Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

⌧

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020

OR

◻

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to             .
Commission File Number 001-33147

---

Evolve Transition Infrastructure LP

(Exact Name of Registrant as Specified in Its Charter)

​

---

Delaware	11-3742489
(State of organization)	(I.R.S. Employer Identification No.)
​	​
1360 Post Oak Blvd, Suite 2400	​
Houston, Texas	77056
(Address of Principal Executive Offices)	(Zip Code)

(713) 783-8000

(Registrant’s Telephone Number, Including Area Code)

​

Securities registered pursuant to Section 12(b) of the Act:

​

​ ​
Title of each class		Trading Symbol(s)	Name of each exchange on which registered
Common Units representing limited partner	​	​	​
interests	​	SNMP	NYSE American

​

Securities registered pursuant to Section 12(g) of the Act: None

​

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ◻    No  ⌧

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ◻    No  ⌧

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ⌧    No  ◻

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ⌧    No  ◻

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ◻

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)    Yes  ◻    No  ⌧

​

The aggregate market value of Evolve Transition Infrastructure LP common units held by non-affiliates as of June 30, 2020 was approximately $4,070,736 based upon the NYSE American closing price as of such date.

​

Common units outstanding on March 15, 2021: 54,533,593 common units.

​

​

​

Table of Contents

TABLE OF CONTENTS

​

​

​

​

​

​

i

Table of Contents

COMMONLY USED DEFINED TERMS

As used in this Annual Report on Form 10-K (this “Form 10-K”), unless the context indicates or otherwise requires, the following terms have the following meanings:

●

“Evolve Transition Infrastructure,” “the Partnership,” “we,” “us,” “our” or like terms refer collectively to Evolve Transition Infrastructure LP, its consolidated subsidiaries and, where the context provides, the entities in which we have a 50% ownership interest.

●

“Bbl” means one barrel of 42 U.S. gallons of oil.

●

“Board” means the board of directors of our general partner.

●

“Boe” means one barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

●

“Boe/d” means one Boe per day.

●

“Class C Preferred Units” means our Class C Preferred Units representing limited partner interests in Evolve Transition Infrastructure.

●

“common units” means our common units representing limited partner interests in Evolve Transition Infrastructure.

●

“Credit Agreement” means collectively, the Third Amended and Restated Credit Agreement, dated as of March 31, 2015, among the Partnership, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto, as amended by (i) Amendment and Waiver of Third Amended and Restated Credit Agreement, dated as of August 12, 2015, (ii) Joinder, Assignment and Second Amendment to Third Amended and Restated Credit Agreement, dated as of October 14, 2015, (iii) Third Amendment to Third Amended and Restated Credit Agreement, dated as of November 12, 2015, (iv) Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of July 5, 2016, (v) Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of April 17, 2017, (vi) Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of November 7, 2017, (vii) Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of February 5, 2018, (viii) Eighth Amendment to Third Amended and Restated Credit Agreement, dated as of May 7, 2018, (ix) Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of November 22, 2019, and (x) Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of November 6, 2020 (individually, the “Tenth Amendment”).

●

“GHGs” mean greenhouse gases.

●

“MBbl” means one thousand barrels of oil or other liquid hydrocarbons.

●

“MBbl/d” means one thousand barrels of oil or other liquid hydrocarbons per day.

●

“MBoe” means one thousand Boe.

●

“Mcf” means one thousand cubic feet of natural gas.

●

“Mesquite” means (i) at all times prior to June 30, 2020, Sanchez Energy Corporation and its consolidated subsidiaries, and (ii) at all times after and including June 30, 2020, Mesquite Energy, Inc. and its consolidated subsidiaries.

●

“MMBbl” means one million barrels of oil or other liquid hydrocarbons.

●

“MMBoe” means one million Boe.

2

Table of Contents

●

“MMBtu” means one million British thermal units.

●

“MMcf” means one million cubic feet of natural gas.

●

“MMcf/d” means one million cubic feet of natural gas per day.

●

“NGLs” means the combination of ethane, propane, butane, natural gasolines and other components that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

●

“Operational Services Agreement” means that certain Services Agreement, effective as of November 1, 2020, between the Partnership, SEP Holdings IV, LLC, Catarina Midstream, LLC, SECO Pipeline and SNMP Services.

●

“our general partner” means Evolve Transition Infrastructure GP LLC, our general partner.

●

“our partnership agreement” means the Third Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of August 2, 2019, as amended by the Stonepeak Letter Agreement (as defined herein), as amended by Amendment No. 1 thereto, dated as of February 12, 2021.

●

“Shared Services Agreement” means the Amended and Restated Shared Services Agreement between SP Holdings and the Partnership, dated as of March 6, 2015.

●

“Settlement Agreement” means the Settlement Agreement, dated June 6, 2020, as amended by that certain Amendment Agreement, dated as of June 14, 2020 and effective as of June 6, 2020, in each case, by and among the Partnership, our general partner, Catarina Midstream, LLC, Seco Pipeline, LLC, the SN Debtors, SP Holdings, Carnero G&P LLC and TPL SouthTex Processing Company LP.

●

“SN Debtors” means collectively, Mesquite, SN Palmetto, LLC, SN Marquis LLC, SN Cotulla Assets, LLC, SN Operating, LLC, SN TMS, LLC, SN Catarina, LLC, Rockin L Ranch Company, LLC, SN Payables, LLC, SN EF Maverick, LLC and SN UR Holdings, LLC.

●

“SNMP Services” means SNMP Services Inc., our wholly owned subsidiary which provides payroll, human resources, employee benefits and other consulting services to us and our subsidiaries.

●

“SP Holdings” means SP Holdings, LLC, the sole member of our general partner.

●

“Stonepeak” means Stonepeak Catarina and its subsidiaries, other than the Partnership.

●

“Stonepeak Catarina” means Stonepeak Catarina Holdings, LLC.

​

3

Table of Contents

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-K contains “forward-looking statements” as defined by the United States Securities and Exchange Commission (the “SEC”) that are subject to a number of risks and uncertainties, many of which are beyond our control. These statements may include discussions about our business strategy; the ability of our customers to meet their drilling and development plans on a timely basis, or at all, and perform under gathering, processing and other agreements; our financing strategy; our acquisition strategy; our ability to make distributions; our future operating results; the ability of our partners to perform under our joint ventures; our future capital expenditures; and our plans, objectives, expectations, forecasts, outlook and intentions.

All of these types of statements, other than statements of historical fact included in this Form 10-K, are forward-looking statements. These forward-looking statements may be found in Part II, Item 7. and other items within this Form 10-K. In some cases, forward-looking statements can be identified by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.  

The forward-looking statements contained in this Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by the management of our general partner. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate.

​

Important factors that could cause our actual results to differ materially from the expectations reflected in the forward-looking statements include, among others:

​

●

the resolution of the pending Rejection Lawsuits (as defined below) and their impact on the effectiveness of the Settlement Agreement and our business, results of operations and financial condition;

​

●

our ability to successfully execute our business, acquisition and financing strategies;

​

●

changes in general economic conditions, including market and macro-economic disruptions resulting from the ongoing pandemic caused by a novel strain of coronavirus (“COVID-19”) and related governmental responses;

​

●

the ability of our customers to meet their drilling and development plans on a timely basis, or at all, and perform under gathering, processing and other agreements;

​

●

the creditworthiness and performance of our counterparties, including financial institutions, operating partners, customers and other counterparties;

​

●

our ability to extend, replace or refinance our Credit Agreement;

​

●

our ability to grow enterprise value;

​

●

the ability of our partners to perform under our joint ventures;

​

●

the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;

​

●

our ability to access the credit and capital markets to obtain financing on terms we deem acceptable, if at all, and to otherwise satisfy our capital expenditure requirements;

​

●

the timing and extent of changes in prices for, and demand for, natural gas, NGLs and oil;

​

●

our ability to successfully execute our hedging strategy and the resulting realized prices therefrom;

4

Table of Contents

​

●

the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may, therefore, be imprecise;

​

●

competition in the oil and natural gas industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

​

●

the extent to which our assets operated by others are operated successfully and economically;

​

●

our ability to compete with other companies in the oil and natural gas industry;

​

●

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

​

●

the use of competing energy sources and the development of alternative energy sources;

​

●

unexpected results of litigation filed against us;

​

●

disruptions due to extreme weather conditions, such as extreme rainfall, hurricanes or tornadoes;

​

●

the extent to which we incur uninsured losses and liabilities or losses and liabilities in excess of our insurance coverage; and

​

●

the other factors described under “Part I, Item 1A. Risk Factors” in this Form 10-K and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

​

Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements. The forward-looking statements speak only as of the date made, and other than as required by law, we do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

​

5

Table of Contents

Table of Contents

Mesquite (the “Seco Comanche Agreement”). Each such agreement will become effective only upon satisfaction of certain closing conditions described in the Settlement Agreement.

On June 23, 2020, certain affiliates of each Occidental Petroleum Corp., The Blackstone Group and GSO Capital Partners each filed a complaint (collectively, the “Rejection Lawsuits”) against Mesquite and certain of its subsidiaries requesting, among other things, that the Bankruptcy Court not approve the rejection of certain commercial agreements, as set forth in the Settlement Agreement, in connection with Mesquite’s Comanche Asset (as defined herein).

On June 30, 2020, the SN Debtors emerged from the Mesquite Chapter 11 Case, with Mesquite becoming a privately held corporation.

The commercial agreements contemplated by the Settlement Agreement will not become effective until, among other things, the Rejection Lawsuits have been resolved in favor of the SN Debtors and the Bankruptcy Court has approved the rejection of the certain commercial agreements underlying the Rejection Lawsuits. The Rejection Lawsuits were not resolved by October 1, 2020, and as a result the parties to the Settlement Agreement may terminate the Settlement Agreement at any time pursuant to its terms. To date, none of the parties of the Settlement Agreement have provided notice of termination.

Our Relationship with Stonepeak

Since October 14, 2015, Stonepeak Catarina has owned all of our issued and outstanding preferred units. As of March 16, 2021, Stonepeak owned (i) 39,623,443 common units, representing approximately 72.7% of our outstanding common units, (ii) all of our issued and outstanding Class C Preferred Units, (iii) a warrant (the “Warrant”) that entitled Stonepeak Catarina to receive junior securities of the Partnership (including common units) representing 10% of all junior securities deemed outstanding when exercised, (iv) the non-economic general partner interest in the Partnership and (v) all of our incentive distribution rights.  Stonepeak also owns 100% of the issued and outstanding equity interests in SP Holdings, which is the sole member of our general partner.  SP Holdings has the right to appoint all of the members of the Board of directors other than two directors which Stonepeak Catarina is entitled to designate pursuant to that certain Amended and Restated Board Representation and Standstill Agreement, dated as of August 2, 2019. As a result of the foregoing, Stonepeak controls us and our general partner and has the ability to appoint all of the members of the Board.  

Stonepeak Catarina is indirectly managed by Stonepeak Partners LP, a leading North American infrastructure private equity firm (“Stonepeak Partners”). Stonepeak Partners’ significant infrastructure and midstream energy expertise and deep financial resources are reflected in over $31 billion of assets under management, with investments to date including, among others, preferred and common interests in the Partnership, MPLX LP, Phillips 66 Partners LP, Plains All American Pipeline, L.P. and Targa Resources Corp.  We believe that, as a result of Stonepeak’s significant ownership interest in us, Stonepeak is incentivized to support and promote our business plan and to encourage us to pursue projects that enhance the overall value of our business.  While our relationship with Stonepeak is a significant strength, it is also a source of potential risks and conflicts. Please read “Part I, Item 1A. Risk Factors—Risks Inherent in an Investment in Our Common Units” and “Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Business Strategy

Our primary business objective is to create long-term value by generating stable and predictable cash flows that allow us to reduce the amount of our indebtedness and pursue energy transition infrastructure opportunities. We plan to achieve this objective by executing the following business strategy:

●

grow our business through the acquisition and development of infrastructure critical to the transition of energy supply to lower carbon sources;

●

pursue organic investments in our existing operating areas to support growth;

●

pursue strategic relationships with third-party producers and other companies with operations in the area in which we operate in order to maximize the utilization of our midstream facilities or provide other revenue-generating services; and

7

Table of Contents

●

maintain financial flexibility and a strong capital structure.

Business Segments

Our business activities are conducted under two operating segments for which we provide information in our consolidated financial statements for the years ended December 31, 2020 and 2019. These two segments are based on the nature of the operations that are undertaken by each segment and are our:

●

midstream business, which includes Western Catarina Midstream, the Carnero JV and Seco Pipeline (each as defined below); and

●

production business, which includes non-operated oil and natural gas interests located in the Eagle Ford Shale in South Texas and in other areas of Texas and Louisiana.

For information about our segments’ revenues, profits and losses and total assets, see Note 17 “Reporting Segments” of our Notes to Consolidated Financial Statements.

Midstream Business

Western Catarina Midstream

In October 2015, we acquired (the “Catarina Transaction”) a gathering system from Mesquite (“Western Catarina Midstream”), which is located on the western portion of Mesquite’s acreage position in Dimmit, La Salle and Webb counties in Texas (such net acreage is collectively referred to herein as “Mesquite’s Catarina Asset,” and the western portion of such net acreage is individually referred to herein as “Western Catarina”). Western Catarina Midstream consists of approximately 160 miles of gathering pipelines, four main processing and gathering facilities, including stabilizers, storage tanks, compressors and dehydration units, and other related assets in Western Catarina, which are located in Dimmit and Webb counties in Texas, and services upstream production from assets located in the Eagle Ford Shale in South Texas. The gathering lines range in diameter from four to 12 inches, with a capacity of 200 MMcf/d for natural gas, and 40 MBbl/d for crude oil and NGLs. There are four main gathering and processing facilities, which includes eight stabilizers of 5,000 Bbls/d, approximately 25,000 Bbls of storage capacity, pressurized storage for NGLs, approximately 23,000 horsepower of compression and approximately 300 MMcf/d of dehydration capacity. The gathering system is currently used solely to support the gathering, processing and transportation of natural gas, NGLs and crude oil produced by Mesquite at Mesquite’s Catarina Asset. The gathering system has oil interconnects with the Plains All American Pipeline, L.P. header system delivered to the Gardendale terminal, and to all four takeaway pipelines to Corpus Christi, and natural gas interconnects with Southcross Energy Partners, L.P., Kinder Morgan Inc., Energy Transfer Operating, L.P. and Targa Resources Corp.

In conjunction with the Catarina Transaction, we entered into a 15-year firm gas gathering and processing agreement with Mesquite, pursuant to which Mesquite agreed to tender all of its crude oil, natural gas and other hydrocarbon-based product volumes on approximately 35,000 dedicated acres in Western Catarina for processing and transportation through Western Catarina Midstream, with the potential to tender additional volumes outside of the dedicated acreage (the “Gathering Agreement”).

All of the revenues from Western Catarina Midstream are currently earned from Mesquite. Under the Gathering Agreement, Mesquite was contractually obligated to meet a minimum quarterly volume delivery commitment for oil and natural gas, subject to certain adjustments, however, this contractual requirement expired in 2020. In addition, Mesquite is required to pay contractually agreed upon gathering and processing fees for oil and natural gas volumes tendered through Western Catarina Midstream. In June 2017, the Gathering Agreement was amended to add an incremental infrastructure fee to be paid by Mesquite based on water that was delivered to Western Catarina Midstream through March 31, 2018. Since March 31, 2018, we have agreed with Mesquite to continue adding the incremental infrastructure fee on a month-to-month basis.

During the year ended December 31, 2020, Mesquite transported average daily production through Western Catarina Midstream of approximately 7.4 MBbls/d of oil, 93.6 MMcf/d of natural gas and 3.1 MBbls/d of water. The average age

8

Table of Contents

of the Western Catarina Midstream assets is approximately nine years, and such assets have an average expected life of approximately 20 additional years.

Carnero JV

In May 2018, we executed a series of agreements with Targa Resources Corp. (NYSE: TRGP) (“Targa”) and other parties pursuant to which, among other things: (1) the parties merged their respective 50% interests in Carnero Gathering, LLC (“Carnero Gathering”) and Carnero Processing, LLC (“Carnero Processing”) (the “Carnero JV Transaction”) to form an expanded 50 / 50 joint venture in South Texas, Carnero G&P, LLC (“Carnero JV”), (2) Targa contributed 100% of the equity interest in the Silver Oak II Gas Processing Plant located in Bee County, Texas (“Silver Oak II”), to Carnero JV, which expanded the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d, (3) Targa contributed certain capacity in the 45 miles of high pressure natural gas gathering pipelines owned by Carnero Gathering that connect Western Catarina Midstream to nearby pipelines and the Raptor Gas Processing Facility (the “Carnero Gathering Line”) to Carnero JV resulting in the joint venture owning all of the capacity in the Carnero Gathering Line, which has a design limit (without compression) of 400 MMcf/d, (4) Carnero JV received a new dedication from Mesquite and its working interest partners of over 315,000 acres located in the Western Eagle Ford on Mesquite’s acreage in Dimmit, Webb, La Salle, Zavala and Maverick counties in Texas (such acreage is collectively referred to herein as “Mesquite’s Comanche Asset”) pursuant to a new long-term firm gas gathering and processing agreement. The agreement with Mesquite, which was approved by all of the unaffiliated Comanche non-operated working interest owners, establishes commercial terms for the gathering of gas on the Carnero Gathering Line and processing at the Raptor Gas Processing Facility and Silver Oak II. Prior to execution of the agreement, Comanche volumes were gathered and processed on an interruptible basis, with the processing capabilities of the joint ventures limited by the capacity of the 260 MMcf/d cryogenic natural gas processing plant in La Salle County, Texas (the “Raptor Gas Processing Facility”).

Seco Pipeline

In August 2017, we completed construction of a 100% owned and operated 30-mile natural gas pipeline with 400 MMcf/d capacity that is designed and used to transport dry gas from the Raptor Gas Processing Facility to multiple markets in South Texas (the “Seco Pipeline”). The Seco Pipeline provides upstream producers with optionality to southern gas markets and creates the potential to export natural gas to premium priced markets in Mexico. On September 1, 2017, we entered into a firm transportation service agreement with Mesquite to transport certain quantities of Mesquite’s natural gas on a firm basis through the Seco Pipeline for $0.22 per MMBtu delivered on or after September 1, 2017 (the “Seco Pipeline Transportation Agreement”). The Seco Pipeline Transportation Agreement had an initial term of one month and renewed automatically on a month-to-month basis. Mesquite terminated the Seco Pipeline Transportation Agreement effective February 12, 2020. From January 1, 2020 through February 12, 2020, the effective date of the Seco Pipeline Transportation Agreement termination, Mesquite transported an insignificant amount of gas through the Seco Pipeline. The Seco Pipeline has an expected life of approximately 40 years.

Title to Properties

Title to Western Catarina Midstream and the Seco Pipeline assets are either owned in fee or derived from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license that is held by us or to the title to any material lease, easement, right-of-way, permit or lease we own, and we believe that we have satisfactory title to all of the material leases, easements, rights-of-way, permits and licenses with respect to all Western Catarina Midstream and Seco Pipeline assets.

Production Business

Our total estimated proved reserves at December 31, 2020, were approximately 2.3 MMBoe, all of which were classified as proved developed, with 13% being natural gas, 12% being NGLs, and 75% being oil. At December 31, 2020, we owned approximately 47 net producing wells. Our total average proved reserve-to-production ratio is approximately 9 years and our portfolio decline rate is 11% based on our estimated proved reserves at December 31, 2020.

Below is a description of our operations and our oil and natural gas properties by basin at December 31, 2020:

9

Table of Contents

Locations

All of our reserves were located in the Eagle Ford Shale on non-operated properties. Production during the year ended December 31, 2020 on these properties was 237.7 MBoe and approximately 2,283.4 MBoe of estimated proved reserves were held at December 31, 2020. All of these reserves were classified as proved developed, with 13% being natural gas, 12% being NGLs, and 75% being oil.

We also own non-operated properties in Louisiana. During the year ended December 31, 2020, production on Louisiana properties was 3.5 MBoe.

Operations

We do not currently operate any of our production assets. The Eagle Ford Shale properties are operated by either Sanchez Oil & Gas Corporation (“SOG”), Mesquite or Marathon Oil Company and the Louisiana properties are operated by another prudent operator.

Proved Reserves of Natural Gas, NGLs, and Oil

The following table reflects our estimates for proved natural gas, NGLs and oil reserves based on the SEC definitions that were used to prepare our financial statements for the periods presented. The standardized measure values shown in the table are not intended to represent the current market values of our estimated proved reserves.

​	​	​	​	​	​	​
​		2020			2019
Estimated proved reserves:	​	​	​	​	​	​
Oil (MBbl)		​	1,716		​	2,241
Natural gas (Mcf)		​	1,722		​	2,088
NGLs (MBbl)		​	280		​	410
Total proved reserves (MBoe)		​	2,283		​	2,999
​	​	​	​	​	​	​
Estimated proved developed reserves:	​	​	​	​	​	​
Oil (MBbl)		​	1,716		​	2,241
Natural gas (Mcf)		​	1,722		​	2,088
NGLs (MBbl)		​	280		​	410
Total proved developed reserves (MBoe)		​	2,283		​	2,999
Proved developed reserves as a percent of total reserves	​	​	100%	​	​	100%
Standardized measure ($ in millions)⁽ᵃ⁾	​	$	11,881	​	$	38,350

​

(a)

Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves. It is determined using SEC-required prices and costs in effect as of the time of estimation without giving effect to non-property related expenses (such as general and administrative expenses or debt service costs) and discounted using an annual discount rate of 10%. Our standardized measure does not include the impact of derivative transactions or future federal income taxes because we are not subject to federal income taxes. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure shown should not be considered the current market value of our reserves. The 10% discount factor used to calculate present value, which is required, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. Please read “Part I, item 1A. Risk Factors.”

​

Our 2020 estimates of total proved reserves decreased 716 MBoe from 2019 due to production and revisions of previous estimates of 241 MBoe and 475 MBoe, respectively.

As of December 31, 2020, we had no remaining proved undeveloped reserves in our reserves base.

We expect to make minimal capital expenditures related to recompletion of existing wells during the year ending December 31, 2021.

At December 31, 2020 and December 31, 2019, Ryder Scott Co. LP (“Ryder Scott”), an independent oil and natural gas engineering firm, prepared estimates of all our proved reserves. We used these estimates of our proved reserves to prepare our financial statements. Ryder Scott maintains a degreed staff of highly competent technical personnel. The average experience level of Ryder Scott’s technical staff of engineers, geoscientists and petrophysicists exceeds 20 years, including five to 15 years with a major oil company. The engineering information presented in their report was overseen

10

Table of Contents

by Mr. Eric Nelson, P.E. Mr. Nelson is an experienced reservoir engineer having been a practicing petroleum engineer since 2002. He has more than 14 years of experience in reserves evaluation with Ryder Scott. He has a Bachelor of Science degree in Chemical Engineering from the University of Tulsa and Master of Business Administration degree from the University of Texas. Mr. Nelson is a Registered Professional Engineer in the State of Texas. Our activities with Ryder Scott are coordinated by a reservoir engineer employed by us who has approximately 41 years of experience in the oil and natural gas industry and an engineering degree from the University of Tennessee and a Master of Business Administration from the University of New Orleans. He is a licensed petroleum engineer in the state of Texas and a member of the Society of Petroleum Engineers. He has prior reservoir engineering and reserves management experience at Exxon Mobil Corporation, Dominion Resources and Hilcorp Energy. He has extensive experience in managing oil and natural gas reserves processes. He serves as the key technical person reviewing the reserve reports prepared by Ryder Scott prior to review by the Audit Committee and approval by the Board.

Production and Price History

The following table sets forth information regarding net production of natural gas, NGLs and oil and certain price and cost information for each of the periods indicated:

​	​	​	​	​	​	​	​	​	​	​	​
​	​	Years Ended
​	​	December 31,					​	​	​	​	​
​		2020			2019			Variance
Net production:	​	​	​	​	​	​	​	​	​	​	​
Natural gas (MMcf)	​		158	​		231	​		(73)	​	(32)%
Oil production (MBbl)	​		191	​		228	​		(37)	​	(16)%
NGLs (MBbl)	​		24	​		42	​		(18)	​	(43)%
Total production (MBoe)	​		241	​		309	​		(68)	​	(22)%
Average daily production (Boe/d)	​		658	​		847	​		(189)	​	(22)%
Average sales prices:	​	​	​	​	​	​	​	​	​	​	​
Natural gas price per Mcf with hedge settlements	​	$	4.13	​	$	2.24	​	$	1.89	​	84%
Natural gas price per Mcf without hedge settlements	​	$	2.15	​	$	1.84	​	$	0.32	​	17%
Oil price per Bbl with hedge settlements	​	$	51.68	​	$	62.94	​	$	(11.26)	​	(18)%
Oil price per Bbl without hedge settlements	​	$	36.87	​	$	59.40	​	$	(22.53)	​	(38)%
NGL price per Bbl without hedge settlements	​	$	10.58	​	$	12.83	​	$	(2.25)	​	(18)%
Total price per Boe with hedge settlements	​	$	44.72	​	$	49.86	​	$	(5.14)	​	(10)%
Total price per Boe without hedge settlements	​	$	31.68	​	$	46.94	​	$	(15.26)	​	(33)%
Average unit costs per Boe:	​	​	​	​	​	​	​	​	​	​	​
Field operating expenses (a)	​	$	23.45	​	$	21.04	​	$	2.41	​	11%
Lease operating expenses	​	$	22.16	​	$	19.03	​	$	3.13	​	16%
Production taxes	​	$	1.29	​	$	2.01	​	$	(0.72)	​	(36)%
Depreciation, depletion and amortization	​	$	9.20	​	$	12.76	​	$	(3.55)	​	(28)%

​

(a)	Field operating expenses include lease operating expenses and production taxes.

Existing Wells

The following table sets forth information at December 31, 2020, relating to the existing wells in which we owned a working interest as of that date. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

​	​	​	​	​	​	​	​	​
​	​	Natural Gas			​	Oil
​		Gross		Net		Gross		Net
Operated		—		—		—		—
Non-operated		—		—		91		47
Total		—		—		91		47

We did not convert any proved undeveloped wells into proved producing wells in 2020.

11

Table of Contents

Drilling Activity

With respect to oil and natural gas wells drilled and completed during the years ended December 31, 2020 and 2019, the information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that are capable of producing commercial quantities of oil or natural gas, regardless of whether they produce a reasonable rate of return. No exploratory wells were drilled on any of our properties during the years ended December 31, 2020 or 2019. During the years ended December 31, 2020 and 2019, there were no wells drilled and there were no wells in progress.  

Developed and Undeveloped Acreage

The following table sets forth information related to our leasehold acreage as of December 31, 2020.

​

​

(a)	Developed acres are acres pooled within or assigned to productive wells/units.

(b)	Undeveloped acres are acres on which wells have not been drilled or acres that have not been pooled into a productive unit.

(c)	A gross acre is an acre in which a working interest is either fully or partially leased. The number of gross acres may include minerals not under lease as a result of leasing some but not all joint mineral owners under any given tract.

(d)	A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Leases

Most of our reserves are comprised of wellbore rights only. We have a small lease position of less than 150 net acres in Louisiana.

Marketing and Major Customers

Our oil and natural gas production in Texas and Louisiana is marketed by the operators of our properties.

Mesquite accounted for 80% and 86% of our total revenue for the years ended December 31, 2020 and 2019, respectively. We are highly dependent upon Mesquite as our most significant customer, and we expect to derive a substantial portion of our revenue from Mesquite in the foreseeable future. Accordingly, we are indirectly subject to the business risks of Mesquite. Any development that materially and adversely affects Mesquite’s operations or financial condition could have a material adverse impact on us. For additional information on the risks associated with our relationship with Mesquite, please read “Part I, Item 1A. Risk Factors.”

Markets and Competition

We operate in a competitive environment for acquiring properties, marketing oil, NGLs and natural gas and retaining trained personnel. Many of our competitors have substantially greater financial, technical and personnel resources than us. As a result, our competitors may be able to outbid us for assets, more competitively price their gathering and transportation services and oil and natural gas production, or utilize superior technical resources than our financial or personnel resources permit. Our ability to acquire additional assets will depend on our ability to evaluate and select suitable assets and to consummate transactions in a competitive environment.

The natural gas gathering, compression, treating and transportation business is very competitive. Upon such time that we seek to obtain customers in addition to Mesquite for Western Catarina Midstream, our competitors will include other midstream companies, producers and intrastate and interstate pipelines. Competition for volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies.

12

Table of Contents

Stonepeak is not restricted from competing with us. Please read “Part I, Item 1A. Risk Factors—Stonepeak Catarina and its affiliates, including our general partner, will have conflicts of interest with us. They will not owe any fiduciary duties to us or our common unitholders, but instead will owe us and our common unitholders limited contractual duties, and they may favor their own interests to the detriment of us and our other common unitholders.” Additional information regarding our relationship with Stonepeak is provided in “Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Governmental Regulation

Environmental Laws

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

​

●

require the acquisition of various permits before drilling commences;

●

restrict the types, quantities and concentrations of various substances, including water and waste, that can be released into the environment;

●

limit or prohibit activities on lands lying within wilderness, wetlands and other protected areas; and

●

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible in the absence of such regulations. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. In addition, federal, state and local authorities frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

Environmental laws and regulations that could have a material impact on the oil and natural gas industry and our operations include the following:

Waste Handling

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous wastes and non-hazardous wastes. With the approval of the federal Environmental Protection Agency (“EPA”), the individual states can administer some or all of the provisions of RCRA, and some states have adopted their own, more stringent requirements. Drilling fluid, produced water and most other wastes associated with the exploration, development and production of oil and natural gas are currently regulated under RCRA’s non-hazardous waste provisions. Although we do not believe that the current costs of managing any of our wastes are material under presently applicable laws, any future reclassification of oil and natural gas exploration, development and production wastes as hazardous wastes, could increase our costs to manage and dispose of wastes.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, can impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons can include the owners or operators of the site where the release occurred, and anyone who disposed of, or arranged for the disposal of, a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, including response costs, alternative water supplies, damages to natural resources and the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property

13

Table of Contents

damage allegedly caused by the hazardous substances released into the environment. Each state also has environmental cleanup laws analogous to CERCLA.

We currently own, lease or operate numerous properties that have been used for oil and natural gas production for a number of years. Although we believe that operating and waste disposal practices utilized in the past with respect to these properties were typical for the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, these properties have been operated by third parties or by previous owners or operators whose practices, including the treatment and disposal or release of hazardous substances, wastes or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future environmental harm.

Water Discharges

The Federal Water Pollution Control Act (the “Clean Water Act”), and comparable state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, impose investigatory or remedial obligations and issue injunctions limiting or preventing our operations for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Oil Pollution Act

The Oil Pollution Act of 1990 amended the Clean Water Act in large part due to the Exxon Valdez incident. Under the Oil Pollution Act, the EPA was directed to promulgate regulations which would create a comprehensive prevention, response, liability and compensation program to deal with oil discharged into United States navigable waters. The Oil Pollution Act imposes ongoing requirements on owners and operators of facilities that handle certain quantities of crude oil, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with a spill. The Oil Pollution Act imposes liability for removal costs and damages resulting from an incident in which oil is discharged into navigable waters and establishes liability for damages for injuries to, or loss of, natural resources.

Air Emissions

The Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. In October 2015, the EPA finalized rules that lower the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 parts per billion (“ppb”) to 70 ppb, and the EPA published a final rule in July 2018 completing the final designations. States can also impose air emissions limitations that are more stringent than the federal standards imposed by the EPA. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. Rules restricting air emissions may require a number of modifications to our operations, including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our operating results. However, we believe that our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies. We believe that our operations are in substantial compliance with federal and state air emission standards.

Climate Change

While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In

14

Table of Contents

the absence of such federal climate legislation, the EPA has used existing authority under the Clean Air Act to regulate GHGs. For example, the EPA has adopted rules requiring the reporting of GHG emissions from various oil and natural gas operations on an annual basis. In addition, in June 2016, the EPA published New Source Performance Standards (“NSPS”) Subpart OOOOa standards that require new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and volatile organic compound emissions. However, in June 2017, the EPA published a proposed rule to stay portions of the Subpart OOOOa standards for two years. In September 2018, the EPA issued proposed revisions to the NSPS applicable to new and modified oil and gas sources, which would reduce the monitoring obligations for wells and compressor stations. Further in October 2018, the EPA issued a draft report which includes a template designed to assist with compliance. In August 2020, EPA issued two final rules that will  make it simpler for the oil and gas industry to comply with NSPS. The first policy amendments remove the transmission and storage segment from the rule, rescind VOC and methane emission standards for that segment and rescind methane emission standards for the production and processing segments. The second simplifies compliance requirements. A number of state and regional efforts have also emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to possess and acquire emission allowances which permit corresponding GHG emissions. Furthermore, the U.S. is currently a party to the Paris Agreement adopted in December 2015 to reduce global GHG emissions. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement in accordance with the Agreement’s four-year exit process and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement and on November 4, 2020 the United States officially withdrew from the Paris Agreement. However, on January 20, 2021, President Biden signed an executive order to have the United States rejoin the Paris Agreement. On November 4,2020 the withdrawal took effect. However, on January 20, 2021 President Biden signed an Executive Order to reverse the withdrawal and the United States formally re-joined the Paris Agreement on February 19, 2021. Additionally, President Biden has issued an executive order seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden Administration’s climate policies.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices and has finalized a study of the potential environmental impacts of hydraulic fracturing activities, finding that under certain circumstances, the “water cycle” activities associated with hydraulic fracturing may impact drinking water resources. In 2014, the EPA released an Advanced Notice of Proposed Rulemaking seeking public comment on its plans to issue regulations under the Toxic Substances Control Act of 1976 to require companies to disclose information regarding chemicals used in hydraulic fracturing. Further, the Department of the Interior has released final regulations governing hydraulic fracturing on federal oil and natural gas leases which require lessees to file for approval of well stimulation work before commencement of operations and require well operators to disclose the trade names and purposes of additives used in the fracturing fluids. The states in which we operate have also adopted disclosure requirements related to fracturing fluids. Legislation has been introduced, but not adopted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Currently, no states in which we utilize hydraulic fracturing have adopted these regulations. In addition, President Biden has declared that he would support federal government efforts to limit or prohibit hydraulic fracturing. These declarations include threats to take actions banning hydraulic fracturing of crude oil and natural gas wells and banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. On January 20, 2021, the Acting Secretary for the Department of the Interior signed an order suspending new fossil fuel leasing and permitting on federal lands for 60 days. In addition, on January 20, 2021, President Biden issued an Executive Order on “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis” seeking to adopt new regulations and policies to address climate change and suspend, revise, or rescind, prior agency actions that are identified as conflicting with the Biden Administration’s climate policies. Among the areas that could be affected by the review are regulations addressing hydraulic fracturing. At this time, it is not possible to accurately estimate how these recent actions and future rules and rulemaking initiatives under the Biden administration will impact our business.

15

Table of Contents

Endangered Species

The federal Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions and may materially delay or prohibit land access for development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the FWS was required to make a determination on the listing of more than 250 species as endangered or threatened under the ESA by the end of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities.

Gathering System Regulation

Regulation of gathering facilities may affect certain aspects of our business and the market for our services. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily the Federal Energy Regulatory Commission (“FERC”). The FERC regulates interstate natural gas transportation rates, terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

The transportation and sale for resale of natural gas in interstate commerce are regulated primarily under the Natural Gas Act (“NGA”), and by regulations and orders promulgated under the NGA by the FERC. In certain limited circumstances, intrastate transportation, gathering, and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the U.S. Congress and by FERC regulations.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests that the FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and varying interpretations. In addition, the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our natural gas gathering facilities are subject to change based on future determinations by the FERC, the courts, or the U.S. Congress. If the FERC were to determine that an individual gathering system is not exempt from FERC regulation and the pipelines associated with such gathering system provide interstate transportation, the rates for, and terms and conditions of, services provided by such gathering system would be subject to regulation by the FERC. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect results of operations and cash flows. If any of our facilities were found to have provided services or otherwise operated in violation of the NGA or the NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

Gathering services, which may occur upstream of transmission service subject to FERC jurisdiction, is regulated by the states. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our purchasing and gathering operations are subject to ratable take and common purchaser statutes in the State of Texas. The ratable take statute generally requires gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, the common purchaser statute generally requires gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport gas.

The Railroad Commission of Texas (“TRRC”) requires gatherers to file reports, obtain permits, make books and records available for audit and provide service on a nondiscriminatory basis. Shippers and producers may file complaints with the TRRC to resolve grievances relating to natural gas gathering access and rate discrimination.

16

Table of Contents

While our gathering systems have not been regulated by the FERC under the NGA, the U.S. Congress may enact legislation or the FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas gatherers with which we compete. Failure to comply with those regulations in the future could subject us to civil penalty liability.

The Energy Policy Act of 2005 (“EPAct 2005”), amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by the FERC, and furthermore provides the FERC with additional civil penalty authority. The EPAct 2005 provided the FERC with the power to assess daily civil penalties for violations of the NGA and the Natural Gas Policy Act (“NGPA”). The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. In Order No. 670, the FERC promulgated rules implementing the anti-market manipulation provision of the EPAct 2005. The rules make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to: (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction.

Pipeline Safety Regulation

We are subject to regulation by the United States Department of Transportation (“DOT”) through the Pipelines and Hazardous Materials Safety Administration (“PHMSA”), pursuant to the Hazardous Liquid Pipeline Safety Act of 1979, as amended (“HLPSA”) and comparable state statutes with respect to design, installation, inspection, testing, construction, operation, replacement and maintenance of pipeline facilities. HLPSA, as amended, governs he design, installation, testing, construction, operation, replacement and management of crude oil pipeline facilities and also covers petroleum and petroleum products, including NGLs and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the U.S. Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.

Our natural gas pipelines are subject to regulation by PHMSA pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002 (“PSIA”), as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (“PIPES Act”). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas (“HCAs”).

PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including us, to:

●

perform ongoing assessments of pipeline integrity;

●

identify and characterize applicable threats to pipeline segments that could impact HCAs;

●

improve data collection, integration and analysis;

●

repair and remediate pipelines as necessary; and

●

implement preventive and mitigating actions.

17

Table of Contents

The HLPSA has been amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The 2011 Pipeline Safety Act doubled the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1 million to $2 million for a related series of violations, but provided that these maximum penalty caps do not apply to certain civil enforcement actions. Effective April 27, 2017, to account for inflation, those maximum civil penalties were increased to $213,268 per day, with a maximum of $2,132,679 for a series of violations. The 2016 Pipeline Safety Act extended PHMSA’s statutory mandate through 2019. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.

PHMSA regularly revises its pipeline safety regulations and has published advanced notices of proposed rulemakings and notices of proposed rulemaking to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations. In the past few years, PHMSA issued advisory bulletins providing guidance on applicable regulatory requirements, including those that must be followed for the abandonment of a pipeline; aspects of overall pipeline integrity, including the need for corrosion-control systems on buried and insulated pipeline segments, to conduct in-line inspections for all threats, and to ensure in-line inspection tool findings are accurate and verified; the need of owners and operators of natural gas facilities to take appropriate steps to prevent damage to pipeline facilities from accumulated snow or ice; actions pipeline operators should consider taking to ensure the integrity of pipelines in the event of severe flooding or hurricane damage; notice of construction; flow reversal procedures; product changes and conversion; integrity management program evaluation metrics; and incident response plans. Further changes to PHMSA’s rules are expected in the future.

For example, in July 2015, PHMSA issued a notice of proposed rulemaking proposing, among other things, to extend operator qualification requirements to operators of certain natural gas gathering lines and to add a specific timeframe for operators’ notifications of accidents or incidents. In January 2017, PHMSA issued a final rule adding a specific timeframe for operators’ notifications of accidents or incidents but delayed final action on the operator qualification proposals until a later date. The final rule became effective March 24, 2017. In addition, in October 2015, PHMSA issued a notice of proposed rulemaking proposing changes to its hazardous liquid pipeline safety regulations, including to extend: (i) reporting requirements to all onshore or offshore, regulated or unregulated hazardous liquid gathering lines; and (ii) certain integrity management periodic assessment and remediation requirements to regulated onshore gathering lines. On January 13, 2017, PHMSA issued a final rule amending its regulations to impose new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. The final rule also significantly extends and expands the reach of certain integrity management requirements, regardless of the pipeline’s proximity to HCAs. However, this final rule remains subject to review and approval by the new administration, pursuant to a memorandum issued by the White House to heads of federal agencies. It is unclear whether the final rule will be revised and when it will be implemented. In April 2016, PHMSA issued a notice of proposed rulemaking that would expand integrity management requirements and impose new pressure requirements on currently regulated gas transmission pipelines and would also significantly expand the regulation of gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. On October 1, 2019, PHMSA issued its final rule which became effective July 1, 2020. While we cannot predict the outcome of legislative or regulatory initiatives, such regulatory changes and any legislative changes could have a material effect on our operations, particularly by extending more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.

Furthermore, DOT regulations have incorporated by reference the American Petroleum Institute Standard 653 (“API 653”) as the industry standard for the inspection, repair, alteration and reconstruction of storage tanks. API 653 requires regularly scheduled inspection and repair of such tanks. These periodic tank maintenance requirements may result in

18

Table of Contents

significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our storage tanks.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing intrastate pipeline regulations and inspection of intrastate pipelines. For example, in Texas the Pipeline Safety Department of the TRRC inspects and enforces the pipeline safety regulations for intrastate pipelines, including gathering lines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include more stringent requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

We have incorporated all existing requirements into our programs by the required regulatory deadlines and are continually incorporating the new requirements into procedures and budgets. We expect to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above. In addition to regulatory changes, costs may be incurred when there is an accidental release of a commodity gathered on our system, or a regulatory inspection identifies a deficiency in our required programs.

Other Laws and Regulation

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”), and comparable state laws. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communications standard, OSHA Process Safety Management, the EPA community right-to-know regulations under Title III of CERCLA and similar state laws require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements.

We believe that we are in substantial compliance with existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements should not have a material adverse impact on our financial condition and results of operations. As of December 31, 2019, we had no accrued environmental obligations. We are not aware of any environmental issues or claims that will require material capital expenditures or that will otherwise have a material impact on our financial position or results of operations. However, we cannot predict how future environmental laws and regulations may impact our operations, and therefore, cannot provide assurance that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial condition, results of operations or cash flows.

Human Capital

Headcount

We do not have any employees. Pursuant to the terms of the Operational Services Agreement, our subsidiary SNMP Services provides us and certain of our subsidiaries, including SEP Holdings IV, LLC, Catarina Midstream, LLC and SECO Pipeline, LLC, with payroll, human resources, employee benefits and other consulting services we mutually agree upon with SNMP Services. Following the effective date of the Operational Services Agreement, SOG no longer provides any employees or support staff for our business. As of March 16, 2021, thirteen (13) employees were employed by SNMP Services with their primary function being to provide services for us, all of which were full-time employees. None of SNMP Services’ employees are subject to a collective bargaining agreement.  When we refer to “our employees” in this Form 10-K we are referring the SNMP Services’ employees. Our success is due in large part to the skills, experience and dedication of such employees.

Employee Safety

We believe our responsibility to our employees, neighbors, shareholders and the environment is only fulfilled through our commitment to safety and reliability. Through training, continuous monitoring and promoting a culture of excellence in operations, we continuously strive to keep our people, the communities in which we operate in and the

19

Table of Contents

environment safe. By monitoring the integrity of our assets and promoting the safety of our employees, we are investing in the long-term sustainability of our business.

We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA Hazard Communication Standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

In response to COVID-19, we have taken steps to manage the potential impacts of the COVID-19 outbreak on our employees. We continue to practice remote work procedures when possible to protect the safety of our employees and their families, and have taken extra precautions for our employees who work in the field or cannot otherwise work remotely, such as social distancing, face covering protocols and sanitation procedures.

Development and Retention

In managing our human capital resources, we use a strategic approach to building a diverse, inclusive, and respectful workplace. SNMP Services provides expertise and tools to attract, develop, and retain diverse talent and support our employees’ career and development goals. We value our employees’ opinions and encourage them to engage with management and ask questions on topics such as our goals, challenges, and employee concerns.

We believe that a combination of competitive compensation and career growth and development opportunities help increase employee morale and reduce voluntary turnover. Our comprehensive benefit packages are competitive in the marketplace and we believe in recognizing and rewarding talent through our various compensation programs.

Health and Welfare

We provide a variety of benefits to help promote the health and welfare of our employees and their families.  These benefits include medical, dental, vision plans and virtual health visits. Eligible employees also have access, at no charge, to an employee assistance program.

Offices

Our principal executive offices are located at 1360 Post Oak Blvd., Suite 2400, Houston, Texas 77056. Our telephone number is (713) 783-8000.

Available Information

Our internet address is http://www.evolvetransition.com. We make our website content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available free of charge on or through our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The SEC maintains an internet website that contains these reports at http://www.sec.gov.

​

20

Table of Contents

Table of Contents

●

Our Credit Agreement has substantial prepayment requirements, other restrictions and financial covenants and requires periodic borrowing base redeterminations.

●

We may not be able to extend, replace or refinance our Credit Agreement on terms reasonably acceptable to us, or at all, which could materially and adversely affect our business, liquidity, cash flows and prospects.

Risks Related to Our Cash Distributions

●

Our partnership agreement prohibits us from making certain distributions until all of the Class C Preferred Units are redeemed and, as a result, our ability to make, maintain and grow cash distributions is dependent on our ability to redeem the Class C Preferred Units.

●

Our Credit Agreement restricts us from paying any distributions on our outstanding common units.

●

Any termination of the Shared Services Agreement requiring the payment of a termination fee may result in substantial dilution and could adversely affect our financial condition, results of operations, operating cash flows and any ability to pay cash distributions.

Risks Related to Regulatory Compliance

●

Increased regulation of hydraulic fracturing could result in reductions or delays in the production of natural gas, NGLs and oil by Mesquite, which could reduce the throughput on our facilities and adversely impact our revenues.

Risks Inherent in an Investment in Our Common Units

●

We are currently not in compliance with the NYSE American listing standards. If our common units are delisted, it could result in even further reductions in the trading price and liquidity of our common units, which could materially adversely affect our ability to raise capital or pursue strategic transactions on acceptable terms, or at all.

●

Certain events may result in our general partner exercising its limited call right, which may require common unitholders to sell their common units at an undesirable time or price.

●

Stonepeak Catarina and its affiliates, including our general partner, will have conflicts of interest with us. They will not owe any fiduciary duties to us or our common unitholders, but instead will owe us and our common unitholders limited contractual duties, and they may favor their own interests to the detriment of us and our other common unitholders

●

Our partnership agreement replaces our general partner’s fiduciary duties to our common unitholders with contractual standards governing its duties.

●

We are able to issue additional units without common unitholder approval, which would dilute unitholder interests.

Tax Risks

●

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

●

Our common unitholders’ share of our income will be taxable to them even if they do not receive any cash distributions from us.

​

22

Table of Contents

Risk Factors

Our business involves a high degree of risk. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this Form 10-K, including the financial statements and the related notes appearing at the end of this Form 10-K. If any of the following risks, or any risk described elsewhere in this Form 10-K, were to occur, our business, financial condition or results of operations could be adversely affected. If any of the following risks, or any risk described elsewhere in this Form 10-K, were to occur, our business, financial condition or results of operations could be adversely affected. The risks below are not the only ones facing the Partnership. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. This Form 10-K also contains forward-looking statements, estimates and projections that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of specific factors, including the risks described below. Please read “Cautionary Note Regarding Forward-Looking Statements.”

Risks Related to the COVID-19 Pandemic

The COVID-19 pandemic has had and could continue to have a material adverse impact on our business, financial condition, cash flows and results of operations.

COVID-19 has had and could continue to have a material adverse impact on our business, including our financial condition, cash flows and results of operations. COVID-19 was first reported in December 2019 and has since spread to over 200 countries and territories, including every state in the United States.  In March 2020, the World Health Organization declared COVID-19 a pandemic and recommended containment and mitigation measures worldwide and the United States declared a national emergency with respect to COVID-19.  As a result, extraordinary and wide-ranging actions were taken by international, federal, state and local public health and governmental authorities to reduce the spread of COVID-19, including quarantines, government restrictions on movement, business closures and suspensions, canceled events and activities, self-isolation, and other voluntary or mandated changes in behavior. Such actions have also resulted in significant business and operational disruptions, including supply chain disruptions, travel restrictions, stay-at-home orders and limitations on the availability of workforces.  COVID-19 and the ongoing response to mitigate its impact have contributed to a massive economic shutdown and decreased demand for crude oil and natural gas.

As the pandemic and responses to it continue, we may experience further disruptions to commodities markets, supply chains and the health, availability and efficiency of our workforce, which could adversely affect our ability to conduct our business and operations and limit our ability to execute on our business plan. Both the outbreak of the disease and measures taken to slow its spread have created significant uncertainty and economic volatility and disruption, which have impacted and may continue to impact our business operations and have materially adversely affected and may continue to materially adversely affect our results of operations, cash flows and financial performance, including, but not limited to, the following:

●

a delay in timing for the collections of our receivables for the services we perform, including as a result of deteriorating financial condition resulting from the COVID-19 pandemic and resulting economic impacts;

●

illness, travel restrictions or other workforce disruptions impacting the availability or productivity of our employees;

●

increased volatility and pricing in the capital markets and credit markets, which may reduce the availability of, and our ability to access, sources of liquidity on acceptable pricing or borrowing terms, if at all; and

●

disruptions in the ability of our suppliers, subcontractors, joint venture partners and others to satisfy their obligations with respect to us, which has impacted, and could continue to impact, our liquidity position, which could result in our inability to pay our payables timely, including required payments under the Credit Agreement.

23

Table of Contents

There are still too many variables and uncertainties regarding COVID-19 — including the pace and efficacy of vaccination efforts, the duration and severity of possible resurgences and the duration and extent of travel restrictions and business closures imposed in affected countries — to reasonably predict the full potential impact of COVID-19 on our business and operations.  Even after the COVID-19 pandemic has subsided, we may experience materially adverse impacts to our business due to the global economic recession that is likely to result from the measures taken to combat the virus. Further, adverse impacts from the COVID-19 pandemic may have the effect of heightening many of the other risks we face.

Risks Related to the Rejection Lawsuits and the Settlement Agreement

The failure of the Bankruptcy Court to approve the rejection of the certain commercial agreements underlying the Rejection Lawsuits, or termination of the Settlement Agreement by any party, could adversely affect our business, financial condition, cash flows and results of operations.

On June 30, 2020, the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) entered an order approving the Settlement Agreement and the parties to the Settlement Agreement entered into or amended certain commercial contracts, including but not limited to, (i) Amendment No. 2 to the Gathering Agreement, (ii) the Seco Catarina Agreement, and (iii) the Seco Comanche Agreement. Each of the agreements that were entered into on June 30, 2020 pursuant to the Settlement Agreement will become effective upon satisfaction of certain closing conditions described in the Settlement Agreement.

On June 23, 2020, certain affiliates of each Occidental Petroleum Corp., The Blackstone Group and GSO Capital Partners each filed a complaint (collectively, the “Rejection Lawsuits”) against Mesquite and certain of its subsidiaries. The commercial agreements contemplated by the Settlement Agreement that the Partnership and its subsidiaries entered into on June 30, 2020 will not become effective until, among other things, the Rejection Lawsuits have been resolved and the Bankruptcy Court has approved the rejection of the certain commercial agreements underlying the Rejection Lawsuits in favor of the SN Debtors. The Rejection Lawsuits were not resolved as of December 31, 2020, and as a result, each of the parties to the Settlement Agreement may terminate the Settlement Agreement at any time pursuant to its terms.

The failure of the Bankruptcy Court to approve the rejection of the certain commercial agreements underlying the Rejection Lawsuits, or the termination of the Settlement Agreement by any party could adversely affect our business, financial condition, cash flows and results of operations.

Risks Related to Our Energy Transition Infrastructure Business

We can provide no assurance that we will be successful in implementing our new energy transition infrastructure business due to competition and other factors, which could limit our ability to grow and extend our dependence on Mesquite and our midstream business.

Part of our new business strategy is to grow our business through the acquisition and development of infrastructure critical to the transition of energy supply to lower carbon sources. This will involve identifying opportunities to offer services to third parties with our existing assets or constructing or acquiring new assets. We are currently pursuing energy transition infrastructure opportunities but we have not yet closed an acquisition or developed infrastructure in connection with this business strategy. We can provide no assurance that we will be successful in implementing our new energy transition infrastructure business, which could limit our ability to grow and extend our dependence on Mesquite and our midstream business. Moreover, we may fail to realize the anticipated benefit of any acquisition we do close, or we may be unable to integrate businesses we acquire effectively. Finally, to the extent that Stonepeak, SP Holdings or our general partner are successful in pursuing energy transition opportunities, there is no guarantee that such opportunities will be offered to us. Please read “—Risks Inherent in an Investment in Our Common Units—Our general partner and its affiliates, including SP Holdings and Stonepeak Catarina, may not allocate corporate opportunities to us.”

​

24

Table of Contents

Risks Related to Our Midstream Business

Mesquite accounts for the majority of our total revenue in general and substantially all of our revenue relating to the operation of our midstream business, as a result, any development that materially and adversely affects Mesquite’s business, financial condition, cash flows or results of operations could have a material and adverse impact on us.

Mesquite is our most significant customer and accounted for approximately 80% of our total revenue and substantially all of our midstream business revenue for the year ended December 31, 2020. We are dependent on Mesquite as our only current customer for utilization of Western Catarina Midstream. In addition, Mesquite is the primary customer for utilization of the Carnero Gathering Line and the Raptor Gas Processing Facility. We expect that a majority of revenues relating to these assets will be derived from Mesquite for the foreseeable future.  As a result, any event, whether in our area of operations or otherwise, that adversely affects Mesquite’s production, drilling and completion schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows could have a material and adverse impact on us.  Accordingly, we are indirectly subject to the business risks of Mesquite, including, among others:

●

a reduction in or slowing of Mesquite’s development program, especially on Mesquite’s Catarina Asset, which would directly and adversely impact demand for our gathering and processing services;

●

a decline in the price of natural gas, NGLs or oil, which have been extremely volatile prior to, and during the pendency of, the COVID-19 pandemic;

●

Mesquite’s ability to finance its operations and development activities;

●

the availability of capital on an economic basis to fund Mesquite’s exploration and development activities;

●

Mesquite’s ability to replace reserves;

●

Mesquite’s drilling and operating risks, including potential environmental liabilities;

●

transportation capacity restraints and interruptions;

●

adverse effects of governmental and environmental regulation; and

●

losses from pending or future litigation, including the Rejection Lawsuits.

Because of the natural decline in production from existing wells, our success depends, in part, on Mesquite’s ability to replace declining production. Any decrease in volumes of natural gas, NGLs and oil that Mesquite produces or any decrease in the number of wells that Mesquite completes could reduce throughput volumes that could adversely affect our business and operating results.

The volumes that support our facilities depend on the level of production from wells connected to our facilities, which may be less than expected and will naturally decline over time. During the year ended December 31, 2020, Mesquite failed to drill the required number of wells on Mesquite’s Catarina Asset, and as a result, Mesquite forfeited acreage not held by production during the year ended December 31, 2020.  This forfeiture will impact Mesquite’s ability to develop additional acreage and replace declining production, which will directly impact revenues for our gathering and processing services.

In addition, volumes from completed wells will naturally decline and our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our facilities, we must obtain new sources of natural gas, NGLs and oil from Mesquite or other third parties. The primary factors affecting our ability to obtain additional sources of natural gas, NGLs and oil include (i) the success of Mesquite’s drilling activity in our areas of operation, (ii) Mesquite’s acquisition of additional acreage and (iii) our ability to obtain additional dedications of acreage from Mesquite or new dedications of acreage from other third parties.

25

Table of Contents

We have no control over Mesquite’s or other producers’ levels of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our facilities or the rate at which production from a well declines. We have no control over Mesquite or other producers or their development plan decisions, which are affected by, among other things:

●

the availability and cost of capital;

●

prevailing and projected prices for natural gas, NGLs and oil;

●

demand for natural gas, NGLs and oil;

●

levels of reserves;

●

geologic considerations;

●

environmental or other governmental regulations, including the availability and maintenance of drilling permits and the regulation of hydraulic fracturing; and

●

the costs of producing natural gas, NGLs and oil and the availability and costs of drilling rigs and other equipment.

Fluctuations in energy prices can also greatly affect the development of reserves. Declines in commodity prices could have a negative impact on Mesquite’s development and production activity, and if sustained, could lead Mesquite to materially reduce its drilling and completion activities. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services.

Due to these and other factors, even if reserves are known to exist in areas served by our facilities, Mesquite and other producers may choose not to develop, or be prohibited from developing, those reserves. If reductions in development activity result in our inability to maintain the current levels of throughput on our facilities, those reductions could adversely affect our business and operating results.

The minimum volume commitment provisions of the Gathering Agreement expired in 2020, which could adversely affect our business, financial condition, cash flows and results of operations.

The term of the minimum volume commitment was the first five years of the 15-year term of the Gathering Agreement.  The minimum volume commitment term expired in 2020. As a result, Mesquite has no contractual commitment with respect to throughput volumes and if Mesquite’s actual throughput volumes are less than anticipated, we will not be entitled to receive any shortfall payments.  If Mesquite’s throughput volumes decrease materially, or if Mesquite ceased shipping throughput volumes on Western Catarina Midstream, it would have a material adverse effect on our business, financial condition, cash flows and results of operations.

Interruptions in operations at our facilities or facilities that Targa operates on behalf of the Carnero JV may adversely affect our business, financial condition, cash flows and results of operations.

Any significant interruption at any of our facilities or the facilities that Targa operates on behalf of the Carnero JV, or in our ability or Targa’s ability on behalf of the Carnero JV, as applicable, to gather, treat or process natural gas, NGLs and oil, would adversely affect our business, financial condition, cash flows and results of operations. Operations at impacted facilities could be partially or completely shut down, temporarily or permanently, as a result of circumstances not within our control, such as:

●

unscheduled turnarounds or catastrophic events at physical plants or pipeline facilities;

●

restrictions imposed by governmental authorities or court proceedings;

●

labor difficulties that result in a work stoppage or slowdown;

26

Table of Contents

●

a disruption or decline in the supply of resources necessary to operate a facility;

●

damage to facilities resulting from natural gas, NGLs and oil that do not comply with applicable specifications; and

●

inadequate transportation or market access to support production volumes, including lack of availability of pipeline capacity.

We may not be able to attract additional third-party volumes, which could limit our ability to grow and would increase our dependence on Mesquite.

Part of our long-term growth strategy includes identifying additional opportunities to offer gathering, processing and transportation services to other third parties. Our ability to increase throughput on our facilities and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when requested by third parties. To the extent that we lack available capacity on our facilities for third-party volumes, we may not be able to compete effectively with third-party gathering or processing systems for additional volumes. In addition, some of our competitors for third-party volumes have greater financial resources and access to larger supplies of oil and natural gas than those available to us, which could allow those competitors to price their services more aggressively than us. Moreover, the underlying lease for the properties on which Western Catarina Midstream is located restricts Western Catarina Midstream to the handling of hydrocarbons produced on the properties covered by the lease.

We may not be able to attract material third-party service opportunities. Our efforts to attract new unaffiliated customers may be adversely affected by (i) certain rights Mesquite has under applicable agreements and, with respect to Western Catarina Midstream, the fact that a substantial portion of the capacity of the facility will be necessary to service Mesquite’s production and development and completion schedule, (ii) the current nature of our facilities, (iii) our desire to provide services pursuant to fee-based contracts and (iv) the existence of current and future dedications to other gatherers by potential third-party customers. As a result, we may not have the capacity or ability to provide services to third parties, or potential third-party customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.

All of our midstream assets are located in the Eagle Ford Shale in Texas, making us vulnerable to risks associated with operating in one major geographic area.

All of our midstream assets are located in the Eagle Ford Shale in Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, market limitations or interruption of the processing or transportation of natural gas, NGLs or oil.

We do not intend to obtain independent evaluations of reserves of natural gas, NGLs and oil reserves connected to Western Catarina Midstream on a regular or ongoing basis; therefore, in the future, volumes of natural gas, NGLs and oil on the gathering system could be less than we anticipate.

We have not obtained and do not intend to obtain independent evaluations of the reserves of natural gas, NGLs and oil, including those of Mesquite, connected to Western Catarina Midstream on a regular or ongoing basis. Moreover, even if we did obtain independent evaluations of the reserves of natural gas, NGLs and oil connected to Western Catarina Midstream, such evaluations may prove to be incorrect. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future 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 some or all of Western Catarina Midstream or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to Western Catarina Midstream are less than we anticipate and we are unable to secure additional sources of natural gas, NGLs and oil, it could adversely affect our business, financial condition, cash flows and results of operations.

27

Table of Contents

A shortage of equipment and skilled labor in the Eagle Ford Shale could reduce equipment availability and labor productivity and increase labor and equipment costs, which could have a material adverse effect on our business and results of operations.

Gathering and processing services require special equipment and laborers skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. Decreased levels of production and shrinking margins from lower commodity prices may result in shortages of equipment and skilled labor in the Eagle Ford Shale, as companies seek to deploy their resources in more profitable basins. If we experience shortages of necessary equipment or skilled labor in the future, our labor and equipment costs and overall productivity could be materially and adversely affected. Material increases in equipment, labor prices or health and benefit costs for employees, could have a material adverse effect on our business and results of operations.

Distributions we receive from the Carnero JV may fluctuate from quarter to quarter, which could adversely affect our cash flows and ability to pay our payables timely.

We received approximately $15.3 million in cash from the Carnero JV in the form of distributions during the year ended December 31, 2020. Targa, as the operator of the Carnero JV, has certain rights which permit it to affect the amount and timing of distributions to us. For example, Targa has certain discretion with regard to cash reserves and working capital adjustments that may cause the amount of our distributions to fluctuate from quarter-to-quarter. Fluctuations in the amount and timing of distributions from the Carnero JV could adversely affect our cash flows and ability to pay our payables timely, including required payments under the Credit Agreement.

Our participation in joint ventures exposes us to liability or harm to our reputation resulting from failures by our joint venture partners.

In May 2018, we executed a series of agreements with Targa and other parties pursuant to which, among other things: (1) the parties merged their respective 50% interests in Carnero Gathering and Carnero Processing to form an expanded 50 / 50 joint venture in South Texas, Carnero JV, (2) Targa contributed 100% of the equity interest in Silver Oak II to Carnero JV, which expanded the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d, (3) Targa contributed certain capacity in the Carnero Gathering Line to Carnero JV resulting in the joint venture owning all of the capacity in the Carnero Gathering Line, which has a design limit (without compression) of 400 MMcf/d, and (4) Carnero JV received a new dedication from Mesquite and its working interest partners of over 315,000 acres located in the Western Eagle Ford on Mesquite’s Comanche Asset pursuant to a new long-term firm gas gathering and processing agreement. We and Targa are jointly and severally liable for all liabilities and obligations of Carnero JV. If Targa fails to perform or is financially unable to bear its portion of required capital contributions or other obligations, including liabilities stemming from claims or lawsuits, we could be required to make additional investments, provide additional services or pay more than our proportionate share of a liability to make up for Targa’s shortfall. Further, if we are unable to adequately address Targa’s performance issues, Mesquite, the main customer on the facilities, may terminate its agreements, which could result in legal liability to us, harm our reputation and reduce cash flows generated from the Carnero Gathering Line and the Raptor Gas Processing Facility.

Increased competition from other companies that provide gathering services could have a negative impact on the demand for our services, which could adversely affect our business, financial condition, cash flows and results of operations.

Our ability to flow a sufficient volume of throughput prior to and after the expiration of the Gathering Agreement to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our facilities compete primarily with other gathering and processing systems. Some competitors have greater financial resources than us and may now, or in the future, have access to greater supplies of natural gas, NGLs and oil than we do. Some of these competitors may expand or construct facilities that would create additional competition for the services that we provide to Mesquite or other future customers. In addition, Mesquite or other future customers may develop their own facilities instead of using our midstream assets.

28

Table of Contents

All of these competitive pressures could make it more difficult for us to retain Mesquite as a customer and/or attract new customers as we seek to expand our business, which could adversely affect our business, financial condition, cash flows and results of operations.

If third-party pipelines or other midstream facilities interconnected to our facilities become partially or fully unavailable, it could adversely affect our business, financial condition, cash flows and results of operations.

Our facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of third-party pipelines, compressor stations and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs or if any of these pipelines or other midstream facilities become unable to receive or transport natural gas, NGLs or oil, it could adversely affect our business, financial condition, cash flows and results of operations.

We do not own the land on which Western Catarina Midstream or the Seco Pipeline is located, which could have a material adverse effect on our business, results of operations and financial condition.

We do not own the land on which Western Catarina Midstream or the Seco Pipeline is located, and we are, therefore, subject to the possibility of more onerous terms 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. We currently have certain rights to construct and operate our pipelines on land owned by third parties for a specific period of time and may need to obtain other rights in the future from third parties and governmental agencies to continue these operations or expand Western Catarina Midstream or the Seco Pipeline. Our loss of these rights or inability to obtain additional rights, through our inability to renew or obtain right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition.

Our right-of-first-offer with Mesquite for midstream assets is subject to risks and uncertainty, and thus may not enhance our ability to grow our business.

Pursuant to a right-of-first-offer, Mesquite has agreed to offer us the right to purchase midstream assets that it desires to transfer to any unaffiliated person through 2030. Mesquite is under no obligation to sell any assets to us or to accept any offer for its assets that we may choose to make. Furthermore, for a variety of reasons, we may decide not to exercise this right when it becomes available.

The acquisition of additional assets in connection with the exercise of our right-of-first-offer will depend upon, among other things, our ability to agree on the price and other terms of the sale, our ability to obtain financing on acceptable terms for the acquisition of such assets and our ability to acquire such assets on the same or better terms than third parties. We can offer no assurance that we will be able to successfully acquire any assets pursuant to this right-of-first-offer.

Our operations could be disrupted if our information systems are hacked or fail, causing increased expenses and loss of revenue.

We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data systems unusable, threats to the security of our facilities and infrastructure, Mesquite’s facilities and infrastructure or other third-party facilities and infrastructure, such as pipelines. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business.

Our business is increasingly dependent on technology infrastructure, certain critical financial, accounting and other data processing systems and other communications and information systems. These systems include data network and telecommunications, internet access, our website, and various computer hardware equipment and software applications, including those that are critical to the safe operations of our assets. We process transactions on a daily basis and rely upon the proper functioning of computer systems. Additionally, we rely on information systems across our operations, including the management of processes and transactions. These systems are subject to damage or interruption from a number of

29

Table of Contents

potential sources including natural disasters, software viruses or other malware, power failures, cybersecurity threats to gain unauthorized access to sensitive information, cyber-attacks, which may render data systems unusable, and physical threats to the security of our facilities and infrastructure or third-party facilities and infrastructure. If a key system were hacked or otherwise interfered with by an unauthorized access, or were to fail or experience unscheduled downtime for any reason, even if only for a short period, our financial results could be affected adversely.

The implementation of social distancing measures and other limitations on our workforce in response to the COVID-19 pandemic have necessitated portions of our workforce switching to remote work arrangements. The increase in companies and individuals working remotely has increased the frequency and scope of cyber-attacks and the risk of potential cybersecurity incidents, both deliberate attacks and unintentional events. While, to date, we have not had a significant cybersecurity breach or attack that had a material impact on our business or results of operations, if we were to be subject to a material successful cyber intrusion, it could result in remediation or service restoration costs, increased cyber protection costs, lost revenues, litigation or regulatory actions by governmental authorities, increased insurance premiums, reputational damage and damage to our competitiveness, financial condition, results of operations and cash flows.

Cyber-attacks against us or others in our industry could result in additional regulations, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches. These attacks may be perpetrated by state-sponsored groups, “hacktivists”, criminal organizations or private individuals (including employee malfeasance). Current efforts by the federal government and any potential future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

Further, our business interruption insurance may not compensate us adequately for losses that may occur. We do not carry insurance specifically for cybersecurity events; however, certain of our insurance policies may allow for coverage of associated damages resulting from such events. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results or operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Risks Related to Our Production Business

Market conditions for natural gas, NGLs and oil are highly volatile. A sustained decline in prices for these commodities could adversely affect our revenue, cash flows, profitability and growth.

Prices for natural gas, NGLs and oil fluctuate widely in response to a variety of factors that are beyond our control, such as:

●

domestic and foreign supply of and demand for natural gas, NGLs and oil;

●

weather conditions and the occurrence of natural disasters;

●

overall domestic and global economic conditions;

●

political and economic conditions in countries producing natural gas, NGLs and oil, including terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war;

●

actions of the Organization of Petroleum Exporting Countries (“OPEC”) and other state-controlled oil companies relating to oil price and production controls;

●

the effect of increasing liquefied natural gas and exports from the United States;

●

the impact of the U.S. dollar exchange rates on prices for natural gas, NGLs and oil;

30

Table of Contents

●

technological advances affecting energy supply and energy consumption;

●

domestic and foreign governmental regulations, including regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells, and taxation;

●

the impact of energy conservation efforts and alternative fuel requirements;

●

the proximity, capacity, cost and availability of production and transportation facilities for natural gas, NGLs and oil;

●

events that impact global market demand, including impacts from global health epidemics and concerns, such as the coronavirus;

●

the availability of refining capacity; and

●

the price and availability of, and consumer demand for, alternative fuels.

Given that natural gas, NGLs and oil are global commodities, prices can also be significantly influenced by developments in other countries and markets, particularly in key consumption markets like China and India.

Governmental actions may also affect prices for natural gas, NGLs and oil. In the past, prices for natural gas, NGLs and oil have been extremely volatile, especially during the pendency of the COVID-19 pandemic, and we expect this volatility to continue. Downward volatility can negatively affect the amount of our net estimated proved reserves and the standardized measure of discounted future net cash flows of our net estimated proved reserves.

In addition, our revenue, profitability and cash flows depend upon the prices of and demand for natural gas, NGLs and oil, and continued price volatility and low commodity prices, or a sustained drop in prices could negatively affect our financial results and impede our growth. In particular, sustained declines in commodity prices will:

●

limit our ability to enter into commodity derivative contracts at attractive prices;

●

reduce the value and quantities of our reserves, because declines in prices for natural gas, NGLs and oil would reduce the amount of natural gas, NGLs and oil that we can economically produce;

●

reduce the amount of cash flows available for capital expenditures;

●

limit our ability to borrow money; and

●

make it uneconomical for our operating partners to commence or continue production levels of natural gas, NGLs and oil.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.

It is not possible to measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels and operating and development costs. Our independent reserve engineers do not independently verify the accuracy and completeness of information and data furnished by us. In estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

●

future oil and natural gas prices;

●

production levels;

31

Table of Contents

●

capital expenditures;

●

operating and development costs;

●

the effects of regulation;

●

the accuracy and reliability of the underlying engineering and geologic data; and

●

the availability of funds.

If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk or recovery and our estimates of the future net cash flows from our reserves could change significantly.

Our standardized measure is calculated using unhedged oil and natural gas prices and is determined in accordance with the rules and regulations of the SEC (except for the impact of income taxes as we are not a taxable entity). Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.

The reserve estimates that we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracies in our estimates of proved reserves, future production rates and the timing of development expenditures.

The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves.

We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

●

the actual prices that are received for oil and natural gas;

●

actual operating costs in producing oil and natural gas;

●

the amount and timing of actual production;

●

the amount and timing of capital expenditures;

●

supply of and demand for oil and natural gas; and

●

changes in governmental regulations or taxation.

The timing of both production and the incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus, their actual present value. In addition, the 10% discount factor used when calculating our discounted future net cash flows in compliance with the Financial Accounting Standard Board’s Accounting Standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and cash flows.

Future price declines or downward reserve revisions may result in write-downs of our asset carrying values, which could adversely affect our results of operations and limit our ability to borrow funds.

Declines in oil and natural gas prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase or production data factors

32

Table of Contents

change, accounting rules may require us to write-down, as a noncash charge to earnings, the carrying value of our properties for impairments. We capitalize costs to acquire, find and develop our oil and natural gas properties under the successful efforts accounting method. We are required to perform impairment tests on our assets periodically and whenever events or circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore would require a write-down. We have incurred impairment charges in the past and may do so again in the future. Any impairment could be substantial and have a material adverse effect on our results of operations in the period incurred and our ability to borrow funds under our Credit Agreement.

We depend on certain key customers for sales of our oil and natural gas. To the extent these and other customers reduce the volumes of oil or natural gas they purchase from us and are not replaced by new customers, our revenues and cash flows could decline.

Our oil and natural gas production in Texas and Louisiana is marketed by the operators of our properties. To the extent these or other customers reduce the volumes of oil and natural gas that they purchase from us and are not replaced by new customers, or the market prices for oil and natural gas decline in our market areas, our revenues and cash flows could decline.

Seasonal weather conditions may adversely affect our ability to conduct production activities, which could adversely impact our cash flows.

Oil and natural gas operations are often adversely affected by seasonal weather conditions, primarily during periods of severe weather or rainfall, and during periods of extreme cold. Power outages and other damages resulting from tornados, ice storms, flooding and other strong storms or weather events may prevent wells from being operated in an optimal manner. These weather conditions may reduce oil and natural gas production, which could adversely impact our cash flows.

Our oil and natural gas properties may be exposed to unanticipated water disposal or processing costs.

Where water produced from properties fails to meet the quality requirements of applicable regulatory agencies or wells produce water in excess of the applicable volumetric permit limit, the wells may have to be shut in or upgraded for water handling or treatment. The costs to treat or dispose of this produced water may increase if any of the following occur:

●

permits cannot be renewed or obtained from applicable regulatory agencies;

●

water of lesser quality or requiring additional treatment is produced;

●

the wells produce excess water; or

●

new laws and regulations require water to be disposed of or treated in a different manner.

Risks Related to Our Midstream and Production Businesses

As a non-operator, our development of successful operations relies extensively on third-parties, including Mesquite and Targa, which could adversely affect our business, financial condition and results of operations.

We have only participated in wells, leasehold acreage and midstream assets operated by third parties, including Mesquite and Targa. The success of our business operations depends on the success of such operators. If our operators are not successful in the development, exploitation, production and operating activities relating to our midstream and production businesses, or are unable or unwilling to perform, it could adversely affect our business, financial condition and results of operations.

The insolvency of an operator of any of our properties or assets, the failure of an operator of any of our properties or assets to adequately perform operations or an operator’s breach of applicable agreements could reduce our production

33

Table of Contents

and revenue and result in our liability to governmental authorities for compliance with environmental, safety and other regulatory requirements, to the operator’s suppliers and vendors and to royalty owners under oil and gas leases jointly owned with the operator or another insolvent owner.

Our operators will make decisions in connection with their operations (subject to their contractual and legal obligations), which may not be in our best interests and could have a material adverse effect on our business, financial condition and results of operations.

Risks Related to Financing and Credit Environment

Our independent registered public accounting firm has expressed doubt about our ability to continue as a going concern.

Our historical consolidated financial statements have been prepared under the assumption that we will continue as a going concern. The report on our audited consolidated financial statements for the year ended December 31, 2020 issued by our independent registered public accounting firm included in this Form 10-K includes an explanatory paragraph referring to the Credit Agreement being a current liability that matures on September 30, 2021 and expressing substantial doubt in our ability to continue as a going concern. Our ability to continue as a going concern is dependent upon our ability to either (i) refinance or extend the maturity of the Credit Agreement, or (ii) obtain adequate new debt or equity financing to repay the Credit Agreement in full at maturity. Our consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. However, if we are unable to refinance or extend the maturity of the Credit Agreement, or otherwise raise adequate funds prior to the maturity date, it will further raise substantial doubt about our ability to continue as a going concern.  The doubt regarding our potential ability to continue as a going concern may adversely affect our ability to obtain new financing on reasonable terms or at all.  Additionally, if we are unable to continue as a going concern, our unitholders may lose some or all of their investment in us.

Our Credit Agreement has substantial prepayment requirements, other restrictions and financial covenants and requires periodic borrowing base redeterminations.

We depend on the Credit Agreement for future capital needs. The Credit Agreement restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. Additionally, the initial aggregate commitment amount is subject to quarterly $10.0 million principal and other mandatory prepayments. We are also required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions, requirements and covenants in the future is uncertain and will be affected by the levels of cash flows from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. Our failure to comply with any of the prepayment requirements, or other restrictions and covenants under the Credit Agreement could result in an event of default, which could cause all of our existing indebtedness to become immediately due and payable. Each of the following is also an event of default:

●

failure to pay any principal when due or any interest, fees or other amount prior to the expiration of certain grace periods;

●

a representation or warranty made under the loan documents or in any report or other instrument furnished thereunder is incorrect when made;

●

failure to perform or otherwise comply with the covenants in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;

●

any event that permits or causes the acceleration of the indebtedness;

●

bankruptcy or insolvency events involving us or our subsidiaries;

●

certain changes in control as specified in the covenants to the Credit Agreement;

34

Table of Contents

●

the entry of, and failure to pay, one or more adverse judgments in excess of $2.5 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal; and

●

specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $2.5 million in any year.

●

failure to comply with the Transaction Covenant (as defined below).

The Credit Agreement will mature on September 30, 2021. We may not be able to renew or replace the facility at similar borrowing costs, terms, covenants, restrictions or borrowing base, or with similar debt issue costs.

The amount available for borrowing at any one time under the Credit Agreement is limited to the separate borrowing bases associated with our oil and natural gas properties and our midstream assets. The borrowing base for the credit available for the upstream oil and natural gas properties is re-determined semi-annually in the second and fourth quarters of the year, and may be re-determined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, using, among other things, the oil and natural gas pricing prevailing at such time. The borrowing base for the credit available for our midstream properties is equal to the rolling four quarter EBITDA of our midstream operations multiplied by 4.5. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders.

Our Credit Agreement contains a condition to borrowing and a representation that no material adverse effect has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations, property, liabilities (actual or contingent) or condition (financial or otherwise) of us and our subsidiaries who are guarantors taken as a whole. If a material adverse effect were to occur, we would be prohibited from borrowing under the Credit Agreement and we would be in default under the Credit Agreement, which could cause all of our existing indebtedness to become immediately due and payable.

The Tenth Amendment contains a new covenant (the “Transaction Covenant”), which provides that we must either (i) engage an investment bank, advisory firm or “sell-side” oil and gas midstream acquisition and divestiture firm (an “Advisory Firm”) to advise us with respect to a possible strategic transaction, which may include a sale of properties or equity interests, an issuance of equity interests in us or a subsidiary or a debt financing transaction (each, a “Qualifying Transaction”), or, (ii) without an Advisory Firm, take material steps towards engaging in a Qualifying Transaction. If we engage an Advisory Firm, then the target closing date for a Qualifying Transaction must be no later than August 31, 2021. If we take material steps on our own, then the target closing date for a Qualifying Transaction must be on or before June 30, 2021 or we must hire an Advisory Firm. In either event, the net cash proceeds must be reasonably expected to be greater than the full amount due under the Credit Agreement on the maturity date. If we are unable to comply with the Transaction Covenant it will be deemed an immediate event of default under the Credit Agreement, which could cause all of our existing indebtedness to become immediately due and payable. Any failure to comply with the Transaction Covenant could have a material and adverse effect on our business, liquidity and cash flows.

We may not be able to extend, replace or refinance our Credit Agreement on terms reasonably acceptable to us, or at all, which could materially and adversely affect our business, liquidity, cash flows and prospects.

Our Credit Agreement matures on September 30, 2021. We may not be able to extend, replace or refinance our existing Credit Agreement on terms reasonably acceptable to us, or at all, with our existing syndicate of banks or with replacement banks. In addition, we may not be able to access other external financial resources sufficient to enable us to repay the debt outstanding under our Credit Agreement upon its maturity. Any of the foregoing could materially and adversely affect our business, liquidity, cash flows and prospects.

35

Table of Contents

Changes in LIBOR reporting practices or the method in which LIBOR is determined may adversely affect the market value of our current or future debt obligations, including obligations under our Credit Agreement.

As of March 16, 2021, we had $104.5 million of debt outstanding under our Credit Agreement that bears interest at variable rates that use the London Interbank Offered Rate (“LIBOR”), as a benchmark rate. On July 27, 2017, the Financial Conduct Authority (the “FCA”), which regulates LIBOR, announced that it intends to stop persuading or compelling banks to submit LIBOR quotations after 2021. The Alternative Reference Rates Committee, a steering committee consisting of large U.S. financial institutions convened by the U.S. Federal Reserve Board and the Federal Reserve Bank of New York, has recommended replacing LIBOR with the Secured Overnight Financing Rate (SOFR), an index supported by short-term Treasury repurchase agreements. On November 30, 2020, ICE Benchmark Administration (“IBA”), the administrator of USD LIBOR announced that it does not intend to cease publication of the remaining USD LIBOR tenors until June 30, 2023, providing additional time for existing contracts that are dependent on LIBOR to mature.

Under our Credit Agreement, if (a) the administrative agent determines that reasonable means do not exist for ascertaining LIBOR and such circumstances are unlikely to be temporary, (b) the supervisor for the administrator of LIBOR or another governmental authority having jurisdiction over the administrative agent has made a public statement identifying a date after which LIBOR shall no longer be used, or (c) new syndicated loans have started to adopt a new benchmark interest rate, then we will be required to negotiate an amendment to our Credit Agreement with the administrative agent. The use of the alternative benchmark interest rate under any such amendment may result in interest obligations which are more than or do not otherwise correlate over time with the payments that would have been made on such debt if LIBOR was available in its current form. Further, the same costs and risks that may lead to the discontinuation or unavailability of LIBOR may make one or more of the alternative methods impossible or impracticable to determine. At this time, it is not possible to predict the effect of any establishment of any alternative benchmark rate(s) and we cannot predict what alternative benchmark rate(s) will be utilized. Any new benchmark rate will likely not replicate LIBOR exactly, and any changes to benchmark rates may have an uncertain impact on our cost of funds under our Credit Agreement. Any of these proposals or consequences could have a material adverse effect on our financing costs.

We will be required to make substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our cash flows may be diminished or our financial leverage could increase.

In order to increase our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations which may diminish our cash flows. To fund our expansion capital expenditures and investment capital expenditures, we will be required to use cash from our operations or incur borrowings. Alternatively, we may sell additional common units or other securities to fund our capital expenditures. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could implement restrictions or limitations on our ability to pay cash distributions. For example, our Credit Agreement currently prohibits us from making distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to make cash distributions to our unitholders in the future, if any, which could materially decrease our ability to pay cash distributions. Stonepeak is not contractually committed to providing any direct or indirect support to fund our growth.

Our ability to access the capital and credit markets to raise capital and borrow on favorable terms will be affected by disruptions in the capital and credit markets, which could adversely affect our operations, our ability to make acquisitions and our ability to pay cash distributions.

Disruptions in the capital and credit markets could limit our ability to access these markets or significantly increase our cost to borrow. Some lenders may increase interest rates, enact tighter lending standards, refuse to refinance existing debt at maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. If we are unable to access the capital markets on favorable terms, our ability to make acquisitions and pay cash distributions could be affected.

36

Table of Contents

We are exposed to credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our customers, vendors, lenders in our Credit Agreement and counterparties to our hedging arrangements. Some of our customers, vendors, lenders and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Despite our credit review and analysis, we may experience financial losses in our dealings with these and other parties with whom we enter into transactions as a normal part of our business activities. Any nonpayment or nonperformance by our customers, vendors, lenders or counterparties could have a material adverse impact on our business, financial condition, results of operations or cash flows.

Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

We may incur substantial additional indebtedness in the future under our Credit Agreement or otherwise. Our future indebtedness could have important consequences to us, including:

●

our ability to obtain additional financing, if necessary, for working capital, maintenance and investment capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

●

covenants and financial tests contained in our existing and future credit and debt instruments may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

●

increased cash flows required to make principal and interest payments on our indebtedness could reduce the funds that would otherwise be available to fund operations, capital expenditures, future business development or any cash distributions; and

●

our debt level may make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

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, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future debt, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms or at all.

Periods of inflation or stagflation, or expectations of inflation or stagflation, could increase our costs and adversely affect our business and operating results.

During periods of inflation or stagflation, our costs of doing business could increase, including increases in the variable interest rates that we pay on amounts we borrow under our Credit Agreement. We have not hedged any of our expected production volumes for 2021, and as a result, the cash flows generated by that future production will be subject to the impact of inflation or stagflation. If any of our operating, administrative or capital costs were to increase as a result of inflation or increase in the cost of goods and services, such a cap could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

An increase in interest rates may cause the market price of our common units to decline and may increase our borrowing costs.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt or other interest-bearing securities may cause a corresponding decline in demand for riskier investments generally, including equity investments such as publicly-traded limited partnership interests. Reduced

37

Table of Contents

demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

Higher interest rates may also increase the borrowing costs associated with our Credit Agreement. If our borrowing costs were to increase, our interest payments on our debt may increase, which would reduce the amount of cash available for our operating or capital activities.

Risks Related to Our Cash Distributions

Our partnership agreement prohibits us from making certain distributions until all of the Class C Preferred Units are redeemed and, as a result, our ability to make, maintain and grow cash distributions to common unitholders is dependent on our ability to redeem the Class C Preferred Units.

Under the terms of our partnership agreement, until the first quarter in which no Class C Preferred Units remain outstanding, we are not permitted to declare or make any distributions, redemptions or repurchases in respect of, among other partnership interests, our common units. As of January 1, 2021, our partnership agreement provides us with the ability to redeem the Class C Preferred Units without a premium to the liquidation preference of the Class C Preferred Units. If we are unable to access the capital markets on favorable terms or otherwise secure debt or equity financing to redeem the Class C Preferred Units, our ability to redeem the Class C Preferred Units and then to make, maintain and grow cash distributions to common unitholders will be materially adversely affected.

Our Credit Agreement restricts us from paying any distributions on our outstanding common units.

We do not have the ability to pay distributions to our common unitholders under our Credit Agreement other than in certain limited circumstances set forth in the Credit Agreement.

Any termination of the Shared Services Agreement requiring the payment of a termination fee may result in substantial dilution and could adversely affect our financial condition, results of operations, operating cash flows and any ability to pay cash distributions.

As previously disclosed and described in more detail in “Part I, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Stonepeak Transactions,” SP Holdings began engaging in non-binding discussions with the Board about terminating or, alternatively, amending and restating the Shared Services Agreement.  If the Shared Services Agreement is terminated, and such termination ultimately requires the payment of a termination fee in cash, which we estimate was in excess of $35.0 million as of December 31, 2020, it could adversely affect our financial condition, results of operations and cash flows. If the Shared Services Agreement is terminated and such termination ultimately requires the payment of a termination fee in common units, then holders of our common units will experience substantial dilution.

If we do not complete expansion projects or make and integrate acquisitions, our future growth may be limited.

Our ability to enhance our financial position depends, in part, on our ability to complete expansion projects and make acquisitions that result in an increase in cash generated. We may be unable to complete successful, accretive expansion projects or acquisitions for any of the following reasons:

●

we are outbid by competitors for potential acquisition candidates;

●

we are unable to identify attractive expansion projects or acquisition candidates;

●

we are unable to obtain necessary rights-of-way or governmental approvals, including from regulatory agencies;

●

we are unable to successfully integrate the businesses that we develop or acquire;

●

we are unable to obtain financing for such expansion projects or acquisitions on economically acceptable terms, or at all;

38

Table of Contents

●

we do not make accurate assumptions about potential volumes, reserves, revenues and costs, including synergies and growth; or

●

we are unable to secure adequate customer commitments to use the newly developed or acquired facilities.

Oil and natural gas prices are very volatile. If commodity prices decline significantly for a temporary or prolonged period, our cash from operations may decline and may adversely affect our financial condition, our results of operations, our profitability and our ability to invest in new midstream facilities.

Our revenue, profitability and operating cash flows depend in part upon the prices and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our operating cash flows and may also impact the fees generated by us from our midstream facilities. In particular, declines in commodity prices will directly reduce the value of our reserves, our operating cash flows, our ability to borrow money or raise capital and may indirectly reduce the cash flows from our midstream facilities. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

●

the domestic and foreign supply of and demand for oil and natural gas;

●

the price and level of foreign imports of oil and natural gas;

●

the level of consumer product demand;

●

weather conditions;

●

overall domestic and global economic conditions;

●

political and economic conditions in oil and natural gas producing countries, including those in West Africa, the Middle East and South America;

●

the ability of members of OPEC to agree to and maintain oil price and production controls;

●

the impact of U.S. dollar exchange rates on oil and natural gas prices;

●

technological advances affecting energy consumption;

●

domestic and foreign governmental regulations and taxation;

●

the impact of energy conservation efforts;

●

the costs, proximity and capacity of oil and natural gas pipelines and other transportation facilities;

●

the price and availability of alternative fuels; and

●

the increase in the supply of natural gas due to the development of natural gas.

In the past, the prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. If commodity prices decline significantly for a temporary or prolonged period, our cash from operations may decline and may adversely affect our financial condition, our results of operations, our profitability and our ability to invest in new midstream facilities.

Acquisitions involve potential risks that could adversely affect our business, financial condition and results of operations.

Any acquisition involves potential risks, including, among other things:

39

Table of Contents

●

the risk of title defects discovered after closing;

●

inaccurate assumptions about revenues and costs, including synergies;

●

significant increases in our indebtedness and working capital requirements;

●

an inability to transition and integrate successfully or timely the businesses we acquire;

●

the cost of transition and integration of data systems and processes;

●

potential environmental problems and costs;

●

the assumptions of unknown liabilities;

●

limitations on rights to indemnity from the seller;

●

the diversion of management’s attention from other business concerns;

●

increased demands on existing personnel and on our organizational structure;

●

disputes arising out of acquisitions;

●

customer or key employee losses of the acquired businesses; and

●

the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Furthermore, our future acquisition costs may be higher than those we have achieved historically. Any of these factors could adversely affect our business, financial condition and results of operations.

Inadequate insurance could have a material adverse impact on our business, financial condition and results of operations.

We ordinarily maintain insurance against certain losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us and we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Additionally, our insurance program may include a number of insurance carriers. Significant disruptions in financial markets could lead to a deterioration in the financial condition of many financial institutions, including insurance companies; therefore, we may not be able to obtain the full amount of our insurance coverage for insured events. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business, financial condition and results of operations.

Risks Related to Regulatory Compliance

Potential regulatory actions could increase our operating or capital costs and delay our operations or otherwise alter the way we conduct our business.

Our business activities are subject to extensive federal, state, and local regulations. Changes to existing regulations or new regulations may unfavorably impact us, our suppliers or our customers. In the United States, legislation that directly impacts the oil and natural gas industry has been proposed covering areas such as emission reporting and reductions, hydraulic fracturing of wells, the repeal of certain oil and natural gas tax incentives and tax deductions and the treatment and disposal of produced water. The EPA has also ruled that carbon dioxide, methane and other greenhouse gases endanger human health and the environment. This allows the EPA to adopt and implement regulations restricting greenhouse gases under existing provisions of the federal Clean Air Act. In addition, provisions of the Dodd-Frank Act, which regulate financial derivatives, may impact our ability to enter into derivatives or require burdensome collateral or reporting requirements. These and other potential regulations could increase our costs, reduce our liquidity, impact our ability to

40

Table of Contents

hedge our future oil and natural gas sales, delay our operations or otherwise alter the way that we conduct our business, negatively impacting our financial condition, results of operations and cash flows.

We are subject to federal, state, and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the production and transportation of oil and natural gas. The possibility exists that any new laws, regulations or enforcement policies could be more stringent than existing laws and could significantly increase our compliance costs.

Our failure to obtain or maintain necessary permits could adversely affect our operations.

Our operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or leases could have a material adverse effect on our ability to develop our properties. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and natural gas we may produce and sell.

Increased regulation of hydraulic fracturing could result in reductions or delays in the production of natural gas, NGLs and oil by Mesquite, which could reduce the throughput on our facilities and adversely impact our revenues.

A substantial portion of Mesquite’s production of natural gas, NGLs and oil is being developed from unconventional sources, such as shale formations. These reservoirs require hydraulic fracturing completion processes to release the liquids and natural gas from the rock so it can flow through casing to the surface. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand (or other proppant) combined with fracturing chemical additives that are pumped at high pressure to crack open previously impenetrable rock to release hydrocarbons. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. Various studies are currently underway by the EPA and other federal and state agencies concerning the potential environmental impacts of hydraulic fracturing activities. For example, the EPA issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act in 2014 requesting comments related to disclosures for hydraulic fracturing chemicals. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of the U.S. Congress to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. Additionally, President Biden has declared that he would support federal government efforts to limit or prohibit hydraulic fracturing. These declarations include threats to take actions banning hydraulic fracturing of crude oil and natural gas wells and banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. We cannot predict whether additional levels of regulations and permits will be required through the adoption of new laws and regulations at the federal or state level, and if so, what the provisions would be. If additional levels of regulation and permits were to be implemented through the adoption of new laws and regulations at the federal or state level, that could lead to delays and process prohibitions that could reduce the volumes of liquids and natural gas that move through our facilities, which in turn could materially adversely affect our revenues and results of operations.

We may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.

As an owner, lessee or operator of gathering pipelines and compressor stations, we are subject to various stringent federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment.  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 response actions. These laws and regulations may impose numerous obligations that are applicable to our and our customer’s 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 or our customers’ operations, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customer’s operations. Failure to comply with these laws, regulations and permits may result in joint and several, strict liability and the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations.

41

Table of Contents

Private parties, including the owners of the properties through which our facilities pass and facilities where wastes resulting from our operations are taken for reclamation or disposal, 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. We may not be able to recover all or any of these costs from insurance, the operators of our facilities and properties or other third parties.  In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.

The operation of our facilities also poses risks of environmental liability due to leakage, migration, releases or spills from our facilities to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in HCAs. The regulations require operators to:

●

perform ongoing assessments of pipeline integrity;

●

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

●

improve data collection, integration and analysis;

●

repair and remediate the pipeline as necessary; and

●

implement preventive and mitigating actions.

The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas.  Should our facilities fail to comply with DOT or comparable state regulations, we could be subject to substantial penalties and fines.

PHMSA has also published advanced notices of proposed rulemaking and notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations as well as advisory bulletins.  In April 2016, PHMSA issued a notice of proposed rulemaking that would expand integrity management requirements and impose new pressure requirements on currently regulated gas transmission pipelines and would also significantly expand the regulation of gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements.  In addition, in 2012, PHMSA issued an advisory bulletin providing guidance on the verification of records related to pipeline maximum allowable operating pressure, which could result in additional requirements for the pressure testing of pipelines or the reduction of maximum operating pressures.  The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital

42

Table of Contents

projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant.  While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flows.  Please read “Item 1. Business—Governmental Regulation—Pipeline Safety Regulation” for more information.

Because we handle oil, natural gas and other petroleum products in our business, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations.

The operations of our wells, gathering systems, processing facilities, pipelines and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations.  Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.  There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle.  Certain environmental statues, including RCRA, CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released.  In addition, an accidental release from one of our facilities 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.

Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, and these costs may not be recoverable from insurance.

Risks Inherent in an Investment in Our Common Units

We are currently not in compliance with the NYSE American listing standards. If our common units are delisted, it could result in even further reductions in the trading price and liquidity of our common units, which could materially adversely affect our ability to raise capital or pursue strategic transactions on acceptable terms, or at all.

Our common units are currently listed on the NYSE American. Continued listing of a security on the NYSE American is conditioned upon compliance with various continued listing standards. On April 3, 2020, we received notice (the “Notice”) from the NYSE American stating that we were below compliance with the continued listing standards as set forth in Part 10 of the NYSE American Company Guide (the “Company Guide”). The Notice provided that the NYSE American’s review of the Partnership showed that we were below compliance with Section 1003(a)(i) of the Company Guide.

The Notice had no immediate effect on our listing on the NYSE American and, therefore, our common units are still listed on the NYSE American, subject to our compliance with other continued listing requirements of the NYSE American. On May 4, 2020, we submitted a plan of compliance (the “Plan”) to the NYSE American addressing how we intend to regain compliance with Section 1003(a)(i) of the Company Guide by October 3, 2021. On June 25, 2020 the Partnership received a letter from the NYSE American stating that the Partnership’s Plan had been accepted and that the Partnership had been granted a plan period through October 3,2021 (the period of time from May 4, 2020 to October 3, 2021 (the “Plan Period”).

By October 3, 2021, we must either be in compliance with Section 1003(a)(i) of the Company Guide or must have made progress that is consistent with the Plan during the Plan Period. In addition, during the Plan Period, we must provide quarterly updates to the NYSE American concurrent with our interim and annual SEC filings. Failure to meet the requirements to regain compliance could result in the initiation of delisting proceedings.

The Notice does not affect our business operations or our reporting obligations under the rules and regulations of the SEC, nor does the Notice conflict with or cause an event of default under any of our material agreements.

43

Table of Contents

If we cannot meet the NYSE American continued listing requirements by the end of the Plan Period, or if the NYSE American is not otherwise satisfied with our progress as of the end of the Plan Period, the NYSE American may delist our common units resulting in our common units trading in the less liquid over-the-counter market, which could have an adverse effect on us and the liquidity and market price of our common units. The delisting of our common units from the NYSE American could result in even further reductions in the trading price of our common units, substantially limit the liquidity of our common units, and materially adversely affect our ability to raise capital or pursue strategic restructuring, refinancing or other transactions on acceptable terms, or at all. Delisting from the NYSE American could also have other negative results, including the potential loss of confidence by vendors and employees, the loss of institutional investor interest and fewer business development opportunities. Our management is considering alternatives to ensure continued compliance with the NYSE American listing standards, but there is no assurance that we will continue to maintain compliance with the NYSE American continued listing standards.

Certain events may result in our general partner exercising its limited call right, which may require common unitholders to sell their common units at an undesirable time or price.

As of March 16, 2021, Stonepeak owned (i) 39,623,443 common units, representing approximately 72.7% of our outstanding common units, (ii) all of our issued and outstanding Class C Preferred Units, (iii) the Warrant that entitled Stonepeak Catarina to receive junior securities of the Partnership (including common units) representing 10% of all junior securities deemed outstanding when exercised, (iv) the non-economic general partner interest in the Partnership and (v) all of our incentive distribution rights.  Stonepeak also owns 100% of the issued and outstanding equity interests in SP Holdings, which is the sole member of our general partner. Pursuant to Section 15.1 of our partnership agreement, if at any time Stonepeak holds more than 80% of our outstanding common units and completes the Stonepeak LCR Transfer (as defined in “Part I, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Stonepeak Transactions), Stonepeak will be able to cause our general partner or a controlled affiliate of our general partner to exercise its right to acquire all, but not less than all, of our common units held by persons other than our general partner and its controlled affiliates at a price equal to the greater of (1) the average of the daily closing price of our common units over the 20 trading days preceding the date three days before notice of exercise of the limited call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its controlled affiliates for common units during the 90-day period preceding the date such notice is first mailed.  As a result, common unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Common unitholders may also incur tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of common units to be repurchased upon exercise of the limited call right. Furthermore, there is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units, including common units issued pursuant to the Stonepeak Letter Agreement (as defined in “Part I, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Stonepeak Transactions) or as a result of the termination or renegotiation of the Shared Services Agreement, and then exercising its limited call right. If our general partner exercises its limited call right, the effect would be to take the Partnership private and, if the common units are subsequently deregistered, the Partnership will no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended.

Stonepeak Catarina and its affiliates, including our general partner, will have conflicts of interest with us. They will not owe any fiduciary duties to us or our common unitholders, but instead will owe us and our common unitholders limited contractual duties, and they may favor their own interests to the detriment of us and our other common unitholders.

Stonepeak Catarina, through its ownership of SP Holdings, owns and controls our general partner and, through the Representation and Standstill Agreement (as defined below) and its ownership of SP Holdings, has the power to appoint all of the directors of our general partner. Although our general partner has a duty to manage us in a manner that is not adverse to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to SP Holdings and its affiliates, including Stonepeak Catarina. Conflicts of interest will arise between Stonepeak Catarina and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Stonepeak over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

44

Table of Contents

●

Neither our partnership agreement nor any other agreement requires Stonepeak to pursue a business strategy that favors us or utilizes our assets. The directors and officers of SP Holdings and its affiliates, including Stonepeak Catarina, have a fiduciary duty to make these decisions in the best interests of the members of SP Holdings and its affiliates, which may be contrary to our interests. Stonepeak may choose to shift the focus of its investment and growth to areas not served by our assets.

●

Our general partner is allowed to take into account the interests of parties other than us, such as Stonepeak Catarina and SP Holdings, in resolving conflicts of interest.

●

SP Holdings and its affiliates, including Stonepeak Catarina, may be constrained by the terms of their respective debt instruments from taking actions, or refraining from taking actions, that may be in our best interests.

●

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limit our general partner’s liabilities and restrict the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

●

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

●

Disputes may arise under our commercial agreements with SP Holdings and its affiliates, including Stonepeak Catarina.

●

Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership units and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash available for distribution.

●

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which will reduce operating surplus, or an expansion or investment capital expenditure, which will not reduce operating surplus. This determination can affect the amount of cash that is distributed.

●

Our general partner determines which costs incurred by it are reimbursable by us, the amount of which is not limited by our partnership agreement.

●

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

●

Our partnership agreement permits us to classify up to $20.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to SP Holdings as the holder of the incentive distribution rights.

●

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

●

Our general partner intends to limit its liability regarding our contractual and other obligations.

●

Our general partner and its controlled affiliates may exercise their right to call and purchase all of the common units not owned by them if they own more than 80% of our common units.

●

Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including the obligations of SP Holdings and Stonepeak Catarina under their commercial agreements with us.

●

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

45

Table of Contents

●

Our general partner may elect to cause us to issue common units to SP Holdings in connection with a resetting of the target distribution levels related to our incentive distribution rights without the approval of the Conflicts Committee or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Our general partner and its affiliates, including SP Holdings and Stonepeak Catarina, may not allocate corporate opportunities to us.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including SP Holdings, its executive officers and directors and Stonepeak Catarina. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us does not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our common unitholders.

Our partnership agreement permits our general partner to redeem any partnership interests held by a limited partner who is an ineligible holder.

If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us or our subsidiaries, or we become subject to federal, state or local laws or regulations that create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, our general partner may redeem the units held by the limited partner at their current market price. In order to avoid any material adverse effect on rates charged or cancellation or forfeiture of property, our general partner may require each limited partner to furnish information about their U.S. federal income tax status or nationality, citizenship or related status. If a limited partner fails to furnish information about their U.S. federal income tax status or nationality, citizenship or other related status after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible holder, our general partner may elect to treat the limited partner as an ineligible holder. An ineligible holder assignee does not have the right to direct the voting of their units and may not receive distributions in kind upon our liquidation.

The market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

The market price of our common units may be influenced by many factors, some of which are beyond our control, including:

●

the resolution of the Rejection Lawsuits and the closing or termination of the Settlement Agreement;

●

provisions in our Credit Agreement which currently prohibit us from paying distributions to our common unitholders other than in certain limited circumstances set forth in our Credit Agreement;

●

our quarterly or annual earnings or those of other companies in our industry;

●

announcements by us or our competitors of significant contracts or acquisitions;

●

changes in accounting standards, policies, guidance, interpretations or principles;

●

general economic conditions, including interest rates and governmental policies impacting interest rates;

●

the failure of securities analysts to cover our common units or changes in financial estimates by analysts;

46

Table of Contents

●

opinions and beliefs on the potential market price of our common units shared on social media channels, such as YouTube and Reddit;

●

future sales of our common units;

●

Stonepeak Catarina is able to elect to receive distributions on the Class C preferred Units in common units for any future quarter; and

●

other factors described in this Form 10-K and the documents incorporated herein.

Our partnership agreement replaces our general partner’s fiduciary duties to our common unitholders with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will fill gaps under the partnership agreement to enforce the reasonable expectations of the partners, but only where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

●

how to allocate business opportunities among us and its other affiliates;

●

whether to exercise its limited call right;

●

whether to seek approval of the resolution of a conflict of interest by the Conflicts Committee; and

●

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

Our partnership agreement restricts the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

The effect of eliminating fiduciary standards in our partnership agreement is that the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law will be significantly restricted. For example, our partnership agreement provides that:

●

whenever our general partner, the Board or any committee thereof (including the Conflicts Committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the Board and any committee thereof (including the Conflicts Committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, and under our partnership agreement, a determination, other action or failure to act by our general partner and any committee thereof (including the Conflicts Committee) will be deemed to be in good faith unless the general partner, the Board or any committee thereof (including the Conflicts Committee) believed that such determination, other action or failure to act was adverse to the interests of the partnership or, with regard to certain determinations by the Board relating to the conflict transactions described below, the Board did not believe that the specified standards were met, and, except as specifically provided by our partnership agreement, neither our general partner, the Board nor any committee thereof (including the Conflicts Committee) will 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;

●

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;

47

Table of Contents

●

our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners 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, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

●

our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

o

approved by the Conflicts Committee of the Board, although our general partner is not obligated to seek such approval;

o

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

o

determined by the Board to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

o

determined by the Board to be 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 determine 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 third and fourth sub-bullets above, then it will be presumed that, in making its decision, the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Furthermore, if any limited partner, our general partner or any person holding any beneficial interest in us brings any claims, suits, actions or proceedings (including, but not limited to, those asserting a claim of breach of a fiduciary duty) and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such limited partner, our general partner or person holding any beneficial interest in us shall be obligated to reimburse us and our “affiliates,” as defined in Section 1.1 of our partnership agreement (including our general partner, the directors and officers of our general partner, and Stonepeak) for all fees, costs and expenses of every kind and description, including, but not limited to, all reasonable attorney’s fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding.

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions and limitations regarding claims, suits, actions or proceedings. By taking ownership of a common unit, a limited partner is irrevocably consenting to these provisions and limitations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue to the fullest extent permitted by applicable law for most claims, suits, actions and proceedings involving us or our officers, directors and employees and limitations regarding claims, suits, actions or proceedings. By taking ownership of a common unit, a limited partner is irrevocably consenting to these provisions and limitations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware, which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment. Furthermore, if any limited partner, our general partner or person holding any beneficial interest in us brings any claims, suits, actions or

48

Table of Contents

proceedings (including, but not limited to, those asserting a claim of breach of a fiduciary duty) and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such limited partner, our general partner or person holding any beneficial interest in us shall be obligated to reimburse us and our affiliates, (as defined in our partnership agreement, which includes our general partner, the directors and officers of our general partner and Stonepeak) for all fees, costs and expenses of every kind and description, including, but not limited to, all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. This provision may have the effect of increasing a unitholder’s cost of asserting a claim and therefore, discourage lawsuits against us and our general partner’s directors and officers. Because fee-shifting provisions such as these are relatively new developments in corporate and partnership law, the enforceability of such provisions are uncertain; in addition, future legislation could restrict or limit this provision of our partnership agreement and its effect of saving us and our affiliates from fees, costs and expenses incurred in connection with claims, actions, suits or proceedings.

Holders of our common units will have limited voting rights and will not be entitled to elect our general partner or its directors.

Our common unitholders have limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s and our general partner’s decisions regarding our business. Common unitholders will have no right on an annual or ongoing basis to elect our general partner or the Board. Rather, the Board will be appointed by Stonepeak Catarina through its ownership of SP Holding. Furthermore, if common unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our common unitholders’ ability to influence the manner or direction of management.

Our partnership agreement restricts the voting rights of common unitholders owning 20% or more of our common units.

Common unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, Stonepeak Catarina, their transferees and persons who acquired such units with the prior approval of the Board, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third-party without unitholder consent.

Our general partner is able to transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of any assets it may own without the consent of our common unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of SP Holdings to transfer its membership interest in our general partner to a third party. The new members of our general partner would then be in a position to replace the directors and officers of our general partner in order to control the decisions taken by the Board or such officers.

The incentive distribution rights held by SP Holdings may be transferred to a third party without unitholder consent.

SP Holdings is able to transfer its incentive distribution rights to a third party at any time without the consent of our common unitholders. If SP Holdings transfers its incentive distribution rights to a third party but retains its ownership interest in our general partner, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if SP Holdings had retained ownership of the incentive distribution rights.

We are able to issue additional units without common unitholder approval, which would dilute unitholder interests.

Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to our common units that we may issue at any time without the approval of our common

49

Table of Contents

unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

●

our existing limited partners’ proportionate ownership interest in us will decrease;

●

the amount of cash available for distribution on each limited partnership interest may decrease;

●

because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;

●

the ratio of taxable income to distributions may increase;

●

the relative voting strength of each previously outstanding limited partner interest may be diminished; and

●

the market price of our common units may decline.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Your 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 and outside of Delaware. 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. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

●

we were conducting business in a state but had not complied with that particular state’s partnership statute; or

●

your 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.

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 Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to you 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. Transferees of common units are liable both for the obligations of the transferor to make contributions to the partnership that were known to the transferee at the time of transfer 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.

50

Table of Contents

The NYSE American does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

Because we are a publicly traded limited partnership, the NYSE American does not require us to have a majority of independent directors on the Board or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE American corporate governance requirements.

Tax Risks

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by states and localities. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation, then our cash available for distribution would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations, we believe that we satisfy the qualifying income requirement and will continue to be treated as a partnership for U.S. federal income tax purposes. Failure to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate income tax rate, and we would also likely pay additional state and local income taxes at varying rates. Distributions to unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits as determined for U.S. federal income tax purposes), and no income, gains, losses, deductions or credits recognized by us would flow through to the unitholders. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be reduced.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of a material amount of any these taxes in the jurisdictions in which we own assets or conduct business could substantially reduce the cash available for distribution to our unitholders.

If we were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction cash flows and after-tax return to our unitholders likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state or local income tax purposes, the minimum quarterly distribution and the target distributions may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative changes or differing judicial interpretation at any time. For example, from time to time members of the U.S. Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. We believe the income that we treat as qualifying satisfies the requirements under current regulations. However, there can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s

51

Table of Contents

interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership for U.S. federal income tax purposes in the future.

We are unable to predict whether legislation or other tax-related proposals will ultimately be enacted. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as a partnership for U.S. federal income tax purposes. Any such change could negatively impact the value of  an investment in our common units.

Our common unitholders’ share of our income will be taxable to them even if they do not receive any cash distributions from us.

Common unitholders are required to pay U.S. federal income and other taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Our Credit Agreement and partnership agreement currently prohibit us from paying distributions to our common unitholders. As a result, for the foreseeable future our common unitholders will not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability due from them with respect to that income.

If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted, and our  cash available for distribution might be substantially reduced.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us.  The IRS may adopt positions that differ from the positions we take.  It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may disagree with some or all of those positions.  Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade.  In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution and thus will be borne indirectly by our unitholders.

Pursuant to legislation applicable for partnership tax years beginning after 2017 if the IRS makes audit adjustments to our partnership tax returns, it may assess and collect any taxes (including any applicable penalties or interest) resulting from such audit adjustments directly from us. To the extent possible under these new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS in the year in which the audit is completed, or, if we are eligible, issue a revised information statement to each current and former unitholder with respect to an audited and adjusted partnership tax return. Although our general partner may elect to have our current and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. If we make payments of taxes and any penalties and interest directly to the IRS in the year in which the audit is completed, our cash available for distribution might be substantially reduced, in which case our current  unitholders may bear some or all of the tax liability resulting from such audit adjustment even if the unitholders did not own units in us during the tax year under audit.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If a common unitholder sells common units, the unitholder will recognize gain or loss equal to the difference between the amount realized and its tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation, depletion and intangible drilling cost recapture. In addition, because the amount realized may include a unitholder’s share of our liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

52

Table of Contents

Unitholders may be subject to limitations on their ability to deduct interest expense we incur.

Our ability to deduct business interest expense is limited for U.S. federal income tax purposes to an amount equal to the sum of our business interest income and a specified percentage of our “adjusted taxable income” during the taxable year, computed without regard to any business interest income or expense, and in the case of taxable years beginning before 2022, any deduction allowable for depreciation, amortization, or depletion. Business interest expense that we are not entitled to fully deduct will be allocated to each unitholder as excess business interest and can be carried forward by the unitholder to successive taxable years and used to offset any excess taxable income allocated by us to the unitholder. Any excess business interest expense allocated to a unitholder will reduce the unitholder’s tax basis in its partnership interest in the year of the allocation even if the expense does not give rise to a deduction to the unitholder in that year.

Tax-exempt entities face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities with multiple unrelated trades or businesses cannot aggregate losses from one unrelated trade or business to offset income from another to reduce total unrelated business taxable income. As a result, it may not be possible for tax-exempt entities to utilize losses from an investment in us to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to income and gain from owning our common units.

Non-U.S. persons are generally taxed and subject to U.S. federal income tax filing requirements on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business.  As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.

The Internal Revenue Code also imposes a U.S. federal income tax withholding obligation of 10% of the amount realized upon a non-U.S. person’s sale or exchange of an interest in a partnership if any portion of the gain on such transfer would be treated as effectively connected income. However, the application of this withholding requirement has been suspended for dispositions of publicly traded partnership interests, including transfers of our common units, that occur before January 1, 2022.  For transfers of common units occurring after December 31, 2021, the amount realized on a transfer of common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and the broker will generally be responsible for the relevant withholding obligations.  Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we have adopted depletion, depreciation and amortization positions that may not conform with all aspects of existing U.S. 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 on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.

​

53

Table of Contents

We prorate our items of income, gain, loss and deduction between transferors and transferees of common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common 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 between transferors and transferees of common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Although Treasury regulations allow publicly traded partnerships to use a similar monthly simplifying convention, these regulations do not specifically authorize all aspects of our proration method.  If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder  may no longer be treated for U.S. federal income tax purposes as a partner with respect to those common 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 common units may not be reportable by the unitholder and any distributions received by the unitholder as to those common units could be fully taxable as ordinary income. 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 with their tax advisor about whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we routinely 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 ourselves using a methodology based on the market value of our common units as a means to determine 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 timing, character or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

As a result of investing in our common units, our unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if they do not reside 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. Furthermore, our unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each unitholder to file all U.S. federal, state and local tax returns that may be required of such unitholder.

54

Table of Contents

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

A description of our properties is included in “Part I, Item 1. Business,” and is incorporated herein by reference.

The obligations under our Credit Agreement are secured by mortgages on substantially all of our assets. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement,” in this Form 10-K for additional information concerning our Credit Agreement.

Item 3. Legal Proceedings

From time to time we may be the subject of lawsuits and claims arising in the ordinary course of business. Management cannot predict the ultimate outcome of such lawsuits or claims. Management does not currently expect the outcome of any of the known claims or proceedings to individually or in the aggregate have a material adverse effect on our results of operations or financial condition.

To date, no claims relating to the Mesquite Chapter 11 Case have been filed against us. However, on March 13, 2020, the official committee of unsecured creditors in the Mesquite Chapter 11 Case (the “Committee”) filed the Motion of the Official Committee of Unsecured Creditors for Leave, Standing, and Authority to Prosecute Claims on Behalf of the Debtors’ Estate and for Related Relief (the “Standing Motion”). In its Standing Motion, the Committee sought, in relevant part, authority from the Court to prosecute certain identified claims against the Partnership, the general partner and Catarina Midstream, LLC (collectively, the “Evolve Parties” and the claims, the “Claims”) that, if valid, belong to Mesquite.

On June 30, 2020, the SN Debtors emerged from the Mesquite Chapter 11 Case, with Mesquite becoming a privately held corporation. Upon emergence, the Claims re-vested, and are owned by, the Reorganized Debtors (as defined in the Plan).  Accordingly, the Committee was dissolved and no longer retains the authority to bring all or a portion of the Claims against the Evolve Parties.  Further, the Settlement Agreement contemplates, in relevant part, the settlement of the Claims between the Reorganized Debtors and the Evolve Parties.  However, the Rejection Lawsuits were not resolved as of October 1, 2020, and as a result the parties to the Settlement Agreement may terminate the Settlement Agreement at any time pursuant to its terms. To date, none of the parties to the Settlement Agreement have provided notice of termination. The settlement of the Claims in accordance with the terms of the Settlement Agreement may be adversely impacted if the Bankruptcy Court does not rule in favor of the SN Debtors in the Rejection Lawsuits.

Item 4. Mine Safety Disclosures

Not applicable.

​

55

Table of Contents

Table of Contents

nor the Shared Services Agreement limits the amount of expenses for which our general partner and its affiliates may be reimbursed.  These expenses may include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates.  Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.  The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates may impact our ability to pay distributions to our unitholders.

●

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Mesquite and its affiliates, if any).

●

Even if our cash distribution policy is not modified or revoked, the decisions regarding the amount of distributions to pay under our cash distribution policy and whether to pay any distribution are determined by our general partner, taking into consideration the terms of our partnership agreement.

●

Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

●

We may lack sufficient cash to pay distributions to our unitholders due to a shortfall in cash flows 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 outstanding debt, tax expenses, working capital requirements or anticipated cash needs.

●

If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels.  We do not anticipate that we will make any distributions from capital surplus.

●

Our ability to make distributions to our unitholders depends on the performance of our assets and subsidiaries and the ability of our subsidiaries to distribute cash to us.  The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state laws and other laws and regulations.

General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Incentive Distribution Rights

All of the incentive distribution rights are held by SP Holdings.  Incentive distribution rights represent the right to receive increasing percentages (13%, 23% and 35.5%) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved.

57

Table of Contents

For any quarter in which we have distributed cash from operating surplus to our common unitholders in an amount equal to the minimum distribution and distributed cash from surplus to the outstanding common units to eliminate any cumulative arrearages in payment of the minimum quarterly distribution, then we will distribute any additional cash from operating surplus for that quarter among the unitholders and the incentive distribution rights holders in the following manner:

​

Securities Authorized for Issuance Under Equity Compensation Plans

See “Part III, Item 12. Security Ownership of Certain Benefits Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plan as of December 31, 2020.

Recent Sales of Unregistered Securities

No unregistered common units were sold by us during the fourth-quarter 2020.

Purchases of Equity Securities by Us and our Affiliates

No common units were repurchased by us during the fourth-quarter 2020.

Default Upon Senior Securities

There were no defaults on senior securities for the years ended December 31, 2020 or 2019.

 Item 6. Selected Financial Data

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required by this Item.

​

58

Table of Contents

Table of Contents

On June 23, 2020, certain affiliates of each Occidental Petroleum Corp., The Blackstone Group and GSO Capital Partners each filed a complaint (collectively, the “Rejection Lawsuits”) against Mesquite and certain of its subsidiaries requesting, among other things, that the Bankruptcy Court not approve the rejection of certain commercial agreements, as set forth in the Settlement Agreement, in connection with Mesquite’s Comanche Asset.

On June 30, 2020, the SN Debtors emerged from the Mesquite Chapter 11 Case, with Mesquite becoming a privately held corporation.

The commercial agreements contemplated by the Settlement Agreement will not become effective until, among other things, the Rejection Lawsuits have been resolved in favor of the SN Debtors and the Bankruptcy Court has approved the rejection of the certain commercial agreements underlying the Rejection Lawsuits. The Rejection Lawsuits were not resolved by October 1, 2020, and as a result the parties to the Settlement Agreement may terminate the Settlement Agreement at any time pursuant to its terms. To date, none of the parties of the Settlement Agreement have provided notice of termination.

Stonepeak Transactions

On September 7, 2020, SP Capital Holdings, LLC (“SP Capital”), SP Common Equity LLC (“SPCE”), and Stonepeak Catarina, entered into a Contribution and Exchange Agreement (the “Contribution Agreement”), pursuant to which (i) SP Capital contributed 100% of the issued and outstanding membership interest in SP Holdings to Stonepeak Catarina, (ii) SPCE irrevocably committed to contribute 100 % of the issued and outstanding membership interests in SP Common Equity Subsidiary LLC (“SPCE Sub”) to Stonepeak Catarina, and (iii) as consideration for the contributions, Stonepeak Catarina issued 10,000 Class B Units in Stonepeak Catarina to SP Capital and 5,000 Class C Units in Stonepeak Catarina to SPCE. Such transactions were completed in their entirety on October 5, 2020. As a result of these transactions, Stonepeak gained control of our general partner and SP Holdings.

Pursuant to our partnership agreement, the general partner conducts, directs and manages all activities of the Partnership under the authority of the Board. Pursuant to the Limited Liability Company Agreement of our general partner, dated March 2, 2015, as amended, SP Holdings appoints all of the members of the Board, other than two directors which Stonepeak is entitled to designate pursuant to the Representation and Standstill Agreement.

On October 6, 2020, Amendment No. 8 to Schedule 13D (the “Catarina 13D”) was filed on behalf of each of (i) SPCE Sub, (ii) Stonepeak Catarina, (iii) Stonepeak Catarina Upper Holdings LLC, (iv) Stonepeak Infrastructure Fund (Orion AIV) LP, (v) Stonepeak Associates LLC, (vi) Stonepeak GP Holdings LP, (vii) Stonepeak GP Investors LLC, (viii) Stonepeak GP Investors Manager LLC, (ix) Michael Dorrell, and (x) Trent Vichie, in it was disclosed that SP Holdings began engaging in non-binding discussions with the Board about terminating or, alternatively, amending and restating the Shared Services Agreement. The Shared Services Agreement can be terminated (i) by either party at any time by 180 days’ prior written notice to the other party, (ii) by SP Holdings if there is an uncured material breach thereunder by the Partnership, or (iii) by the Partnership, subject to Board approval, if (1) there is an uncured material breach thereunder by SP Holdings or (2)  there is a change in control of SP Holdings. Pursuant to the Standstill Agreement, the Partnership must obtain Stonepeak Catarina’s consent to its termination of the Shared Services Agreement. The Shared Services Agreement provides that if there is a termination other than by either party at the end of the Service Agreement’s term, by the Partnership for an uncured breach by SP Holdings, or by the Partnership upon a change of control of SP Holdings, then the Partnership will owe a termination payment to SP Holdings in an amount equal to $5,000,000 plus 5% of the transaction value of all asset acquisitions theretofore consummated. We estimate that this amount was in excess of $35.0 million as of December 31, 2020. Such termination fee may be payable in cash or common units. If the Partnership terminates upon 180 days’ prior notice then the Partnership must also pay to SP Holdings all costs and expenses of SP Holdings that result from such termination.  The Catarina 13D reports that SP Holdings may terminate the Shared Services Agreement upon 180 days’ prior written notice to the Partnership and such termination would trigger the Partnership’s obligation to pay the termination fee in an amount equal to $5,000,000 plus 5% of the transaction value of all asset acquisitions theretofore consummated.  To date, no notice of termination of the Shared Services Agreement has been delivered by SP Holdings.

On November 11, 2020, the Board declared that after establishing a cash reserve for the payment of certain amounts outstanding under the Credit Agreement, the Partnership did not have any available cash and, as a result, there would be no cash distribution on the Partnership’s common units. Section 5.9(b)(ii) of the Amended Partnership Agreement requires

60

Table of Contents

that the quarterly distribution on the Class C Preferred Units be paid in cash, Class C Preferred PIK Units or a combination thereof. On November 16, 2020, the Partnership and Stonepeak Catarina entered into a letter agreement (the “Stonepeak Letter Agreement”) wherein the parties agreed that the distribution on the Class C Preferred Units for the three months ended September 30, 2020 would be paid in common units instead of Class C Preferred PIK Units, cash or a combination thereof.  The Stonepeak Letter Agreement also provides that Stonepeak Catarina will be able to elect to receive distributions on the Class C Preferred Units in common units for any quarter following the third quarter of 2020 by providing written notice to the Partnership no later than the last day of the calendar month following the end of such quarter. The Stonepeak Letter Agreement and the transactions completed therein, including the distribution for the three months ended September 30, 2020 (the “Letter Agreement Transactions”), was referred to the Conflicts Committee of the Board. The Conflicts Committee approved the Letter Agreement Transactions, recommended that the Board approve and authorize the execution and performance of the Letter Agreement Transactions, and verified that their approvals constituted “Special Approval” of the Letter Agreement Transactions under and pursuant to our partnership agreement. Following the approval and recommendation from the Conflicts Committee, the Board approved the Letter Agreement Transactions. The aggregate distribution of 22,274,869 common units was made to Stonepeak Catarina on February 1, 2021, following the satisfaction of certain issuance conditions, including, among other things, the delivery by the Partnership of a fully executed supplemental listing application from the NYSE American approving the issuance of the Stonepeak Common Distribution Units and the compliance by the Partnership and Stonepeak Catarina with any applicable federal securities laws applicable to the issuance of the Stonepeak Common Distribution Units.

On January 28, 2021, Stonepeak Catarina provided us with its notice of election to receive a Common Unit PIK Distribution for the fourth quarter of 2020. The aggregate distribution of 12,445,491 common units was made to Stonepeak Catarina on February 25, 2021, following the satisfaction of certain issuance conditions.

We refer to the foregoing transactions collectively as the “Stonepeak Transactions.”

As a result of the Stonepeak Transactions, as of March 16, 2021, Stonepeak owned (i) 39,623,443 common units, representing approximately 72.7% of our outstanding common units, (ii) all of our issued and outstanding Class C Preferred Units, (iii)  the Warrant that entitled Stonepeak Catarina to receive junior securities of the Partnership (including common units) representing 10% of all junior securities deemed outstanding when exercised, (iv) the non-economic general partner interest in the Partnership and (v) all of our incentive distribution rights.

Pursuant to Section 15.1 of our partnership agreement, if at any time Stonepeak holds more than 80% of our outstanding common units and completes the Stonepeak LCR Transfer, Stonepeak will be able to cause our general partner or a controlled affiliate of our general partner to exercise its right to acquire all, but not less than all, of our common units held by persons other than our general partner and its controlled affiliates (the “limited call right”). Stonepeak would effect any such exercise by first transferring all of the common units held by it to our general partner or a controlled affiliate of our general partner (the “Stonepeak LCR Transfer”) and then causing our general partner to exercise its limited call right at a price equal to the greater of (1) the average of the daily closing price of our common units over the 20 trading days preceding the date three days before notice of exercise of the limited call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its controlled affiliates for common units during the 90-day period preceding the date such notice is first mailed.  As a result, common unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Common unitholders may also incur tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of common units to be repurchased upon exercise of the limited call right. Furthermore, there is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units, including common units issued pursuant to the Stonepeak Letter Agreement or as a result of the termination or renegotiation of the Shared Services Agreement, and then exercising its limited call right. If our general partner exercises its limited call right, the effect would be to take the Partnership private and, if the common units are subsequently deregistered, the Partnership will no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended. As of March 16, 2021, the General Partner and its controlled affiliates do not own any Common Units.

​

61

Table of Contents

Our Relationship with Stonepeak

We have had a relationship with Stonepeak since 2015. Stonepeak has a significant ownership interest in us and our affiliates, including our general partner and SP Holdings, controls us and our general partner and has the ability to appoint all of the members of the Board.

Stonepeak Catarina is indirectly managed by Stonepeak Partners LP, a leading North American infrastructure private equity firm (“Stonepeak Partners”). Stonepeak Partners’ significant infrastructure and midstream energy expertise and deep financial resources are reflected in over $31 billion of assets under management, with to date including, among others, preferred and common interests in the Partnership, MPLX LP, Phillips 66 Partners LP, Plains All American Pipeline, L.P. and Targa Resources Corp.  We believe that, as a result of Stonepeak’s significant ownership interest in us, Stonepeak is incentivized to support and promote our business plan and to encourage us to pursue projects that enhance the overall value of our business.  While our relationship with Stonepeak is a significant strength, it is also a source of potential risks and conflicts. Please read “Part I, Item 1A. Risk Factors—Risks Inherent in an Investment in Our Common Units” and “Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence.”

Business Strategy

Our primary business objective is to create long-term value by generating stable and predictable cash flows that allow us to reduce the amount of our indebtedness and pursue energy transition infrastructure opportunities. We plan to achieve this objective by executing the following business strategy:

●

grow our business through the acquisition and development of infrastructure critical to the transition of energy supply to lower carbon sources;

●

pursue organic investments in our existing operating areas to support growth;

●

pursue strategic relationships with third-party producers and other companies with operations in the area in which we operate in order to maximize the utilization of our midstream facilities or provide other revenue-generating services; and

●

maintain financial flexibility and a strong capital structure.

Business Segments

Our business activities are conducted under two operating segments for which we provide information in our consolidated financial statements for the years ended December 31, 2020 and 2019. These two segments are based on the nature of the operations that are undertaken by each segment and are our:

●

midstream business, which includes Western Catarina Midstream, the Carnero JV and Seco Pipeline (each as defined below); and

●

production business, which includes non-operated oil and natural gas interests located in the Eagle Ford Shale in South Texas and in other areas of Texas and Louisiana.

For information about our segments’ revenues, profits and losses and total assets, see Note 17 “Reporting Segments” of our Notes to Consolidated Financial Statements.

Significant Operational Factors in 2020

Some key highlights of our business activities for the year ended December 31, 2020 were:

●

On Western Catarina Midstream, the Partnership continued the implementation of two tariff rate increases on throughput volumes from the portion of Mesquite’s Catarina Asset which is not currently dedicated under the Gathering Agreement; and

62

Table of Contents

●

For the year ended December 31, 2020, we reduced cash related general and administrative expense by $1.6 million, or 16%, compared to the same period in 2019.

How We Evaluate Our Operations

We evaluate our business on the basis of the following key measures:

●

our throughput volumes on gathering systems upon those assets;

●

our operating expenses; and

●

our Adjusted EBITDA, a non-GAAP financial measure (for a reconciliation of Adjusted EBITDA to the most comparable GAAP financial measure please read “Non-GAAP Financial Measures—Adjusted EBITDA”).

Throughput Volumes

Our management analyzes our performance based on the aggregate amount of throughput volumes on the gathering system. We must connect additional wells or well pads within Mesquite’s Catarina Asset, which is in Dimmit, La Salle and Webb counties in Texas, in order to maintain or increase throughput volumes on Western Catarina Midstream. Our success in connecting additional wells is impacted by successful drilling activity by Mesquite on the acreage dedicated to Western Catarina Midstream, our ability to secure volumes from Mesquite or third parties from new wells drilled on non-dedicated acreage, our ability to attract hydrocarbon volumes currently gathered by our competitors and our ability to cost-effectively construct or acquire new infrastructure. Construction of the Seco Pipeline was completed in August 2017, however, Mesquite does not currently transport any volumes on the Seco Pipeline following termination of the Seco Pipeline Transportation Agreement effective February 12, 2020. Future throughput volumes on the pipeline are dependent on execution of a new transportation agreement with Mesquite or execution of an agreement with a third party.

Operating Expenses

Our management seeks to maximize Adjusted EBITDA, a non-GAAP financial measure, in part by minimizing operating expenses. These expenses are, or will be, comprised primarily of field operating costs (which generally consists of lease operating expenses, labor, vehicles, supervision, transportation, minor maintenance, tools and supplies expenses, among other items), compression expense, ad valorem taxes and other operating costs, some of which will be independent of our oil and natural gas production or the throughput volumes on the midstream gathering system, but fluctuate depending on the scale of our operations during a specific period.

Non-GAAP Financial Measures—Adjusted EBITDA

To supplement our financial results and guidance presented in accordance with U.S. generally accepted accounting principles (“GAAP”), we use Adjusted EBITDA, a non-GAAP financial measure, in this Form 10-K.  We believe that non-GAAP financial measures are helpful in understanding our past financial performance and potential future results, particularly in light of the effect of various transactions effected by us.  We define Adjusted EBITDA as net income (loss) adjusted by: (i) interest (income) expense, net, which includes interest expense, interest expense net (gain) loss on interest rate derivative contracts, and interest (income); (ii) income tax expense (benefit); (iii) depreciation, depletion and amortization; (iv) asset impairments; (v) accretion expense; (vi) (gain) loss on sale of assets; (vii) unit-based compensation expense; (viii) unit-based asset management fees; (ix) distributions in excess of equity earnings; (x) (gain) loss on mark-to-market activities; (xi) commodity derivatives settled early; (xii) (gain) loss on embedded derivatives; and (xiii) acquisition and divestiture costs.  

Adjusted EBITDA is used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts, our lenders and others to assess: (i) the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; (ii) the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and (iii) our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure.

63

Table of Contents

We believe that the presentation of Adjusted EBITDA provides useful information to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss). Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income (loss). Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income (loss). Adjusted EBITDA should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP.  Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

The following table sets forth a reconciliation of Adjusted EBITDA to net income (loss), its most directly comparable GAAP performance measure, for each of the periods presented (in thousands):

Significant Operational Factors

Throughput. The following table sets forth selected throughput data pertaining to the Midstream segment for the years ended December 31, 2020 and 2019:

Production. Our production for the year ended December 31, 2020 was approximately 241 MBoe, or an average of 658 Boe/d, compared to approximately 309 MBoe, or an average of 847 Boe/d, for the same period in 2019.

Capital Expenditures. For the year ended December 31, 2020, we spent approximately $1.9 million in capital expenditures, of which $1.7 million related to the development of the Seco Pipeline. For the year ended December 31, 2019, we spent approximately $0.5 million in capital expenditures, consisting of $0.5 million related to the development of Western Catarina Midstream and less than $0.1 million related to the development of the Seco Pipeline.

Hedging Activities. For the year ended December 31, 2020, the non-cash mark-to-market loss for our commodity derivatives was approximately $0.8 million, compared to a loss of approximately $4.7 million for the same period in 2019.

64

Table of Contents

Table of Contents

Depreciation and amortization expense. Gathering and transportation assets are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 5 to 15 years for equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets. Our depreciation and amortization expense decreased approximately $0.7 million, or 3%, to approximately $20.7 million for the year ended December 31, 2020, compared to approximately $21.4 million during the same period in 2019.  This decrease was due to the impairment of the Seco Pipeline as of December 31, 2019 to a fair value of zero.  As a result of this impairment, there was no depreciation recorded on the Seco Pipeline during the year ended December 31, 2020.

Impairment expense. For the year ended December 31, 2020, our non-cash impairment charge to impair the Seco Pipeline was approximately $0.9 million. During 2020 we made an agreed upon cash settlement related to the original construction of the Seco Pipeline which was impaired to a fair value of zero.  For the year ended December 31, 2019, our non-cash impairment charge to impair the Seco Pipeline was approximately $32.1 million. We received a written notice from Mesquite terminating the Seco Pipeline Transportation Agreement effective as of February 12, 2020.

Earnings from equity investments. Earnings from equity investments increased approximately $1.6 million, or 58%, to earnings of approximately $4.5 million for the year ended December 31, 2020, compared to earnings of approximately $2.8 million for the same period in 2019. This increase in earnings was primarily the result of a reduction in operating expenses at one of the natural gas processing facilities during the year ended December 31, 2020.

Production Operating Results

The following tables set forth the selected financial and operating data pertaining to the Production segment for the periods indicated (in thousands, except net production and average sales and costs):

​	​	​	​	​	​	​	​	​	​	​	​
​	​	Years Ended
​	​	December 31,					​	​	​	​	​
​		2020			2019			Variance
Revenues:	​	​	​	​	​	​	​	​	​	​	​
Natural gas sales at market price	​	$	340	​	$	424	​	$	(84)	​	(20)%
Natural gas hedge settlements	​		313	​		94	​		219	​	NM (a)
Natural gas mark-to-market activities	​	​	(226)	​		165	​	​	(391)	​	NM (a)
Natural gas total	​		427	​		683	​		(256)	​	(37)%
Oil sales	​		7,042	​		13,543	​		(6,501)	​	(48)%
Oil hedge settlements	​		2,829	​		807	​		2,022	​	NM (a)
Oil mark-to-market activities	​		985	​		(4,838)	​		5,823	​	NM (a)
Oil total	​		10,856	​		9,512	​		1,344	​	14%
NGL sales	​		254	​		539	​		(285)	​	(53)%
Total revenues	​		11,537	​		10,734	​		803	​	7%
Operating costs:	​	​	​	​	​	​	​	​	​	​	​
Lease operating expenses	​		5,340	​		5,879	​		(539)	​	(9)%
Production taxes	​		311	​		621	​		(310)	​	(50)%
Depreciation, depletion and amortization	​		2,218	​		3,942	​		(1,724)	​	(44)%
Asset impairments	​		23,355	​	​	—	​	​	23,355	​	NM (a)
Accretion expense	​		212	​		200	​		12	​	6%
Total operating expenses	​		31,436	​		10,642	​		20,794	​	NM (a)
Operating income (loss)	​	$	(19,899)	​	$	92	​	$	(19,991)	​	NM (a)

(a)	Variances deemed to be Not Meaningful “NM.”

66

Table of Contents

(a)	Field operating expenses include lease operating expenses (average production costs) and production taxes.

Production, For the year ended December 31, 2020, 79% of our production was oil, 10% was NGLs and 11% was natural gas compared to the year ended December 31, 2019, where 74% of our production was oil, 14% was NGLs and 12% was natural gas.

Sales of natural gas, NGLs and oil. Unhedged oil sales decreased $6.5 million, or 48%, to $7.0 million for the year ended December 31, 2020, compared to approximately $13.5 million for the same period in 2019. Sales of NGLs decreased approximately $0.3 million, or 53%, to $0.3 million for the year ended December 31, 2020, compared to approximately $0.5 million for the same period in 2019. Unhedged natural gas sales decreased approximately $0.1 million, or 20%, to approximately $0.3 million for the year ended December 31, 2020, compared to approximately $0.4 million for the same period in 2019. The total decrease in sales of natural gas, NGLs and oil for the year ended December 31, 2020 was primarily the result of a decrease in average sales prices.

Including hedges and mark-to-market activities, our total production-related revenue increased approximately $0.8 million for the year ended December 31, 2020. This increase was primarily the result of a reduction in oil sales of approximately $6.5 million offset by an increase in hedge and mark-to-market gains of approximately $7.8 million.