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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

For the quarterly period ended March 31, 2021

OR

For the transition period from                      to                      .

Commission File Number 001-33147

Evolve Transition Infrastructure LP

(Exact name of registrant as specified in its charter)

(713) 783-8000

(Registrant’s Telephone Number, Including Area Code)

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(Former name, former address and former fiscal year, if changed since last report)

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

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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 (§232.405 of this chapter) 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, or 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.

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 standards provided pursuant to Section 13(a) of the Exchange Act. ◻

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

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Common units outstanding as of May 12, 2021: approximately 56,185,378 common units.

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TABLE OF CONTENTS

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COMMONLY USED DEFINED TERMS

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

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Cautionary Note Regarding Forward-Looking Statements

This Form 10-Q contains “forward-looking statements” within the meaning of the federal securities laws. Except for statements of historical fact, all statements in this Form 10-Q 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-Q are largely based on our current expectations, which reflect estimates and assumptions made by the management of our general partner. Although we believe such estimates and assumptions to be reasonable, statements made regarding future results are not guarantees of future performance and are subject to numerous assumptions, uncertainties and risks that are beyond our control. Actual outcomes and results may be materially different from the results stated or implied in such forward-looking statements included in this report. You should not put any undue reliance on any forward-looking statement. All forward-looking information in this Form 10-Q and subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

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

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Management cautions all readers that the forward-looking statements contained in this Form 10-Q 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.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EVOLVE TRANSITION INFRASTRUCTURE LP and SUBSIDIARIES

Condensed Consolidated Statements of Operations

(In thousands, except unit data)

(Unaudited)

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See accompanying notes to condensed consolidated financial statements.

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EVOLVE TRANSITION INFRASTRUCTURE LP and SUBSIDIARIES

Condensed Consolidated Balance Sheets

(In thousands, except unit data)

See accompanying notes to condensed consolidated financial statements.

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EVOLVE TRANSITION INFRASTRUCTURE LP and SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

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See accompanying notes to condensed consolidated financial statements.

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EVOLVE TRANSITION INFRASTRUCTURE LP and SUBSIDIARIES

Condensed Consolidated Statements of Changes in Partners’ Capital

(In thousands, except unit data)

(Unaudited)

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See accompanying notes to condensed consolidated financial statements.

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EVOLVE TRANSITION INFRASTRUCTURE LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 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. Our business consists of two reportable segments: Production and Midstream. Midstream includes Western Catarina Midstream (as defined in Note 9 “Intangible Assets”), the Carnero JV (as defined in Note 10 “Investments”) and Seco Pipeline (as defined in Note 4 “Fair Value Measurements”). Production consists of our oil and natural gas properties in Texas and Louisiana. Our management evaluates performance based on these two business segments.

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with GAAP, have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included. The results of operations for the interim periods are not necessarily indicative of the results for the entire year.

These unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2020, which was filed with the SEC on March 16, 2021. 

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 No. 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

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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 condensed consolidated financial statements.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows. 

Liquidity and Going Concern

The Partnership’s inability to generate sufficient liquidity to meet future debt obligations raises substantial doubt regarding our ability to continue as a going concern. The Credit Agreement matures September 30, 2021 and our ability to continue as a going concern is contingent upon our ability to either (i) refinance or extend the maturity of the Credit Agreement, or (ii) obtain adequate new debt or equity financing to repay the Credit Agreement in full at maturity. We intend to refinance or extend the maturity of the Credit Agreement prior to its maturity date. However, we may not be able to refinance or extend the maturity of the Credit Agreement or, if we are able to refinance or extend the maturity, we may not be able to do so with borrowing and debt issue costs, terms, covenants, restrictions, commitment amount or a borrowing base favorable to us. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of substantial doubt as to the Partnership’s ability to continue as a going concern. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Use of Estimates

The condensed consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the condensed 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 estimates of our reserves of natural gas, NGLs and oil; future cash flows from oil and natural gas properties; depreciation, depletion and 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. 

3. REVENUE RECOGNITION

Revenue from Contracts with Customers

We account for revenue from contracts with customers in accordance with 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 $11.8 million for the three months ended March 31, 2021. We disaggregate revenue based on type of 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 type of revenue and product type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.

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Midstream Segment

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 account for under ASC 606. The Seco Pipeline Transportation Agreement was terminated by Mesquite effective February 12, 2020. The Gathering Agreement (as defined in Note 12 “Related Party Transactions”) 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 10 “Investments.”

Production Segment

Our oil, natural gas, and NGL revenue is marketed and sold on our behalf by the respective asset operators. We are not party to the contracts with the third-party customers. However, we are party to joint operating agreements, which we account for under ASC 808, “Collaborative Agreements,” and revenues for these arrangements is recognized based on the information provided to us by the operators.

We additionally recognize and present changes in the fair value of our commodity derivative instruments within natural gas sales and oil sales in our consolidated statements of operations, which is accounted for under ASC 815, “Derivatives and Hedging.”

Performance Obligations

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. We applied the series guidance and treated these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. The Seco Pipeline Transportation Agreement required payment within 30 days following the calendar month of delivery.

The Seco Pipeline Transportation Agreement contained 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 condensed 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

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 March 31, 2021 and December 31, 2020, our accounts receivables from contracts with customers were $1.9 million and $1.9 million, respectively.

4. 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

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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 March 31, 2021 (in thousands):

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):

As of March 31, 2021and December 31, 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 8 “Asset Retirement Obligation.”

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

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 (as defined in Note 6 “Debt”) approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar 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 6 “Debt.”

Warrant – As part of the Exchange, the Partnership issued to Stonepeak the Warrant which entitles the holder to receive junior securities representing ten percent of junior securities deemed outstanding when exercised. The Warrant is valued using ten percent of the junior securities deemed outstanding and the common unit price as of the balance sheet date. We have therefore classified the fair value measurements of the 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 10 “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. As of March 31, 2021 and December 31, 2020, the fair value of the earnout was determined to be zero.

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5. DERIVATIVE AND FINANCIAL INSTRUMENTS

To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter 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. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is 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 condensed 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; however, 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 condensed 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):

The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands):

Earnout Derivative

Refer to Note 4 “Fair Value Measurements.”

6. DEBT

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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 by the Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of November 22, 2019 (the “Credit Agreement”).  The Credit Agreement provides a quarterly amortizing term loan of $155.0 million (the “Term Loan”) and a maximum revolving credit amount of $17.5 million, which was reduced to the lesser of (i) $15.0 million through May 14, 2021 and (ii) from and after May 15, 2021, the positive difference of the Borrowing Base minus the aggregate outstanding principal amount of the Term Loan (the “Revolving Loan”). The Credit Agreement is a current liability that matures on September 30, 2021. We expect to refinance or extend the maturity of the Credit Agreement prior to its maturity date. However, we may not be able to refinance or extend the maturity of the Credit Agreement or, if we are able to refinance or extend the maturity, we may not be able to do so with borrowing and debt issue costs, terms, covenants, restrictions, commitment amount or a borrowing base favorable to us. Borrowings under the Credit Agreement are secured by various mortgages of both midstream and upstream properties that we own as well as various security and pledge agreements among us, certain of our subsidiaries and the administrative agent.

On November 6, 2020, the Partnership, as borrower, entered into that certain Tenth Amendment to the Third Amended and Restated Credit Agreement with the guarantors party thereto, Royal Bank of Canada, as administrative agent and collateral agent (the “Agent”)

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and the lenders party thereto (each a “Lender”) (the “Credit Agreement Amendment” and the Third Amended and Restated Credit Agreement, as amended by the Tenth Amendment, the “Amended Credit Agreement”). Pursuant to the Credit Agreement Amendment, the parties thereto agreed to, among other things: (a) amend the initial aggregate commitment amount under the first lien revolving credit facility to reduce such amount to $17.5 million, which was reduced to the lesser of (i) $15.0 million through May 14, 2021 and (ii) from and after May 15, 2021, the positive difference of the Borrowing Base minus the aggregate outstanding principal amount of the Term Loan; (b) amend the conditions precedent to the obligations of any Lender to make a Loan (as defined in the Amended Credit Agreement) to provide that through May 14, 2021, a Borrowing Base Deficiency (as defined in the Amended Credit Agreement) may exist; (c) amend the annual financial statements and annual budget affirmative covenant to provide that the Partnership’s audited annual financial statements as reported on by the Partnership’s independent public accountants may be delivered with a “going concern” or like qualification or exception, if such qualification or exception results from (i) any actual or prospective breach of the financial covenants set forth in Section 9.01 of the Amended Credit Agreement or (ii) the fact that the final maturity date of any Debt (as defined in the Amended Credit Agreement) is less than one year after the date of such report, and does not otherwise include any qualification or exception as to the scope of such audit; and (d) include a new post-closing covenant requiring the Partnership to either engage an Advisory Firm (as defined in the Credit Agreement Amendment) or certify that the Partnership has taken material steps, in either case, to implement a strategic transaction generating net cash proceeds reasonably expected to be greater than an amount that will allow the Partnership to repay in full all outstanding obligations under the Loan Documents (as defined in the Amended Credit Agreement) that is anticipated to close by August 31, 2021.

Borrowings under the Credit Agreement are available for limited direct investment in oil and natural gas properties, 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. Pursuant to the Credit Agreement, the initial aggregate commitment amount under the Term Loan is $155.0 million, subject to quarterly $10.0 million principal and other mandatory prepayments. The initial borrowing base under the Credit Agreement was $235.5 million. The borrowing base is equal to the sum of the rolling four quarter EBITDA of our midstream operations and the amount of distributions received from the Carnero JV multiplied by 4.5 or a lower number dependent upon natural gas volumes flowing through Western Catarina Midstream. Outstanding borrowings in excess of our borrowing base must be repaid within 45 days. As of March 31, 2021, the borrowing base under the Credit Agreement was $113.7 million and we had $104.5 million of debt outstanding, consisting of $95.0 million under the Term Loan and $9.5 million under the Revolving Loan. We are required to make mandatory amortizing payments of outstanding principal on the Term Loan of $10.0 million per fiscal quarter. The maximum revolving credit amount is $15.0 million leaving us with $5.5 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement as of March 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 2.50% and 3.00% per annum based on net debt to EBITDA or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.50% and 2.00% per annum based on net debt to EBITDA plus (iii) a commitment fee of 0.500% per annum based on the unutilized maximum revolving credit. 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: 

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 March 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

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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.

Debt Issuance Costs

As of March 31, 2021 and December 31, 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 condensed consolidated statements of operations over the life of our Credit Agreement. Amortization of debt issuance costs recorded during the three months ended March 31, 2021 and 2020 was approximately $0.2 million and $0.2 million, respectively.

7. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT

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

Oil and natural gas properties and related equipment consisted of the following (in thousands):

Oil and Natural Gas Properties. We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties.

Depreciation, Depletion and Amortization. Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold and proved property acquisition costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves.

All other properties, including the 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):

Impairment of Oil and Natural Gas Properties and Other Non-Current Assets. Oil and natural gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third-party reserve reports using future expected oil and natural gas prices adjusted for basis differentials.

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Other inputs, besides reserves, used to determine the fair values of proved properties include estimates of: (i) future operating and development costs; (ii) future commodity prices; and (iii) a market-based weighted average cost of capital rate. Cash flow estimates for impairment testing exclude derivative instruments.

The recoverability of gathering and transportation assets is evaluated when facts or circumstances indicate that their 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.

At year end December 31, 2020, we recorded non-cash impairment charges of $23.4 million to impair our producing oil and natural gas properties.

8. 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 changes in ARO for the three months ended March 31, 2021 and the year ended December 31, 2020 (in thousands):

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. During the three months ended March 31, 2021 and the year ended December 31, 2020, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs.

9. INTANGIBLE ASSETS

Intangible assets are comprised of customer and marketing contracts. The intangible assets balance as of March 31, 2021 is related to the Gathering Agreement with Mesquite that was entered into as part of the acquisition 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 each of the three months ended March 31, 2021 and 2020 was approximately $3.4 million. These costs are amortized to depreciation, depletion, and amortization expense in our condensed consolidated statements of operations. The following table is a reconciliation of changes in intangible assets (in thousands):

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10. 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 condensed 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 4 “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 (the “Carnero Processing Transaction”).

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 acreage in Dimmit, Webb, La Salle, Zavala and Maverick counties, Texas (such acreage is collectively referred to 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 Asset 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 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 condensed 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 March 31, 2021 the Partnership had paid approximately $124.2 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 the condensed consolidated balance sheets. For the three months ended March 31, 2021, the Partnership recorded earnings of approximately $0.9 million in equity investments from the Carnero JV, which was partially offset by approximately $0.3 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 condensed consolidated statements of operations. Cash distributions of approximately $2.6 million were received during the three months ended March 31, 2021.

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

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11. 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 zero as of March 31, 2021. For the three months ended March 31, 2021, we made no payments to Mesquite related to the earnout.

12. RELATED PARTY TRANSACTIONS

Please read the disclosure under the headings “Relationship with Stonepeak,” “Relationship with Mesquite,” “Relationship with SP Holdings” and “Shared Services Agreement” in Note 13 “Related Party Transactions” of our Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2020 for a more complete description of certain related party transactions that were entered into prior to 2021.

13. 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:

In April 2019, the Partnership issued 137,613 restricted common units pursuant to the LTIP to certain directors of the Partnership’s general partner that vested immediately on the date of grant. In March 2019, the Partnership issued 991,560 restricted common units pursuant to the LTIP to certain officers and directors of the Partnership’s general partner that vest over three years from the date of grant. The unit-based compensation expense for the awards was based on the fair value on the day before the grant date.

As of March 31, 2021, 1,577,847 common units remained available for future issuance to participants under the LTIP.

14. DISTRIBUTIONS TO UNITHOLDERS

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

On November 16, 2020, the Partnership and Stonepeak entered into a letter agreement (the “Stonepeak Letter Agreement”) wherein the parties agreed that the distribution on the Class C Preferred Units for the three months ended September 30, 2020 would be paid in

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common units instead of Class C Preferred PIK Units, cash or a combination thereof. The aggregate distribution of 22,274,869 common units was made payable to Stonepeak on February 1, 2021.

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.

In accordance with the Stonepeak Letter Agreement, on January 28, 2021, the Partnership received written notice of Stonepeak’s election to receive distributions on the Class C Preferred Units for the quarter ended December 31, 2020 in common units. The aggregate distribution of 12,445,491 common units was paid to Stonepeak on February 25, 2021.

In accordance with the Stonepeak Letter Agreement, on April 30, 2021, the Partnership received written notice of Stonepeak’s election to receive distributions on the Class C Preferred Units for the quarter ended March 31, 2021 in common units. The aggregate distribution of 13,763,249 common units will be paid to Stonepeak on May 20, 2021.

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15. PARTNERS’ CAPITAL

Outstanding Units

As of March 31, 2021, we had 36,474,436 Class C Preferred Units outstanding and 56,185,378 common units outstanding which included 2,194,309 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 March 31, 2021, the number of units to be issued under the Shared Services Agreement is 15,294,741.

Class C Preferred Units

On August 2, 2019, Stonepeak exchanged all of their current equity ownership for newly issued Class C Preferred Units and a warrant exercisable for junior securities (the “Warrant”) in a private placement transaction (the “Exchange”).

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 the Third Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended 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.

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

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Warrant

On August 2, 2019, in connection with the Exchange, the Partnership issued to Stonepeak the Warrant, which entitles the holder to receive junior securities representing ten percent of junior securities deemed outstanding when exercised. The 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 Warrant. The Warrant is accounted for as a liability in accordance with ASC 480 and is presented within other liabilities on the condensed consolidated balance sheet. Changes in the fair value of the Warrant are charged to interest expense in our condensed 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 provisions of the Amended 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 the Amended 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 the Amended 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.

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16. REPORTING SEGMENTS

“Midstream” and “Production” best describe the operating segments of the businesses that we separately report. The factors used to identify these reporting segments are based on the nature of the operations that are undertaken by each segment. The Midstream segment operates the gathering, processing and transportation of natural gas, NGLs and crude oil. The Production segment operates to produce crude oil and natural gas. These segments are broadly understood across the petroleum and petrochemical industries.

These functions have been defined as the operating segments of the Partnership because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Partnership’s chief operating decision maker (“CODM”) to make decisions about resources to be allocated to the segment and to assess its performance; and (3) for which discrete financial information is available. Operating segments are evaluated for their contribution to the Partnership’s consolidated results based on operating income, which is defined as segment operating revenues less expenses.

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The following tables present financial information for each operating segment for the periods indicated based on our operating segments (in thousands):

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The following table summarizes the total assets by operating segment as of March 31, 2021 and December 31, 2020 and total capital expenditures for the three months ended March 31, 2021 and the year ended December 31, 2020 (in thousands):

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