Exhibit 99.1

Mid-Con Energy Partners, LP and subsidiaries

The accompanying notes are an integral part of these consolidated financial statements.

5

Mid-Con Energy Partners, LP and subsidiaries

The accompanying notes are an integral part of these consolidated financial statements.

6

Mid-Con Energy Partners, LP and subsidiaries

The accompanying notes are an integral part of these consolidated financial statements.

7

Mid-Con Energy Partners, LP and subsidiaries

The accompanying notes are an integral part of these consolidated financial statements.

8

Mid-Con Energy Partners, LP and subsidiaries

Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

Revenue Recognition

We adopted Accounting Standards Codification (“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 December 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 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 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.

Performance Obligations Satisfied in Prior Reporting Periods Recognized in the Current Period. At the end of each month, the Partnership estimates the amount of production delivered and sold to customers and the proceeds to be received for such sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer and are reflected in the financial statements within the captions “oil sales” and “natural gas sales”. Revenues recognized during the years ended December 31, 2020 and 2019 related to the performance obligations satisfied in prior reporting periods were not material.

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

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

Oil and Natural Gas Properties

Our oil and natural gas development and production activities are accounted for using the successful efforts method. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized costs of proved properties are depleted quarterly using the units-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment is based on the units-of-production method using proved developed reserves on a field basis. Capitalized costs of individual properties abandoned or retired are charged to accumulated depletion, depreciation and amortization. Proceeds from sales of individual properties are credited to property costs.

Costs associated with unproved properties are excluded from depletion until proved reserves are established or impairment determined. When proven reserves are established, any unproved property costs associated with the project are transferred to proved properties and included in depletion. Unproved properties are assessed at least annually to ascertain whether impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. The impairment test for unproved properties is not based on the estimated fair value of the unproved properties. The impairment assessment includes consideration of our intent to fully develop our unproved properties, remaining lease terms, geological and geophysical evaluations, our drilling results, potential drilling locations, availability of capital, assignment of proved reserves, expected divestitures, anticipated future capital expenditures and economic considerations, among others.

Costs of significant proved non-producing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depletion until the related project is completed. We capitalize interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. We had no capitalized interest during any of the periods presented. We review our long-lived assets to be held and used, including proved oil and natural gas properties whenever events or circumstances indicate that the carrying value may be greater than management’s estimates of its future net cash flows, including cash flows from proved reserves. The need to test an asset 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 sum of estimated undiscounted future net cash flows, an impairment expense is recognized for the difference between the estimated fair value and the carrying value of the assets. We review our oil and natural gas properties by amortization base (field) or by individual well for those wells not constituting part of an amortization base. These evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. Cash flow estimates for the impairment testing exclude derivative instruments used to mitigate the price risk related to lower future oil and natural gas prices.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or drilling a well. Determining the future restoration and removal 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 estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. 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. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the asset 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. See Note 7 in this section for additional information.

Derivatives and Hedging

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 derivatives (commodity price and differential 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.

Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. We net the fair value of derivatives by counterparty where the right of offset exists and determine the fair value of our derivatives by utilizing certain pricing models to validate the data provided by third parties. See Note 6 in this section for additional discussion 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 unsettled 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 income or expenses 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 payments made or received on monthly settlements, proceeds 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. See Note 5 in this section for discussion regarding derivative financial instruments.

Equity-Based Compensation

The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value and is recorded as compensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria vest when it is probable that the performance criteria will be met. We recognize forfeitures of equity awards as they occur.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

Debt Issuance Costs

Debt placement costs are stated at cost, net of amortization, which is computed using the straight-line method and recognized as interest expense in the consolidated statements of operations over the remaining life of the agreement. Since our debt consists of a revolving credit facility, net debt placement costs are presented in “Other Assets” in our consolidated balance sheets. When debt is retired before its scheduled maturity date, any remaining issuance costs associated with that debt are expensed.

Income Taxes

The Partnership is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, taxable income or loss is includable in the federal income tax returns of our unitholders. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

Allocation of Net Income or Loss

Net income or loss was allocated to our general partner in proportion to its pro rata ownership during the period. The remaining net income or loss was 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 reflected the potential dilution of non-vested restricted stock awards and the conversion of Preferred Units to common units. On June 4, 2020, as part of the Recapitalization Transactions, the general partner units were converted to common units; therefore, net income or loss will no longer be allocated to our general partner.

Reverse Unit Split

On April 9, 2020, the Partnership effected a 1-for-20 reverse common unit split. For presentation purposes, the consolidated financial statements and footnotes have been adjusted to reflect this reverse unit split as if it had occurred at the beginning of the periods presented.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

Recently Issued Accounting Standards

In June 2016, the Financial Accounting Standards Board 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 adoption on our consolidated financial statements.

NOTE 3 - ACQUISITIONS, DIVESTITURES AND ASSETS HELD FOR SALE

Acquisitions

Assets and liabilities assumed in acquisitions accounted for as business combinations are recorded in our 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 6 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 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 $9.3 million was reported in the consolidated statements of operations.

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

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

Divestiture

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 consolidated balance sheets. No gain or loss on the transaction was recorded during the twelve months ended December 31, 2020.

NOTE 4 - EQUITY AWARDS

We have a long-term incentive program (the “Long-Term Incentive Program”) for employees, officers, consultants and directors of our general partner. 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 December 31, 2020:

We recognized $0.3 million and $0.7 million of total equity-based compensation expense for the years ended December 31, 2020 and 2019, respectively. These costs are reported as a component of G&A in our consolidated statements of operations.

Unrestricted Unit Awards

During the year ended December 31, 2020, we granted 1,633 unrestricted units with an average grant date fair value of $5.20, as adjusted for the reverse unit split. During the year ended December 31, 2019, we granted 2,500 unrestricted units with an average grant date fair value of $20.80 per unit, as adjusted for the reverse unit split.

Equity-Settled Phantom Unit Awards

Equity-settled phantom units vest over a period of two or three years. During the year ended December 31, 2020, we did not grant any equity-settled phantom units. During the year ended December 31, 2019, we granted 25,500 equity-settled phantom awards with a two-year vesting period and 3,300 equity-settled phantom awards with a three-year vesting period, as adjusted for the reverse split.

A summary of our equity-settled phantom unit awards for the years ended December 31, 2020 and 2019, is presented below:

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Mid-Con Energy Partners, LP and subsidiaries

NOTE 5 - 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 (commodity price and differential 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 6 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 December 31, 2020, our commodity derivative contracts were in a net asset position with a fair value of $3.1 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. During the years ended December 31, 2020 and 2019, all of our counterparties have performed pursuant to their commodity derivative contracts.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

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 consolidated balance sheets at December 31, 2020 and 2019:

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Mid-Con Energy Partners, LP and subsidiaries

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

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

NOTE 6 - FAIR VALUE DISCLOSURES

Fair Value of Financial Instruments

The carrying amounts reported in our 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 Measures at Fair Value on a Recurring Basis” below.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

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. U.S. 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:

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 during the years ended December 31, 2020 and 2019.

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 changes in valuation approach or related inputs for the years ended December 31, 2020 and 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 5 in this section for a summary of our derivative financial instruments.

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Mid-Con Energy Partners, LP and subsidiaries

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

Asset Retirement Obligations

We estimate the fair value of our 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 7 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 3 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.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

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 fair value and the carrying value of the assets. For the year ended December 31, 2020, we recorded impairment expense for proved properties of $19.6 million and $4.3 million of abandonment expense for unproved properties. For the year ended December 31, 2019, we recorded impairment expense for proved properties of $0.4 million. Additionally, for the year ended December 31, 2019, we recorded impairment expense related to assets held for sale of $0.1 million to reduce the carrying amount of the assets to their fair value.

NOTE 7 - 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 production 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 consolidated statement 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.

For the years ended December 31, 2020 and 2019, our ARO were reported as asset retirement obligations in our consolidated balance sheets. Changes in our ARO for the periods indicated are presented in the following table:

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

NOTE 8 - DEBT

At December 31, 2020 and 2019, we had outstanding borrowings under our revolving credit facility of $68.5 million and $68.0 million, 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. At 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. In connection with entering into the Merger Agreement with Contango Oil and Gas Company (“Contango”), the Partnership entered into a postponement letter with its lenders under our revolving credit facility (the “Postponement Letter”). The Postponement Letter provided, among other things, the Partnership could postpone the payment of the Original Deficiency Balance Amount and the Partnership’s compliance with the Leverage Ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX until December 31, 2020, which was later extended until January 22, 2021. In connection with the closing of the merger with Contango on January 21, 2021, the Partnership terminated its Credit Agreement and all outstanding borrowings, fees and expenses were paid in full. See Note 16 for additional information.

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.

Borrowings under the revolving credit facility bear 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 year ended December 31, 2020, the average effective rate was 5.08%. Any unused portion of the borrowing base will be 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 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 3 in this section for further discussion of the Strategic Transaction.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

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 was 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 maintain a maximum Leverage Ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX not to exceed:

Amendment 15 to the credit agreement, effective June 1, 2020, among other changes decreased the borrowing base from $95.0 million to $64.0 million and established a monthly repayment schedule beginning June 1, 2020, through November 1, 2020, for the $11.0 million borrowing base deficiency (such amount due on November 1, 2020, the “Original Deficiency Balance Amount”); permitted the Recapitalization Transactions; introduced anti-cash hoarding provisions and restrictive covenants on capital and general and administrative spending; provided for all loans to bear payment-in-kind interest, capitalized on a quarterly basis; excluded certain assumed liabilities from the Current Ratio calculation for the quarters ending June 30, 2020, September 30, 2020, and December 31, 2020; and required the Partnership’s Leverage Ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX not to exceed:

NOTE 9 - COMMITMENT AND CONTINGENCIES

Services Agreement

The Partnership entered into a management services agreement with Contango Resources, Inc. (“Contango Resources”) on June 4, 2020, as part of the Recapitalization Transactions. Under the agreement, effective July 1, 2020, Contango Resources provides management and administrative services and serves as the operator of the Partnership’s assets for a flat fee arrangement of $4.0 million annually, plus a maximum $2.0 million termination fee. These expenses were included in G&A in our consolidated statements of operations. See Note 11 in this section for additional information.

Employment Agreements

As part of the Recapitalization Transactions, the general partner terminated the employment agreements of Charles R. Olmstead and Jeffrey R. Olmstead. Pursuant to the employment agreements, each employee served in his respective position with our general partner 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. No payments were made under the employment agreements.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

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 former 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. At December 31, 2020, no liability has been recorded associated with the Change in Control Severance Plan.

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 10 - EQUITY

On June 5, 2020, the Partnership announced the completion of the strategic recapitalization transactions (the “Recapitalization Transactions”), that resulted in significant changes to our capital structure and governance, strengthened our balance sheet, created alignment across all unitholders, reduced costs and streamlined operations and created immediate and sustainable value for all unitholders. In connection with these Recapitalization Transactions, the limited partnership agreement of the Partnership was amended and restated, and the Partnership entered into a Management Services Agreement (“MSA”) with Contango Resources effective as of July 1, 2020. Under the MSA, Contango Resources provides management and administrative services and serve as the operator of the Partnership’s assets for a flat fee arrangement of $4.0 million annually, plus a maximum $2.0 million termination fee.

Common Units

At December 31, 2020 and 2019, the Partnership’s equity consisted of 14,311,522 and 1,541,215 common units, respectively, representing, a 100% and 98.8% limited partnership interest in us, respectively.

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 December 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

Preferred Units

The Partnership had issued two classes of 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 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%. 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.

Each holder of Preferred Units had the right, prior to August 11, 2021, 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.

As part of the Recapitalization Transactions on June 4, 2020, the holders of all of the Partnership’s Preferred Units converted their Preferred Units to common units at an average conversion price of $3.12 per Preferred Unit. Accrued distributions for the first quarter 2020 were paid in kind and, along with the second quarter 2020 pro-rata distribution, were included in the calculation of the conversion price to 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 $0.5 million and $1.2 million for the years ended December 31, 2020 and 2019, respectively. 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.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

As the holders of all the Partnership’s Preferred Units received payment-in-kind for all accrued distributions as part of the previously announced Recapitalization Transactions, the Partnership did not accrue any distributions as of December 31, 2020. The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2020:

The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 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 $0.1 million and $0.2 million for the years ended December 31, 2020 and 2019, respectively. 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.

As the holders of all the Partnership’s Preferred Units received payment-in-kind for all accrued distributions as part of the previously announced Recapitalization Transactions, the Partnership did not accrue any distributions as of December 31, 2020. The following table summarizes cash distributions paid on our Class B Preferred Units during the year ended December 31, 2020:

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Allocations of Net Income or Loss

Net income or loss was allocated to our general partner in proportion to its pro-rata ownership during the period. The remaining net income or loss was 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 reflected the potential dilution of non-vested restricted stock awards and the conversion of Preferred Units. On June 4, 2020, as part of the Recapitalization Transactions, the general partner units were converted to common units; therefore, net income or loss will no longer be allocated to our general partner.

NOTE 11 - 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 former board member and Chief Executive Officer, Mr. Charles R. Olmstead.

Services Agreement

Prior to the Recapitalization Transactions on June 4, 2020, we were party to a services agreement with our former 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 consolidated statements of operations.

The Partnership entered into a Management Services Agreement with Contango Resources on June 4, 2020, as part of the Recapitalization Transactions. Under the agreement, effective July 1, 2020, Contango Resources provides management and administrative services and serves 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. These expenses were included in G&A in our consolidated statements of operations.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

Operating Agreements

Prior to the Recapitalization Transactions on June 4, 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 former 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 consolidated statements of operations. Mid-Con Energy Operating resigned as operator under these joint operating agreements and Contango Resources became operator on July 1, 2020. Pursuant to the Management Services Agreement with Contango Resources, Contango Resources does not charge overhead associated with operating our properties.

Oilfield Services

Prior to the Recapitalization Transactions on June 4, 2020, we were party to operating agreements, pursuant to which our former 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 consolidated statements of operations or were capitalized as part of oil and natural gas properties in our consolidated balance sheets. Mid-Con Energy Operating resigned as operator under these service agreements, and Contango Resources became operator on July 1, 2020.

Other Agreements

Prior to the Recapitalization Transactions on June 4, 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 consolidated statements of operations.

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

At December 31, 2020, we had a net payable to Contango Resources of $3.5 million, comprised of a joint interest billing payable of $6.1 million, offset by an operating services and other miscellaneous items receivable of $1.0 million and an oil and natural gas revenue receivable of $1.6 million. At December 31, 2019, we had a net payable to our former 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 million. These amounts were included in accounts payable-related parties in our consolidated balance sheets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

NOTE 12 - CREDIT RISK

Credit risk relates to the risk of loss resulting from non-performance of non-payment by counterparties under the terms of their contractual obligations, thereby impacting the amount and timing of expected cash flows. Financial instruments which potentially subject us to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. We have not experienced any significant losses from such investments.

For the year ended December 31, 2020, sales of oil and natural gas to three purchasers accounted for approximately 84% of our sales. At December 31, 2020, these purchasers accounted for approximately 91% of our outstanding oil and natural gas accounts receivable. For the year ended December 31, 2019, sales of oil and natural gas to three purchasers accounted for approximately 76% of our sales. At December 31, 2019, these purchasers accounted for approximately 89% of our outstanding oil and natural gas accounts receivable. We believe that the loss of any one purchaser would not have a material adverse effect on our ability to sell our oil and natural gas production as other purchasers would be accessible. We have not experienced any significant losses due to uncollectible accounts receivable from these purchasers.

NOTE 13 - EMPLOYEE BENEFIT PLANS

In 2011, our general partner adopted the Long-Term Incentive Program which is intended to promote the interests of the Partnership by providing to employees, officers, consultants and directors of our general partner grants of restricted units, phantom units, unit appreciation rights, distribution equivalent rights and other unit based awards to encourage superior performance. The Long-Term Incentive Program is also intended to enhance the ability of the general partner and our affiliates, to attract and retain the services of individuals who are essential for the growth and profitability of the Partnership and to encourage them to devote their best efforts to advancing the business of the Partnership.

The Long-Term Incentive Program is administered by the voting members of our general partner, and awards are approved by the Board. Except as set forth in the employment agreements of the executive officers of our general partner, there is no set formula for granting awards to our employees, officers, consultants and directors of our general partner and our affiliates. In determining whether to grant awards and the amount of any awards, the administrators take into consideration the performance of the Partnership along with discretionary factors such as the individual’s current and expected future performance, level of responsibility, retention considerations and the total compensation package. See Note 4 in this section for additional information regarding awards granted under the Long-Term Incentive Program.

NOTE 14 - INCOME TAXES

The Partnership is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, taxable income or loss is includable in the federal income tax returns of our unitholders. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

NOTE 15 - 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, as of January 1, 2019.

We lease office space in Tulsa, Oklahoma and Abilene, Texas. 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.

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Mid-Con Energy Partners, LP and subsidiaries

NOTE 16 - SUBSEQUENT EVENTS

Completion of Merger with Contango

On January 21, 2021, the previously announced Merger with Contango was completed. At the effective time of the Merger, the separate existence of Mid-Con ceased, and Merger Sub survived the Merger as a wholly owned, direct subsidiary of Contango. The Merger was consummated in accordance with the terms of the Merger Agreement. Each common unit representing limited partners interests in the partnership were converted into and became exchangeable for 1.75 shares of common stock of Contango. On January 21, 2021, in connection with the closing of the Merger, the Partnership terminated its Credit Agreement. In connection with the termination of the Credit Agreement, all outstanding borrowings and unpaid fees and expenses thereunder were paid in full. Also on January 21, 2021, in connection with the closing of the Merger, the Partnership terminated the Management Services Agreement with Contango Resources, dated as of July 1, 2020. In light of the Merger, Contango Resources, a subsidiary of Contango, agreed to waive (i) its right to the warrant compensation and (ii) the termination fee Contango Resources was otherwise entitled to under the Management Services Agreement.

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Mid-Con Energy Partners, LP and subsidiaries

Estimated Proved Oil and Natural Gas Reserves (Unaudited)

The Partnership’s proved oil and natural gas reserves are all located in the United States. The proved oil and natural gas reserves for the year ended December 31, 2020, were prepared by our reservoir engineers and audited by William M. Cobb & Associates, independent third party petroleum consultants. For the year ended December 31, 2019, the proved oil and natural gas reserves were prepared by our reservoir engineers and audited by CG&A, independent third party petroleum consultants. These reserve estimates have been prepared in compliance with the rules of the SEC. We emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates are expected to change as future information becomes available.

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Mid-Con Energy Partners, LP and subsidiaries

The increase in quantities of proved reserves from December 31, 2018, to December 31, 2019, was due in part to net upward revisions of 2,136 MBoe from certain recent results and development modifications, offset in part by commodity price decreases of 1,700 MBoe which decreased the economic lives of certain producing properties. The net upward revision is primarily the result of restoring production (reactivation of wells) from the acquired Oklahoma waterflood properties. During 2019, the acquisition of the Oklahoma waterflood properties resulted in a positive revision of 5,541 MBoe, and the divestiture of the Texas core area resulted in a decrease in proved reserves of 3,880 MBoe.

The decrease in quantities of proved reserves from December 31, 2019, to December 31, 2020, was due largely to commodity price decreases of 5,170 MBoe which shortened the economic lives of certain producing properties. In addition, net downward revisions of 2,081 MBoe from certain recent developments contributed to the overall decrease in proved reserves. The net downward revision is primarily the result of production declines resulting from large scale shut-ins and operational changes that occurred across the assets in early 2020 due to the historic pricing collapse.

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Unaudited)

The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, production, plugging and abandonment costs, discounted at the rate prescribed by the SEC. The standardized measure of discounted future net cash flow does not purport to be, nor should it be interpreted to represent, the fair market value of our proved oil and natural gas reserves. The following assumptions have been made:

The standardized measure of discounted future net cash flow relating to estimated proved oil and natural gas reserves is presented below for the periods indicated:

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Mid-Con Energy Partners, LP and subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

December 31, 2020 and 2019

The prices utilized in calculating our total proved reserves were $39.57 and $55.69 per Bbl of oil and $2.14 and $2.58 per Mcf of natural gas for December 31, 2020 and 2019, respectively. These prices were adjusted by lease for quality, transportation fees, location differentials, marketing bonuses or deductions or other factors affecting the price received at the wellhead. Average adjusted prices used were $36.95 and $52.90 per Bbl of oil and $1.65 and $1.68 per Mcf of natural gas for December 31, 2020 and 2019, respectively. Adjusted natural gas price includes the sale of associated NGLs. During the years ended December 31, 2020 and 2019, we did not extract 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. Therefore, we do not report NGLs in our production or proved reserves. All wellhead prices are held flat over the life of the properties for all reserve categories.

Changes in the standardized measure of discounted future net cash flow relating to proved oil and natural gas reserves is presented below for the periods indicated:

35

Exhibit 99.2

UNAUDITED PRO FORMA CONSOLIDATED COMBINED FINANCIAL STATEMENTS

The following unaudited pro forma consolidated combined financial statements present the historical consolidated financial statements of Contango Oil & Gas Company and Subsidiaries (“Contango”) and the historical consolidated financial statements of Michael Merger Sub LLC (successor to Mid-Con Energy Partners, LP) and Subsidiaries (“Mid-Con”), adjusted to give effect to the following transactions (collectively, the “Transactions”):

The unaudited pro forma consolidated combined statement of operations for the year ended December 31, 2020 combines the historical consolidated statements of operations of Contango and the historical consolidated statements of operations of Mid-Con, giving effect to the Transactions as if they had been consummated on January 1, 2020, the beginning of the earliest period presented. The unaudited pro forma consolidated combined balance sheet combines the historical consolidated balance sheet of Contango and the historical consolidated balance sheet of Mid-Con as of December 31, 2020, giving effect to the Transactions as if they had been consummated on December 31, 2020. The historical consolidated financial statements have been adjusted in the unaudited pro forma consolidated combined financial statements to give pro forma effect to events that are: (1) directly attributable to the Transactions; (2) factually supportable; and (3) with respect to the statement of operations, expected to have a continuing impact on Contango’s results following the completion of the Transactions.

The unaudited pro forma consolidated combined financial statements have been developed from and should be read in conjunction with: