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 ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§~~232.405)~~232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. ~~(Check one):~~

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

As of July ~~31, 2018,~~26, 2019, the registrant had ~~30,436,124~~30,785,958 common ~~units.~~

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 (each a “forward-looking statement”).~~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 our:~~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.~~1A of our Annual Report on Form 10-K for the year ended December 31, ~~2017~~2018 (“Annual Report”) and Part II - Item ~~1A.~~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.

We make available, free of charge on our website (www.midconenergypartners.com), copies of our Annual Reports, Form 10-Qs, Current Reports on Form 8-K, amendments to those reports filed or furnished to the Securities and Exchange Commission (“SEC”) pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and the written charter of our Audit Committee are also available on our website and we will provide copies of these documents upon request. Our website and any contents thereof are not incorporated by reference into this report. ~~We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.~~


	June 30, 2018			December 31, 2017			June 30, 2019			December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	517		$	1,832		$	525		$	467
Accounts receivable								6,438			4,194
Oil and natural gas sales		5,073			5,262
Other		656			103
Prepaid expenses and other		395			166
Derivative financial instruments								—			5,666
Prepaid expenses								393			118
Assets held for sale, net		430			2,058			430			430
Total current assets		7,071			9,421			7,786			10,875
Property and equipment
Oil and natural gas properties, successful efforts method
Proved properties		360,284			335,796			256,654			379,441
Unproved properties		436			369			3,476			2,928
Other property and equipment		427			427			1,456			427
Accumulated depletion, depreciation, amortization and impairment		(145,644	)		(129,101	)		(71,686	)		(175,948	)
Total property and equipment, net		215,503			207,491			189,900			206,848
Derivative financial instruments								955			2,418
Other assets		3,109			2,451			1,186			1,563
Total assets	$	225,683		$	219,363		$	199,827		$	221,704

LIABILITIES, CONVERTIBLE PREFERRED UNITS AND EQUITY
Current liabilities
Accounts payable
Trade	$	851		$	593		$	693		$	141
Related parties		3,047			1,631			3,320			3,732
Derivative financial instruments		9,100			4,252			1,086			—
Accrued liabilities		442			603			632			2,024
Liabilities related to assets held for sale		—			77
Other current liabilities								415			—
Total current liabilities		13,440			7,156			6,146			5,897
Derivative financial instruments		5,196			666
Long-term debt		87,000			99,000			66,000			93,000
Other long-term liabilities		58			70			675			47
Asset retirement obligations		21,027			10,249			30,082			26,001
Commitments and contingencies
Class A convertible preferred units - 11,627,906 issued and outstanding, respectively		21,111			20,534			22,325			21,715
Class B convertible preferred units - 9,803,921 and 0 issued and outstanding, respectively		14,538			—
Class B convertible preferred units - 9,803,921 issued and outstanding, respectively								14,731			14,635
Equity, per accompanying statements
General partner		(776	)		(572	)		(771	)		(786	)
Limited partners - 30,305,628 and 30,090,463 units issued and outstanding, respectively		64,089			82,260
Limited partners - 30,785,958 and 30,436,124 units issued and outstanding, respectively								60,639			61,195
Total equity		63,313			81,688			59,868			60,409
Total liabilities, convertible preferred units and equity	$	225,683		$	219,363		$	199,827		$	221,704

	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2018			2017			2018			2017			2019			2018			2019			2018
Revenues
Oil sales	$	15,931		$	13,657		$	30,475		$	28,612		$	16,792		$	15,931		$	31,386		$	30,475
Natural gas sales		264			288			432			684			397			264			647			432
(Loss) gain on derivatives, net		(9,500	)		2,533			(12,882	)		5,665
Other operating revenues														340			—			712			—
Gain (loss) on derivatives, net														3,396			(9,500	)		(8,802	)		(12,882	)
Total revenues		6,695			16,478			18,025			34,961			20,925			6,695			23,943			18,025
Operating costs and expenses
Lease operating expenses		5,251			5,581			10,052			10,573			7,587			5,009			14,417			9,649
Oil and natural gas production taxes		963			707			1,835			1,509
Production and ad valorem taxes														1,469			1,205			2,751			2,238
Other operating expenses														417			—			890			—
Impairment of proved oil and natural gas properties		959			17,672			9,710			17,672			204			959			204			9,710
Depreciation, depletion and amortization		3,393			4,631			6,834			9,500			2,369			3,393			5,467			6,834
Dry holes and abandonments of unproved properties		97			—			185			—			—			97			—			185
Accretion of discount on asset retirement obligations		191			136			344			244			417			191			745			344
General and administrative		1,358			1,471			3,252			3,297			2,348			1,358			5,010			3,252
Total operating costs and expenses		12,212			30,198			32,212			42,795			14,811			12,212			29,484			32,212
Gain (loss) on sales of oil and natural gas properties, net		12			—			(388	)		—			223			12			9,692			(388	)
Loss from operations		(5,505	)		(13,720	)		(14,575	)		(7,834	)
Income (loss) from operations														6,337			(5,505	)		4,151			(14,575	)
Other (expense) income
Interest income		—			2			2			5			1			—			9			2
Interest expense		(1,410	)		(1,539	)		(2,749	)		(2,989	)		(1,229	)		(1,410	)		(2,844	)		(2,749	)
Other income		—			66			—			66			44			—			49			—
Gain (loss) on settlements of asset retirement obligations		60			(8	)		49			(5	)
(Loss) gain on settlements of asset retirement obligations														(56	)		60			(56	)		49
Total other expense		(1,350	)		(1,479	)		(2,698	)		(2,923	)		(1,240	)		(1,350	)		(2,842	)		(2,698	)
Net loss		(6,855	)		(15,199	)		(17,273	)		(10,757	)
Net income (loss)														5,097			(6,855	)		1,309			(17,273	)
Less: Distributions to preferred unitholders		1,139			694			2,155			1,492			1,157			1,139			2,306			2,155
Less: General partner's interest in net loss		(81	)		(181	)		(204	)		(128	)
Limited partners' interest in net loss	$	(7,913	)	$	(15,712	)	$	(19,224	)	$	(12,121	)
Limited partners' interest in net loss per unit
Basic and diluted	$	(0.26	)	$	(0.52	)	$	(0.64	)	$	(0.40	)
Less: General partner's interest in net income (loss)														60			(81	)		15			(204	)
Limited partners' interest in net income (loss)													$	3,880		$	(7,913	)	$	(1,012	)	$	(19,224	)
Limited partners' interest in net income (loss) per unit
Basic													$	0.13		$	(0.26	)	$	(0.03	)	$	(0.64	)
Diluted													$	0.07		$	(0.26	)	$	(0.03	)	$	(0.64	)
Weighted average limited partner units outstanding
Limited partner units (basic and diluted)		30,306			29,945			30,241			29,936
Limited partner units (basic)														30,786			30,306			30,708			30,241
Limited partner units (diluted)														53,187			30,306			30,708			30,241

	Six Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2019			2018
Cash Flows from Operating Activities
Net loss	$	(17,273	)	$	(10,757	)
Adjustments to reconcile net loss to net cash provided by operating activities
Cash flows from operating activities
Net income (loss)							$	1,309		$	(17,273	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization		6,834			9,500			5,467			6,834
Debt issuance costs amortization		329			680			356			329
Accretion of discount on asset retirement obligations		344			244			745			344
Impairment of proved oil and natural gas properties		9,710			17,672			204			9,710
Dry holes and abandonments of unproved properties		185			—			—			185
(Gain) loss on settlements of asset retirement obligations		(49	)		5
Loss (gain) on settlements of asset retirement obligations								56			(49	)
Cash paid for settlements of asset retirement obligations		(65	)		(21	)		(72	)		(65	)
Mark to market on derivatives
Loss (gain) on derivatives, net		12,882			(5,665	)
Cash settlements (paid) received for matured derivatives		(3,505	)		201
Cash premiums paid for derivatives		—			(2,571	)
Loss on sales of oil and natural gas properties		388			—
Loss on derivatives, net								8,802			12,882
Cash settlements paid for matured derivatives, net								(586	)		(3,505	)
(Gain) loss on sales of oil and natural gas properties								(9,692	)		388
Non-cash equity-based compensation		367			335			456			367
Changes in operating assets and liabilities
Accounts receivable		189			1,048			(2,441	)		(325	)
Other receivables		(514	)		150
Prepaids and other		(1,565	)		224
Prepaid expenses and other assets								(254	)		(1,565	)
Accounts payable - trade and accrued liabilities		442			308			434			442
Accounts payable - related parties		1,277			(2,027	)		(293	)		1,277
Net cash provided by operating activities		9,976			9,326			4,491			9,976
Cash Flows from Investing Activities
Cash flows from investing activities
Acquisitions of oil and natural gas properties		(9,257	)		(4,666	)		(3,262	)		(9,257	)
Additions to oil and natural gas properties		(3,724	)		(4,341	)		(5,085	)		(3,724	)
Additions to other property and equipment		—			(133	)
Proceeds from sales of oil and natural gas properties		1,163			—			32,514			1,163
Net cash used in investing activities		(11,818	)		(9,140	)
Cash Flows from Financing Activities
Net cash provided by (used in) investing activities								24,167			(11,818	)
Cash flows from financing activities
Proceeds from line of credit		7,000			4,000			7,000			7,000
Payments on line of credit		(19,000	)		(5,000	)		(34,000	)		(19,000	)
Offering costs		—			(59	)
Debt issuance costs		(651	)		—			—			(651	)
Proceeds from sale of Class B convertible preferred units, net of offering costs		14,878			—			—			14,878
Distributions to Class A convertible preferred units		(1,500	)		(1,000	)		(1,000	)		(1,500	)
Distributions to Class B convertible preferred units		(200	)		—			(600	)		(200	)
Net cash provided by (used in) financing activities		527			(2,059	)
Net decrease in cash and cash equivalents		(1,315	)		(1,873	)
Net cash (used in) provided by financing activities								(28,600	)		527
Net increase (decrease) in cash and cash equivalents								58			(1,315	)
Beginning cash and cash equivalents		1,832			2,359			467			1,832
Ending cash and cash equivalents	$	517		$	486		$	525		$	517

	General			Limited Partners					Total			General			Limited Partners					Total
	Partner			Units		Amount			Equity			Partner			Units		Amount			Equity

Balance, December 31, 2018												$	(786	)		30,436	$	61,195		$	60,409
Equity-based compensation													—			350		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	)		30,786		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	)		30,786	$	60,639		$	59,868

Balance, December 31, 2017	$	(572	)		30,091	$	82,260		$	81,688		$	(572	)		30,091	$	82,260		$	81,688
Equity-based compensation		—			215		367			367			—			215		239			239
Distributions to Class A convertible preferred units		—			—		(1,000	)		(1,000	)		—			—		(500	)		(500	)
Distributions to Class B convertible preferred units		—			—		(500	)		(500	)		—			—		(200	)		(200	)
Allocation of value to beneficial conversion feature of Class B convertible preferred units		—			—		686			686			—			—		686			686
Accretion of beneficial conversion feature of Class A convertible preferred units		—			—		(577	)		(577	)		—			—		(285	)		(285	)
Accretion of beneficial conversion feature of Class B convertible preferred units		—			—		(78	)		(78	)		—			—		(31	)		(31	)
Net loss		(204	)		—		(17,069	)		(17,273	)		(123	)		—		(10,295	)		(10,418	)
Balance, March 31, 2018													(695	)		30,306		71,874			71,179
Equity-based compensation													—			—		128			128
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													—			—		(292	)		(292	)
Accretion of beneficial conversion feature of Class B convertible preferred units													—			—		(47	)		(47	)
Net loss													(81	)		—		(6,774	)		(6,855	)
Balance, June 30, 2018	$	(776	)		30,306	$	64,089		$	63,313		$	(776	)		30,306	$	64,089		$	63,313

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

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, ~~2017,~~2018, is derived from the audited financial statements. Accordingly, certain information and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted in this Form 10-Q. We believe that the presentations and disclosures made are adequate to make the information not misleading.

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

The unaudited condensed consolidated statements of operations for the prior year includes reclassifications from lease operating expenses (“LOE”) to production and ad valorem taxes to conform to the current presentation. Such reclassifications have no impact on previously reported net loss.

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

	Six Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2018		2017			2019			2018
Non-cash investing information
Change in oil and natural gas properties - assets received in exchange						$	38,533		$	—
Change in oil and natural gas properties - accrued capital expenditures	$	238	$	(40	)	$	(74	)	$	238
Change in oil and natural gas properties - accrued acquisitions						$	(1,428	)	$	—
Change in oil and natural gas properties - acquisition deposit paid in prior year	$	1,000	$	—		$	—		$	1,000
Supplemental cash flow information
Cash paid for interest	$	2,153	$	2,305		$	2,619		$	2,153

We adopted ASU No. 2017-01, “Business Combinations (Topic 805)” effective January 1, 2018. We now evaluate all acquisitions to determine whether they should be accounted for as business combinations or asset acquisitions. The guidance

provides a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the acquired assets is concentrated in a single asset or a group of similar assets, the set is not a business. If the screen is not met, to be considered a business, ~~combination or~~the set must include an ~~asset acquisition. The assets acquired~~input and substantive process that together significantly contribute to the ability to create output.

Assets and liabilities assumed in ~~the~~ acquisitions ~~were~~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 ~~were~~are included in our unaudited condensed consolidated statements of operations.

~~Powder River Basin~~The operations and cash flows of divested properties are eliminated from our ongoing operations.

In January 2018, we acquired multiple oil and natural gas properties located in Campbell and Converse Counties, Wyoming ~~through two separate transactions collectively referred to as the Powder River Basin acquisition (“PRB”)~~(the “Pine Tree” acquisition). ~~The~~ Pine

Tree ~~acquisition~~ was accounted for as a business combination. We acquired Pine Tree for cash consideration of $8.4 million, after final post-closing purchase price adjustments.

The recognized fair values of the Pine Tree assets acquired and liabilities assumed are as follows:

(in thousands)
Fair value of net assets acquired
Oil and natural gas properties	$	9,232
Proved oil and natural gas properties			$	8,833
Total assets acquired		9,232		8,833
Fair value of net liabilities assumed
Asset retirement obligation		862		463
Net assets acquired	$	8,370	$	8,370

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

	Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2018		2017		2018		2017			2019		2018		2019		2018
Oil and natural gas sales	$	354	$	—	$	484	$	—		$	481	$	354	$	703	$	484
Expenses⁽¹⁾	$	161	$	—	$	281	$	—		$	356	$	161	$	564	$	281
⁽¹⁾ Expenses include LOE, production and ad valorem taxes, accretion and depletion.									⁽¹⁾ Expenses include LOE, production and ad valorem taxes, accretion and depletion.

In ~~June 2017,~~March 2019, we ~~acquired multiple~~simultaneously closed the previously announced definitive agreements to sell substantially all of our oil and natural gas properties located in ~~Oklahoma~~Texas for $60.0 million and ~~Cleveland~~to purchase certain oil and natural gas properties located in Osage, Grady and Caddo Counties in Oklahoma for ~~cash consideration of $4.0 million, after final post-closing~~an aggregate purchase price of $27.5 million, both agreements subject to customary purchase price adjustments.

We received net proceeds of $32.5 million at the close of this Strategic Transaction (“Strategic Transaction”) of which $32.0 million was used to reduce borrowings outstanding on our revolving credit facility. The ~~recognized fair values~~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 ~~assets acquired and liabilities assumed are as follows:~~

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

	Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2018		2017		2018		2017			2019			2018		2019		2018
Oil and natural gas sales	$	776	$	142	$	1,498	$	142		$	39		$	6,898	$	4,689	$	13,866
Expenses⁽¹⁾	$	576	$	83	$	1,123	$	83		$	(4	)	$	5,301	$	3,370	$	9,719
⁽¹⁾ Expenses include LOE, production and ad valorem taxes, impairment of proved oil and natural gas properties, dry hole and abandonment, accretion and depletion.									⁽¹⁾ Expenses include LOE, production and ad valorem taxes, impairment of proved oil and natural gas properties, dry hole and abandonment, accretion and depletion.

Effective at closing, the operations and cash flows of the following divested properties were eliminated from the ongoing operations of the Partnership and the Partnership has no continuing involvement in these properties. The divestitures did not represent a strategic shift and did not have a major effect on the Partnership’s operations or financial results.

In January 2018, we completed the sale of certain oil and natural gas proved properties in Nolan County, Texas, for $1.5 million, after final post-closing purchase price adjustments. These properties were deemed to meet held-for-sale accounting criteria as of December 31, 2017, and impairment of $0.3 million was recorded to reduce the carrying value of these assets to their estimated fair value of $1.5 million at December 31, 2017; therefore, no gain or loss was realized on the sale in 2018.

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

In December 2017, we sold the properties located in Southern Oklahoma for cash proceeds, net of expenses, of $21.7 million, prior to final post-closing purchase price adjustments, and recognized a loss of $4.6 million.

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

Land in Southern Oklahoma met held-for-sale criteria as of June 30, ~~2018,~~2019, and December 31, ~~2017.~~2018. The carrying value of $0.4 million was presented inas “Assets held for sale, net” in our unaudited condensed consolidated balance sheets.

We have a long-term incentive program (the “Long-Term Incentive Program”) for employees, officers, consultants and directors of our general partner and its affiliates, including Mid-Con Energy Operating, LLC (“Mid-Con Energy Operating”) and ME3 Oilfield Service, LLC (“ME3 Oilfield Service”), who perform services for us. The Long-Term Incentive Program allows for the award of unit options, unit appreciation rights, unrestricted units, restricted units, phantom units, distribution equivalent rights granted with phantom units and other types of awards. The Long-Term Incentive Program is administered by Charles R. Olmstead, Executive Chairman of the Board, and Jeffrey R. Olmstead, President and Chief Executive Officer, 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, ~~2018:~~2019:

We recognized $0.1 million and $0.4 million of total equity-based compensation expense for the three months and six months ended June 30, 2019, respectively. We recognized $0.1 million and $0.3 million of total equity-based compensation expense for ~~both~~ the three months and six months ended June 30, 2018, ~~and 2017,~~ respectively. 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, 2019, we granted 50,000 unrestricted units with an average grant date fair value of $1.04 per unit. During the six months ended June 30, 2018, we granted 87,832 unrestricted units with an average grant date fair value of $1.79 per unit. ~~During the six months ended June 30, 2017, we granted 25,400 unrestricted units with an average grant date fair value of $2.65 per unit.~~

~~All restricted units were vested as of June 30, 2018. A summary of our restricted unit awards for the six months ended June 30, 2018, is presented below:~~

Equity-settled phantom units vest over a period of two or three ~~years~~years. During the six months ended June 30, 2019, we granted 510,000 equity-settled phantom units with a two-year vesting period and ~~do not have any rights or privileges of~~63,000 equity-settled phantom units with a ~~common unitholder, including right to distributions, until~~three-year vesting ~~and the resulting conversion into common units.~~period. During the six months ended June 30, 2018, we granted 381,000 equity-settled phantom units with a two-year vesting period and 8,500 equity-settled phantom units with a three-year vesting ~~period. During the six months ended June 30, 2017, we granted 9,000 equity-settled phantom units with~~ ~~a three-year vesting~~ period. As of June 30, ~~2018,~~2019, there were $0.6 million of unrecognized compensation costs related to non-vested equity-settled phantom units. These costs are expected to be recognized over a weighted average period of ~~twenty~~seventeen months.

A summary of our equity-settled phantom unit awards for the six months ended June 30, ~~2018,~~2019, is presented below:

	Number of Equity- Settled Phantom Units			Average Grant Date Fair Value per Unit		Number of Equity-Settled Phantom Units			Average Grant Date Fair Value per Unit
Outstanding at December 31, 2017		117,495		$	1.45
Outstanding at December 31, 2018							351,166		$	1.73
Units granted		389,500			1.75		573,000			1.04
Units vested		(127,333	)		1.75		(299,834	)		1.35
Units forfeited		—			—		(15,000	)		1.60
Outstanding at June 30, 2018		379,662		$	1.66
Outstanding at June 30, 2019							609,332		$	1.27

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, ~~2018, and at December 31, 2017,~~2019, our commodity derivative contracts were in a net liability position with a fair value of ~~$14.3~~$0.1 million, ~~and $4.9 million, respectively.~~whereas at December 31, 2018, our commodity derivative contracts were in a net asset position with a fair value of $8.1 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, ~~2018,~~2019, 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, ~~2018,~~2019, and December 31, ~~2017:~~2018:

(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			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, 2018
June 30, 2019
Assets
Derivative financial instruments - current asset	$	2		$	(2	)	$	—		$	67		$	(67	)	$	—
Derivative financial instruments - long-term asset											2,369			(1,414	)		955
Total		2			(2	)		—			2,436			(1,481	)		955

Liabilities
Derivative financial instruments - current liability		(8,701	)		(399	)		(9,100	)		(1,153	)		67			(1,086	)
Derivative deferred premium - current liability		(401	)		401			—
Derivative financial instruments - long-term liability		(5,196	)		—			(5,196	)		(1,414	)		1,414			—
Total		(14,298	)		2			(14,296	)		(2,567	)		1,481			(1,086	)
Net Liability	$	(14,296	)	$	—		$	(14,296	)
Net liability										$	(131	)	$	—		$	(131	)

(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			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, 2017
December 31, 2018
Assets
Derivative financial instruments - current asset	$	39		$	(39	)	$	—		$	5,705		$	(39	)	$	5,666
Derivative financial instruments - long-term asset											2,418			—			2,418
Total		39			(39	)		—			8,123			(39	)		8,084

Liabilities
Derivative financial instruments - current liability		(3,890	)		(362	)		(4,252	)		(39	)		39			—
Derivative deferred premium - current liability		(401	)		401			—
Derivative financial instruments - long-term liability		(666	)		—			(666	)
Total		(4,957	)		39			(4,918	)		(39	)		39			—
Net Liability	$	(4,918	)	$	—		$	(4,918	)
Net asset										$	8,084		$	—		$	8,084

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

	Three Months Ended June 30,					Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2018			2017		2018			2017			2019			2018			2019			2018
Net settlements on matured derivatives⁽¹⁾	$	(2,181	)	$	357	$	(3,505	)	$	201		$	(729	)	$	(2,181	)	$	(586	)	$	(3,505	)
Net change in fair value of derivatives		(7,319	)		2,176		(9,377	)		5,464			4,125			(7,319	)		(8,216	)		(9,377	)
Total (loss) gain on derivatives, net	$	(9,500	)	$	2,533	$	(12,882	)	$	5,665
Total gain (loss) on derivatives, net												$	3,396		$	(9,500	)	$	(8,802	)	$	(12,882	)
⁽¹⁾ The settlement amount does not include premiums paid attributable to contracts that matured during the respective period.											⁽¹⁾ The settlement amount does not include premiums paid attributable to contracts that matured during the respective period.

⁽¹⁾~~The settlement amount does not include premiums paid attributable to contracts that matured or early terminated during the respective period.~~

At June 30, ~~2018,~~2019, and December 31, ~~2017,~~2018, our commodity derivative contracts had maturities at various dates through ~~September 2020~~December 2021 and were comprised of commodity price ~~swap, put~~and differential swaps and collar contracts. At June 30, 2019, we had the following oil derivatives net positions:

Period Covered	Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price		Total Bbls Hedged/day		NYMEX Index	Differential Fixed Price			Weighted Average Fixed Price		Total Bbls Hedged/day		Index
Swaps - 2018	$	54.51	$	—	$	—		488	WTI
Puts - 2018	$	—	$	45.00	$	—		326	WTI
Collars - 2018	$	—	$	43.57	$	52.78		1,141	WTI
Swaps - 2019										$	—		$	56.14		1,779	NYMEX-WTI
Swaps - 2019	$	56.14	$	—	$	—		1,779	WTI	$	(20.15	)	$	—		137	WCS-CRUDE-OIL
Swaps - 2020	$	54.81	$	—	$	—		1,199	WTI	$	—		$	54.81		1,199	NYMEX-WTI

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, ~~2018,~~2019, and for the year ended December 31, ~~2017.~~2018.

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, ~~2018,~~2019, and for the year ended December 31, ~~2017.~~2018.

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. ~~The Partnership’s~~Any deferred premiums associated with its commodity derivative contracts are categorized as Level 3, as ~~the Partnership utilizes~~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, ~~2018,~~2019, and December 31, ~~2017:~~2018:

(in thousands)	Level 1		Level 2		Level 3		Fair Value		Level 1		Level 2		Level 3		Fair Value
June 30, 2018
June 30, 2019
Derivative financial instruments - asset	$	—	$	2	$	—	$	2	$	—	$	2,436	$	—	$	2,436
Derivative financial instruments - liability	$	—	$	13,897	$	—	$	13,897	$	—	$	2,567	$	—	$	2,567
Derivative deferred premiums - liability	$	—	$	—	$	401	$	401
December 31, 2017
December 31, 2018
Derivative financial instruments - asset	$	—	$	39	$	—	$	39	$	—	$	8,123	$	—	$	8,123
Derivative financial instruments - liability	$	—	$	4,556	$	—	$	4,556	$	—	$	39	$	—	$	39
Derivative deferred premiums - liability	$	—	$	—	$	401	$	401

A summary of the changes in Level 3 fair value measurements for the periods presented are as follows:


(in thousands)	Six Months Ended June 30, 2018		��	Year Ended December 31, 2017			Six Months Ended June 30, 2019		Year Ended December 31, 2018
Balance of Level 3 at beginning of period	$	(401	)	$	(5,449	)	$	—	$	(401	)
Derivative deferred premiums - settlements		—			5,048			—		401
Balance of Level 3 at end of period	$	(401	)	$	(401	)	$	—	$	—

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. 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 ~~the Partnership’s~~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 ~~loss~~expense is recognized for the difference between the estimated fair value and the carrying value of the assets. We recorded ~~non-cash~~ impairment expense of $0.2 million for the three and six months ended June 30, 2019. We recorded impairment expense of $1.0 million and $9.7 million for the three and

six months ended June 30, 2018, respectively. ~~We recorded a non-cash impairment of $17.7 million for the three and six months ended June 30, 2017.~~

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~~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, ~~2018,~~2019, and December 31, ~~2017,~~2018, our ARO were reported as ~~“Asset~~asset retirement ~~obligations”~~obligations in our unaudited condensed consolidated balance sheets. Changes in our ARO for the periods indicated are presented in the following table:

(in thousands)	Six Months Ended June 30, 2018			Year Ended December 31, 2017			Six Months Ended June 30, 2019			Year Ended December 31, 2018
Asset retirement obligations - beginning of period	$	10,326		$	11,331		$	26,001		$	10,326
Liabilities incurred for new wells and interest		10,556			759			8,993			15,497
Liabilities settled upon plugging and abandoning wells		(114	)		(57	)		(16	)		(138	)
Liabilities removed upon sale of wells		(77	)		(2,152	)		(5,641	)		(399	)
Revision of estimates		(8	)		(75	)		—			(6	)
Accretion expense		344			520			745			721
Asset retirement obligations - end of period	$	21,027		$	10,326		$	30,082		$	26,001

We had outstanding borrowings under our revolving credit facility of ~~$87.0~~$66.0 million and ~~$99.0~~$93.0 million at June 30, ~~2018,~~2019, and December 31, ~~2017,~~2018, respectively. Our current revolving credit facility matures in November 2020. Borrowings under the facility are secured by liens on not less than 90% of the value of our proved reserves.

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. The next regularly scheduled redetermination is expected to occur in the fall of 2019.

Borrowings under the revolving credit facility bear interest at a floating rate based on, at our election, the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50% and the one month adjusted London Interbank Offered Rate (“LIBOR”) plus 1.0%, all of which are subject to a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or the applicable LIBOR plus a margin that varies from 2.75% to 3.75% per annum according to the borrowing base usage. For the three months ended June 30, ~~2018,~~2019, the average effective rate was ~~5.21%~~5.73%. Any unused portion of the borrowing base ~~will be~~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 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, ~~leverage ratios~~ and restrictions on certain transactions and payments, including ~~distributions.~~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.

During the spring 2017 semi-annual borrowing base redetermination of our revolving credit facility completed in May 2017, the lender group reaffirmed the Partnership’s $140.0 million conforming borrowing base effective May 24, 2017. There were no changes to the terms or conditions of the credit agreement.

During the quarter ended September 30, 2017, we were not in compliance with our leverage ratio calculation. On November 10, 2017, the Partnership received a waiver from the Administrative Agent and the Lenders of our revolving credit facility waiving the noncompliance through December 15, 2017. On December 22, 2017, Amendment 11 to the credit agreement was finalized. The amendment extended the waiver of the leverage ratio default until January 31, 2018. This amendment decreased the Partnership’s borrowing base to $115.0 million effective December 22, 2017, and required the facility usage not exceed $100.0 million. The amendment also required that the cash proceeds received from the Southern Oklahoma divestiture on December 22, 2017, and the Nolan County divestiture on January 9, 2018, be applied to the borrowings outstanding. See Note 2 in this section for more information regarding these divestitures.

On January 31, 2018, Amendment 12 to the credit agreement was executed, extending the maturity of our credit facility from November 2018 until November 2020 and increasing the borrowing base of ~~the Partnership’s~~our revolving credit facility to $125.0 million. The lenders also waived any default or event of default that occurred as a result of ~~the Partnership’s~~our failure to maintain the required leverage ratios for the quarter ended September 30, 2017. The amendment also required ~~the Partnership~~us to have a minimum liquidity of 20% to make cash distributions to the Preferred Unitholders. ~~As of June 30, 2018, we were in compliance with our financial covenants.~~

During the ~~spring~~fall 2018 semi-annual borrowing base redetermination of our revolving credit facility completed in ~~June~~December 2018, the lender group ~~reaffirmed the Partnership’s $125.0~~increased our borrowing base to $135.0 million ~~conforming borrowing base.~~effective December 19, 2018. There were no changes to the terms or conditions of the credit agreement.

On March 28, 2019, in conjunction with closing the Strategic Transaction and serving as our spring redetermination, Amendment 13 to the credit agreement was executed, decreasing our borrowing base to $110.0 million. The amendment also required that the leverage ratio be calculated on a building, period-annualized basis, beginning the second quarter of 2019. As of June 30, 2019, we were in compliance with our financial covenants. See Note 2 in this section for further discussion of the Strategic Transaction.

~~We lease corporate office space in Tulsa, Oklahoma, and Abilene, Texas. Total lease expenses were~~ ~~$0.1 million~~ ~~for both the three and six months ended June 30, 2018, and 2017. These expenses are included in G&A in our unaudited condensed consolidated statements of operations.~~

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

We are party to a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating provides certain services to us including management, administrative and operational services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. See Note 10 in this section for additional information.

Our general partner has entered into employment agreements with Charles R. Olmstead, Executive Chairman of the Board and Jeffrey R. Olmstead, President and Chief Executive Officer. The employment agreements automatically renew for one-year terms on August 1st of each year unless either we or the employee gives written notice of termination by ~~at least~~ the preceding February. Pursuant to the employment agreements, each employee will serve in his respective position with our

general partner, as set forth above, and has duties, responsibilities and authority as the Board may specify from time to time, in roles consistent with such positions that are assigned to them. The ~~agreement stipulates~~agreements stipulate that if there is a change of control, termination of employment, with cause or without cause, or death of the executive certain payments will be made to the executive officer. These payments, depending on the reason for termination, currently range from $0.3 million to $0.6 million, including the value of vesting of any outstanding units.

WeAlthough 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 claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management and our General Counsel, the ultimate resolution of all claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our financial position, results of operations or cash flows.environmental protection statutes to which we are subject.

At June 30, ~~2018,~~2019, and December 31, ~~2017,~~2018, the Partnership’s equity consisted of ~~30,305,628~~30,785,958 and ~~30,090,463~~30,436,124 common units, respectively, representing a 98.8% limited partnership interest in us.

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

Our Partnership Agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. As of June 30, ~~2018,~~2019, 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 has issued two classes of Preferred Units. Per accounting guidance, we were required to allocate a portion of the proceeds from Preferred Units to a beneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value is 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 is 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 are entitled to certain rights that are senior to the rights of holders of common units, such as rights to distributions and rights upon liquidation of the Partnership. We pay holders of Preferred Units a cumulative, quarterly cash distribution on Preferred Units then outstanding at an annual rate of 8.0%, or in the event that the Partnership’s existing secured indebtedness prevents the payment of a cash distribution to all holders of the Preferred Units, in kind (additional Class A or Class B Preferred Units), at an annual rate of 10.0%. Such distributions will be paid for each such quarter within 45 days after such quarter end, or as otherwise permitted to accumulate pursuant to the Partnership Agreement.

Prior to August 11, 2021, each holder of Preferred Units has the right, subject to certain conditions, to convert all or a portion of their Preferred Units into common units representing limited partner interests in the Partnership on a one-for-one basis, subject to adjustment for splits, subdivisions, combinations and reclassifications of the common units. Upon conversion of the Preferred Units, the Partnership will 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.

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 (the “Class A Unit Purchase Price”).~~Unit. Proceeds from this issuance were used to fund ~~the Permian Bolt-On~~an acquisition and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We received net proceeds of $24.6 million in connection with the issuance of these Class A

Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Class A Preferred Units ($18.6 million) and the beneficial conversion feature ($6.0 million). Accretion of the beneficial conversion feature was $0.3 million and $0.6 million for the three and six months ended June 30, ~~2018. Accretion of the beneficial conversion feature was $0.2 million~~2019 and ~~$0.5 million for the three and six months ended June 30, 2017.~~2018, respectively. The registration statement registering resales of common units issued or to be issued upon conversion of the Class A Preferred Units was declared effective by the SEC on June 14, 2017.

At June 30, ~~2018,~~2019, the Partnership had accrued $0.5 million for the second quarter ~~2018 distribution~~2019 distributions that will be paid in cash in August ~~2018.~~ 2019. The following table summarizes cash distributions paid on our Class A Preferred Units during the six months ended June 30, 2019:

The following table summarizes cash distributions paid on our Class A Preferred Units during the six months ended June 30, 2018:

~~The following table summarizes cash distributions paid on our Class A Preferred Units during the six months ended June 30, 2017:~~

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 (the “Class B Unit Purchase Price”).~~Unit. Proceeds from this issuance were used to fund the acquisition of certain oil and natural gas properties located in Campbell and Converse Counties, Wyoming, and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We received net proceeds of $14.9 million in connection with the issuance of these Class B Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Class B Preferred Units ($14.2 million) and the beneficial conversion feature ($0.7 million). Accretion of the beneficial conversion feature was $0.1 million for the six months ended June 30, 2019 and 2018. The registration statement registering resales of common units issued or to be issued upon conversion of the Class B Preferred Units was declared effective by the SEC on May 25, 2018.

At June 30, ~~2018,~~2019, the Partnership had accrued $0.3 million for the second quarter ~~2018 distribution~~2019 distributions that will be paid in cash in August ~~2018.~~ 2019. The following table summarizes cash distributions paid on our Class B Preferred Units during the six months ended June 30, 2019:

The following table summarizes cash distributions paid on our Class B Preferred Units during the six months ended June 30, 2018:

Date Paid

Period Covered

Distribution per

Unit

Total Distributions

(in thousands)

Period Covered

Distribution per

Unit

Total Distributions

(in thousands)

May 15, 2018

February 1, 2018 - March 31, 2018

0.020

200

February 1, 2018 - March 31, 2018

0.0200

200

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

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 have been entered into with the affiliates of our general partner and with our general partner.

We are party to a services agreement with our affiliate, Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating provides certain services to us, including ~~management,~~managerial, administrative and operational services. The operational services include marketing, geological and engineering services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. These expenses are included in G&A in our unaudited condensed consolidated statements of operations.

We, along with various third parties with an ownership interest in the same property, are parties to standard oil and natural gas joint operating agreements with our affiliate, Mid-Con Energy Operating. We and those third parties pay Mid-Con Energy Operating overhead associated with operating our properties and for its direct and indirect expenses that are chargeable to the wells under their respective operating agreements. The majority of these expenses ~~were~~are included in ~~lease operating expenses (“LOE”)~~LOE in our unaudited condensed consolidated statements of operations.

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

We are 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 pay Bonanza and GFS a quarterly monitoring fee in connection with monitoring the purchasers’ investments in the Preferred Units. These expenses are included in G&A in our unaudited condensed consolidated statements of operations.

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

	Three Months Ended				Six Months Ended				Three Months Ended				Six Months Ended
	June 30,				June 30,				June 30,				June 30,
(in thousands)	2018		2017		2018		2017		2019		2018		2019		2018
Services agreement	$	599	$	652	$	1,129	$	1,293	$	708	$	599	$	1,477	$	1,129
Operating agreements		1,465		1,613		2,791		3,016		2,708		1,465		5,544		2,791
Oilfield services		1,117		857		2,028		1,667		1,415		1,117		2,512		2,028
Other Agreements										80		80		160		150
	$	3,181	$	3,122	$	5,948	$	5,976	$	4,911	$	3,261	$	9,693	$	6,098

At June 30, 2019, we had a net payable to our affiliate, Mid-Con Energy Operating, of $3.3 million, comprised of a joint interest billing payable of $5.0 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 $1.9 million. At December 31, 2018, we had a net payable to our affiliate, Mid-Con Energy Operating, of ~~$3.0~~$3.7 million, comprised of a joint interest billing payable of ~~$2.7~~$3.7 million and a payable for operating services and other miscellaneous items of ~~$0.3 million. At December 31, 2017, we had a net payable to our affiliate, Mid-Con Energy Operating,~~$1.2 million, offset by an oil and natural gas revenue receivable of ~~$1.6 million, comprised of a joint interest billing payable of $1.4 million and a payable for operating services of $0.2~~$1.2 million. These amounts were included in accounts payable-related parties in our unaudited condensed consolidated balance sheets.

On January 1, 2019, we adopted ASC 842, Leases (“ASC 842”). See Note 13 in this section for further discussion of ASC 842.

In ~~February~~June 2016, the FASB issued ~~ASU No. 2016-02, “~~ASC 326, ~~Leases~~Financial Instruments- Credit Losses ~~(Topic 842)~~(“ASC 326”),” which ~~supersedes~~replaces the current ~~lease guidance. The~~“incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new ~~lease standard~~methodology requires ~~all leases with~~that a ~~term greater than one year~~financial asset measured at amortized cost be presented at the net amount expected to be ~~recognized~~collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on ~~the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged.~~financial instruments. This guidance is effective for ~~reporting periods~~fiscal years beginning after December 15, ~~2018,~~2019, and early adoption is ~~permitted.~~allowed as early as fiscal years beginning after December 15, 2018. We ~~are currently in the process of identifying all contracts that are leases or contain leases. We plan to adopt~~do not believe this ~~standard on January 1, 2019 and believe the primary~~new guidance will have a material impact ~~of adoption will be the recognition of assets and liabilities~~ on our ~~balance sheet for current operating leases.~~consolidated financial statements.

We adopted ASC 606 effective January 1, 2018, using the modified retrospective approach. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Under ASC 605, we followed the sales method of accounting for oil and natural gas sales revenues in which revenues were recognized on our share of actual proceeds from oil and natural gas sold to purchasers. Revenue recognition required for our oil and natural gas sales contracts by ASC 606 does not differ from revenue recognition required under ASC 605 to account for such contracts. Therefore, we concluded that there was no change in our revenue recognition under ASC 606 and the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018, did not result in an adjustment to retained earnings. We had no significant natural gas imbalances at June 30, 2019 and 2018.

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 ~~crude~~ 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. ~~Our~~The majority of our natural gas ~~sales revenues~~contract pricing provisions are tied to a ~~percentage of the proceeds received by the purchaser for selling the volume of gas produced by the Partnership on a monthly basis. The purchaser sells the volume of natural gas at~~market index ~~rates per Mcf.~~less customary deductions, such as gathering, processing and transportation. Payment is typically received 30 to 60 days after the date production is delivered.

Our ~~product~~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.

WeFor 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. For our crude oil sales and natural gas sales contracts, the variable consideration related to variable production in 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.

Our ~~product~~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, as of 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:

~~The~~On July 29, 2019, the Partnership announced that the Board declared Preferred Unit distributions for the second quarter of ~~2018,~~2019, according to terms outlined in the Partnership Agreement. Distributions will be paid on August ~~22, 2018,~~14, 2019, to holders of record as of the close of business on August 7, ~~2018.~~2019. The Class A Preferred Unit cash distributions will be ~~$0.043~~$0.0430 per Class A Preferred Unit, or $0.5 million in aggregate. Additionally, the Class B Preferred Unit cash distributions will be $0.0306 per Class B Preferred Unit, or $0.3 million in aggregate.

On July ~~2, 2018, we acquired multiple oil~~24, 2019, the Board adopted a change in control severance plan that provides severance benefits to certain key management in the event of a change in control.

Appointment and ~~natural gas properties located in Oklahoma for a purchase price~~Departure of ~~$8.3 million, subject to customary post-closing sale price adjustments and resolution of certain title defects. The effective date of the acquisition was July 1, 2018.~~

On July 10, 2018, we acquired multiple oil and natural gas properties located in Campbell County, Wyoming, for a purchase price of $1.0 million, subject to customary post-closing sale price adjustments. The effective date24, 2019, the Board appointed Chad B. Roller, Ph.D., as Chief Operating Officer of the ~~acquisition was July 1, 2018.~~general partner.

On July 27, 2018, we acquired multiple oil and natural gas properties and mid-stream assets located in Washakie County, Wyoming for a purchase price of $5.0 million, subject to customary post-closing sale price adjustments. The effective date of the acquisition was January 1, 2018.

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 ~~Texas~~ 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 markets for oil and natural gas ~~and NGLs~~ 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 ~~$62.32~~$53.84 and ~~$46.83~~$62.32 for the six months ended June 30, ~~2018,~~2019 and ~~2017,~~2018, respectively.

puts and collars) to manage a portion of our exposure to commodity prices. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent ~~to do so,~~ or as required by our lenders. We conduct our risk management activities exclusively with participant lenders in our revolving credit facility. We have entered oil commodity derivative contracts covering a portion of our anticipated oil production through ~~September 2020.~~December 2021.

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

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

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~~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:

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others, to assess the cash flow generated by our assets, without regard to financing methods, capital structure or historical cost basis and our ability to incur and service debt and fund capital expenditures. In addition, management uses Adjusted EBITDA to evaluate actual potential cash flow available to reduce debt, develop existing reserves or acquire additional properties and pay distributions to our unitholders. Adjusted EBITDA is a non-U.S. GAAP measure and should not be considered an alternative to net income (loss), net cash provided by operating activities or any other performance or liquidity measure determined in accordance with U.S. GAAP. Our calculations of Adjusted EBITDA are not necessarily comparable to EBITDA or Adjusted EBITDA as calculated by other companies.

The tables presented in this section summarize certain of the results of operations and period-to-period comparisons for the three and six months ended June 30, ~~2018,~~2019 and ~~2017.~~2018. 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.

Production, Prices and Unit Costs per ~~BOE~~Boe. The table below provides production volume data, average sales prices and average unit costs per ~~BOE:~~Boe:

	Three Months Ended June 30,						Change				Six Months Ended June 30,						Change				Three Months Ended June 30,									%	Six Months Ended June 30,									%
	2018			2017			$			%	2018			2017			$			%	2019			2018			Change			Change	2019			2018			Change			Change
Production Volumes
Oil (MBbls)		251			306			(55	)	(18%)		489			611			(122	)	(20%)		291			251			40		16%		583			489			94		19%
Natural gas (MMcf)		92			110			(18	)	(16%)		178			234			(56	)	(24%)		184			92			92		100%		305			178			127		71%
Total (MBoe)		267			324			(57	)	(18%)		519			650			(131	)	(20%)		322			267			55		21%		634			519			115		22%

Average daily net production (Boe/d)		2,934			3,560			(626	)	(18%)		2,867			3,591			(724	)	(20%)		3,538			2,934			604		21%		3,503			2,867			636		22%

Average sales price
Oil (per Bbl)
Sales price	$	63.47		$	44.63		$	18.84		42%	$	62.32		$	46.83		$	15.49		33%	$	57.70		$	63.47		$	(5.77	)	(9%)	$	53.84		$	62.32		$	(8.48	)	(14%)
Effect of net settlements on matured derivative instruments	$	(8.69	)	$	(3.21	)	$	(5.48	)	171%	$	(7.17	)	$	(3.95	)	$	(3.22	)	82%	$	(2.50	)	$	(8.69	)	$	6.19		71%	$	(1.01	)	$	(7.17	)	$	6.16		86%
Realized oil price after derivatives	$	54.78		$	41.42		$	13.36		32%	$	55.15		$	42.88		$	12.27		29%	$	55.20		$	54.78		$	0.42		1%	$	52.83		$	55.15		$	(2.32	)	(4%)
Natural gas (per Mcf)	$	2.87		$	2.62		$	0.25		10%	$	2.43		$	2.92		$	(0.49	)	(17%)	$	2.16		$	2.87		$	(0.71	)	(25%)	$	2.12		$	2.43		$	(0.31	)	(13%)

Average unit costs per Boe
Lease operating expenses	$	19.67		$	17.23		$	2.44		14%	$	19.37		$	16.27		$	3.10		19%	$	23.56		$	18.76		$	4.80		26%	$	22.74		$	18.59		$	4.15		22%
Oil and natural gas production taxes	$	3.61		$	2.18		$	1.43		66%	$	3.54		$	2.32		$	1.22		53%
Production and ad valorem taxes																					$	4.56		$	4.51		$	0.05		1%	$	4.34		$	4.31		$	0.03		1%
Depreciation, depletion and amortization	$	12.71		$	14.29		$	(1.58	)	(11%)	$	13.17		$	14.62		$	(1.45	)	(10%)	$	7.36		$	12.71		$	(5.35	)	(42%)	$	8.62		$	13.17		$	(4.55	)	(35%)
General and administrative expenses	$	5.09		$	4.54		$	0.55		12%	$	6.27		$	5.07		$	1.20		24%	$	7.29		$	5.09		$	2.20		43%	$	7.90		$	6.27		$	1.63		26%

~~Operating Revenues.~~Oil and natural gas sales. The following table provides oil and natural gas sales data for the three and six months ended June 30, ~~2018,~~2019 and ~~2017:~~2018:

	Three Months Ended June 30,				Change				Six Months Ended June 30,				Change				Three Months Ended June 30,						%	Six Months Ended June 30,						%
(in thousands)	2018		2017		$			%	2018		2017		$			%	2019		2018		Change		Change	2019		2018		Change		Change
Oil sales	$	15,931	$	13,657	$	2,274		17%	$	30,475	$	28,612	$	1,863		7%	$	16,792	$	15,931	$	861	5%	$	31,386	$	30,475	$	911	3%
Natural gas sales		264		288		(24	)	(8%)		432		684		(252	)	(37%)		397		264		133	50%		647		432		215	50%
Total oil and natural gas sales	$	16,195	$	13,945	$	2,250		16%	$	30,907	$	29,296	$	1,611		5%	$	17,189	$	16,195	$	994	6%	$	32,033	$	30,907	$	1,126	4%

The following table details the change in ~~revenues~~oil and natural gas sales due to price and volume variances:

	Three Months Ended June 30, 2018 and 2017								Six Months Ended June 30, 2018 and 2017								Three Months Ended June 30, 2019 and 2018								Six Months Ended June 30, 2019 and 2018
(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			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)	$	18.84			251	$	4,729		$	15.49			489	$	7,575		$	(5.77	)		291	$	(1,679	)	$	(8.48	)		583	$	(4,945	)
Natural gas (Mcf)	$	0.25			92		23		$	(0.49	)		178		(87	)	$	(0.71	)		184		(131	)		(0.31	)		305		(95	)
Total revenues due to change in price							4,752								7,488
Total oil and natural gas sales due to change in price																						$	(1,810	)						$	(5,040	)

	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			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 production volumes
Oil (Bbls)		(55	)	$	44.63	$	(2,455	)		(122	)	$	46.83	$	(5,713	)		40		$	63.47	$	2,540			94		$	62.32	$	5,856
Natural gas (Mcf)		(18	)	$	2.62		(47	)		(56	)	$	2.92		(164	)		92		$	2.87		264			127		$	2.43		310
Total revenues due to change in production volumes							(2,502	)							(5,877	)
Total change in revenues						$	2,250							$	1,611
Total oil and natural gas sales due to change in production volumes																							2,804								6,166
Total change in oil and natural gas sales																						$	994							$	1,126

The change in ~~operating revenues~~oil and natural gas sales for the three and six months ended June 30, ~~2018,~~2019, compared to the three and six months ended June 30, ~~2017,~~2018, was primarily due to:

~~(Loss) gain~~Gain (loss) on derivatives, net. The table below summarizes the ~~non-cash~~cash and ~~cash~~non-cash components of our commodity derivative contracts as well as the change for the three and six months ended June 30, ~~2018,~~2019 and ~~2017:~~2018:

	Three Months Ended June 30,					Change				Six Months Ended June 30,					Change					Three Months Ended June 30,								%	Six Months Ended June 30,								%
(in thousands)	2018			2017		$			%	2018			2017		$			%		2019			2018			Change		Change	2019			2018			Change		Change
Cash settlements on matured derivatives	$	(2,181	)	$	357	$	(2,538	)	(711%)	$	(3,505	)	$	201	$	(3,706	)	(1844%)
Cash settlements on matured derivatives, net⁽¹⁾																				$	(729	)	$	(2,181	)	$	1,452	67%	$	(586	)	$	(3,505	)	$	2,919	83%
Non-cash change in fair value of derivatives		(7,319	)		2,176		(9,495	)	(436%)		(9,377	)		5,464		(14,841	)	(272%)			4,125			(7,319	)		11,444	156%		(8,216	)		(9,377	)		1,161	12%
Total (loss) gain on derivatives, net	$	(9,500	)	$	2,533	$	(12,033	)	(475%)	$	(12,882	)	$	5,665	$	(18,547	)	(327%)
Total gain (loss) on derivatives																				$	3,396		$	(9,500	)	$	12,896	136%	$	(8,802	)	$	(12,882	)	$	4,080	32%
⁽¹⁾ The settlement amount does not include premiums paid attributable to contracts that matured during the respective period.																			⁽¹⁾ The settlement amount does not include premiums paid attributable to contracts that matured during the respective period.

~~Production~~Lease operating expenses. The following table summarizes the change in ~~oil and natural gas production expense for the three and six months ended June 30, 2018, and 2017:~~

~~The change in production~~lease operating expenses for the three and six months ended June 30, ~~2018,~~2019 and 2018:

The change in lease operating expenses for the three and six months ended June 30, 2019, compared to the three and six months ended June 30, ~~2017,~~2018, was primarily due to:

The following table summarizes ~~production~~lease operating expenses per Boe data for the three and six months ended June 30, ~~2018,~~2019 and ~~2017:~~2018:

	Three Months Ended June 30,				Change			Six Months Ended June 30,				Change			Three Months Ended June 30,							%	Six Months Ended June 30,							%
(per Boe)	2018		2017		$		%	2018		2017		$		%	2019		2018		Change			Change	2019		2018		Change			Change
Lease operating expenses	$	19.67	$	17.23	$	2.44	14%	$	19.37	$	16.27	$	3.10	19%	$	22.75	$	17.72	$	5.03		28%	$	21.92	$	17.42	$	4.50		26%
Oil and natural gas production taxes		3.61		2.18		1.43	66%		3.54		2.32		1.22	53%
Total oil and natural gas production expenses per Boe	$	23.28	$	19.41	$	3.87	20%	$	22.91	$	18.59	$	4.32	23%
Workover expenses																0.81		1.04		(0.23	)	(22%)		0.82		1.17		(0.35	)	(30%)
Total lease operating expenses per Boe															$	23.56	$	18.76	$	4.80		26%	$	22.74	$	18.59	$	4.15		22%

The change in ~~production~~lease operating expenses per Boe for the three and six months ended June 30, ~~2018,~~2019, compared to the three and six months ended June 30, ~~2017,~~2018, was primarily due to:

Production and ad valorem taxes. The following table summarizes the change in production and ad valorem taxes for the three and six months ended June 30, 2019 and 2018:

The change in production and ad valorem expenses for the three and six months ended June 30, 2019, compared to the three and six months ended June 30, 2018, was primarily due to:

The following table summarizes production and ad valorem taxes per Boe data for the three and six months ended June 30, 2019 and 2018:

The change in production and ad valorem taxes per Boe for the three and six months ended June 30, 2019, compared to the three and six months ended June 30, 2018, was primarily due to the changes noted above and the divestitures of our Texas properties with a lower state oil production ~~volumes, partially offset by the decreases noted above.~~tax rate.

Depreciation, ~~Depletion, Amortization~~depletion, amortization and ~~Impairment Expenses.~~impairment expenses. The following table provides our non-cash depreciation, depletion and amortization (“DD&A”) and impairment expense for the three and six months ended June 30, ~~2018,~~2019 and ~~2017:~~2018:

	Three Months Ended June 30,				Change				Six Months Ended June 30,				Change				Three Months Ended June 30,							%	Six Months Ended June 30,							%
(in thousands)	2018		2017		$			%	2018		2017		$			%	2019		2018		Change			Change	2019		2018		Change			Change
Depreciation, depletion and amortization	$	3,393	$	4,631	$	(1,238	)	(27%)	$	6,834	$	9,500	$	(2,666	)	(28%)	$	2,369	$	3,393	$	(1,024	)	(30%)	$	5,467	$	6,834	$	(1,367	)	(20%)
Impairment		959		17,672		(16,713	)	(95%)		9,710		17,672		(7,962	)	(45%)		204		959		(755	)	(79%)		204		9,710		(9,506	)	(98%)
Total DD&A and impairment	$	4,352	$	22,303	$	(17,951	)	(80%)	$	16,544	$	27,172	$	(10,628	)	(39%)
Total DD&A and impairment expense																	$	2,573	$	4,352	$	(1,779	)	(41%)	$	5,671	$	16,544	$	(10,873	)	(66%)

The change in DD&A for the three and six months ended June 30, ~~2018,~~2019, compared to the three and six months ended June 30, ~~2017,~~2018, was primarily due to:

General and ~~Administrative Expenses.~~administrative expenses. The following table provides components of our G&A for the three and six months ended June 30, ~~2018,~~2019 and ~~2017:~~2018:

	Three Months Ended June 30,				Change				Six Months Ended June 30,				Change				Three Months Ended June 30,							%	Six Months Ended June 30,						%
(in thousands, except for per Boe)	2018		2017		$			%	2018		2017		$			%	2019		2018		Change			Change	2019		2018		Change		Change
General and administrative expenses	$	1,230	$	1,300	$	(70	)	(5%)	$	2,885	$	2,962	$	(77	)	(3%)	$	2,226	$	1,230	$	996		81%	$	4,554	$	2,885	$	1,669	58%
Non-cash compensation		128		171		(43	)	(25%)		367		335		32		10%		122		128		(6	)	(5%)		456		367		89	24%
Total general and administrative expenses	$	1,358	$	1,471	$	(113	)	(8%)	$	3,252	$	3,297	$	(45	)	(1%)	$	2,348	$	1,358	$	990		73%	$	5,010	$	3,252	$	1,758	54%
General and administrative expenses (per Boe)	$	5.09	$	4.54		0.55		12%	$	6.27	$	5.07		1.20		24%	$	7.29	$	5.09		2.20		43%	$	7.90	$	6.27		1.63	26%

The change in both G&A and G&A per Boe for the three ~~months ended June 30, 2018, compared to the three months ended June 30, 2017, was primarily due to:~~

~~The change in G&A for the~~ six months ended June 30, ~~2018,~~2019, compared to ~~the six months ended June 30, 2017, was primarily due to increased non-cash compensation.~~

~~The increase in G&A per BOE for both~~ the three and six months ended June 30, 2018, was primarily due to ~~lower production volumes, partially offset by~~increased professional and other fees related to acquisition and divestiture activity.

Gain (loss) on sales of oil and natural gas properties. The following table provides our gain (loss) on sales of oil and natural gas properties for the ~~decreases~~three and six months ended June 30, 2019 and 2018:

The change in ~~G&A noted above.~~gain (loss) on sales of oil and natural gas properties for the three and six months ended June 30, 2019, was due to the divestiture of substantially all of our Texas properties as part of the Strategic Transaction. For the three and six months ended June 30, 2018, the gain (loss) on sales of oil and natural gas properties was primarily related to the Southern Oklahoma divestiture.

Interest ~~Expense.~~expense. Interest expense is impacted by our borrowings outstanding, interest rates, commitment fees and related debt placement fees which are amortized over the life of the credit agreement. The following table sets forth interest expense for the three and six months ended June 30, ~~2018,~~2019 and ~~2017:~~2018:

	Three Months Ended June 30,				Change				Six Months Ended June 30,				Change				Three Months Ended June 30,									%	Six Months Ended June 30,								%
(in thousands)	2018		2017		$			%	2018		2017		$			%	2019			2018			Change			Change	2019		2018			Change			Change
Interest expense	$	1,410	$	1,539	$	(129	)	(8%)	$	2,749	$	2,989	$	(240	)	(8%)	$	1,229		$	1,410		$	(181	)	(13%)	$	2,844	$	2,749		$	95		3%
Average effective interest rate	5.21%		3.81%		1.40%			37%	5.05%		3.69%		1.36%			37%		5.73	%		5.21	%		0.52	%	10%	5.75%			5.05	%		0.70	%	14%

The change in interest expense for the three and six months ended June 30, ~~2018,~~2019, compared to the three and six months ended June 30, ~~2017,~~2018, was primarily due to:

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.~~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~~(including acquisitions) and distributions.

Since November 2014, oil prices have been extremely volatile, impacting the way we conduct business. In response, we have implemented a number of adjustments to strengthen our financial position. We have continued to hedge a portion of our production to limit downside and volatility in the prevailing commodity price environment. We have aggressively pursued cost reductions to improve profitability and maximize cash flows. Our primary cost reduction initiatives encompass periodic economic review of each well within our portfolio along with ongoing scrutiny of LOE and G&A. Additionally, in the third quarter 2015, we indefinitely suspended our quarterly cash distributions on common units.

Our liquidity position at July ~~30, 2018,~~26, 2019, consisted of approximately ~~$0.9~~$0.6 million of available cash and ~~$26.0~~$43.0 million of available borrowings ($~~125.0~~110.0 million borrowing base less ~~$98.0~~$66.0 million outstanding borrowings and $1.0 million outstanding standby letter of credit). Our borrowing base is redetermined in the spring and fall of each year.

~~During~~On March 28, 2019, in conjunction with closing the ~~spring 2018 semi-annual redetermination~~Strategic Transaction, Amendment 13 to the credit agreement was executed, decreasing the borrowing base of the Partnership’s revolving credit facility ~~completed in June 2018,~~to $110.0 million. The amendment also required that the ~~lender group reaffirmed~~leverage ratio be calculated on a building, period-annualized basis, beginning the ~~existing conforming borrowing base~~second quarter of ~~$125.0 million. There were no changes to the terms or conditions of the credit agreement~~2019. At July ~~30, 2018,~~26, 2019, the outstanding ~~borrowings~~balances of our revolving credit facility and standby letter of credit were ~~$98.0 million.~~$66.0 million and $1.0 million, respectively.

Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures budget, meet our debt service requirements and fund our other commitments and obligations. 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 due to the discretion of our lenders to potentially decrease our borrowing base. 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.

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 Preferred Units.

We currently expect capital spending for the remainder of ~~2018~~2019 for the development, growth and maintenance of our oil and natural gas properties to be ~~$7.5~~$5.4 million. We will adjust our capital program in response to business conditions and operating results along with our evaluation of additional development opportunities that are identified throughout the year.

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,~~(commodity price and differential 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 ~~to do so,~~ or as required by our lenders. At June 30, ~~2018,~~2019, we had commodity derivative contracts covering approximately ~~63%~~52%, ~~57%~~60% and ~~52%~~41%, respectively, of our estimated ~~2018,~~ 2019, 2020 and ~~2020~~2021 average daily production (estimate calculated based on the mid-point of our ~~full year 2018~~

full-year 2019 Boe production guidance as released on July 31, ~~2018,~~2019, and multiplied by a ~~94%~~90% oil weighting based on second quarter ~~2018~~2019 reported production volumes). See Note 4 to the unaudited condensed consolidated financial statements for additional information regarding our commodity derivative contracts.

As of June 30, ~~2018,~~2019, we have issued $25.0 million of Class A Preferred Units and $15.0 million of Class B Preferred Units through private placements in August 2016 and January 2018, respectively. Both classes of Preferred Units receive a cumulative, quarterly cash distribution on Preferred Units then outstanding at an annual rate of 8.0%, or in the event that the Partnership’s existing secured indebtedness prevents the payment of a cash distribution to all holders of the Preferred Units, in kind (additional Class A or Class B Preferred Units), at an annual rate of 10.0%. Such distributions will be paid for each such quarter within 45 days after such quarter end, or as otherwise permitted to accumulate pursuant to the Partnership Agreements. See Note 9 to the unaudited condensed consolidated financial statements for additional information regarding Preferred Units.

The following table summarizes the net ~~increase (decrease)~~change in cash for the six months ended June 30, ~~2018,~~2019 and ~~2017:~~2018:

Six Months Ended
June 30,

(in thousands)

2018

2017

Change

% Change

Net cash provided by operating activities

$
9,976

$
9,326

$
650

7%

Net cash used in investing activities

(11,818
)

(9,140
)

(2,678
)

29%

Net cash provided by (used in) financing activities

527

(2,059
)

2,586

126%

Net decrease in cash and cash equivalents

$
(1,315
)

$
(1,873
)

$
558

30%

	Six Months Ended June 30,									%
(in thousands)	2019			2018			Change			Change
Operating activities
Net cash provided by operating activities	$	4,491		$	9,976		$	(5,485	)		(55	%)
Investing activities
Acquisitions of oil and natural gas properties		(3,262	)		(9,257	)		5,995			65	%
Additions to oil and natural gas properties		(5,085	)		(3,724	)		(1,361	)		(37	%)
Proceeds from sales of oil and natural gas properties		32,514			1,163			31,351			2696	%
Net cash provided by (used in) investing activities		24,167			(11,818	)		35,985			304	%
Financing activities
Proceeds from line of credit		7,000			7,000			—			0	%
Payments on line of credit		(34,000	)		(19,000	)		(15,000	)		(79	%)
Proceeds from sale of Class B convertible preferred units, net of offering costs		—			14,878			(14,878	)		(100	%)
Other		(1,600	)		(2,351	)		751			32	%
Net cash (used in) provided by financing activities		(28,600	)		527			(29,127	)		(5527	%)
Change in cash and cash equivalents	$	58		$	(1,315	)	$	1,373			104	%

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

Investing ~~Activities.~~and financing activities. The change in ~~net~~investing and financing cash ~~used in investing activities~~flows for the periods compared was primarily attributable to:

~~Financing Activities.~~ ~~The change in net cash provided by financing activities was primarily attributable to:~~

See Note 11 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 financial 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, ~~2018.~~2019. 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, ~~2018,~~2019, 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 control over financial reporting, which do not have a material effect on our overall internal control over financial reporting.

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 ~~significant~~material legal or governmental proceedings ~~against us, or contemplated to be brought~~ against us under the various environmental protection statutes to which we are subject.

~~There~~Except for the risk factor discussed below, there have been no material changes with respect to the risk factors disclosed in our Annual Report for the year ended December 31, ~~2017.~~2018.

We may not be able to maintain our listing on the NASDAQ Global Select Market, which could have a material adverse effect on us and our unitholders.

NASDAQ has established certain standards for the continued listing of a security on the NASDAQ Global Select Market. The standards for continued listing include, among other things, that the minimum bid price for the listed securities not fall below $1.00 per share for a period of 30 consecutive days.

On March 26, 2019, the Partnership received a deficiency letter from the Listing Qualifications Department (the “Staff”) of the NASDAQ Stock Market notifying the Partnership that, for the last 30 consecutive business days, the bid price for the Partnership’s common units had closed below the minimum $1.00 per unit requirement for continued inclusion on the NASDAQ Global Select Market pursuant to NASDAQ Listing Rule 5450(a)(1) (the “Bid Price Rule”). In accordance with NASDAQ rules, the Partnership has been provided an initial period of 180 calendar days, or until September 23, 2019 (the “Compliance Date”), to regain compliance with the Bid Price Rule. If, at any time before the Compliance Date, the bid price for the Partnership’s common units closes at $1.00 or more for a minimum of 10 consecutive business days, the Staff will provide written notification to the Partnership that it complies with the Bid Price Rule.

If the Partnership does not regain compliance with the Bid Price Rule by the Compliance Date, the Partnership may be eligible for an additional 180 calendar day compliance period. To qualify, the Partnership would need to provide written notice of its intention to cure the deficiency during the additional compliance period, which could include a reverse unit split, if necessary, provided that it meets the continued listing requirement for the market value of publicly held shares and all other initial listing standards, with the exception of the bid price requirement.

If the Partnership does not regain compliance with the Bid Price Rule by the Compliance Date and is not eligible for an additional compliance period at that time, the Staff will provide written notification to the Partnership that its common units may be delisted. At that time, the Partnership may appeal the Staff’s delisting determination to a NASDAQ Listing Qualifications Panel.

Any such delisting could adversely affect the market liquidity of our units and the market price of our units could decrease. A delisting could adversely affect our ability to obtain financing for our operations or result in a loss of confidence by investors, customers, suppliers or employees.

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	Ticker symbol(s)	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	MCEP	NASDAQ Global Select Market

Large accelerated filer	☐		Accelerated filer	☐

Non-accelerated filer	☐☒	~~(Do not check if a smaller reporting company)~~	Smaller reporting company	☒

Emerging Growth Company	☐

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		9

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		23
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		3031
ITEM 4. CONTROLS AND PROCEDURES		3031

PART II
OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		31
ITEM 1A. RISK FACTORS		31
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		3132
ITEM 3. DEFAULTS UPON SENIOR SECURITIES		3132
ITEM 4. MINE SAFETY DISCLOSURES		3132
ITEM 5. OTHER INFORMATION		3132
ITEM 6. EXHIBITS		3233

Signatures		3334

	Number of Common Units
Approved and authorized awards		3,514,000
Unrestricted units granted		(~~1,300,538~~1,350,538	)
Restricted units granted, net of forfeitures		(399,424	)
Equity-settled phantom units granted, net of forfeitures		(~~830,669~~1,490,669	)
Awards available for future grant		~~983,369~~273,369

	Number of Restricted Units			Average Grant Date Fair Value per Unit
Outstanding at December 31, 2017		6,362		$	5.42
Units granted		—			—
Units vested		(6,362	)		5.42
Units forfeited		—			—
Outstanding at June 30, 2018		—		$	—

(in thousands)
Remaining 2018	$	241
2019		413
2020		418
2021		423
Total	$	1,495

(in thousands)	Classification	Six Months Ended June 30, 2019		Year Ended December 31, 2018
Assets
Operating	Other property and equipment	$	1,029	$	—
Total lease assets		$	1,029	$	—

Liabilities
Current operating	Other current liabilities	$	415	$	—
Non-current operating	Other long-term liabilities		675		—
Total lease liabilities		$	1,090	$	—

(in thousands)	Operating Leases
Remaining 2019	$	236
2020		469
2021		472
Total lease maturities		1,177
Less: interest		87
Present value of lease liabilities	$	1,090

Exhibit No.		Exhibit Description


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 Chief Financial Officer

32.1+		Section 1350 Certificate of Chief Executive Officer

32.2+		Section 1350 Certificate of Chief 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

July 31, ~~2018~~2019	By:	/s/ Jeffrey R. Olmstead
		Jeffrey R. Olmstead
		Chief Executive Officer


July 31, ~~2018~~2019	By:	/s/s/ Philip R. Houchin
		Philip R. Houchin
		Chief Financial Officer