mcep-10q_20200630.htm

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 ☒

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.

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.


	June 30, 2020			December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	987		$	255
Accounts receivable		4,026			6,853
Derivative financial instruments		8,924			—
Prepaid expenses		261			87
Assets held for sale		—			365
Total current assets		14,198			7,560
Property and equipment
Oil and natural gas properties, successful efforts method
Proved properties		264,755			261,375
Unproved properties		4,290			3,125
Other property and equipment		1,060			1,262
Accumulated depletion, depreciation, amortization and impairment		(96,505	)		(72,303	)
Total property and equipment, net		173,600			193,459
Derivative financial instruments		3,320			730
Other assets		1,932			1,020
Total assets	$	193,050		$	202,769

LIABILITIES, CONVERTIBLE PREFERRED UNITS AND EQUITY
Current liabilities
Accounts payable
Trade	$	1,018		$	320
Related parties		2,029			6,902
Derivative financial instruments		—			1,944
Accrued liabilities		2,599			795
Other current liabilities		446			430
Current debt		73,250			—
Total current liabilities		79,342			10,391
Long-term debt		—			68,000
Other long-term liabilities		230			457
Asset retirement obligations		31,734			30,265
Commitments and contingencies
Class A convertible preferred units - 0 and 11,627,906 issued and outstanding, respectively		—			22,964
Class B convertible preferred units - 0 and 9,803,921 issued and outstanding, respectively		—			14,829
Equity, per accompanying statements
General partner		—			(793	)
Limited partners - 14,311,522 and 1,541,215 units issued and outstanding, respectively		81,744			56,656
Total equity		81,744			55,863
Total liabilities, convertible preferred units and equity	$	193,050		$	202,769

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020			2019			2020			2019
Revenues
Oil sales	$	5,639		$	16,792		$	18,621		$	31,386
Natural gas sales		81			397			364			647
Other operating revenues		83			340			321			712
(Loss) gain on derivatives, net		(4,511	)		3,396			20,441			(8,802	)
Total revenues		1,292			20,925			39,747			23,943
Operating costs and expenses
Lease operating expenses		5,378			7,587			13,516			14,417
Production and ad valorem taxes		178			1,469			1,248			2,751
Other operating expenses		292			417			876			890
Impairment of proved oil and natural gas properties		1,215			204			19,547			204
Depreciation, depletion and amortization		1,819			2,369			4,655			5,467
Accretion of discount on asset retirement obligations		439			417			838			745
General and administrative		2,728			2,348			5,780			5,010
Total operating costs and expenses		12,049			14,811			46,460			29,484
Gain on sales of oil and natural gas properties, net		—			223			—			9,692
(Loss) income from operations		(10,757	)		6,337			(6,713	)		4,151
Other (expense) income
Interest income		—			1			1			9
Interest expense		(1,094	)		(1,229	)		(2,368	)		(2,844	)
Other (expense) income		(59	)		44			(47	)		49
Loss on settlements of asset retirement obligations		(15	)		(56	)		(15	)		(56	)
Total other expense		(1,168	)		(1,240	)		(2,429	)		(2,842	)
Net (loss) income		(11,925	)		5,097			(9,142	)		1,309
Less: Distributions to preferred unitholders		—			1,157			1,172			2,306
Less: General partner's interest in net (loss) income		(31	)		60			—			15
Limited partners' interest in net (loss) income	$	(11,894	)	$	3,880		$	(10,314	)	$	(1,012	)
Limited partners' interest in net (loss) income per unit
Basic	$	(2.29	)	$	2.53		$	(3.06	)	$	(0.66	)
Diluted	$	(2.29	)	$	1.47		$	(3.06	)	$	(0.66	)

Weighted average limited partner units outstanding
Limited partner units (basic)		5,202			1,539			3,376			1,535
Limited partner units (diluted)		5,202			2,659			3,376			1,535

	Six Months Ended June 30,
	2020			2019
Cash flows from operating activities
Net (loss) income	$	(9,142	)	$	1,309
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization		4,655			5,467
Debt issuance costs amortization		328			356
Accretion of discount on asset retirement obligations		838			745
Impairment of proved oil and natural gas properties		19,547			204
Loss on settlements of asset retirement obligations		15			56
Cash paid for settlements of asset retirement obligations		(21	)		(72	)
Mark to market on derivatives
(Gain) loss on derivatives, net		(20,441	)		8,802
Cash settlements received (paid) for matured derivatives, net		6,984			(586	)
Gain on sales of oil and natural gas properties		—			(9,692	)
Non-cash equity-based compensation		271			456
Changes in operating assets and liabilities
Accounts receivable		2,827			(2,441	)
Prepaid expenses and other assets		(1,103	)		(254	)
Accounts payable - trade and accrued liabilities		319			434
Accounts payable - related parties		(3,143	)		(293	)
Net cash provided by operating activities		1,934			4,491
Cash flows from investing activities
Acquisitions of oil and natural gas properties		(111	)		(3,262	)
Additions to oil and natural gas properties		(5,526	)		(5,085	)
Additions to other property and equipment		(69	)		—
Proceeds from sales of oil and natural gas properties		—			32,514
Proceeds from sale of other assets		365			—
Net cash (used in) provided by investing activities		(5,341	)		24,167
Cash flows from financing activities
Proceeds from line of credit		6,000			7,000
Payments on line of credit		(750	)		(34,000	)
Debt issuance costs		(311	)		—
Distributions to Class A convertible preferred units		(500	)		(1,000	)
Distributions to Class B convertible preferred units		(300	)		(600	)
Net cash provided by (used in) financing activities		4,139			(28,600	)
Net increase in cash and cash equivalents		732			58
Beginning cash and cash equivalents		255			467
Ending cash and cash equivalents	$	987		$	525

	General			Limited Partners					Total
	Partner			Units		Amount			Equity

Balance, December 31, 2019	$	(793	)		1,541	$	56,656		$	55,863
Equity-based compensation		—			17		78			78
Distributions to Class A convertible preferred units		—			—		(500	)		(500	)
Distributions to Class B convertible preferred units		—			—		(300	)		(300	)
Accretion of beneficial conversion feature of Class A convertible preferred units		—			—		(323	)		(323	)
Accretion of beneficial conversion feature of Class B convertible preferred units					—		(49	)		(49	)
Net income		31			—		2,752			2,783
Balance, March 31, 2020		(762	)		1,558		58,314			57,552
Equity-based compensation		—			11		193			193
Distributions to Class A convertible preferred units		—			—		(333	)		(333	)
Distributions to Class B convertible preferred units		—			—		(200	)		(200	)
Accretion of beneficial conversion feature of Class A convertible preferred units		—			—		(219	)		(219	)
Accretion of beneficial conversion feature of Class B convertible preferred units		—			—		(32	)		(32	)
Conversion of Preferred Units Class A and Class B to common units		—			12,725		36,708			36,708
Conversion of General Partner to common units		762			18		(762	)		—
Net income		—			—		(11,925	)		(11,925	)
Balance, June 30, 2020	$	—			14,312	$	81,744		$	81,744

	General			Limited Partners					Total
	Partner			Units		Amount			Equity

Balance, December 31, 2018	$	(786	)		1,522	$	61,195		$	60,409
Equity-based compensation		—			19		334			334
Distributions to Class A convertible preferred units		—			—		(500	)		(500	)
Distributions to Class B convertible preferred units		—			—		(300	)		(300	)
Accretion of beneficial conversion feature of Class A convertible preferred units		—			—		(301	)		(301	)
Accretion of beneficial conversion feature of Class B convertible preferred units		—			—		(48	)		(48	)
Net loss		(45	)		—		(3,743	)		(3,788	)
Balance, March 31, 2019		(831	)		1,541		56,637			55,806
Equity-based compensation		—					122			122
Distributions to Class A convertible preferred units		—			—		(500	)		(500	)
Distributions to Class B convertible preferred units		—			—		(300	)		(300	)
Accretion of beneficial conversion feature of Class A convertible preferred units		—			—		(309	)		(309	)
Accretion of beneficial conversion feature of Class B convertible preferred units		—			—		(48	)		(48	)
Net income		60			—		5,037			5,097
Balance, June 30, 2019	$	(771	)		1,541	$	60,639		$	59,868

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.

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, Inc. (“Contango Resources”) effective as of July 1, 2020. Under the MSA, Contango Resources will provide 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, which is expected to generate pro forma annual cash savings of approximately $6.5 million compared with 2019.

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 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.

These unaudited condensed consolidated 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 revolving credit facility 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. See Note 7 in this section for additional information on Amendment 15 to the credit agreement. At June 30, 2020, the Partnership was in compliance with the financial covenants required by the credit agreement. Our ability to continue as a going concern is dependent on the re-negotiation of our revolving credit agreement that matures May 1, 2021, or other measures such as the sale of assets or raising additional capital. There can be 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.

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

On April 9, 2020, the Partnership effected a 1-for-20 reverse common unit split. For presentation purposes, the unaudited condensed 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.

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.

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 under 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 six months ended June 30, 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:

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. No gain or loss on the transaction was recorded during the six months ended June 30, 2020.

We have a long-term incentive program (the “Long-Term Incentive Program”) for employees, officers, consultants and directors of our general partner and its former affiliates, including Mid-Con Energy Operating, LLC (“Mid-Con Energy Operating”) and ME3 Oilfield Service, LLC (“ME3 Oilfield Service”), who performed 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 June 30, 2020:

We recognized $0.2 million and $0.3 million of total equity-based compensation expense for the three and six months ended June 30, 2020, respectively. We recognized $0.1 million and $0.4 million of total equity-based compensation expense for the three and six months ended June 30, 2019. These costs are reported as a component of general and administrative expenses (“G&A”) in our unaudited condensed consolidated statements of operations.

During the six months ended June 30, 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 six months ended June 30, 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 units vest over a period of two or three years. During the six months ended June 30, 2020, we did not grant any equity-settled phantom units. During the six months ended June 30, 2019, we granted 25,500 equity-settled phantom units with a two-year vesting period and 3,150 equity-settled phantom units with a three-year vesting period, as adjusted for the reverse split.

A summary of our equity-settled phantom unit awards for the six months ended June 30, 2020, is presented below:

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 June 30, 2020, our commodity derivative contracts were in a net asset position with a fair value of $12.2 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 June 30, 2020, all of our counterparties have performed pursuant to the terms of their commodity derivative contracts.

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 June 30, 2020, and December 31, 2019:

(in thousands)	Gross Amounts Recognized			Gross Amounts Offset in the Unaudited Condensed Consolidated Balance Sheets			Net Amounts Presented in the Unaudited Condensed Consolidated Balance Sheets
June 30, 2020
Assets
Derivative financial instruments - current asset	$	9,032		$	(108	)	$	8,924
Derivative financial instruments - long-term asset		3,497			(177	)	$	3,320
Total		12,529			(285	)		12,244

Liabilities
Derivative financial instruments - current liability		(108	)		108			—
Derivative financial instruments - long-term liability		(177	)		177			—
Total		(285	)		285			—
Net asset	$	12,244		$	—		$	12,244

(in thousands)	Gross Amounts Recognized			Gross Amounts Offset in the Unaudited Condensed Consolidated Balance Sheets			Net Amounts Presented in the Unaudited Condensed Consolidated Balance Sheets
December 31, 2019
Assets
Derivative financial instruments - long-term asset	$	1,635		$	(905	)	$	730
Total		1,635			(905	)		730

Liabilities
Derivative financial instruments - current liability		(1,944	)		—			(1,944	)
Derivative financial instruments - long-term liability		(905	)		905			—
Total		(2,849	)		905			(1,944	)
Net liability	$	(1,214	)	$	—		$	(1,214	)

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

At June 30, 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 June 30, 2020, we had the following oil derivatives net positions:

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 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 and six months ended June 30, 2020, and for the year ended December 31, 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 material changes in valuation approach or related inputs for the three and six months ended June 30, 2020, and for the year ended December 31, 2019.

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 June 30, 2020, and December 31, 2019:

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.

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.

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.

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. Due to the unprecedented decline in oil prices, we recorded impairment expense of $1.2 million and $19.5 million for the three and six months ended June 30, 2020, respectively. We recorded impairment expense of $0.2 million for the three and six months ended June 30, 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 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 June 30, 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:

We had outstanding borrowings under our revolving credit facility of $73.3 million and $68.0 million at June 30, 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. 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. At June 30, 2020, we were in compliance with the financial covenants required by our 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 June 30, 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 June 30, 2020, the average effective rate was 5.49%. Any 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 with 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:

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 borrowing base deficiency; 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:

As of June 30, 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. 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.

The Partnership entered into a master services agreement with Contango Resources on June 4, 2020, as part of the Recapitalization Transaction. Under the agreement, Contango Resources will provide 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, effective July 1, 2020.

As part of the Restructuring 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.

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 June 30, 2020, no liability has been recorded associated with the Change in Control Severance Plan. For a more detailed description of the Change in Control Severance Plan, please refer to our Current Report on Form 8-K filed with the SEC on July 26, 2019.

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.

At June 30, 2020, and December 31, 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 June 30, 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.

The Partnership had previously 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.

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 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%.

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. The total of $0.8 million in accrued distributions for the first quarter 2020 were paid in kind and, along with the second quarter 2020 pro-rata distribution, included in the calculation of the conversion price to common 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 $0.2 million and $0.5 million for the three and six months ended June 30, 2020, and $0.3 million and $0.6 million for the three and six months ended June 30, 2019. The registration statement registering resales of common units issued upon conversion of the Class A Preferred Units was declared effective by the SEC on June 14, 2017.

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 Transaction, the Partnership did not accrue any distributions as of June 30, 2020. The following table summarizes cash distributions paid on our Class A Preferred Units during the six months ended June 30, 2020:

The following table summarizes cash distributions paid on our Class A Preferred Units during the six months ended June 30, 2019:

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 $0.03 million and $0.1 million for the three and six months ended June 30, 2020, and $0.1 million for the three and six months ended June 30, 2019. The registration statement registering resales of common units 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 Transaction, the Partnership did not accrue any distributions as of June 30, 2020. The following table summarizes cash distributions paid on our Class B Preferred Units during the six months ended June 30, 2020:

The following table summarizes cash distributions paid on our Class B Preferred Units during the six months ended June 30, 2019:

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.

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.

As of June 30, 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 unaudited condensed consolidated statements of operations.

The Partnership entered into a master services agreement with Contango Resources on June 4, 2020, as part of the Recapitalization Transaction. Under the agreement, 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, effective July 1, 2020.

As of June 30, 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 unaudited condensed 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 MSA with Contango Resources, Contango Resources will not charge overhead associated with operating our properties.

As of June 30, 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 unaudited condensed consolidated statements of operations or were capitalized as part of oil and natural gas properties in our unaudited condensed consolidated balance sheets. Mid-Con Energy Operating resigned as operator under these service agreements, and Contango Resources became operator, on July 1, 2020.

During the six months ended June 30, 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 June 30, 2020, we had a payable to Contango Resources of $1.3 million for accrued joint interest billings. At June 30, 2020, we had a net payable to our former affiliate, Mid-Con Energy Operating, of $0.7 million, comprised of a joint interest billing payable of $1.1 million and a payable for operating services and other miscellaneous items of $0.2 million, offset by an oil and natural gas revenue receivable of $0.6 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 million. These amounts were included in accounts payable-related parties in our unaudited condensed consolidated balance sheets.

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. We had no significant natural gas imbalances at June 30, 2020 and 2019.

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.

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

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.

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.

⁽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:

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.

On July 6, 2020, the Partnership announced the resignation of Mr. Chad B. Roller, President and Chief Operating Officer, and Mr. Charles L. McLawhorn, III, Vice President, General Counsel and Corporate Secretary to pursue opportunities with Contango Oil & Gas Company. Messrs. Roller and McLawhorn will continue to provide services to the Partnership pursuant to that Management Services Agreement.

On August 6, 2020, the Partnership announced the resignation of Mr. Philip R. Houchin as Chief Financial Officer. Effective July 31, 2020, Ms. Sherry L. Morgan was appointed as Chief Executive Officer, Mr. Greg Westfall was appointed as Chief Operating Officer and Ms. Jodie L. DiGiacomo was appointed as Chief Accounting Officer.

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.

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.

The Partnership closed the Recapitalization Transactions on June 4, 2020, resulting in significant changes to our capital structure and governance, strengthened our balance sheet, created alignment across all unitholders, reduced costs, streamlined operations and created 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 per Preferred Unit. In addition, ownership of the Partnership’s general partner was transferred to the Partnership, resulting in strengthened corporate governance, and a new Board of Directors was elected by the written consent of the holders of a majority of the outstanding common units.

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.

Our financial and operational performance for the three months ended June 30, 2020, included the following:

Our financial and operational performance for the six months ended June 30, 2020, included the following:

The energy landscape changed dramatically in 2020 with simultaneous demand and supply shocks that drove the industry into a severe downturn. The demand shock was triggered by COVID-19, which was declared a global pandemic and caused unprecedented social and economic consequences. Mitigation efforts to stop the spread of this contagious disease included stay-at-home orders and business closures that caused sharp contractions in economic activity worldwide. The supply shock was triggered by disagreements between OPEC and Russia, beginning in early March 2020, which resulted in significant supply coming onto the market and an oil price war. These dual demand and supply shocks caused oil prices to collapse as we exited the first quarter.

As we entered the second quarter, predictions of COVID-19 driven global oil demand losses intensified, with forecasts of unprecedented demand declines. Based on these forecasts, OPEC plus nations held an emergency meeting, and in April they announced a coordinated production cut that was unprecedented in both its magnitude and duration. The OPEC plus countries agreed to cut production by 9.7 MBbls in May and June, 9.6 MBbls in July, and 7.7 MBbls from August to December. From January 2021 to April 2022, they agreed to cut production by 5.8 MBbls. Additionally, non-OPEC plus countries, including the U.S., Canada, Brazil and other G-20 countries, announced organic reductions to production through the release of drilling rigs, frac crews, normal field decline and curtailments. Despite these planned production decreases, the supply cuts were not timely enough to overcome significant demand decline. Futures prices for April West Texas Intermediate crude (“WTI”) closed under $20 a barrel for the first time since 2001, followed by May WTI settling below zero on the day before futures contracts expiry, as holders of May futures contracts struggled to exit positions and avoid taking physical delivery. As storage constraints approached, spot prices in April for certain North American landlocked grades of crude oil were in the single digits or even negative for particularly remote or low-grade crudes, while waterborne priced crudes such as Brent crude sold at a relative advantage.

Since the start of the severe downturn, we have closely monitored the market and taken prudent actions in response to this situation. Beginning in March 2020, the Partnership started identifying and shutting in wells that are not economically viable, at prevailing prices. We shut-in approximately 250 uneconomic wells during March 2020, and an additional 150 uneconomical wells in April 2020. As of August 10, 2020, we have returned 30 net wells to production. We continue to monitor pricing and expenses to determine when to return these wells to production. In addition to shut-in activities, the Partnership has continued to identify and execute strategies for reducing expenditures and lowering its leverage. As discussed above, in June 2020, the Partnership negotiated and executed the Recapitalization Transaction which is expected to generate pro forma annual cash savings of approximately $6.5 million compared to 2019.

Our workforce and operations have also adjusted to mitigate the impacts of the COVID-19 global pandemic. A large portion of our office staff have been successfully working remotely, with offices designing and executing a flexible, phased reentry, following national, state and local guidelines. Workforce health and safety remains the overriding driver for our actions and we have demonstrated our ability to adapt to local conditions as warranted. These mitigation measures have thus far been effective at protecting employees’ health and reducing business operation disruptions.

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.

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.

The Partnership announced the resignations of Mr. Charles R. 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 5, 2020. In connection with the Recapitalization Transactions, the Participation and Restrictive Covenant Agreements with Mr. Charles R. 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.

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 $35.13 and $53.84 for the six months ended June 30, 2020 and 2019, respectively.

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.

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:

The tables presented in this section summarize certain results of operations and period-to-period comparisons for the three and six months ended June 30, 2020. 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.

	Three Months Ended June 30,								%	Six Months Ended June 30,								%
	2020		2019			Change			Change	2020		2019			Change			Change
Production volumes, net
Oil (MBbls)		234		291			(57	)	(20%)		530		583			(53	)	(9%)
Natural gas (MMcf)		114		184			(70	)	(38%)		270		305			(35	)	(11%)
Total (MBoe)		253		322			(69	)	(21%)		575		634			(59	)	(9%)
Average daily net production (Boe/d)		2,780		3,538			(758	)	(21%)		3,159		3,503			(344	)	(10%)

Average sales prices
Oil (per Bbl)
Sales price	$	24.10	$	57.70		$	(33.60	)	(58%)	$	35.13	$	53.84		$	(18.71	)	(35%)
Effect of net settlements on matured derivative instruments	$	22.23	$	(2.50	)	$	24.73		989%	$	13.18	$	(1.01	)	$	14.19		1405%
Realized oil price after derivatives	$	46.33	$	55.20		$	(8.87	)	(16%)	$	48.31	$	52.83		$	(4.52	)	(9%)
Natural gas (per Mcf)	$	0.71	$	2.16		$	(1.45	)	(67%)	$	1.35	$	2.12		$	(0.77	)	(36%)

Average unit costs per Boe
Lease operating expenses	$	21.26	$	23.56		$	(2.30	)	(10%)	$	23.51	$	22.74		$	0.77		3%
Production and ad valorem taxes	$	0.70	$	4.56		$	(3.86	)	(85%)	$	2.17	$	4.34		$	(2.17	)	(50%)
Depreciation, depletion and amortization	$	7.19	$	7.36		$	(0.17	)	(2%)	$	8.10	$	8.62		$	(0.52	)	(6%)
General and administrative expenses	$	10.78	$	7.29		$	3.49		48%	$	10.05	$	7.90		$	2.15		27%

	Three Months Ended June 30,							%	Six Months Ended June 30,							%
(in thousands)	2020		2019		Change			Change	2020		2019		Change			Change
Oil sales	$	5,639	$	16,792	$	(11,153	)	(66%)	$	18,621	$	31,386	$	(12,765	)	(41%)
Natural gas sales		81		397		(316	)	(80%)		364		647		(283	)	(44%)
Total oil and natural gas sales	$	5,720	$	17,189	$	(11,469	)	(67%)	$	18,985	$	32,033	$	(13,048	)	(41%)

	Three Months Ended June 30, 2020 and 2019								Six Months Ended June 30, 2020 and 2019
(in thousands, except prices)	Change in prices			Production Volumes		Total Net Dollar Effect of Change			Change in prices			Production Volumes		Total Net Dollar Effect of Change
Effects of changes in sales price
Oil (Bbls)	$	(33.60	)		234	$	(7,863	)	$	(18.71	)		530	$	(9,911	)
Natural gas (Mcf)	$	(1.45	)		114		(165	)	$	(0.77	)		270		(206	)
Total oil and natural gas sales due to change in price						$	(8,028	)						$	(10,117	)

	Change in Production Volumes			Prior Period Average Prices		Total Net Dollar Effect of Change			Change in Production Volumes			Prior Period Average Prices		Total Net Dollar Effect of Change
Effects of changes in production volumes
Oil (Bbls)		(57	)	$	57.70	$	(3,290	)		(53	)	$	53.84	$	(2,854	)
Natural gas (Mcf)		(70	)	$	2.16		(151	)		(35	)	$	2.12		(77	)
Total oil and natural gas sales due to change in production volumes							(3,441	)							(2,931	)
Total change in oil and natural gas sales						$	(11,469	)						$	(13,048	)

	Three Months Ended June 30,									%	Six Months Ended June 30,							%
(in thousands)	2020			2019			Change			Change	2020		2019			Change		Change
Cash settlements on matured derivatives, net	$	5,201		$	(729	)	$	5,930		813%	$	6,984	$	(586	)	$	7,570	1292%
Non-cash change in fair value of derivatives		(9,712	)		4,125			(13,837	)	(335%)		13,457		(8,216	)		21,673	264%
Total gain (loss) on derivatives, net	$	(4,511	)	$	3,396		$	(7,907	)	(233%)	$	20,441	$	(8,802	)	$	29,243	332%

See Note 4 and Note 5 to the unaudited condensed consolidated financial statements for additional information regarding our commodity derivative contracts.

	Three Months Ended June 30,							%	Six Months Ended June 30,							%
(in thousands)	2020		2019		Change			Change	2020		2019		Change			Change
Lease operating expenses	$	5,368	$	7,327	$	(1,959	)	(27%)	$	13,357	$	13,896	$	(539	)	(4%)
Workover expenses		10		260		(250	)	(96%)		159		521		(362	)	(69%)
Total lease operating expenses	$	5,378	$	7,587	$	(2,209	)	(29%)	$	13,516	$	14,417	$	(901	)	(6%)

The change in LOE in total and per Boe for the three months ended June 30, 2020, compared to the three months ended June 30, 2019, was primarily due to:

The change in LOE in total and per Boe for the six months ended June 30, 2020, compared to the six months ended June 30, 2019, was primarily due to:

	Three Months Ended June 30,								%	Six Months Ended June 30,								%
(in thousands)	2020			2019		Change			Change	2020			2019		Change			Change
Production taxes	$	405		$	1,193	$	(788	)	(66%)	$	1,290		$	2,109	$	(819	)	(39%)
Ad valorem taxes		(227	)		276		(503	)	(182%)		(42	)		642		(684	)	(107%)
Total production and ad valorem taxes	$	178		$	1,469	$	(1,291	)	(88%)	$	1,248		$	2,751	$	(1,503	)	(55%)

The change in production and ad valorem taxes in total and per Boe was primarily due to:

	Three Months Ended June 30,							%	Six Months Ended June 30,							%
(in thousands)	2020		2019		Change			Change	2020		2019		Change			Change
Depreciation, depletion and amortization	$	1,819	$	2,369	$	(550	)	(23%)	$	4,655	$	5,467	$	(812	)	(15%)
Impairment		1,215		204		1,011		496%		19,547		204		19,343		9482%
Total DD&A and impairment expense	$	3,034	$	2,573	$	461		18%	$	24,202	$	5,671	$	18,531		327%

The change in DD&A was primarily due to the net impact of the Texas divestitures and the properties acquired in Oklahoma and Wyoming.

Impairment of proved oil and natural gas properties for the three and six months ended June 30, 2020, was primarily due to an unprecedented decline in oil prices. Impairment of proved oil and natural gas properties for the three and six months ended June 30, 2019, was primarily due to wellbore issues on a certain Texas project.

	Three Months Ended June 30,						%	Six Months Ended June 30,							%
(in thousands)	2020		2019		Change		Change	2020		2019		Change			Change
General and administrative expenses	$	2,534	$	2,226	$	308	14%	$	5,509	$	4,554	$	955		21%
Non-cash compensation		194		122		72	59%		271		456		(185	)	(41%)
Total general and administrative expenses	$	2,728	$	2,348	$	380	16%	$	5,780	$	5,010	$	770		15%

The change in G&A in total and per Boe for the three months ended June 30, 2020, compared to the three months ended June 30, 2019, was primarily due to:

The change in G&A in total and per Boe for the six months ended June 30, 2020, compared to the six months ended June 30, 2019, was primarily due to:

During the three and six months ended June 30, 2020, there was no gain on sales of oil and natural gas properties, net. During the three and six months ended June 30, 2019, there was a gain on sales of oil and natural gas properties, net of $0.2 million and $9.7 million, respectively, which was primarily due to the divestiture of substantially all of our Texas properties as part of the Strategic Transaction.

The change in interest expense was primarily due to both lower average outstanding borrowings and a decreased average effective interest rate.

Our ability to finance our operations, fund our capital expenditures and acquisitions, meet or refinance our debt obligations and meet our collateral requirements will depend on our future cash flows, our ability to borrow and our ability to raise equity or debt capital. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, oil and natural gas prices (including regional price differentials), operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. Historically, our primary use of cash has been for debt reduction, capital spending (including acquisitions) and distributions.

Our liquidity position at August 10, 2020, consisted of approximately $1.2 million of available cash. We currently have no availability under our revolving credit facility. At March 31, 2020, the Partnership was not in compliance with the leverage ratio covenant of our credit agreement. Amendment 15 to the credit agreement was effective as of June 1, 2020. Amendment 15 to the credit agreement, 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; 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:

At June 30, 2020, we were in compliance with the financial covenants required by the credit agreement. Our ability to continue as a going concern is dependent on the re-negotiation of our revolving credit facility that matures May 1, 2021, or other measures such as the sale of assets or raising additional capital. These factors raise substantial doubt over the Partnership’s ability to continue as a going concern, 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 financial statements.

Based on our cash balance and forecasted cash flows from operating activities we expect to be able to meet our debt service requirements and fund our other commitments and obligations in the near term. Although we currently expect our sources of cash to be sufficient to meet our near-term liquidity needs, there can be no assurance that our liquidity requirements will continue to be satisfied. Our lenders have the discretion to further decrease the borrowing base of our revolving credit facility. Any further reduction in the borrowing base under the revolving credit facility would negatively impact our ability to meet our debt service requirements and fund our other commitments and obligations. Due to the volatility of commodity prices, we may not be able to obtain funding in the equity or debt capital markets on terms we find acceptable. The cost of obtaining debt capital from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, and reduced and, in some cases, ceased to provide any new funding.

At March 31, 2020, we were not in compliance with our leverage calculation ratio. Amendment 15 to the credit agreement was effective as of June 1, 2020. Amendment 15 to the credit agreement, 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 borrowing base deficiency; 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:

At June 30, 2020, the Partnership was in compliance with the financial covenants required by the credit agreement. At August 10, 2020, the outstanding balances of our revolving credit facility and standby letter of credit were $71.8 million and $1.0 million, respectively. See Note 7 to the unaudited condensed consolidated financial statements for additional information on Amendment 15 to the credit agreement.

Our business requires continual investment to upgrade or enhance existing operations in order to increase and maintain our production and the size of our asset base. The primary purpose of growth capital is to acquire and develop producing assets that allow us to increase our production and asset base. To date, we have funded acquisition transactions through a combination of cash, available borrowing capacity under our revolving credit facility and through the issuance of equity, including the Preferred Units.

Due to the current oil and natural gas environment, Amendment 15 to our credit agreement restricted our capital spending for the remainder of 2020.

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. The commodity derivative contracts that we have entered into generally have the effect of providing us with a fixed price or a floor for a portion of our expected future oil production over a fixed period of time. 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. At June 30, 2020, we had commodity derivative contracts covering 69% and 51%, respectively, of our estimated 2020 and 2021 average daily production (estimate calculated based on June 2020 net daily oil production volumes). See Note 4 to the unaudited condensed consolidated financial statements for additional information regarding our commodity derivative contracts.

The following table summarizes the net change in cash and cash equivalents for the six months ended June 30, 2020 and 2019:

	Six Months Ended June 30,									%
(in thousands)	2020			2019			Change			Change
Operating activities
Net used in operating activities	$	1,934		$	4,491		$	(2,557	)	(57%)
Investing activities
Acquisitions of oil and natural gas properties		(111	)		(3,262	)		3,151		97%
Additions to oil and natural gas properties		(5,526	)		(5,085	)		(441	)	(9%)
Additions to other property and equipment		(69	)		—			(69	)	(100%)
Proceeds from sales of oil and natural gas properties		—			32,514			(32,514	)	(100%)
Proceeds from sale of other assets		365			—			365		100%
Net cash (used in) provided by investing activities		(5,341	)		24,167			(29,508	)	(122%)
Financing activities
Proceeds from line of credit		6,000			7,000			(1,000	)	(14%)
Payments on line of credit		(750	)		(34,000	)		33,250		98%
Distributions to preferred unitholders		(800	)		(1,600	)		800		50%
Debt issuance costs		(311	)		—			(311	)	(100%)
Net cash provided by (used in) financing activities		4,139			(28,600	)		32,739		114%
Change in cash and cash equivalents	$	732		$	58		$	674		1162%

Operating activities. The change in operating cash flows for the periods compared was primarily attributable to:

See Results of Operations in Item 2 for further discussion of the items listed above.

Investing and financing activities. The change in investing and financing cash flows for the periods compared was primarily attributable to net proceeds from the Strategic Transaction in March 2019 and the resulting payment on the revolving credit facility. See Note 2 to the unaudited condensed consolidated financial statements for further discussion of the Strategic Transaction.

See Note 13 to the unaudited condensed consolidated financial statements for additional information regarding recently issued accounting pronouncements.

As a smaller reporting company, we are not required to provide the information otherwise required by this Item.

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our chief executive officer (principal executive officer) and chief accounting officer (principal financial officer), the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2020. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this Form 10-Q.

There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the quarterly period ended June 30, 2020, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

In the course of our ongoing preparations for making management’s report on internal control over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002, from time to time we have identified areas in need of improvement and have taken remedial actions to strengthen the affected controls as appropriate. We make these and other changes to enhance the effectiveness of our internal controls over financial reporting, which do not have a material effect on our overall internal control over financial reporting.

Our significant business risks are described in Part I, Item 1A in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019, to which reference is made herein. Other than as set forth below, there have been no material changes to the risk factors disclosed in such Annual Report.

Our business has been, and will continue to be, affected by the coronavirus (COVID-19) pandemic.

The COVID-19 outbreak and the measures put in place to address it have negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. Public health officials have recommended or mandated certain precautions to mitigate the spread of COVID-19, including limiting non-essential gatherings of people, ceasing all non-essential travel and issuing “social or physical distancing” guidelines, “shelter-in-place” orders and mandatory closures or reductions in capacity for non-essential businesses. The full impact of the COVID-19 pandemic remains uncertain and will depend on the severity, location and duration of the effects and spread of the disease, the effectiveness and duration of actions taken by authorities to contain the virus or treat its effect, and how quickly and to what extent economic conditions improve. According to the National Bureau of Economic Research, as a result of the pandemic and its broad reach across the entire economy, the U.S. entered a recession in early 2020.

We have already been impacted by the COVID-19 pandemic. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, for additional information on how we have been impacted and the steps we have taken in response. Our business is likely to be further negatively impacted by the COVID-19 pandemic. These impacts could include but are not limited to:

Any of these factors, or other cascading effects of the COVID-19 pandemic that are not currently foreseeable, could materially increase our costs, negatively impact our revenues and damage our financial condition, results of operations, cash flows and liquidity position. The pandemic continues to progress and evolve, and the full extent and duration of any such impacts cannot be predicted at this time because of the sweeping impact of the COVID-19 pandemic on daily life around the world.

We have been negatively affected and are likely to continue to be negatively affected by the recent swift and sharp drop in commodity prices.

The oil and gas business is fundamentally a commodity business and prices for crude oil, bitumen, natural gas, and NGLs can fluctuate widely depending upon global events or conditions that affect supply and demand. Recently, there has been a precipitous decrease in demand for oil globally, largely caused by the dramatic decrease in travel and commerce resulting from the COVID-19 pandemic. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, for additional information on commodity prices and how we have been impacted. There is no assurance of when or if commodity prices will return to pre-COVID-19 levels. The speed and extent of any recovery remains uncertain and is subject to various risks, including the duration, impact and actions taken to stem the proliferation of the COVID-19 pandemic, the extent to which those nations party to the OPEC plus production agreement decide to increase production of crude oil, natural gas, and NGLs, and other risks described in this Quarterly Report on Form 10-Q or in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

Even after a recovery, our industry will continue to be exposed to the effects of changing commodity prices given the volatility in commodity price drivers and the worldwide political and economic environment generally, as well as continued uncertainty caused by armed hostilities in various oil-producing regions around the globe. Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas and NGLs. Many of the factors influencing these prices are beyond our control.

Lower crude oil, natural gas and NGL prices may have a material adverse effect on our revenues, operating income, cash flows and liquidity. As a result of the recent market downturn, we have entered into an amendment to our revolving credit facility which temporarily prohibits us from declaring a dividend on our common units. Lower prices may also limit the amount of reserves we can produce economically, thus adversely affecting our proved reserves, reserve replacement ratio and accelerating the reduction in our existing reserve levels as we continue production from upstream fields. Prolonged lower crude oil prices may affect certain decisions related to our operations, including decisions to reduce capital investments or decisions to shut-in production.

Significant reductions in crude oil, natural gas and NGLs prices could also require us to reduce our capital expenditures, impair the carrying value of our assets or discontinue the classification of certain assets as proved reserves. In the first six-

month period of 2020, we recognized several impairments, which are described in Note 5— Fair Value Disclosures. If the outlook for commodity prices remain low relative to their historic levels, and as we continue to optimize our investments and exercise capital flexibility, it is reasonably likely we will incur future impairments to long-lived assets. Although it is not reasonably practicable to quantify the impact of any future impairments or estimated change to our unit-of-production at this time, our results of operations could be adversely affected as a result.

Risks Related to the Business of the Partnership as a Result of the Recapitalization Transactions

As described in the notes to our unaudited condensed consolidated financial statements, there is substantial doubt about our ability to continue as a going concern and we are dependent on restructuring of our existing capital to fund our obligations and to continue in operation.

As a result of the sustained commodity price decline and our substantial debt burden, the Partnership believes that forecasted cash and available credit capacity may not be sufficient to meet commitments as they come due over the next twelve months. The Partnership will not be able to comply with the covenants unless we are able to successfully increase liquidity or deleverage. The unaudited condensed consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern. The Partnership's borrowings under the revolving credit facility come due in less than one year.

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. These factors raise substantial doubt over the Partnership’s ability to continue as a going concern, 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 balance sheet. If the Partnership were unable to refinance its indebtedness, the Partnership would need to engage financial and legal advisors to assist with analyzing various strategic alternatives to address our liquidity and capital structure, among other things. There can be no assurance the Partnership will be able to restructure our capital structure on terms acceptable to the Partnership and our creditors, or at all.

We recently competed the Recapitalization Transactions which resulted in the composition of our Board and management changing.

Upon consummation of the Recapitalization Transactions, the composition of the Board and management of our general partner was changed. The Board now consists of four directors, all of whom are new to the Partnership. Our new directors and management have different backgrounds, experiences and perspectives from those individuals who previously served on the board and as management and, thus, may have different views on the issues that will determine the future of the Partnership. As a result, the future strategy and plans of the Partnership may differ materially from those of the past.

Since the majority of our common units are owned by one significant unitholder, our other unitholders may not be able to influence control of our Partnership or decision making by our management.

One significant unitholder beneficially owns approximately 56% of our outstanding common units. The interests of this unitholder may not be, at all times, the same as that of our other unitholders. This significant unitholder will have the ability to significantly influence the outcome of most corporate actions requiring shareholder approval, including our merger with or into another company, the sale of all or substantially all of our assets and amendments to our articles of incorporation. This concentration of ownership may also have the effect of delaying, deferring or preventing a change of control of our company, which may be disadvantageous to minority unitholders.

Our Partnership Agreement continues to replace our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

Our Partnership Agreement was amended and restated in connection with the Recapitalization Transactions and continues to contain provisions that eliminate the fiduciary standards to which our general partner and its officers and directors would otherwise be held by state fiduciary law and replaces those duties with several different contractual standards. For example, our Partnership Agreement permits our general partner to make a number of decisions in its sole discretion, free of any duties to us and holders of our common units other than the implied contractual covenant of good faith and fair dealing. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us or our unitholders. In addition, our Partnership Agreement

grants broad rights of indemnification to our general partner and its officers and directors. By owning a common unit, a holder is treated as having consented to the provisions in our Partnership Agreement.

Our Partnership Agreement continues to restrict the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our Partnership Agreement was amended and restated in connection with the Recapitalization Transactions and continues to contain provisions that restrict the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement:

Beginning on July 1, 2020, we will rely primarily on a subsidiary of Contango to manage and operate our business. The individuals who Contango uses to manage us may also provide substantially similar services to the affiliates of Contango, and thus may not be solely focused on our business.

Beginning on July 1, 2020, we will rely primarily on Contango to manage us and operate our assets. Upon the consummation of the Recapitalization Transactions, we entered into a services agreement with Contango Resources effective on July 1, 2020, pursuant to which Contango Resources will provide management, administrative and operational services to us after the termination of a transition service agreement with Mid-Con Energy Operating.

Contango Resources will also continue to provide substantially similar services and personnel to the affiliates of Contango Resources and, as a result, may not have sufficient human, technical and other resources to provide those services at a level that it would be able to provide to us if it did not provide similar services to these other entities. Additionally, Contango may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to those of the affiliates of Contango or other affiliates of our general partner. There is no requirement that Contango Resources favor us over these other entities in providing its services. If the employees of Contango Resources do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

We may fail to realize all of the anticipated benefits of the Recapitalization Transactions or those benefits may take longer to realize than expected.

Our ability to realize the anticipated benefits of the Recapitalization Transactions will depend, to a large extent, on our ability to take action in a manner that facilitates growth opportunities, and achieves the projected stand-alone cost savings and revenue growth trends identified as part of the Recapitalization Transactions. It is expected that we will benefit from operational and general and administrative cost improvements. If we are not able to successfully achieve these objectives, the anticipated benefits of the Recapitalization Transactions may not be realized fully or at all or may take longer to realize than expected.

In addition, the recapitalization of a business is a complex, costly and time-consuming process. As a result, the general partner will be required to devote significant management attention and resources to our business practices and operations. This process may disrupt the business. The failure to realize the anticipated benefits of the transactions contemplated by the Recapitalization Transactions could cause an interruption of, or a loss of momentum in, our activities and could adversely affect our results of operations. The Recapitalization Transactions may also result in material unanticipated problems, expenses, liabilities, competitive responses, loss of customer and other business relationships and diversion of management attention.

Many of these factors are outside of our control, and any one of them could result in increased costs, decreased expected revenues and diversion of management time and energy, which could materially impact the business, financial condition and results of operations of the Partnership. In addition, even if our operations are restructured successfully, the full benefits of the Recapitalization Transactions may not be realized, including the cost savings, increased sales or growth opportunities that are anticipated. These benefits may not be achieved within the anticipated time frame, or at all. Further, additional unanticipated costs may be incurred in the Recapitalization Transactions. All of these factors could cause dilution to our earnings per share and negatively impact the price of our common units.

Completion of the Recapitalization Transactions may trigger change in control or other provisions in certain agreements to which we are a party.

The completion of the Recapitalization Transactions may trigger change in control or other provisions in certain agreements to which we are a party. If we are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements or seek monetary damages from us. Even if we are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements.

The private placement of common units in connection with the Recapitalization Transactions relied upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereunder.

At March 31, 2020, we were in default of the Consolidated Funded Indebtedness to Consolidated EBITDAX covenant under our existing credit agreement. On June 4, 2020, we entered into Amendment 15 to our credit agreement in conjunction with the closing of the Recapitalization Transactions, which included a waiver of this default. At June 30, 2020, we were in compliance with financial covenants required by our credit agreement.

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Delaware	45-2842469
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

Title of each class	Trading symbol	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	MCEP	NASDAQ Global Select Market

PART I
FINANCIAL INFORMATION

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		3
ITEM 1. FINANCIAL STATEMENTS		5
Unaudited Condensed Consolidated Balance Sheets		5
Unaudited Condensed Consolidated Statements of Operations		6
Unaudited Condensed Consolidated Statements of Cash Flows		7
Unaudited Condensed Consolidated Statements of Changes in Equity		8
Notes to Unaudited Condensed Consolidated Financial Statements		10

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		24
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		33
ITEM 4. CONTROLS AND PROCEDURES		33

PART II
OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		33
ITEM 1A. RISK FACTORS		33
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		37
ITEM 3. DEFAULTS UPON SENIOR SECURITIES		37
ITEM 4. MINE SAFETY DISCLOSURES		37
ITEM 5. OTHER INFORMATION		37
ITEM 6. EXHIBITS		38

Signature		40

	Six Months Ended June 30,
(in thousands)	2020			2019
Non-cash investing information
Conversion of preferred equity to common units	$	(36,708	)	$	—
Change in oil and natural gas properties - assets received in exchange	$	—		$	38,533
Change in oil and natural gas properties - accrued capital expenditures	$	(2,090	)	$	(74	)
Change in oil and natural gas properties - accrued acquisitions	$	360		$	(1,428	)
Supplemental cash flow information
Cash paid for interest	$	1,940		$	2,619

	Number of Common Units
Approved and authorized awards		175,700
Unrestricted units granted		(69,160	)
Restricted units granted, net of forfeitures		(19,971	)
Equity-settled phantom units granted, net of forfeitures		(72,251	)
Awards available for future grant		14,318

Large accelerated filer	☐	Accelerated filer	☐

Non-accelerated filer	☒	Smaller reporting company	☒

Emerging Growth Company	☐

	Number of Equity-Settled Phantom Units			Average Grant Date Fair Value per Unit
Outstanding at December 31, 2019		28,550		$	25.00
Units vested		(26,267	)		15.73
Units forfeited		(2,283	)		23.24
Outstanding at June 30, 2020		-		$	-

Period Covered	Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price		Total Bbls Hedged/day		Index
Swaps - 2020	$	55.98	$	—	$	—		1,798	NYMEX-WTI
Swaps - 2021	$	55.78	$	—	$	—		672	NYMEX-WTI
Collars - 2021	$	—	$	52.00	$	58.80		672	NYMEX-WTI

(in thousands)	Level 1		Level 2		Level 3		Fair Value
June 30, 2020
Derivative financial instruments - asset	$	—	$	12,529	$	—	$	12,529
Derivative financial instruments - liability	$	—	$	285	$	—	$	285
December 31, 2019
Derivative financial instruments - asset	$	—	$	1,635	$	—	$	1,635
Derivative financial instruments - liability	$	—	$	2,849	$	—	$	2,849

(in thousands)	Six Months Ended June 30, 2020			Year Ended December 31, 2019
Asset retirement obligations - beginning of period	$	30,265		$	26,001
Liabilities incurred for new wells and interest		637			8,840
Liabilities settled upon plugging and abandoning wells		(6	)		(24	)
Liabilities removed upon sale of wells		—			(5,795	)
Revision of estimates		—			(353	)
Accretion expense		838			1,596
Asset retirement obligations - end of period	$	31,734		$	30,265

(in thousands)	Classification	Six Months Ended June 30, 2020		Year Ended December 31, 2019
Assets
Operating	Other property and equipment	$	564	$	835
Total lease assets		$	564	$	835

Liabilities
Current operating	Other current liabilities	$	445	$	430
Non-current operating	Other long-term liabilities		230		457
Total lease liabilities		$	675	$	887

(in thousands)	Operating Leases
Remaining 2020	$	240
2021		471
Total lease maturities		711
Less: interest		36
Present value of lease liabilities	$	675

Exhibit No.		Exhibit Description

2.1		Contribution Agreement, dated June 4, 2020, by and among Mid-Con Energy Partners, LP, Charles R. Olmstead, Jeffrey R. Olmstead, and S. Craig George (incorporated by reference Exhibit 2.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on June 10, 2020).

3.1		Third Amendment to First Amended and Restated Agreement of Limited Partnership of Mid-Con Energy Partners, LP, dated June 4, 2020 (incorporated by reference Exhibit 3.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on June 10, 2020).

3.2		Second Amended and Restated Agreement of Limited Partnership of Mid-Con Energy Partners, LP, dated June 4, 2020 (incorporated by reference Exhibit 3.2 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on June 10, 2020).

3.3		Third Amended and Restated Limited Liability Company Agreement of Mid-Con Energy GP, LLC, dated June 4, 2020 (incorporated by reference Exhibit 3.3 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on June 10, 2020).

10.1		Amendment No. 15 to Credit Agreement, effective June 1, 2020, by and among Mid-Con Energy Properties, LLC, as borrower, Mid-Con Energy Partners, LP, as guarantor, Wells Fargo Bank, National Association, as administrative agent and the lenders party thereto (incorporated by reference Exhibit 10.1 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on June 10, 2020).

10.2		Management Services Agreement, effective July 1, 2020, by and among Mid-Con Energy Partners, LP and Contango Resources, Inc. (incorporated by reference Exhibit 10.2 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on June 10, 2020).

10.3		Transition Services Agreement, effective June 1, 2020, by and among Mid-Con Energy Partners, LP and Mid-Con Energy Operating, LLC (incorporated by reference Exhibit 10.3 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on June 10, 2020).

10.4		Assignment and Assumption Agreement, effective June 1, 2020, by and among Mid-Con Energy Partners, LP and Mid-Con Energy Operating, LLC (incorporated by reference Exhibit 10.4 to Mid-Con Energy Partners, LP’s current report on Form 8-K filed with the SEC on June 10, 2020).

10.5+		Separation Agreement between Philip Houchin and Mid-Con Energy GP, LLC dated July 31, 2020.

31.1+		Rule 13a-14(a)/ 15(d)- 14(a) Certification of Chief Executive Officer

31.2+		Rule 13a-14(a)/ 15(d)- 14(a) Certification of Principal Financial Officer

32.1+		Section 1350 Certificate of Chief Executive Officer

32.2+		Section 1350 Certificate of Principal Financial Officer

101.INS+		XBRL Instance Document

101.SCH+		XBRL Taxonomy Extension Schema Document

101.CAL+		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF+		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB+		XBRL Taxonomy Extension Label Linkbase Document

101.PRE+		XBRL Taxonomy Extension Presentation Linkbase Document

	MID-CON ENERGY PARTNERS, LP

	By: Mid-Con Energy GP, LLC, its general partner

August 14, 2020	By:	/s/ Sherry L. Morgan
		Sherry L. Morgan
		Chief Executive Officer

August 14, 2020	By:	/s/ Jodie L. DiGiacomo
		Jodie L. DiGiacomo
		Chief Accounting Officer
		as Principal Financial Officer