose.
The initial distribution rate for the Series A Preferred Units is 9.50% per annum of the $1,000 liquidation preference per Series A Preferred Unit. On and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of the liquidation preference equal to the three-month LIBOR plus a spread of 7.43%. See Note 13 to the consolidated financial statements for additional details.
Subsidiary Series A Preferred Units
In December 2019 and during the year ended December 31, 2020, Permian Holdco issued 30,000 and 55,251 Subsidiary Series A Preferred Units, respectively, representing limited partner interests in Permian Holdco at a price of $1,000 per unit. Permian Holdco used the net proceeds of $48.7 million and $27.4 million, respectively, (after deducting offering expenses) to fund capital calls associated with the Double E Project.
Distributions on the Subsidiary Series A Preferred Units are cumulative and compounding and are payable quarterly in arrears 21 days after the quarter ending March, June, September and December of each year (each, a “Subsidiary Series A Preferred Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Subsidiary Series A Preferred Distribution Payment Date, in each case, when, as, and if declared by the board of directors of Permian Holdco out of legally available funds for such purpose.
The distribution rate is 7.00% per annum of the $1,000 issue amount per outstanding Permian Holdco Subsidiary Series A Preferred Unit. Permian Holdco has the option to pay this distribution in-kind until the earlier of June 30, 2022 or the first full quarter following the date the Double E pipeline is placed in service. See Note 13 to the consolidated financial statements for additional details.
Unregistered Sales of Equity Securities
In July 2020, the Partnership completed the Preferred Exchange Offer. The Preferred Exchange Offer expired on July 28, 2020, and on July 31, 2020, the Partnership issued 837,547 SMLP common units in exchange for 62,816 Series A Preferred Units. Upon closing the Preferred Exchange Offer, we eliminated $66.5 million of the Series A Preferred Unit liquidation preference amount, inclusive of accrued distributions due as of the settlement date. The Partnership did not receive any cash proceeds from the Preferred Exchange Offer.
The Partnership relied on Section 3(a)(9) of the Securities Act to exempt the Preferred Exchange Offer from the registration requirements of the Securities Act. Section 3(a)(9) offers exemptions from the registration requirements of the Securities Act for exchange offers in which (i) the issuer of the securities offered is the same as the issuer of the securities being surrendered, (ii) the holders are not being asked to surrender anything of value other than the outstanding securities, (iii) the exchange offer is made exclusively to existing holders of the issuer’s outstanding securities, and (iv) the issuer does not pay any commission or remuneration for solicitation of the exchange. Because the Partnership offered only its own common units exclusively to the holders of and in exchange for its outstanding Series A Preferred Units, and because it neither paid nor received anything of value other than the subject securities, the Partnership was able to rely on the exemption afforded by Section 3(a)(9) of the Securities Act.
Issuer Purchases of Equity Securities
In May 2020, the Partnership closed the GP Buy-In Transaction whereby the Partnership acquired from its then private equity sponsor, ECP, (i) Summit Investments, which owned the Partnership’s General Partner, and (ii) through its indirect ownership of SMP Holdings, 3,415,646 of its common units. Consideration paid to ECP included a $35.0 million cash payment and warrants to purchase up to 666,667 common units.
Equity Compensation Plans
The information relating to SMLP’s equity compensation plans required by Item 5 is included in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
MD&A is intended to inform the reader about matters affecting the financial condition and results of operations of the Partnership and its subsidiaries. As a result, the following discussion for the year ended December 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 ended December 31, 2019 and December 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 dated August 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 United States.
We classify our midstream energy infrastructure assets into two categories, our Core Focus Areas and our Legacy Areas. Further details on our Focus Areas and Legacy Areas are summarized below.
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Core Focus Areas. Core producing areas of basins in which we expect our gathering systems to experience greater long-term growth, driven by our customers’ ability to generate more favorable returns and support sustained drilling and completion activity in varying commodity price environments. In the near-term, we expect to concentrate the majority of our capital expenditures in our Core Focus Areas. Our Utica Shale, Ohio Gathering, Williston Basin, DJ Basin and Permian Basin reportable segments (as described below) comprise our Core Focus Areas.
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Legacy Areas. Production basins in which we expect volume throughput on our gathering systems to experience relatively lower long-term growth compared to our Core Focus Areas, given that our customers require relatively higher commodity prices to support drilling and completion activities in these basins. Upstream production served by our gathering systems in our Legacy Areas is generally more mature, as compared to our Core Focus Areas, and the decline rates for volume throughput on our gathering systems in the Legacy Areas are typically lower as a result. We expect to continue to decrease our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments (as described below) comprise our Legacy Areas.
Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn a portion of our revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers in the Williston Basin, Piceance Basin, and Permian Basin segments, (ii) the sale of natural gas we retain from certain Barnett Shale customers and (iii) the sale of condensate we retain from our gathering services in the Piceance Basin segment. During the 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.
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 Ended December 31, 2020 and 2019” section herein.
(1) See "Liquidity and Capital Resources" herein and Note 20 to the consolidated financial statements for additional information on capital expenditures.
Key Matters for the Year ended December 31, 2020. The following items are reflected in our financial results for the fiscal year ended December 31, 2020:
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GP Buy-In Transaction. In May 2020, the Partnership completed the GP Buy-In Transaction whereby the Partnership acquired from its then private equity sponsor, ECP, (i) Summit Investments, which indirectly owned the Partnership’s General Partner, (ii) through its ownership of SMP Holdings, 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 $35.0 million cash payment and warrants to purchase up to 666,667 common 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.
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Suspension of common and preferred unit distributions. In May 2020, and 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 March 31, 2020. The suspension of distributions enabled the Partnership to retain an incremental $76 million per annum of operating cash flow and reallocate this retained 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.
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July 2020 Series A Preferred Unit Exchange. In July 2020, the Partnership 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 $66.5 million of the Series A Preferred Unit liquidation preference amount, inclusive of $3.7 million of accrued distributions due as of the settlement date.
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Open Market Repurchase of Senior Notes. Throughout 2020, the Partnership completed its Open Market Repurchases, which resulted in the extinguishment of $32.4 million of face value of the 2022 Senior Notes and $201.8 million 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.
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Debt Tender Offers. In September 2020, the Co-Issuers completed the Debt 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 $48.7 million, and the Partnership recognized a $23.3 million gain on the extinguishment of debt related to the Debt Tender Offers during 2020.
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TL Restructuring. In November 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 $26.5 million in cash as consideration to fully settle the deferred purchase price obligation, which SMP Holdings then paid to the Term Loan 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 SMP Holdings’ outstanding obligations under the SMPH Term Loan.
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December 2020 Series A Preferred Unit Tender. On December 29, 2020, the 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 the Series A Preferred Unit liquidation preference due as of the settlement date, inclusive of $7.6 million of accrued distributions.
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Double E Project. For the year ended December 2020, the Partnership’s proportionate share of capital calls due in 2020 totaled $99.9 million, which includes $2.7 million in capitalized interest, and was funded with $20.6 million of Partnership generated funds and the issuance of $85.3 million of Subsidiary Series A Preferred Units.
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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 December 31, 2020, we incurred approximately $5.6 million in restructuring costs relating to this initiative (included in general and administrative expense).
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2020 Impairments. In the fourth quarter of 2020, we recorded $8.6 million of impairments related to certain long-lived assets, of which $5.1 million related to a January 2021 sale of compressor equipment for a total cash purchase price of $8.0 million.
Key Matters for the Year ended December 31, 2019. The following items are reflected in our financial results for the fiscal year ended 2019:
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Equity Method Investment Impairment. In December 2019, we identified certain triggering events which indicated that our equity method investment in Ohio 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 $329.7 million was recorded in the loss from equity method investees caption on the consolidated statement of operations.
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Goodwill Impairment. In September 2019, in connection with our annual 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 $16.2 million.
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Disposition. In March 2019, we identified certain triggering events which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, we performed a recoverability assessment of certain assets within these reporting segments. In the DJ Basin, we determined certain processing plant assets related to 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 $34.7 million related to these assets. In the Barnett Shale, we determined certain compressor station assets would be shut down and de-commissioned and we recorded an impairment charge of $9.7 million related to these assets.
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Double E Project. In June 2019, we continued development of the Double E 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 Double E’s foundation shipper. The Double E Project, which consists of an approximately 116-mile mainline and related facilities, will provide interstate natural gas transportation service from the Delaware Basin production area to the Waha Hub in Texas.
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Summit Permian Transmission. In connection with the Double E Project, Summit Permian Transmission contributed total assets of approximately $23.6 million for a 70% ownership interest in Double E. Concurrent with this contribution, Double E distributed $7.3 million to the Partnership.
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Double E Financing. In December 2019, as part of our financing for the Double E Project, we formed Permian Holdco, a newly created, unrestricted subsidiary of SMLP that indirectly owns SMLP’s 70% interest in Double E. In connection with the formation of Permian Holdco, we entered into an agreement with TPG Energy Solutions Anthem, L.P. (“TPG”) on December 24, 2019 to fund up to $80 million of Permian Holdco’s future capital calls associated with the Double E Project. Simultaneously, on December 24, 2019, Permian Holdco issued 30,000 Subsidiary Series A Preferred Units to TPG for net proceeds of $27.4 million.
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Red Rock. In December 2019, Red Rock Gathering and certain affiliates of 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 Red Rock Gathering system assets for a cash purchase price of $12.0 million (the “Red Rock Sale”). Prior to closing, we recorded an impairment charge of $14.2 million based on the expected consideration and the carrying value for the Red Rock Gathering system assets. On December 2, 2019, we closed the Red Rock Sale. The impairment is included in the 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 from January 1, 2019 through December 1, 2019.
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Tioga Midstream. Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system in the Williston Basin. On March 22, 2019, we sold the Tioga Midstream system to affiliates of Hess Infrastructure Partners LP for a combined cash purchase price of approximately $90 million and recorded a gain on sale of $0.9 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 consolidated financial 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.
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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 December 31, 2019, we incurred approximately $5.0 million in restructuring costs relating to this initiative (included in general and administrative expense). For the year ended December 31, 2020, we incurred an additional $3.5 million related to this initiative.
Trends and Outlook
Our business has been, and we expect our future business to continue to be, affected by the following key trends:
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Ongoing impact of the COVID-19 pandemic and reduced demand and prices for oil;
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Natural gas, NGL and crude oil supply and demand dynamics;
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Production from U.S. shale plays;
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Capital markets availability and cost of capital; and
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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 of OPEC and other foreign, oil-exporting countries. This disrupted the oil and natural gas exploration and production industry and other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular.
Over the past 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
continued volatility in market conditions since March 2020, and based on recently updated production forecasts and 2021 development plans from our customers, we currently expect our 2021 results to be affected by decreased drilling activity.
Natural gas, NGL and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the 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 on December 31, 2020. As of February 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 continental United States. The average amount of working natural gas in underground storage in the continental U.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 daily Cushing, 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 continental United States decreased from 677 in December 2019 to 267 in December 2020, according to Baker Hughes. Over the next several years, we expect that crude oil prices will support continued drilling activity and increasing production in the Williston Basin, Permian Basin and, given the current regulatory environment in Colorado, in rural parts of the DJ Basin.
Growth in production from U.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 and Permian 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 from U.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 in May 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.
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 across the 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.
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, and Marcellus 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.
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
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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.
Results of Operations
Consolidated Overview for the Years Ended December 31, 2020 and 2019
The following table presents certain consolidated data and volume throughput for the years ended December 31, 2020 and 2019.
* 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 ended December 31, 2020 compared to the year ended December 31, 2019, primarily reflecting:
•
a volume throughput increase of 5 MMcf/d for the Marcellus Shale segment.
•
a volume throughput decrease of 88 MMcf/d for the Piceance Basin segment.
•
a volume throughput increase of 85 MMcf/d for the Utica Shale segment.
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a volume throughput increase of 14 MMcf/d for the Permian Basin segment.
•
a volume throughput decrease of 39 MMcf/d for the Barnett Shale segment.
Volumes - Liquids. Crude oil and produced water throughput volumes at the Williston segment decreased 26 Mbbl/d for the year ended December 31, 2020 compared to the year ended December 31, 2019.
For additional information on volumes, see the "Segment Overview for the Years Ended December 31, 2020 and 2019" section herein.
Revenues. Total revenues decreased $60.1 million during the year ended December 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 $24.0 million compared to the year ended December 31, 2019, primarily reflecting:
•
a $7.2 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting $7.5 million in lower gas gathering 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 the Piceance Basin relating to lower volume throughput due to a lack of drilling and completion activity and natural production declines.
•
a $4.6 million increase in gathering services and related fees in the Utica 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 $18.4 million decrease in gathering services and related fees in the Williston Basin primarily reflecting a decrease in gathering services and 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 January 1, 2019 through March 22, 2019 as well as lower liquids volume throughput, partially offset by the completion of new wells through 2019 and 2020.
•
a $1.9 million increase in gathering services and related fees in the DJ 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 June 2019, partially offset by natural production declines 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.
•
a $6.5 million increase in gathering services and related fees in the Permian Basin primarily as a result of an uptick in customer volumes, partially offset by natural production declines from wells previously put in service.
Costs and expenses. Total costs and expenses decreased $76.6 million during the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily reflecting:
•
a $31.2 million decrease in long-lived asset impairments in the DJ Basin in 2019.
•
a $16.2 million decrease in goodwill impairment charge relating to the Mountaineer Midstream system in the Marcellus Basin in 2019.
•
a $14.2 million decrease in long-lived asset impairments relating to the sale of certain Red Rock Gathering system assets in the Piceance Basin in 2019.
Cost of natural gas and NGLs. Cost of natural gas and NGLs decreased $26.8 million during the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily driven by lower natural gas, NGL and crude oil marketing activity.
Operation and maintenance. Operation and maintenance expense decreased $12.7 million for the year ended December 31, 2020 compared to the year ended December 31, 2019.
Depreciation and amortization. The increase in depreciation and amortization expense during 2020 compared to the year ended December 31, 2019 was primarily due to the assets placed into service in the Permian Basin.
Interest Expense. The decrease in interest expense in the year ended December 31, 2020 compared to the year ended December 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.
Segment Overview for the Years Ended December 31, 2020 and 2019
Utica Shale. The Utica Shale reportable segment includes the Summit Utica system. Volume throughput for our Summit Utica system follows.
Volume throughput increased compared to the year ended December 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 reportable segment follows.
* Not considered meaningful
Year ended December 31, 2020. Segment adjusted EBITDA increased $3.5 million compared to the year ended December 31, 2019, primarily due to the volume throughput previously discussed.
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.
* 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.
Financial data for our Ohio Gathering reportable segment, based on a one-month lag follows.
Year ended December 31, 2020. Segment adjusted EBITDA for equity method investees decreased $8.1 million compared to the year ended December 31, 2019, primarily related to lower volume throughput described above.
Williston Basin. The Polar and Divide, Tioga Midstream (through March 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 the Williston Basin reportable segment. Volume throughput for our Williston Basin reportable segment follows.
Natural gas. Natural gas volume throughput in 2020 increased compared to the year ended December 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 ended December 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 reportable segment follows.
* Not considered meaningful
Year ended December 31, 2020. Segment adjusted EBITDA decreased $17.4 million compared to the year ended December 31, 2019 primarily associated with the decreased liquid volume throughput described above, and the sale of Tioga Midstream in March of 2019. The decrease was partially offset by the increased natural gas volume throughput described above.
DJ Basin. The Niobrara G&P system provides midstream services for the DJ Basin reportable segment. Volume throughput for our DJ Basin reportable segment follows.
Volume throughput in 2020 decreased compared to the year ended December 31, 2019, primarily as a result of natural production declines, shut-ins and fewer well connection through 2020.
Financial data for our DJ Basin reportable segment follows.
* Not considered meaningful
Year ended December 31, 2020. Segment adjusted EBITDA increased $0.8 million compared to the year ended December 31, 2019, primarily associated with a more favorable volume and gathering rate mix from customers.
Permian Basin. The Summit Permian system provides our midstream services for the Permian Basin reportable segment. Volume throughput for our Permian Basin reportable segment follows.
Volume throughput in 2020 increased compared to the year ended December 31, 2019, primarily as a result of new well connections in the fourth quarter of 2019 and through the first quarter of 2020, partially offset by natural production declines from wells previously in service.
Financial data for our Permian Basin reportable segment follows.
* Not considered meaningful
Year ended December 31, 2020. Segment adjusted EBITDA increased $5.3 million compared to the year ended December 31, 2019, primarily as a result of higher volumes throughput described above.
Piceance Basin. The Grand River system provides midstream services for the Piceance Basin reportable segment. Volume throughput for our Piceance Basin reportable segment follows.
Volume throughput decreased in 2020 compared to the year ended December 31, 2019, as a result of natural production declines.
Financial data for our Piceance Basin reportable segment follows.
* Not considered meaningful
Year ended December 31, 2020. Segment adjusted EBITDA decreased $9.9 million compared to the year ended December 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.
Barnett Shale. The DFW Midstream system provides our midstream services for the Barnett Shale reportable segment.
Volume throughput for our Barnett Shale reportable segment follows.
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 reportable segment follows.
*Not considered meaningful
(1) Includes the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues.
Year ended December 31, 2020. Segment adjusted EBITDA decreased $10.9 million compared to the year ended December 31, 2019 primarily related to the decreased volume throughput described above.
Marcellus Shale. The Mountaineer Midstream system provides our midstream services for the Marcellus Shale reportable segment.
Volume throughput for the Marcellus Shale reportable segment follows.
Volume throughput increased in 2020 compared to the year ended December 31, 2019, primarily due to new well connection in the third quarter of 2020, partially offset by natural production declines.
Financial data for our Marcellus Shale reportable segment follows.
*Not considered meaningful
Year ended December 31, 2020. Segment adjusted EBITDA increased $2.0 million compared to the year ended December 31, 2019, primarily associated with the increased volume throughput described above.
Corporate and Other Overview for the Years Ended December 31, 2020 and 2019
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.
* 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 ended December 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 ended December 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 ended December 31, 2020 are primarily related to costs associated with our liability management initiatives.
Interest Expense. Interest expense decreased $13.1 million compared to the year ended December 31, 2019 primarily as 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 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 $1.1 billion senior secured Revolving Credit Facility with a maturity of May 2022 (see Note 9 to the consolidated financial statements). As of December 31, 2020, the outstanding balance of the Revolving Credit Facility was $857.0 million and the unused portion totaled $238.9 million, after giving effect to the issuance thereunder of a $4.1 million
outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of December 31, 2020 was approximately $105 million. There were no defaults or events of default during 2020, and as of December 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. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers") co-issued $300.0 million of 5.5% senior unsecured notes maturing August 15, 2022 (the "2022 Senior Notes" and, together with the 2025 Senior Notes (defined below), the “Senior Notes”). As of December 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 on February 15 and August 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 ended December 31, 2020, we were in compliance with the financial covenants governing our 2022 Senior Notes.
2025 Senior Notes. In February 2017, the Co-Issuers co-issued $500.0 million of 5.75% senior unsecured notes maturing April 15, 2025 (the “2025 Senior Notes”). As of December 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 on April 15 and October 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 each April 15 to 100.000% on April 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 ended December 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
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 December 31, 2020, primarily reflected:
•
net income of $189.1 million plus adjustments of $40.5 million for non-cash items; and
•
$50.0 million increase in working capital accounts.
Cash flows from operating activities for the year ended December 31, 2019, primarily reflected:
•
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 December 31, 2020 primarily reflected:
•
$99.9 million of investments in our equity method investee; and
•
$43.1 million of capital expenditures primarily attributable to the ongoing development of our Williston, DJ, Utica and Permian segments.
Cash flows used in investing activities during the year ended December 31, 2019 primarily reflected:
•
$182.3 million of capital expenditures primarily attributable to the ongoing development of the DJ Basin of $80.5 million, Summit Permian of $45.0 million, the Williston Basin of $30.9 million and Corporate and Other, which includes $17.7 million of capital expenditures relating to the Double E Project;
•
$18.3 million for investments in the Double E joint venture relating to the Double E Project;
•
$89.5 million of net proceeds from the Tioga Midstream sale and $12.0 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 December 31, 2020 primarily reflected:
•
$145.6 million paid for open market repurchases of the 2022 and 2025 Notes;
•
$47.5 million paid for tender offer of 2022 and 2025 Senior Notes;
•
$41.8 million for the purchase of common units in the GP Buy-In Transaction;
•
$35.0 million for the repayment of the ECP Loan;
•
$26.5 million for cash paid in connection with the TL Restructuring;
•
$25.0 million of cash paid for in connection with the Preferred Tender Offer;
•
$6.3 million of cash repayments on the SMPH Term loan; and
•
$6.0 million of distributions offset by;
•
$180.0 million of net proceeds from borrowings on our Revolving Credit Facility;
•
$48.7 million in proceeds from the issuance of our Subsidiary Series A Preferred Units and;
•
$35.0 million in proceeds from the ECP Loan.
Cash flows used in financing activities during the year ended December 31, 2019 primarily reflected:
•
$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
•
$27.4 of net proceeds from the issuance of Subsidiary Series A Preferred 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 December 31, 2020 (in thousands):
(1)
The Partnership issued a parental guaranty on behalf of its wholly owned subsidiary to fund the subsidiary’s pro rata share of required Double E construction project capital calls. As of December 31, 2020, this amount represents the Partnership's best estimate of its remaining obligation to fund Double E for the construction of the Double E Project.
(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 ended December 31, 2020, cash paid for capital expenditures totaled $43.1 million which included $14.1 million of maintenance capital expenditures. For the year ended December 31, 2020, we contributed $99.9 million to Double 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 60 MMcf/d DJ Basin processing plant and compression expansions in the Permian 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 the Double 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 in Double 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 our Double E capital commitments to third parties, including commercial banks. On December 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 the Double E Project. For the years ended December 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 $20.0 million to $35.0 million, including approximately $10.0 million of maintenance capital expenditures.
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.
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 of December 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 required Double 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 at December 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
On March 2, 2020, the SEC issued Final Rule Release No. 33-10762, Financial Disclosures about Guarantors and Issuers of Guaranteed 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, an SEC 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 effective January 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 the Obligor Group is presented on a combined basis and intercompany balances and transactions between the Co-Issuers and Guarantor Subsidiaries have been eliminated. There were no reportable transactions between the Co-Issuers and Obligor Group and the subsidiaries that were not issuers or guarantors of the Senior Notes.
Payments to holders of the Senior Notes are affected by the composition of and relationships among the Co-Issuers, the Guarantor Subsidiaries 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.
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 December 31, 2020 and December 31, 2019 follow.
Summarized Statements of Operations Information. For the purposes of the following summarized statements of operations, we allocate a portion of general and administrative expenses recognized at the SMLP parent to the Obligor Group to reflect what those entities' results would have been had they operated on a stand-alone basis. Summarized statements of operations for the years ended December 31, 2020 and 2019 follow.
Critical Accounting Estimates
The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the amounts of assets, liabilities,
revenues and expenses and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following describes significant judgments and estimates used in the preparation of our consolidated financial statements.
Impairment of Long-Lived Assets. As of December 31, 2020, we had net property, plant and equipment with a carrying value of approximately $1.8 billion and net amortizing intangible assets with a carrying value of approximately $200.0 million. When evidence exists that we will not be able to recover a long-lived asset's carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. With respect to property, plant and equipment and our amortizing intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset's use and eventual disposal. In this situation, we would recognize an impairment loss equal to the amount by which the carrying value exceeds the asset's fair value. We determine fair value using a combination of approaches, including a market-based approach and an income-based approach in which we discount the asset's expected future cash flows to reflect the risk associated with achieving the underlying cash flows. Any impairment determinations involve significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.
We evaluate our equity method investments for impairment when we believe the current fair value may be less than the carrying amount and record an impairment if we believe the decline in value is other than temporary.
Adjustments for MVC Shortfall Payments. For our calculation of segment adjusted EBITDA, we estimate the impact of expected MVC shortfall payments based on assumptions that include, but are not limited to, contract terms, historical volume throughput data, and expectations regarding future investment expenditures, customer drilling activities, and customer production volumes.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Interest Rate Risk
Our current interest rate risk exposure is largely related to our indebtedness. As of December 31, 2020, we had $493.5 million principal of fixed-rate Senior Notes and $857.0 million outstanding under our variable rate Revolving Credit Facility. While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our Revolving Credit Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. For the year ended December 31, 2020, a hypothetical 1% increase (decrease) in interest rates would have increased (decreased) our interest expense by approximately $7.7 million assuming no changes in amounts drawn or other variables under our Revolving Credit Facility or Senior Notes.
Commodity Price Risk
We generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, many of which include MVCs and areas of mutual interest. Our direct commodity price exposure relates to (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds and 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 segment customers and (iii) the sale of condensate we retain from certain gathering services in the Piceance Basin segment. Our gathering agreements with certain Barnett Shale customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 Index. By basing the power prices on a system and basin-relevant market, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales. We do not enter into risk management contracts for speculative purposes.
Item 8.
Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Summit Midstream, GP, LLC and the unitholders of Summit Midstream Partners, LP
Houston, Texas
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Summit Midstream Partners, LP and subsidiaries (the "Partnership") as of December 31, 2020 and 2019, the related consolidated statements of operations, partners' capital and cash flows, for the years then ended, and the related notes (collectively referred to as the "financial statements"). In our opinion, based on our audits and the report of the other auditors, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years then ended in conformity with accounting principles generally accepted in the United States of America.
We did not audit the financial statements of Ohio Gathering Company, L.L.C. (“Ohio Gathering”) as of and for the year ended December 31, 2019, the Partnership’s investment in which is accounted for by use of the equity method. The accompanying financial statements of the Partnership include its equity investment in Ohio Gathering of $275,000,000 as of December 31, 2019, and its loss from equity method investee in Ohio Gathering of $329,736,000 for the year then ended. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Ohio Gathering for 2019, prior to the 2019 impairment loss discussed in Note 7, which was audited by us, is based solely on the report of the other auditors.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 4, 2021 expressed an unqualified opinion on the Partnership's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.
GP Buy-In Transaction - Refer to Notes 1 and 14 to the financial statements
Critical Audit Matter Description
As described in Note 1 to the consolidated financial statements, on May 28, 2020, the transactions contemplated by the Purchase Agreement (the “GP Buy-In Transaction”) closed. As a result of the GP Buy-In Transaction, the Partnership now indirectly owns its General Partner, Summit Midstream Partners LLC (“Summit Investments”). Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although the Partnership is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results included herein prior to the GP Buy-In Transaction are those of Summit Investments.
We identified the GP Buy-In Transaction as a significant and unusual transaction and as a critical audit matter because of the significant audit effort necessary to perform procedures and evaluate the audit evidence obtained relating to management’s accounting for the GP Buy-In Transaction due to the pervasive nature of the GP Buy-In Transaction on the composition of the Partnership’s consolidated financial statements and disclosures, including judgements necessary to combine legacy Summit Investments into the Partnership.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to evaluating the accounting treatment of the GP Buy-in Transaction included the following, among others:
•
We tested the effectiveness of controls over the Partnership’s accounting for significant unusual transactions, including management’s controls over the identification and application of relevant GAAP, and over the combination and presentation of the historical carrying amounts in the consolidated financial statements.
•
We read the GP Buy-In Transaction agreements and evaluated the reasonableness of management’s assessment of the accounting associated with the transaction between entities under common control and the completeness and accuracy of the consolidated financial statements, including the retrospective consolidation of Summit Investments within the Partnership’s consolidated financial statements.
•
We evaluated the sufficiency of the disclosures in the consolidated financial statements of the Partnership with respect to this matter.
Commitments and Contingencies - Environmental Matters - Refer to Notes 2 and 11 to the financial statements
Critical Audit Matter Description
In 2015, the Partnership learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream Company, LLC (“Meadowlark Midstream”) system near Williston, North Dakota (“Meadowlark Rupture”). The U.S. Department of Justice (“DOJ”) issued grand jury subpoenas to Summit Investments, the Partnership, the Partnership’s General Partner and Meadowlark Midstream requesting certain materials related to the Meadowlark Rupture. Meadowlark Midstream and Summit Investments received a complaint from the North Dakota Industrial Commission seeking fines and other fees related to the incident, and this matter is also under investigation by the U.S. Environmental Protection Agency, the North Dakota Office of the Attorney General, the North Dakota Department of Environmental Quality, and the North Dakota Game and Fish Department. Discussions with the DOJ and other agencies regarding a resolution of this matter are ongoing. Liability for this incident could arise under civil and misdemeanor and felony criminal statutes, including the Clean Water Act.
When required, the Partnership records accruals for loss contingencies in accordance with FASB ASC 450, Contingencies. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. As of December 31, 2020, the Partnership has accrued a $17.0 million loss contingency for this matter. While the Partnership believes a loss for claims and/or actions arising from the Meadowlark Rupture, whether in a negotiated settlement or as a result of litigation, is probable, due to the complexity of resolving the numerous issues surrounding this matter, at this time the Partnership cannot reasonably predict whether any actual loss, if incurred, would be materially higher or lower than the accrued amount.
We identified the accrued loss contingency for the Meadowlark Rupture as a critical audit matter because of the challenges of auditing management’s judgments applied in determining the accrued loss contingency as of December 31, 2020. Specifically, auditing management’s interpretations of the current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events is subjective and requires significant judgment due to the complexity of resolving the numerous issues surrounding this matter.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to evaluating the accrued loss contingency for the Meadowlark Rupture included the following, among others:
•
We evaluated management’s analysis of claims and/or actions arising from the Meadowlark Rupture, read Board of Directors meeting minutes, including relevant sub-committee meeting minutes, and compared to responses from internal and external counsel.
•
We obtained letters from the Partnership’s internal and external legal counsel as it relates to potential claims and/or actions arising from the Meadowlark Rupture.
•
We evaluated any events subsequent to December 31, 2020, that might impact our evaluation of claims and/or actions arising from the Meadowlark Rupture, including any related accrual or disclosure.
/s/ Deloitte & Touche LLP
Houston, Texas
March 4, 2021
We have served as the Partnership's auditor since 2009.
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(1) Prior to the GP Buy-in Transaction, common noncontrolling interests reported by Summit Investments included equity interests in SMLP that were not owned by Summit Investments.
(2) Includes deemed contributions of $54.9 million and $55.7 million related to the Exchange Offer and Tender Offer, respectively.
The accompanying notes are an integral part of these consolidated financial statements.
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION
Organization. Summit Midstream Partners, LP (including its subsidiaries, collectively “SMLP” or the “Partnership”) is a Delaware limited partnership that was formed in May 2012 and began operations in October 2012. SMLP is a value-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States. The Partnership’s business activities are conducted through various operating subsidiaries, each of which is owned or controlled by its wholly owned subsidiary holding company, Summit Holdings, a Delaware limited liability company. As of December 31, 2020, the Partnership indirectly owns its General Partner, and the General Partner is a wholly owned, indirect subsidiary of the Partnership. The General Partner has no assets or liabilities and holds the non-economic general partner interest in the Partnership.
GP Buy-In Transaction. On May 28, 2020, the Partnership closed the transactions contemplated by the Purchase Agreement (the “Purchase Agreement”), dated May 3, 2020, with affiliates of its then private equity sponsor, Energy Capital Partners II, LLC (“ECP”), to acquire Summit Investments. The acquisition of Summit Investments resulted in the Partnership acquiring (a) 2.3 million SMLP common units that were pledged as collateral under the SMPH Term Loan, (b) 0.7 million SMLP common units that were not pledged as collateral under the SMPH Term Loan and (c) a deferred purchase price obligation receivable owed by the Partnership. In addition, the Partnership acquired 0.4 million SMLP common units held by an affiliate of ECP. The total purchase price was $35.0 million in cash and warrants giving ECP the right to purchase up to 0.7 million SMLP common units (refer to Note 13 - Partners’ Capital and Mezzanine Capital for additional details). Pursuant to the Purchase Agreement, the Partnership retained any liabilities stemming from the release of produced water from a produced water pipeline operated by Meadowlark Midstream, a subsidiary of the Partnership, that occurred near Williston, North Dakota and was discovered on January 6, 2015. These transactions are collectively referred to as the “GP Buy-In Transaction.”
As a result of the GP Buy-In Transaction, the Partnership indirectly owns its General Partner. Following the closing of the GP Buy-In Transaction, the Partnership retired 1.1 million SMLP common units it acquired that were not pledged as collateral under the SMPH Term Loan. The 2.3 million SMLP common units that were pledged as collateral under the SMPH Term Loan were not considered outstanding with respect to voting and distributions under the Partnership Agreement until the closing of the TL Restructuring on November 17, 2020 (refer to Note 10).
Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although SMLP is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results included herein, prior to the GP Buy-In Transaction are those of Summit Investments. Prior to the GP Buy-In Transaction, Summit Investments controlled SMLP and SMLP’s financial statements were consolidated into Summit Investments.
Reverse Unit Split. On November 9, 2020, after the close of trading on the NYSE, the Partnership effected a 1-for-15 reverse unit split (the “Reverse Unit Split”) of its common units. The common units began trading on a split-adjusted basis on November 10, 2020. Pursuant to the Reverse Unit Split, common unitholders received one common unit for every 15 common units owned at the close of business on November 9, 2020. Immediately prior to the Reverse Unit Split, there were 56,624,887 common units issued and outstanding and immediately after the Reverse Unit Split, the number of issued and outstanding common units decreased to 3,774,992.
Business Operations. The Partnership provides natural gas gathering, compression, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term, fee-based agreements with its customers. The Partnership’s results are primarily driven by the volumes of natural gas that it gathers, compresses, treats and/or processes as well as by the volumes of crude oil and produced water that it gathers. Other than the Partnership’s investments in Double E and Ohio Gathering, all of its business activities are conducted through wholly owned operating subsidiaries
Presentation and Consolidation. The Partnership prepares its consolidated financial statements in accordance with GAAP as established by the FASB. The Partnership makes estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenues and expenses and the
disclosure of commitments and contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.
The consolidated financial statements include the assets, liabilities and results of operations of SMLP and its subsidiaries. All intercompany transactions among the consolidated entities have been eliminated in consolidation. Comprehensive income or loss is the same as net income or loss for all periods presented.
Risks and Uncertainties. The Partnership is closely monitoring the impact of the outbreak of COVID-19 on all aspects of its business, including how it has impacted and will impact its customers, employees, supply chain and distribution network. The Partnership is unable to predict the ultimate impact that COVID-19 may have on its business, future results of operations, financial position or cash flows.
Given the dynamic nature of the COVID-19 pandemic and related market conditions, the Partnership cannot reasonably estimate the period of time that these events will persist or the full extent of the impact they will have on its business. The full extent to which the Partnership’s 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 ability of pharmaceutical companies to develop effective and safe vaccines and therapeutic drugs. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cash, Cash Equivalents and Restricted Cash. The Partnership considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Accounts Receivable. Accounts receivable relate to gathering and other services provided to the Partnership’s customers and other counterparties. The Partnership evaluates the collectability of accounts receivable and the need for an allowance for doubtful accounts based on customer-specific facts and circumstances. To the extent the collectability of a specific customer or counterparty receivable is doubtful, the Partnership recognizes an allowance for doubtful accounts. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or a receivable amount is deemed otherwise unrealizable.
Property, Plant and Equipment. The Partnership records property, plant and equipment at historical cost of construction or fair value of the assets at acquisition. The Partnership capitalizes expenditures that extend the useful life of an asset or enhance its productivity or efficiency from its original design over the expected remaining period of use. For maintenance and repairs that do not add capacity or extend the useful life of an asset, the Partnership recognizes expenditures as an expense as incurred. The Partnership capitalizes project costs incurred during construction, including interest on funds borrowed to finance the construction of facilities, as construction in progress. Accrued capital expenditures are reflected in trade accounts payable.
The Partnership records depreciation on a straight-line basis over an asset’s estimated useful life and bases its estimates for useful life on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Estimates of useful lives follow.
Construction in progress is depreciated consistent with its applicable asset class once it is placed in service. Land and line fill are not depreciated.
The Partnership bases an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. Upon sale, retirement or other disposal, the Partnership removes the carrying value of an asset and its accumulated depreciation from its balance sheet and recognizes the related gain or loss, if any.
Asset Retirement Obligations. The Partnership records a liability for asset retirement obligations only if and when a future asset retirement obligation with a determinable life is identified. For identified asset retirement obligations, the Partnership evaluates
whether the expected retirement date and related costs of retirement can be estimated. The Partnership has concluded that its gathering and processing assets have an indeterminate life because they are owned and will operate for an indeterminate period when properly maintained. Because the Partnership does not have sufficient information to reasonably estimate the amount or timing of such obligations and does not have any current plan to discontinue use of any significant assets, the Partnership did not provide for any asset retirement obligations as of December 31, 2020 or 2019.
Amortizing Intangibles. The Partnership has certain acquired gas gathering contracts that had above-market pricing structures at the acquisition date and the Partnership amortizes these favorable contracts using a straight-line method over the contract’s estimated useful life. The Partnership defines useful life as the period over which the contract is expected to contribute to the Partnership’s future cash flows. These favorable contracts have original terms ranging from 10 years to 20 years and the Partnership recognizes the amortization expense associated with these contracts in Other revenues.
The Partnership amortizes all other gas gathering contracts, or contract intangibles, over the period of economic benefit based upon expected revenues over the life of the contract. The useful life of these contracts ranges from 3 years to 25 years. The Partnership recognizes the amortization expense associated with these contracts in Depreciation and amortization expense.
The Partnership also has rights-of-way associated with municipal easements and easements granted within existing rights-of-way. The Partnership amortizes these intangible assets over the shorter of the contractual term of the rights-of-way or the estimated useful life of the gathering system. The contractual terms of the rights-of-way range from 20 years to 30 years and the Partnership recognizes the amortization expense associated with these rights-of-way assets in Depreciation and amortization expense.
Equity Method Investments. The Partnership accounts for investments in which it exercises significant influence using the equity method so long as it (i) does not control the investee and (ii) is not the primary beneficiary. The Partnership reflects these investments in its consolidated balance sheets under the caption titled “investment in equity method investees.”
The Partnership recognizes an other-than-temporary impairment for losses in the value of equity method investees when evidence indicates that the carrying amount is no longer supportable. Evidence of a loss in value might include, but is not limited to, absence of an ability to recover the carrying amount of the investment or an inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. The Partnership evaluates its equity method investments whenever a triggering event exists that would indicate a need to assess the investment for potential impairment.
Impairment of Long-Lived Assets. The Partnership tests assets for impairment when events or circumstances indicate the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset (except goodwill) is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If the Partnership concludes that an asset's carrying value will not be recovered through future cash flows, the Partnership recognizes an impairment loss on the long-lived asset equal to the amount by which the carrying value exceeds its fair value. The Partnership determines fair value using a combination of market-based and income-based approaches.
Environmental Matters. The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. The Partnership accrues for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties or insurers are recorded as assets when their realization is assured beyond a reasonable doubt.
Commitments and Contingencies. When required, the Partnership records accruals for loss contingencies in accordance with FASB ASC 450, Contingencies. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events.
Noncontrolling Interest and Mezzanine Capital. A noncontrolling interest represents the portion of a consolidated subsidiary that is owned by a third party. Amounts are adjusted by the noncontrolling interest holder’s proportionate share of the subsidiary’s earnings or losses each period and any distributions that are paid. A noncontrolling interest is reported as a
component of equity unless the noncontrolling interest is considered redeemable, in which case the noncontrolling interest is recorded between liabilities and equity (mezzanine or temporary equity) in the Partnership’s consolidated balance sheet.
Revenue Recognition. The Partnership provides gathering and/or processing services principally under contracts that contain one or more of the following arrangements described below:
•
Fee-based arrangements. Under fee-based arrangements, the Partnership receives a fee or fees for one or more of the following services (i) natural gas gathering, treating, compressing and/or processing and (ii) crude oil and/or produced water gathering.
•
Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, the Partnership generally purchases natural gas from producers at the wellhead, or other receipt points, gathers the wellhead natural gas through its gathering system, treats and compresses the natural gas, processes the natural gas and/or sells the natural gas to a third party for processing. The Partnership then remits to its producers an agreed-upon percentage of the actual proceeds received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. The margins earned are directly related to the volume of natural gas that flows through the system and the price at which the Partnership is able to sell the residue natural gas and NGLs.
For the contracts described above, the Partnership reflects its revenues in the financial statement captions described below.
Certain of the Partnership’s gathering and/or processing agreements provide for monthly or annual MVCs. Under these MVCs, customers agree to ship and/or process a minimum volume of production on its gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to the Partnership at the end of the contracted measurement period if its actual throughput volumes are less than its contractual MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period.
The Partnership recognizes customer obligations under their MVCs as revenue and contract assets when (i) it considers it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right. In making this determination, the Partnership considers both quantitative and qualitative facts and circumstances, including, but not limited to, contract terms, capacity of the associated pipeline or receipt point and/or expectations regarding future investment, drilling and production.
Unit-Based Compensation. For awards of unit-based compensation, the Partnership determines a grant date fair value and recognizes the related compensation expense in the statements of operations over the vesting period for each respective award.
Income Taxes. The Partnership is generally not subject to federal and state income taxes, except as noted below. However, its unitholders are individually responsible for paying federal and state income taxes on their share of its taxable income. Net income or loss for GAAP purposes may differ significantly from taxable income reportable to its unitholders as a result of differences between the tax basis and the GAAP basis of assets and liabilities and the taxable income allocation requirements of the Partnership’s governing documents. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to the information about each partner’s tax attributes related to the Partnership.
In general, legal entities that are chartered, organized or conducting business in the state of Texas are subject to a franchise tax (the "Texas Margin Tax"). The Texas Margin Tax has the characteristics of an income tax because it is determined by applying a tax rate to a tax base that considers both revenues and expenses. The Partnership’s financial statements reflect provisions for these tax obligations.
New accounting standards implemented in this Annual Report.
ASU No. 2018-13 Fair Value Measurement (“ASU 2018-13”). ASU 2018-13 updates the disclosure requirements on fair value measurements including new disclosures for the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. ASU 2018-13 modifies existing disclosures including clarifying the measurement uncertainty disclosure. ASU 2018-13 removes certain existing disclosure requirements including the amount and reasons for transfers between Level 1 and Level 2 fair value measurements and the policy for the timing of transfer between levels. The adoption of ASU 2018-13 on January 1, 2020 did not have a material impact on the Partnership’s consolidated financial statements or disclosures.
ASU No. 2016-13 Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 requires the use of a current expected loss model for financial assets measured at amortized cost and certain off-balance sheet credit exposures. Under this model, entities will be required to estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied using a modified retrospective approach. The adoption of ASU 2016-13 on January 1, 2020 did not have a material impact on the Partnership’s consolidated financial statements or disclosures.
New accounting standards not yet implemented in this Annual Report.
ASU No. 2020-06 Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815 - 40) (“ASU 2020-06”). ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. The ASU is part of the FASB’s simplification initiative, which aims to reduce unnecessary complexity in U.S. GAAP. The ASU’s amendments are effective for fiscal years beginning after December 15, 2023, and interim periods within those fiscal years. The Partnership is currently evaluating the provisions of ASU 2020-06 to determine its impact on the Partnership’s consolidated financial statements and disclosures.
ASU No. 2020-04 Reference Rate Reform (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform on financial reporting. The amendments in ASU 2020-04 are effective as of March 12, 2020 through December 31, 2022. The Partnership is currently evaluating the provisions of ASU 2020-04 to determine its impact on the Partnership’s consolidated financial statements and disclosures.
3. REVENUE
The majority of the Partnership’s revenue is derived from long-term, fee-based contracts with its customers, which include original terms of up to 25 years. The Partnership recognizes revenue earned from fee-based gathering, compression, treating and processing services in gathering services and related fees. The Partnership also earns revenue in the Williston Basin and Permian
Basin reporting segments from the sale of physical natural gas purchased from its customers under certain percent-of-proceeds arrangements. Under ASC Topic 606, these gathering contracts are presented net within cost of natural gas and NGLs. The Partnership sells natural gas that it retains from certain customers in the Barnett Shale reporting segment to offset the power expenses of the electric-driven compression on the DFW Midstream system. The Partnership also sells condensate and NGLs retained from certain of its gathering services in the Piceance Basin and Permian Basin reporting segments. Revenues from the sale of natural gas and condensate are recognized in Natural gas, NGLs and condensate sales; the associated expense is included in Operation and maintenance expense. Certain customers reimburse the Partnership for costs incurred on their behalf. The Partnership records costs incurred and reimbursed by its customers on a gross basis, with the revenue component recognized in Other revenues.
The transaction price in the Partnership’s contracts is primarily based on the volume of natural gas, crude oil or produced water transferred by its gathering systems to the customer’s agreed upon delivery point multiplied by the contractual rate. For contracts that include MVCs, variable consideration up to the MVC will be included in the transaction price. For contracts that do not include MVCs, the Partnership does not estimate variable consideration because the performance obligations are completed and settled on a daily basis. For contracts containing noncash consideration such as fuel received in-kind, the Partnership measures the transaction price at the point of sale when the volume, mix and market price of the commodities are known.
The Partnership has contracts with MVCs that are variable and constrained. Contracts with longer than monthly MVCs are reviewed on a quarterly basis and adjustments to those estimates are made during each respective reporting period, if necessary.
The transaction price is allocated if the contract contains more than one performance obligation such as contracts that include MVCs. The transaction price allocated is based on the MVC for the applicable measurement period.
Performance obligations. The majority of the Partnership’s contracts have a single performance obligation which is either to provide gathering services (an integrated service) or sell natural gas, NGLs and condensate, which are both satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. The Partnership also has certain contracts with multiple performance obligations. They include an option for the customer to acquire additional services such as contracts containing MVCs. These performance obligations would also be satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. In these instances, the Partnership allocates the contract’s transaction price to each performance obligation using its best estimate of the standalone selling price of each service in the contract.
Performance obligations for gathering services are generally satisfied over time. The Partnership utilizes either an output method (i.e., measure of progress) for guaranteed, stand-ready service contracts or an asset/system delivery time estimate for non-guaranteed, as-available service contracts.
Performance obligations for the sale of natural gas, NGLs and condensate are satisfied at a point in time. There are no significant judgments for these transactions because the customer obtains control based on an agreed upon delivery point.
Certain of the Partnership’s gathering and/or processing agreements provide for monthly or annual MVCs. Under these MVCs, the Partnership’s customers agree to ship and/or process a minimum volume of production on its gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to the Partnership at the end of the contracted measurement period if its actual throughput volumes are less than its contractual MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period.
The Partnership recognizes customer obligations under their MVCs as revenue and contract assets when (i) it is considered remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right.
Services are typically billed on a monthly basis and the Partnership does not offer extended payment terms. The Partnership does not have contracts with financing components.
The following table presents estimated revenue expected to be recognized over the remaining contract period related to performance obligations that are unsatisfied and are comprised of estimated MVC shortfall payments.
The Partnership applies the practical expedient in paragraph 606-10-50-14 of Topic 606 for certain arrangements that are considered optional purchases (i.e., there is no enforceable obligation for the customer to make purchases) and those amounts are therefore excluded from the table.
Revenue by Category. In the following table, revenue is disaggregated by geographic area and major products and services. For more detailed information about reportable segments, see Note 20.
Contract balances. Contract assets relate to the Partnership’s rights to consideration for work completed but not billed at the reporting date and consist of the estimated MVC shortfall payments expected from its customers and unbilled activity associated with contributions in aid of construction. Contract assets are transferred to trade receivables when the rights become unconditional. The following table provides information about contract assets from contracts with customers:
As of December 31, 2020, receivables with customers totaled $57.5 million and contract assets totaled $2.0 million which were included in the Accounts receivable caption on the consolidated balance sheet.
As of December 31, 2019, receivables with customers totaled $90.4 million and contract assets totaled $3.9 million which were included in the Accounts receivable caption on the consolidated balance sheet.
Contract liabilities (deferred revenue) relate to the advance consideration received from customers primarily for contributions in aid of construction. The Partnership recognizes contract liabilities under these arrangements in revenue over the contract period. For the years ended December 31, 2020 and 2019, the Partnership recognized $4.0 million and $10.1 million, respectively, of gathering services and related fees which was included in the contract liability balance as of the beginning of the period. See Note 8 for additional details.
4. PROPERTY, PLANT AND EQUIPMENT, NET
Details on the Partnership’s property, plant and equipment follow.
When the carrying amount of a long-lived asset is not recoverable, an impairment is recognized equal to the excess of the asset’s carrying value over its fair value, which is based on inputs that are not observable in the market, and thus represent Level 3 inputs under GAAP’s fair value hierarchy. The Partnership recognized $13.1 million and $59.4 million of impairments during the fiscal years ended December 31, 2020 and 2019, respectively. Due to the volatility of the inputs used, the Partnership cannot predict the likelihood of any future impairment. The details on significant impairments recognized during the years ended December 31, 2020 and 2019 are provided below.
Significant 2020 Impairments. The Partnership recognized a $5.1 million impairment related to the 2021 sale of compressor equipment in which the carrying value of the equipment exceeded the sale price, and a $3.6 million impairment related to the cancellation of a DJ Basin compressor station construction project due to delays in customer drilling plans.
Significant 2019 Impairments. The Partnership recognized a $34.7 million impairment resulting from the expansion of a processing plant in the DJ Basin that caused a significant reduction in the utilization of the original processing plant’s infrastructure, a $14.2 million impairment resulting from the sale of gathering system in the Piceance Basin in which the carrying value of the system exceeded the sale price, and a $9.7 million impairment of compressor equipment in the Barnett Shale.
Depreciation expense and capitalized interest for the Partnership follow.
5. AMORTIZING INTANGIBLE ASSETS
Details regarding the Partnership’s intangible assets, all of which are subject to amortization, follow.
The Partnership recognized amortization expense of its favorable gas gathering contracts in Other revenues as follows:
The Partnership recognized amortization expense of its contract and right of way intangibles in costs and expenses as follows:
The Partnership’s estimated aggregate annual amortization expected to be recognized as of December 31, 2020 for each of the five succeeding fiscal years follows.
6. GOODWILL
The Partnership evaluates goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill. If the reporting unit’s fair value exceeds its carrying value, including goodwill, the Partnership concludes that the goodwill of the reporting unit has not been impaired and no further work is performed. If it is determined that the reporting unit’s carrying value, including goodwill, exceeds its fair value, an impairment loss is recognized in the amount of the excess of the carrying value over the fair value. The Partnership’s impairment determinations, in the context of (i) its annual impairment evaluations and (ii) other-than-annual impairment evaluations involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources.
As of September 30, 2019, the Partnership performed its annual goodwill impairment testing for the Mountaineer Midstream reporting unit, a reporting unit included in the Marcellus Shale reportable segment, using a combination of the income and market approaches. It was determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value, including goodwill. As a result, a goodwill impairment charge of $16.2 million was recorded for the year ended December 31, 2019 that reduced the goodwill balance on the Partnership’s consolidated balance sheet to zero. The Partnership did not have a transaction in 2020 that resulted in the establishment of a goodwill balance.
7. EQUITY METHOD INVESTMENTS
Double E. In June 2019, the Partnership formed Double E in connection with (the “Double E Project”). Effective June 26, 2019, Summit Permian Transmission, a wholly owned, indirect and consolidated subsidiary of the Partnership, and an affiliate of Double E’s foundation shipper (the “JV Partner”), executed a definitive joint venture agreement (“Double E Agreement”) to fund the capital expenditures associated with the development of the Double E Project. In connection with the Double E Agreement and the related Double E Project, the Partnership contributed total assets of approximately $23.6 million in exchange for a 70% ownership interest in Double E and the JV Partner contributed $7.3 million of cash in exchange for a 30% ownership interest in Double E. Concurrent with these contributions, and in accordance with the Double E Agreement, Double E distributed $7.3 million to the Partnership. Subsequent to the formation of Double E, the Partnership made additional cash investments to Double E of $99.9 million, which includes $2.7 million in capitalized interest, and $18.3 million, which includes $1.1 million in capitalized interest and $0.7 million in capitalized legal costs, in 2020 and 2019, respectively.
Double E is deemed to be a variable interest entity as defined in GAAP. As of the date of the Double E Agreement, Summit Permian Transmission was not deemed to be the primary beneficiary of Double E due to the JV Partner’s voting rights on significant matters. The Partnership accounts for its ownership interest in Double E as an equity method investment because it has significant influence over Double E. The Partnership’s portion of Double E’s net assets, which was $132.9 million and $34.7 million at December 31, 2020 and 2019, respectively, is reported under the caption Investment in equity method investees on the consolidated balance sheet.
For the years ended December 31, 2020 and 2019, other than the investment activity noted above, Double E did not have any results of operations given that the Double E Project is currently under development.
Ohio Gathering. The Partnership has investments in OGC and OCC that it collectively refers to as Ohio Gathering. Ohio Gathering is accounted for as an equity method investment because it has joint control with non-affiliated owners, which gives the Partnership significant influence.
Ohio Gathering owns, operates and is currently developing midstream infrastructure consisting of a liquids-rich natural gas gathering system, a dry natural gas gathering system and a condensate stabilization facility in the Utica Shale in southeastern Ohio. Ohio Gathering provides gathering services pursuant to primarily long-term, fee-based gathering agreements, which include acreage dedications. The Partnership made its initial investment in Ohio Gathering in 2014 and owned 38.2% and 38.5% of Ohio Gathering at December 31, 2020 and 2019, respectively.
In December 2019, the Partnership identified certain triggering events which indicated that its equity method investment in Ohio Gathering could be impaired. In accordance with ASC Topic 323, an equity method impairment analysis was performed and determined the equity method impairment charge to be recorded on its consolidated financial statements resulting from an
other-than-temporary impairment. As a result of the analysis, an impairment charge of $329.7 million was recorded in 2019 in Loss from equity method investments on the accompanying consolidated statements of operations.
The fair value of the Partnership’s investment in Ohio Gathering was determined based upon applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the measurement date. The significant assumptions that were used to develop the estimate of the fair value under the discounted cash flow method include management’s best estimates of the expected future results using a probability weighted average set of cash flow forecasts and a discount rate of approximately 9.0%. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As such, the fair value of the Ohio Gathering equity method investment represents a Level 3 measurement. As a result, actual results may differ from the estimates and assumptions made for purposes of this impairment analysis.
Also in December 2019, an impairment loss of long-lived assets was recognized by OCC. Although the Partnership recognized activity for Ohio Gathering on a one-month lag, an impairment loss of $6.3 million was recorded in Loss from equity method investees in the consolidated statements of operations because the information was available to the Partnership.
A reconciliation of the difference between the carrying amount of the Partnership’s interest in Ohio Gathering and the Partnership’s underlying investment in Ohio Gathering, per Ohio Gathering’s books and records, is shown below.
(1) Amount is comprised of (i) a $329.7 million impairment of the Partnership’s equity method investment in Ohio Gathering; (ii) the write-off of the Partnership’s basis difference of $103.5 million in Ohio Gathering as a result of the impairment in the Partnership’s equity method investment in Ohio Gathering; and (iii) a $6.3 million impairment of long-lived assets in OCC.
Summarized balance sheet information for OGC and OCC follows (amounts represent 100% of investee financial information).
Summarized statements of operations information for OGC and OCC follow (amounts represent 100% of investee financial information).
8. DEFERRED REVENUE
Certain of the Partnership’s gathering and/or processing agreements provide for monthly or annual MVCs. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped and/or processed for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering or processing fee.
Many of the Partnership’s gas gathering agreements contain provisions that can reduce or delay the cash flows that it expects to receive from MVCs to the extent that a customer's actual throughput volumes are above or below its MVC for the applicable contracted measurement period. These provisions include the following:
•
To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, the Partnership would not receive gathering fees on throughput in excess of that customer's MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding measurement periods (as applicable).
•
To the extent that a customer's throughput volumes exceed its MVC in the applicable contracted measurement period, it may be entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. As a result of this mechanism, the weighted-average remaining period for which the Partnership’s MVCs apply will be less than the weighted-average of the originally stated MVC contractual terms.
•
To the extent that certain of the Partnership’s customers' throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement.
A rollforward of current deferred revenue follows.
A rollforward of noncurrent deferred revenue follows.
9. DEBT
Debt for the Partnership at December 31, 2020 and 2019 follows.
(1) Issuance costs are being amortized over the life of the notes.
The aggregate amount of Partnership’s debt maturing during each of the years after December 31, 2020 are as follows (in thousands):
Revolving Credit Facility. The Partnership’s subsidiary, Summit Holdings, has a senior secured revolving credit facility (the “Revolving Credit Facility”) which allows for revolving loans, letters of credit and swingline loans. SMLP and the Guarantor Subsidiaries fully and unconditionally and jointly and severally guarantee, and pledge substantially all of their assets in support of the indebtedness outstanding under the Revolving Credit Facility. At December 31, 2020, the Revolving Credit Facility has a $1.1 billion borrowing capacity and matures in May 2022.
On December 18, 2020, Summit Holdings entered into the Fourth Amendment to the Third Amended and Restated Credit Agreement which amended the Revolving Credit Facility to: (i) reduce the commitments from $1.25 billion to $1.1 billion; (ii) eliminate the $250.0 million accordion feature; (iii) add a basket for the potential issuance of up to $400.0 million of junior lien indebtedness; (iv) revise restrictions on the Partnership’s ability to use operating cash flow to repurchase junior debt and equity securities; (v) increase the total leverage covenant from 5.50x to 5.75x at all times going forward; (vi) replace the 3.75x senior secured leverage covenant with a new 3.50x first lien leverage covenant; (vii) add a new pricing tier of L + 325 bps if the total leverage ratio is greater than 5.00x; and (viii) restrict the Partnership’s ability to resume distributions on preferred and common units, subject to achieving certain financial and liquidity thresholds.
Borrowings under the Revolving Credit Facility bear interest, at the election of Summit Holdings, at a rate based on the alternate base rate (as defined in the credit agreement) plus an applicable margin ranging from 0.75% to 2.25% or the adjusted Eurodollar rate (as defined in the credit agreement) plus an applicable margin ranging from 1.75% to 3.25%, with the commitment fee ranging from 0.30% to 0.50% in each case based on the Partnership’s relative leverage at the time of determination. At December 31, 2020, the applicable margin under LIBOR borrowings was 2.75%, the interest rate was 2.9% and the unused portion of the
Revolving Credit Facility totaled $238.9 million, subject to a commitment fee of 0.50%, after giving effect to the issuance thereunder of a $4.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, the available borrowing capacity under the Revolving Credit Facility as of December 31, 2020 was approximately $105 million.
At December 31, 2020, the Revolving Credit Facility is secured by the membership interests of Summit Holdings and the membership interests of the Guarantor Subsidiaries of Summit Holdings and by substantially all of the assets of Summit Holdings and its Guarantor Subsidiaries (subject to exclusions set forth in the credit agreement). The credit agreement contains affirmative and negative covenants customary for credit facilities of its size and nature that, among other things, limit or restrict the ability (i) to incur additional debt; (ii) to make investments; (iii) to engage in certain mergers, consolidations, acquisitions or sales of assets; (iv) to enter into swap agreements and power purchase agreements; (v) to enter into leases that would cumulatively obligate payments in excess of $50.0 million over any 12 -month period; and (vi) of Summit Holdings to make distributions, with certain exceptions, including the distribution of Available Cash (as defined in the SMLP Partnership Agreement) if no default or event of default then exists or would result therefrom and Summit Holdings is in pro forma compliance with its financial covenants. In addition, the Revolving Credit Facility requires Summit Holdings to maintain (i) a ratio of consolidated trailing 12 -month earnings before interest, income taxes, depreciation and amortization ("EBITDA") to net interest expense of not less than 2.5 to 1.0 as defined in the credit agreement, (ii) a ratio of total net indebtedness to consolidated trailing 12 -month EBITDA of not more than 5.75 to 1.00 and, (iii) a ratio of first lien net indebtedness to consolidated trailing 12 -month EBITDA of not more than 3.75 to 1.00. As of December 31, 2020, the Partnership was in compliance with the Revolving Credit Facility's financial covenants and there were no defaults or events of default during the year ended December 31, 2020.
As of December 31, 2020, the Partnership had $7.4 million of debt issuance costs attributable to its Revolving Credit Facility and related amendments, which are included in Other noncurrent assets on the consolidated balance sheet.
ECP Loans. On May 28, 2020, in connection with the closing of the GP Buy-In Transaction, Summit Holdings, entered into (i) a Term Loan Credit Agreement (the “ECP NewCo Term Loan Credit Agreement”), with SMP TopCo, LLC, a Delaware limited liability company and affiliate of ECP (“ECP NewCo”), as lender and administrative agent, and Mizuho Bank (USA) (“Mizuho”), as collateral agent, in a principal amount of $28.2 million (the “ECP NewCo Loan”), and (ii) a Term Loan Credit Agreement (the “ECP Holdings Term Loan Credit Agreement” and together with the ECP NewCo Term Loan Credit Agreement, the “ECP Term Loan Credit Agreements”), with ECP Holdings, as lender, and ECP NewCo, as administrative agent and Mizuho, as collateral agent, in a principal amount of $6.8 million (the “ECP Holdings Loan” and together with the ECP NewCo Loan, the “ECP Loans”). The ECP Loans were set to mature on March 31, 2021 and bore interest at a fixed rate of 8.00% per annum, with the interest payment due at maturity of the ECP Loans. With borrowings under the Partnership’s Revolving Credit Facility, the Partnership fully repaid all amounts outstanding under the ECP Loans ($35 million of principal and $0.6 million of accrued interest) on August 7, 2020.
2022 Senior Notes. In July 2014, the Co-Issuers co-issued the 2022 Senior Notes. The Partnership pays interest on the 2022 Senior Notes semi-annually in cash in arrears on February 15 and August 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 ended December 31, 2020, we were in compliance with the financial covenants governing its 2022 Senior Notes.
2025 Senior Notes. In February 2017, the Co-Issuers co-issued the 2025 Senior Notes. The Partnership pays interest on the 2025 Senior Notes semi-annually in cash in arrears on April 15 and October 15 of each year. The 2025 Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of the Partnership’s existing and future senior obligations. The 2025 Senior Notes are effectively subordinated in right of payment to all of the Partnership’s secured indebtedness, to the extent of the collateral securing such indebtedness.
The Co-Issuers have the right to redeem all or part of the 2025 Senior Notes at a redemption price of 104.313%. On and after April 15, 2021, the Co-Issuers may redeem all or part of the 2025 Senior Notes at a redemption price of 102.875% (with the redemption price declining ratably each year to 100.000% on April 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 ended December 31, 2020, that Partnership was in compliance with the financial covenants governing its 2025 Senior Notes.
SMPH Term Loan and TL Restructuring. Until November 17, 2020, a subsidiary of the Partnership, SMP Holdings, had a senior secured term loan facility with $155.2 million of principal outstanding and a maturity date of May 15, 2022. Borrowings under the SMPH Term Loan bore interest at LIBOR plus 6.00% or ABR plus 5.00%, as defined in the SMPH Term Loan, and were secured by the following collateral: (i) a perfected first-priority lien on, and pledge of (a) all of the capital stock issued by SMP Holdings, (b) 2.3 million SMLP units owned by SMP Holdings, (c) all of the equity interests owned by SMP Holdings in the General Partner, and (ii) substantially all other personal property of SMP Holdings.
On September 29, 2020, SMP Holdings, Summit Investments and, for limited purposes, the Partnership, entered into the TL Restructuring. At the closing of the TL Restructuring on November 17, 2020, the Term Loan Agent executed a Strict Foreclosure on behalf of the Term Loan Lenders on the 2,306,972 common units held by SMP Holdings and pledged as collateral under the SMPH Term Loan, which was then distributed to all SMPH Term Loan Lenders on a pro rata basis. In addition to the Strict Foreclosure, SMP Holdings paid to each of the SMPH Term Loan Lenders its pro rata share of $26.5 million in cash that the Partnership paid to SMP Holdings to fully satisfy its obligation with respect to the deferred purchased price obligation.
As of December 31, 2020, the SMPH Term Loan is fully satisfied and no longer exists.
10. LIABILITY MANAGEMENT TRANSACTIONS
During the year ended December 31, 2020, the Partnership and its subsidiaries completed several liability management transactions, described below, that resulted in the early extinguishment of an aggregate $306.5 million face value of the Partnership’s indebtedness.
Open Market Repurchases. During the year ended December 31, 2020, the Partnership made a number of open market repurchases of the 2022 Senior Notes and 2025 Senior Notes that resulted in the extinguishment of $32.4 million of face value of the 2022 Senior Notes and $201.8 million of face value of the 2025 Senior Notes (the “Open Market Repurchases”). 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 early extinguishment of debt during the year ended December 31, 2020.
Debt Tender Offers. In September 2020, the Co-Issuers completed the Debt Tender Offers to purchase a portion of the 2022 Senior Notes and 2025 Senior Notes. Upon concluding 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 $48.7 million, and the Partnership recognized a $23.3 million gain on the early extinguishment of debt during the year ended December 31, 2020.
SMPH Term Loan Restructuring. On November 17, 2020, the Partnership completed the TL Restructuring and recognized a gain of $94.0 million equal to the difference between the face value of the cancelled SMPH Term Loan and the fair value of the total consideration transferred, including unamortized debt issuance costs, and certain direct transaction costs related to the restructuring. The transaction was accounted for under ASC Topic 470-60 “Troubled Debt Restructuring with Debtors” and had a total impact of $26.15 per share.
Summary of gain on extinguishment of debt. The Partnership recognized a $203.1 million gain on extinguishment of debt during the year ended December 31, 2020, the components of which are summarized in the table below.
11. COMMITMENTS AND CONTINGENCIES
Environmental Matters. Although the Partnership believes that it is in material compliance with applicable environmental regulations, the risk of environmental remediation costs and liabilities are inherent in pipeline ownership and operation. Furthermore, the Partnership can provide no assurances that significant environmental remediation costs and liabilities will not be incurred in the future. The Partnership is currently not aware of any material contingent liabilities that exist with respect to environmental matters, except as noted below.
In 2015, the Partnership learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota (“Meadowlark Rupture”). The Meadowlark Rupture, which was covered by Summit Investments’ insurance policies, was subject to maximum coverage of $25.0 million from its pollution liability insurance policy and $200.0 million from its property and business interruption insurance policy. The pollution liability policy was exhausted in 2015. Prior to the GP Buy-In Transaction, Summit Investments and SMP Holdings indemnified the Partnership for certain obligations and liabilities related to the incident. As a result of the GP Buy-In Transaction, the Partnership is no longer indemnified for these obligations.
A rollforward of the Partnership’s undiscounted accrued environmental remediation liabilities related to the Meadowlark Rupture follows.
As of December 31, 2020, the Partnership has recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures expected to be incurred subsequent to December 31, 2021. Each of these amounts represent the Partnership’s best estimate for costs expected to be incurred. Neither of these amounts have been discounted to its present value.
Beginning in 2015, the U.S. Department of Justice (“DOJ”) issued grand jury subpoenas to Summit Investments, the Partnership, our General Partner and Meadowlark Midstream requesting certain materials related to the Meadowlark Rupture. On June 19, 2015, Meadowlark Midstream and Summit Investments received a complaint from the North Dakota Industrial Commission seeking approximately $2.5 million in fines and other fees related to the incident. This matter is also under investigation by the U.S. Environmental Protection Agency, the North Dakota Office of the Attorney General, the North Dakota Department of Environmental Quality, and the North Dakota Game and Fish Department. The government’s investigation is still ongoing. During this time, the Partnership has entered ‎into tolling agreements with both the DOJ and the North Dakota attorney general, which ‎were most recently extended to May 7, 2021. There can be no assurance that these tolling agreements will be extended. Discussions with the DOJ and other agencies regarding a resolution of this matter are ongoing. Liability for this incident could arise under civil and misdemeanor and felony criminal statutes, including the Clean Water Act. In accordance with GAAP, the Partnership has accrued a $17.0 million loss contingency for this matter as of December 31, 2020. While the Partnership believes a loss for claims and/or actions arising from the Meadowlark Rupture, whether in a negotiated settlement or as a result of litigation, is probable, due to the complexity of resolving the numerous issues surrounding this matter, at this time we cannot reasonably predict whether any actual loss, if incurred, would be materially higher or lower than the accrued amount.
Legal Proceedings. The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims or those arising in the normal course of business would not individually or in the aggregate have a material adverse effect on the Partnership's financial position or results of operations.
12. FINANCIAL INSTRUMENTS
Concentrations of Credit Risk. Financial instruments that potentially subject the Partnership to concentrations of credit risk consist of cash and cash equivalents, restricted cash and accounts receivable. The Partnership maintains its cash and cash equivalents and restricted cash in bank deposit accounts that frequently exceed federally insured limits. The Partnership has not experienced any losses in such accounts and does not believe it is exposed to any significant risk.
Accounts receivable primarily comprise amounts due for the gathering, compression, treating and processing services the Partnership provides to its customers and also the sale of natural gas liquids resulting from its processing services. This industry concentration has the potential to impact its overall exposure to credit risk, either positively or negatively, in that the Partnerships customers may be similarly affected by changes in economic, industry or other conditions. The Partnership monitors the creditworthiness of its counterparties and can require letters of credit or other forms of credit assurance for receivables from counterparties that are judged to have substandard credit, unless the credit risk can otherwise be mitigated. The Partnerships top five customers or counterparties accounted for 51% of its total accounts receivable at December 31, 2020, compared to 46% as of December 31, 2019.
Fair Value. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and trade accounts payable reported on the consolidated balance sheet approximates fair value due to their short-term maturities.
A summary of the estimated fair value of the Partnerships debt financial instruments follows.
The carrying value on the balance sheet of the Revolving Credit Facility is its fair value due to its floating interest rate. The fair value for the Senior Notes is based on an average of nonbinding broker quotes as of December 31, 2020 and 2019. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the Senior Notes.
13. PARTNERS' CAPITAL AND MEZZANINE CAPITAL
Noncontrolling Interest. In March 2019, and prior to the GP Buy-In Transaction, a subsidiary of Summit Investments cancelled its incentive distribution rights agreement with SMLP and converted its 2% economic general partner interest to a non-economic general partner interest in exchange for 0.6 million SMLP common units. This exchange is reflected in the Consolidated Statements of Partners’ Capital as a reduction to noncontrolling interest and an increase to Partners’ Capital.
Common Units. A rollforward of the number of common limited partner units follows for the period from December 31, 2018 to December 31, 2020.
(1) The purchase price for the SMLP common units reflected in the consolidated statement of partners’ capital for the year ended December 31, 2020 is comprised of the (i) the $35.0 million cash payment to ECP, (ii) the $2.3 million fair value for the issuance of 0.7 million warrants, and (iii) $6.8 million of advisory fees and other direct costs related to closing the GP Buy-In Transaction.
(2) As adjusted for reverse unit split.
Series A Preferred Units. In November 2017, the Partnership issued 300,000 Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series A Preferred Units”) representing limited partner interests in the Partnership at a price to the public of $1,000 per unit. The Partnership used the net proceeds of $293.2 million (after deducting underwriting discounts and offering expenses) to repay outstanding borrowings under the Revolving Credit Facility.
The Series A Preferred Units rank senior to (i) common units representing limited partner interests in the Partnership and (ii) each other class or series of limited partner interests or other equity securities in the Partnership that may be established in the future that expressly ranks junior to the Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (the “Junior Securities”). The Series A Preferred Units rank equal in all respects with each class or series of limited partner interests or other equity securities in the Partnership that may be established in the future that is not expressly made senior or subordinated to the Series A Preferred Units as to the payment of distributions and amounts payable on a liquidation event (the “Parity Securities”). The Series A Preferred Units rank junior to (i) all of the Partnership’s existing and future indebtedness and other liabilities with respect to assets available to satisfy claims against the Partnership and (ii) each other class or series of limited partner interests or other equity securities in the Partnership established in the future that is expressly made senior to the Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event. Income is allocated to the Series A Preferred Units in an amount equal to the earned distributions (whether these distributions are declared by the General Partner to be paid or not) for the respective reporting period.
Distributions on the Series A Preferred Units are cumulative and compounding and are payable semi-annually in arrears on the 15th day of each June and December through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year (each, a “Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Distribution Payment Date, in each case, when, as, and if declared by the General Partner out of legally available funds for such purpose.
The initial distribution rate for the Series A Preferred Units is 9.50% per annum of the $1,000 liquidation preference per Series A Preferred Unit. On and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of the liquidation preference equal to the three-month LIBOR plus a spread of 7.43%.
In connection with the GP Buy-In Transaction, the Partnership suspended its distributions to be paid to holders of its Series A Preferred Units, commencing with respect to the quarter ending March 31, 2020.
A rollforward of the number of Series A Preferred Units follows for the period from December 31, 2018 to December 31, 2020.
Series A Preferred Unit Exchange Offer. In July 2020, the Partnership completed an offer to exchange its Series A Preferred Units for newly issued common units, whereby it issued 837,547 SMLP common units in exchange for 62,816 Series A Preferred Units.
Series A Preferred Tender Offer. In December 2020, the Partnership completed a cash tender offer for its Series A Preferred Units 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.
Subsidiary Series A Preferred Units. The Partnership has Subsidiary Series A Preferred Units that ranks senior to each other class or series of limited partner interests or other equity securities in Permian Holdco that may be established in the future that expressly ranks junior to the Subsidiary Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (the “Junior Securities”). The Subsidiary Series A Preferred Units rank equal in all respects with each class or
series of limited partner interests or other equity securities in Permian Holdco that may be established in the future that is not expressly made senior or subordinated to the Subsidiary Series A Preferred Units as to the payment of distributions and amounts payable on a liquidation event (the “Parity Securities”). The Subsidiary Series A Preferred Units rank junior to (i) all of Permian Holdco’s or a subsidiary of Permian Holdco’s future indebtedness and other liabilities with respect to assets available to satisfy claims against Permian Holdco and (ii) each other class or series of limited partner interests or other equity securities in Permian Holdco established in the future that is expressly made senior to the Subsidiary Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event. Income is allocated to the Subsidiary Series A Preferred Units in an amount equal to the earned distributions for the respective reporting period.
Distributions on the Subsidiary Series A Preferred Units are cumulative and compounding and are payable 21 days following the quarterly period ended March, June, September and December of each year (each, a “Series A Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Series A Distribution Payment Date, in each case, when, as, and if declared by Permian Holdco out of legally available funds for such purpose.
The distribution rate for the Subsidiary Series A Preferred Units is 7.00% per annum of the $1,000 liquidation preference per Subsidiary Series A Preferred Unit. A pro-rated initial distribution on the Subsidiary Series A Preferred Units was Paid-in-kind (“PIK”) on January 21, 2020 in an amount equal to 7.00% per Subsidiary Series A Preferred Unit plus 1.00% per annum of the undrawn commitment units.
In 2020, the Partnership issued 55,251 Subsidiary Series A Preferred Units at a price of $1,000 per unit for net proceeds of $48.7 million (after deducting underwriting discounts and offering expenses). All proceeds were used to fund capital expenses associated with the Double E Project.
In 2019, the Partnership issued 30,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. The net proceeds of $27.4 million (after deducting underwriting discounts and offering expenses) were used to fund capital expenses associated with the Double E Project.
The proceeds associated with the issuance of Subsidiary Series A Preferred Units are classified as restricted cash on the accompanying consolidated balance sheets in accordance with the underlying agreement with TPG Energy Solutions Anthem, L.P. until the related funding is used for the Double E Project.
These Subsidiary Series A Preferred Units are considered redeemable securities under GAAP due to the existence of certain redemption provisions that are outside of the Partnership’s control. Therefore, the securities are classified as temporary equity in the mezzanine section of the consolidated balance sheets.
The Partnership records its Subsidiary Series A Preferred Units at fair value upon issuance, net of issuance costs, and subsequently records an effective interest method accretion amount each reporting period to accrete the carrying value to a most probable redemption value that is based on a predetermined internal rate of return measure. The Partnership also elected to make payment-in-kind (“PIK”) distributions to holders of the Subsidiary Series A Preferred Units during the year ended December 31, 2020 and these PIK distributions increase the liquidation preference on each Subsidiary Series A Preferred Unit. Ultimately, Net Income (Loss) Attributable to common limited partners includes adjustments for PIK distributions and redemption accretion.
If the Subsidiary Series A Preferred Units were redeemed on December 31, 2020, the redemption amount would be $106.6 million, when considering the applicable multiple of invested capital metric and make-whole amount provisions contained in the Subsidiary Series A Preferred Unit agreement. The following table shows the change in the Partnership’s Subsidiary Series A Preferred Unit balance during the year ended December 31, 2020:
(1) Amount is net of $3.9 million of issuance costs at December 31, 2020.
Warrants. On May 28, 2020 and in connection with the GP Buy-In Transaction, the Partnership issued (i) a warrant to purchase up to 0.5 million SMLP common units to ECP NewCo (the “ECP NewCo Warrant”) and (ii) a warrant to purchase up to 0.1 million SMLP common units to ECP Holdings (the “ECP Holdings Warrant” and together with the ECP NewCo Warrant, the “ECP Warrants”). The exercise price under the ECP Warrants is $15.35 per SMLP common unit and the Partnership may issue a maximum of 0.7 million SMLP common units under the ECP Warrants.
Upon exercise of the ECP Warrants, each of ECP NewCo and ECP Holdings may receive, at its election: (i) a number of SMLP common units equal to the number of SMLP common units for which the ECP Warrants are being exercised, if exercising the ECP Warrants by cash payment of the exercise price; (ii) a number of SMLP common units equal to the product of the number of common units being exercised multiplied by (a) the difference between the average of the daily volume-weighted average price (“VWAP”) of the SMLP common units on the New York Stock Exchange (the “NYSE”) on each of the three trading days prior to the delivery of the notice of exercise (the “VWAP Average”) and the exercise price (the “VWAP Difference”), divided by (b) the VWAP Average; and/or (iii) an amount in cash, to the extent that the Partnership’s leverage ratio would be at least 0.5x less than the maximum applicable ratio set forth in the Revolving Credit Facility, equal to the product of (a) the number of SMLP common units exercised and (b) the VWAP Difference, subject to certain adjustments under the ECP Warrants.
The ECP Warrants are subject to standard anti-dilution adjustments for stock dividends, stock splits (including reverse splits) and recapitalizations and are exercisable at any time on or before May 28, 2023. Upon exercise of the ECP Warrants, the proceeds to the holders of the ECP Warrants, whether in the form of cash or common units, will be capped at $30.00 per SMLP common unit above the exercise price.
At issuance the ECP Warrants were valued at $2.3 million using a Black-Scholes model and accounted for as a liability instrument. At December 31, 2020, the ECP Warrants were valued at $1.9 million.
Cash Distribution Policy. In connection with the GP Buy-In Transaction, the Partnership suspended its cash distributions to holders of its common units, commencing with respect to the quarter ending March 31, 2020. Upon the resumption of distributions, the Partnership Agreement requires that it distribute all available cash, subject to reserves established by its General Partner, within 45 days after the end of each quarter to unitholders of record on the applicable record date. The amount of distributions paid under this policy is subject to fluctuations based on the amount of cash the Partnership generates from its business and the decision to make any distribution is determined by the General Partner, taking into consideration the terms of the Partnership Agreement.
Cash Distributions Paid and Declared. Prior to the GP Buy-In Transaction, SMLP paid the following per-unit cash distributions to its unitholders during the years ended December 31:
On January 29, 2020, the Board of Directors declared a distribution of $0.125 per unit for the quarterly period ended December 31, 2019. This distribution, which totaled $11.7 million, was paid on February 14, 2020 to unitholders of record at the close of business on February 7, 2020.
14. EARNINGS PER UNIT
The following table details the components of EPU.
(1)
As a result of the GP Buy-In Transaction, our historical results are those of Summit Investments. The number of common units of 3.0 million as of December 31, 2019 represents those of Summit Investments and has been used for the earnings per unit calculation presented herein.
15. SUPPLEMENTAL CASH FLOW INFORMATION
16. UNIT-BASED AND NONCASH COMPENSATION
SMLP Long-Term Incentive Plan. The Partnership’s Long-Term Incentive Plan (“SMLP LTIP”) provides for equity awards to eligible officers, employees, consultants and directors of the Partnership, thereby linking the recipients' compensation directly to SMLP’s performance. The SMLP LTIP provides for the granting, from time to time, of unit-based awards, including common
units, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Grants are made at the discretion of the Board of Directors or Compensation Committee. A total of 1.0 million common units was reserved for issuance pursuant to and in accordance with the SMLP LTIP. As of December 31, 2020, approximately 0.4 million common units remained available for future issuance.
The following table presents phantom unit activity for the periods presented:
A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. Distribution equivalent rights for each phantom unit provide for a lump sum cash amount equal to the accrued distributions from the grant date to be paid in cash upon the vesting date.
Phantom units granted to date generally vest ratably over a three-year period. Grant date fair value is determined based on the closing price of SMLP’s common units on the date of grant multiplied by the number of phantom units awarded to the grantee. Forfeitures are recorded as incurred. Holders of all phantom units granted to date are entitled to receive distribution equivalent rights for each phantom unit, providing for a lump sum cash amount equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. Upon vesting, phantom unit awards may be settled, at the Partnership’s discretion, in cash and/or common units, but the current intention is to settle all phantom unit awards with common units.
The intrinsic value of phantom units that vested during the years ended December 31, follows.
As of December 31, 2020, the unrecognized unit-based compensation related to the SMLP LTIP was $3.4 million. Incremental unit-based compensation will be recorded over the remaining weighted-average vesting period of approximately 1.4 years.
Unit-based compensation recognized in general and administrative expense related to awards under the SMLP LTIP follows.
17. LEASES
Leases. The Partnership leases certain office space and equipment under operating leases. The Partnership leases office space for terms of between 3 and 10 years. Office space leases limit exposure to risks related to ownership, such as fluctuations in real estate prices. The Partnership leases equipment primarily to support its operations in response to the needs of its gathering systems for terms of between 3 and 4 years. The Partnership also leases vehicles under finance leases to support its operations in response to the needs of its gathering systems for a term of 3 years.
Some of the Partnerships leases are subject to annual escalations relating to the Consumer Price Index (“CPI”). While lease liabilities are not remeasured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred.
In accordance with the provisions in the Revolving Credit Facility, the Partnership’s aggregate finance lease obligations cannot exceed $50.0 million in any period of twelve consecutive calendar months during the life of such leases.
Significant assumptions or judgments include the determination of whether a contract contains a lease and the discount rate used in the lease liabilities.
The rate implicit in the lease contracts are not readily determinable. In determining the discount rate used in for lease liabilities, the Partnership analyzed certain factors in its incremental borrowing rate, including collateral assumptions and the term used. The incremental borrowing rate on the Revolving Credit Facility was 2.90% at December 31, 2020, which reflects the fixed rate at which the Partnership could borrow a similar amount, for a similar term and with similar collateral as in the lease contracts at the commencement date.
In connection with the adoption of Topic 842, the Partnership elected the package of practical expedients which permits them not to reassess under the new standard its prior conclusions about lease identification, lease classification and initial direct costs. The Company also elected the practical expedient to not separate the nonlease components from the associated lease components for all classes of underlying assets, as well as the short-term lease recognition exemption.
ROU assets (included in the Property, plant and equipment, net caption on the Partnership’s consolidated balance sheet) and lease liabilities (included in the Other current liabilities and Other noncurrent liabilities captions on the Partnership’s consolidated balance sheet) follow:
Lease cost and Other information follow:
The Partnership recognizes total lease expense incurred or allocated to us in general and administrative expenses. Lease expense related to operating leases, including lease expense incurred on the Partnership’s behalf and allocated to us, was as follows:
Future minimum lease payments due under noncancelable leases at December 31, 2020, were as follows:
18. DISPOSITIONS
In 2019, the Partnership completed two divestitures described in further detail below.
Red Rock Gathering Asset Disposition. In December 2019, the Partnership completed the sale of certain assets contained in its Piceance Basin reportable segment for a cash purchase price of $12.0 million. Prior to the sale, the Partnership recorded an impairment charge of $14.2 million based on the expected consideration and the carrying value for the disposed assets. The financial contribution of these assets in 2019 (a component of the Piceance Basin reportable segment) are included in the Partnership’s consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019.
Tioga Midstream Disposition. In March 2019, the Partnership closed on the sale of certain assets contained in the Williston Basin reportable segment for a cash purchase price of $90.0 million. Upon closing the sale in March 2019, the Partnership recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for disposed assets. The gain is included in the Gain on asset sales, net caption on the consolidated statement of operations. The financial contribution of these assets in 2019 (a component of the Williston Basin reportable segment) are included in the Partnership’s consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019.
19. RESTRUCTURING
2020 Restructuring Activities. In 2020, management approved and initiated a plan to restructure its operations (“2020 Restructuring Plan”), resulting in certain management, facility and organizational changes. Under the 2020 Restructuring Plan, the Partnership expensed approximately $5.6 million in 2020 of costs associated with its restructuring activities. These activities consisted primarily of employee-related severance costs, and are included within the General and administrative caption on the consolidated statement of operations.
2019 Restructuring Activities. In 2019, management approved and initiated a plan to restructure its operations (“2019 Restructuring Plan”), resulting in certain management, facility and organizational changes. Under the 2019 Restructuring Plan, the Partnership expensed approximately $3.5 million and $4.9 million in 2020 and 2019, respectively, of costs associated with its restructuring activities. These activities consisted primarily of employee-related costs and consulting costs in support of the project. These costs are included within the General and administrative caption on the consolidated statement of operations.
Details for the 2020 Restructuring Plan and the 2019 Restructuring Plan follow.
20. SEGMENT INFORMATION
As of December 31, 2020, the Partnership’s reportable segments are:
•
the Utica Shale, which is served by Summit Utica;
•
Ohio Gathering, which includes the Partnership’s ownership interest in OGC and OCC;
•
the Williston Basin, which is served by Polar and Divide, Meadowlark Midstream and Bison Midstream;
•
the DJ Basin, which is served by Niobrara G&P;
•
the Permian Basin, which is served by Summit Permian;
•
the Piceance Basin, which is served by Grand River;
•
the Barnett Shale, which is served by DFW Midstream; and
•
the Marcellus Shale, which is served by Mountaineer Midstream.
Until March 22, 2019, the Partnership owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Until December 1, 2019, the Partnership owned certain assets in the Red Rock Gathering system operating in the Piceance Basin. Refer to Note 16 to the consolidated financial statements for details on the sale of Tioga Midstream and on the sale of certain assets in the Red Rock Gathering system.
Each of the Partnership’s reportable segments provides midstream services in a specific geographic area. Reportable segments reflect the way in which the Partnership internally report’s the financial information used to make decisions and allocate resources in connection with its operations.
The Ohio Gathering reportable segment includes the Partnership’s investment in Ohio Gathering. Income or loss from equity method investees, as reflected on the statements of operations, relates to Ohio Gathering and is recognized and disclosed on a one-month lag see Note 7.
For the year ended December 31, 2020, other than the investment activity described in Note 7, Double E did not have any results of operations given that the Double E Project is currently under development. The Double E Project is expected to be operational in the fourth quarter of 2021.
Corporate and Other represents those results that: (i) are not specifically attributable to a reportable segment; (ii) are not individually reportable (such as Double E); or (iii) have not been allocated to a reportable segments for the purpose of evaluating their performance, including certain general and administrative expense items, certain natural gas and crude oil marketing services and transaction costs.
Assets by reportable segment follow.
(1) At December 31, 2020, Corporate and Other included $132.9 million relating to the Partnership’s investment in Double E (included in the Investment in equity method investees caption of the consolidated balance sheet). At December 31, 2019, Corporate and Other included $34.7 million relating to the Partnership’s investment in Double E (included in the Investment in equity method investees caption of the consolidated balance sheet).
Revenues by reportable segment follow.
Counterparties accounting for a significant portion of total revenues were as follows:
* Less than 10%
Depreciation and amortization, including the amortization expense associated with the Partnership’s favorable and unfavorable gas gathering contracts as reported in other revenues, by reportable segment follows.
(1) Includes the amortization expense associated with the Partnership’s favorable and unfavorable gas gathering contracts as reported in Other revenues.
Cash paid for capital expenditures by reportable segment follow.
(1) For the year ended December 31, 2019, the amount includes sales tax reimbursements of $1.1 million.
For the year ended December 31, 2019, Corporate and Other includes cash paid of $1.6 million for corporate purposes; the remainder represents capital expenditures relating to the Double E Project.
The Partnership assesses the performance of its reportable segments based on segment adjusted EBITDA. The Partnership defines segment adjusted EBITDA as total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) 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 (vii) other noncash expenses or losses, less other noncash income or gains and (ix) restructuring expenses. Proportional adjusted EBITDA for the Partnership’s equity method investees is defined as the product of (i) total revenues less total expenses, excluding impairments and other noncash income or expense items, and amortization for deferred contract costs; and (ii) ownership interest in Ohio Gathering during the respective period.
For the purpose of evaluating segment performance, the Partnership excludes the effect of Corporate and Other revenues and expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees), certain natural gas and crude oil marketing services, transaction costs, interest expense and income tax expense or benefit from segment adjusted EBITDA.
Segment adjusted EBITDA by reportable segment follows.
A reconciliation of income or loss before income taxes and income or loss from equity method investees to total of reportable segments' measures of profit or loss follows.
(1) Includes the amortization expense associated with the Partnership’s favorable gas gathering contracts as reported in other revenues.
For the years ended December 31, 2020 and 2019, adjustments related to MVC shortfall payments recognize the earnings from MVC shortfall payments ratably over the term of the associated MVC.
Contributions in aid of construction are recognized over the remaining term of the respective contract. The Partnership includes adjustments related to capital reimbursement activity in its calculation of segment adjusted EBITDA to account for revenue recognized from contributions in aid of construction.
21. SUBSEQUENT EVENTS
In January 2021, Double E received its Notice to Proceed with construction, as well as approval of its implementation plan, from FERC. With the receipt of the 7(c) certificate and the NTP, construction on the Double E pipeline commenced in February 2021, and the pipeline is expected to be in-service by the end of 2021.
In February 2021, Summit Permian Transmission, LLC, received $175.0 million of commitments to finance the development of the Double E Project. The lenders have committed to provide senior secured credit facilities consisting of a $160.0 million delayed draw term loan facility and a $15.0 million working capital facility (the “Credit Facilities”). The Credit Facilities
are non-recourse to SMLP and mature seven years after the date of initial borrowing. SMLP expects to close and fund on the Credit Facilities shortly and will post a $15.0 million letter of credit under its corporate revolving credit facility to support back-end equity contributions, if needed, upon first funding.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
There have been no changes in, or disagreements with, accountants on accounting and financial disclosure matters during the years ended December 31, 2020 and 2019.
Item 9A.
Item 9A. Controls and Procedures.
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to the management of our General Partner, including our General Partner’s principal executive and principal financial officers (whom we refer to as the Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. SMLP’s management, with the participation of the Chief Executive Officer and Chief Financial Officer of SMLP's General Partner, has evaluated the effectiveness of SMLP’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this annual report (the "Evaluation Date"). Based on such evaluation, the Chief Executive Officer and Chief Financial Officer of SMLP's General Partner have concluded that, as of the Evaluation Date, SMLP’s disclosure controls and procedures are effective.
Changes in Internal Control Over Financial Reporting
There have not been any changes in SMLP’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth fiscal quarter of 2020 that have materially affected, or are reasonably likely to materially affect, SMLP's internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
Our General Partner is responsible for establishing and maintaining adequate internal control over financial reporting for the Partnership. With our participation, an evaluation of the effectiveness of our internal control over financial reporting was conducted as of December 31, 2020, based on the framework and criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has concluded that our internal control over financial reporting was effective as of December 31, 2020. Our independent registered public accounting firm has issued an audit report on our internal control over financial reporting, included below of this report.
/s/ J. HEATH DENEKE
J. Heath Deneke
President and Chief Executive Officer, Summit Midstream GP, LLC (the General Partner of SMLP)
/s/ MARC D. STRATTON
Marc D. Stratton
Executive Vice President and Chief Financial Officer, Summit Midstream GP, LLC (the General Partner of SMLP)
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Summit Midstream, GP, LLC and the unitholders of Summit Midstream Partners, LP
Houston, Texas
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Summit Midstream Partners, LP and
subsidiaries (the “Partnership”) as of December 31, 2020, based on criteria established in Internal Control
- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control
- Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2020, of the Partnership and our report dated March 4, 2021, expressed an unqualified opinion on those financial statements based on our audit.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Houston, Texas
March 4, 2021
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
Management of Summit Midstream Partners, LP
The Partnership is managed by the directors and executive officers of its General Partner, a wholly owned subsidiary of the Partnership as of December 31, 2020. The General Partner became a wholly owned subsidiary of the Partnership in May 2020 as a result of the GP Buy-In Transaction. Directors are appointed for a term of three years and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. In connection with the GP Buy-In Transaction, the Partnership amended its Partnership Agreement to, among other things, provide its common unitholders with voting rights in the election of the members of the Board on a staggered basis beginning in 2022. The Board is divided into three classes of directors. Two Class I directors will serve for an initial term that expires at the 2022 annual meeting, two Class II directors will serve for an initial term that expires at the 2023 annual meeting, and one Class III director will serve for an initial term that expires at the 2024 annual meeting. J. Heath Deneke, President and Chief Executive Offer of the general partner, serves as Chairman of the Board and will not be subject to public election.
Committees of the Board of Directors
The Board of Directors has an Audit Committee, a Compensation Committee, and a Corporate Governance and Nominating Committee, and may have such other committees as the Board of Directors shall determine from time to time.
The table below shows the current membership of each standing board committee and indicates which directors are independent directors.
(1) In May 2020, the Conflicts Committee ceased to be a standing Committee of the Board.
(2) The Corporate Governance and Nominating Committee of the Board was established in May 2020
(3) Mr. Deneke was appointed Chairman of Board effective May 28, 2020
(4) Mr. Wohleber was appointed as the Lead Director effective May 28, 2020
Each of the standing committees of the Board of Directors will have the composition and responsibilities described below.
Audit Committee. Mr. Jacobe, Mr. McNally and Mr. Peters serve as the members of the Audit Committee. Mr. Peters serves as the chair of the Audit Committee. In this role, Mr. Peters satisfies the SEC and New York Stock Exchange rules regarding independence and qualifies as an Audit Committee financial expert.
The Audit Committee assists the Board of Directors in its oversight of the integrity of the Partnership’s financial statements and its compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee has the sole authority to retain and terminate the Partnership’s independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by the Partnership’s independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of the Partnership’s independent registered public accounting firm. The Partnership’s independent registered public accounting firm has unrestricted access to the Audit Committee.
The Partnership’s Audit Committee has adopted an audit committee charter, which is publicly available on the Partnership’s website under the "Corporate Governance" subsection of the “Investors” section at www.summitmidstream.com.
Compensation Committee. Mr. Cleary, Mr. Jacobe, and Mr. Wohleber serve as the members of the Compensation Committee, with Mr. Wohleber serving as chair of the committee. The Compensation Committee provides oversight, administers and makes decisions regarding the Partnership’s executive compensation policies and incentive plans. The Compensation Committee has adopted a Compensation Committee charter, which is publicly available on its website under the “Corporate Governance” subsection of the “Investors” section at www.summitmidstream.com.
Corporate Governance and Nominating Committee. Mr. Cleary, Mr. Peters, and Ms. Woung-Chapman serve as the members of the Corporate Governance and Nominating Committee, with Ms. Woung-Chapman serving as the chair of the Corporate Governance and Nominating Committee, which was established by the Board of Directors on May 28,2020. The Corporate Governance and Nominating Committee identifies individuals qualified to become board members consistent with criteria approved by the Board of Directors, assists the Board of Directors in selection of directors nominees; oversees corporate governance principles, and oversees the evaluation of the Board of Directors and management. The Corporate Governance and Nominating Committee has adopted a Corporate Governance and Nominating Committee charter, which is publicly available on its website under the “Corporate Governance” subsection of the “Investors” section at www.summitmidstream.com.
Directors and Executive Officers
Directors of the General Partner are appointed for a term of three years and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. In connection with the GP Buy-In Transaction, the Partnership amended its Partnership Agreement to, among other things, provide its common unitholders with voting rights in the election of the members of the Board on a staggered basis beginning in 2022. Officers serve at the discretion of the Board of Directors.
The following table shows information for the directors and executive officers of the General Partner as of February 25, 2021.
Heath Deneke has been President and Chief Executive Officer and a director of the General Partner since September 2019. Prior to joining the General Partner, Mr. Deneke served as Executive Vice President, Chief Operating Officer for Crestwood Equity Partners LP and Crestwood Midstream Partners LP from August 2017 through April 2019. Previously, Mr. Deneke was the President, Chief Operating Officer of Crestwood’s Pipeline Services Group from June 2015 to August 2017, where he was responsible for the commercial development and operations of Crestwood’s midstream businesses, including assets in the Marcellus, Bakken, PRB Niobrara, Delaware, Permian, Barnett, Granite Wash, Fayetteville and Haynesville shale plays. Prior to that, he served as President of Crestwood’s Natural Gas Business Unit from October 2013 to June 2015 and as Senior Vice President and Chief Commercial Officer of Crestwood’s legacy business from August 2012 until October 2013. Prior to joining Crestwood, Mr. Deneke served in various management positions at El Paso Corporation and its affiliates, including Vice President of Project Development and Engineering for the Pipeline Group, Director of Marketing and Asset Optimization for Tennessee Gas Pipeline Company, LLC and Manager of Business Development and Strategy for Southern Natural Gas Company, LLC. Mr. Deneke holds a bachelor’s degree in Mechanical Engineering from Auburn University.
Marc D. Stratton has been the Executive Vice President and Chief Financial Officer of the General Partner since December 2018. Mr. Stratton joined Summit Investments as a founding member in 2009 and has held various senior management roles at the General Partner including, Senior Vice President of Finance, Treasurer and Head of Investor Relations. Prior to joining the General Partner, Mr. Stratton served as a midstream infrastructure investment analyst at ING Investment Management and, prior
to that, as Vice President of Project Finance at SunTrust Robinson Humphrey. Mr. Stratton has over 18 years of oil and gas industry experience in corporate finance and holds a bachelor’s degree in Economics from Denison University.
James Johnston has been the Executive Vice President, General Counsel and Chief Compliance Officer of the General Partner since September 2020. Prior to joining the General Partner, Mr. Johnston worked in the corporate legal department for Crestwood Equity Partners as Senior Vice President and General Counsel, after serving as Vice President, Deputy General Counsel at Crestwood. Prior to joining Crestwood in 2013, Mr. Johnston served as Assistant General Counsel for Kinder Morgan and in various legal and commercial roles of increasing responsibility at Kinder Morgan, El Paso Corporation and Sonat, Inc. from 1997 to 2013. Mr. Johnston holds a bachelor's degree from Western University in Ontario, Canada and a Doctor of Jurisprudence from Samford University's Cumberland School of Law in Birmingham, Alabama.
James J. Cleary has served as a director of the General Partner since June 2020. Mr. Cleary serves on the Compensation Committee and the Corporate Governance and Nominating Committee of the General Partner. Mr. Cleary has served as a Managing Director of Global Infrastructure Partners, a leading private equity infrastructure fund with over $60 billion under management and a focus on the energy, transport and water/waste industries since 2012. Prior to that, from 1999 until its acquisition by Kinder Morgan in 2012, Mr. Cleary served in various leadership roles for El Paso Corporation, a Fortune 500 energy company, including service as the President of Western Pipelines and President of the ANR Pipeline Company. From 1979 until 1999, Mr. Cleary served in various capacities of increasing responsibility with Sonat Inc., a Fortune 500 energy company, including service as the Executive Vice President & General Counsel of Southern Natural Gas Company, which was Sonat’s pipeline business. In addition to his experience as an executive, Mr. Cleary has had significant experience in the boardroom, having served on the board of the general partner of Access Midstream Partners, L.P., a large midstream master limited partnership, and he currently serves on the board of directors of Gibson Energy, Inc., a Canadian public company that transports, stores, processes and markets crude oil and refined products in Canada and the United States. He has a B.A. in Sociology from the College of William & Mary and a J.D. from Boston College Law School.
Lee Jacobe has served as a director of the General Partner since April 2019. Additionally, Mr. Jacobe serves on the Audit Committee and the Compensation Committee of the General Partner. Mr. Jacobe currently serves as an advisor with respect to energy investments for Kelso & Company, a New York based private equity firm. From 2008 through 2018, Mr. Jacobe was involved in various capacities at Barclays Investment Banking - Energy Group, including head of the firm’s midstream coverage effort, co-head of its US Oil & Gas group, and Vice Chairman of the firm. From 1993 through 2008, Mr. Jacobe was an investment banker in the energy group at Lehman Brothers, including serving as a managing director from 2001-2008. Mr. Jacobe began his investment banking career at Wasserstein Perella & Co. in 1990. He has a B.B.A., with a major in Finance, from the University of Texas at Austin. Mr. Jacobe has valuable and extensive experience in the energy banking sector, including a vast array of experience in corporate finance, capital structure, and the evaluation of financial risks associated with publicly traded partnerships that invest in midstream infrastructure.
Robert J. McNally has served as a director of the General Partner since May 2020. Additionally, Mr. McNally serves on the Audit Committee of the General Partner. Mr. McNally also serves as a director of Oasis Petroleum, where he sits on the Audit & Reserves Committee and the Compensation Committee. From 2018 through 2019, Mr. McNally served as President and Chief Executive Officer of EQT Corporation, an NYSE-listed independent natural gas producer with operations in Pennsylvania, West Virginia and Ohio. Prior to that, from 2016 to 2018, Mr. McNally served as Senior Vice President and Chief Financial Officer of EQT Corporation. From 2010 until 2016, Mr. McNally served as Executive Vice President and Chief Financial Officer of Precision Drilling Corporation, a TSE and NYSE-listed drilling contractor with operations primarily in the United States, Canada and the Middle East. From 2009 to 2010, and for a period in 2007, Mr. McNally served as an Investment Principal for Kenda Capital LLC. In 2008, Mr. McNally served as the Chief Executive Officer of Dalbo Holdings, Inc. In 2006, Mr. McNally served as Executive Vice President of Operations and Finance for Warrior Energy Services Corp. From 2000 to 2005, Mr. McNally worked in corporate finance with Simmons & Company International. Mr. McNally began his career as an engineer with Schlumberger Limited and served in various capacities of increasing responsibility during his tenure from 1994 until 2000. In addition to his experience as an executive, Mr. McNally has had extensive experience in the boardroom, where he has served, at various times, on the boards of Warrior Energy Services, Dalbo Holdings, EQT Midstream Partners, EQT GP Holdings, Rice Midstream Partners and EQT Corporation. He has a B.S. in Mechanical Engineering from University of Illinois, a B.A. in Mathematics from Knox College, and an M.B.A. from Tulane University Freeman School of Business. Mr. McNally brings a wealth of executive management, operational, and financial experience in the oil and gas industry to the Board of Directors.
Jerry L. Peters has served as a director of the General Partner since September 2012. Additionally, Mr. Peters served as the chair of the Conflicts Committee of the General Partner until November 2012 and serves as the chair and financial expert of the Audit Committee of the General Partner. Mr. Peters served as the Chief Financial Officer of Green Plains Inc., a publicly traded vertically integrated ethanol producer, from June 2007 until his retirement in September 2017. In 2015, Mr. Peters was appointed Chief Financial Officer and Director of the General Partner of Green Plains Partners LP, a publicly traded partnership engaged in fuel storage and transportation services. He retired from his role as Chief Financial Officer of the General Partner of Green Plains Partners LP in September 2017 but remains on the Board of Directors. Prior to joining Green Plains, Mr. Peters served as Senior Vice President-Chief Accounting Officer for ONEOK Partners, L.P. from May 2006 to April 2007, as Chief Financial Officer of ONEOK Partners, L.P. from July 1994 to May 2006, and in various senior management roles of ONEOK Partners, L.P. from 1985 to May 2006. Prior to joining ONEOK Partners, Mr. Peters was employed by KPMG LLP as a certified public accountant from 1980 to 1985. In October 2017, Mr. Peters joined the board of the general partner of USA Compression Partners LP and served as chair and financial expert of the audit committee thereof. Mr. Peters resigned from the board of the general partner of USA Compression Partners LP in March 2018. Mr. Peters received an MBA from Creighton University with an emphasis in finance and a B.S. in Business Administration from the University of Nebraska-Lincoln. Mr. Peters' extensive executive, financial and operational experience bring important and necessary skills to the Board of Directors.
Robert M. Wohleber has served as a director of the General Partner since August 2013. Mr. Wohleber also serves as Chairperson of the Compensation committee of the General Partner. Mr. Wohleber served as Senior Vice President and Chief Financial Officer of Kerr-McGee Corporation, an oil and gas exploration and production company, from December 1999 to August 2006. From 1996 to 1998, he served as Senior Vice President and Chief Financial Officer of Freeport-McMoran, Inc., one of the largest phosphate fertilizer producers in the United States. He holds a B.B.A. from the University of Notre Dame and an M.B.A. from the University of Pittsburgh. Mr. Wohleber’s extensive executive and financial experience in the oil and gas industry bring important and necessary skills to the Board of Directors.
Marguerite Woung-Chapman has served as a director of the General Partner since May 2020. Ms. Woung-Chapman also serves as the Chairperson of the Corporate Governance & Nominating Committee of the General Partner. In 2018, Ms. Woung-Chapman served as Senior Vice President, General Counsel and Corporate Secretary of Energy XXI Gulf Coast, Inc., a NASDAQ-listed independent exploration and production company that was engaged in the development, exploitation and acquisition of oil and natural gas properties in the U.S. Gulf Coast region. Prior to that, from 2012 to 2017, Ms. Woung-Chapman served in various capacities at EP Energy Corporation, a private company that subsequently became an NYSE-listed independent oil and gas exploration and production company, including, among others, Senior Vice President, Land Administration, General Counsel and Corporate Secretary. Ms. Woung-Chapman began her career as a corporate attorney with El Paso Corporation (including its predecessors) and served in various capacities of increasing responsibility during her tenure from 1991 until 2012, including, among others, Vice President, Legal Shared Services, Corporate Secretary and Chief Governance Officer. She has a B.S. in Linguistics from Georgetown University and a J.D. from the Georgetown University Law Center. Ms. Woung-Chapman also serves, since June 2020, as the Chair of the Board of Directors and President of the Girl Scouts of San Jacinto Council, which is the second largest Girl Scout council in the country. Ms. Woung-Chapman has valuable and extensive experience in all aspects of management and strategic direction of publicly-traded energy companies and brings a unique combination of corporate governance, regulatory, compliance, legal and business administration experience to the Board of Directors.
Code of Business Conduct and Ethics
The Board of Directors has adopted a Code of Business Conduct and Ethics which sets forth the Partnership’s policy with respect to business ethics and conflicts of interest. The Code of Business Conduct and Ethics is intended to ensure that the employees, officers and directors of the Partnership and its General Partner conduct business with the highest standards of integrity and in compliance with all applicable laws and regulations. It applies to the employees, officers and directors of the Partnership and its General Partner, including the principal executive officer, principal financial officer and principal accounting officer or controller, or persons performing similar functions (the “Senior Financial Officers”). The Code of Business Conduct and Ethics also incorporates expectations of the Senior Financial Officers that enable the Partnership to provide accurate and timely disclosure in its filings with the SEC and other public communications. The Code of Business Conduct and Ethics is publicly available on the Partnership’s website under the “Corporate Governance” subsection of the “Investors” section at www.summitmidstream.com and is also available free of charge on written request to the Secretary at the Houston office address given under the "Contact" section on the Partnership’s website.
Corporate Governance Guidelines
The Partnership’s Corporate Governance Guidelines, which are available on its website under the “Corporate Governance” subsection of the “Investors” section at www.summitmidstream.com, provide guidelines for the governance of the Partnership. The Corporate Governance Guidelines specifically provide, among other things, that (i) the independent members of the Board will select an independent director to serve as “Lead Director” to preside over any executive sessions at which the Chairman of the Board is not present, and (ii) interested parties may communicate directly with the General Partner’s independent directors by submitting an envelope marked “Confidential” addressed to the “Independent Members of the Board” in care of the Secretary of the General Partner.
Delinquent Section 16(a) Reports
Section 16(a) of the Exchange Act requires SMLP’s directors and executive officers, and persons who own more than 10% of a registered class of the Partnership’s securities, to file with the SEC initial reports of ownership and reports of changes in ownership of SMLP's common units and other equity securities. Based on the Partnership’s records, it believes that all directors, executive officers and persons who own more than 10% of the Partnership’s common units have complied with the reporting requirements of Section 16(a) except for the following. On February 7, 2020, Energy Capital Partners II, LLC and Summit Midstream Partners, LLC filed delinquent Section 16(a) reports relating to the second amendment to that certain Contribution Agreement between SMP Holdings and the Partnership dated February 25, 2016, as amended, pursuant to which the Partnership issued 714,286 common units (as adjusted for the Reverse Unit Split) to SMP Holdings on November 15, 2019.
Item 11.
Item 11. Executive Compensation.
This Compensation Discussion and Analysis (“CD&A”) provides information regarding the compensation of certain of our executive officers as reported in the Summary Compensation Table and other tables in this document. In this CD&A, we review the compensation decisions, and rationale for those decisions, relating to the person who served as our principal executive officer during the past fiscal year, the person who served as our principal financial officer during the past fiscal year, and the Partnership’s next most highly compensated executive officer. (1)
The following describes the material components of the Partnership’s executive compensation program for the following individuals, who are referred to as the “Named Executive Officers” or “NEOs”:
•
Heath Deneke, President and Chief Executive Officer
•
Marc D. Stratton, Executive Vice President and Chief Financial Officer
•
James Johnston, Executive Vice President, General Counsel and Chief Compliance Officer(2)
•
Leonard W. Mallett, Former Executive Vice President and Chief Operations Officer(3)
•
Louise E. Matthews, Former Executive Vice President and Chief Administration Officer(4)
(1) Mr. Deneke, Mr. Stratton, and Mr. Johnston are the only executive officers of the General Partner.
(2) Mr. Johnston was appointed Executive Vice President, General Counsel and Chief Compliance Officer effective September 4, 2020.
(3) Mr. Mallett’s employment terminated effective October 31, 2020.
(4) Ms. Matthews’ employment terminated effective April 1, 2020.
The NEOs are employees of Summit Operating Services Company, LLC (“Summit Operating”), a wholly owned subsidiary of the Partnership, and executive officers of the General Partner. Prior to the GP Buy-In Transaction, certain of the NEOs split their working time between SMLP's business and their responsibilities for its then affiliate relationships. See Note 1 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the GP Buy-In Transaction and the presentation of Partnership’s financial statements for periods prior to the GP Buy-In Transaction. All compensation amounts for the NEOs are reflected in the Partnership’s financial statements included in this Annual Report.
The Compensation Committee provides oversight, administers and makes decisions regarding the Partnership’s compensation policies and plans.
Compensation Philosophy and Objectives
We seek to provide reasonable and competitive rewards to executives through compensation and benefit programs structured to:
Attract and retain outstanding talent
•
Drive achievement of short-term and long-term goals
•
Reward successful execution of objectives
•
Reinforce our culture and leadership competencies
•
Align executives with the interests of the our unitholders
We employ a pay-for-performance philosophy when designing executive compensation opportunities. Thus, a portion of an executive’s target compensation is performance based through linkage to the achievement of financial and other measures deemed to be drivers in the creation of unitholder value. While the Compensation Committee does not set a specific target allocation among the elements of total direct compensation, a portion of the compensation opportunity available to each of our NEOs is, by design, tied to the Partnership’s annual and long-term performance.
Compensation of Named Executive Officers
The Compensation Committee establishes the target total direct compensation of our executives and administers other benefit programs. The Compensation Committee engages an independent compensation consultant (the “Compensation Consultant”) who provides the Compensation Committee with data, analysis and advice on the structure and level of executive compensation. The Compensation Consultant participates in Compensation Committee meetings and executive sessions of the Compensation Committee meetings as requested. The Compensation Consultant may work with our management on various matters for which
the Compensation Committee is responsible. However, the Compensation Committee, not management, directs the activities of the Compensation Consultant. We consider the Compensation Consultant to be independent of the Partnership according to current NYSE listing requirements and SEC guidance. Willis Towers Watson serves as the Compensation Consultant.
Partnership management, in consultation with the Compensation Committee chair and the Compensation Consultant, prepares materials for the Compensation Committee relevant to matters under consideration by the Compensation Committee, including market data provided by the Compensation Consultant and recommendations of our Chief Executive Officer (the "CEO") regarding compensation of the other executives. The Compensation Committee works directly with the Compensation Consultant to determine the compensation of our CEO, as required.
Based on market data which the we use as a reference, we believe compensation for our NEOs is reasonably competitive with opportunities available to officers holding similar positions at comparable midstream companies. We seek to set compensation levels for each component of total direct compensation based on our assessment of market practices at or near the median. The Compensation Committee adjusts target compensation for each NEO above or below the median, taking into consideration experience, performance, internal equity and other relevant circumstances.
During the Compensation Committee’s annual review of executive compensation, the Compensation Consultant provided the Compensation Committee with an analysis of positions comparable to the NEOs at peer companies. To develop these exhibits, information from peer company public filings was compiled, including public company proxy statements and annual reports on Form 10-K. The peer group used for 2020 executive compensation consisted of publicly traded midstream companies with whom we compete for executive talent.
The peer group comprised the following companies:
The compensation analysis encompassed the primary components of total direct compensation, including annual base salary, annual short-term incentive and long-term incentive awards for the NEOs of these peer group companies. The Compensation Committee considered the information provided to ascertain whether the compensation of our NEOs is aligned with the its compensation philosophy and competitive with the compensation for executive officers of the peer group companies. The Compensation Committee reviewed the compensation analysis to confirm our compensation programs were supporting a competitive total compensation approach that emphasizes incentive-based compensation and appropriately rewards achievement of our objectives. For 2020, the target total direct compensation for the NEOs as set by the Compensation Committee is summarized below. Each element is further discussed in this CD&A.
Components of Executive Compensation
(1)
James Johnston was appointed Executive Vice President, General Counsel and Chief Compliance Officer effective September 4, 2020; his target total direct compensation was approved by the Compensation Committee. Although Mr. Johnston's target annual bonus set forth in his employment agreement is 100% of his base salary, his employment agreement further provides that his 2020 bonus shall be prorated for the period of time he actually served as Executive Vice President, General Counsel and Chief Compliance Officer.
(2)
Mr. Mallett’s employment terminated effective October 31, 2020.
(3)
Ms. Matthews’ employment terminated effective April 1, 2020.
The primary elements of compensation for the NEOs are base salary, annual incentive compensation and long-term equity-based compensation awards. The NEOs also receive certain retirement, health and welfare and additional benefits.
Base Salary. The base salaries for our NEOs are reviewed annually by the Compensation Committee. Base salaries our NEOs have generally been set at levels deemed necessary to attract and retain individuals with superior talent.
The base salaries of our NEOs are set forth in the following table:
(1)
James Johnston was appointed Executive Vice President, General Counsel and Chief Compliance Officer effective September 4, 2020.
(2)
Mr. Mallett’s employment terminated effective October 31, 2020.
(3)
Ms. Matthews’ employment terminated effective April 1, 2020.
Annual Incentive Compensation. We provide an annual incentive bonus (“annual bonus”) to drive the achievement of key business results and to recognize NEOs based on their contributions to those results. The annual bonus plan is a cash-based incentive plan. Incentive amounts are intended to provide total cash compensation near the market range for executive officers in comparable positions when target performance is achieved. Annual bonus compensation levels are set above or below the market range to reflect actual performance results as appropriate when performance is greater or less than expectations. Annual bonus payouts may range from 0% to 200% of the target opportunity and may be adjusted at the discretion of the Compensation Committee.
In March 2020, the Compensation Committee established the 2020 annual bonus plan target opportunities as a percentage of base salary for our NEOs other than Mr. Johnston. The 2020 target for Mr. Deneke was 150%. For Messrs. Stratton and Mallett and for Ms. Matthews it was 100% of their base salaries. In August 2020, the Compensation Committee approved Mr. Johnston’s annual bonus plan target opportunity as 100% of his base salary. Although Mr. Johnston's target annual bonus set forth in his employment agreement is 100% of his base salary, his employment agreement further provides that his 2020 bonus shall be prorated for the period of time he actually served as Executive Vice President, General Counsel and Chief Compliance Officer.
(1)James Johnston was appointed Executive Vice President, General Counsel and Chief Compliance Officer effective September 4, 2020.
(2)Mr. Mallett’s employment terminated effective October 31, 2020.
(3) Ms. Matthews’ employment terminated effective April 1, 2020.
In 2020, quantitative factors, as reflected in the corporate scorecard applicable to the senior leadership team (the "SLT Scorecard") set the baseline for the annual bonuses for our NEOs, which were subject to further adjustments as explained below. The SLT Scorecard contained four factors, which are considered by the Board of Directors and management as key indicators of the successful execution of our business plan. Those factors were (i) adjusted EBITDA, (ii) distributable cash flow per unit, (iii) controllable expense metric and (iv) health, safety, environmental and regulatory goals.
The annual bonuses paid to Messrs. Deneke, Stratton and Johnston were approved by the Board and determined in accordance with their employment agreements, as further described below.
In February 2021, the Compensation Committee and the Board of Directors reviewed the SLT Scorecards for 2020 and determined the level of achievement of each key factor. We exceeded our health, safety, environmental and regulatory goals and met our (i) controllable expense metric and (ii) distributable cash flow per unit targets. We did not meet our adjusted EBITDA target. These results yielded a calculated SLT Scorecard result of 52% of target. In addition to corporate results, additional considerations are applied at the discretion of the CEO, the Compensation Committee and the Board of Directors that may affect the actual annual bonus earned. Those considerations include judgments regarding overall company performance and business events, performance of each NEO’s respective business unit, industry climate and performance, the market for executive talent, demonstrated leadership capabilities and progress on strategic initiatives. Each NEO’s bonus amount, as reflected below, is adjusted up or down in recognition of these additional considerations.
Mr. Deneke’s annual bonus payout reflects his demonstrated leadership capabilities. Mr. Deneke was awarded 75% of his target annual bonus in 2020, or $675,000.
Mr. Stratton’s annual bonus payout reflects consideration for the combined performance of the finance and accounting business units. Mr. Stratton was awarded 75% of his target annual bonus in 2020, or $262,500.
Mr. Johnston’s annual bonus payout reflects consideration for the combined performance of the legal, human resources and health, safety, environmental and regulatory units. Mr. Johnston was awarded 75% of his target annual bonus in 2020, or $87,500, prorated for the period of time he served as Executive Vice President, General Counsel and Chief Compliance Officer.
In connection with their terminations, Mr. Mallett and Ms. Matthews received prorated annual bonuses for 2020 pursuant to the terms of their employment agreements. Mr. Mallett received a prorated annual bonus of $158,333 and Ms. Matthews received a prorated annual bonus equal to $74,795.
Based on the foregoing discussion, the annual bonus awards to be paid in March 2021 to our NEOs for 2020 performance are as follows:
(1) The amounts reflected are prorated annual bonuses paid to Mr. Mallett and Ms. Matthews upon their terminations in accordance with their employment agreements. Mr. Mallett employment terminated on October 31, 2020. Ms. Matthews employment terminated on April 1, 2020.
Long-Term Equity-Based Compensation Awards. The General Partner approved the SMLP LTIP pursuant to which eligible officers (including the NEOs), employees, consultants and directors of the General Partner and its affiliates are eligible to receive awards with respect to our equity interests, thereby linking the recipients’ compensation directly to the value of our common units and enhancing our ability to attract and retain superior talent. The SMLP LTIP provides for the grant, from time to time at the discretion of the Board of Directors or Compensation Committee, of a dollar-denominated award, unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards.
The SMLP LTIP is designed to promote our interests, as well as the interests of our unitholders, by aligning the interests of our eligible employees (including the NEOs) and directors with those of common unitholders, as well as by strengthening our ability to attract, retain and motivate qualified individuals to serve as directors and employees.
SMLP LTIP award guidelines for NEOs are designed to attract, retain and motivate the NEOs and were determined using the Compensation Consultant's analysis for individuals in comparable positions and an analysis of the scope of their roles and duties. These guidelines set an annual equity award target in the amount of 275% of salary for Mr. Deneke; 165% for Messrs. Stratton, Johnston and Mallett; 150% of base salary for Ms. Matthews.
Although LTIP is usually granted once per fiscal year (during the quarterly period ended March 31st), in 2020 there were two separate equity grants, described below:
March 2020 Equity Grants. Effective March 20, 2020, based on the recommendation of the Compensation Committee, the Board of Directors approved a grant of phantom units and cash award to Messrs. Deneke, Stratton, and Mallet. The underlying phantom units and cash award vest ratably over a three-year period. Holders of phantom units are entitled to distribution equivalent rights for each phantom unit, if applicable, providing for a lump sum payment equal to any accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. The Compensation Committee selected equity awards that vest contingent on continued service to foster increased unit ownership by the NEOs and as a retention incentive for continued employment with the Partnership.
September 11, 2020 Equity Grant to Mr. Johnston. As an inducement to accept the position of Executive Vice President, General Counsel and Chief Compliance Officer of the General Partner, on September 11, 2020, Mr. Johnston received a one-time grant of phantom units and cash award valued at approximately $1,155,000, pursuant to a standalone phantom unit award agreement (the "Award Agreement"). Subject to the terms and conditions of the Award Agreement, the underlying phantom units will vest ratably over a two-year period, and are entitled to distribution equivalent rights for each phantom unit, if applicable, providing for a lump sum payment equal to any accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date.
All SMLP LTIP grants to our NEOs are subject to accelerated vesting on the occurrence of any of the following events: (i) a termination of the NEO's employment other than for cause, (ii) a termination of the NEO's employment by the NEO for good reason (as defined in the NEO's employment agreement), (iii) a termination of the NEO's employment by reason of the NEO's death or disability or (iv) a Change in Control (as defined in the applicable award agreement).
To calculate the number of phantom units granted to each eligible NEO in March 2020, the Compensation Committee determined the dollar amount of the long-term incentive compensation award, and then granted the number of phantom units that had a fair market value equal to that amount as of market close on the date of the grant. The same calculation was performed with respect to the September 4, 2020 grant to Mr. Johnston. Phantom unit and Cash awards granted in 2020 were as follows:
(1) Although Mr. Johnston’s employment agreement provides for a target LTIP award valued at 165% of his base salary, in 2020 the value of his initial one-time grant of phantom units and cash award was approved by the Compensation Committee.
(2) Ms. Matthews employment terminated effective April 1, 2020. Ms. Mathews received no grants of phantom unit awards in 2020.
Retirement, Health and Welfare and Additional Benefits. The NEOs are eligible to participate in such employee benefit plans and programs we offer to our employees, subject to the terms and eligibility requirements of those plans.
401(k) Plan. The NEOs are eligible to participate in a tax qualified 401(k) defined contribution plan to the same extent as all of our other employees. In 2020, we made a fully vested matching contribution on behalf of each of the 401(k) plan's participants up to 5% of such participant's eligible salary for the year.
Health Savings Account ("HSA") Program. The NEOs are eligible to participate in a tax qualified health savings account (“HSA”) if they are enrolled in the available high-deductible health plan. The HSA is a tax-free savings account owned by an individual and can be used to pay for current or future qualified medical expenses. Participants determine how much to contribute, when and how to spend the money on eligible medical expenses, and how to invest the balance. The balance remains in the account and is not subject to forfeiture. The Partnership makes annual contributions to all HSA-eligible employees who enroll in and contribute to an HSA. In 2020, we made tax-free HSA contributions of $600 to Mr. Deneke, $600 to Mr. Stratton and $185 to Ms. Matthews.
Deferred Compensation Plan.
Effective May 28, 2020, the Deferred Compensation Plan was terminated. As a result, payment of all remaining amounts deferred thereunder was tendered to participants or their designated beneficiaries, as applicable, in a single lump sum payment.
Additional Benefits. Pursuant to the terms of their employment agreements:
•
All NEOs are entitled to reimbursement for tax preparation and advisory services expenses of up to $12,000 per year.
•
Mr. Deneke is entitled to be reimbursed up to $15,000 per year for annual international or local chapter dues associated with his membership in the Young Presidents Organization (“YPO”).
Expenditures for these benefits are included as “All Other Compensation” in the Summary Compensation Table and further described in the table entitled “All Other Compensation” below.
Employment and Severance Arrangements.
Employment Agreements. Our NEOs each have employment agreements with Summit Operating. Elements of the NEOs’ total direct compensation are subject to periodic review and may be adjusted accordingly by the Compensation Committee.
Mr. Deneke’s employment agreement, which has an effective date of September 1, 2020, has an initial term that expires on September 1, 2022, and is then automatically extended for successive one-year periods, unless either party gives notice of non-extension to the other no later than 30 days prior to the expiration of the then-applicable term. Mr. Deneke’s employment agreement provides for an annual base salary of $600,000, and a performance-based bonus ranging from 0% to 300% of base salary, with a target of 150% of base salary. Mr. Deneke is entitled to receive a prorated annual bonus (based on target) if his employment is terminated by Mr. Deneke with good reason, or by us without cause or as a result of a non-extension of the term, or due to death or disability. In addition, Mr. Deneke’s employment agreement also provides for reimbursement of certain business expenses incurred in connection with his employment, including company-paid tax preparation and advisory services of up to $12,000 per year and YPO membership dues of up to $15,000 per year.
Mr. Deneke’s employment agreement provides for a cash severance payment upon a termination resulting from a non-extension of the term by us, or a termination by us without cause or by Mr. Deneke for good reason, which is defined generally as the officer's termination of employment within two years after the occurrence of (i) a material diminution in Mr. Deneke’s authority, duties or responsibilities, (ii) a material diminution in the aggregated total of Mr. Deneke’s base salary, target bonus (as a percentage of base salary) or Annual LTIP Target (as that term is defined in the agreement), (iii) a material change in the geographic location at which Mr. Deneke must perform his services under the agreement, (iv) a change in Mr. Deneke’s reporting relationship resulting in Mr. Deneke no longer reporting directly to the Board of Directors, or (v) any other action or inaction that constitutes a material breach of the employment agreement by us (each a "Qualifying Termination"). In the event of a Qualifying Termination, Mr. Deneke’s severance payment will be equal to two and one-half times the sum of his annual base salary and the higher of his target annual bonus payable in respect of the immediately preceding year and the annual bonus actually paid to him in respect of that year.
Following any termination of employment other than one resulting from non-extension of the term, his employment agreement provides that Mr. Deneke will be subject to a post-termination non-competition covenant through the severance period, and, following any termination of employment, Mr. Deneke will be subject to a one-year post-termination non-solicitation covenant. If Mr. Deneke’s employment terminates as a result of a non-extension of the term, we may choose to subject him to a non-competition covenant for up to one year post-termination. If we exercise this “noncompete option” following a non-extension of term by Mr. Deneke, then Mr. Deneke would be entitled to a severance payment in an amount equal to two and one-half times the sum of his annual base salary and the higher of his target annual bonus payable in respect of the immediately preceding year and the annual bonus actually paid to him in respect of that year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by us) and the denominator of which is 365. In this case, the severance payment will be payable in equal installments over the restricted period. Following any termination of employment, we have agreed to pay the out-of-pocket premium cost to continue Mr. Deneke’s medical and dental coverage for a period not to exceed 18 months, with such coverage terminating if any new employer provides benefits coverage.
Mr. Deneke’s employment agreement also provides that all equity awards granted to him under the SMLP LTIP and held by him as of immediately prior to a change in control of the Partnership or the General Partner will become fully vested immediately prior to the change in control.
Additionally, as an inducement to accept the position as our President and Chief Executive Officer of the General Partner, at the beginning of his employment term, Mr. Deneke received a one-time grant of phantom units valued at $4,000,000, pursuant to standalone phantom unit award agreement (“Deneke Award Agreement”). Subject to the terms and conditions of the Deneke Award Agreement, the underlying phantom units will vest ratably over a three-year period, and are entitled to distribution equivalent rights for each phantom unit, providing for a lump sum payment equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. Furthermore, the phantom units will be subject to accelerated vesting on the occurrence of any of the following events: (i) a termination of Mr. Deneke’s employment other than for cause, (ii)
a termination of employment by Mr. Deneke for good reason (as that term is defined in Mr. Deneke’s employment agreement), (iii) a termination of Mr. Deneke’s employment by reason of death or disability or (iv) a Change in Control (as defined in the Award Agreement).
The remaining NEOs’ employment agreements are substantially the same as Mr. Deneke’s, except for the following:
•
Each of the other NEOs is entitled to a severance payment in the event of a Qualifying Termination equal to one and one-half times the sum of his or her annual base salary and his or her annual bonus payable in respect of the immediately preceding year.
•
Each of the other NEOs is entitled to a severance payment in the event the we exercise the “noncompete option” following a non-extension of the term by the NEO equal to the sum of 1.5 times his annual base salary and the higher of his target annual bonus and the annual bonus paid to him in respect of the immediately preceding year.
•
Each of the other NEOs is entitled to a performance-based bonus ranging from 0% to 200% of base salary, with a target of 100% of base salary.
•
The other NEOs are not entitled to be reimbursed for membership dues.
•
Mr. Stratton’s base salary is $350,000, and the initial term of his employment agreement ends on September 1, 2022.
•
Mr. Johnston’s base salary is $350,000, and the initial term of his employment agreement ends on September 4, 2022.
Retention Bonus Agreements.
Effective June 7, 2019, and prior to the GP Buy-In Transaction, Summit Investments, the General Partner, and SMLP jointly entered into retention bonus agreements with certain NEOs for the amounts indicated below:
Mr. Mallett:$420,000
Mr. Stratton:$365,000
Ms. Matthews:$365,000
The agreements provided for a cash payment “Retention Bonus” upon the earlier of a termination without cause or a change in control (as those terms are defined in the executive’s employment agreement). The agreements terminated if the executive officer continued to be employed and a change in control had not occurred on or prior to December 31, 2020.
Mr. Mallett’s employment terminated effective October 31, 2020. According to the terms of his retention bonus agreement, Mr. Mallett received payment of $420,000 upon his termination. Ms. Matthews’ employment terminated effective April 1, 2020. According to the terms of her retention bonus agreement, Ms. Matthews’ received payment of $365,000 upon her termination.
Risk Assessment Relative to Compensation Programs. The Compensation Committee manages risk as it relates to our compensation plans, programs, and structure (collectively, our “Compensation Practices”). The Compensation Committee meets with management to review whether any aspect of our Compensation Practices creates incentives for our employees to take inappropriate risks that could materially adversely affect the Partnership. Accordingly, we believe that the compensation practices for our NEOs and other employees are appropriately structured and do not pose a material risk to the Partnership. We believe these compensation practices are designed and implemented in a manner that does not promote excessive risk-taking that could damage the value of the Partnership or provide compensatory rewards for inappropriate decisions or behavior.
Compensation Committee Report. The Compensation Committee has reviewed and discussed this CD&A with the our management and, based on such review and discussion, has recommended to the Board of Directors that the CD&A be included in the Annual Report.
Summary Compensation Table for 2020, 2019 and 2018
The following table sets forth certain information with respect to the compensation paid to our NEOs for the years ended December 31, 2020, 2019 and 2018.
(1)
Amounts shown represent the portion of the NEO’s base salary and bonus allocated to the Partnership. Prior to closing the GP Buy-In Transaction in May 2020, compensation amounts for the NEO were allocated between the General Partner and SMLP. As a result of the GP Buy-In Transaction, the Partnership now pays for 100% of the NEO’s compensation. For a discussion of the cost allocation methodology, please refer to “Agreements with Affiliates-Reimbursement of Expenses from General Partner” in Item 13. Certain Relationships and Related Transactions, and Director Independence.
(2)
Amounts shown reflect the grant date fair value of the phantom unit awards granted to the NEOs in 2020, 2019 and 2018, respectively, in accordance with FASB Accounting Standards Codification Topic 718, Compensation-Stock Compensation ("FASB ASC Topic 718"). For the assumptions made in valuing these awards, see Note 16 to the consolidated financial statements. For additional information, please refer to "Components of Executive Compensation-Long-Term Equity-Based Compensation Awards" above.
(3)
Amounts shown represent the incentive bonus earned under the Partnership’s annual incentive bonus program in the fiscal year indicated but paid in the following fiscal year. The amounts shown represent that portion of the NEO's annual bonus that has been allocated to SMLP. Prior to closing the GP Buy-In Transaction in May 2020, compensation amounts for the NEO were allocated between the General Partner and SMLP. As a result of the GP Buy-In Transaction, the Partnership now pays for 100% of the NEO’s compensation. For a discussion of the cost allocation methodology, please refer to “Agreements with Affiliates-Reimbursement of Expenses from General Partner” in Item 13. Certain Relationships and Related Transactions, and Director Independence
(4)
The table below presents the components of "All Other Compensation" allocated to SMLP for each NEO for the fiscal year ended December 31, 2020. For additional information, please see "Components of Executive Compensation-Retirement, Health and Welfare and Additional Benefits" above. Prior to closing the GP Buy-In Transaction in May 2020, compensation amounts for the NEO were allocated between the General Partner and SMLP. As a result of the GP Buy-In Transaction, the Partnership now pays for 100% of the NEO’s compensation. For a discussion of the cost allocation methodology, please refer to “Agreements with Affiliates-Reimbursement of Expenses from General Partner” in Item 13. Certain Relationships and Related Transactions, and Director Independence
(5)
Mr. Johnston began his employment with the Partnership effective September 4, 2020.
(6)
Mr. Mallett’s employment terminated on October 31, 2020. The portion of the severance payment made to Mr. Mallett in 2020 is included in the “All Other Compensation” column.
(7)
Ms. Matthews’ employment terminated on April 1, 2020. The severance payment made to Ms. Mathews in 2020 is included in the “All Other Compensation” column.
Pay Ratio Disclosure
The following is a reasonable estimate, prepared under applicable SEC rules, of the ratio of the annual total compensation of our CEO to the median of the annual total compensation of our other employees. Although we previously identified our median employee on December 31, 2019, due to a change in our employee population that we reasonably believe will result in a significant change to our pay ratio disclosure, we identified a new median employee in 2020. For 2020, we determined or median employee by ranking our employees (other than the CEO) employed as of December 31, 2020 (the “determination date”) by the sum of each employee’s annualized base salary, his or her actual cash bonus received in 2020 for 2019 performance, and his or her actual overtime pay received in 2020. In annualizing each employee’s base salary, we used each employee’s base salary rate as of the determination date. We made no full-time equivalent adjustment for any employee, we had no temporary or seasonal workers as of the determination date, and we made no cost-of-living adjustments. The annual total compensation our median
employee (other than the CEO) for 2020 was $120,592. To determine the annual total compensation of our CEO for purposes of this disclosure, we chose the person who was serving as CEO as of the determination date and used the total compensation he received in 2020 as set forth in the Summary Compensation Table above. Accordingly, for purposes of this disclosure, we determined that the CEO’s annual total compensation for 2020 was $2,510,333. Based on the foregoing, we estimate of the ratio of the annual total compensation of our CEO to the median of the annual total compensation of all other employees was 20.8 to 1. Given the different methodologies that various public companies will use to determine an estimated pay ratio, our estimated pay ratio should not be used as a basis for comparison with ratios disclosed by other companies.
All Other Compensation. The following table sets forth information concerning all other compensation paid to our NEOs in 2020.
(1) Amounts shown represent the portion of the NEO’s base salary and bonus allocated to the Partnership. Prior to closing the GP Buy-In Transaction in May 2020, compensation amounts for the NEO were allocated between the General Partner and SMLP. As a result of the GP Buy-In Transaction, the Partnership now pays for 100% of the NEO’s compensation. For a discussion of the cost allocation methodology, please refer to “Agreements with Affiliates-Reimbursement of Expenses from General Partner” in Item 13. Certain Relationships and Related Transactions, and Director Independence.
Grants of Plan-Based Awards in 2020. The following table sets forth information concerning annual incentive awards and phantom unit awards granted to the Partnership’s NEOs in fiscal year 2020.
(1)
Represents annual incentive opportunities that may be awarded pursuant to the Partnership’s annual incentive program for the year ended December 31, 2020 with payment based upon the Partnership’s achievement of pre-established performance goals and other factors. For additional information, please see "Components of Executive Compensation-Annual Incentive Compensation" above.
(2)
Represents grants of phantom units with distribution equivalent rights under the SMLP LTIP. For additional information, please see "Components of Executive Compensation-Long-Term Equity-Based Compensation Awards" above.
(3)
Amounts shown represent the fair value of the award on the date of the grant, in accordance with FASB ASC Topic 718. For the assumptions made in valuing these awards, see Note 13 to the consolidated financial statements.
(4)
Amount shown represent the dollar-denominated cash amount of the LTIP grant award.
(5)
Ms. Matthews’ employment terminated on April 1, 2020. Ms. Mathews received no grants of phantom unit awards in 2020.
Narrative Disclosure to the Summary Compensation Table and Grants of the Plan-Based Awards Table. A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, non-equity incentive plan compensation and all other compensation can be found in the CD&A that precedes these tables.
Outstanding Equity Awards at December 31, 2020. The following table presents information regarding the outstanding equity awards held by the Partnership’s NEOs at December 31, 2020.
(1)
Ms. Mathews is omitted from this table because her outstanding equity awards vested upon her termination effective April 1, 2020. Mr. Mallet is omitted from this table because his outstanding equity awards vested upon his termination effective October 31, 2020.
(2)
Except in the case of Mr. Johnston, as noted below, phantom units granted to the NEOs vest ratably over a three-year period with the first tranche scheduled to vest on the first anniversary of the grant date, subject to continued employment, and accelerated vesting as provided in the applicable award agreement. The NEOs also receive distribution equivalent rights for each phantom unit, if applicable, providing for a lump sum payment equal to any accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date.
(3)
Amounts were calculated using the closing price of SMLP's publicly traded common units on December 31, 2020.
(4)
Amounts shown represent the dollar-denominated cash amount of the SMLP LTIP grant award.
(5)
Phantom units granted on November 15, 2019, vest in their entirety on the third anniversary of the grant date.
(6)
One half of the phantom units and cash awards granted on September 11, 2020 vest on March 31, 2021 and the other half vests on March 31, 2022
Phantom Units and Cash Awards Vested. The following table represents information regarding the vesting of phantom units during the year ended December 31, 2020 with respect to the Partnership’s NEOs.
(1)
Mr. Deneke’s amounts represent the number and value of the phantom units that vested on September 16, 2020, plus the distribution equivalent rights earned in tandem. The value of the phantom units that vested was calculated using the closing price of SMLP’s publicly traded common units as of September 15, 2020, the trading day immediately prior to vesting.
(2)
Mr. Stratton amounts represent the number and value of the phantom units that vested on March 16, 2020, plus the distribution equivalent rights earned in tandem. The value of the phantom units that vested was calculated using the closing price of SMLP’s publicly traded common units as of March 13, 2020, the trading day prior to vesting.
(3)
Mr. Mallett’s amounts represent the number and value of the phantom units that vested on March 16, 2020 plus the distribution equivalent rights earned in tandem. The value of the phantom units that vested on March 16, 2020 was calculated using the closing price of SMLP’s publicly traded common units as of March 13, 2020, the trading day prior to vesting. In addition, the amount includes amounts for the phantom units and cash awards
that vested upon his termination effective October 31, 2020, plus the distribution equivalent rights earned in tandem. The value of Mr. Mallett’s phantom units that vested on October 31, 2020 was calculated using the closing price of SMLP’s units as of October 30, 2020, the trading day immediately prior to vesting.
(4)
Ms. Mathews' amounts represent the number and value of the phantom units that vested on March 16, 2020 and upon her termination effective April 1, 2020, plus the distribution equivalent rights earned in tandem. The value of the phantom units that vested on March 16, 2020 was calculated using the closing price of SMLP's publicly traded common units as of March 13, 2020, the trading day prior to vesting. The value of Ms. Matthews' phantom units that vested on April 1, 2020 was calculated using the closing price of SMLP’s units as of March 31, 2020, the trading day immediately prior to vesting.
Pension Benefits. Currently, the Partnership does not sponsor or maintain a pension or defined benefit program for its NEOs. This policy may change in the future.
Nonqualified Deferred Compensation Table for 2020. Effective May 28, 2020, the Deferred Compensation was terminated resulting in payment of all remaining amounts deferred thereunder to participants or their designated beneficiaries, as applicable, in a single lump sum payment.
Potential Payments upon Termination or Change in Control. The following table sets forth information concerning potential amounts payable to the NEOs upon termination of employment under various circumstances, and upon a change in control, if such event took place on December 31, 2020.
(1)
Where applicable, the amount includes the “Retention Bonus” payable to Mr. Mallett and Ms. Matthews upon a termination without cause or change in control. For more information see “Employment and Severance Arrangements; Retention Bonus Agreements” above.
(2)
Amounts represent the value of the phantom units that vest upon the occurrence of a triggering event plus the earned distribution equivalent rights that vest in tandem. The value of the phantom units was calculated using the closing price of SMLP's publicly traded common units on December 31, 2020.
(3)
Mr. Deneke’s employment agreement provides that upon termination of employment resulting from a non-extension of the term, termination without cause, or by Mr. Deneke’s resignation for good reason (each a "Qualifying Termination"), Mr. Deneke’s severance payment will be equal to two and one-half times the sum of his annual base salary and the higher of his target annual bonus payable in respect of the immediately preceding year and the annual bonus actually paid to him in respect of that year. Mr. Deneke is also entitled to receive a prorated annual bonus (based on target) if his employment is terminated by reason of death or disability or as a result of a Qualifying Termination. If the Partnership exercises the “noncompete option” after Mr. Deneke elects not to extend the term, then Mr. Deneke is entitled to a severance payment in an amount equal to the two and one-half times the sum of his annual base salary and the higher of the target annual bonus payable or the bonus actually paid in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by the Partnership) and the denominator of which is 365. Any unvested equity awards granted to Mr. Deneke will immediately vest upon a Qualifying Termination, termination by reason of death or disability, or a change in control. If any portion of the payments or benefits provided to Mr. Deneke in connection with a change in control become subject to the excise tax under Section 4999 of the Internal Revenue Code, then the payments and benefits will be reduced to the extent such reduction would result in a greater after-tax benefit to Mr. Deneke. Following any termination
of employment, the Partnership has agreed to pay the out-of-pocket premium cost to continue Mr. Deneke’s medical and dental coverage for a period not to exceed 18 months, with such coverage terminating if any new employer provides benefits coverage.
(4)
Single-trigger event without a qualifying termination of employment.
(5)
Mr. Stratton’s, Mr. Johnston’s, Mr. Mallett’s, and Ms. Matthews’ employment agreements are substantially identical to Mr. Deneke’s with respect to potential payments upon termination or a change in control, except that (i) in the event of a Qualifying Termination, each of these NEOs is entitled to receive a severance payment equal to one and one-half times the sum of his or her annual base salary and his or her annual bonus payable in respect of the immediately preceding year; and (ii) in the event the Partnership exercises the “noncompete option” after any such NEO elects not to extend the term, then the NEO is entitled to a severance payment equal to the sum of his or her annual base salary and the bonus actually paid in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by the Partnership) and the denominator of which is 365.
(6)
Both Mr. Mallett and Ms. Matthews were terminated without cause in 2020. Accordingly, disclosure is limited to the triggering event that occurred. The amounts reflect actual amounts.
Compensation Committee Report
The Compensation Committee provides oversight, administers and makes decisions regarding the Partnership’s compensation policies and plans. Additionally, the Compensation Committee generally reviews and discusses the Compensation Discussion and Analysis with senior management of the Partnership as a part of the Partnership’s governance practices. Based on this review and discussion, the Compensation Committee has recommended to the Board of Directors of the General Partner that the Compensation Discussion and Analysis be included in this report for filing with the SEC.
Director Compensation
In 2020, under the director compensation plan, the independent directors, which include Messrs. Peters, Wohleber, Jacobe, McNally, Cleary and Ms. Woung-Chapman each received the following:
•
an annual cash retainer of $80,000; and
•
an annual award of common units with a grant date fair value of approximately $100,000.
•
In addition, under the director compensation plan, the independent directors receive the following for their respective service on the committees of our Board of Directors:
o
the chairman of the Audit Committee receives an additional annual retainer of $15,000; each independent member of the Audit Committee received an additional annual retainer of $7,000;
o
the chairman of the Conflicts Committee, which was dissolved in May 2020, received an additional annual retainer of $15,000;
o
the chairman of the Corporate Governance and Nominating Committee received an additional annual retainer of $10,000;
o
the chairman of the Compensation Committee receives an additional annual retainer of $12,000; and
o
each independent member of any committee (other than the chairman) receives an additional annual retainer of $5,000.
Messrs. Peters, Jacobe and Wohleber were paid their compensation in March 2020, whereas Messrs. McNally, Cleary and Ms. Woung-Chapman were paid upon the commencement of their service on the Board in June 2020.
In addition to their regular compensation described above, the independent directors received the following additional fees for the increased time and effort they expended as chairperson and members, respectively, of the Conflicts Committee, in connection with the review of the GP Buy-In transaction for fairness to the Partnership and its unitholders:
•
$25,000 to Mr. Wohleber and $20,000 to Mr. Peters and Mr. Jacobe for their work related to the GP Buy-In Transaction.
Board members are reconsidered for appointment on the one-year anniversary of their most recent appointment.
The Partnership reimburses all directors for travel and other related expenses in connection with attending board and committee meetings and board-related activities.
The following table shows the compensation paid, including amounts deferred, under the Partnership’s director compensation plan in 2020.
(1)
Amount shown represents the grant date fair value of the unit awards as determined in accordance with GAAP. These unit awards were fully vested on the grant date.
(2)
In 2020, no director elected to defer any portion of his compensation related to Board committee service.
Compensation Committee Interlocks and Insider Participation
The Partnership’s Compensation Committee consists of Mr. Jacobe, Mr. Cleary and Mr. Wohleber. Although the Partnership’s common units are listed on the NYSE, the Partnership has taken advantage of the “Limited Partnership” exemption to the NYSE rule that would otherwise require listed companies to have an independent compensation committee with a written charter. During 2020, no member of the Compensation Committee was an executive officer of another entity on whose compensation committee or board of directors any executive officer of the Partnership served. During 2019, no director was an executive officer of another entity on whose compensation committee any executive officer of Summit Investments (and in connection therewith, SMLP) served.
The Partnership’s CEO participated in his capacity as a director in the deliberations of the Board of Directors concerning named executive officer compensation and made recommendations to the Compensation Committee regarding named executive officer compensation but abstained from any decisions regarding his compensation.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The following table sets forth certain information regarding the beneficial ownership of the Partnership’s common units of:
•
each person who is known to us to beneficially own 5% or more of such units to be outstanding (based solely on Schedules 13D and 13G filed with the SEC prior to February 17, 2021);
•
the General Partner;
•
each of the directors and NEOs of the General Partner; and
•
all of the directors and executive officers of the General Partner as a group.
All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be. The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a beneficial owner of a security if that person has or shares voting power, which includes the power to vote or to direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security.
In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units that a person has the right to acquire upon the vesting of phantom units where the units are issuable within 60 days of February 17, 2021, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. The percentage of units beneficially owned is based on a total of 6,110,092 common limited partner units outstanding as of February 17, 2021. All common unit amounts reflect the Reverse Unit Split.
Except as indicated by footnote, the persons named in the following table have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
* An asterisk indicates that the person or entity owns less than one percent.
(1) Ares Management LLC (“Ares”) controls, directly or indirectly, each Ares Lender of Record, as defined in the Form 13G filed by Ares Management LLC on November 27, 2020. The number of common units beneficially owned by Ares represents the collective number of common units beneficially owned by each Ares Lender of Record, as set forth in the Form 13G filed by Ares. The address for this entity is 2000 Avenue of the Stars, 12th Floor, Los Angeles, CA 90067.
(2) The address for this entity is 1555 Peachtree Street NE, Suite 1800, Atlanta, GA 30309.
(3) The address for this person is 910 Louisiana Street, Suite 4200, Houston, TX 77002.
(4) Includes common units which the individuals have the right to acquire upon vesting of phantom units, where the units are issuable as of February 17, 2021 or within 60 days thereafter. Such units are deemed to be outstanding in calculating the percentage ownership of such individual (and all directors and officers as a group) but are not deemed to be outstanding as to any other person.
(5) This individual’s employment was terminated in 2020, and the common units beneficially owned by this individual are based on the last Form 4 filed by or on behalf of such individual.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2020 with respect to the Partnership's common units that may be issued under the SMLP LTIP, as amended.
(1) Amount shown represents phantom unit awards outstanding under the SMLP LTIP at December 31, 2020. The awards are expected to be settled in common units upon the applicable vesting date and are not subject to an exercise price.
2012 SMLP Long-Term Incentive Plan. In connection with the IPO, the Partnership’s General Partner approved the SMLP LTIP, as amended and restated on March 19, 2020, pursuant to which eligible officers, employees, consultants and directors of the Partnership’s General Partner and its affiliates are eligible to receive awards with respect to the Partnership’s equity interests. The SMLP LTIP is designed to promote the Partnership’s interests, as well as the interests of the Partnership’s unitholders, by rewarding eligible officers, employees, consultants and directors for delivering desired performance results, as well as by strengthening the Partnership’s ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees. A total of 15,000,000 common units was reserved for issuance, pursuant to and in accordance with the SMLP LTIP. Following the Reverse Unit Split, a total of 1,000,000 common units were reserved for issuance under the SMLP LTIP.
The SMLP LTIP is administered by Compensation Committee of the General Partner’s the Board of Directors. The SMLP LTIP provides for the grant, from time to time at the discretion of the Board of Directors, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Units that are canceled or forfeited are available for delivery pursuant to other awards.
Common units to be delivered with respect to awards may be newly issued units, common units acquired by the Partnership or the Partnership’s General Partner in the open market, common units already owned by the Partnership or the Partnership’s General Partner, common units acquired by the Partnership’s General Partner directly from the Partnership or any other person or any combination of the foregoing.
The General Partner's Board of Directors, at its discretion, may terminate the SMLP LTIP at any time with respect to the common units for which a grant has not previously been made. The SMLP LTIP will automatically terminate on the 10th anniversary of the amendment effective date, presently set at March 19, 2030. The General Partner's Board of Directors also has the right to alter or amend the SMLP LTIP or any part of it from time to time or to amend any outstanding award made under the SMLP LTIP, provided that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
In May 2020, the Partnership completed the GP Buy-In Transaction, whereby the Partnership acquired from its then private equity sponsor, ECP, (i) Summit Investments, which owned the Partnership’s General Partner, (ii) through its indirect ownership of SMP Holdings, 3,415,646 of its common units and (iii) the Deferred Purchase Price obligation receivable owed by the Partnership. Consideration paid to ECP included a $35.0 million cash payment and the issuance of warrants to purchase up to 666,667 common units. In connection with the closing of the GP Buy-In Transaction, ECP’s management resigned from the Board of Directors and ECP fully exited its investment in the Partnership (other than retaining the aforementioned warrants).
As a result of the GP Buy-In Transaction, the Partnership indirectly owns its General Partner, and the General Partner’s Board of Directors is comprised of a majority of independent directors. The Partnership Agreement provides the Partnership’s common unitholders with voting rights in the election of the members of the Board of Directions on a staggered basis beginning in 2022.
Distributions and Payments to the Partnership’s General Partner and its Affiliates. The following summarizes the distributions and payments made by us to the General Partner and its affiliates in connection with the Partnership’s ongoing operations and its liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.
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Operational Stage: See "Agreements with Affiliates-Reimbursement of Expenses from General Partner" below.
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Liquidation Stage: Upon the Partnership’s liquidation, the Partnership’s partners, including the General Partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
Agreements with Affiliates. The Partnership has various agreements with certain of its affiliates, as described below. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm's-length negotiations.
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Reimbursement of Expenses from General Partner: Prior to the GP Buy-In Transaction, under the then effective Partnership Agreement, SMLP reimbursed its General Partner and its affiliates for certain expenses incurred on SMLP’s behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to SMLP’s General
Partner's employees and executive officers who perform services necessary to run SMLP. The then effective Partnership Agreement provided that SMLP’s General Partner will determine in good faith the expenses that are allocable to us. Operation and maintenance expenses incurred by the General Partner and reimbursed by SMLP under then then effective Partnership Agreement were $28.6 million in 2019 and $9.0 million for the period from January 1, 2020 to May 28, 2020. General and administrative expenses incurred by the General Partner and reimbursed by SMLP under the then effective Partnership Agreement were $32.2 million in 2019 and $11.9 million for the period from January 1, 2020 to May 28, 2020. As a result of the GP Buy-In Transaction, the Partnership indirectly owns its General Partner and is no longer required to reimburses an affiliate for its expenses.
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Expense Allocations: Prior to the completion of the GP Buy-In Transaction in May 2020, certain of Summit Investments’ current and former employees received Class B membership interests, classified as net profits interests, in Summit Investments (the “Net Profits Interests”). The Net Profits Interests participated in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Net Profits Interests. The Net Profits Interests were accounted for as compensatory awards. Concurrent with closing the GP Buy-In Transaction, the Net Profits Interests were settled and are no longer outstanding.
Review, Approval and Ratification of Related-Person Transactions. The Board of Directors has a policy for the identification, review and approval of certain related person transactions. The policy provides for the review and (as appropriate) approval by the Conflicts Committee of transactions between SMLP and its subsidiaries, on the one hand, and related persons (as that term is defined in SEC rules), on the other hand. Pursuant to the policy, the General Counsel of SMLP's General Partner is charged with primary responsibility for determining whether, based on the facts and circumstances, a proposed transaction is a related person transaction.
For purposes of the policy, a "related person" is any director or executive officer of SMLP's General Partner, any nominee for director, any unitholder known to SMLP to be the beneficial owner of more than 5% of any class of the SMLP's common units, and any immediate family member, affiliate or controlled subsidiary of any such person. A "related person transaction" is generally a transaction in which SMLP is, or SMLP's General Partner or any of SMLP's subsidiaries is, a participant, where the amount involved exceeds the lesser of (i) $120,000 or (ii) 1% of the average of our total assets at year-end for the last two completed fiscal years, and a related person has a direct or indirect material interest. Transactions resolved under the conflicts provision of the Partnership Agreement are not required to be reviewed or approved under the policy.
If, after weighing all of the facts and circumstances, the general counsel of SMLP's General Partner determines that a proposed transaction is a related person transaction that requires review or approval and the transaction meets certain monetary thresholds or involves certain related persons, management must present the proposed transaction to the Conflicts Committee for advance approval. If the transaction does not meet the designated monetary threshold or involve certain related persons, management presents the transaction(s) to the Committee for their review on a quarterly basis.
The policy described above was adopted by the Board of Directors on March 7, 2013, and as a result, certain of the transactions described in "Agreements with Affiliates" above were not reviewed under such policy.
Director Independence. Each of the current members of the Audit, Compensation and Corporate Governance & Nominating Committees have been determined to be independent under the applicable NYSE listing standards and rules of the SEC and the Corporate Governance Guidelines.
Item 14.
Item 14. Principal Accounting Fees and Services.
The Partnership’s Audit Committee has ratified Deloitte & Touche LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of SMLP for the year ended December 31, 2020.
Audit Fees. The fees billed by Deloitte & Touche LLP, as principal accountant, for the audit of the Partnership’s consolidated financial statements and other services rendered for the years ended December 31, 2020 and 2019 follow.
(1) Audit fees are fees billed by Deloitte & Touche LLP for professional services for the audit and quarterly reviews of the Partnership’s consolidated financial statements, review of other SEC filings, including registration statements, and issuance of comfort letters and consents.
(2) Represents fees related to the Partnership’s At-the-market Program.
(3) Tax fees are billed by Deloitte Tax LLP for tax compliance services, including the preparation of state, federal and Schedule K-1 tax filings and other tax planning and advisory services.
Pre-approval Policy. Pursuant to its charter, the Audit Committee is responsible for the appointment, compensation, retention and oversight of SMLP's independent auditor (including resolution of disagreements between management and the independent auditor regarding financial reporting). The Audit Committee shall have sole authority to pre-approve all audit, audit-related and permitted non-audit engagements with the independent auditor, including the fees and other terms of such engagements. The independent auditor shall report directly to the Audit Committee. The Audit Committee may consult with management but may not delegate these responsibilities to management.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a)(1) Financial Statements
Our Consolidated Financial Statements and accompanying footnotes are included in Part II, Item 8, of this report.
(2) Financial Statement Schedules
All schedules are omitted because the required information is inapplicable or the information is presented in the financial statements or the notes thereto.
(3) Exhibit Index
The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this Annual Report.
* Management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 15(b) of this report
† Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the SEC.
** Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. The financial information contained in the XBRL (eXtensible Business Reporting Language)-related documents is unaudited and unreviewed.
*** Filed herewith
(c) Financial Statement Schedules
Not applicable.
Item 16. Form 10-K Summary.
Not applicable.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Summit Midstream Partners, LP
(Registrant)
By: Summit Midstream GP, LLC (its General Partner)
March 4, 2021
/s/ MARC D. STRATTON
Marc D. Stratton, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.