UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2020

OR

Commission File No.: 1-35374

Mid-Con Energy Partners, LP

(Exact name of registrant as specified in its charter)

2431 East 61st Street, Suite 850

Tulsa, Oklahoma 74136

(Address of principal executive offices and zip code)

(918) 743-7575

(Registrant’s telephone number, including area code)

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

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

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, 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 accounting 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 Act). Yes  ☐    No  ☒

As of June 8, 2020, the registrant had 14,311,522 common units outstanding.

EXPLANATORY NOTE

Extended Filing Deadline

On March 25, 2020, the SEC issued an order (SEC Release No. 34-88465) granting conditional relief to public companies that are unable to timely comply with their SEC filing obligations as a result of the coronavirus (“COVID-19”) pandemic (the “Order”). We relied on the Order to delay the filing of this Form 10-Q for the quarter ended March 31, 2020, (the “Quarterly Report”) due to circumstances related to COVID-19. Our operations and business have experienced disruption due to the unprecedented conditions surrounding the COVID-19 pandemic, which has resulted in reduced availability of our accounting, financial, legal and other key personnel required to assist in the preparation of the Quarterly Report due to recommended and mandated social quarantining and work from home orders. We have also had to modify our business practices, including employee work locations, travel restrictions and cancellation of physical participation in meetings. These restrictions slowed the preparation and review of our Quarterly Report.

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TABLE OF CONTENTS

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Form 10-Q”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about:

All of these types of statements, other than statements of historical fact included in this Form 10-Q, are forward-looking statements. These forward-looking statements may be found in Item 1. “Financial Statements,” Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Form 10-Q. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” “goal,” “forecast,” “guidance,” “might,” “scheduled” and the negative of such terms or other comparable terminology.

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The forward-looking statements contained in this Form 10-Q are largely based on our expectations, which reflect estimates and assumptions made by our management. 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. All readers are cautioned 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 that the forward-looking events will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in the “Risk Factors” section included in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2019 (“Annual Report”) and Part II - Item 1A in this Form 10-Q. All forward-looking statements speak only as of the date made, and other than as required by law, we do not intend to 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.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge on our website (www.midconenergypartners.com), copies of our Annual Reports, Form 10-Qs, Current Reports on Form 8-K, amendments to those reports filed or furnished to the Securities and Exchange Commission (“SEC”) pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and the written charter of our Audit Committee are also available on our website and we will provide copies of these documents upon request. Our website and any contents thereof are not incorporated by reference into this report.

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PART I

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Mid-Con Energy Partners, LP and subsidiaries

Condensed Consolidated Balance Sheets

(in thousands, except number of units)

(Unaudited)

See accompanying notes to condensed consolidated financial statements

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Mid-Con Energy Partners, LP and subsidiaries

Condensed Consolidated Statements of Operations

(in thousands, except per unit data)

(Unaudited)

See accompanying notes to condensed consolidated financial statements

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Mid-Con Energy Partners, LP and subsidiaries

Condensed Consolidated Statements of Cash Flows

(in thousands)

(Unaudited) 

See accompanying notes to condensed consolidated financial statements

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Mid-Con Energy Partners, LP and subsidiaries

Condensed Consolidated Statements of Changes in Equity

(in thousands)

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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Mid-Con Energy Partners, LP and subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Organization and Nature of Operations

Nature of Operations

Mid-Con Energy Partners, LP (“we,” “our,” “us,” the “Partnership” or the “Company”) is a publicly held Delaware limited partnership formed in July 2011 that engages in the ownership, acquisition and development of producing oil and natural gas properties in North America, with a focus on enhanced oil recovery (“EOR”). Our limited partner units (“common units”) are listed under the symbol “MCEP” on the NASDAQ. Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company.

Basis of Presentation

Our unaudited condensed consolidated financial statements are prepared pursuant to the rules and regulations of the SEC. These financial statements have not been audited by our independent registered public accounting firm, except that the condensed consolidated balance sheet at December 31, 2019, is derived from the audited financial statements. Accordingly, certain information and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted in this Form 10-Q. We believe that the presentations and disclosures made are adequate to make the information not misleading.

The unaudited condensed consolidated financial statements include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our Annual Report. All intercompany transactions and account balances have been eliminated.

Liquidity and Going Concern

These financial statements have been prepared on a going concern basis, which contemplates the continuity of normal business activities and the realization of assets and settlement of liabilities in the normal course of business. At March 31, 2020, the Partnership was not in compliance with the leverage ratio covenant of our credit agreement. On June 4, 2020, Amendment 15 to the credit agreement was executed, decreasing the borrowing base of the credit agreement from $95.0 million to $64.0 million, establishing a repayment schedule for the borrowing base deficiency and waiving the March 31, 2020, leverage ratio noncompliance. However, we did not receive a waiver for more than one year from the balance sheet date, resulting in borrowings payable of $74.0 million being classified as current liabilities at March 31, 2020. See Note 14 in this section for additional information on Amendment 15 to the credit agreement. The Partnership’s total current liabilities of $77.2 million exceeded our total current assets of $20.9 million at March 31, 2020. Our ability to continue as a going concern is dependent on the re-negotiation of our revolving credit facility, or other measures such as the sale of assets or raising additional capital. There is no assurance, however, that such discussions will result in a refinancing of the credit facility on acceptable terms, if at all, or provide any specific amount of additional liquidity. These factors raise substantial doubt over the Partnership’s ability to continue as a going concern for at least one year from the date that these financial statements are issued, and therefore, whether we will realize our assets and extinguish our liabilities in the normal course of business and at the amounts stated in the unaudited condensed consolidated financial statements. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty, nor do they include adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts and classifications of liabilities that might be necessary should the Partnership be unable to continue as a going concern.

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Non-cash Investing and Supplemental Cash Flow Information

The following presents the non-cash investing and supplemental cash flow information for the periods presented:

Note 2. Acquisitions, Divestitures and Assets Held for Sale

We adopted ASU No. 2017-01, “Business Combinations (Topic 805)” effective January 1, 2018. We now evaluate all acquisitions to determine whether they should be accounted for as business combinations or asset acquisitions. The guidance provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, the set must include an input and substantive process that together significantly contribute to the ability to create output.

Assets and liabilities assumed in acquisitions accounted for as business combinations are recorded in our unaudited condensed consolidated balance sheets at their estimated fair values as of the acquisition date using assumptions that represent Level 3 fair value measurement inputs. See Note 5 in this section for additional discussion of our fair value measurements.

Results of operations attributable to the acquisition subsequent to the closing are included in our unaudited condensed consolidated statements of operations. The operations and cash flows of divested properties are eliminated from our ongoing operations.

Strategic Transaction

In March 2019, we simultaneously closed the previously announced definitive agreements to sell substantially all of our oil and natural gas properties located in Texas for $60.0 million and to purchase certain oil and natural gas properties located in Osage, Grady and Caddo Counties in Oklahoma for an aggregate purchase price of $27.5 million, both agreements subject to customary purchase price adjustments. We received net proceeds of $32.5 million at the close of this Strategic Transaction (“Strategic Transaction”) of which $32.0 million was used to reduce borrowings outstanding on our revolving credit facility. The acquired properties were accounted for as an asset acquisition. A gain on the sale of oil and natural gas properties of $9.5 million was reported in the unaudited condensed consolidated statements of operations for the three months ended March 31, 2019.

The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying unaudited condensed consolidated statements of operations for the periods presented:

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Assets Held for Sale

On January 23, 2020, we closed the sale of land in Southern Oklahoma for a net cash settlement of $0.4 million. At December 31, 2019, the carrying value of $0.4 million was presented in “Assets held for sale” in our unaudited condensed consolidated balance sheets.

Note 3. Equity Awards

We have a long-term incentive program (the “Long-Term Incentive Program”) for employees, officers, consultants and directors of our general partner and its affiliates, including Mid-Con Energy Operating, LLC (“Mid-Con Energy Operating”) and ME3 Oilfield Service, LLC (“ME3 Oilfield Service”), who perform services for us. The Long-Term Incentive Program allows for the award of unit options, unit appreciation rights, unrestricted units, restricted units, phantom units, distribution equivalent rights granted with phantom units and other types of awards. The Long-Term Incentive Program is administered by the voting members of our general partner, and approved by the Board of Directors of our general partner (the “Board”). If an employee terminates employment prior to the restriction lapse date, the awarded units are forfeited and canceled and are no longer considered issued and outstanding.

The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at March 31, 2020:

We recognized $0.1 million and $0.3 million of total equity-based compensation expense for the three months ended March 31, 2020 and 2019, respectively. These costs are reported as a component of general and administrative expenses (“G&A”) in our unaudited condensed consolidated statements of operations.  

Unrestricted Unit Awards

During the three months ended March 31, 2020, we granted 32,666 unrestricted units with an average grant date fair value of $0.26 per unit. During the three months ended March 31, 2019, we granted 50,000 unrestricted units with an average grant date fair value of $1.04 per unit.

Equity-Settled Phantom Unit Awards

Equity-settled phantom units vest over a period of two or three years. During the three months ended March 31, 2020, we did not grant any equity-settled phantom units. During the three months ended March 31, 2019, we granted 510,000 equity-settled phantom units with a two-year vesting period and 63,000 equity-settled phantom units with a three-year vesting period. As of March 31, 2020, there were $0.2 million of unrecognized compensation costs related to non-vested equity-settled phantom units. These costs are expected to be recognized over a weighted average period of twelve months.

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A summary of our equity-settled phantom unit awards for the three months ended March 31, 2020, is presented below:

Note 4. Derivative Financial Instruments

Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivative contracts (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent or as required by our lenders. We account for our commodity derivative contracts at fair value. See Note 5 in this section for a description of our fair value measurements.

We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of our commodity derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash gains or losses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-market adjustments, gains or losses arise from net amounts paid or received on monthly settlements, proceeds from or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. Pursuant to the accounting standard that permits netting of assets and liabilities where the right of offset exists, we present the fair value of commodity derivative contracts on a net basis.

At March 31, 2020, our commodity derivative contracts were in a net asset position with a fair value of $22.0 million, whereas at December 31, 2019, our commodity derivative contracts were in a net liability position with a fair value of $1.2 million. All of our commodity derivative contracts are with major financial institutions that are also lenders under our revolving credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our commodity derivative contracts under lower commodity prices and we could incur a loss. As of March 31, 2020, all of our counterparties have performed pursuant to the terms of their commodity derivative contracts.

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The following tables summarize the gross fair value by the appropriate balance sheet classification, even when the derivative financial instruments are subject to netting arrangements and qualify for net presentation, in our unaudited condensed consolidated balance sheets at March 31, 2020, and December 31, 2019:

The following table presents the impact of derivative financial instruments and their location within the unaudited condensed consolidated statements of operations:

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At March 31, 2020, and December 31, 2019, our commodity derivative contracts had maturities at various dates through December 2021 and were comprised of commodity price swap and collar contracts. At March 31, 2020, we had the following oil derivatives net positions:

At December 31, 2019, we had the following oil derivatives net positions:

Note 5. Fair Value Disclosures

Fair Value of Financial Instruments

The carrying amounts reported in our unaudited condensed consolidated balance sheets for cash, accounts receivable and accounts payable approximate their fair values. The carrying amount of debt under our revolving credit facility approximates fair value because the revolving credit facility’s variable interest rate resets frequently and approximates current market rates available to us. We account for our commodity derivative contracts at fair value as discussed in “Assets and Liabilities Measured at Fair Value on a Recurring Basis” below.

Fair Value Measurements

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. GAAP establishes a three-tier fair value hierarchy that is intended to increase consistency and comparability in fair value measurements and related disclosures. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded in the balance sheet are categorized based on the inputs to the valuation technique as follows:

Level 1 - Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. We consider active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an on-going basis.

Level 2 - Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Level 2 instruments primarily include swap, call, put and collar contracts.

Level 3 - Financial assets and liabilities for which values are based on prices or valuation approaches that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. We had no transfers in or out of Levels 1, 2 or 3 for the three months ended March 31, 2020, and for the year ended December 31, 2019.

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Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no material changes in valuation approach or related inputs for the three months ended March 31, 2020, and for the year ended December 31, 2019.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

We account for commodity derivative contracts and their corresponding deferred premiums at fair value on a recurring basis utilizing certain pricing models. Inputs to the pricing models include publicly available prices from a compilation of data gathered from third parties and brokers. We validate the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Any deferred premiums associated with our commodity derivative contracts are categorized as Level 3, as we utilize a net present value calculation to determine the valuation. See Note 4 in this section for a summary of our derivative financial instruments.

The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value on a recurring basis as of March 31, 2020, and December 31, 2019:

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Asset Retirement Obligations

We estimate the fair value of our asset retirement obligations (“ARO”) based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 6 in this section for a summary of changes in ARO.

Acquisitions

The estimated fair values of proved oil and natural gas properties acquired in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates at the acquisition date. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and natural gas properties acquired is deemed to use Level 3 inputs. See Note 2 in this section for further discussion of our acquisitions.

Reserves

We calculate the estimated fair values of reserves and properties using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of reserves, future operating and developmental costs, future commodity prices, a market-based weighted average cost of capital rate and the rate at which future cash flows are discounted to estimate present value. We discount future values by a per annum rate of 10% because we believe this amount approximates our long-term cost of capital and accordingly, is well aligned with our internal business decisions. The underlying commodity prices embedded in our estimated cash flows begin with Level 1 NYMEX-WTI forward curve pricing, less Level 3 assumptions that include location, pricing adjustments and quality differentials.

Impairment

The need to test oil and natural gas assets for impairment may result from significant declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. If the carrying value of the long-lived assets exceeds the estimated undiscounted future net cash flows, an impairment expense is recognized for the difference between the estimated

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fair value and the carrying value of the assets. Due to the unprecedented decline in oil prices, we recorded impairment expense of $18.3 million for the three months ended March 31, 2020. There was no impairment expense for the three months ended March 31, 2019.

Note 6. Asset Retirement Obligations

We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or successfully drilling a well and determine our ARO by calculating the present value of estimated cash flow related to the estimated future liability. Determining the removal and future restoration obligation requires management to make estimates and judgments, including the ultimate settlement amounts, inflation factors, credit-adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. We are required to record the fair value of a liability for the ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We review our assumptions and estimates of future ARO on an annual basis, or more frequently, if an event or circumstances occur that would impact our assumptions. To the extent future revisions to these assumptions impact the present value of the abandonment liability, management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. The liability is accreted each period toward its future value and is recorded in our unaudited condensed consolidated statements of operations. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the assets based on proved developed reserves. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.

As of March 31, 2020, and December 31, 2019, our ARO were reported as asset retirement obligations in our unaudited condensed consolidated balance sheets. Changes in our ARO for the periods indicated are presented in the following table:

Note 7. Debt

We had outstanding borrowings under our revolving credit facility of $74.0 million and $68.0 million at March 31, 2020, and December 31, 2019, respectively. Our current revolving credit facility matures in May 2021. Borrowings under the facility are secured by liens on not less than 90% of the value of our proved reserves. As of March 31, 2020, we were not in compliance with our leverage ratio covenant, which was waived in Amendment 15 to the credit agreement, executed June 4, 2020. See Note 14 in this section for further information on Amendment 15 to the credit agreement.

The borrowing base of our revolving credit facility is collectively determined by our lenders based on the value of our proved oil and natural gas reserves using assumptions regarding future prices, costs and other variables. The borrowing base is subject to scheduled redeterminations in the spring and fall of each year with an additional redetermination, either at our request or at the request of the lenders, during the period between each scheduled borrowing base redetermination. An additional borrowing base redetermination may be made at the request of the lenders in connection with a material disposition of our properties or a material liquidation of a hedge contract. Our spring 2020 redetermination was finalized in June 2020. The next regularly scheduled semi-annual redetermination is expected to be completed in the fall of 2020.

At March 31, 2020, borrowings under the revolving credit facility bore interest at a floating rate based on, at our election, the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50% and the one month adjusted London Interbank Offered Rate (“LIBOR”) plus 1.0%, all of which are subject to a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or the applicable LIBOR plus a margin that varies from 2.75% to 3.75% per annum according to the borrowing base usage. For the three months ended March 31, 2020, the average effective rate was 5.19%. Any

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unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Letters of credit are subject to a letter of credit fee that varies from 2.75% to 3.75% according to usage.

We may use borrowings under the revolving credit facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership purposes and for funding distributions to our unitholders. The revolving credit facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, and restrictions on certain transactions and payments, including distributions, and requires us to maintain hedges covering projected production. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the credit agreement, together with accrued interest, could be declared immediately due and payable.

On March 28, 2019, in conjunction with closing the Strategic Transaction and serving as our spring redetermination, Amendment 13 to the credit agreement was executed, decreasing our borrowing base to $110.0 million. The amendment also required that the leverage ratio be calculated on a building, period-annualized basis, beginning the second quarter of 2019. See Note 2 in this section for further discussion of the Strategic Transaction.

On December 6, 2019, Amendment 14 to the credit agreement was executed, decreasing the borrowing base of the Partnership’s revolving credit facility to $95.0 million. The amendment also extended the maturity date of the revolving credit facility to May 1, 2021, and provided for a benchmark rate replacement to address the transition of LIBOR in 2021. Under the terms of the amendment, the Partnership is required to have a Consolidated Funded Indebtedness to Consolidated EBITDAX of less than 3.0 to 1.0 to make any borrowings above the borrowing cap of $85.0 million, and must maintain a maximum Leverage Ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX that does not exceed:

Note 8. Commitments and Contingencies

Services Agreement

As of March 31, 2020, we were a party to a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating provided certain services to us including management, administrative and operational services. We reimbursed Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurred in its performance under the services agreement. See Note 10 in this section for additional information. See Note 14 in this section for further information on the termination of this services agreement.

Employment Agreements

As of March 31, 2020, our general partner had entered into employment agreements with Charles R. Olmstead and Jeffrey R. Olmstead. The employment agreements automatically renewed for one-year terms on August 1st of each year unless either we or the employee gave written notice of termination by the preceding February. Pursuant to the employment agreements, each employee served in his respective position with our general partner, as set forth above, and had duties, responsibilities and authority as the Board specified from time to time, in roles consistent with such positions that were assigned to them. The agreements stipulated that if there was a change of control, termination of employment, with cause or without cause, or death of the executive certain payments would be made to the executive officer. These payments, depending on the reason for termination, ranged from $0.1 million to $0.3 million, including the value of vesting of any outstanding units at March 31, 2020. See Note 14 in this section for further information on the termination of these employment agreements.

Change in Control Severance Plan

On July 24, 2019, the Board adopted a Change in Control Severance Plan that provides severance benefits to certain key management employees of the general partner and its affiliates. The Change in Control Severance Plan provides for the payment of cash compensation and certain other benefits to eligible employees in the event of a change in control and a qualifying termination of employment. The obligations under the Change in Control Severance Plan are generally based on the terminated employee’s cash compensation and position within the Partnership. Depending on the facts and circumstances associated with a potential change in control, the total payments made pursuant to the Change in Control Severance Plan could be material. No liability has been recorded at March 31, 2020, associated with the Change in Control Severance Plan. For a

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more detailed description of the Change in Control Severance Plan, please refer to our Current Report on Form 8-K filed on July 26, 2019.

Legal

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us under the various environmental protection statutes to which we are subject.

Note 9. Equity

Common Units

At March 31, 2020, and December 31, 2019, the Partnership’s equity consisted of 1,557,851 and 1,541,215 common units, respectively, representing a 98.9% and 98.8% limited partnership interest in us, respectively. These common units were retroactively adjusted for the impact of the reverse stock split that occurred on April 9, 2020. See Footnote 14 in this section for additional information regarding the reverse stock split.

On May 5, 2015, we entered into an Equity Distribution Agreement to sell, from time to time through or to the Managers (as defined in the agreement), up to $50.0 million in common units representing limited partner interests. In connection with the purchase agreement for the Class A Preferred Units described below, we suspended sales of common units pursuant to the Equity Distribution Agreement effective as of the closing date until August 11, 2021, without the consent of a majority of the holders of the outstanding Preferred Units.

Our Partnership Agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. As of March 31, 2020, cash distributions to our common units continued to be indefinitely suspended. Our credit agreement stipulates written consent from our lenders is required in order to reinstate common unit distributions. Management and the Board will continue to evaluate, on a quarterly basis, the appropriate level of cash reserves in determining future distributions. The suspension of common unit cash distributions is designed to preserve liquidity and reallocate excess cash flow towards capital expenditure projects and debt reduction to maximize long-term value for our unitholders. There is no assurance as to future cash distributions since they are dependent upon our projections for future earnings, cash flows, capital requirements, financial conditions and other factors.

Preferred Units

As of March 31, 2020, the Partnership had issued Class A and Class B Preferred Units (collectively, the “Preferred Units”). Per accounting guidance, we were required to allocate a portion of the proceeds from Preferred Units to a beneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value was calculated at the commitment date based on the difference between the fair value of the common units at the issuance date (number of common units issuable at conversion multiplied by the per-share value of our common units at the issuance date) and the proceeds attributed to the class of Preferred Units. The beneficial conversion feature was accreted using the effective yield method over the period from the closing date to the effective date of the holder’s conversion right.

The holders of our Preferred Units were entitled to certain rights that were senior to the rights of holders of common units, such as rights to distributions and rights upon liquidation of the Partnership. We paid holders of Preferred Units a cumulative, quarterly cash distribution on Preferred Units then outstanding at an annual rate of 8.0%, or in the event that the Partnership’s existing secured indebtedness prevented the payment of a cash distribution to all holders of the Preferred Units, in kind (additional Class A or Class B Preferred Units), at an annual rate of 10.0%. Such distributions were paid for each such quarter within 45 days after such quarter end, or as otherwise permitted to accumulate pursuant to the Partnership Agreement.

Prior to August 11, 2021, each holder of Preferred Units had the right, subject to certain conditions, to convert all or a portion of their Preferred Units into common units representing limited partner interests in the Partnership on a one-for-one basis, subject to adjustment for splits, subdivisions, combinations and reclassifications of the common units. Upon conversion of the Preferred Units, the Partnership would pay any distributions (to the extent accrued and unpaid as of the then most recent Preferred Units distribution date) on the converted units in cash, or in the event that the Partnership’s existing secured indebtedness prevents the payment of a cash distribution to all holders of the Preferred Units, in kind (additional Class A or Class B Preferred Units), at an annual rate of 10.0%.

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See Note 14 in this section for further information on the conversion of the Preferred Units into common units.

Class A Preferred Units

On August 11, 2016, we completed a private placement of 11,627,906 Class A Preferred Units for an aggregate offering price of $25.0 million. The Class A Preferred Units were issued at a price of $2.15 per Class A Preferred Unit. Proceeds from this issuance were used to fund an acquisition and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We received net proceeds of $24.6 million in connection with the issuance of these Class A Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Class A Preferred Units ($18.6 million) and the beneficial conversion feature ($6.0 million). Accretion of the beneficial conversion feature was $0.3 million for the three months ended March 31, 2020 and 2019. The registration statement registering resales of common units issued or to be issued upon conversion of the Class A Preferred Units was declared effective by the SEC on June 14, 2017.

At March 31, 2020, the Partnership had accrued $0.5 million for the first quarter 2020 distributions. The following table summarizes cash distributions paid on our Class A Preferred Units during the three months ended March 31, 2020:

The following table summarizes cash distributions paid on our Class A Preferred Units during the three months ended March 31, 2019:

Class B Preferred Units

On January 31, 2018, we completed a private placement of 9,803,921 Class B Preferred Units for an aggregate offering price of $15.0 million. The Class B Preferred Units were issued at a price of $1.53 per Class B Preferred Unit. Proceeds from this issuance were used to fund the acquisition of certain oil and natural gas properties located in Campbell and Converse Counties, Wyoming, and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We received net proceeds of $14.9 million in connection with the issuance of these Class B Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Class B Preferred Units ($14.2 million) and the beneficial conversion feature ($0.7 million). Accretion of the beneficial conversion feature was $0.05 million for the three months ended March 31, 2020 and 2019. The registration statement registering resales of common units issued or to be issued upon conversion of the Class B Preferred Units was declared effective by the SEC on May 25, 2018.

At March 31, 2020, the Partnership had accrued $0.3 million for the first quarter 2020 distributions. The following table summarizes cash distributions paid on our Class B Preferred Units during the three months ended March 31, 2020:

The following table summarizes cash distributions paid on our Class B Preferred Units during the three months ended March 31, 2019:

Allocation of Net Income or Loss

Net income or loss is allocated to our general partner in proportion to its pro rata ownership during the period. The remaining net income or loss is allocated to the limited partner unitholders net of Preferred Unit distributions, including accretion of the Preferred Unit beneficial conversion feature. In the event of net income, diluted net income per partner unit reflects the potential dilution of non-vested restricted stock awards and the conversion of Preferred Units.

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Note 10. Related Party Transactions

Agreements with Affiliates

The following agreements were negotiated among affiliated parties and, consequently, are not the result of arm’s length negotiations. The following is a description of those agreements that were entered into with the affiliates of our general partner and with our general partner.

Services Agreement

As of March 31, 2020, we were party to a services agreement with our affiliate, Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating provided certain services to us, including managerial, administrative and operational services. The operational services included marketing, geological and engineering services. We reimbursed Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurred in its performance under the services agreement. These expenses included, among other things, salary, bonus, incentive compensation and other amounts paid to persons who performed services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. These expenses were included in G&A in our unaudited condensed consolidated statements of operations.

Operating Agreements

As of March 31, 2020, we, along with various third parties with an ownership interest in the same property, were parties to standard oil and natural gas joint operating agreements with our affiliate, Mid-Con Energy Operating. We and those third parties paid Mid-Con Energy Operating overhead associated with operating our properties and for its direct and indirect expenses that were chargeable to the wells under their respective operating agreements. The majority of these expenses were included in LOE in our unaudited condensed consolidated statements of operations. See Note 14 in this section for further information on the agreement by Mid-Con Energy Operating to resign as operator under these joint operating agreements as of July 1, 2020.

Oilfield Services

As of March 31, 2020, we were party to operating agreements, pursuant to which our affiliate, Mid-Con Energy Operating, billed us for oilfield services performed by our affiliates, ME3 Oilfield Service and ME2 Well Services, LLC. These amounts were either included in LOE in our unaudited condensed consolidated statements of operations or were capitalized as part of oil and natural gas properties in our unaudited condensed consolidated balance sheets.

Other Agreements

As of March 31, 2020, we were party to monitoring fee agreements with Bonanza Fund Management, Inc. (“Bonanza”), a Class A Preferred Unitholder, and Goff Focused Strategies, LLC (“GFS”), a Class B Preferred Unitholder, pursuant to which we paid Bonanza and GFS a quarterly monitoring fee in connection with monitoring the purchasers’ investments in the Preferred Units. These expenses were included in G&A in our unaudited condensed consolidated statements of operations.

The following table summarizes the related party transactions for the periods indicated:

At March 31, 2020, we had a net payable to our affiliate, Mid-Con Energy Operating, of $1.9 million, comprised of a joint interest billing payable of $2.7 million and a payable for operating services and other miscellaneous items of $0.3 million, offset by an oil and natural gas revenue receivable of $1.1 million. At December 31, 2019, we had a net payable to our affiliate, Mid-Con Energy Operating, of $6.9 million, comprised of a joint interest billing payable of $7.8 million and a payable for operating services and other miscellaneous items of $0.8 million, offset by an oil and natural gas revenue receivable of $1.7

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million. These amounts were included in accounts payable-related parties in our unaudited condensed consolidated balance sheets.

Note 11. Revenue Recognition

We adopted ASC 606 effective January 1, 2018, using the modified retrospective approach. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Under ASC 605, we followed the sales method of accounting for oil and natural gas sales revenues in which revenues were recognized on our share of actual proceeds from oil and natural gas sold to purchasers. Revenue recognition required for our oil and natural gas sales contracts by ASC 606 does not differ from revenue recognition required under ASC 605 to account for such contracts. Therefore, we concluded that there was no change in our revenue recognition under ASC 606 and the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018, did not result in an adjustment to retained earnings. We had no significant natural gas imbalances at March 31, 2020 and 2019.

Revenue from Contracts with Customers

Under our oil and natural gas sales contracts, enforceable rights and obligations arise at the time production occurs on dedicated leases as the Partnership promises to deliver goods in the form of oil or natural gas production on contractually-specified leases to the purchasers. Sales of oil and natural gas are recognized at the point that control of the product is transferred to the customer; title and risk of loss to the product generally transfers at the delivery point specified in the contract. We do not extract natural gas liquids (“NGLs”) from our natural gas production prior to the sale and transfer of title of the natural gas stream to our purchasers. While some of our purchasers extracted NGLs from the natural gas stream sold by us to them, we had no ownership in such NGLs. The Partnership commits and dedicates for sale all of the oil or natural gas production from contractually agreed-upon leases to the purchaser. Our oil contract pricing provisions are tied to a market index, with certain marketing adjustments, including location and quality differentials as well as certain embedded marketing fees. The majority of our natural gas contract pricing provisions are tied to a market index less customary deductions, such as gathering, processing and transportation. Payment is typically received 30 to 60 days after the date production is delivered.

Transaction Price Allocated to Remaining Performance Obligations

Our oil and natural gas sales are generally short-term in nature, with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14, exempting the Partnership from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our oil and natural gas sales contracts, the variable consideration related to variable production is not estimated because the uncertainty related to the consideration is resolved as the barrel of oil (“Bbl”) and Mcf of natural gas are transferred to the customer each day. Therefore, we have utilized the practical expedient in ASC 606-10-50-14(a), which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations for specific situations in which the Partnership does not need to estimate variable consideration to recognize revenue.

Contract Balances

Our oil and natural gas sales contracts do not give rise to contract assets or liabilities under ASC 606.

Note 12. Leases

We adopted ASC 842, as amended, on January 1, 2019, using the modified retrospective approach. The modified retrospective approach provided a method for recording existing leases at adoption and allowed for a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The adoption of this standard did not result in an adjustment to retained earnings. We elected the transition package of practical expedients permitted under the transition guidance, which among other things, allowed us to carry forward the historical lease classification. We also elected the optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840, Leases (“ASC 840”). Our leases do not provide an implicit discount rate; therefore, we used our incremental borrowing rate as of January 1, 2019. As a result of adopting the new standard, we recorded lease assets and lease liabilities of $1.2 million and $1.3 million, respectively, at January 1, 2019.

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We lease office space in Tulsa, Oklahoma, Abilene, Texas, and Gillette, Wyoming. Per the short-term accounting policy election, leases with an initial term of 12 months or less were not recorded on the balance sheet, and we recognize lease expense for these leases on a straight-line basis over the term of the lease. Most of our leases include an option to renew. The exercise of the lease renewal options is at our discretion.

A summary of our leases is presented below:

⁽¹⁾ Includes short-term leases.

⁽²⁾ There is not a material difference between cash paid and amortized expense.

Future minimum lease payments under the non-cancellable operating leases are presented in the following table:

Note 13. New Accounting Standards

In June 2016, the FASB issued ASC 326, Financial Instruments- Credit Losses (“ASC 326”), which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. For smaller reporting companies, this guidance is effective for fiscal years beginning after December 15, 2022, and early adoption is permitted. We plan to adopt this standard on January 1, 2023, and are currently evaluating the impact of the adoption on our consolidated financial statements.

Note 14. Subsequent Events

Transformational Recapitalization

The Partnership announced on June 5, 2020, that we had completed strategic recapitalization transactions (the “Recapitalization Transactions”), resulting in significant changes to our capital structure and governance to strengthen our balance sheet, create alignment across all unitholders, reduce costs and streamline operations, thereby creating immediate and sustainable value for all unitholders. As part of the Recapitalization Transactions, the holders of all of the Partnership’s

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Preferred Units, led by Goff Capital, Inc., (“Goff Capital”) converted their Preferred Units to common units at an average conversion price of $3.12/unit. In addition, the equity holders of the general partner contributed the ownership of the general partner to the Partnership in exchange for common units. In connection with these Recapitalization Transactions, the limited partnership agreement of the Partnership has been amended, the directors of the general partner have resigned, and a new Board has been elected by written consent of affiliates of Goff Capital that now hold a majority of the outstanding common units. Following these transactions, the Partnership had 14,311,522 common units outstanding. The Recapitalization Transactions closed on June 4, 2020. For a more detailed description of the Recapitalization Transactions, please refer to our Current Report on Form 8-K filed on June 10, 2020.

Election of New Board Members and Departure of Board Members

On June 5, 2020, the Partnership announced that Mr. Robert Boulware, Mr. Travis Goff and Mr. Fred Reynolds were elected to the Board. On June 10, 2020, the Partnership announced that the Board, acting by unanimous written consent, adopted resolutions on June 8, 2020, that expanded the size of the Board from three to four and appointed Mr. Caperton White to serve as the fourth member of the Board.

Mr. Robert Boulware served as President and CEO of ING Funds Distributor, LLC. Mr. Boulware’s experience also includes executive and management positions with WESAV Financial, Bank of America and Western Savings. Since 2008, he has served on the Brighthouse Funds Trustee Board as Chairman of the Investment Committee and as a member of the Nominating and Governance and Audit Committees. He has also served since 2013 as Board Trustee for the Vertical Capital Fund, where he is the Lead Independent Director and a member of the Audit Committee and Nominating and Governance Committee. Since 2014, Mr. Boulware has served as Board Trustee with the Sharespost 100 Fund, where he is currently Chairman of the Board, as well as Chairman of the Audit Committee and Nominating and Governance Committee. He also has served on the Board of Gainsco Auto Insurance since 2005 as Director, Chairman of the Audit Committee and member of the Compensation Committee. Mr. Boulware received his BSBA from Northern Arizona University at Flagstaff, Arizona.

Mr. Travis Goff is President of Goff Capital, a Fort Worth, Texas-based family office. Goff Capital is the family office of John Goff, which directly invests in public securities as well as private equity in a variety of industries. Mr. Goff manages all existing and potential private and public investments for Goff Capital. Mr. Goff is a graduate of the University of Texas at Austin and began his career at Morgan Stanley in New York, working in both the investment banking and principal investing platforms. He currently serves as a Board Member of several companies in the oil and gas, manufacturing and media and entertainment industries.

Mr. Fred N. Reynolds is the principal owner of Fred S. Reynolds & Associates, a petroleum engineering consulting firm located in Fort Worth, Texas. Mr. Reynolds graduated in 1979 with a Bachelor of Science in Petroleum Engineering from the University of Oklahoma. Following graduation, Mr. Reynolds worked for Chevron U.S.A. and Equity Oil Company as a drilling and completion engineer and Engineering Manager, before joining his father and forming the petroleum engineering consulting firm of Fred S. Reynolds & Associates in 1983.

Mr. Caperton White is President of Holly Oak Minerals Management, which manages over 40,000 gross mineral acres. Mr. White, a licensed Certified Public Accountant, previously worked at KPMG. He has significant transactional and restructuring experience. Mr. White received a Bachelor of Business Administration in Finance and a Master of Science in Accounting from the Cox School of Business at Southern Methodist University.

Departing Board members include Mr. Charles R. “Randy” Olmstead, Mr. Fred Ball Jr., Mr. John (“J.W.”) Brown, Mr. Peter A. Leidel and Mr. Cameron Smith, who resigned in connection with the Recapitalization Transactions. Mr. Wilkie S. Colyer, Jr., the President and CEO of Contango Oil & Gas Company (“Contango”), the parent of the new operator of the Partnership’s properties, also resigned from the Board, as announced on June 5, 2020.

Resignation of Senior Executive Management

The Partnership announced the resignations of Mr. Randy Olmstead, Chief Executive Officer, and Mr. Jeffrey R. Olmstead, former Chief Executive Officer and President (prior to serving on a sabbatical), from their positions as officers of the general partner on June 10, 2020. In connection with the Recapitalization Transactions, the Participation and Restrictive Covenant Agreements with Mr. Randy Olmstead and Mr. Jeffrey R. Olmstead under the Change in Control Severance Plan were terminated, and none of the parties’ rights or obligations thereunder survive termination. Any outstanding phantom units, restricted units or other awards granted to either executive under our Long-Term Incentive Plan were immediately vested and non-forfeitable as of termination.

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Amendment 15 to Credit Agreement and Borrowing Base Determination

Amendment 15 to the credit agreement was effective as of June 1, 2020. This amendment to the credit agreement, among other changes:

Appointment of Contango Resources, Inc. as Operator for the Partnership

The Partnership has entered into a Management Services Agreement (“MSA”) with Contango Resources, Inc. (“Contango Resources”) effective as of July 1, 2020. Under the MSA, Contango Resources will provide management and administrative services and serve as operator of the Partnership’s assets for a flat fee arrangement of $4.0 million annually, plus a maximum $2.0 million termination fee, which is expected to generate pro forma annual cash savings of approximately $6.5 million compared with 2019. Contango will also receive warrants to acquire common units of the Partnership within ten business days of July 1, 2020, further aligning it with equity holders. 

Delay of Filing

On May 12, 2020, we filed a Current Report on Form 8-K giving notice that the Partnership intended to delay the filing of our Quarterly report on Form 10-Q for the fiscal quarter ended March 31, 2020. The Partnership relied on the SEC order (SEC Release 34-88465), to delay the filing of our Quarterly Report.

Reverse Stock Split

On April 9, 2020, the previously approved 1-for-20 reverse unit split on the Partnership’s common units became effective after market close. The unaudited condensed consolidated financial statements were adjusted for the reverse stock split.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto, as well as our Annual Report.

Overview

Mid-Con Energy Partners, LP is a publicly held limited partnership formed in July 2011 that engages in the ownership, acquisition and development of producing oil and natural gas properties in North America, with a focus on EOR. Our properties are located in Oklahoma and Wyoming. Our properties primarily consist of mature, legacy onshore oil reservoirs with long-lived, relatively predictable production profiles and low production decline rates.

Executive Summary

Recapitalization Transactions

As described in Note 14 to the unaudited condensed consolidated financial statements, the Partnership closed the Recapitalization Transactions on June 4, 2020, resulting in significant changes to our capital structure and governance to

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strengthen our balance sheet, create alignment across all unitholders, reduce costs and streamline operations, thereby creating immediate and sustainable value for all unitholders. As part of the Recapitalization Transactions, all of the Partnership’s Class A and B Preferred Units were converted into common units at an average conversion price of $3.12/unit. In addition, ownership of the Partnership’s general partner has been transferred to the Partnership, resulting in strengthened corporate governance, and a new Board of Directors has been elected by written consent of the holders of a majority of the common unitholders.

In conjunction with the Recapitalization Transactions, the Partnership also announced that Contango Resources will be the new operator of the Partnership’s properties, replacing Mid-Con Energy Operating. The move is expected to generate pro forma annual cash savings of approximately $6.5 million compared to 2019.

Financial and Operational Performance

Our financial and operational performance for the three months ended March 31, 2020, included the following:

Recent Developments

COVID-19

The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility in financial markets. As a result, there has been a significant reduction in demand for and prices of oil and natural gas. The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies, is uncertain and depends on various factors, including the demand for oil and natural gas, the availability of critical personnel to operate our properties and the potential governmental restrictions on operations. We have implemented remote working arrangements where possible. Our remote working arrangements have not significantly impacted our internal controls over financial reporting and disclosure controls and procedures.

Crude Oil Price Declines

During the first quarter of 2020, the oil and natural gas industry witnessed a significant decline in oil prices from $63 per Bbl in early January to just above $20 per Bbl in late March. This sudden decline in oil prices was primarily attributable to the decline in global oil demand resulting from COVID-19 and a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to increase its oil production to world markets. As a result of these unexpected events and the resulting declines in oil prices, the Partnership modified our 2020 operational plan. We remain focused on cost reductions, including periodic economic review of each well within our portfolio along with ongoing scrutiny of LOE and G&A. Wells that are not economically viable, at prevailing prices, are shut-in provided there are no contractual, operating or reservoir constraints precluding the suspension of operations. We have shut-in approximately 250 uneconomic wells during March 2020, and an additional 150 uneconomical wells in April 2020. We continue to monitor pricing and expenses to determine when to return these wells to production.

Business Environment

The markets for oil and natural gas have been volatile and may continue to be volatile in the future, which means that the price of oil and natural gas may fluctuate widely. Sustained periods of low prices for oil and natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. Our average sales price per Bbl, excluding commodity derivative contracts, was $43.86 and $49.98 for the three months ended March 31, 2020 and 2019, respectively.

Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivative contracts (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices. We enter into commodity derivative contracts or modify our portfolio of existing

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commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent or as required by our lenders. We conduct our risk management activities exclusively with participant lenders in our revolving credit facility. We have entered oil commodity derivative contracts covering a portion of our anticipated oil production through December 2021.

Our business faces the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well or formation decreases. Although our waterflood operations tend to restore reservoir pressure and production, once a waterflood is fully effected, production, once again, begins to decline. Our future growth will depend on our ability to continue to add reserves in excess of our production. Our focus on adding reserves is primarily through improving the economics of producing oil from our existing fields and, secondarily, through acquisitions of additional proved reserves. Our ability to add reserves through development projects and acquisitions is dependent upon many factors, including our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and close acquisitions.

We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flows from operations are impacted by our ability to manage our overall cost structure.

How We Evaluate Our Operations

Our primary business objective is to manage our oil and natural gas properties for the purpose of generating stable cash flows, which will provide stability and, over time, growth of distributions to our unitholders. The amount of cash that we may distribute to our unitholders in the future depends principally on the cash we generate from our operations, which will fluctuate from quarter-to-quarter based on, among other factors:

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas properties, including:

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Results of Operations

The tables presented in this section summarize certain results of operations and period-to-period comparisons for the three months ended March 31, 2020 and 2019. Because of normal production declines, changes in drilling activities, fluctuations in commodity prices and the effects of acquisitions and divestitures, the historical data presented below should not be interpreted as being indicative of future results.

Net production volumes, average sales prices and unit costs per Boe

Oil and natural gas sales

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Oil and natural gas sales price and volume variances