Evolve Transition Infrastructure (SNMP) 10-K 2021 FY Annual report

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, 2021

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):

Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☒ Smaller reporting company ☒ Emerging growth company ☐

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, 2021 was approximately $3,733,555 based upon the NYSE American closing price as of such date.

Common units outstanding on March 29, 2022: 148,951,002 common units.

TABLE OF CONTENTS

		Page
	Part I	7
Item 1.	Business	7
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	47
Item 2.	Properties	47
Item 3.	Legal Proceedings	47
Item 4.	Mine Safety Disclosures	48
	Part II	49
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	49
Item 6.	Selected Financial Data	51
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	52
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	59
Item 8.	Financial Statements and Supplementary Data	60
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	60
Item 9A.	Controls and Procedures	60
Item 9B.	Other Information	61
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	61
	Part III	61
Item 10.	Directors, Executive Officers and Corporate Governance	61
Item 11.	Executive Compensation	66
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	72
Item 13.	Certain Relationships and Related Transactions, and Director Independence	74
Item 14.	Principal Accountant Fees and Services	78
	Part IV	79
Item 15.	Exhibit and Financial Statement Schedules	79
Item 16.	Form 10-K Summary	87
	Signatures	88

i

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:

● “Bankruptcy Court” means that United States Bankruptcy Court for the Southern District of Texas, Houston Division.

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

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

● “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, 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, (x) Tenth Amendment to Third Amended and Restated Credit Agreement, dated as of November 6, 2020, (xi) Eleventh Amendment to Third Amended and Restated Credit Agreement, dated as of July 28, 2021, and (xii) Twelfth Amendment to Third Amended and Restated Credit Agreement, dated as of August 20, 2021.

● “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.

● “Gathering Agreement” means the Firm Gathering and Processing Agreement, dated as of October 14, 2015, by and between Catarina Midstream, LLC and SN Catarina LLC, as amended by Amendment No. 1 thereto, dated June 30, 2017.

● “GHGs” mean greenhouse gases.

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

● “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.

● “MMBtu” means one million British thermal units.

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

2

● “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.

● “NYSE American” means NYSE American LLC.

● “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 amended by Amendment No. 1 thereto, effective as of February 26, 2021.

● “SEC” means the United States Securities and Exchange Commission.

● “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.

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

● “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.

● “Stonepeak Letter Agreement” means that certain letter agreement, dated as of November 16, 2020, by and between the Partnership and Stonepeak Catarina, wherein the parties agreed 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 noticed to the Partnership no later than the last day of the calendar month following the end of such quarter.

● “Stonepeak Warrant” means (i) at all times prior to February 24, 2021, that certain Warrant Exercisable for Junior Securities, issued to Stonepeak Catarina on August 2, 2019 (the “Original Warrant”); (ii) at all times from February 24, 2021 to May 4, 2021, the Original Warrant, as amended by Amendment No. 1 thereto, dated February 24, 2021 (“Warrant Amendment 1”); (iii) at all times from May 4, 2021 to August 2, 2021, the Original Warrant, as amended by Warrant Amendment 1, and Amendment No. 2 thereto, dated May 4, 2021 (“Warrant Amendment 2”); (iv) at all times from August 2, 2021 through November 5, 2021, the Original Warrant, as amended by Warrant Amendment 1, Warrant Amendment 2 and Amendment No. 3 thereto, dated August 2, 2021 (“Warrant Amendment 3”), (v) at all times from November 5, 2021 through November 9, 2021, the Original Warrant, as amended by Warrant Amendment 1, Warrant Amendment 2, Warrant Amendment 3 and Amendment No. 4 thereto, dated November 5, 2021 (“Warrant Amendment 4”); (vi) at all times from November 9, 2021 through February 1, 2022, the Original Warrant, as amended by Warrant Amendment 1, Warrant

3

Amendment 2, Warrant Amendment 3, Warrant Amendment 4 and Amendment No. 5 thereto, dated November 9, 2021 (“Warrant Amendment 5”); and (vii) at all times from February 1, 2022 to present, the Original Warrant, as amended by Warrant Amendment 1, Warrant Amendment 2, Warrant Amendment 3, Warrant Amendment 4, Warrant Amendment 5 and Amendment No. 6 thereto, dated February 1, 2022.

4

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-K contains “forward-looking statements” within the meaning of the federal securities laws. Except for statements of historical fact, all statements in this Form 10-K constitute forward-looking statements.  Forward-looking statements may be identified by words like “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” ��potential,” “pursue,” “target,” “continue,” the negative of such terms or other similar expressions. The absence of such words or expressions does not necessarily mean the statements are not forward-looking.

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:

● our ability to successfully execute our business, acquisition and financing strategies, including our business strategy to focus on the ongoing energy transition in the industries in which we operate;

● our ability to successfully finance and develop the Initial Project (as defined in “Part I, Item 1. Business—Execution of Energy Transition Strategy—HOBO Transaction”) with HOBO Renewable Diesel LLC and meet our future funding obligations in connection with the Levo JV;

● 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 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;

● 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 and energy transition infrastructure industries;

5

● 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;

● unexpected results of litigation filed against us or other legal proceedings we are involved in;

● disruptions due to extreme weather conditions, such as extreme cold, 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.

6

PART I

Item 1.Business

Overview

We are a publicly-traded limited partnership formed in 2005 focused on the acquisition, development, and ownership of infrastructure critical to the transition of energy supply to lower carbon sources. We own natural gas gathering systems, pipelines, and processing facilities in South Texas and continue to pursue energy transition infrastructure opportunities. Our common units are currently listed on the NYSE American under the symbol “SNMP.”

On February 26, 2021, in connection with our management team’s focus on expanding our business strategy to focus on the ongoing energy transition in the industries in which we operate, we changed our name to Evolve Transition Infrastructure LP and our general partner changed its name to Evolve Transition Infrastructure GP LLC.

COVID-19

The outbreak of the COVID-19 pandemic caused incredible disruption to global economic and commercial activity and negatively impacted the global demand for oil and natural gas.  COVID-19 was first reported in December 2019 and has since spread to nearly every country and territory around the globe, 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.  The continuance of the COVID-19 pandemic, including resurgences and variants of the virus, have continued to result in significant business and operational disruptions during 2021. While demand for oil and natural gas improved in 2021, it remains lower than pre-pandemic levels. We continue to evaluate remote work protocols in light of resurgences and variants of the virus and the advisability of continuing in-person operations based on federal, state, and local guidance, and the best interests of our employees, their families, customers and our unitholders.

Our Relationship with Mesquite

On June 6, 2020, the Partnership, our general partner and certain of our subsidiaries entered into the Settlement Agreement. On June 30, 2020, the Bankruptcy Court entered an order approving the Settlement Agreement.

On June 23, 2020, certain affiliates of 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). As of December 2021 all of the Rejection Lawsuits were resolved.

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

On June 24, 2021, the Partnership, our general partner, Catarina Midstream, LLC (“Catarina Midstream”) and Seco Pipeline LLC received written notice from Mesquite, of Mesquite’s intention to terminate the Settlement Agreement (the “Settlement Agreement Termination Notice”). The Settlement Agreement Termination Notice was delivered pursuant to Section 5.1.2 and/or 5.1.3 of the Settlement Agreement and the termination was effective as of the date of the notice.

On October 15, 2021, Mesquite and SN Catarina, LLC (“SN Catarina” and collectively, the “Mesquite Plaintiffs”) initiated adversary proceeding 21-03931 (MI) against the Partnership and Catarina Midstream in the Bankruptcy Court (the “Mesquite Adversary”). In the Mesquite Adversary, the Mesquite Plaintiffs seek recharacterization of the Catarina Transaction (as defined below under “—Midstream Business—Western Catarina Midstream”) as a disguised financing.

7

The Mesquite Plaintiffs claim that SN Catarina is the legal owner of Western Catarina Midstream (as defined below under “—Midstream Business—Western Catarina Midstream”) and demand its return.

The Mesquite Plaintiffs also assert various claims for constructive and actual fraudulent transfer arising from (1) the Catarina Transaction; (2) payments made by SN Catarina to Catarina Midstream under the Gathering Agreement after Catarina Midstream increased tariff rates for interruptible throughput volumes from the eastern portion (“Eastern Catarina”) of Mesquite’s acreage position in Dimmit, La Salle and Webb counties in Texas; and (3) payments made by SN Catarina to Catarina Midstream for the incremental infrastructure fee under the Gathering Agreement amendment and on a month-to-month basis by mutual agreement of the parties after the amendment’s expiration. The Mesquite Plaintiffs seek declaratory relief related to the recharacterization claim as well as avoidance of the alleged constructive and actual fraudulent transfers and recovery of the amounts transferred to Catarina Midstream.

On August 30, 2021, Catarina Midstream, LLC, our wholly owned subsidiary (“Catarina Midstream”), initiated a non-administered arbitration against SN Catarina pursuant to the International Institute for Conflict Prevention & Resolution Non-Administered Arbitration Rules (the “Catarina Arbitration”). In the Catarina Arbitration, Catarina Midstream asserts claims for declaratory judgment and breach of contract arising from SN Catarina’s failure to pay increased tariff rates for interruptible throughput volumes from Eastern Catarina and its refusal to pay the incremental infrastructure fee since July 2021. Catarina Midstream also seeks its attorneys’ fees, costs, and pre- and post-judgment interest from SN Catarina. SN Catarina filed a counterclaim against Catarina Midstream alleging Catarina Midstream’s June 24, 2021 tariff rate increase, and its two prior tariff rate increases under the Gathering Agreement, constitute breaches of contract. SN Catarina also alleges that Catarina Midstream’s continued addition of the incremental infrastructure fee on a month-to-month basis after March 31, 2018 constitutes an additional breach of the Gathering Agreement. SN Catarina seeks declaratory and injunctive relief, monetary damages, and attorneys’ fees and costs.

Execution of Energy Transition Strategy

Levo JV Transaction

On May 17, 2021, we entered into a letter agreement (the “Levo Letter Agreement”) with Nuvve Holding Corp. (“Nuvve Holding”) and Stonepeak Rocket Holdings LP (“Stonepeak Rocket”), relating to the proposed formation of a joint venture, Levo Mobility LLC (“Levo” and such proposed joint venture, the “Levo JV”). In connection with the Levo Letter Agreement, on May 17, 2021, Nuvve Holding issued ten-year warrants to us as follows: (i) Series B Warrants to purchase 200,000 shares of Nuvve Holding’s common stock, at an exercise price of $10.00 per share, which are fully vested upon issuance, (ii) Series C warrants to purchase 100,000 shares of Nuvve Holding’s common stock, at an exercise price of $15.00 per share, which are vested as to 50% of the shares upon issuance and vest as to the remaining 50% when Levo has entered into contracts with third parties for $125 million in aggregate capital expenditures; (iii) Series D warrants to purchase 100,000 shares of Nuvve Holding’s common stock, at an exercise price of $20.00 per share, which are vested as to 50% of the shares upon issuance and vest as to the remaining 50% when Levo has entered into contracts with third parties for $250 million in aggregate capital expenditures; (iv) Series E warrants to purchase 100,000 shares of Nuvve Holding’s common stock, at an exercise price of $30.00 per share, which are vested as to 50% of the shares upon issuance and vest as to the remaining 50% when Levo has entered into contracts with third parties for $375 million in aggregate capital expenditures; and (v) Series F warrants to purchase 100,000 shares of Nuvve Holding’s common stock, at an exercise price of $40.00 per share, which are vested as to 50% of the shares upon issuance and vest as to the remaining 50% when Levo has entered into contracts with third parties for $500 million in aggregate capital expenditures (collectively the “Nuvve Holding Warrants”).

On August 4, 2021, we, Stonepeak Rocket and Nuvve Holding completed the formation of Levo and in connection therewith, we entered into an Amended and Restated Limited Liability Company Agreement for Levo (the “Levo LLC Agreement”). Pursuant to the Levo LLC Agreement, we and Stonepeak Rocket plan to make capital contributions to Levo in an aggregate amount of up to $750 million to finance Levo’s business, with a maximum of $75 million of such capital contributions being funded by us. The membership interests authorized by the Levo LLC Agreement consist of Class A Common Units, Class B Preferred Units, Class C Common Units and Class D Incentive Units. On August 4, 2021 in connection with the signing of the Levo LLC Agreement, Levo issued 2,800 Class B Preferred Units to Stonepeak Rocket, 1 Class B Preferred Unit to us, 441,000 Class C Common Units to Stonepeak Rocket, 49,000 Class C Common Units to us and 510,000 Class A Common Units to Nuvve Holding. Stonepeak Rocket agreed to pay to Levo an aggregate purchase

8

price of $2,800,044.10 for its Class B Preferred Units and Class C Common Units. We agreed to pay to Levo an aggregate purchase price of $1,004.90 for our Class B Preferred Unit and Class C Common Units. Each of us and Stonepeak Rocket are able to receive additional Class B Preferred Units in consideration for each $1,000 in additional capital contributions we make.

HOBO Transaction

On November 3, 2021, we entered into a Framework Agreement (the “Framework Agreement”) with HOBO Renewable Diesel LLC (“HOBO”). The Framework Agreement provides that, subject to the satisfaction of applicable conditions precedent, we will fund certain development expenses of HOBO as HOBO seeks to develop, construct, own and operate renewable fuels facilities. HOBO’s initial project is a 9,000 barrel per day (120 million gallons per year) renewable diesel production facility (the “Initial Project”).

Subject to the satisfaction of certain conditions, including HOBO securing a long-term strategic offtake agreement for the Initial Project, we will exclusively fund the development and construction of the Initial Project and future renewable fuels projects that can produce renewable diesel and sustainable aviation fuel (“SAF”) and contribute to the advancement of the transition to a low-carbon world. Renewable diesel and SAF are unique drop-in fuels that are immediately consumable by existing automotive and airplane engines and reduce carbon emissions relative to petroleum based products. These drop-in fuels are in increasingly high demand by customers, including the US federal government, as more organizations embrace de-carbonization. We and HOBO are also considering incorporation of additional carbon reduction opportunities into the Initial Project and future projects which the management teams believe could result in the production of some of the lowest carbon intensity fuels in the US. We refer to the transactions described above or otherwise contemplated by the Framework Agreement as the “HOBO Transaction.”  As of March 29, 2022, we have not funded any development expenses related to the HOBO Transaction.

In furtherance of the Initial Project and to support our energy transition focus, key members of the HOBO leadership team joined the Partnership’s management team effective December 1, 2021. HOBO Co-Founder and Chief Executive Officer Randy Gibbs was appointed as the new Chief Executive Officer of our general partner, and as a member of the Board, HOBO Co-Founder and President Mike Keuss was appointed as the new President and Chief Operating Officer of our general partner, and HOBO’s Chief Financial Officer Jonathan Hartigan was appointed as the new President and Chief Investment Officer of our general partner (collectively, the “New Executives”).  Each of the New Executives accepted employment with our general partner effective November 3, 2021, and transitioned to their respective director and executive roles effective December 1, 2021.  For additional information about the New Executives please read “Part III, Item 10. Directors, Executive Officers and Corporate Governance.”

2021 Upstream Divestitures

In connection with our focus on the acquisition and development of infrastructure critical to the transition of energy supply to lower carbon sources, during the year ended December 31, 2021, we sold all of our remaining upstream oil and gas production assets in Texas and Louisiana. Each of the purchase agreements we entered into with respect to our Texas production assets (i) had an effective date of March 1, 2021, (ii) contained customary representations, warranties, covenants and indemnities, and (iii) provided that, other than a limited amount of retained obligations, the buyer assumed all obligations relating to the assets purchased.  In September 2021 we sold our remaining de minimis Louisiana assets to the majority owner of such assets for an immaterial amount (the “Louisiana Divestiture”). The Louisiana Divestiture, together with the Palmetto Divestiture, the Maverick 1 Divestiture, the Maverick 2 Divestiture and the Maverick 3 Divestiture (as each is defined below), are collectively referred to in this Form 10-K as the “2021 Upstream Divestitures.”

Palmetto Divestiture

On April 30, 2021, but effective March 1, 2021, SEP Holdings IV, LLC (“SEP IV”), a wholly-owned subsidiary of the Partnership entered into a purchase agreement (the “Palmetto PSA”) with Westhoff Palmetto LP (“Palmetto Buyer”), pursuant to which SEP IV sold to Palmetto Buyer specified wellbores and other associated assets located in Gonzales and Dewitt Counties, Texas for a base purchase price of approximately $11.5 million, prior to applicable post-closing adjustments (the “Palmetto Divestiture”). The Palmetto Divestiture closed simultaneously with the execution of the Palmetto PSA.

9

Maverick Divestiture

On April 30, 2021, but effective March 1, 2021, SEP IV entered into a purchase agreement (the “Maverick PSA”) with Bayshore Energy TX LLC (“Maverick Buyer”), pursuant to which SEP IV sold to Maverick Buyer specified wellbores and other associated assets located in Zavala County, Texas for a base purchase price of approximately $2.8 million, prior to post-closing adjustments (the “Maverick 1 Divestiture”). The Maverick 1 Divestiture closed simultaneously with the execution of the Maverick PSA.

On April 30, 2021, SEP IV entered into a letter agreement with Maverick Buyer (the “Maverick Letter Agreement”) pursuant to which SEP IV agreed to sell additional other specified wellbores and other associated assets located in Zavala and Dimmit Counties, Texas (the “Maverick 2 Assets”) for a base purchase price of approximately $1.4 million (the “Maverick 2 Divestiture”). The closing of the Maverick 2 Divestiture was conditioned upon SEP IV obtaining certain consents and complying with other preferential rights related to the Maverick 2 Assets. Following the entrance into the Maverick Letter Agreement, SEP IV complied with the preferential rights and obtained multiple consents related to the Maverick 2 Assets. SEP IV did not obtain one of the required consents and, as a result, the Maverick 2 Assets subject to such consent were removed from the Maverick 2 Assets included in the Maverick 2 Disposition (the “Updated Maverick 2 Assets”) and the base purchase price was adjusted downward by approximately $31,000.

On May 14, 2021, but effective as of March 1, 2021, SEP IV and Maverick Buyer entered into a purchase agreement (the “Maverick 2 PSA”) pursuant to which SEP IV sold to Maverick Buyer the Updated Maverick 2 Assets. The Maverick 2 Divestiture closed simultaneously with the execution of the Maverick 2 PSA.

On August 13, 2021, but effect as of March 1, 2021, SEP IV and Maverick Buyer entered into a Purchase Agreement (the “Maverick 3 PSA”) pursuant to which SEP IV sold to Maverick Buyer specified wellbores and other associated assets located in Zavala County, Texas, including the Maverick 2 Assets excluded from the original closing of the Maverick 2 Divestiture (the “Maverick 3 Assets”) for a base purchase price of approximately $31,000, prior to post-closing adjustments (the “Maverick 3 Divestiture”). The Maverick 3 Divestiture closed simultaneously with the execution of the Maverick 3 PSA.

Our Relationship with Stonepeak

Since October 14, 2015, Stonepeak Catarina has owned all of our issued and outstanding preferred units. As of March 29, 2022, Stonepeak owned (i) 96,734,084 common units, representing approximately 65% of our outstanding common units, (ii) all of our issued and outstanding Class C Preferred Units, (iii) the Stonepeak Warrant, which entitles 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 $46 billion of assets under management, with investments to date including, among others, preferred and common interests in the Partnership, MPLX 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.”

10

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.

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 the Gathering 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.

All of the revenues from Western Catarina Midstream are currently earned from Mesquite. 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. The incremental infrastructure fee has not been paid since July 2021.

During the year ended December 31, 2021, Mesquite transported average daily production through Western Catarina Midstream of approximately 5.7 MBbls/d of oil, 75.1 MMcf/d of natural gas and 1.9 MBbls/d of water. The average age of the Western Catarina Midstream assets is approximately ten years, and such assets have an average expected life of approximately 19 additional years.

11

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 the Carnero JV Transaction, Comanche volumes were gathered and processed on an interruptible basis, with the processing capabilities limited by the capacity of the 260 MMcf/d cryogenic natural gas processing plant in La Salle County, Texas (the “Raptor Gas Processing Facility”). During the year ended December 31, 2021, certain assets within the Carneno JV were impaired.

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 has an expected life of approximately 40 years and 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”). Mesquite terminated the Seco Pipeline Transportation Agreement on February 12, 2020 and, since such termination, we have not contracted with a customer for transportation on the Seco Pipeline or utilized the pipeline other than transportation of de minimis volumes required to comply with requirements under certain of our rights-of-way.

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.

Marketing and Major Customers

Prior to the completion of the 2021 Upstream Divestitures, our oil and natural gas production in Texas and Louisiana was marketed by the operators of our properties.

Mesquite accounted for 93% and 80% of our total revenue for the years ended December 31, 2021 and 2020, 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.”

12

Markets and Competition

We operate in a competitive environment for acquiring, funding and developing infrastructure assets and properties 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 or properties, more competitively price their gathering and transportation services, 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.

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

13

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 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. States can also impose air

14

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

The U.S. Congress has from time to time considered legislation to reduce emissions of GHGs. The EPA is considering rulemaking proposals in accordance with Executive Order 13990 Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis (“E.O. 13990”) which was signed by President Biden in January 2021 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. In November 2021, EPA proposed rules to reduce methane and other air pollutants from both new and existing sources in the oil and gas industry. 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.

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. 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, E.O. 13990 includes provisions 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.

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

15

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.

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.

16

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.  

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

17

$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 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

18

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 IV, Catarina Midstream and SECO Pipeline, LLC, with payroll, human resources, employee benefits and other consulting services we mutually agree upon with SNMP Services. As of March 29, 2022, fifteen (15) 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 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.

19

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

Item 1A. Risk Factors

Summary of Risk Factors

The following summary outlines our Risk Factors, which we have grouped into risk categories.  These summarized Risk Factors should be read in conjunction with the detailed Risk Factors that follow:

Risks Related to Our Energy Transition Infrastructure Business

● We can provide no assurance that we will be successful in implementing our 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.

● We may be unable to fund our future capital requirements for the Levo JV and the HOBO Transaction.

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.

● Failure to achieve commercial resolution with Mesquite could adversely affect our business, cash flows and results of operations.

● 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.

● 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.

● 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

Risks Related to Financing and Credit Environment

● Our Credit Agreement has substantial prepayment requirements, other restrictions and financial covenants.

● Absent relief, as a result of our failure to timely file a periodic report with the SEC, we are currently ineligible to continue to use or file a registration statement on Form S-3, which may impair our ability to raise capital on terms favorable to us, in a timely manner or at all.

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.

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

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

21

● You will not receive cash distributions on your common units until we are able to redeem 100% of the outstanding Class C Preferred Units, as a result, you are unlikely to receive cash distributions on your common units for the foreseeable future.

● We may be unable to maintain compliance with the NYSE American listing standards. If our common units are delisted, it could adversely affect our business, cash flows and results of operations.

● 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.

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 Our Energy Transition Infrastructure Business

We can provide no assurance that we will be successful in implementing our 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 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.

22

We are currently pursuing energy transition infrastructure opportunities and while we have entered into the Framework Agreement with HOBO and completed the formation of the Levo JV, we have not developed any project in connection with this business strategy. We can provide no assurance that we will be successful in implementing our 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 project under the Framework Agreement , in connection with the Levo JV or any acquisition we make, 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.”

We may be unable to fund our future capital requirements for the Levo JV and the HOBO Transaction.

Upon completion of certain milestones or execution of specific contracts, we will be asked to provide capital to fulfill our funding and reimbursement obligations in connection with the Levo JV and the HOBO Transaction. If we cannot provide capital for such opportunities from cash on hand or borrowings under our Credit Agreement, we may need to raise additional funds through the issuance of securities, including equity, debt or a combination of both. Additional financing may not be available to us on favorable terms, or at all.  If we are unable to access the capital markets and other adequate financing is not available to us on acceptable terms, we may be unable to fund these capital requirements, which could adversely affect our business and limit our ability to expand and grow.

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 93% of our total revenue and substantially all of our midstream business revenue for the year ended December 31, 2021. 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.

23

Failure to achieve commercial resolution with Mesquite could adversely affect our business, cash flows and results of operations.

The Settlement Agreement contemplated, among other things, our entry into Amendment No. 2 to the Gathering Agreement (the “Gathering Agreement Amendment”) providing for, among other things, the dedication of Eastern Catarina by Mesquite and the establishment of field-wide rates.

As a result of our receipt of the Settlement Agreement Termination Notice, the Gathering Agreement Amendment will not become effective. Western Catarina is currently dedicated under the Gathering Agreement. As previously disclosed, on June 24, 2021, we increased the tariff rate for interruptible throughput volumes from Eastern Catarina. Despite the increase, Mesquite continues to short-pay invoices and is currently paying the fees being charged for throughput volumes from Western Catarina for all throughput volumes from Eastern Catarina. As previously disclosed, we are currently engaged in the Catarina Arbitration with Mesquite, which seeks to bring commercial resolution to the tariff rate on Eastern Catarina and all disputed amounts are being held in suspense during the pendency of the Catarina Arbitration. Additionally, we are also involved in the Mesquite Adversary. There can be no guarantee that we are able to reach any commercial resolution and our failure to do so could adversely affect our business, financial condition, cash flows and results of operations.

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.

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.

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

24

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.

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;

● 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 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.

25

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.

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 $15.6 million in cash from the Carnero JV in the form of distributions during the year ended December 31, 2021. 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 resulting in the formation of the Carnero JV. 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 with us, which

26

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.

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 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

27

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 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.

As a result of the COVID-19 pandemic, 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, including the Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure executive order, the issuance of new cybersecurity requirements for critical pipeline owners and operators issued by the Department of Homeland Security’s Transportation Security Administration following a cyberattack on a major petroleum pipeline in 2021, 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.

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 operating activities relating to our midstream business, 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 assets, the failure of an operator of any of our assets to adequately perform operations or an operator’s breach of applicable agreements could reduce our 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 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

28

Our Credit Agreement has substantial prepayment requirements, other restrictions and financial covenants.

We depend on the Credit Agreement for future capital needs. The Credit Agreement contains various covenants that limit, among other things, our ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions to unitholders. The Credit Agreement provides a quarterly amortizing term loan of $65.0 million (the “Term Loan”). The Term Loan is subject to mandatory amortizing payments of outstanding principal of (i) $3.0 million per fiscal quarter commencing with the quarter ended December 31, 2021, and (ii) $2.0 million per fiscal quarter commencing with the quarter ending March 31, 2023. The Credit Agreement matures on September 30, 2023. 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. In addition, 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. 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.

Absent relief, as a result of our failure to timely file a periodic report with the SEC, we are currently ineligible to continue to use or file a registration statement on Form S-3, which may impair our ability to raise capital on terms favorable to us, in a timely manner or at all.

Form S-3 permits eligible issuers to conduct registered offerings using a short form registration statement that allows the issuer to incorporate by reference its past and future filings and reports made under the Exchange Act. In addition, Form S-3 enables eligible issuers to conduct primary offerings under Rule 415 of the Securities Act of 1933, as amended (the “Securities Act”). The shelf registration process, combined with the ability to forward incorporate information, allows issuers to avoid delays and interruptions in the offering process and to access the capital markets in a more expeditions and efficient manner than raising capital in a standard registered offering pursuant to a registration statement on Form S-3. The ability to newly register securities for resale may also be limited as a result of the loss of Form S-3 eligibility with respect to such registrations.

As a result of our failure to timely file certain exhibits required in connection with the filing of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, absent a waiver of the Form S-3 eligibility requirements, we are ineligible to use or file new registration statements on Form S-3 until September 1, 2022. In the event of the absence of a waiver, our S-3 ineligibility may significantly impair our ability to raise necessary capital needed for our business or our obligations under the Levo JV and the HOBO Transaction. If we seek to access the capital markets through a registered offering pursuant to a new registration statement on Form S-1, we would be required to disclose the proposed offering and the material terms thereof before the offering commences. As a result of such disclosure and potential for SEC review of such registration statement on Form S-1, we may experience delays in the offering process and we may incur increased offering and transaction costs and other considerations. If we are unable to raise capital through a registered offering, we would be required to raise capital on a private placement basis, which may be subject to pricing, size and other limitations imposed under NYSE American rules, or seek other sources of capital. In addition, absent a waiver of the Form S-3 eligibility requirements, we will not be permitted to conduct sales of our common units pursuant to the ATM Sales Agreement we entered into with Virtu Americas LLC on April 20, 2021, as such sales must be made by a method that is deemed an “at the market offering” as defined in Rule 415 under the Securities Act.  Any of the foregoing may impair our ability to raise capital on terms favorable to us, in a timely manner or at all.

The expected replacement of the LIBOR benchmark interest rate and other interbank offered rates with new benchmark rates may adversely affect our financing costs.  

As of March 29, 2022, we had $47.7 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

29

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.

The Credit Agreement contains fallback language that seeks to facilitate an agreement with the administrative agent under on a replacement benchmark rate for LIBOR upon the occurrence of certain benchmark transition events or an early opt-in election. Upon the occurrence of one of these triggering events, the administrative agent has the right to make conforming changes to the Credit Agreement to reflect the new benchmark rate. We cannot predict what the impact of any such replacement rate would be to our interest expense, however, the replacement of LIBOR or any other benchmark rates may result in fluctuating interest rates that may have a negative impact on or other 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.

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.

30

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. During periods of inflation, we may be unable to increase profits sufficiently to keep up with the rate of inflation. 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, it 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 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. We currently have 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.

You may continue to experience substantial dilution.

On November 16, 2020, we entered into the “Stonepeak Letter Agreement” wherein we agreed with Stonepeak Catarina that the distribution on their 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 Stonepeak Catarina with the ability 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 us no later than the last day of the calendar month following the end of such quarter. The transactions under the Stonepeak Letter Agreement were approved by the conflicts committee of the Board. As of March 29, 2022, we have issued a total of 91,831,001 common units to Stonepeak Catarina pursuant to the Stonepeak Letter Agreement, which represents all distributions made to Stonepeak Catarina since the third quarter of 2020, and Stonepeak Catarina may continue to elect to receive future distributions on their Class C Preferred Units in common units. Additionally, in order to fulfill our funding

31

and reimbursement obligations in connection with the Levo JV and the HOBO Transaction, we may issue additional common units, which will result in current common unitholders experiencing dilution. As a result of the foregoing, you may experience substantial future 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;

● 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.

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, and the repeal of certain oil and natural gas tax incentives and tax deductions. 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. These and other potential regulations could increase our costs, reduce our liquidity, 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

32

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. 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

33

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 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 “Part I, Item 1. Business—Governmental Regulation—Pipeline Safety Regulation” for more information.

34

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 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 statutes, 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

You will not receive cash distributions on your common units until we are able to redeem 100% of the outstanding Class C Preferred Units, as a result, you are unlikely to receive cash distributions on your common units for the foreseeable future.

Our partnership agreement prohibits us from declaring or making any distributions, redemptions or repurchases in respect of any junior securities or any parity securities until the first quarter in which no Class C Preferred Units remain outstanding. This means that you will not receive any cash distributions on your common units until such time as we are able to redeem all of the outstanding Class C Preferred Units. We currently have the right to redeem 100% of the outstanding Class C Preferred Units for cash at the greater of the current market price or the liquidation preference for the Class C Preferred Units. As of March 29, 2022, the liquidation preference for the Class C Preferred Units was approximately $426.0 million. Our total revenues for the three months ended September 30, 2021 were approximately $16.9 million. As a result, you are unlikely to receive cash distributions on your common units for the foreseeable future.

We may be unable to maintain compliance with the NYSE American listing standards. If our common units are delisted, it could adversely affect our business, cash flows and results of operations.

Our common units are currently listed on the NYSE American. On April 3, 2020, we received notice from the NYSE American stating that we were below compliance with the continued listing standards set forth in Section 1003(a)(i) of the Company Guide. On April 29, 2021, we received a second notice from the NYSE American that we were not in compliance with the continued listing standards set forth in Section 1003(a)(ii) of the Company Guide. On October 4, 2021, the NYSE American informed us that we have regained compliance by meeting the requirements of the $50 million market capitalization exemption from the stockholders’ equity requirement in Section 1003(a) of the Company Guide.

Going forward, we will be subject to the NYSE American’s normal continued listing monitoring. If we are again determined to be below any of the continued listing standards of the NYSE American prior to October 4, 2022, then the NYSE American will examine the relationship between the incidents of noncompliance and re-evaluate our method of financial recovery from the prior incidents. The NYSE American may, among other things, truncate the compliance procedures described in Section 1009 of the Company Guide or immediately initiate delisting proceedings with respect to our common units.

If we are unable to maintain compliance with the NYSE American listing standards, the NYSE American may delist our common units, which could adversely affect our business, cash flows and results of operations.

35

The market price of our common units has been extremely volatile and may continue to be volatile due to numerous circumstances beyond our control.

The market price of our common units has fluctuated, and may continue to fluctuate, widely, due to various factors, many of which are beyond our control. These factors include, without limitation:

● comments by securities analysts or other third parties, including blogs, articles, message boards and social and other media;

● actual or anticipated fluctuations in our financial and operating results;

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

● 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;

● future sales of our common units; and

● other factors described in the documents incorporated by reference herein.

Stock markets in general and our common unit price in particular have recently experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the companies impacted, including us. For example, during the year ended December 31, 2021, our common units have closed at a high of $1.70 per common unit and a low of $0.56 per common unit. In addition, during that same period, daily trading volume ranged from approximately 151,800 to 147,396,400 common units. These broad market fluctuations may adversely affect the trading price of our common units, which may limit or prevent investors from readily selling their common units and may otherwise negatively affect the liquidity of our common units.

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 29, 2022, Stonepeak owned (i) 96,734,084 common units, representing approximately 65% of our outstanding common units, (ii) all of our issued and outstanding Class C Preferred Units, (iii) the Stonepeak Warrant, which entitles 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 III, Item 13. Certain Relationships and Related Transactions, and Director Independence—Certain Transactions with Stonepeak), 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

36

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.

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 in “Part III, Item 10. Directors, Executive Officers and Corporate Governance”) 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:

● 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.

37

● 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.

● 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.

Stonepeak may sell common units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

As of March 29, 2022, Stonepeak owned (i) 96,734,084 common units, representing approximately 65% of our outstanding common units, and (ii) the Stonepeak Warrant, which entitles Stonepeak Catarina to receive junior securities of the Partnership (including common units) representing 10% of all junior securities deemed outstanding when exercised. Additionally, we have agreed to provide Stonepeak Catarina with certain registration rights under applicable securities laws. Pursuant to such registration rights, on November 10, 2021, we filed a Registration Statement on Form S-1 to register 9,000,000 common units for resale by a subsidiary of Stonepeak Catarina, which was declared effective by the SEC on December 17, 2021. The sale of the common units owned by Stonepeak in the public or private markets could have an adverse impact on the price of the common units or on the trading market for our common units.

38

The New Executives have significant duties with, and spend significant time serving, HOBO and may have conflicts of interests in allocating time or pursuing business opportunities.

The New Executives who, together with the Board and our existing officers and employees, will be responsible for managing the direction of our operations, hold positions of responsibility with HOBO and other entities. Subject to restrictions in the Framework Agreement and their respective Executive Services Agreements, the New Executives may pursue other business or investment ventures while employed with us. Additionally, as a result of their ownership of HOBO, the New Executives are incentivized to achieve specific milestones with respect to the Initial Project, which may result in additional time being allocated to the Initial Project and the HOBO Transaction. Accordingly, each of the New Executives may have conflicts of interest in allocating time among various business activities and potentially competitive fiduciary and pecuniary interests that conflict with our interests. These conflicts may not be resolved in our favor.

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.

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.

39

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;

● 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.

40

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 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 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.

41

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.

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 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.

42

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.

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

43

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 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 partnership audit rules 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 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.

44

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.

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. 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.

Moreover, the transferee of an interest in a partnership that is engaged in a United States trade or business is generally required to withhold 10% of the “amount realized” by the transferor unless the transferor certifies that it is not a non-U.S. person.  While the determination of a partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, Treasury Regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. The Treasury Regulations and recent guidance from the IRS further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2023, and after that date, if effected through a broker, the obligation to withhold is

45

imposed on the transferor’s broker. 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.

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.

46

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.

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.

On August 30, 2021, Catarina Midstream initiated a non-administered arbitration against SN Catarina pursuant to the International Institute for Conflict Prevention & Resolution Non-Administered Arbitration Rules (the “Catarina Arbitration”). In the Catarina Arbitration, Catarina Midstream asserts claims for declaratory judgment and breach of contract arising from SN Catarina’s failure to pay increased tariff rates for interruptible throughput volumes from Eastern Catarina and its refusal to pay the incremental infrastructure fee since July 2021. Catarina Midstream also seeks its attorneys’ fees, costs, and pre- and post-judgment interest from SN Catarina. SN Catarina filed a counterclaim against Catarina Midstream alleging Catarina Midstream’s June 24, 2021 tariff rate increase, and its two prior tariff rate increases under the Gathering Agreement, constitute breaches of contract. SN Catarina also alleges that Catarina Midstream’s continued addition of the incremental infrastructure fee on a month-to-month basis after March 31, 2018 constitutes an additional breach of the Gathering Agreement. SN Catarina seeks declaratory and injunctive relief, monetary damages, and attorneys’ fees and costs. The Catarina Arbitration is set for final hearing in August 2022.

On October 15, 2021, the Mesquite Plaintiffs initiated adversary proceeding 21-03931 (MI) against the Partnership and Catarina Midstream in the Bankruptcy Court (the “Mesquite Adversary”). In the Mesquite Adversary, the Mesquite Plaintiffs seek recharacterization of the Catarina Transaction as a disguised financing. The Mesquite Plaintiffs claim that SN Catarina is the legal owner of Western Catarina Midstream and demand its return.

The Mesquite Plaintiffs also assert various claims for constructive and actual fraudulent transfer arising from (1) the Catarina Transaction; (2) payments made by SN Catarina to Catarina Midstream under the Gathering Agreement after Catarina Midstream increased tariff rates for interruptible throughput volumes from Eastern Catarina; and (3) payments made by SN Catarina to Catarina Midstream for the incremental infrastructure fee under the Gathering Agreement amendment and on a month-to-month basis by mutual agreement of the parties after the amendment’s expiration. The Mesquite Plaintiffs seek declaratory relief related to the recharacterization claim as well as avoidance of the alleged constructive and actual fraudulent transfers and recovery of the amounts transferred to Catarina Midstream. The Partnership and Catarina Midstream have filed a Motion to Dismiss the allegations asserted by the Mesquite Plaintiffs.

47

Item 4. Mine Safety Disclosures

Not applicable.

48

PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Our common units are listed on the NYSE American under the symbol “SNMP.”

Holders

The number of unitholders of record of our common units was approximately 40 on March 29, 2022, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or a bank.

Distributions

Rationale for Our Cash Distribution Policy

Our partnership agreement requires us to distribute all of our available cash quarterly.  Our cash distribution policy reflects a fundamental judgment that our unitholders generally will be better served by our distributing rather than retaining our available cash. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in any amount, and our general partner has considerable discretion to determine the amount of our available cash each quarter.  Our partnership agreement generally defines “available cash” as cash on hand at the end of a quarter after the payment of expenses, less the amount of cash reserves established by our general partner to provide for the conduct of our business and to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the next four quarters.  Our available cash may also include, if our general partner so determines, all or any portion of the cash on hand immediately prior to the date of distribution of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.  Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to our unitholders than would be the case if we were subject to entity-level federal income tax.  If we do not generate sufficient available cash from our operations, we may, but are under no obligation to, borrow funds to pay distributions to our unitholders.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will make quarterly cash distributions to our unitholders. We do not have a legal or contractual obligation to pay quarterly distributions or any other distributions except as provided in our partnership agreement.  Our cash distribution policy may be changed at any time and is subject to certain restrictions and uncertainties, including the following:

● Until the first quarter in which no Class C Preferred Units remain outstanding, we are not permitted to declare or make any distributions in respect to our common units.

● Our cash distribution policy is subject to restrictions on distributions under our Credit Agreement, which contains financial tests that we must meet and covenants that we must satisfy.  Should we be unable to meet these financial tests or satisfy these covenants or if we are otherwise in default under our Credit Agreement, we will be prohibited from making cash distributions notwithstanding our cash distribution policy.

● Our general partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy.  Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish.  Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

● Prior to making any distribution on our common units, and pursuant to the Shared Services Agreement, we will pay SP Holdings an administrative fee and reimburse our general partner and its affiliates, including SP Holdings, for all direct and indirect expenses that they incur on our behalf.  Neither our partnership agreement

49

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.

50

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:

		Marginal Percentage Interest
		in Distributions
			Manager
			(as Holder of
	Total Quarterly		Incentive
	Distribution	Common	Distribution
	Per Common Unit	Unitholders	Rights)
Minimum Quarterly Distribution	up to $0.50	100.00%	0.00%
	above $0.50
First Target Distribution	up to	100.00%	0.00%
	$0.575
	above $0.575
Second Target Distribution	up to	87.00%	13.00%
	$0.625
	above $0.625
Third Target Distribution	up to	77.00%	23.00%
	$0.875
Thereafter	above $0.875	64.50%	35.50%

Securities Authorized for Issuance Under Equity Compensation Plans

See “Part III, Item 12. Security Ownership of Certain Benefits Owners and Management and Related Stockholder Matters” for information regarding our equity compensation plan as of December 31, 2021.

Recent Sales of Unregistered Securities

As previously announced, on November 22, 2021, pursuant to the terms of the Stonepeak Letter Agreement, we issued 10,832,186 common units to Stonepeak Catarina in response to Stonepeak Catarina’s election to receive distributions on the Class C Preferred Units for the quarter ended September 30, 2021 in common units. The issuance of these common units was exempt from the registration requirements of the Securities Act pursuant to Section 4(a)(2) thereof as a transaction by an issuer not involve public offering.

Purchases of Equity Securities by Us and our Affiliates

No common units were repurchased by us during the fourth-quarter 2021.

Default Upon Senior Securities

There were no defaults on senior securities for the years ended December 31, 2021 or 2020.

 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.

51

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the financial statements and the summary of significant accounting policies and notes included herein this Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, forecasts, guidance, beliefs and expected performance. The “forward-looking statements” are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these “forward-looking statements”. Please read “Cautionary Note Regarding Forward-Looking Statements.”  

Overview

We are a publicly-traded limited partnership formed in 2005 focused on the acquisition, development and ownership of infrastructure critical to the transition of energy supply to lower carbon sources. We own natural gas gathering systems, pipelines, and processing facilities in South Texas and continue to pursue energy transition infrastructure opportunities. Our common units are currently listed on the NYSE American under the symbol “SNMP.”

On February 26, 2021, in connection with our management team’s focus on expanding our business strategy to focus on the ongoing energy transition in the industries in which we operate, we changed our name to Evolve Transition Infrastructure LP and our general partner changed its name to Evolve Transition Infrastructure GP LLC.

Business Updates

Please read the following subsections contained in “Part I, Item 1. Business” of this Form 10-K for a discussion regarding material updates to our business and operations during the year ended December 31, 2021: “COVID-19,” “Our Relationship with Mesquite,” “Execution of Energy Transition Strategy,” “2021 Upstream Divestitures” and “Our Relationship with Stonepeak.”

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.

52

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 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 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. Please note that the gathering and transportation lease revenues utilized to determine net loss for the year ended December 31, 2021 do not net out the approximately $16.2 million of such revenues that have not been collected from Mesquite.

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.

53

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):

	Years Ended
	December 31,
	2021		2020
Net loss	$	(154,539)	$	(118,761)
Adjusted by:
Interest expense, net		112,969		95,871
Income tax expense (benefit)		393		24
Depreciation, depletion and amortization		20,998		22,873
Asset impairments		—		24,222
Accretion expense		460		567
Gain on sale of assets		(67)		—
Unit-based compensation expense		955		2,602
Unit-based asset management fees		(1,923)		7,245
Distributions in excess of equity earnings		68,389		11,737
(Gain) loss on mark-to-market activities		(664)		(759)
Adjusted EBITDA	$	46,971	$	45,621

Significant Operational Factors

Throughput. The following table sets forth selected throughput data pertaining to the Midstream segment for the years ended December 31, 2021 and 2020:

	Years Ended
	December 31,
	2021	2020
Western Catarina Midstream:
Oil (MBbl/d)	5.7	7.4
Natural gas (MMcf/d)	75.1	93.6
Water (MBbl/d)	1.9	3.1

54

Results of Operations

The following table sets forth the selected financial and operating data pertaining to our continuing operations for the periods indicated (in thousands):

	Years Ended
	December 31,
	2021		2020		Variance
Revenues:
Gathering and transportation sales	$	—	$	785	$	(785)	(100)%
Gathering and transportation lease revenues		51,482		44,671		6,811	15%
Total revenues		51,482		45,456		6,026	13%
Expenses
Operating expenses
Transportation operating expenses		8,501		10,198		(1,697)	(17)%
General and administrative expenses		10,103		18,296		(8,193)	(45)%
Unit-based compensation expense		955		2,602		(1,647)	(63)%
Depreciation and amortization		20,559		20,655		(96)	(0)%
Accretion expense		387		355		32	9%
Total operating expenses		40,505		52,106		(11,601)	(22)%
Other (income) expense
Interest expense, net		112,969		95,871		17,098	18%
Loss (earnings) from equity investment		54,073		(4,479)		58,552	NM (a)
Other income, net		(643)		(71)		(572)	NM (a)
Total other expenses		166,399		91,321		75,078	82%
Total expenses		206,904		143,427		63,477	44%
Loss before income taxes		(155,422)		(97,971)		(57,451)	59%
Income tax (benefit) expense		(5)		159		(164)	NM (a)
Loss from continuing operations		(155,417)		(98,130)		(57,287)	58%
Income (loss) from discontinued operations		878		(19,764)		20,642	(104)%
Net loss	$	(154,539)	$	(117,894)	$	(36,645)	31%

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

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Gathering and transportation lease revenues. Gathering and transportation lease revenues increased approximately $6.8 million, or 15%, to approximately $51.5 million for the year ended December 31, 2021, compared to approximately $44.7 million for the same period in 2020. This increase was primarily the result of an increase in the rate charged for hydrocarbons transported on Western Catarina Midstream that was produced from outside the dedicated acreage under the Gathering Agreement, effective as of July 1, 2021. This increase was partially offset by a decrease in throughput. As discussed in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” SN Catarina has failed to pay the increased rate for the throughput outside the dedicated acreage. For the year ended December 31, 2021, approximately $16.2 million of the gathering and transportation lease revenues are associated with the rate increase.

Transportation operating expenses. Our transportation operating expenses generally consist of equipment rentals, chemicals, treating, metering fees, permit and regulatory fees, labor, minor maintenance, tools, supplies and pipeline integrity management expenses and ad valorem taxes. Our transportation operating expenses decreased by approximately $1.7 million, or 17%, to approximately $8.5 million for the year ended December 31, 2021 compared to approximately $10.2 million for the same period in 2020. This decrease was due to the nature of operating expenses being dependent on throughput.

General and administrative expenses. General and administrative expenses include indirect costs billed by SP Holdings in connection with the Shared Services Agreement, field office expenses, professional fees and other costs not

55

directly associated with field operations. General and administrative expenses decreased by approximately $8.2 million, or 45%, to approximately $10.1 million for the year ended December 31, 2021 compared to approximately $18.3 million for the same period in 2020. The decrease was primarily the result of the mark-to-market impact on indirect costs billed in connection with the Shared Services Agreement of approximately $9.2 million due to the volatility in the market price of our common units during the period. This decrease was partially offset by bad debt expenses of approximately $1.9 million. Cash general and administrative expense for the year ended December 31, 2021 was approximately $10.1 million compared to approximately $10.9 million for the same period in 2020. The decrease in cash general and administrative expenses was primarily the result of lower professional fees when compared to the professional fees attributable to negotiation of the Settlement Agreement and related agreements with Mesquite during the year ended December 31, 2020.

Unit-based compensation expense. Unit-based compensation expense decreased approximately $1.6 million, or 63%, to approximately $1.0 million for the year ended December 31, 2021, compared to approximately $2.6 million for the same period in 2020. The decrease is due to awards vesting during the year ended December 31, 2020.

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 five to 15 years for equipment and up to 36 years for gathering facilities. Our depreciation and amortization expense was consistent for the year ended December 31, 2021 compared to the same period in 2020.

Interest expense, net. Interest expense consists of distributions on the Class C Preferred Units, non-cash accretion of the discount on the Class C Preferred Units, the non-cash change in fair value of the Stonepeak Warrant and cash interest expense from borrowings under the Credit Agreement. Interest expense increased approximately $7.1 million, or 18%, to approximately $113.0 million for the year ended December 31, 2021 compared to approximately $95.9 million for the same period in 2020. This increase was the result of an increase in the number of junior securities deemed outstanding causing the Stonepeak Warrant value to increase and higher distributions on the Class C Preferred Units. Cash interest expense for the year ended December 31, 2021 was approximately $2.6 million compared to approximately $5.2 million for the same period in 2020. This decrease is due to a decrease in the debt balance outstanding under the Credit Agreement between the periods.

Loss (earnings) from equity investment. For the year ended December 31, 2021, the loss from our equity method investment was approximately $54.1 million compared to earnings of approximately $4.5 million for the same period in 2020.  During 2021, an impairment of approximately $55.0 million was recorded as a result of lower expectations regarding volumes and rates associated with the renewal of future expiring contracts and negotiation of new contracts.  Excluding this impairment, our earnings from equity method investment was approximately $0.9 million for the year ended December 31, 2021.  The decrease when compared to the year ended December 31, 2020, was the result of lower margins.

Other income, net. Other income, net includes the mark-to-market impact of the Nuvve Holding Warrants as well as other expenses and income not associated with our operations. Other income, net for the year ended December 31, 2021, was approximately $0.6 million compared to $71 thousand during the year ended December 31, 2020. The primary income for the year ended December 31, 2021, relates to the mark-to-market impact of the Nuvve Holding Warrants which we received in May 2021.

Income tax (benefit) expense. Income tax benefit was approximately $5 thousand for the year ended December 31, 2021, compared to an expense of approximately $159 thousand for the same period in 2020. The decrease in income tax expense resulted from a decrease in taxable margin over the comparable periods.

Liquidity and Capital Resources

As of December 31, 2021, we had approximately $1.7 million in cash and cash equivalents and $5.0 million available for borrowing under the Credit Agreement in effect on such date, as discussed further below.

During the years ended December 31, 2021 and 2020, we paid approximately $2.6 million and approximately $5.2 million, respectively, in cash for interest on borrowings under our Credit Agreement.

56

Our capital expenditures during the year ended December 31, 2021 were funded with cash on hand. In the future, capital and liquidity are anticipated to be provided by operating cash flows, borrowings under our Credit Agreement and proceeds from the issuance of additional debt, additional common units or other limited partner interests.  We expect that the combination of these capital resources will be adequate to meet our short-term working capital requirements and long-term capital expenditures program. However, there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain our current debt level, planned levels of capital expenditures, operating expenses or any cash distributions that we may make to unitholders.

While we cannot predict the duration or complete financial impact of the COVID-19 pandemic and volatile market conditions, we believe that our balances of cash, cash equivalents, cash generated from operations, borrowings under the Credit Agreement and potential issuances of securities will be sufficient to satisfy cash requirements over the next twelve months, including relating to working capital, amortizing debt payments on the Term Loan, and maintenance and expansion capital expenditures.  However, there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain our current debt level, planned levels of capital expenditures, operating expenses.

Credit Agreement

The Credit Agreement provides a quarterly amortizing term loan of $65.0 million (the “Term Loan”) and a maximum revolving credit amount of $5.0 million (the “Revolving Loan”). The Term Loan and Revolving Loan both have a maturity date of September 30, 2023. Borrowings under the Credit Agreement are secured by various mortgages of midstream properties that we own as well as various security and pledge agreements among us, certain of our subsidiaries and the administrative agent.

Borrowings under the Credit Agreement are available for limited direct investment in midstream properties, acquisitions, and working capital and general business purposes. The Credit Agreement has a sub-limit of up to $2.5 million which may be used for the issuance of letters of credit. As of December 31, 2021, we had $49.2 million of debt outstanding, consisting of $49.2 million under the Term Loan with no balance outstanding under the Revolving Loan. We are required to make mandatory amortizing payments of outstanding principal on the Term Loan of (i) $3.0 million per fiscal quarter commencing with the quarter ending December 31, 2021, and (ii) $2.0 million per fiscal quarter commencing with the quarter ending March 31, 2023. As of December 31, 2021, we have met our mandatory amortizing payments of outstanding principal on the Term Loan through March 2022. The maximum revolving credit amount is $5.0 million leaving us with $5.0 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement as of December 31, 2021.

At our election, interest for borrowings under the Credit Agreement are determined by reference to (i) the LIBOR plus an applicable margin between 2.75% and 3.50% per annum based on net debt to EBITDA or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.75% and 2.50% per annum based on net debt to EBITDA plus (iii) a commitment fee of 0.50% per annum based on the unutilized portion of the Revolving Loan. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date.

The Credit Agreement contains various covenants that limit, among other things, our ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions to unitholders.

In addition, we are required to maintain the following financial covenants:

● current assets to current liabilities, excluding any current maturities of debt, of at least 1.0 to 1.0 at all times; and

● senior secured net debt to consolidated adjusted EBITDA for the last twelve months, as of the last day of any fiscal quarter, of not greater than 3.25 to 1.00.

57

The Credit Agreement also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid and a change in control. A change in control is generally defined as the occurrence of one of the following events: (i) our existing general partner ceases to be our sole general partner or (ii) certain specified persons shall cease to own more than 50% of the equity interests of our general partner or shall cease to control our general partner. If an event of default occurs, the lenders will be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies.

Our partnership agreement prohibits us from paying any distributions on our common units until we have redeemed all of the Class C Preferred Units. Following such redemption, the Credit Agreement further limits our ability to pay distributions to unitholders.

At December 31, 2021, we were in compliance with the financial covenants contained in the Credit Agreement. We monitor compliance on an ongoing basis. If we are unable to remain in compliance with the financial covenants contained in our Credit Agreement or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of the Credit Agreement, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated financial covenants from the lenders, but there is no assurance that such waivers would be granted.

Sources of Debt and Equity Financing

As of December 31, 2021, we had approximately $49.2 million of debt outstanding under the Term Loan with no balance outstanding under the Revolving Loan, leaving us with approximately $5.0 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement at December 31, 2021. Our Credit Agreement matures on September 30, 2023.

Operating Cash Flows

We had net cash flows provided by operating activities for the year ended December 31, 2021, of approximately $31.0 million, compared to net cash flows provided by operating activities of approximately $37.9 million for the same period in 2020. This decrease was primarily related to the decrease in throughput between the periods.

Our operating cash flows are subject to many variables, the most significant of which is the volume of oil and natural gas transported through our midstream assets. Our future operating cash flows will depend on oil and natural gas transported through our midstream assets.

Investing Activities

We had net cash flows provided by investing activities for the year ended December 31, 2021, of approximately $15.4 million, substantially all of which were proceeds from the sale of oil and natural gas properties.

Our net cash flows used in investing activities for the year ended December 31, 2020 were approximately $1.9 million, consisting of approximately $1.8 million related to midstream activities, including pipeline construction, and contributions to Carnero JV totaling approximately $0.1 million.

Financing Activities

Net cash flows used in financing activities was approximately $46.4 million for the year ended December 31, 2021. During the year ended December 31, 2021, we repaid $61.8 million of borrowings under the Credit Agreement.

Net cash flows used in financing activities were approximately $39.4 million for the year ended December 31, 2020. During the year ended December 31, 2020, we repaid $39.0 million of borrowings under the Credit Agreement.

58

Credit Markets and Counterparty Risk

We actively monitor the credit exposure and risks associated with our counterparties. Additionally, we continue to monitor global credit markets to limit our potential exposure to credit risk where possible. Our primary credit exposures result from the generation of substantially all of our midstream revenues from a single customer, Mesquite.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States of America. The preparation of the financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the calculation of depletion and impairment of oil and natural gas properties, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.

The policies disclosed included the accounting for oil and natural gas properties, oil and natural gas reserve quantities, revenue recognition and hedging activities. Please read Note 2 “Basis of Presentation and Summary of Significant Accounting Policies” to our consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Gathering and Transportation Assets

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 three to 15 years for furniture and equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets.

Estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over the useful life of the asset. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

We perform a periodic assessment of gathering and transportation assets to identify facts and circumstances, or triggering events, that indicate the carrying value may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our gathering and transportation assets and the recognition of additional impairments. Refer to Note 8 “Gathering and Transportation Related Assets” to our consolidated financial statements for additional information.

Recent Accounting Pronouncements and Accounting Changes

See Note 2 “Basis of Presentation and Summary of Significant Accounting Policies” to our consolidated financial statements included in this report for information on new accounting pronouncements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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.

59

Item 8. Financial Statements and Supplementary Data

The information required by this Item is included in this report as set forth in the “Index to Consolidated Financial Statements” beginning on page F-1 of this Form 10-K and is incorporated by reference herein.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, with the Partnership have been detected. These inherent limitations include error by personnel in executing controls due to faulty judgment or simple mistakes, which could occur in situations such as when personnel performing controls are new to a job function or when inadequate resources are applied to a process. Additionally, controls can be circumvented by the individual acts of some persons or by collusion of two or more people.

The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no absolute assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions or personnel, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. The principal executive officer and principal financial officer of our general partner have concluded that our current disclosure controls and procedures were effective as of December 31, 2021 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

During the three months ended December 31, 2021, there were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Reports of Management

Financial Statements

The management of our general partner is responsible for the information and representations in our financial statements. We prepare the financial statements in accordance with accounting principles generally accepted in the United States of America based upon available facts and circumstances and management’s best estimates and judgments of known conditions.

60

The Audit Committee, which consists of two independent directors, meets periodically with management, our internal auditor and KPMG LLP to review the activities of each in discharging their responsibilities. Our internal auditor and KPMG LLP have free access to the Audit Committee.

Management’s Report on Internal Control Over Financial Reporting

Our management, under the direction of the principal executive officer and principal financial officer of our general partner, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Exchange Act.

Our system of internal control over financial reporting is designed to provide reasonable assurance to our management and the Board regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America.

The management of our general partner conducted an evaluation of the effectiveness of our internal control over financial reporting using the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). As noted in the COSO framework, an internal control system, no matter how well conceived and operated, can provide only reasonable-not absolute-assurance to management and the Board regarding achievement of an entity’s financial reporting objectives. Based upon the evaluation under this framework, management concluded that our internal control over financial reporting was effective as of December 31, 2021.

Report of Independent Registered Public Accounting Firm

Please see Report of Independent Registered Public Accounting Firm beginning on Page F-2 of this Form 10-K.

Item 9B. Other Information

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The following table shows information for members of the Board and the executive officers of our general partner as of March 29, 2022.  All of the directors of our general partner are elected by SP Holdings, as the sole member of our general partner, except for two persons who are appointed by Stonepeak Catarina pursuant to the Representation and Standstill Agreement. Members of the Board hold office until their successors have been elected or qualified or until the earlier of their death, incapacity, resignation or removal.  Executive officers hold office at the discretion of, and may be removed by, the Board.

Name	Age	Position with Evolve Transition Infrastructure LP
Randall L. Gibbs	70	Chief Executive Officer and Director
Charles C. Ward	61	Chief Financial Officer and Secretary
Michael A. Keuss	53	President and Chief Operating Officer
Jonathan C. M. Hartigan	43	President and Chief Investment Officer
Michael Bricker	33	Director
Jack Howell	35	Director
Richard S. Langdon	71	Independent Director
Steven E. Meisel	37	Independent Director
John T. Steen III	41	Director; Chairman of the Board
Luke R. Taylor	44	Director

61

Randall L. Gibbs, 70, was elected as a member of the Board and Chief Executive Officer in December 2021. Mr. Gibbs brings to the General Partner forty years’ experience in the energy industry, with twenty years on the energy commodity trading and marketing side as a founding partner of Texport Oil LP, a trader and gasoline blender focused on refined products distribution in the Northeast United States and Canada, including New York Harbor, and the last twenty years in energy infrastructure development and operations across the broad energy spectrum. From August 2019 to present, Mr. Gibbs has served as a co-founder and Chief Executive Officer of HOBO, a privately-owned energy infrastructure developer, where Mr. Gibbs co-manages the company and its business development activities with a specific focus on corporate strategy, commercial agreements and structured finance, including development of the relationship with Stonepeak and Evolve. Prior to his work with HOBO, beginning in 2001, Mr. Gibbs was sole owner and Chief Executive Officer of Multifuels LP (“Multifuels”), a privately-owned energy infrastructure developer, which Mr. Gibbs founded. Multifuels developed pipelines, terminals, natural gas storage and various forms of renewables under Mr. Gibbs’ direction, including Freebird Natural Gas Storage (“Freebird”) a depleted reservoir FERC certified storage facility connected to the Tennessee Gas Pipeline (500 Leg) by a lateral pipeline entirely developed, constructed and operated by Multifuels in partnership with private equity sponsorship in 2006 until its sale in 2008. More recently, Multifuels, in a combination of transactions, developed, acquired, reconfigured, constructed and operated approximately 150 miles of natural gas pipeline laterals in central Texas primarily serving a large public utility and collectively operating as Multifuels Midstream Group LLC. Multifuels and its private equity partner sold this business in a transaction with Macquarie Principal Finance, Inc. Mr. Gibbs is also presently the majority owner of Victory Solar LLC, a Texas based solar sales and installation company operating in Texas, Florida, Virginia and North Carolina.

Charles C. Ward, 61, was elected Chief Financial Officer and Secretary of our general partner in March 2015.  Mr. Ward previously served as Chief Financial Officer and Treasurer of Sanchez Production Partners LLC from March 2008 until its conversion to a limited partnership in March 2015 and Secretary from July 2014 until March 2015.  Mr. Ward also served as a Vice President of Constellation Energy Commodities Group, Inc. from November 2005 until December 2008.  Prior to that time, he was a Vice President of Enron Creditors Recovery Corp. from March 2002 to November 2005.

Michael A. Keuss, 53, was elected President and Chief Operating Officer in December 2021. Mr. Keuss has extensive experience in management, manufacturing, trading and business development in the renewable fuels, chemical and petroleum refining industries. From August 2019 to present, Mr. Keuss has served as a co-founder and President of HOBO, where Mr. Keuss co-founded and co-manages the company and its business development activities and utilizes his extensive experience in marketing, trading and engineering to further the development of multiple potential renewable diesel and sustainable aviation fuels projects. From June 2018 to August 2019, Mr. Keuss served as a founder, officer and director of Aristide Energy Corporation, a privately-owned energy trading company (“Aristide”). At Aristide, Mr. Keuss developed a renewable fuels trading company in Houston with a complimentary recycling manufacturing facility and engineering services division. From 2011 to 2018, Mr. Keuss served as Vice President of Business Development for Kolmar Group, where he developed a biodiesel business platform that traded and blended biodiesel. Over the course of 2½ years, Mr. Keuss also managed and engineered the transformation of the American Green Fuels biodiesel facility from a soy-only operation to a multi-feedstock operation as of early 2018. From 2000 to 2010, Mr. Keuss worked for LyondellBasell, a multinational publicly traded corporation, and Musket Corporation, a privately held company, where he held various marketing roles, primarily in the physical trading of gasoline, diesel and natural gas, and a short period as a business analyst. From 1991 to 1999, Mr. Keuss held various engineering, operations and management roles for crude refining operations for Valero Energy and Mobil Corporation.

Jonathan C. M. Hartigan, 43, was elected President and Chief Investment Officer in December 2021. Mr. Hartigan has more than 20 years’ experience in capital raising, M&A, strategy, finance and accounting, focused on the development of and investment in projects in the energy infrastructure space. From June 2020 to present, Mr. Hartigan has served as Executive Vice President and Chief Financial Officer of HOBO, where Mr. Hartigan directs capital raising, M&A, and commercial and marketing activities. Prior to that, from May 2019 to January 2020, Mr. Hartigan served as Senior Vice President, Strategy and Analytics for SemGroup Corporation, a publicly-traded company with pipelines, processing plants, refinery-connected storage facilities and deep-water marine terminals with import and export capabilities. At SemGroup Corporation, Mr. Hartigan led corporate development, deal structuring and corporate strategy resulting in the sale of SemGroup to Energy Transfer. After the transaction closed, Mr. Hartigan led the postmerger integration efforts. From December 2016 to March 2019, Mr. Hartigan served as Senior Vice President, Corporate Development and Capital Markets for Sunnova Energy International Inc. (“Sunnova”), a leader in residential solar, battery storage and system protection services. At Sunnova, Mr. Hartigan raised equity and debt at the corporate level as well as project finance and

62

tax equity at the asset level. From December 2014 to November 2016, Mr. Hartigan served as a Senior Vice President for GE Energy Financial Services focusing on energy investments in the midstream industry. From December 2011 to November 2014, Mr. Hartigan was a Vice President/Associate with Alinda Capital Partners (“Alinda”), an infrastructure investment firm. At Alinda, Mr. Hartigan managed certain of Alinda’s portfolio companies, and led capital market transactions, follow-on mergers and acquisitions, strategic reviews, and greenfield expansion projects executed under long-term contracts. Previously, Mr. Hartigan developed renewable power and midstream projects at Devonshire Investors (an affiliate of Fidelity Investments) and began his career at Ernst & Young in their Transaction Advisory Services Group.

Michael Bricker, 33, was appointed as a member of the Board in September 2020.  Mr. Bricker is currently a Managing Director at Stonepeak and has been with Stonepeak since April 2017. Mr. Bricker currently serves as a member of the Operating Committee for Whistler Pipeline, a greenfield natural gas pipeline, and Oryx Midstream Services LLC, the owner and operator of a crude oil pipeline system, both located in the Permian Basin. From April 2014 to April 2017, Mr. Bricker was an Investment Associate with First Reserve Corporation, a private equity firm that focuses on energy infrastructure investments. Mr. Bricker started his career as an Analyst in Citigroup’s oil and gas investment banking group. Mr. Bricker holds a Master in Professional Accounting with a Minor in Finance, graduating with high honors from the University of Texas at Austin.

Jack Howell, 35, was elected as a member of the Board in October 2015.  Mr. Howell is a Senior Managing Director at Stonepeak and a member of Stonepeak’s Executive Committee. Mr. Howell has been with Stonepeak since 2015. Prior to joining Stonepeak, Mr. Howell covered the oil and gas sector for Davidson Kempner, a hedge fund that focuses on distressed investments, from 2014 to 2015. Prior to Davidson Kempner, Mr. Howell worked for Denham Capital, an energy-focused private equity firm from 2011 to 2014. Mr. Howell started his career as an Analyst in Credit Suisse’s oil and gas investment banking group. Mr. Howell holds a Bachelor of Arts degree in Plan II Honors and Business Economics, Phi Beta Kappa, from the University of Texas at Austin.

Richard S. Langdon, 71, was elected as a member of the Board in March 2015 and was previously a director of Sanchez Production Partners LLC, having been first elected in December 2006. Mr. Langdon is an independent member of the Audit Committee and the Conflicts Committee. Mr. Langdon is currently the President, Chief Executive Officer, and Chief Financial Officer of Altamont Energy LLC ("Altamont"), a privately held exploration and production company, a position he has held since May 2021, from April 2018 to May 2021, Mr. Langdon was the Executive Vice President and Chief Financial Officer of Altamont. Mr. Langdon previously served as the President and Chief Executive Officer of Badlands Energy, Inc., a privately held exploration and production company (“Badlands Energy”), and its publicly traded predecessor entity, Gasco Energy, Inc. (“Gasco”), from May 2013 to October 2018. Mr. Langdon also served as a director of Badlands Energy and its predecessor, Gasco from March 2003 to October 2018. Badlands Energy filed for bankruptcy in August 2017. In addition to his Badlands Energy titles, Mr. Langdon also served as Debtor-in-Possession for Badlands Energy from August 2017 to October 2018. Mr. Langdon also currently serves on the board of directors, as chairman of the audit committee and as a member of the compensation committee of Gulfslope Energy, Inc., which capacities he has served in since March 2014.  Mr. Langdon was the President and Chief Executive Officer of KMD Operating Company LLC (“KMD Operating”), a privately held production company, from November 2011 until December 2015 and Matris Exploration Company L.P., a privately held production company, from July 2004 until the merger of Matris Exploration into KMD Operating in November 2011, which merger was effective January 2011.  Mr. Langdon also served as President and Chief Executive Officer of Sigma Energy Ventures, LLC, a privately held production company, from November 2007 until November 2013.  From 1997 until 2002, Mr. Langdon served as Executive Vice President and Chief Financial Officer of EEX Corporation, a publicly traded exploration and production company that merged with Newfield Exploration Company in 2002.  Prior to that, he held various positions with the Pennzoil Companies from 1991 to 1996, including Executive Vice President—International Marketing—Pennzoil Products Company; Senior Vice President—Business Development—Pennzoil Company; and Senior Vice President—Commercial & Control—Pennzoil Exploration & Production Company.

Steven E. Meisel, 37, was appointed as a member of the Board in September 2020 and is an independent member of the Board. Mr. Meisel also historically provided consulting services to the Partnership and its subsidiaries through that certain Consultancy Agreement (the “Meisel Consulting Agreement”) entered into with our general partner, effective as of October 1, 2020. The Meisel Consulting Agreement was terminated in March 2021. Mr. Meisel was Co-Chief Executive Officer and Managing Partner of Discovery Midstream Holdings II LLC (“Discovery II”). Prior to joining Discovery II, Mr. Meisel co-founded Discovery Midstream Holdings LLC (“Discovery I”) in January 2016, and grew it from a small

63

greenfield gathering and processing project into the premier system on the southern side of the DJ Basin. The asset was sold to Williams and KKR in August 2018. From March 2012 to January 2016, Mr. Meisel served as Senior Vice President of Commercial and Business Development at Wildcat Midstream Partners LLC, leading the commercial efforts in North Louisiana while also securing Wildcat’s Southern Midland Basin oil pipeline project. Prior to Wildcat, Mr. Meisel worked in various capacities for Regency Energy including corporate development, corporate finance and business development. Mr. Meisel started his career as an Analyst in Southwest Securities investment banking group. Mr. Meisel has a Bachelor of Finance from the University of Kansas.

John T. Steen III, 41, was appointed as a member of the Board in September 2020 and currently serves as the Chairman of the Board. Mr. Steen also historically provided consulting services to the Partnership and its subsidiaries through the JT3 Consulting Agreement defined and described in “Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence—Related Party Transactions—2020—JT3 Consulting Agreement.” The JT3 Consulting Agreement was terminated in March 2021. Mr. Steen is also currently a Senior Operating Partner with Stonepeak Infrastructure Partners and supports Stonepeak’s efforts in the midstream energy sector. Prior to joining Stonepeak, from 2017 to 2018, Mr. Steen was CEO of Paradigm Energy Partners, which focused on oil and gas pipeline and storage assets in the Bakken Shale of North Dakota and the Eagle Ford Shale of South Texas. From 2012 to 2017, Mr. Steen was a Vice President for Sage Midstream.  Prior to Sage Midstream, Mr. Steen worked in various midstream business development capacities for Energy Transfer and LDH Energy. He is the Chairman of the Texas Racing Commission, which oversees all pari-mutuel wagering on horse and greyhound racing in the state of Texas. Mr. Steen also serves on the boards of Oryx Midstream Services LLC and King Ranch, Inc. He graduated cum laude from Vanderbilt University and received an MBA from the Wharton School as well as an MA in International Studies from the University of Pennsylvania. Mr. Steen is also a CFA charterholder.

Luke R. Taylor, 44, was elected as a member of the Board in October 2015.  Mr. Taylor has served as a Senior Managing Director with Stonepeak since August 2011 and serves as a member of Stonepeak’s Executive Committee. Mr. Taylor has been investing across the infrastructure space for over 15 years and sits on the boards of Lineage Logistics, Golar Power and Ironclad Energy Partners, and is a former director of Paradigm Energy Partners, Tidewater Holdings, Carlsbad Desalination Project, Casper Crude to Rail and Northstar Renewable Power. Prior to joining Stonepeak, Mr. Taylor was a Senior Vice President with Macquarie Capital based in New York. Mr. Taylor has a Bachelor of Commerce and a Master of Business (Distinction) from the University of Otago (New Zealand).

Messrs. Steen, Bricker and Meisel were appointed to serve as directors on the Board in September 2020. Messrs.  Howell and Taylor were elected as members of the Board in October 2015 pursuant to that certain Board Representation and Standstill Agreement, by and among us, our general partner and Stonepeak Catarina, which was subsequently amended and restated by that certain Amended and Restated Board Representation and Standstill Agreement, dated as of August 2, 2019, by and among us, our general partner and Stonepeak Catarina (as amended and restated, the “Representation and Standstill Agreement”).  Pursuant to the Representation and Standstill Agreement, we and our general partner agreed to permit Stonepeak Catarina to designate two persons to serve on the Board. The right to designate one Board member will immediately terminate on such date as Stonepeak Catarina no longer owns at least 25% of the Partnership’s outstanding Class C Preferred Units issued to it; and the right to designate the second Board member will immediately terminate on such date as Stonepeak Catarina does not hold any issued and outstanding Class C Preferred Units.

Qualifications of the Board of Directors

The sole member of our general partner elects all of the members of the Board, except for two members designated by Stonepeak Catarina pursuant to the Representation and Standstill Agreement. The following sets forth the specific experience, qualifications, attributes and skills that led the sole member of our general partner to conclude that the persons appointed by it should serve as directors:

Mr. Bricker brings extensive investing and corporate finance experience to the Board, as well as a depth of knowledge of the upstream and midstream oil and gas industry.  Mr. Bricker also bring substantial experience in mergers and acquisitions to the Board.

Mr. Gibbs brings more than 40 years of energy industry experience to the Board, with twenty years on the energy commodity trading and marketing side, and the last twenty years in energy infrastructure development and operations

64

across the broad energy spectrum. Mr. Gibbs also brings substantial experience in renewable fuels and alternative energy and will assist the Board in developing the Partnership’s business, acquisition and financing strategies with respect to energy transition infrastructure opportunities.

Mr. Langdon brings more than 45 years of management experience in energy banking, energy consulting and executive management and board experience in large and small, public and private, domestic and international energy companies to the Board.  He has served as the Chief Financial Officer of EEX Corporation, a publicly traded production company that merged with Newfield Exploration. He has also held significant commercial positions with the Pennzoil Companies, including roles in business development and marketing. He was also the founder and owner of two privately held oil and gas companies. Mr. Langdon has extensive experience in finance and accounting that adds significant value to the board’s oversight role of our financial reporting. He has prior public company board and audit committee experience, which is beneficial for our board operations, and served as the chairman of the audit committee of Gasco until he was named Gasco’s President and Chief Executive Officer. The Board, after review and discussion of the applicable NYSE American listing standards and requirements, has determined that Mr. Langdon is “independent” for purposes of service on the Board.

Mr. Meisel brings expansive operating and management experience with respect to gathering, processing, treating and transmission infrastructure to the Board. He also brings extensive experience executing corporate finance transactions and corporate development transactions including acquisitions, divestitures, capital raises and project development transactions to the Board. The Board, after review and discussion of the applicable NYSE American listing standards and requirements, has determined that Mr. Meisel is “independent” for purposes of service on the Board.

Mr. Steen brings extensive operational, management and business development experience with respect to pipeline, storage and other midstream infrastructure assets to the Board. Mr. Steen also brings experience with respect to negotiation of commercial contracts and commercial projects to the Board.

The following sets forth the specific experience, qualifications, attributes and skills that led the holders of our Class C Preferred Units to conclude that the persons appointed by them should serve as directors:

Mr. Howell brings extensive oil and gas investing experience, along with experience in oil and gas transaction financings and mergers and acquisitions to the Board.

Mr. Taylor brings significant investment experience in energy and infrastructure companies, along with experience in finance and mergers and acquisitions to the Board.

Committees of the Board of Directors

The Board has two standing committees: the Audit Committee and the Conflicts Committee.  We do not have a compensation committee, but rather the Board approves executive officer salary changes and bonuses and equity grants to directors, executive officers, employees and service providers.

Audit Committee

As described in its charter, the Audit Committee is directly responsible for the appointment, compensation, retention and oversight of the work of the independent public accountants to audit our financial statements, including assessing the independent auditor’s qualifications and independence, and establishes the scope of, and oversees, the annual audit. The Audit Committee also approves any other services provided by public accounting firms. The Board has delegated to the Audit Committee the review and approval of our decision to enter into derivative transactions and our exemption from the swap clearing and swap execution requirements of the Dodd-Frank Act. The Audit Committee provides assistance to the Board in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of our internal audit function. The Audit Committee oversees our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and the Board established. In doing so, it is the responsibility of the Audit

65

Committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and our management.

The Audit Committee consists of Messrs. Langdon (Chair) and Meisel. The Board has determined that each of Messrs. Langdon and Meisel is an “audit committee financial expert” as that term is defined in the applicable rules of the SEC. Additionally, the Board has also determined that each of Messrs. Langdon and Meisel is “independent” for purposes of service on the Audit Committee as required by applicable NYSE American listing standards.

Conflicts Committee

The Conflicts Committee consists of Messrs. Meisel (Chair) and Langdon. The Conflicts Committee reviews specific matters that the Board believes may involve conflicts of interest. Our partnership agreement provides that members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of any of our General Partner’s affiliates or, subject to certain exceptions, a holder of any ownership interest in our General Partner or its affiliates and must meet the independence standards for service on an audit committee of a board of directors as established by NYSE American and SEC rules. Any matters approved by the Conflicts Committee will be presumed to be taken in good faith.

Other

We maintain on our website, http://www.evolvetransition.com in the “Corporate Governance” section under the “Investors” tab, a copy of the Audit Committee charter as well as copies of the Corporate Governance Guidelines and Code of Business Conduct and Ethics that are applicable to us and our general partner. Copies of these documents are also available in print and may be obtained without charge, upon written request, by emailing our investor relations group at ir@evolvetransition.com. Our Code of Business Conduct and Ethics applies to our general partner’s principal executive officer, principal financial officer and principal accounting officer, among others. We intend to post any changes to or waivers of our Code of Business Conduct and Ethics for the executive officers of our general partner on our website.

Certifications

The NYSE American requires the Chief Executive Officer of each listed company to certify annually that he is not aware of any violation by a listed company of the NYSE American’s corporate governance listing standards, qualifying the certification to the extent necessary.  In accordance with the rules of the NYSE American, we last provided such a certification on March 16, 2021. The certifications of the Chief Executive Officer and Chief Financial Officer of our general partners required by Sections 302 and 906 of the Sarbanes-Oxley Act have been included as exhibits to this Form 10-K.

Item 11. Executive Compensation

Our general partner has the sole responsibility for conducting our business and for managing our operations, and its Board makes decisions on our behalf. The executive officers of our general partner are employed by Evolve Transition Infrastructure GP LLC and manage the day-to-day affairs of our business. 

Summary Compensation Table

The following table sets forth the compensation of our named executive officers (the “NEOs”) (which are the chief executive officer and the two next most highly compensated officers of our general partner) for 2021 and 2020:

66

						Unit		All Other
Name and Principal Position (a)	Year	Salary		Bonus (b)		Awards (c)		Compensation (d)		Total
Gerald F. Willinger	2021	$	362,500	$	—	$	—	$	1,682,786	$	2,045,286
Former Chief Executive Officer (e)	2020	$	600,000	$	1,300,000	$	—	$	55,260	$	1,955,260
Charles C. Ward	2021	$	375,000	$	843,750	$	—	$	11,138	$	1,229,888
Chief Financial Officer and Secretary	2020	$	375,000	$	550,000	$	—	$	54,792	$	979,792
Randall L. Gibbs	2021	$	95,455	$	—	$	5,129,347	$	—	$	5,224,802
Chief Executive Officer (f)	2020	$	—	$	—	$	—	$	—	$	—
Michael A. Keuss	2021	$	95,455	$	—	$	5,129,347	$	—	$	5,224,802
President and Chief Operating Officer (f)	2020	$	—	$	—	$	—	$	—	$	—
Jonathan C. M. Hartigan	2021	$	59,659	$	—	$	2,308,307	$	—	$	2,367,966
President and Chief Investment Officer (f)	2020	$	—	$	—	$	—	$	—	$	—

(a) On November 3, 2021, Mr. Willinger resigned from his positions as Chief Executive Officer of the general partner and a member of the Board, to be effective November 30, 2021.  On November 3, 2021, in connection with the HOBO Transaction, the Board appointed Randall Gibbs as Chief Executive Officer of our general partner, Michael Keuss as the President and Chief Operating Officer of our general partner and Jonathan Hartigan as the President and Chief Investment Officer of our general partner, with each such appointment becoming effective on December 1, 2021.

(b) On March 13, 2020, our general partner entered into the Award Letter Agreement with each of Messrs. Willinger and Ward. In the Award Letter Agreements the Board determined that the annual grant for 2020 of $1,300,000 to Mr. Willinger and $550,000 to Mr. Ward would be payable either in cash or restricted units under the Plan. The Board, in its discretion, paid Messrs. Willinger and Ward's 2020 annual bonus in the form of restricted common units on March 18, 2021.  The value above reflects the aggregate grant date fair value of these units. On October 1, 2021, the Board, in its discretion, determined that Mr. Ward’s annual cash bonus under his Executive Agreement for performance during fiscal year 2020 would be paid at the high end of the range, or 125%, resulting in a cash bonus of $468,750. On March 29, 2022, the Board, in its discretion, determined that Mr. Ward's annual cash bonus under his Executive Agreement for performance during fiscal year 2021 would be paid at the midpoint of the range, or 100%, resulting in a cash bonus of $375,000. A portion of the 2021 cash bonus award of $140,625 was paid to Mr. Ward in 2021 with the remainder of the 2021 cash bonus of $234,375 to be paid out in 2022.

(c) The amounts reported in this column reflect the aggregate grant date fair value of awards granted, if any, for fiscal years 2021 and 2020, computed in accordance with FASB ASC Topic 718, excluding estimated forfeitures. See Note 15 “Unit-Based Compensation,” to the Consolidated Financial Statements included under “Part II, Item 8. Financial Statements and Supplementary Data” for additional detail regarding these figures. On November 3, 2021, the Board granted Messrs. Gibbs, Keuss, and Hartigan Inducement Awards in the form of restricted common units that will vest in three separate tranches if certain performance conditions are satisfied.  In addition, the Board granted Messrs. Gibbs, Keuss, and Hartigan long-term incentive awards (“LTIP Awards”) that will also vest in three separate tranches if certain performance conditions are satisfied.  

(d) Our NEOs are eligible to participate in benefit plans such as medical, dental, vision, life and disability insurance, 401(k) and flexible spending accounts on the same terms as all employees or service providers.  The amount in this column reflects the amount of matching contributions made under our 401(k) plan; parking cost paid for our NEOs; the cost of life insurance, accidental death and dismemberment insurance, and health insurance for our NEOs; and for those Mr. Willinger who also served as director, this column includes cash fees he received for service as a director. 

(e) On November 3, 2021, Mr. Willinger resigned from his position as Chief Executive Officer, effective as of November 30, 2021. As a result, the salary amount for Mr. Willinger for 2021 has been prorated based on salary paid from January 1, 2021 through November 30, 2021.

(f) The salary amounts for the New Executives for 2021 reflect salary paid from November 3, 2021 through December 31, 2021.

Executive Agreements

The general partner has entered into Executive Service Agreements with the NEOs, and a Transition Agreement with the Former Chief Executive Officer.  Set forth below is the description of the material terms of these agreements.  

Executive Services Agreements – New Executives

On November 3, 2021, our general partner entered into Executive Services Agreements (each, an “Executive Agreement” and, collectively, the “Executive Agreements”) with each of the New Executives. Each respective Executive Agreement provides for: (i) an annual base salary (Mr. Gibbs: $600,000, Mr. Keuss: $600,000, and Mr. Hartigan: $375,000), (ii) eligibility to receive an annual cash bonus equal to an amount between 100% and 150% of such New Executive’s base salary based on a qualitative assessment of financial and individual performance achievements, as determined in the Board’s sole discretion, (iii) a grant of Common Units as an inducement material to entering into employment with our general partner pursuant to the Evolve Transition Infrastructure 2021 Equity Inducement Award Plan (discussed further below) (Mr. Gibbs: 5,755,056 Common Units, Mr. Keuss: 5,755,056 Common Units, and Mr.

67

Hartigan: 2,589,888 Common Units) (the “Inducement Awards”), (iv) eligibility to receive awards under the Sanchez Production Partners LP Long-Term Incentive Plan (the “LTIP”), (v) participation in applicable retirement plans, health and welfare plans and disability insurance plans of our general partner and Evolve, (vi) unlimited paid vacation to be used in each New Executive’s reasonable discretion, and (vii) reimbursement of certain reasonable out-of-pocket business expenses.

Under each Executive Agreement, each New Executive will be entitled to the payments described below upon the occurrence of certain termination of employment or related change of control events. A termination of employment by our general partner for Cause or by such New Executive without Good Reason (as each term is defined in such Executive Agreement) will result in payment of any accrued but unpaid then-current base salary and any unpaid expense reimbursements (collectively, “Accrued Obligations”). A termination of employment upon such New Executive’s death or Disability (as defined in the Executive Agreements) will result in (i) payment of any Accrued Obligations and any then-unpaid Deferred Initial Bonus Amounts (as defined in such Executive Agreement) (“Unpaid Deferred Bonus”), and (ii) if the Offtake Condition  (as defined in the Framework Agreement dated November 3, 2021 between Evolve and HOBO Renewable Diesel) is achieved prior to the termination date for such New Executive, payment of any unpaid annual bonus for the year prior to the year of termination (“Unpaid Prior-Year Bonus”) and a pro-rated annual bonus for the year of termination (the “Pro-Rated Current Bonus”). A termination of employment by our general partner without Cause or by such New Executive for Good Reason will result in (x) payment of any Accrued Obligations and Unpaid Deferred Bonus, (y) if the Offtake Condition is achieved prior to the termination date for such New Executive, (A) payment of an amount equal to 100% of such New Executive’s then-current base salary, plus 100% of the largest annual bonus paid to (or due to be paid to) such New Executive for the year in which the termination occurs or any of the previous three calendar year periods, (B) if such New Executive timely elects, payment of the COBRA premiums for such executive and such executive’s eligible dependents during the COBRA continuation period, and (C) payment of any Unpaid Prior-Year Bonus and the Pro-Rated Current Year Bonus (payments in (y)(A)-(C), “Severance Payments”); provided that, in the event such termination of employment occurs during the period beginning sixty (60) days prior to and ending two (2) years immediately following a Change in Control (as defined in the Executive Agreements), then the payments provided under (x), (y) and (z) above will be made, except that references to 100% in (y)(A) will be 200%.  As a condition to receive any Severance Payments, such New Executive must sign and return a release acceptable to our general partner. Treatment of long-term incentive compensation awards in connection with any termination described above shall all be governed by the applicable award agreement. Following any termination, such New Executive will be subject to a standard one-year non-compete covenant.

Executive Services Agreements – Former Chief Executive Officer and Chief Financial Officer and Secretary

On August 2, 2019, our general partner entered into Executive Agreements with Messrs. Willinger and Ward.  Each respective Executive Agreement provides (i) that the applicable executive will continue to serve in his current executive officer position with our general partner and provide services to us and our general partner during the applicable term, (ii) for an annual base salary (Mr. Willinger: $600,000 and Mr. Ward: $375,000), (iii) for an annual cash bonus equal to a percentage of the annual base salary (Mr. Willinger: 100% to 150% and Mr. Ward: 75% to 125%) based on a qualitative assessment of financial and individual performance achievements, and (iv) for eligibility to receive awards under our LTIP or any successor thereto and to participate in any long-term incentive programs available generally to the executive officers of our general partner, as determined in the sole discretion of the Board.  

Under each Executive Agreement, in the event of the applicable executive’s termination as an officer of the general partner due to (a) such executive’s death or “disability,” (b) the general partner terminating such executive without “cause,” or (c) such executive terminating for “good reason” (as such terms are defined in the Executive Agreements), such executive (or such executive’s designated beneficiaries, as applicable) will be entitled to receive payment of: (i) any accrued but unpaid then-current annual base salary through the date of termination, (ii) any unpaid annual bonus for the year prior to the year of termination and (iii) a pro-rated annual bonus for the year of termination.

In addition, such executive will also be entitled to receive the following severance payments or benefits in the event of: (1) the general partner terminating such executive without “cause,” (2) such executive terminating for “good reason” or (3)(A) the general partner terminating such executive without “cause,” (B) such executive’s death or “disability,” or (C) such executive terminating for any reason, in the case of (A)-(C), during a period beginning sixty (60) days prior to and ending two (2) years following a Change in Control (as defined in the Executive Agreements) such executive will be

68

entitled to receive (w) a lump-sum cash payment equal to two times such executive’s then-current annual base salary plus two times the largest annual bonus paid (or due to be paid) to such executive for the year in which the termination occurs or any year in the three calendar year period immediately preceding the date of termination, (x) payment of the COBRA premiums for such executive and such executive’s eligible dependents during the COBRA continuation period, (y) to the extent not yet paid to such executive, a lump-sum cash payment equal to all outstanding amounts owed to such executive for services performed for or on behalf of us and our general partner, the amount of such executive’s annual bonus for the last full year during which such executive performed services for us and our general partner, and the amount of such executive’s annual bonus for the current year, based on such executive’s annual bonus for such last full year (pro-rated to the date of termination), and (z) immediate vesting in full, as of the date of such Change in Control, of any units awarded to such executive under our Plan. On March 1, 2021, Messrs. Willinger and Ward agreed with our general partner to defer the determination and payment of their annual cash bonuses for 2020.

On March 13, 2020, our general partner entered into an Award Letter Agreement with each of Messrs. Willinger and Ward (each, an “Award Letter Agreement” and, together, the “Award Letter Agreements”). Pursuant to the Award Letter Agreements, the Board agreed with Messrs. Willinger and Ward to grant awards with respect to the performance of the Partnership in 2019 in amounts equal to $1,300,000 for Mr. Willinger, and $550,000 for Mr. Ward (the “Deferred Awards”). However, due to the declining market price of our common units from 2019 to 2020, the dilutive effect of granting awards to Messrs. Willinger and Ward under the Plan in March 2020 would have been extreme and in order to advance the interests of the Partnership and its unitholders, Messrs. Willinger and Ward agreed with our general partner to defer to determination on the form of the awards under the Award Letter Agreement until a time prior to March 1, 2021.

On March 1, 2021, Messrs. Willinger and Ward agreed with our general partner to delay the determination as to the form of the Deferred Awards until a time prior to March 31, 2021. The Deferred Awards were granted on March 18, 2021 in the form of restricted common units.

Transition Agreement – Former Chief Executive Officer

On November 3, 2021, Mr. Willinger resigned from his positions as Chief Executive Officer of our general partner and a member of the Board, to be effective November 30, 2021.  In connection with Mr. Willinger’s departure, our general partner and Mr. Willinger entered into a Separation and Transition Agreement (the “Transition Agreement”).  Pursuant to the Transition Agreement, Mr. Willinger is entitled to (i) payment of his current base salary earned through November 30, 2021, (ii) payment of any then-outstanding expense reimbursement amounts, and (iii) payment of the Special Separation Compensation (as defined in the Transition Agreement), which includes (x) the retention payments described in, and payable at the times specified under, the Amended and Restated Executive Services Agreement for Realignment between Mr. Willinger, our general partner and Evolve, dated April 15, 2021 (the “Restated Agreement”), and (y) the acceleration of the unvested portion of any outstanding awards issued to Mr. Willinger under the LTIP, subject to Mr. Willinger’s continued compliance with certain lock-up and tax withholding reimbursement obligations.  Additionally, payment of the Special Separation Compensation is conditioned on, among other things, Mr. Willinger’s execution, delivery and non-revocation of the release attached as Exhibit 2 to the Transition Agreement and continued compliance with the covenants and other obligations under the Transition Agreement and under the Restated Agreement, including restrictive covenants with respect to confidentiality, mutual non-disparagement, non-solicitation and non-competition, among others.

Long-Term Incentive Compensation

Inducement Plan

On November 3, 2021, the Board adopted the Evolve Transition Infrastructure LP 2021 Equity Inducement Award Plan (the “Inducement Plan”). The Inducement Plan was adopted without unitholder approval pursuant to Section 711 of the NYSE American Company Guide (the “Company Guide”).  The Board also adopted a form of Inducement Award Agreement Relating to Restricted Units and reserved 14,100,000 common units for issuance pursuant to equity awards granted under the Inducement Plan. The Inducement Plan is administered by the Board and its terms are substantially similar to the LTIP.

The purposes of the Inducement Plan is to further the long term stability and success of Evolve and its affiliates by providing a program to reward selected individuals hired as employees of Evolve, our general partner and their affiliates

69

with grants of inducement awards by affording such individuals an opportunity to acquire a proprietary interest in Evolve. In accordance with Section 711(a) of the Company Guide, inducement awards may only be issued to individuals who were not previously employees or non-employee directors of our general partner, or following a bona fide period of non-employment, as an inducement material to entering into employment with our general partner or, to the extent permitted by Section 711(c) of the Company Guide, in connection with a merger or acquisition.

On November 3, 2021, the Board granted Messrs. Gibbs, Keuss, and Hartigan Inducement Awards in the form of restricted common units that will vest in three separate tranches if certain performance conditions are satisfied.  Messrs. Gibbs and Keuss each received a grant of 5,755,056 common units and Mr. Hartigan received a grant of 2,589,888 common units.  With respect to each tranche there is a primary vesting schedule which is tied to satisfaction of certain conditions set forth in the Framework Agreement and an alternative vesting schedule that may apply upon satisfaction of certain performance metrics relating to total unitholder return.

The performance goal under the first tranche will be met upon the occurrence of the Offtake Condition within seven (7) years of the grant date, or alternatively, upon Evolve’s achievement of a total unitholder return of 150% for sixty (60) consecutive days during the period beginning on the grant date and ending on December 31, 2023. The performance goal under the second tranche will be met upon the occurrence of Financial Close (as defined in the award agreements) within seven (7) years of the grant date, or alternatively, upon Evolve’s achievement of a total unitholder return of 200% for sixty (60) consecutive days during the period commencing on January 1, 2023 and ending on December 31, 2024. The performance goal under the third tranche will be met upon the occurrence of Commercial Operation (as defined in the award agreements) within seven (7) years of the grant date, or alternatively, upon Evolve’s achievement of a total unitholder return of 250% for sixty (60) consecutive days during the period commencing on January 1, 2024 and ending on December 31, 2025.

Long-Term Incentive Plan

On November 3, 2021, LTIP Awards were granted to Messrs. Gibbs, Keuss, and Hartigan in the form of restricted common units.  Messrs. Gibbs and Keuss each received a grant of 1,469,376 common units and Mr. Hartigan received a grant of 661,248 common units.  The LTIP Awards will vest in three (3) separate tranches if certain performance conditions are satisfied.

With respect to each tranche there is a primary vesting schedule which is tied to satisfaction of the Offtake Condition set forth in the Framework Agreement and an alternative vesting schedule that may apply upon satisfaction of certain performance metrics relating to total unitholder return. The performance goal under all tranches will be met upon the occurrence of the Offtake Condition within seven (7) years of the grant date; provided that, if the Offtake Condition occurs prior to November 3, 2022, then the second tranche will vest as of November 3, 2022, and similarly, if the Offtake Condition occurs prior to November 3, 2023, then the third tranche will vest as of November 3, 2022. Alternatively, the performance goal will be met upon Evolve’s achievement of a total unitholder return, (i) with respect to the first tranche, of 150% for sixty (60) consecutive days during the period commencing on the grant date and ending on December 31, 2023, (ii) with respect to the second tranche, of 200% for sixty (60) consecutive days during the period commencing on January 1, 2023 and ending on December 31, 2024, and (iii) with respect to the third tranche, of 250% for sixty (60) consecutive days during the period commencing on January 1, 2024 and ending on December 31, 2025.

Outstanding Equity Awards at Fiscal Year-End 2021

The following table sets forth the outstanding equity awards and their market value using the closing price of our common units on NYSE American at December 31, 2021 for the named executive officers: 

70

	Number of		Fair Market
	Units Not		Value of Units
Name	Vested		Not Vested⁽ᵃ⁾
Gerald F. Willinger	—	(b)​	$	—
Charles C. Ward	654,082	(b)​	$	385,908
Randall L. Gibbs	7,224,432	(c)​	$	4,262,415
Michael A. Keuss	7,224,432	(c)​	$	4,262,415
Jonathan C. M. Hartigan	3,251,136	(c)​	$	1,918,170

(a) Amounts are based on the closing price of our common units of $0.59 as reported on the NYSE American on December 31, 2021.

(b) Reflects restricted common units granted under the LTIP on March 4, 2019, which units vest pro-rata over a three year period. Except in connection with a change in control (as defined in the LTIP) or in the discretion of the Board of our general partner, any unvested restricted units will be forfeited upon such time as the holder is no longer an officer, employee, consultant or director of us, our general partner, any of their affiliates or any other person performing bona fide services for us.

(c) Reflects the restricted common units granted under the LTIP and the Inducement Plan on November 3, 2021.

Compensation of Directors

For the year ended December 31, 2021, compensation for the independent directors of the Board consisted of:

● a cash retainer of $35,000, payable quarterly on the last day of each fiscal quarter through March 31, 2021 and a cash retainer of $12,500, payable monthly on the last day of each fiscal month from April 1, 2021, through December 31, 2021;

● a $1,500 fee for each meeting of the Board and $1,000 for each substantive meeting of the Audit Committee and $3,500 for each substantive meeting of the Conflicts Committee attended by a member thereof through March 31, 2021;

● a cash retainer of $3,500 for the Chair of the Audit Committee and $2,500 for the Chair of the Conflicts Committee, each payable quarterly on the last day of each fiscal quarter through March 31, 2021; and

● eligibility for independent directors to participate in a basic health benefits package similar to that available to all employees through March 31, 2021.

Beginning April 1, 2021, the separate retainers for committee chairs and separate fees payable for each meeting were terminated. This termination resulted in the monthly cash retainer being increased to $12,500.

Messrs. Howell, Taylor, Bricker and Steen do not receive separate compensation for their service on the Board, but they are entitled to indemnification related to their service as directors pursuant to the terms of our partnership agreement.

The following table sets forth a summary of the 2021 compensation for the directors except for Messrs. Gibbs and Willinger whose director compensation is included above under “—Summary Compensation Table”:

	Director Compensation
	Fees Earned or Paid		Unit		All Other
Name	in Cash		Awards		Compensation (a)		Total
Michael Bricker (b)	$	—	$	—	$	—	$	—
Randall L. Gibbs	$	—	$	—	$	—	$	—
Jack Howell (c)	$	—	$	—	$	—	$	—
Richard S. Langdon	$	152,500	$	—	$	—	$	152,500
Steven E. Meisel (e)	$	112,500	$	—	$	—	$	112,500
John T. Steen III (d)	$	—	$	—	$	—	$	—
Luke R. Taylor (c)	$	—	$	—	$	—	$	—

(a) All other compensation includes amounts for health, vision, dental, basic life and/or accidental death and dismemberment insurance premium fees paid by us for the director.

(b) Due to his employment with Stonepeak, Mr. Bricker does not receive any compensation for his service on the Board.

(c) As appointees of the holders of the Class C Preferred Units, Messrs. Howell and Taylor were not entitled to any compensation under our 2021 Board compensation program.

(d) Does not include compensation of $40,000 received under the JT3 Consulting Agreement during 2021.

71

(e) Does not include compensation of $37,500 received under the Meisel Consulting Agreement during 2021.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth the beneficial ownership of our units, as of March 29, 2022, held by:

● each unitholder known by us to beneficially own more than 5% of our outstanding units;

● each of the directors of the Board;

● each of our general partner’s named executive officers (as such term is defined by the SEC); and

● the directors and executive officers of our general partner as a group.

The list of persons named in the table below is derived from our review of Form 3, Form 4, Form 5, Schedule 13D and Schedule 13G filings made with the SEC as of March 29, 2022. The amounts and percentage of common units and Class C Preferred Units beneficially owned are reported on the basis of the SEC rules governing the determination of beneficial ownership of securities. Under the SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, and/or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities, and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Percentage of total units beneficially owned is based on 148,951,002 common units and 36,474,436 Class C Preferred Units outstanding as of March 29, 2022, the number of common units beneficially owned and the number of Class C Preferred Units beneficially owned is based upon ownership as of March 29, 2022, unless otherwise specified. Except as indicated by footnote, to our knowledge the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

							Percentage of
	Common Units Beneficially			Class C Preferred Units			Total Units
	Owned			Beneficially Owned			Beneficially
Name and address of Beneficial Owner(1)	Number	Percentage		Number	Percentage		Owned
Stonepeak Catarina Holdings, LLC(2)	111,654,790	68.1	%	36,474,436	100	%	73.9	%
Randall L. Gibbs	7,224,432	4.9	%	—	—		3.9	%
Michael A. Keuss	7,224,432	4.9	%	—	—		3.9	%
Jonathan C. M. Hartigan	3,251,136	2.2	%	—	—		1.8	%
Charles C. Ward	379,027	*		—	—		*
Gerald F. Willinger(3)	1,000,013	*		—	—		*
Michael Bricker	—	—		—	—		—
Jack Howell	—	—		—	—		—
Richard S. Langdon	81,827	*		—	—		*
Steven E. Meisel	—	—		—	—		—
John T. Steen III	—	—		—	—		—
Luke R. Taylor	—	—		—	—		—
All directors and executive officers as a group (11 persons)	19,160,867	12.9	%	—	—		10.3	%

* Less than 1%

(1) Unless otherwise set forth below, the address of all beneficial owners is c/o Evolve Transition Infrastructure LP, 1360 Post Oak Blvd, Suite 2400, Houston, Texas 77056.

(2) Ownership data as reported on (i) Schedule 13D/A filed on February 2, 2022, by Stonepeak Catarina, Stonepeak Texas Midstream Holdco LLC, Stonepeak Catarina Upper Holdings LLC, Stonepeak Infrastructure Fund (Orion AIV) LP, Stonepeak Associates LLC, Stonepeak GP Holdings LP, Stonepeak GP Investors LLC, Stonepeak GP Investors Manager LLC and Michael Dorrell (collectively, the “Stonepeak Beneficial Owners”), SP Preferred Equity Subsidiary LLC (“SPPE Sub”), and SP Common Equity Subsidiary LLC (“SPCE Sub”), and (ii) Form 4 filed on February 2, 2022 by the Stonepeak Beneficial Owners.  The number of common units disclosed in the Schedule 13D/A includes 14,920,706 common units that the Stonepeak Beneficial Owners currently

72

have the right to acquire within the next 60 days upon exercise of the Stonepeak Warrant held by Stonepeak Catarina, as a result the percentage of common units beneficially owned is based on a total of 163,871,708 common units. Such common units are not included for any other person on this table in accordance with Rule 13d-3(d)(1)(i) under the Exchange Act. In addition, the total number of common units beneficially owned also includes (y) 4,509,792 common units held directly by SPCE Sub, SPCE Sub may be deemed the beneficial owner of such units, and (z) 9,000,000 common units held directly by SPPE Sub, which Stonepeak Catarina transferred to SPPE Sub on November 9, 2021 at no cost in a transaction exempt from Section 16 of the Exchange Act pursuant to Rule 16a-13, SPPE Sub may be deemed the beneficial owner of such units.  The principal business address of each reporting person in the Schedule 13D/A is 55 Hudson Yards, 550 W. 34th St., 48th Floor, New York, NY 10001. The Schedule 13D/A filing lists each of the Stonepeak Beneficial Owners as having shared voting and dispositive power over the common units and the Class C Preferred Units.

(3) Effective November 30, 2021, Mr. Willinger resigned from his positions as Chief Executive Officer of our general partner and a member of the Board.

73

Equity Compensation Plan Information

The following table reflects our equity compensation plan information for our only equity compensation plan, the Sanchez Production Partners LP Long-Term Incentive Plan, as of December 31, 2021:

	Number of
	Securities			Number of securities
	to be issued upon	Weighted-average		remaining available
	exercise of	exercise price of		for future
	outstanding options,	outstanding options,		issuance under equity
	warrants, and rights	warrants, and rights		compensation plans
Plan Category
Equity compensation plans approved by security holders	—	$	—	8,848,410
Equity compensation plans not approved by security holders	—		—	—
Total	—	$	—	8,848,410

Item 13. Certain Relationships and Related Transactions, and Director Independence

Relationship with Stonepeak

Since October 14, 2015, Stonepeak Catarina has owned all of our issued and outstanding preferred units.

As of March 29, 2022, Stonepeak owned (i) 96,734,084 common units, representing approximately 65% of our outstanding common units, (ii) all of our issued and outstanding Class C Preferred Units, (iii) the Stonepeak Warrant, which entitles 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. Stonepeak controls us and our general partner and has the ability to appoint all of the members of the Board and is considered a related party of the Partnership. Stonepeak Catarina is considered to be our parent because it is our affiliate and has the power to control us, directly or indirectly, through its ownership of common units, Class C Preferred Units, and all of the issued and outstanding equity interests of SP Holdings and its other contractual rights with us.

Currently, four of our directors, Jack Howell, Luke Taylor, Michael Bricker and John T. Steen III are representatives of Stonepeak, as either employees or operating partners of Stonepeak. Messrs. Howell, Taylor, Bricker and Steen do not receive separate compensation for their service on the Board, but they are entitled to indemnification related to their service as directors pursuant to the terms of our partnership agreement. “See Part III, Item 11. Executive Compensation—Compensation of Directors.”

Relationship with Mesquite

Prior to emergence from bankruptcy, Mesquite was considered a related party of the Partnership because (i) Antonio R. Sanchez, III, who served as the Chairman of the Board at such time, also served as the Chief Executive Officer of Mesquite, (ii) Patricio D. Sanchez, who served as a member of the Board and as our President and Chief Operating Officer at such time, also served as a senior vice president and Chief Operating Officer of Mesquite, and (iii) Mesquite and certain other members of the Sanchez family directly or indirectly owned approximately 24.3% of the issued and outstanding common units of the Partnership at such time. As of June 30, 2020, Mesquite is not considered a related party of the Partnership. Patricio D. Sanchez resigned from his position as a member of the Board and as our President and Chief Operating Officer in September 2020. Antonio R. Sanchez, III resigned from his position as a member of the Board and the Chairman of the Board in February 2021.

74

Relationship with SP Holdings

We are controlled by our general partner, Evolve Transition Infrastructure GP LLC.  The sole member of our general partner is SP Holdings which has no officers. The sole member of SP Holdings is Stonepeak Catarina and the managing member of SP Holdings is Stonepeak Catarina Upper Holdings, LLC, an affiliate of Stonepeak Catarina.  

Shared Services Agreement

We have entered into the Shared Services Agreement with SP Holdings. In connection with providing the services under the Shared Services Agreement, SP Holdings receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in the Mid-Continent region, (ii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction.  Prior to August 2, 2019 each of these fees, not including the reimbursement of costs, was paid in cash unless SP Holdings elected for such fee to be paid in our equity. However, on August 2, 2019, we and SP Holdings entered into a letter agreement providing that until such time as we redeem all of our issued and outstanding Class C Preferred Units, SP Holdings will elect to receive its fees, not including reimbursement of costs, in common units rather than cash.  In addition, on November 8, 2019, we and SP Holdings entered into an additional letter agreement providing that during the period beginning with the fiscal quarter ended September 30, 2019 and continuing until the end of the fiscal quarter after the fiscal quarter in which we redeem all of our issued and outstanding Class C Preferred Units (the “Tolling Period”), SP Holdings would agree to delay receipt of its fees, not including reimbursement of costs. During the Tolling Period, we are required to keep an accurate ledger of the dollar amount of the fee applicable to each quarter within the Tolling Period and the daily closing price of our common units on the NYSE. Following the end of the Tolling Period we will provide a notice to SP Holdings including such ledgers and pay the accrued fees within thirty days of delivery of such notice. The Shared Services Agreement has a ten-year term and will be automatically renewed for an additional ten years unless we or SP Holdings provide notice of termination to the other with at least 180 days’ notice. During the year ended December 31, 2021, pursuant to the November 8, 2019 letter agreement, SP Holdings did not receive any fees, other than reimbursement of its costs. However, pursuant to the requirements under the November 8, 2019 letter agreement, we have determined that there was a net benefit during the year ended December 31, 2021, of approximately $1.9 million and fees earned during the year ended December 31, 2020, of approximately $7.2 million. The November 8, 2019 letter agreement resulted in the accumulating balance being subject to mark-to-market adjustments based on the market price for our common units. The volatility in our common unit market price during the periods caused the swing in fees earned.

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 $34.0 million as of December 31, 2021. 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.  To date, no notice of termination of the Shared Services Agreement has been delivered by SP Holdings, and the Partnership is continuing to discuss the Shared Services Agreement with SP Holdings.

Relationship with HOBO

As described below under “—Related Party Transactions—2021—HOBO Transaction,” we have committed to fund certain development expenses of HOBO as HOBO seeks to develop, construct, own and operate renewable fuels facilities. Messrs. Gibbs, Keuss and Hartigan, the current Chief Executive Officer, Chief Operating Officer and Chief Investment Officer of our general partner, respectively, also serve as the Chief Executive Officer, President, and Executive Vice President and Chief Financial Officer, respectively, of HOBO and own 45.25%, 45.25% and 9.5% of HOBO.  

75

Related Party Transactions

2020

Settlement Agreement

On June 6, 2020 the Partnership, our general partner and certain of our subsidiaries entered into the Settlement Agreement with Mesquite and certain of its subsidiaries. On June 30, 2020, 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, (ii) the Seco Catarina Agreement, and (iii) the Seco Comanche Agreement. As described below under “—2021—Settlement Agreement,” the Settlement Agreement was terminated on June 24, 2021.

JT3 Consulting Agreement

On June 30, 2020, our general partner entered into that certain Consultancy Agreement (the “JT3 Consulting Agreement”) with JT3 Advisors LLC (“JT3 Advisors”).  JT3 Advisors is an entity owned by John T Steen III, who has served as the Chairman of the Board since September 2020. Pursuant to the terms of the JT3 Consulting Agreement the Partnership pays JT3 Advisors a consulting fee of $20,000 per month for the provision of services to aid the Partnership in achieving its commercial goals, including analysis and assessment of potential commercial arrangements and recommendation of selected arrangements to our management. The JT3 Consulting Agreement was terminated in March 2021.  Consulting fees earned under the JT3 Consulting Agreement were approximately $200,000.

Certain Transactions with Stonepeak

On November 16, 2020, the Partnership and Stonepeak Catarina entered 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 Letter Agreement Transactions were 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. As of March 29, 2022, we distributed a total of 91,831,001 common units under the Stonepeak Letter Agreement with an approximate value of $77.2 million.

As a result of the foregoing transactions, as of March 29, 2022, Stonepeak owned (i) 96,734,084 common units, representing approximately 65% of our outstanding common units, (ii) all of our issued and outstanding Class C Preferred Units, (iii) the Stonepeak Warrant, which entitles 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

76

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 29, 2022, the General Partner and its controlled affiliates do not own any Common Units.

2021

Settlement Agreement

On June 24, 2021, the Partnership, our general partner, Catarina Midstream and Seco Pipeline LLC received the Settlement Agreement Termination Notice from Mesquite. The Settlement Agreement Termination Notice was delivered pursuant to Section 5.1.2 and/or 5.1.3 of the Settlement Agreement and the termination was effective as of the date of the notice.

HOBO Transaction

On November 3, 2021, we entered into a Framework Agreement (the “Framework Agreement”) with HOBO. At the time of entry into the Framework Agreement there were no other material relationships between us or any of our affiliates and HOBO. The Framework Agreement provides that, subject to the satisfaction of applicable conditions precedent, we will fund certain development expenses of HOBO as HOBO seeks to develop, construct, own and operate renewable fuels facilities (each, a “Project”). HOBO’s initial Project is a 9,000 barrel per day (120 million gallons per year) renewable diesel production facility (the “Initial Project”).

Upon satisfaction of the Offtake Condition, HOBO will send written notice thereof to us. If we are reasonably satisfied with our review of the supporting materials relating to the Offtake Condition then we will pay to HOBO the lesser of 50% of the Qualified Development Costs incurred as of such date and $3.0 million (the “Initial Development Payment”).

Upon receipt of all Material Permits (as defined in the Framework Agreement) for the Initial Project and conclusion of the FEL2 Level Pre-Feasibility Study Report verifying the Initial Project can be completed in accordance with the Qualified Project Model, HOBO will send written notice thereof to us and if we are reasonably satisfied with our review of the supporting materials, we will pay to HOBO (i) the lesser of 50% of the aggregate Qualified Development Costs incurred as of such date and $7.5 million minus (ii) the amount of any Qualified Development Costs previously paid by us (the “Interim Development Payment”).

Upon achievement of all Conditions Precedent (as defined in the Framework Agreement) for the Initial Project (other than Evolve Approval (as defined in the Framework Agreement)), HOBO will send written notice thereof to us. If we are reasonably satisfied with our review of the Conditions Precedent, then subject to the closing and initial funding of Project Financing (as defined in the Framework Agreement), which is required to cover a specified percentage of the anticipated procurement, construction, completion and commercialization costs of the Initial Project, we will pay to HOBO (i) the lesser of $15.0 million and the aggregate Qualified Development Costs incurred as of such date, minus (ii) the aggregate amount of the Initial Development Payment, the Interim Development Payment and any other Qualified Development Costs previously paid by us (the “Final Development Payment”).

For the Initial Project, HOBO shall also be entitled to payment of an Incentive Development Fee (as defined in the Framework Agreement), equal to 5% of the aggregate capital expenditures in the final capital expenditure budget included in the Final Qualified Project Model (as defined in the Framework Agreement) with a maximum payment of $22.7 million (subject to adjustment for any change in the scope of the Initial Project), at least 50% of which shall be payable in Class A units of the holding company we form in connection with the Initial Project. We may be required to issue common units to HOBO if, at HOBO’s election, it chooses to receive payment of the Incentive Development Fee in the form of common units in lieu of cash or Class A units in the holding company. Half of the Incentive Development Fee shall be due at Financial Close (as defined in the Framework Agreement) and the remaining half shall be due upon the Initial Project

77

achieving Commercial Operation. On or prior to Financial Close, HOBO shall also have the right to commit to purchase up to 10% of the total expected Class A units in the holding company.

If we make each of the required funding payments in connection with the Initial Project, the approximate dollar value of such payments would be approximately $15.0 million plus the amount of the Incentive Development Fee.  As explained above in “Part III, Item 13. Related Party Transactions—Relationship with HOBO,” Messrs. Gibbs, Keuss and Hartigan, the current Chief Executive Officer, Chief Operating Officer and Chief Investment Officer of our general partner, respectively, also serve as the Chief Executive Officer, President, and Executive Vice President and Chief Financial Officer, respectively, of HOBO and own 45.25%, 45.25% and 9.5% of HOBO.  As a result of their ownership of HOBO, each of Messrs. Gibbs, Keuss and Hartigan would receive an aggregate of approximately 45.25%, 45.25% and 9.5%, respectively, of such payments. Additionally, all or part of the cash portion of the Incentive Development Fee may be utilized to purchase Class A units in the holding company. As a result, HOBO may choose to acquire additional interests in the Initial Project as a result of ownership of such Class A units. Any increase in HOBO’s ownership of Class A units would increase each of Messrs. Gibbs, Keuss and Hartigan’s indirect interest in the holding company and could increase the value of their interest in the HOBO Transaction.

Director Independence

See “Part III, Item 10. Directors, Executive Officers, and Corporate Governance” for information regarding director independence.

Item 14. Principal Accountant Fees and Services

We engaged our principal accountant, KPMG LLP (PCAOB ID No. 185) (“KPMG”), to audit our financial statements and perform other professional services for the fiscal years ended December 31, 2021 and 2020.

Audit Fees. The aggregate fees billed for the financial statement audit or services provided in connection with statutory or regulatory filings for the years ended December 31, 2021 and 2020 were $780,500 and $932,857, respectively.

Audit-Related Fees. There were no audit-related fees billed by KPMG for the years ended December 31, 2021 and 2020.

Tax Fees. There were no tax fees billed by KPMG for the years ended December 31, 2021 and 2020.

All Other Fees. There were no other fees billed by KPMG for the years ended December 31, 2021 and 2020.

Audit Committee Pre-Approval Policies and Practices

The Audit Committee must pre-approve any audit and permissible non-audit services performed by our independent registered public accounting firm. In addition, the Audit Committee has oversight responsibility to ensure that the independent registered public accounting firm is not engaged to perform certain enumerated non-audit services, including, but not limited to, bookkeeping, financial information system design and implementation, appraisal or valuation services, internal audit outsourcing services and legal services. The Audit Committee has adopted an audit and non-audit services pre-approval policy, which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent registered public accounting firm must be approved. Pursuant to the policy, all services must be reviewed and approved and the chairman of the Audit Committee has been delegated the authority to specifically pre-approve services, which pre-approval is subsequently reviewed with the committee.  All of the services described as Audit Fees, Audit-Related Fees, Tax Fees and All Other Fees were approved by the Audit Committee.

78

PART IV

Item 15. Exhibit and Financial Statement Schedules

(a) The following documents are filed as a part of this Form 10-K:

1. Financial Statements:

See “Part II, Item 8. Financial Statements and Supplementary Data.”

2. Financial Statement Schedules:

None.

3. Exhibits Required by Item 601 of Regulation S-K.

The exhibits required by Item 601 of Regulation S-K are listed in subparagraph (b) below.

(b) The following exhibits are filed or furnished with this Form 10-K or incorporated by reference:

HIDDEN_ROW
Exhibit
Number	Description
2.1	Membership Interest Purchase and Sale Agreement, dated May 10, 2017, between Sanchez Production Partners LP and Exponent Energy, LLC (incorporated herein by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).
2.2	Purchase and Sale Agreement, dated June 30, 2017, between SEP Holdings IV, LLC and Sendero Petroleum, LLC (incorporated herein by reference to Exhibit 2.2 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).
2.3	Amendment No. 1 to Purchase and Sale Agreement, dated July 31, 2017, between SEP Holdings IV, LLC and Sendero Petroleum, LLC (incorporated herein by reference to Exhibit 2.3 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).
2.4	Purchase and Sale Agreement between Sanchez Midstream Partners LP and Dallas Petroleum Group, LLC dated October 12, 2017 (incorporated herein by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on November 14, 2017, File No. 001-33147).
2.5	Agreement to Purchase Oil and Gas Interests between SEP Holdings IV, LLC and EP Energy E&P Company, L.P., dated April 30, 2018 (incorporated herein by reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on May 10, 2018, File No. 001-33147).
3.1	Certificate of Conversion of Sanchez Production Partners LLC (incorporated herein by reference to Exhibit 4.1 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).
3.2	Certificate of Limited Partnership of Sanchez Production Partners LP (incorporated herein by reference to Exhibit 4.2 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).
3.3	Certificate of Amendment to Certificate of Limited Partnership of Sanchez Production Partners LP (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on June 2, 2017, File No. 001-33147).

79

3.4	Certificate of Amendment to Certificate of Limited Partnership of Sanchez Midstream Partners LP (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on February 26, 2021, File No. 001-33147).
3.5	Third Amended and Restated Agreement of Limited Partnership of Sanchez Production Partners LP (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on August 5, 2019, File No. 001-33147).
3.6	Letter Agreement, dated November 16, 2020, by and between Sanchez Midstream Partners LP, Sanchez Midstream Partners GP LLC and Stonepeak Catarina Holdings LLC (incorporated herein by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on November 16, 2020, File No. 001-33147).
3.7	Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Sanchez Midstream Partners LP (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on February 26, 2021, File No. 001-33147).
3.8	Certificate of Formation of Sanchez Production Partners GP LLC (incorporated herein by reference to Exhibit 4.4 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).
3.9	Certificate of Amendment to Certificate of Formation of Sanchez Midstream Partners GP LLC (incorporated herein by reference to Exhibit 3.3 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on February 26, 2021, File No. 001-33147).
3.10	Limited Liability Company Agreement of Sanchez Production Partners GP LLC (incorporated herein by reference to Exhibit 4.5 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).
3.11	Amendment No. 1 to Limited Liability Company Agreement of Sanchez Production Partners GP LLC (incorporated herein by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q/A filed by Sanchez Production Partners LP on September 3, 2015, File No. 001-33147).
3.12	Amendment No. 2 to Limited Liability Company Agreement of Sanchez Production Partners GP LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).
3.13	Amendment No. 3 to Limited Liability Company Agreement of Sanchez Midstream Partners GP LLC, dated August 2, 2019 (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on August 5, 2019, File No. 001-33147).
3.14	Amendment No. 4 to Limited Liability Company Agreement of Sanchez Midstream Partners GP LLC, dated September 7, 2020 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on September 9, 2020, File No. 001-33147).
3.15	Amendment No. 5 to Limited Liability Company Agreement of Sanchez Midstream Partners GP LLC, dated September 7, 2020 (incorporated herein by reference to Exhibit 3.4 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on February 26, 2021, File No. 001-33147).
4.1	Amended and Restated Registration Rights Agreement, dated August 2, 2019, by and among Sanchez Midstream Partners LP and Stonepeak Catarina Holdings LLC (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on August 5, 2019, File No. 001-33147).

80

4.2*	Description of Registrant Securities.
10.1	Third Amended and Restated Credit Agreement, dated as of March 31, 2015, among Sanchez Production Partners LP, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on April 1, 2015, File No. 001-33147).
10.2	Amendment and Waiver of Third Amended and Restated Credit Agreement, dated as of August 12, 2015, between Sanchez Production Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on August 14, 2015, File No. 001-33147).
10.3	Joinder, Assignment and Second Amendment to Third Amended and Restated Credit Agreement, dated as of October 14, 2015, among Sanchez Production Partners LP, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).
10.4	Third Amendment to Third Amended and Restated Credit Agreement, dated as of November 12, 2015, among Sanchez Production Partners LP, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on November 13, 2015, File No. 001-33147).
10.5	Fourth Amendment to Third Amended and Restated Credit Agreement among Sanchez Production Partners LP, the guarantors party thereto, each of the lenders party thereto, and Royal Bank of Canada, as administrative agent and collateral agent, dated July 5, 2016 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on August 12, 2016, File No. 001-33147).
10.6	Fifth Amendment to the Third Amended and Restated Credit Agreement dated as of April 17, 2017, between Sanchez Production Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on May 15, 2017, File No. 001-33147).
10.7	Sixth Amendment to the Third Amended and Restated Credit Agreement dated as of November 7, 2017, between Sanchez Midstream Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on November 14, 2017, File No. 001-33147).
10.8	Seventh Amendment to the Third Amended and Restated Credit Agreement dated as of February 5, 2018, between Sanchez Midstream Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated herein by reference to Exhibit 10.11 to the Annual Report on Form 10-K filed by Sanchez Midstream Partners LP on March 12, 2018, File No. 001-33147).
10.9	Eighth Amendment to the Third Amended and Restated Credit Agreement dated as of May 7, 2018, between Sanchez Midstream Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on May 10, 2018, File No. 001-33147).

81

10.10	Ninth Amendment to the Third Amended and Restated Credit Agreement dated as of November 22, 2019, between Sanchez Midstream Partners LP, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on November 25, 2019, File No. 001-33147).
10.11	Tenth Amendment to Third Amended and Restated Credit Agreement dated as of November 6, 2020, between Sanchez Midstream Partners LP, the lenders party thereto and Royal Bank of Canada, as Administrative Agent and as Collateral Agent (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on November 9, 2020, File No. 001-33147).
10.12	Eleventh Amendment to Third Amended and Restated Credit Agreement dated as of July 28, 2021, between Evolve Transition Infrastructure LP, the guarantors party thereto, the lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on August 3, 2021, File No. 001-33147).
10.13**	Twelfth Amendment to Third Amended and Restated Credit Agreement dated as of August 20, 2021, between Evolve Transition Infrastructure LP, the guarantors party thereto, the lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on August 23, 2021, File No. 001-33147).
10.14**	Letter Agreement, dated August 10, 2021, between Evolve Transition Infrastructure LP and Royal Bank of Canada (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.15	Purchase Agreement, dated April 30, 2021, by and between SEP Holdings IV, LLC and Bayshore Energy TX LLC (incorporated herein by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.16	Letter Agreement, dated April 30, 2021, by and between SEP Holdings IV, LLC and Bayshore Energy TX LLC (incorporated herein by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.17	Purchase Agreement, dated April 30, 2021, by and between SEP Holdings IV, LLC and Westhoff Palmetto LP (incorporated herein by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.18	Letter Agreement, dated May 11, 2021, by and between Evolve Transition Infrastructure LP, Royal Bank of Canada, as Administrative Agent under the Third Amended and Restated Credit Agreement of the Partnership, as amended, and the lenders party thereto (incorporated herein by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.19	Purchase Agreement, dated May 14, 2021, by and between SEP Holdings IV, LLC and Bayshore Energy TX LLC (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.20	Series B Warrant for the Purchase of 200,000 Shares of Common Stock of Nuvve Holding Corp. issued May 17, 2021 (incorporated herein by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).

82

10.21	Series C Warrant for the Purchase of 100,000 Shares of Common Stock of Nuvve Holding Corp. issued May 17, 2021 (incorporated herein by reference to Exhibit 10.11 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.22	Series D Warrant for the Purchase of 100,000 Shares of Common Stock of Nuvve Holding Corp. issued May 17, 2021 (incorporated herein by reference to Exhibit 10.12 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.23	Series E Warrant for the Purchase of 100,000 Shares of Common Stock of Nuvve Holding Corp. issued May 17, 2021 (incorporated herein by reference to Exhibit 10.13 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.24	Series F Warrant for the Purchase of 100,000 Shares of Common Stock of Nuvve Holding Corp. issued May 17, 2021 (incorporated herein by reference to Exhibit 10.14 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.25	Letter Agreement, dated May 17, 2021, among Stonepeak Rocket Holdings LP, Evolve Transition Infrastructure LP and Nuvve Holding Corp (incorporated herein by reference to Exhibit 10.15 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.26	Securities Purchase Agreement, dated May 17, 2021, by and among Nuvve Holding Corp., Stonepeak Rocket Holdings LP and Evolve Transition Infrastructure LP (incorporated herein by reference to Exhibit 10.16 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.27	Registration Rights Agreement, dated May 17, 2021, by and among Nuvve Holding Corp., Stonepeak Rocket Holdings LP and Evolve Transition Infrastructure LP (incorporated herein by reference to Exhibit 10.17 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.28*	Summary Compensation of Executive Officers of Evolve Transition Infrastructure Partners GP LLC.
10.29*	Summary Compensation of Directors of Evolve Transition Infrastructure GP LLC.
10.30	Amended and Restated Shared Services Agreement, dated as of March 6, 2015, between SP Holdings, LLC and Sanchez Production Partners LP (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Production Partners LP on May 15, 2015, File No. 001-33147).
10.31	Geophysical Seismic Data Use License Agreement, dated as of September 7, 2020, by and among Sanchez Oil & Gas Corporation, Sanchez Midstream Partners LP, Sanchez Midstream Partners GP LLC and SEP Holdings IV, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on September 9, 2020, File No. 001-33147).
10.32	Firm Gathering and Processing Agreement, dated as of October 14, 2015, by and between Catarina Midstream, LLC and SN Catarina, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on October 14, 2015, File No. 001-33147).
10.33	Amendment No. 1 to Firm Gathering and Processing Agreement by and between SN Catarina, LLC and Catarina Midstream, LLC, dated June 30, 2017 (incorporated herein by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed by Sanchez Midstream Partners LP on August 14, 2017, File No. 001-33147).

83

10.34+	Sanchez Production Partners LP Long-Term Incentive Plan (incorporated herein by reference to Exhibit 4.6 to the Post-Effective Amendment No. 1 to the Registration Statement on Form S-4 filed by Sanchez Production Partners LP on March 6, 2015, File No. 333-198440).
10.35+	Form of Award Agreement Relating to Restricted Units (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on December 3, 2015, File No. 001-33147).
10.36+	Form of Award Agreement Relating to Restricted Units (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on March 28, 2017, File No. 001-33147).
10.37	Settlement Agreement and Release, effective January 25, 2017, by and between Stonepeak Catarina Holdings LLC and Sanchez Production Partners LP (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Production Partners LP on January 27, 2017, File No. 001-33147).
10.38+	Form of Award Agreement Relating to Restricted Units (incorporated herein by reference to Exhibit 10.24 to the Annual Report on Form 10-K filed by Sanchez Midstream Partners LP on March 7, 2019, File No. 001-33147).
10.39	Amended and Restated Board Representation and Standstill Agreement, dated August 2, 2019, by and among Sanchez Midstream Partners LP, Sanchez Midstream Partners GP LLC and Stonepeak Catarina Holdings LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on August 5, 2019, File No. 001-33147).
10.40+	Executive Services Agreement, dated as of August 2, 2019, by and between Charles C. Ward and Sanchez Midstream Partners GP LLC (incorporated herein by reference to Exhibit 10.27 to the Annual Report on Form 10-K filed by Evolve Transition Infrastructure LP on March 16, 2021, File No. 001-33147).
10.41+	Executive Services Agreement, dated as of August 2, 2019, by and between Gerald F. Willinger and Sanchez Midstream Partners GP LLC (incorporated herein by reference to 10.28 to the Annual Report on Form 10-K filed by Evolve Transition Infrastructure LP on March 16, 2021, File No. 001-33147).
10.42	Form of Award Agreement Relating to Restricted Units (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on March 23, 2021, File No. 001-33147).
10.43	Award Agreement Relating to Restricted Units, dated March 18, 2021, between Evolve Transition Infrastructure LP and Gerald F. Willinger (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on March 23, 2021, File No. 001-33147).
10.44	Award Agreement Relating to Restricted Units, dated March 18, 2021, between Evolve Transition Infrastructure LP and Charles C. Ward (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on March 23, 2021, File No. 001-33147).
10.45+	Amended and Restated Executive Services Agreement for Realignment, dated April 16, 2021, by and among Gerald F. Willinger, Evolve Transition Infrastructure GP LLC and Evolve Transition Infrastructure LP (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on April 16, 2021, File No. 001-33147).
10.46	ATM Sales Agreement, dated as of April 20, 2021 between Evolve Transition Infrastructure LP and Virtu Americas LLC (incorporated herein by reference to Exhibit 1.1 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on April 20, 2021, File No. 001-33147).

84

10.47+	Separation and Transition Agreement, dated November 3, 2021, by and between Gerald F. Willinger and Evolve Transition Infrastructure GP LLC (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 9, 2021, File No. 001-33147).
10.48+	Executive Services Agreement, dated November 3, 2021, by and between Randall L. Gibbs and Evolve Transition Infrastructure GP LLC (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 9, 2021, File No. 001-33147).
10.49+	Executive Services Agreement, dated November 3, 2021, by and between Mike Keuss and Evolve Transition Infrastructure GP LLC (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 9, 2021, File No. 001-33147).
10.50+	Executive Services Agreement, dated November 3, 2021, by and between Jonathan Hartigan and Evolve Transition Infrastructure GP LLC (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 9, 2021, File No. 001-33147).
10.51	Warrant Exercisable for Junior Securities, dated August 2, 2019, by and between Sanchez Midstream Partners LP and Stonepeak Catarina Holdings LLC (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on August 5, 2019, File No. 001-33147).
10.52	Amendment No. 1 to Warrant Exercisable for Junior Securities, dated February 24, 2021, by and between Sanchez Midstream Partners LP and Stonepeak Catarina Holdings LLC (incorporated herein by reference to Exhibit 10.30 to the Annual Report on Form 10-K filed by Evolve Transition Infrastructure LP on March 16, 2021, File No. 001-33147).
10.53	Amendment No. 2 to Warrant Exercisable for Junior Securities, dated May 4, 2021 (incorporated herein by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on August 12, 2021, File No. 001-33147).
10.54	Amendment No. 3 to Warrant Exercisable for Junior Securities, dated August 2, 2021 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on August 3, 2021, File No. 001-33147).
10.55	Amendment No. 4 to Warrant Exercisable for Junior Securities, dated November 5, 2021 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 10, 2021, File No. 001-33147).
10.56	Amendment No. 5 to Warrant Exercisable for Junior Securities, dated November 9, 2021 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 10, 2021, File No. 001-33147).
10.57	Amendment No. 6 to Warrant Exercisable for Junior Securities, dated February 1, 2022 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on February 3, 2022, File No. 001-33147).
10.58**	Amended and Restated Limited Liability Company Agreement, dated August 4, 2021, by and between Evolve Transition Infrastructure LP, Stonepeak Rocket Holdings LP, Nuvve Corporation, and Levo Mobility LLC (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on November 10, 2021, File No. 001-33147).

85

10.59**	Parent Letter Agreement, dated August 4, 2021, by and between Evolve Transition Infrastructure LP, Stonepeak Rocket Holdings LP, Nuvve Corporation, and Levo Mobility LLC (incorporated herein by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q filed by Evolve Transition Infrastructure LP on November 10, 2021, File No. 001-33147).
10.60+	Inducement Award Agreement Relating to Restricted Units, dated November 3, 2021, between Randall L. Gibbs and Evolve Transition Infrastructure GP LLC (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 9, 2021, File No. 001-33147).
10.61 +	Inducement Award Agreement Relating to Restricted Units, dated November 3, 2021, between Mike Keuss and Evolve Transition Infrastructure GP LLC (incorporated herein by reference to Exhibit 10.8 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 9, 2021, File No. 001-33147).
10.62+	Inducement Award Agreement Relating to Restricted Units, dated November 3, 2021, between Jonathan Hartigan and Evolve Transition Infrastructure GP LLC (incorporated herein by reference to Exhibit 10.9 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 9, 2021, File No. 001-33147).
10.63+	Award Agreement Relating to Restricted Units, dated November 3, 2021, between Randall L. Gibbs and Evolve Transition Infrastructure GP LLC (incorporated herein by reference to Exhibit 10.10 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 9, 2021, File No. 001-33147).
10.64+	Award Agreement Relating to Restricted Units, dated November 3, 2021, between Mike Keuss and Evolve Transition Infrastructure GP LLC (incorporated herein by reference to Exhibit 10.11 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 9, 2021, File No. 001-33147).
10.65+	Award Agreement Relating to Restricted Units, dated November 3, 2021, between Jonathan Hartigan and Evolve Transition Infrastructure GP LLC (incorporated herein by reference to Exhibit 10.12 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 9, 2021, File No. 001-33147).
10.66+	Award Letter Agreement, dated March 13, 2020, by and between Gerald F. Willinger and Sanchez Midstream Partners GP LLC (incorporated herein by reference to Exhibit 10.35 to the Annual Report on Form 10-K filed by Evolve Transition Infrastructure LP on March 16, 2021, File No. 001-33147).
10.67+	Award Letter Agreement, dated March 13, 2020, by and between Charles C. Ward and Sanchez Midstream Partners GP LLC (incorporated herein by reference to Exhibit 10.36 to the Annual Report on Form 10-K filed by Evolve Transition Infrastructure LP on March 16, 2021, File No. 001-33147).
10.68	Full and Final Settlement and Release Agreement, dated as of December 23, 2020, by and among Dimension Energy Services, LLC, Sunbelt Tractor & Equipment Company, Sanchez Oil and Gas Corporation, Mesquite Energy, Inc., Sanchez Midstream Partners LP, Seco Pipeline LLC and Sanchez Midstream Partners GP LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Sanchez Midstream Partners LP on December 30, 2020, File No. 001-33147).
10.69**	Gas Lift Agreement, entered into on April 21, 2021 but effective January 1, 2021, by and between SN Catarina, LLC and Catarina Midstream, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on April 26, 2021, File No. 001-33147).

86

10.70**	Framework Agreement, dated as of November 3, 2021, by and between HOBO Renewable Diesel LLC and Evolve Transition Infrastructure LP (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Evolve Transition Infrastructure LP on November 9, 2021, File No. 001-33147).
10.71*+	Evolve Transition Infrastructure LP 2021 Equity Inducement Award Plan, effective as of November 3, 2021.
21.1*	List of subsidiaries of Evolve Transition Infrastructure LP.
23.1*	Consent of KPMG LLP.
31.1*	Certification of Chief Executive Officer of Evolve Transition Infrastructure GP LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer and Secretary of Evolve Transition Infrastructure GP LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer of Evolve Transition Infrastructure GP LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer and Secretary of Evolve Transition Infrastructure GP LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	Inline XBRL Instance Document
101.SCH*	Inline XBRL Schema Document
101.CAL*	Inline XBRL Calculation Linkbase Document
101.LAB*	Inline XBRL Label Linkbase Document
101.PRE*	Inline XBRL Presentation Linkbase Document
101.DEF*	Inline XBRL Definition Linkbase Document
104	Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101)

* Filed herewith

** Certain portions of this exhibit (indicated by “[***]”) have been omitted pursuant to Item 601(b)(10) of Regulation S-K.

+ Management contract or compensatory plan or arrangement.

Item 16. Form 10-K Summary

None.

87

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

		Evolve Transition Infrastructure LP
	By:	Evolve Transition Infrastructure GP LLC,
		its general partner
Date: March 30, 2022	By	/S/    Randall L. Gibbs
	Name	Randall L. Gibbs
	Title	Chief Executive Officer

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below, constitutes and appoints Randall L. Gibbs and Charles C. Ward, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite or necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

This report has been signed below by the following persons on behalf of the general partner of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/  Randall L. Gibbs	Director; Chief Executive Officer	March 30, 2022
Randall L. Gibbs	(Principal Executive Officer)
/S/  Charles C. Ward	Chief Financial Officer & Secretary	March 30, 2022
Charles C. Ward	(Principal Financial Officer)
/S/  John T. Steen III	Director; Chairman of the Board	March 30, 2022
John T. Steen III
/s/ Michael A. Keuss	President and Chief Operating Officer	March 30, 2022
Michael A. Keuss
/s/ Jonathan C. M. Hartigan	President and Chief Investment Officer	March 30, 2022
Jonathan C. M. Hartigan
/S/  Michael Bricker	Director	March 30, 2022
Michael Bricker
/S/  Jack Howell	Director	March 30, 2022
Jack Howell
/S/  Richard S. Langdon	Director	March 30, 2022
Richard S. Langdon
/S/  Steven E. Meisel	Director	March 30, 2022
Steven E. Meisel
/S/  Luke R. Taylor	Director	March 30, 2022
Luke R. Taylor

88

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Evolve Transition Infrastructure LP and Subsidiaries:
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 185)	F-2
Consolidated Statements of Operations	F-4
Consolidated Balance Sheets	F-5
Consolidated Statements of Cash Flows	F-6
Consolidated Statements of Changes in Partners’ Capital	F-7
Notes to Consolidated Financial Statements	F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Evolve Transition Infrastructure LP and the Board of Directors of Evolve Transition Infrastructure GP LLC
Evolve Transition Infrastructure LP:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Evolve Transition Infrastructure LP and subsidiaries (the Partnership) as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in partners’ capital, and cash flows for each of the years in the two-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.

Evaluation of gathering and transportation assets for impairment triggering events

As discussed in Note 8 to the consolidated financial statements, the Partnership performs a periodic assessment of gathering and transportation assets to identify facts or circumstances, or triggering events, that indicate the carrying value of such assets may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. As of December 31, 2021, the Partnership had $98.5 million of gathering and transportation assets.

F-2

We identified the evaluation of gathering and transportation assets for impairment triggering events as a critical audit matter. Sustained decreases in pricing or throughput volumes and significant increases in competition or operating costs could significantly affect the recoverability of the gathering and transportation assets, and the evaluation of these factors required a higher degree of auditor judgment.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the Partnerships’ identification and assessment of triggering events by comparing actual operating and financial results to historical results as well as forecasts for the current year. We also evaluated whether there are new gathering or transportation options for their customers. For a selection of revenue transactions throughout the year we compared the throughput volumes and pricing in those transactions to the underlying revenue agreements to identify modifications to the revenue agreements that could have a significant effect on the recoverability of the assets.

Impairment assessment of the Carnero equity method investment

As discussed in Notes 2 and 12 to the consolidated financial statements, the Partnership’s equity method investment in Carnero G&P, LLC (Carnero JV) at December 31, 2021 was $20.2 million. The Partnership evaluates its equity investments for impairment when evidence indicates that a loss in value may have occurred or the carrying amount of their investment is no longer recoverable. The Partnership determines the fair value of the EMI using an income approach. Certain inputs included in the income approach, including sales projections, discount rate and exit multiple are unobservable and require management judgment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, the Partnership recognizes the excess of the carrying value over the estimated fair value as an impairment loss within earnings from equity investments in its consolidated statements of operations.

We identified the evaluation of the fair value estimate of the equity method investment in Carnero JV used in the impairment assessment as a critical audit matter. A high degree of subjective auditor judgment was required to evaluate certain assumptions within the discounted cash flow model used to estimate the fair value of the equity method investment, including sales projections, discount rate, and exit multiple as these inputs were not observable in the market. The fair value is also sensitive to changes to the sales projections, discount rate, and exit multiple assumptions.

The following are the primary procedures we performed to address this critical audit matter. We evaluated management’s sales projections for Carnero JV by comparing them to Carnero JV’s historical sales, historical throughput volumes, existing contracts and customer projections. We involved valuation professionals with specialized skills and knowledge who assisted in:

–evaluating the discount rate by comparing it against an independently developed discount rate range that was developed using publicly available data for comparable entities, and

​
–evaluating reasonableness of management’s exit multiple by comparing it to multiples for guideline public companies and making certain adjustments based on the size and customer base specific to the Carnero JV.

/s/ KPMG LLP

We have served as the Partnership’s auditor since 2013.

Houston, Texas
March 30, 2022

F-3

EVOLVE TRANSITION INFRASTRUCTURE LP and SUBSIDIARIES

Consolidated Statements of Operations

(In thousands, except unit data)

	Years Ended
	December 31,
	2021		2020
Revenues
Gathering and transportation sales	$	—	$	785
Gathering and transportation lease revenues		51,482		44,671
Total revenues		51,482		45,456
Expenses
Operating expenses
Transportation operating expenses		8,501		10,198
General and administrative expenses		10,103		18,296
Unit-based compensation expense		955		2,602
Depreciation and amortization		20,559		20,655
Asset impairments		—		867
Accretion expense		387		355
Total operating expenses		40,505		52,973
Other (income) expense
Interest expense, net		112,969		95,871
Loss (earnings) from equity investment		54,073		(4,479)
Other (income) expense		(643)		(71)
Total other expenses		166,399		91,321
Total expenses		206,904		144,294
Loss before income taxes		(155,422)		(98,838)
Income tax expense (benefit)		(5)		159
Loss from continuing operations		(155,417)		(98,997)
Income (loss) from discontinued operations		878		(19,764)
Net loss	$	(154,539)	$	(118,761)
Loss from continuing operations per unit
Common units - Basic and Diluted	$	(2.05)	$	(4.96)
Loss from discontinued operations per unit
Common units - Basic and Diluted	$	0.01	$	(0.99)
Net loss per unit
Common units - Basic and Diluted	$	(2.04)	$	(5.94)
Weighted Average Units Outstanding
Common units - Basic and Diluted		75,693,259		19,978,633

See accompanying notes to consolidated financial statements.

F-4

EVOLVE TRANSITION INFRASTRUCTURE LP and SUBSIDIARIES

Consolidated Balance Sheets

(In thousands, except unit data)

	December 31,
	2021		2020
ASSETS
Current assets
Cash and cash equivalents	$	1,675	$	1,718
Accounts receivable		19,466		5,259
Prepaid expenses		629		404
Fair value of warrants		664		—
Current assets from discontinued operations		—		1,602
Total current assets		22,434		8,983
Gathering and transportation assets, net		98,235		105,323
Intangible assets, net		118,329		131,786
Equity investments		20,198		89,635
Right of use assets, net		1,428		—
Other non-current assets		75		25
Long-term assets from discontinued operations		—		17,969
Total assets	$	260,699	$	353,721
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities
Accounts payable and accrued liabilities	$	3,225	$	4,079
Accounts payable and accrued liabilities - related entities		12,869		25,737
Royalties payable		359		359
Short-term debt, net of debt issuance costs		8,841		110,233
Class C Preferred Units		397,387		345,205
Short term lease liabilities		391		—
Current liabilities from discontinued operations		79		341
Total current liabilities		423,151		485,954
Other liabilities
Long term accrued liabilities - related entities		10,215		12,137
Asset retirement obligation		4,700		4,313
Long-term debt, net of discount and debt issuance costs		39,488		—
Long-term lease liabilities		782		—
Other liabilities		7,483		1,709
Long-term liabilities from discontinued operations		—		3,152
Total other liabilities		62,668		21,311
Total liabilities		485,819		507,265
Commitments and contingencies (See Note 13)
Partners' deficit
Common units, 124,448,646 and 19,953,880 units issued and outstanding as of December 31, 2021 and December 31, 2020, respectively		(225,120)		(153,544)
Total partners' deficit		(225,120)		(153,544)
Total liabilities and partners' capital	$	260,699	$	353,721

See accompanying notes to consolidated financial statements.

F-5

EVOLVE TRANSITION INFRASTRUCTURE LP and SUBSIDIARIES

Consolidated Statements of Cash Flows

(In thousands)

	Years Ended
	December 31,
	2021		2020
Cash flows from operating activities:
Net loss	$	(154,539)	$	(118,761)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion and amortization		7,541		9,413
Amortization of debt issuance costs		921		767
Accretion of Class C discount		52,182		38,938
Class C distribution accrual		—		50,317
Asset impairments		—		24,222
Accretion expense		460		567
Distributions from equity investments		15,596		15,266
Equity earnings in affiliate		54,073		(4,479)
Bad debt expense		(1,926)		—
Gain on sale of assets		(537)		—
Mark-to-market on Stonepeak Warrant		5,779		787
Net gain on commodity derivative contracts		—		(3,901)
Net cash settlements received on commodity derivative contracts		101		3,054
Gain on Nuvve Holding Warrants		(664)		—
Unit-based compensation		2,291		2,602
Amortization of intangible assets		13,457		13,460
Changes in Operating Assets and Liabilities:
Accounts receivable		(12,726)		(6,499)
Accounts receivable - related entities		—		6,719
Prepaid expenses		(34)		598
Other assets		118		(115)
Accounts payable and accrued liabilities		63,452		(27,363)
Accounts payable and accrued liabilities- related entities		(14,790)		32,351
Other long-term liabilities		289		—
Net cash provided by operating activities		31,044		37,943
Cash flows from investing activities:
Proceeds from sales of oil and natural gas properties		15,721		—
Development of oil and natural gas properties		—		5
Construction of gathering and transportation assets		(133)		(1,832)
Contributions to equity affiliates		(232)		(111)
Net cash provided by (used in) investing activities		15,356		(1,938)
Cash flows from financing activities:
Repayment of debt		(67,300)		(52,000)
Proceeds from issuance of debt		5,500		13,000
Issuance of common units		17,054		—
Payments for offering costs		(672)		—
Units tendered by employees for tax withholdings		—		(41)
Debt issuance costs		(1,025)		(345)
Net cash used in financing activities		(46,443)		(39,386)
Net decrease in cash and cash equivalents		(43)		(3,381)
Cash and cash equivalents, beginning of period		1,718		5,099
Cash and cash equivalents, end of period	$	1,675	$	1,718
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	$	255	$	796
Cash paid during the period for income tax	$	139	$	242
Cash paid during the period for interest	$	2,575	$	5,235

See accompanying notes to consolidated financial statements.

F-6

EVOLVE TRANSITION INFRASTRUCTURE and SUBSIDIARIES

Consolidated Statements of Changes in Partners’ Capital

(In thousands, except unit data)

	Common Units			Total
	Units	Amount		Capital
Partners' Deficit, December 31, 2019	20,087,462	$	(35,800)	$	(35,800)
Unit-based compensation programs	(24,896)		1,058		1,058
Units tendered by SOG employees for tax withholdings	(108,686)		(41)		(41)
Net loss	—		(118,761)		(118,761)
Partners' Deficit, December 31, 2020	19,953,880	$	(153,544)	$	(153,544)
Unit-based compensation programs	18,662,379		2,291		2,291
Issuance of common units, net of offering costs of $0.7 million	18,503,742		16,382		16,382
Common units issued as Class C Preferred distributions	67,328,645		64,290		64,290
Net loss	—		(154,539)		(154,539)
Partners' Deficit, December 31, 2021	124,448,646	$	(225,120)	$	(225,120)

See accompanying notes to consolidated financial statements.

F-7

EVOLVE TRANSITION INFRASTRUCTURE and SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2021 and 2020

1. ORGANIZATION AND BUSINESS

Organization

We are a publicly-traded limited partnership formed in 2005 focused on the acquisition, development, and ownership of infrastructure critical to the transition of energy supply to lower carbon sources. We own natural gas gathering systems, pipelines, and processing facilities in South Texas and continue to pursue energy transition infrastructure opportunities. Our common units are currently listed on the NYSE American under the symbol “SNMP.”

On February 26, 2021, in connection with our management team’s focus on expanding our business strategy to focus on the ongoing energy transition in the industries in which we operate, we changed our name from Sanchez Midstream Partners to Evolve Transition Infrastructure LP and our general partner changed its name to Evolve Transition Infrastructure GP LLC.

2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Accounting policies used by us conform to accounting principles generally accepted in the United States of America (“GAAP”). The accompanying financial statements include the accounts of us and our wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.  

Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date.  Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our consolidated financial statements upon adoption.

In January 2020, the FASB issued Accounting Standards Update (“ASU”) 2020-01 “Investments – Equity Securities (Topic 321), Investments – Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815),” which clarifies the interaction among the accounting standards for equity securities, equity method investments and certain derivatives. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2020. The adoption of this standard did not have a material impact on our condensed consolidated financial statements.

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in more timely recognition of losses. Additionally, in November 2019, the FASB issued ASU 2019-10 “Financial Instruments – Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates,” which changed the effective date for certain issuers to annual and interim periods in fiscal years beginning after December 15, 2022, and earlier adoption is permitted. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements.

Use of Estimates

The consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes.  These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses.  The estimates that are particularly significant to our financial statements include our ability to continue as a going concern; depreciation, depletion and

F-8

amortization; asset retirement obligations; certain revenues and operating expenses; fair values of derivatives; and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best judgment using the data available.  Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances.  Such estimates and assumptions are adjusted when facts and circumstances dictate.  As future events and their effects cannot be determined with precision, actual results could differ from the estimates.  Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Revenue Recognition

We account for revenue from contracts with customers in accordance with ASC 606 and ASC 842 for our midstream segment. The Seco Pipeline Transportation Agreement is our only contract that we account for using ASC 606. Under the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. As such, we applied the series guidance and treat these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. Additionally, Seco Pipeline Transportation Agreement contains variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606. Under this exception, revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved.

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.  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 for processing and transportation through Western Catarina Midstream, with the potential to tender additional volumes outside of the dedicated acreage (the “Gathering Agreement”).

The Gathering Agreement was classified as an operating lease at inception and is accounted for under ASC 842, as Mesquite controls the physical use of the property under the lease. Revenues relating to the Gathering Agreement is recognized in the period service is provided. Under this arrangement, the Partnership receives a fee or fees for services provided. The revenue the Partnership recognizes from gathering and transportation services is generally directly related to the volume of oil and natural gas that flows through its systems.

Accounts Receivable, Net

Our accounts receivable are primarily from our contractual agreements with Mesquite and its subsidiaries. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. Our allowance for doubtful accounts was $0.4 million as of December 31, 2021 and 2020.

Concentration of Credit Risk and Accounts Receivable

Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents and accounts receivable. We place our cash with high credit quality financial institutions. We routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. We have no off-balance-sheet credit exposure related to our operations or customers.

Mesquite accounted for 93% and 80% of total revenue for the years ended December 31, 2021 and 2020, respectively. We are highly dependent upon Mesquite as our most significant customer, and we expect to derive a

F-9

substantial portion of our revenue from Mesquite in the foreseeable future.  Accordingly, we are indirectly subject to the business risks of Mesquite. 

Income Taxes

The Partnership and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes.  All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements.

Earnings per Unit

Net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss) based on provisions of our partnership agreement, divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss) as if all of the income for the period had been distributed in accordance with our partnership agreement. Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units based on provisions of our partnership agreement. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

Asset Retirement Obligations

Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, asset life, inflation and the credit-adjusted risk-free rate. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset and is included in accretion expense in the our consolidated statements of operations.

To estimate the fair value of an asset retirement obligation, the Partnership employs a present value technique, which reflects certain assumptions, including its credit-adjusted risk-free interest rate, inflation rate, the estimated settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.

Gathering and Transportation Assets

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 three to 15 years for furniture and equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets.

Estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over the useful life of the asset. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

We perform a periodic assessment of gathering and transportation assets to identify facts and circumstances, or triggering events, that indicate the carrying value may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow

F-10

estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our gathering and transportation assets and the recognition of additional impairments. Refer to Note 8 “Gathering and Transportation Related Assets” to our consolidated financial statements for additional information.

Leases

Our leasing activity primarily consists of field equipment. We determine if an arrangement is an operating or finance lease at inception. Right of use assets represent our right to use an underlying asset for the lease term when we control the use of the asset by obtaining substantially all of the economic benefits of the asset and direct the use of the asset. Lease liabilities represent our obligation to make lease payments arising from the lease. Right of use assets and lease liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. The interest rate used to calculate the present value of lease payments is the rate implicit in the lease when determinable or our incremental borrowing rate. Our incremental borrowing rate is primarily based on our collateralized borrowing rate when such borrowings exist or an estimated collateralized borrowing rate based on independent third party quotes when such borrowings do not exist. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. Operating lease expense is recognized on a straight-line basis over the lease term. Finance lease expense is recognized based on the effective-interest method and amortization of the right of use asset is recognized based on the straight-line method.

Unit-Based Compensation

The Partnership records unit-based compensation expense for awards granted in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Unit-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method.

Investments

We follow the equity method of accounting when we do not exercise control over the investee, but we can exercise significant influence over the operating and financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. The Partnership determines the fair value of the equity method investment using an income approach. Certain inputs included in the income approach, including sales projections, discount rate and exit multiple are unobservable and require management judgement. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as an impairment loss within earnings from equity investments in our consolidated statements of operations.

Earnout Derivative

As part of the Carnero Gathering Transaction (as defined in Note 12. “Investments”), we are required to pay Mesquite an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Mesquite and other producers. The earnout derivative is accounted for under ASC 815, and we measure its fair value through the use of a Monte Carlo simulation model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios. 

F-11

3. DISCONTINUED OPERATIONS

Palmetto Divestiture

On April 30, 2021, but effective March 1, 2021 (the “Palmetto Effective Time”), SEP Holdings IV, LLC (“SEP IV”), a wholly-owned subsidiary of the Partnership entered into a purchase agreement (the “Palmetto PSA”) with Westhoff Palmetto LP (“Palmetto Buyer”), pursuant to which SEP IV sold to Palmetto Buyer specified wellbores and other associated assets located in Gonzales and Dewitt Counties, Texas (the “Palmetto Assets”) for a base purchase price of approximately $11.5 million, including the impact of final post-closing adjustments (the “Palmetto Divestiture”). Pursuant to the Palmetto PSA, other than a limited amount of retained obligations, Palmetto Buyer has agreed to assume all obligations relating to the Palmetto Assets that arose on or after the Palmetto Effective Time. The Palmetto PSA contains customary representations and warranties by SEP IV and Palmetto Buyer, and SEP IV and Palmetto Buyer have agreed to customary indemnities relating to breaches of representations, warranties and covenants and the payment of assumed and excluded obligations. The Palmetto Divestiture closed simultaneously with the execution of the Palmetto PSA and we recorded a gain of approximately $0.3 million on the sale.

Maverick Divestitures

On April 30, 2021, but effective March 1, 2021 (the “Maverick Effective Time”), SEP IV entered into a purchase agreement (the “Maverick PSA”) with Bayshore Energy TX LLC (“Maverick Buyer”), pursuant to which SEP IV sold to Maverick Buyer specified wellbores and other associated assets located in Zavala County, Texas (the “Maverick 1 Assets”) for a base purchase price of approximately $2.8 million, prior to post-closing adjustments (the “Maverick 1 Divestiture”). Pursuant to the Maverick PSA, other than a limited amount of retained obligations, Maverick Buyer has agreed to assume all obligations relating to the Maverick 1 Assets that arose on or after the Maverick Effective Time. The Maverick PSA contains customary representations and warranties by SEP IV and Maverick Buyer, and SEP IV and Maverick Buyer agreed to customary indemnities relating to breaches of representations, warranties and covenants and the payment of assumed and excluded obligations. The Maverick 1 Divestiture closed simultaneously with the execution of the Maverick PSA.

Also on April 30, 2021, SEP IV entered into a letter agreement with Maverick Buyer (the “Maverick Letter Agreement”) pursuant to which SEP IV agreed to sell additional other specified wellbores and other associated assets located in Zavala and Dimmit Counties, Texas (the “Maverick 2 Assets”) for a base purchase price of approximately $1.4 million, which remains subject to final post-closing adjustments expected in the fourth quarter of 2021 (the “Maverick 2 Divestiture”). The closing of the Maverick 2 Divestiture was conditioned upon SEP IV obtaining certain consents and complying with other preferential rights related to the Maverick 2 Assets. Following the entrance into the Maverick Letter Agreement, SEP IV complied with the preferential rights and obtained multiple consents related to the Maverick 2 Assets. SEP IV did not obtain one of the required consents and, as a result, the Maverick 2 Assets subject to such consent were removed from the Maverick 2 Assets included in the Maverick 2 Divestiture (the “Updated Maverick 2 Assets”) and the base purchase price was adjusted downward by approximately $31,000.

On May 14, 2021, but effective as of the Maverick Effective Time, SEP IV and Maverick Buyer entered into a purchase agreement (the “Maverick 2 PSA”) pursuant to which SEP IV sold to Maverick Buyer the Updated Maverick 2 Assets. Pursuant to the Maverick 2 PSA, other than a limited amount of retained obligations, Maverick Buyer agreed to assume all obligations and liabilities related to the Updated Maverick 2 Assets that arose on or after the Maverick Effective Time. The Maverick 2 PSA contains customary representations and warranties by SEP IV and Maverick Buyer, and SEP IV and Maverick Buyer agreed to customary indemnities relating to breaches of representations, warranties and covenants and the payment of assumed and excluded obligations. The Maverick 2 Divestiture closed simultaneously with the execution of the Maverick 2 PSA.

On August 13, 2021, but effect as of the Maverick Effective Time, SEP IV and Maverick Buyer entered into a Purchase Agreement (the “Maverick 3 PSA”) pursuant to which SEP IV sold to Maverick Buyer specified wellbores and other associated assets located in Zavala County, Texas, including the remaining Maverick 2 Assets excluded from the original closing of the Maverick 2 Divestiture (the “Maverick 3 Assets”) for a base purchase price of approximately $31,000, prior to post-closing adjustments (the “Maverick 3 Divestiture” and together with the Maverick 1 Divestiture and the Maverick 2 Divestiture, the “Maverick Divestitures”). Pursuant to the Maverick 3 PSA, other than a limited amount of

F-12

retained obligations, Maverick Buyer agreed to assume all obligations and liabilities related to the Maverick 3 Assets that arose on or after the Maverick Effective Time. The Maverick 3 PSA contains customary representations and warranties by SEP IV and Maverick Buyer, and SEP IV and Maverick Buyer agreed to customary indemnities relating to breaches of representations, warranties and covenants and the payment of assumed and excluded obligations. The Maverick 3 Divestiture closed simultaneously with the execution of the Maverick 3 PSA.

We recorded a net loss of approximately $0.3 million related to the Maverick Divestitures.

Information related to the upstream oil and natural gas assets sold have been reflected in the consolidated financial statements as discontinued operations. The following table presents the results of operations and the gain on disposal which has been included in discontinued operations (in thousands):

	Years Ended
	December 31,
	2021		2020
Revenues
Natural gas sales	$	255	$	427
Oil sales		3,241		10,856
Natural gas liquid sales		182		254
Total revenues		3,678		11,537
Expenses
Operating expenses
Lease operating expenses		1,797		5,340
Production taxes		160		311
Gain on sale of assets		(67)		—
Depreciation, depletion and amortization		439		2,218
Asset impairments		—		23,355
Accretion expense		73		212
Total operating expenses		2,402		31,436
Income (loss) before income taxes		1,276		(19,899)
Income tax expense (benefit)		398		(135)
Income (loss) from discontinued operations	$	878	$	(19,764)

4. REVENUE RECOGNITION

Revenue from Contracts with Customers

The majority of our revenues are accounted for under ASC 842, “Leases,” however, to a limited extent, some revenues are accounted for under ASC 606, “Revenue from Contracts with Customers.”

The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.

Disaggregation of Revenue

We recognized revenue of approximately $51.5 million and $44.7 million for the years ended December 31, 2021 and 2020, respectively related to lease revenue under ASC 842. As of December 31, 2021 and 2020, our accounts receivable from lease revenue were approximately $19.1 million and $3.3 million, respectively. Mesquite accounted for 93% and 80% of total revenue for the years ended December 31, 2021 and 2020, respectively. We are highly dependent upon Mesquite as our most significant customer.  

During the year ended December 31, 2021, we did 0t record any revenue under ASC 606.  We recognized approximately $0.8 million of revenue under ASC 606 for the year ended December 31, 2020. We disaggregate revenue

F-13

based on revenue and product type. In selecting the disaggregation categories, we considered a number of factors, including disclosures presented outside the financial statements, such as in our earnings release and investor presentations, information reviewed internally for evaluating performance, and other factors used by the Partnership or the users of its financial statements to evaluate performance or allocate resources.  We have concluded that disaggregating revenue by revenue and product type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.

The Firm Transportation Service Agreement, dated September 1, 2017, by and between Seco Pipeline, LLC and SN Catarina, LLC (the “Seco Pipeline Transportation Agreement”) is the only contract that we historically accounted for under ASC 606. The Seco Pipeline Transportation Agreement was terminated by Mesquite effective February 12, 2020. The Gathering Agreement is classified as an operating lease and is accounted for under ASC 842, “Leases” and is reported as gathering and transportation lease revenues in our condensed consolidated statements of operations.

We account for income from our unconsolidated equity method investments as earnings from equity investments in our condensed consolidated statements of operations. Earnings from these equity method investments are further discussed in Note 12 “Investments.”

Performance Obligations

Pursuant to the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. We applied the series guidance and treat these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. The Seco Pipeline Transportation Agreement requires payment within 30 days following the calendar month of delivery.

The Seco Pipeline Transportation Agreement contains variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606 which is available only for wholly unsatisfied performance obligations for which the criteria in ASC 606 have been met. Under this exception, neither estimation of variable consideration nor disclosure of the transaction price allocated to the remaining performance obligations is required. Revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved.

For forms of variable consideration that are not associated with a specific volume (such as late payment fees) and thus do not meet allocation exception, estimation is required. These fees, however, are immaterial to our consolidated financial statements and have a low probability of occurrence. As significant reversals of revenue due to this variability are not probable, no estimation is required.

Contract Balances

At December 31, 2021, and 2020 our accounts receivable from contracts with customers were approximately $19.1 million and approximately $3.3 million, respectively, under ASC 842. The gathering and transportation lease revenues utilized to determine net loss for the year ended December 31, 2021 do not net out the approximately $16.2 million of such revenues that have not been collected from Mesquite. As previously disclosed, on June 24, 2021, we increased the tariff rate for interruptible throughput volumes from Eastern Catarina. Despite the increase, Mesquite continues to short-pay invoices and is currently paying the fees being charged for throughput volumes from Western Catarina for all throughput volumes from Eastern Catarina. As previously disclosed, we are currently engaged in the Catarina Arbitration with Mesquite, which seeks to bring commercial resolution to the tariff rate on Eastern Catarina and all disputed amounts are being held in suspense during the pendency of the Catarina Arbitration. We continue to evaluate the collectability of the amounts being held in suspense. Additionally, we are also involved in the Mesquite Adversary. There can be no guarantee that we are able to reach any commercial resolution and our failure to do so could adversely affect our business, financial condition, cash flows and results of operations.

F-14

Under our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under ASC 606. At December 31, 2021, and 2020 our accounts receivable from contracts with customers were 0 and approximately $1.9 million, respectively, and are presented within accounts receivable – related entities on the consolidated balance sheets.

5. FAIR VALUE MEASUREMENTS

Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:

Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the term of the instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity).

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2021 (in thousands):

	Fair Value Measurements at December 31, 2021
	Active Markets for		Observable
	Identical Assets		Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
Fair value of warrants
Nuvve Holding Warrants	$	—	$	664	$	—	$	664
Other liabilities
Stonepeak Warrant		—		(7,197)		—		(7,197)
Total	$	—	$	(6,533)	$	—	$	(6,533)

The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2020 (in thousands):

	Fair Value Measurements at December 31, 2020
	Active Markets for		Observable
	Identical Assets		Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
Other liabilities
Stonepeak Warrant		—		(1,418)		—		(1,418)
Total	$	—	$	(1,418)	$	—	$	(1,418)

F-15

As of December 31, 2021 and 2020, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature.

Fair Value on a Non-Recurring Basis

The Partnership follows the provisions of Topic 820-10, “Fair Value Measurement,” for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. We periodically review oil and natural gas properties and related equipment for impairment when facts and circumstances indicate that their carrying values may not be recoverable.

A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 10 “Asset Retirement Obligation.”

The following table summarizes the non-recurring fair value measurements of our production assets as of December 31, 2020 (in thousands):

	Fair Value Measurements at December 31, 2020
	Active Markets for		Observable
	Identical Assets		Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)
Impairment(a)	$	—	$	—	$	12,884
Total net assets	$	—	$	—	$	12,884

(a) During the year ended December 31, 2020, we recorded non-cash impairment charges of $23.4 million to impair our producing oil and natural gas properties and $0.9 million to impair the Seco Pipeline. The carrying values of the impaired properties were reduced to a fair value of $12.9 million, estimated using inputs characteristic of a Level 3 fair value measurement.

We had 0 non-recurring fair value measurements of our gathering and transportation assets as of December 31, 2021.

The fair values of oil and natural gas properties and related equipment were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties and related equipment include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; (v) estimated throughput; and (vi) a market-based weighted average cost of capital rate of 15%. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change.

Seco Pipeline – We own and operate a 30-mile natural gas pipeline with 400 MMcf/d capacity that is designed to transport dry gas to multiple markets in South Texas (the “Seco Pipeline”). As of December 31, 2020, we recorded a non-cash impairment charge of $0.9 million to impair the Seco Pipeline. The carrying value of the Seco Pipeline was reduced to a fair value of zero, estimated based on inputs characteristic of a Level 3 fair value measurement.

The fair value of the Seco Pipeline was measured using probabilistic valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of the Seco Pipeline include estimates of: (i) future operating and development costs; (ii) estimated future cash flows; and (iii) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change.  

Fair Value of Financial Instruments

The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below. We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value.

Credit Agreement – We believe that the carrying value of our Credit Agreement (defined in Note 7 “Debt”) approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar

F-16

terms.  The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties.  The Credit Agreement is discussed further in Note 7 “Debt.”

Nuvve Holding Warrants – The Nuvve Holding Warrants (as defined in Note 6. “Derivative and Financial Instruments”) are valued using the value of Nuvve’s common stock and the Nuvve Holding Warrants exercise price. We have therefore classified the fair value measurement of the Nuvve Holding Warrants as Level 2 and is presented within fair value of warrants on the condensed consolidated balance sheets.

Stonepeak Warrant – As part of the Exchange (as defined in Note 16. “Partners’ Capital”), the Partnership issued to Stonepeak Catarina the Stonepeak Warrant which entitles the holder to receive junior securities of the Partnership representing ten percent of junior securities deemed outstanding when exercised. The Stonepeak Warrant is valued using ten percent of the Partnership’s junior securities deemed outstanding and the common unit price as of the balance sheet date. We have therefore classified the fair value measurement of the Stonepeak Warrant as Level 2 and is presented within other liabilities on the condensed consolidated balance sheets.

Earnout Derivative – As part of the Carnero Gathering Transaction (as defined in Note 12. “Investments”), we are required to pay Mesquite an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Mesquite and other producers. The earnout derivative was valued through the use of a Monte Carlo simulation model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios. We have therefore classified the fair value measurements of the earnout derivative as Level 3 inputs.  For the years ended December 31, 2021 and 2020, the fair value of the earnout was determined to be 0.

6. DERIVATIVE AND FINANCIAL INSTRUMENTS

On May 17, 2021, the Partnership entered into a letter agreement (the “Levo Letter Agreement”) with Nuvve Holding Corp. (“Nuvve Holding”) and Stonepeak Rocket Holdings LP (“Stonepeak Rocket”), relating to the proposed formation of a joint venture, Levo Mobility LLC (“Levo” and such proposed joint venture, the “Levo JV”). In connection with the Levo Letter Agreement, on May 17, 2021, Nuvve Holding issued ten-year warrants to the Partnership as follows: (i) Series B Warrants to purchase 200,000 shares of Nuvve Holding’s common stock, at an exercise price of $10.00 per share, which are fully vested upon issuance, (ii) Series C warrants to purchase 100,000 shares of Nuvve Holding’s common stock, at an exercise price of $15.00 per share, which are vested as to 50% of the shares upon issuance and vest as to the remaining 50% when Levo has entered into contracts with third parties for $125 million in aggregate capital expenditures; (iii) Series D warrants to purchase 100,000 shares of Nuvve Holding’s common stock, at an exercise price of $20.00 per share, which are vested as to 50% of the shares upon issuance and vest as to the remaining 50% when Levo has entered into contracts with third parties for $250 million in aggregate capital expenditures; (iv) Series E warrants to purchase 100,000 shares of Nuvve Holding’s common stock, at an exercise price of $30.00 per share, which are vested as to 50% of the shares upon issuance and vest as to the remaining 50% when Levo has entered into contracts with third parties for $375 million in aggregate capital expenditures; and (v) Series F warrants to purchase 100,000 shares of Nuvve Holding’s common stock, at an exercise price of $40.00 per share, which are vested as to 50% of the shares upon issuance and vest as to the remaining 50% when Levo has entered into contracts with third parties for $500 million in aggregate capital expenditures (collectively the “Nuvve Holding Warrants”).The Nuvve Holding Warrants are accounted for in accordance with Topic 815, “Derivatives and Hedging,” and are recorded on the condensed consolidated balance sheets at fair value. Changes in the Nuvve Holding Warrants fair value are recognized in earnings and included in other income on the condensed consolidated statements of operations.

The following table sets forth a reconciliation of the changes in fair value of the Partnership’s Nuvve Holding Warrants for the periods indicated (in thousands):

	Year Ended
	December 31, 2021
Beginning fair value of warrants	$	—
Net gain (loss) on warrants		664
Ending fair value of warrants	$	664

F-17

To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we historically entered into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. We did not hedge any of our expected production volumes for 2021. Our historical hedging activities were intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It was never our intention to enter into derivative contracts for speculative trading purposes.

Under Topic 815, “Derivatives and Hedging”, all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We will net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met.  We have not elected to designate any of our current derivative contracts as hedges; instead, changes in the fair value of all of our derivative instruments are recognized in earnings and included in natural gas sales and oil sales in the consolidated statements of operations. We do not have derivative contracts related to production in 2021 and beyond.

The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the year ended December 31, 2020 (in thousands):

	Year Ended
	December 31, 2020
Beginning fair value of commodity derivatives	$	(759)
Net gains (losses) on crude oil derivatives		3,814
Net gains on natural gas derivatives		87
Net settlements received on derivative contracts:
Oil		(2,829)
Natural gas		(313)
Ending fair value of commodity derivatives	$	—

The effect of derivative instruments on our condensed consolidated statements of operations for the year ended December 31, 2020 was as follows (in thousands). As disclosed above, we did not hedge any of our expected production volumes for 2021.

	Location of Gain (Loss)	Year Ended
Derivative Type	in Income	December 31, 2020
Commodity – Mark-to-Market	Income (loss) from discontinued operations	$	3,814
Commodity – Mark-to-Market	Income (loss) from discontinued operations		87
		$	3,901

Earnout Derivative

Refer to Note 5 “Fair Value Measurements”.

7. DEBT

Credit Agreement

We have entered into a credit facility with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto, as amended through the date of the Twelfth Amendment to Third Amended and Restated Credit Agreement, dated as of August 20, 2021 (the “Credit Agreement”). The Credit Agreement provides a quarterly amortizing term loan of $65.0 million (the “Term Loan”) and a maximum revolving credit amount of $5.0 million (the “Revolving Loan”). The Credit Agreement matures on September 30, 2023. Borrowings under the Credit Agreement are secured by various mortgages of midstream properties that we own as well as various security and pledge agreements among us, certain of our subsidiaries and the administrative agent.

F-18

Borrowings under the Credit Agreement are available for limited direct investment in midstream properties, acquisitions, and working capital and general business purposes. The Credit Agreement has a sub-limit of up to $2.5 million which may be used for the issuance of letters of credit. As of December 31, 2021, we had $49.2 million of debt outstanding, consisting of $49.2 million under the Term Loan and 0 balance outstanding under the Revolving Loan. We are required to make mandatory amortizing payments of outstanding principal on the Term Loan of (i) $3.0 million per fiscal quarter commencing with the quarter ending December 31, 2021, and (ii) $2.0 million per fiscal quarter commencing with the quarter ending March 31, 2023. As of December 31, 2021, we have met our mandatory amortizing payments of outstanding principal on the Term Loan through March 2022. The maximum revolving credit amount is $5.0 million leaving us with $5.0 million in unused borrowing capacity. There were 0 letters of credit outstanding under our Credit Agreement as of December 31, 2021.

At our election, interest for borrowings under the Credit Agreement are determined by reference to (i) the LIBOR plus an applicable margin between 2.75% and 3.50% per annum based on net debt to EBITDA or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.75% and 2.50% per annum based on net debt to EBITDA plus (iii) a commitment fee of 0.50% per annum based on the unutilized portion of the Revolving Loan. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date.

The Credit Agreement contains various covenants that limit, among other things, our ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions to unitholders.

In addition, we are required to maintain the following financial covenants:

● current assets to current liabilities, excluding any current maturities of debt, of at least 1.0 to 1.0 at all times; and

● senior secured net debt to consolidated adjusted EBITDA for the last twelve months, as of the last day of any fiscal quarter, of not greater than 3.25 to 1.00.

The Credit Agreement also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid and a change in control. A change in control is generally defined as the occurrence of one of the following events: (i) our existing general partner ceases to be our sole general partner or (ii) certain specified persons shall cease to own more than 50% of the equity interests of our general partner or shall cease to control our general partner. If an event of default occurs, the lenders will be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies.

At December 31, 2021, we were in compliance with the financial covenants contained in the Credit Agreement. We monitor compliance on an ongoing basis. If we are unable to remain in compliance with the financial covenants contained in our Credit Agreement or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of the Credit Agreement, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated financial covenants from the lenders, but there is no assurance that such waivers would be granted.

We are required to make mandatory amortizing payments of the outstanding principal on the Term Loan, we expect these quarterly amortizing payments will be made from our operating cash flows and other capital resources. However, there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to make these mandatory amortizing payments.

Debt Issuance Costs

As of December 31, 2021 and 2020, our unamortized debt issuance costs were approximately $0.6 million and $0.8 million, respectively. These costs are amortized to interest expense in our consolidated statements of operations over the

F-19

life of our Credit Agreement. Amortization of debt issuance costs recorded during the years ended December 31, 2021 and 2020 were approximately $0.9 million and $0.8 million, respectively.

8. GATHERING AND TRANSPORTATION ASSETS

Gathering and transportation assets consist of the following (in thousands):

	December 31,
	2021		2020
Gathering and transportation assets
Midstream assets	$	188,246	$	187,977
Less: Accumulated depreciation and impairment		(89,756)		(82,654)
Total gathering and transportation assets, net	$	98,490	$	105,323

Depreciation and Amortization. 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 three to 15 years for furniture and equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets.

Depreciation, depletion and amortization consisted of the following (in thousands):

	Years Ended
	December 31,
	2021		2020
Depreciation and amortization of gathering and transportation related assets	$	7,102	$	7,195
Amortization of intangible assets		13,457		13,460
Total depreciation and amortization	$	20,559	$	20,655

Impairment of Gathering and Transportation Assets. We perform a periodic review of gathering and transportation assets to identify facts and circumstances, or triggering events, that indicate the carrying value may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our gathering and transportation assets and the recognition of additional impairments. Upon disposition or retirement of gathering and transportation assets, any gain or loss is recorded to operations.

For the year ended December 31, 2021, we did not record an impairment of our gathering and transportation assets. For the year ended December 31, 2020, we recorded an impairment charge on the Seco Pipeline of $0.9 million.

9. PROVISION FOR INCOME TAXES

Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in qualifying income (as that term is defined in the Internal Revenue Code).  We satisfied this requirement in each of the years ended December 31, 2021 and 2020 and, as a result, are not subject to federal income tax.  However, our partners are individually responsible for paying federal income taxes on their share of our taxable income.  Net earnings for financial reporting purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors.  We do not have access to information regarding each partner's individual tax basis in our limited partner interests.

F-20

Provision for income taxes reflects franchise tax obligations in the state of Texas (the “Texas Margin Tax”).  Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.

Our federal and state income tax provision (benefit) is summarized below:

	December 31,
	2021		2020
Current:
Federal	$	3	$	—
State		(2)		128
Total current		1		128
Deferred:
Federal		—		—
State		(6)		31
Total deferred		(6)		31
Total provision for income taxes	$	(5)	$	159

A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income (loss) before income taxes is as follows (in thousands):

	Years Ended
	December 31,
	2021		2020
Pre-tax net book loss	$	(155,422)	$	(98,838)
Federal Income Tax		3		—
Texas Margin Tax (a)		(6)		171
Return to accrual		(2)		(12)
Provision for income taxes	$	(5)	$	159
Effective income tax rate		0.00%		(0.16)%

(a) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.

F-21

The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated (in thousands):

	December 31,
	2021		2020
Deferred tax assets (liabilities):
Derivative assets	$	(22)	$	(29)
Depreciable, depletable property, plant and equipment		(271)		(269)
Other		5		5
Deferred tax assets (liabilities):		(288)		(293)
Valuation allowance		—		—
Total deferred tax assets (liabilities)	$	(288)	$	(293)

The Partnership assessed the available positive and negative evidence to determine that a valuation allowance was not required for a portion of its deferred tax assets because it is more likely than not that the deferred tax assets will be realized.

As of December 31, 2021 and 2020, the Partnership had no material uncertain tax positions.

The Partnership files income tax returns in the U.S. and various state jurisdictions. The Partnership is no longer subject to examination by federal income tax authorities prior to 2018. State statutes vary by jurisdiction.

10. ASSET RETIREMENT OBLIGATION

We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (“ARC”) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities or gathering and transportation assets. Subsequently, the ARC is depreciated using the units-of-production method for production assets and the straight-line method for midstream assets. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells and decommissioning of oil and natural gas gathering and other facilities.

Inherent in the fair value calculation of AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas properties, equipment and facilities or gathering and transportation assets.

The following table is a reconciliation of ARO for the years ended December 31, 2021 and 2020 (in thousands):

	Years Ended
	December 31,
	2021		2020
Asset retirement obligation, beginning balance	$	4,313	$	3,958
Accretion expense		387		355
Asset retirement obligation, ending balance	$	4,700	$	4,313

Additional AROs increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Abandonments of oil and natural gas wells and other facilities reduce the liability for AROs. In 2021 and 2020, there were no significant expenditures for abandonments and there were 0 assets legally restricted for purposes of settling existing AROs. During the year ended December 31, 2021, obligations were relieved as part of the Palmetto Divestiture and the Maverick Divestitures.

F-22

11. INTANGIBLE ASSETS

Intangible assets are comprised of customer and marketing contracts. The intangible assets balance as of December 31, 2021 is related to the Gathering Agreement with Mesquite that was entered into as part of the Western Catarina gathering system. The Western Catarina gathering system (“Western Catarina Midstream”) is located on the western portion of Mesquite’s acreage position in Dimmit, La Salle and Webb counties, Texas (the western portion of such acreage, “Western Catarina”). Pursuant to the 15-year agreement, Mesquite tenders all of its crude oil, natural gas and other hydrocarbon-based product volumes produced in the Western Catarina of the Eagle Ford Shale in Texas for processing and transportation through Western Catarina Midstream, with a right to tender additional volumes outside of the dedicated acreage. These intangible assets are being amortized using the straight-line method over the 15-year life of the agreement.

Amortization expense for the years ended December 31, 2021 and 2020 was $13.5 million, respectively. These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations. The following table is a reconciliation of changes in intangible assets (in thousands):

	Years Ended
	December 31,
	2021		2020
Beginning balance	$	131,786	$	145,246
Amortization		(13,457)		(13,460)
Ending balance	$	118,329	$	131,786

12. INVESTMENTS

In July 2016, we completed a transaction pursuant to which we acquired from Mesquite a 50% interest in Carnero Gathering, LLC (“Carnero Gathering”), a joint venture that was 50% owned and operated by Targa Resources Corp. (NYSE: TRGP) (“Targa”), for an initial payment of approximately $37.0 million and the assumption of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of the acquisition date (the “Carnero Gathering Transaction”). The fair value of the intangible asset for the contractual customer relationship related to Carnero Gathering was valued at approximately $13.0 million. This amount is being amortized over a contract term of 15 years and decreases earnings from equity investments in our consolidated statements of operations. As part of the Carnero Gathering Transaction, we are required to pay Mesquite an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Mesquite and other producers. See Note 5 “Fair Value Measurements” for further discussion of the earnout derivative.

In November 2016, we completed a transaction pursuant to which we acquired from Mesquite a 50% interest in Carnero Processing, LLC (“Carnero Processing”), a joint venture that was 50% owned and operated by Targa, for aggregate cash consideration of approximately $55.5 million and the assumption of remaining capital contribution commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of acquisition.

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 (the “Carnero JV Transaction”) to form an expanded 50 / 50 joint venture in South Texas, within Carnero G&P, LLC (“the Carnero JV”), (2) Targa contributed 100% of the equity interest in the Silver Oak II Gas Processing Plant (“Silver Oak II”), located in Bee County Texas, to the Carnero JV, which expands the processing capacity of the Carnero JV 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 the Carnero JV resulting in the Carnero JV owning all of the capacity in the Carnero Gathering Line, which has a design limit (without compression) of 400 MMcf/d, (4) the 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. The agreement with Mesquite, which was approved by all of the unaffiliated Comanche working interest partners, 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

F-23

basis, with the processing capabilities of the Carnero JV limited by the capacity of the Raptor Gas Processing Facility. As a result of the Carnero JV Transaction we now record our share of earnings and losses from the Carnero JV using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting.  The HLBV is a balance-sheet approach that calculates the amount we would have received if the Carnero JV were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our consolidated statements of operations. In the event of liquidation of the Carnero JV, available proceeds are first distributed to any priority return and unpaid capital associated with Silver Oak II, and then to members in accordance with their capital accounts.

As of December 31, 2021, the Partnership had paid approximately $124.4 million for its investment in the Carnero JV related to the initial payments and contributed capital. The Partnership has accounted for this investment using the equity method. Targa is the operator of the Carnero JV and has significant influence with respect to the normal day-to-day capital and operating decisions. We have included the investment balance in the equity investments caption on our consolidated balance sheets. For the year ended December 31, 2021, the Partnership recorded losses of approximately $52.9 million in equity investments from the Carnero JV, which was compounded by approximately $1.2 million related to the amortization of the contractual customer intangible asset. We have included these equity method earnings in the earnings from equity investments line within the consolidated statements of operations.  Cash distributions of approximately $15.6 million were received during the year ended December 31, 2021. As of December 31, 2021, an impairment of approximately $173.2 million was recorded at the JV level with approximately $55.0 million allocated to our net loss based on the Partnership’s proportionate share of aggregate capital contributions. At December 31, 2021, the carrying value of our investment in the Carnero JV was $20.2 million.

Summarized financial information of unconsolidated entities is as follows (in thousands):

	Years Ended
	December 31,
	2021		2020
Sales	$	114,165	$	80,228
Total expenses		277,545		63,121
Net income	$	(163,380)	$	17,107

13. COMMITMENTS AND CONTINGENCIES

As part of the Carnero Gathering Transaction, we are required to pay Mesquite an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Mesquite and other producers. This earnout has an approximate value of 0 as of December 31, 2021 and 2020. For the years ended December 31, 2021 and 2020, natural gas received did not exceed the threshold.

14. RELATED PARTY TRANSACTIONS

Relationship with Stonepeak

Since October 14, 2015, Stonepeak Catarina has owned all of our issued and outstanding preferred units.

As of March 29, 2022, Stonepeak owned (i) 96,734,084 common units, representing approximately 65% of our outstanding common units, (ii) all of our issued and outstanding Class C Preferred Units, (iii) the Stonepeak Warrant, which entitles 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. Stonepeak controls us and our general partner and has the ability to appoint all of the members of the Board and is considered a related party of the Partnership.

Currently, 4 of our directors, Jack Howell, Luke Taylor, Michael Bricker and John T. Steen III are representatives of Stonepeak, as either employees or operating partners of Stonepeak. Messrs. Howell, Taylor, Bricker and Steen do not

F-24

receive separate compensation for their service on the Board, but they are entitled to indemnification related to their service as directors pursuant to the terms of our partnership agreement. “See Part III, Item 11. Executive Compensation—Compensation of Directors.”

Relationship with Mesquite

Prior to emergence from bankruptcy, Mesquite was considered a related party of the Partnership because (i) Antonio R. Sanchez, III, who served as the Chairman of the Board at such time, also served as the Chief Executive Officer of Mesquite, (ii) Patricio D. Sanchez, who served as a member of the Board and as our President and Chief Operating Officer at such time, also served as a senior vice president and Chief Operating Officer of Mesquite, and (iii) Mesquite and certain other members of the Sanchez family directly or indirectly owned approximately 24.3% of the issued and outstanding common units of the Partnership at such time. As of June 30, 2020, Mesquite is not considered a related party of the Partnership. Patricio D. Sanchez resigned from his position as a member of the Board and as our President and Chief Operating Officer in September 2020. Antonio R. Sanchez, III resigned from his position as a member of the Board and the Chairman of the Board in February 2021.

Relationship with SP Holdings

We are controlled by our general partner, Evolve Transition Infrastructure GP LLC.  The sole member of our general partner is SP Holdings which has no officers. The sole member of SP Holdings is Stonepeak Catarina and the managing member of SP Holdings is Stonepeak Catarina Upper Holdings, LLC, an affiliate of Stonepeak Catarina.  

Shared Services Agreement

We have entered into the Shared Services Agreement with SP Holdings. In connection with providing the services under the Shared Services Agreement, SP Holdings receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in the Mid-Continent region, (ii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction.  Prior to August 2, 2019 each of these fees, not including the reimbursement of costs, was paid in cash unless SP Holdings elected for such fee to be paid in our equity. However, on August 2, 2019, we and SP Holdings entered into a letter agreement providing that until such time as we redeem all of our issued and outstanding Class C Preferred Units, SP Holdings will elect to receive its fees, not including reimbursement of costs, in common units rather than cash.  In addition, on November 8, 2019, we and SP Holdings entered into an additional letter agreement providing that during the period beginning with the fiscal quarter ended September 30, 2019 and continuing until the end of the fiscal quarter after the fiscal quarter in which we redeem all of our issued and outstanding Class C Preferred Units (the “Tolling Period”), SP Holdings would agree to delay receipt of its fees, not including reimbursement of costs. During the Tolling Period, we are required to keep an accurate ledger of the dollar amount of the fee applicable to each quarter within the Tolling Period and the daily closing price of our common units on the NYSE. Following the end of the Tolling Period we will provide a notice to SP Holdings including such ledgers and pay the accrued fees within thirty days of delivery of such notice. The Shared Services Agreement has a ten-year term and will be automatically renewed for an additional ten years unless we or SP Holdings provide notice of termination to the other with at least 180 days’ notice. During the year ended December 31, 2021, pursuant to the November 8, 2019 letter agreement, SP Holdings did not receive any fees, other than reimbursement of its costs. However, pursuant to the requirements under the November 8, 2019 letter agreement, we have determined that there was a net benefit during the year ended December 31, 2021, of approximately $1.9 million and fees earned during the year ended December 31, 2020, of approximately $7.2 million. The November 8, 2019 letter agreement resulted in the accumulating balance being subject to mark-to-market adjustments based on the market price for our common units. The volatility in our common unit market price during the periods caused the swing in fees earned.

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

F-25

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 $34.0 million as of December 31, 2021. 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.  To date, no notice of termination of the Shared Services Agreement has been delivered by SP Holdings, and the Partnership is continuing to discuss the Shared Services Agreement with SP Holdings.

Relationship with HOBO

As described below under “—Related Party Transactions—2021—HOBO Transaction,” we have committed to fund certain development expenses of HOBO as HOBO seeks to develop, construct, own and operate renewable fuels facilities. Messrs. Gibbs, Keuss and Hartigan, the current Chief Executive Officer, Chief Operating Officer and Chief Investment Officer of our general partner, respectively, also serve as the Chief Executive Officer, President, and Executive Vice President and Chief Financial Officer, respectively, of HOBO and own 45.25%, 45.25% and 9.5% of HOBO.  

Related Party Transactions

2020

Settlement Agreement

On June 6, 2020 the Partnership, our general partner and certain of our subsidiaries entered into the Settlement Agreement with Mesquite and certain of its subsidiaries. On June 30, 2020, 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, (ii) the Seco Catarina Agreement, and (iii) the Seco Comanche Agreement. As described below under “—2021—Settlement Agreement,” the Settlement Agreement was terminated on June 24, 2021.

JT3 Consulting Agreement

On June 30, 2020, our general partner entered into that certain Consultancy Agreement (the “JT3 Consulting Agreement”) with JT3 Advisors LLC (“JT3 Advisors”).  JT3 Advisors is an entity owned by John T Steen III, who has served as the Chairman of the Board since September 2020. Pursuant to the terms of the JT3 Consulting Agreement the Partnership pays JT3 Advisors a consulting fee of $20,000 per month for the provision of services to aid the Partnership in achieving its commercial goals, including analysis and assessment of potential commercial arrangements and recommendation of selected arrangements to our management. The JT3 Consulting Agreement was terminated in March 2021. Consulting fees earned under the JT3 Consulting Agreement were approximately $200,000.

Certain Transactions with Stonepeak

On November 16, 2020, the Partnership and Stonepeak Catarina entered 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 Letter Agreement Transactions were 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. As of March 29, 2022, we distributed a total of 91,831,001 common units under the Stonepeak Letter Agreement with an approximate value of $77.2 million.

As a result of the foregoing transactions, as of March 29, 2022, Stonepeak owned (i) 96,734,084 common units, representing approximately 65% of our outstanding common units, (ii) all of our issued and outstanding Class C Preferred

F-26

Units, (iii) the Stonepeak Warrant, which entitles 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 the limited call right. Stonepeak would effect any such exercise by first completing 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 29, 2022, the General Partner and its controlled affiliates do not own any Common Units.

2021

Settlement Agreement

On June 24, 2021, the Partnership, our general partner, Catarina Midstream and Seco Pipeline LLC received the Settlement Agreement Termination Notice from Mesquite. The Settlement Agreement Termination Notice was delivered pursuant to Section 5.1.2 and/or 5.1.3 of the Settlement Agreement and the termination was effective as of the date of the notice.

HOBO Transaction

On November 3, 2021, we entered into a Framework Agreement (the “Framework Agreement”) with HOBO. At the time of entry into the Framework Agreement there were no other material relationships between us or any of our affiliates and HOBO. The Framework Agreement provides that, subject to the satisfaction of applicable conditions precedent, we will fund certain development expenses of HOBO as HOBO seeks to develop, construct, own and operate renewable fuels facilities (each a “Project”). HOBO’s initial Project is a 9,000 barrel per day (120 million gallons per year) renewable diesel production facility (the “Initial Project”).

Upon satisfaction of the Offtake Condition (as defined in the Framework Agreement), HOBO will send written notice thereof to us. If we are reasonably satisfied with our review of the supporting materials relating to the Offtake Condition then we will pay to HOBO the lesser of 50% of the Qualified Development Costs incurred as of such date and $3.0 million (the “Initial Development Payment”).

Upon receipt of all Material Permits (as defined in the Framework Agreement) for the Initial Project and conclusion of the FEL2 Level Pre-Feasibility Study Report verifying the Initial Project can be completed in accordance with the Qualified Project Model, HOBO will send written notice thereof to us and if we are reasonably satisfied with our review of the supporting materials, we will pay to HOBO (i) the lesser of 50% of the aggregate Qualified Development Costs incurred as of such date and $7.5 million minus (ii) the amount of any Qualified Development Costs previously paid by us (the “Interim Development Payment”).

Upon achievement of all Conditions Precedent (as defined in the Framework Agreement) for the Initial Project (other than Evolve Approval (as defined in the Framework Agreement)), HOBO will send written notice thereof to us. If we are reasonably satisfied with our review of the Conditions Precedent, then subject to the closing and initial funding of Project

F-27

Financing (as defined in the Framework Agreement), which is required to cover a specified percentage of the anticipated procurement, construction, completion and commercialization costs of the Initial Project, we will pay to HOBO (i) the lesser of $15.0 million and the aggregate Qualified Development Costs incurred as of such date, minus (ii) the aggregate amount of the Initial Development Payment, the Interim Development Payment and any other Qualified Development Costs previously paid by us (the “Final Development Payment”).

For the Initial Project, HOBO shall also be entitled to payment of an Incentive Development Fee (as defined in the Framework Agreement), equal to 5% of the aggregate capital expenditures in the final capital expenditure budget included in the Final Qualified Project Model (as defined in the Framework Agreement) with a maximum payment of $22.7 million (subject to adjustment for any change in the scope of the Initial Project), at least 50% of which shall be payable in Class A units of the holding company we form in connection with the Initial Project. We may be required to issue common units to HOBO if, at HOBO’s election, it chooses to receive payment of the Incentive Development Fee in the form of common units in lieu of cash or Class A units in the holding company. Half of the Incentive Development Fee shall be due at Financial Close (as defined in the Framework Agreement) and the remaining half shall be due upon the Initial Project achieving Commercial Operation. On or prior to Financial Close, HOBO shall also have the right to commit to purchase up to 10% of the total expected Class A units in the holding company.

If we make each of the required funding payments in connection with the Initial Project, the approximate dollar value of such payments would be approximately $15.0 million plus the amount of the Incentive Development Fee. As a result of their ownership of HOBO, each of Messrs. Gibbs, Keuss and Hartigan would receive an aggregate of approximately 45.25%, 45.25% and 9.5%, respectively, of such payments. Additionally, all or part of the cash portion of the Incentive Development Fee may be utilized to purchase Class A units in the holding company. As a result, HOBO may choose to acquire additional interests in the Initial Project as a result of ownership of such Class A units. Any increase in HOBO’s ownership of Class A units would increase each of Messrs. Gibbs, Keuss and Hartigan’s indirect interest in the holding company and could increase the value of their interest in the HOBO Transaction.

15. UNIT-BASED COMPENSATION

The Sanchez Production Partners LP Long-Term Incentive Plan (the “LTIP”) allows for grants of restricted common units. Restricted common unit activity under the LTIP during the period is presented in the following table:

		Weighted
		Average
	Number of	Grant Date
	Restricted	Fair Value
	Units	Per Unit
Outstanding at December 31, 2019	1,155,467	$	3.86
Vested	(338,840)		5.14
Returned/Cancelled	(133,456)		5.61
Outstanding at December 31, 2020	683,171	$	2.68
Granted	5,251,785		1.18
Vested	(991,468)		1.51
Returned/Cancelled	(689,406)		1.51
Outstanding at December 31, 2021	4,254,082	$	1.24

In March 2021, the Partnership granted 1,651,785 restricted common units pursuant to the LTIP to certain officers of the Partnership’s general partner. Two-thirds of the restricted common units vest on the one year anniversary of the date of grant and the remaining one-third vest on the second year anniversary of the date of grant. The number of restricted common units granted was based on the fair value on the day before the grant date. In November 2021, the Partnership granted 3,600,000 restricted common units pursuant to the LTIP to certain officers of the Partnership’s general partner. The vesting of the restricted common units is dependent upon certain performance conditions being met.

As of December 31, 2021, 8,848,410 common units remained available for future issuance to participants under the LTIP.

F-28

The Evolve Transition Infrastructure LP 2021 Equity Inducement Award Plan (the “Inducement Plan”) allows for grants of restricted common units. During the year ended December 31, 2021, 14,100,000 restricted common units were issued under the Inducement Plan and vesting is dependent upon certain performance conditions being met. As of December 31, 2021, there are 0 common units available for issuance to participants under the Inducement Plan.

16. PARTNERS’ CAPITAL

Outstanding Units

As of December 31, 2021, we had 36,474,436 Class C Preferred Units outstanding and 124,448,646 common units outstanding which included 4,254,082 unvested restricted common units issued under the LTIP.

Common Unit Issuances

We entered into a letter agreement with SP Holdings providing that during the period beginning with the fiscal quarter ended September 30, 2019 and continuing until the end of the fiscal quarter after the fiscal quarter in which we redeem all of our issued and outstanding Class C Preferred Units, SP Holdings agrees to delay receipt of its fees, not including reimbursement of costs, as a result, we have not issued any common units to SP Holdings in connection with providing services under the Shared Services Agreement for any quarter following the quarter ended June 30, 2019. As of December 31, 2021, the number of units to be issued under the Shared Services Agreement is 14,867,664.

Class C Preferred Units

On August 2, 2019, Stonepeak exchanged all of their current equity ownership for newly issued Class C Preferred Units and the Stonepeak Warrant in a private placement transaction (the “Exchange”). On February 24, 2021, the Partnership and Stonepeak entered into Amendment No. 1 to the Stonepeak Warrant, on May 4, 2021, the Partnership and Stonepeak entered into Amendment No. 2 to the Stonepeak Warrant, and on August 2, 2021, the Partnership and Stonepeak entered into Amendment No. 3 to the Stonepeak Warrant.

The holders of the Class C Preferred Units receive a quarterly distribution of 12.5% per annum payable in cash. To the extent that Available Cash (as defined in our partnership agreement) is insufficient to pay the distribution in cash, all or a portion of the distribution may be paid in Class C Preferred PIK Units. Commencing with the quarter ending March 31, 2022, the distribution rate will increase to 14% per annum. Distributions are to be paid on or about the last day of each of February, May, August and November following the end of each quarter and are charged to interest expense in our condensed consolidated statements of operations. Beginning January 1, 2022, Adjusted Available Cash (as defined in our partnership agreement) will be distributed to holders of the Class C Preferred Units to redeem a number of Class C Preferred Units to be determined based on the amount of Adjusted Available Cash.

The Class C Preferred Units are accounted for as a current liability on our condensed consolidated balance sheet consisting of the following (in thousands):

	Years Ended
	December 31,
	2021		2020
Class C Preferred Units, beginning balance	$	345,205	$	281,688
Accretion of discount		52,182		38,938
Distribution accrual		0		24,579
Class C Preferred Units, ending balance	$	397,387	$	345,205

F-29

The table below reflects the payment of distributions on Class C Preferred Units related to the periods indicated.

	Class C Preferred		Date of	Date of	Date of
Three Months Ended	PIK Distribution		Declaration	Record	Distribution
December 31, 2019		1,039,314	February 13, 2020	February 28, 2020	February 20, 2020
March 31, 2020		1,071,793	April 29, 2020	May 20, 2020	May 29, 2020
June 30, 2020		1,105,286	July 31, 2020	August 20, 2020	August 31, 2020

On November 16, 2020, the Partnership and Stonepeak entered into 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 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 table below reflects distributions on Class C Preferred Units which were elected to be paid in common units related to the periods indicated.

	Class C Preferred		Date of
Three Months Ended	Distribution of Common Units		Distribution
September 30, 2020		22,274,869	February 1, 2021
December 31, 2020		12,445,491	February 25, 2021
March 31, 2021		13,763,249	May 20, 2021
June 30, 2021		8,012,850	August 20, 2021
September 30, 2021		10,832,186	November 22, 2021

Stonepeak Warrant

On August 2, 2019, in connection with the Exchange, the Partnership issued to Stonepeak the Stonepeak Warrant, which entitles the holder to receive junior securities representing ten percent of junior securities deemed outstanding when exercised. The Stonepeak Warrant expires on the later of August 2, 2026 or 30 days following the full redemption of the Class C Preferred Units. There is no strike price associated with the exercise of the Stonepeak Warrant. The Stonepeak Warrant is accounted for as a liability in accordance with ASC 480 and is presented within other liabilities on the consolidated balance sheet. Changes in the fair value of the Stonepeak Warrant are charged to interest expense in our consolidated statements of operations.

Earnings per Unit

Net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss), based on the provisions of our partnership agreement, divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss) as if all of the net income for the period had been distributed in accordance with our partnership agreement. Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units based on provisions of our partnership agreement. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

The Partnership’s general partner does not have an economic interest in the Partnership and, therefore, does not participate in the Partnership’s net income. 

F-30

17. VARIABLE INTEREST ENTITIES

The Partnership’s investment in the Carnero JV represents a variable interest entity (“VIE”) that could expose the Partnership to losses. The amount of losses the Partnership could be exposed to from the Carnero JV is limited to the capital investment of approximately $20.2 million.

As of December 31, 2021, the Partnership had invested approximately $124.4 million in the Carnero JV and 0 debt has been incurred by the Carnero JV. We have included this VIE in other assets, equity investments on the balance sheet.

Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Partnership’s maximum exposure to loss as of December 31, 2021 and 2020 (in thousands):

	December 31,
	2021		2020
Acquisitions, earnout and capital investments	$	128,483	$	128,251
Earnings in equity investments		(23,618)		30,455
Distributions received		(84,667)		(69,071)
Maximum exposure to loss	$	20,198	$	89,635

18. LEASES

On November 9, 2021, the Partnership entered into a Gas Compression Agreement with Kodiak Gas Services, LLC (“Kodiak”) to lease gas compression units from Kodiak. All leased units have a 36 month primary term commencing on the startup date. Following the primary term of the leased units, the Gas Compression Agreement calls for continuation of the term on a month to month basis until terminated with 30 days written notice. As of December 31, 2021, 2 gas compression units have gone online.

As of December 31, 2021, the Partnership recorded right of use assets, net of $1.43 million on the balance sheet. Lease costs incurred during the year are insignificant and determined not material as of December 31, 2021.

19. SUBSEQUENT EVENTS

On January 31, 2022, the Partnership received written notice of Stonepeak’s election to receive distributions on the Class C Preferred Units for the quarter ended December 31, 2021 in common units. The aggregate distribution of 24,502,356 common units was made to Stonepeak Catarina on February 22, 2022, following the satisfaction of certain issuance conditions.

F-31