UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June 30, 2020~~March 31, 2021


☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-16317

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

TEXAS		95-4079863

(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

~~717 TEXAS AVENUE, SUITE 2900~~111 E. 5^th Street, Suite 300 ~~HOUSTON, TEXAS~~Fort Worth, Texas		~~77002~~76102
(Address of principal executive offices)		(Zip Code)

~~(713) 236-7400~~(817) 529-0059

(Registrant’s telephone number, including area code)

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

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, Par Value $0.04 per share	MCF	NYSE American

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

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


Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☒
Emerging growth company	☐

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 Exchange Act). Yes ☐ No ☒

The total number of shares of common stock, par value $0.04 per share, outstanding as of ~~August 14, 2020~~May 10, 2021 was ~~133,038,930.~~200,686,671.

Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE ~~SIX~~THREE MONTHS ENDED ~~JUNE 30, 2020~~MARCH 31, 2021

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		Page
PART I—FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets ~~(unaudited)~~ as of ~~June 30, 2020~~March 31, 2021 (unaudited) and December 31, ~~2019~~2020	3
	Consolidated Statements of Operations (unaudited) for the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~	4
	Consolidated Statements of Cash Flows (unaudited) for the ~~six~~three months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~	5
	Consolidated Statement of Shareholders’ Equity (unaudited) for the ~~six~~three months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~	6
	Notes to the Consolidated Financial Statements (unaudited)	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2629
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	4041
Item 4.	Controls and Procedures	4041

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	4142
Item 1A.	Risk Factors	4142
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4142
Item 3.	Defaults upon Senior Securities	4142
Item 4.	Mine Safety Disclosures	42
Item 5.	Other Information	4243
Item 6.	Exhibits	4243

Unless the context requires otherwise or unless otherwise noted, all references in this Quarterly Report on Form 10-Q to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and its wholly owned subsidiaries.

Table of Contents

Item 1. Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except number of shares)


	June 30,		December 31,		March 31,		December 31,
	2020		2019		2021		2020


		(unaudited)				(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	404	$	1,624	$	1,596	$	1,383
Accounts receivable, net		25,672		39,567		54,330		37,862
Prepaid expenses		1,363		1,191		3,778		3,360
Current derivative asset		16,826		3,819		2,294		2,996
Inventory		1,710		186		535		442
Deposits and other						100		763
Total current assets		45,975		46,387		62,633		46,806
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, successful efforts method of accounting:
Proved properties		1,315,040		1,306,916		1,534,757		1,274,508
Unproved properties		20,901		27,619		16,280		16,201
Other property and equipment		1,668		1,655
Accumulated depreciation, depletion and amortization		(1,206,957)		(1,045,070)
Other property & equipment						1,912		1,669
Accumulated depreciation, depletion, amortization and impairment						(1,197,904)		(1,190,475)
Total property, plant and equipment, net		130,652		291,120		355,045		101,903
OTHER NON-CURRENT ASSETS:
Investments in affiliates		6,879		6,766		6,793		6,793
Long-term derivative asset		4,395		357		128		497
Right-of-use lease assets		5,691		5,885		7,404		5,448
Debt issuance costs		1,939		3,311		2,493		1,782
Deposits						1,813		7,038
Total other non-current assets		18,904		16,319		18,631		21,558
TOTAL ASSETS	$	195,531	$	353,826	$	436,309	$	170,267

CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	77,143	$	104,593	$	109,823	$	83,970
Current derivative liability		908		3,951		8,733		1,317
Current asset retirement obligations		2,291		2,003		4,197		4,249
Total current liabilities		80,342		110,547		122,753		89,536
NON-CURRENT LIABILITIES:
Long-term debt		82,537		72,768		101,969		12,369
Long-term derivative liability		917		2,020		5,258		1,648
Asset retirement obligations		45,581		49,662		109,960		48,523
Lease liabilities		2,156		2,789		3,482		2,624
Deferred tax liability		376		—
Total non-current liabilities		131,567		127,239		220,669		65,164
TOTAL LIABILITIES		211,909		237,786		343,422		154,700
COMMITMENTS AND CONTINGENCIES (NOTE 12)
SHAREHOLDERS’ EQUITY (DEFICIT):
Series C contingent convertible preferred stock, $0.04 par value, no shares authorized, issued and outstanding at June 30, 2020 and 2,700,000 shares authorized, issued and outstanding at December 31, 2019		—		108
Common stock, $0.04 par value, 400 million shares authorized, 132,067,369 shares issued and 131,996,757 shares outstanding at June 30, 2020, 128,985,146 shares issued and 128,977,816 shares outstanding at December 31, 2019		5,271		5,148
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 400,000,000 shares authorized, 199,393,595 shares issued and 199,267,434 shares outstanding at March 31, 2021, 173,830,390 shares issued and 173,737,816 shares outstanding at December 31, 2020						7,963		6,941
Additional paid-in capital		472,814		471,778		615,949		535,192
Treasury shares at cost (70,612 shares at June 30, 2020 and 7,330 shares at December 31, 2019)		(198)		(18)
Treasury shares at cost (126,161 shares at March 31, 2021 and 92,574 shares at December 31, 2020)						(414)		(248)
Accumulated deficit		(494,265)		(360,976)		(530,611)		(526,318)
Total shareholders’ equity (deficit)		(16,378)		116,040
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY (DEFICIT)	$	195,531	$	353,826
Total shareholders’ equity						92,887		15,567
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY					$	436,309	$	170,267

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)


	Three Months Ended				Six Months Ended				Three Months Ended
	June 30,				June 30,				March 31,
	2020		2019		2020		2019		2021		2020

	(unaudited)				(unaudited)				(unaudited)
REVENUES:
Oil and condensate sales	$	7,930	$	7,439	$	30,712	$	13,845	$	36,993	$	22,782
Natural gas sales		6,618		3,857		14,789		9,499		14,492		8,170
Natural gas liquids sales		3,294		1,466		6,915		3,429		8,281		3,621
Other operating revenues										184		—
Total revenues		17,842		12,762		52,416		26,773		59,950		34,573
EXPENSES:
Operating expenses		17,139		5,694		38,621		10,886		27,478		19,257
Exploration expenses		11,173		249		11,571		473		196		398
Depreciation, depletion and amortization		5,092		7,573		17,946		15,129		9,143		12,854
Impairment and abandonment of oil and gas properties		—		1,247		145,878		1,834
Impairment and abandonment of oil and natural gas properties										3		145,878
General and administrative expenses		5,713		4,456		11,138		9,461		11,359		7,651
Total expenses		39,117		19,219		225,154		37,783		48,179		186,038
OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates, net of income taxes		(173)		427		113		457
Gain from investment in affiliates, net of income taxes										—		286
Gain from sale of assets		4,406		421		4,433		409		217		27
Interest expense		(2,151)		(1,079)		(3,365)		(2,171)		(1,197)		(1,213)
Gain (loss) on derivatives, net		(8,804)		2,065		37,895		(813)		(16,080)		46,699
Other income		332		89		1,136		3		1,535		805
Total other income (expense)		(6,390)		1,923		40,212		(2,115)		(15,525)		46,604
NET LOSS BEFORE INCOME TAXES		(27,665)		(4,534)		(132,526)		(13,125)		(3,754)		(104,861)
Income tax provision		(369)		(427)		(763)		(454)		(539)		(394)
NET LOSS	$	(28,034)	$	(4,961)	$	(133,289)	$	(13,579)	$	(4,293)	$	(105,255)
NET LOSS PER SHARE:
Basic	$	(0.21)	$	(0.15)	$	(1.01)	$	(0.40)	$	(0.02)	$	(0.80)
Diluted	$	(0.21)	$	(0.15)	$	(1.01)	$	(0.40)	$	(0.02)	$	(0.80)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		131,449		33,909		131,394		33,840		192,271		131,338
Diluted		131,449		33,909		131,394		33,840		192,271		131,338

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

Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Six Months Ended				Three Months Ended
	June 30,				March 31,
	2020		2019		2021		2020

	(unaudited)				(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(133,289)	$	(13,579)	$	(4,293)	$	(105,255)
Adjustments to reconcile net loss to net cash provided by operating activities:
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		17,946		15,129		9,143		12,854
Impairment of oil and natural gas properties		145,878		1,079		—		145,878
Exploration expenditures - dry hole costs		10,878		—
Amortization of debt issuance costs		1,372		—		178		177
Deferred income taxes		—		424
Gain on sale of assets		(4,433)		(409)		(217)		(27)
Gain from investment in affiliates		(113)		(457)		—		(286)
Stock-based compensation		616		1,637		1,779		350
Unrealized loss (gain) on derivative instruments		(21,192)		2,078
Non-cash mark-to-market loss (gain) on derivative instruments						13,639		(41,391)
Changes in operating assets and liabilities:
Decrease in accounts receivable & other receivables		13,614		1,530
Decrease (increase) in prepaids		(172)		298
Decrease (increase) in accounts receivable & other receivables						(12,139)		10,761
Increase in prepaid expenses						(194)		(245)
Increase in inventory		(1,560)		—		(93)		(1)
Increase (decrease) in accounts payable & advances from joint owners		(17,132)		8,592		11,016		(14,326)
Decrease in other accrued liabilities		(4,636)		(350)
Decrease (increase) in income taxes receivable, net		281		(424)
Increase (decrease) in income taxes payable, net		119		(258)
Increase (decrease) in deposits and other		36		(392)
Net cash provided by operating activities	$	8,213	$	14,898
Increase (decrease) in other accrued liabilities						4,304		(1,951)
Decrease in income taxes receivable, net						—		241
Increase in income taxes payable, net						578		192
Decrease (increase) in deposits and other						7,038		(7,219)
Net cash provided by (used in) operating activities					$	30,739	$	(248)
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas exploration and development expenditures	$	(19,719)	$	(14,604)	$	(1,862)	$	(9,492)
Additions to furniture & equipment		(77)		(17)
Sale of oil & gas properties		339		—
Acquisition of oil & natural gas properties						(117,555)		—
Sale of oil & natural gas properties						199		5
Write off of fully depreciated oil & natural gas properties						(307)		—
Net cash used in investing activities	$	(19,457)	$	(14,621)	$	(119,525)	$	(9,487)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	$	55,000	$	73,548
Repayments under credit facility		(48,600)		(73,548)
PPP loan		3,369		—
Borrowings under Credit Agreement					$	127,000	$	37,000
Repayments under Credit Agreement						(37,400)		(27,000)
Net proceeds (costs) from equity offering		435		(41)		453		(47)
Purchase of treasury stock		(180)		(236)		(166)		(157)
Net cash provided by (used in) financing activities	$	10,024	$	(277)
Debt issuance costs						(888)		—
Net cash provided by financing activities					$	88,999	$	9,796
NET CHANGE IN CASH AND CASH EQUIVALENTS	$	(1,220)	$	—	$	213	$	61
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		1,624		—		1,383		1,624
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	404	$	—	$	1,596	$	1,685

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY ~~(DEFICIT)~~

For the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021

(in thousands, except number of shares)


	Series C						Additional						Total					Additional						Total
	Preferred Stock			Common Stock			Paid-in		Treasury		Accumulated		Shareholders’		Common Stock			Paid-in		Treasury		Accumulated		Shareholders’
	Shares	Amount		Shares	Amount		Capital		Stock		Deficit		Equity (Deficit)		Shares	Amount		Capital		Stock		Deficit		Equity

				(unaudited)											(unaudited)
Balance at December 31, 2019	2,700,000	$	108	128,977,816	$	5,148	$	471,778	$	(18)	$	(360,976)	$	116,040
Equity offering costs	—		—	—		—		(47)		—		—		(47)
Balance at December 31, 2020															173,737,816	$	6,941	$	535,192	$	(248)	$	(526,318)	$	15,567
Equity offering - common stock															117,000		5		448		—		—		453
Mid-Con Acquisition															25,409,164		1,015		78,514		—		—		79,529
Treasury shares at cost	—		—	(49,474)		—		—		(157)		—		(157)	(33,587)		—		—		(166)		—		(166)
Restricted shares activity	—		—	77,485		3		(3)		—		—		—	37,041		2		(2)		—		—		—
Stock-based compensation	—		—	—		—		350		—		—		350	—		—		1,797		—		—		1,797
Net loss	—		—	—		—		—		—		(105,255)		(105,255)	—		—		—		—		(4,293)		(4,293)
Balance at March 31, 2020	2,700,000	$	108	129,005,827	$	5,151	$	472,078	$	(175)	$	(466,231)	$	10,931
Equity offering - common stock	—		—	155,029		6		477		—		—		483
Conversion of preferred stock to common stock	(2,700,000)		(108)	2,700,000		108		—		—		—		—
Treasury shares at cost	—		—	(13,808)		—		—		(23)		—		(23)
Restricted shares activity	—		—	149,709		6		(6)		—		—		—
Stock-based compensation	—		—	—		—		265		—		—		265
Net loss	—		—	—		—		—		—		(28,034)		(28,034)
Balance at June 30, 2020	—	$	—	131,996,757	$	5,271	$	472,814	$	(198)	$	(494,265)	$	(16,378)
Balance at March 31, 2021															199,267,434	$	7,963	$	615,949	$	(414)	$	(530,611)	$	92,887

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020

(in thousands, except number of shares)


				Additional						Total		Series C						Additional						Total
	Common Stock			Paid-in		Treasury		Accumulated		Shareholders’		Preferred Stock			Common Stock			Paid-in		Treasury		Accumulated		Shareholders’
	Shares	Amount		Capital		Stock		Deficit		Equity (Deficit)		Shares	Amount		Shares	Amount		Capital		Stock		Deficit		Equity

	(unaudited)											(unaudited)
Balance at December 31, 2018	34,158,492	$	1,573	$	339,981	$	(129,030)	$	(72,135)	$	140,389
Equity offering costs	—		—		(86)		—		—		(86)
Balance at December 31, 2019												2,700,000	$	108	128,977,816	$	5,148	$	471,778	$	(18)	$	(360,976)	$	116,040
Equity offering - common stock												—		—	—		—		(47)		—		—		(47)
Treasury shares at cost	(49,415)		—		—		(186)		—		(186)	—		—	(49,474)		—		—		(157)		—		(157)
Restricted shares activity	307,650		12		(12)		—		—		—	—		—	77,485		3		(3)		—		—		—
Stock-based compensation	—		—		1,052		—		—		1,052	—		—	—		—		350		—		—		350
Net loss	—		—		—		—		(8,618)		(8,618)	—		—	—		—		—		—		(105,255)		(105,255)
Balance at March 31, 2019	34,416,727	$	1,585	$	340,935	$	(129,216)	$	(80,753)	$	132,551
Equity offering proceeds	—		—		45		—		—		45
Treasury shares at cost	(16,133)		—		—		(50)		—		(50)
Restricted shares activity	42,249		2		(2)		—		—		—
Stock-based compensation	—		—		585		—		—		585
Net loss	—		—		—		—		(4,961)		(4,961)
Balance at June 30, 2019	34,442,843	$	1,587	$	341,563	$	(129,266)	$	(85,714)	$	128,170
Balance at March 31, 2020												2,700,000	$	108	129,005,827	$	5,151	$	472,078	$	(175)	$	(466,231)	$	10,931

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and Business

Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a ~~Houston,~~Fort Worth, Texas based independent oil and natural gas ~~company, with regional offices in Oklahoma City and Stillwater, Oklahoma.~~company. The Company’s business is to maximize production and cash flow from its onshore properties primarily located in its Midcontinent, Permian, Rockies and other smaller onshore areas and its offshore properties in the shallow waters of the Gulf of Mexico ~~(“GOM”) and onshore Texas, Oklahoma, Louisiana and Wyoming properties~~ and use that cash flow to explore, develop and acquire oil and natural gas properties across the United States.

The following table lists the Company’s primary producing ~~areas~~regions as of ~~June 30, 2020:~~March 31, 2021:

~~Location~~Region		Formation
~~Gulf of Mexico~~Midcontinent		Cleveland, Bartlesville, Mississippian, Woodford and others
Permian		San Andres, Yeso, Bone Springs, Wolfcamp and others
Rockies		Sussex, Shannon, Muddy, Phosphoria, Embar-Tensleep, Madison and others
Other		Woodbine, Lewisville, Buda, Georgetown, Eagleford and Offshore ~~Louisiana -~~Gulf of Mexico properties in water depths off of Louisiana in less than 300 feet
~~Mid-continent Region of Oklahoma~~		~~Mississippian, Woodford, Oswego, Cottage Grove, Chester and Red Fork~~
~~Southern Delaware Basin, Pecos County, Texas~~		~~Wolfcamp A and B~~
~~Madison and Grimes counties, Texas~~		~~Woodbine / Upper Lewisville~~
~~Zavala and Dimmit counties, Texas~~		~~Buda / Eagle Ford / Georgetown~~
~~San Augustine County, Texas~~		~~Haynesville shale, Mid Bossier shale and James Lime~~
~~Other Texas Gulf Coast~~		~~Conventional and smaller unconventional formations~~
~~Weston County, Wyoming~~		~~Muddy Sandstone~~
~~Sublette County, Wyoming~~		~~Jonah Field~~ ⁽¹⁾

~~(1)~~

Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this equity investment is not included in the Company’s reported production results for all periods shown in this report.

From the Company’s initial entry into the Southern Delaware Basin in 2016 and through mid-2019, the Company was focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas. In January 2020, the Company brought one West Texas well online but suspended further drilling in the area in response to the dramatic decline in oil prices during the quarter. As of June 30, 2020, the Company was producing from eighteen wells over its approximate 16,200 gross operated (7,500 company net) acre position in West Texas, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

During the fourth quarter of 2019, the Company closed on the acquisitions of certain producing assets and undeveloped acreage of Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”), and established an additional core strategic area, located primarily in the Central Oklahoma and Western Anadarko basins. These acquisitions were transformative, as production from these acquisitions represented approximately 70% of the Company’s total net production for the three and six months ended June 30, 2020.

Impact of the COVID-19 Pandemic

~~A novel strain of the~~The coronavirus (“COVID-19”) surfaced in late 2019 and has spread, and continues to spread, around the world, including to the United States. In March 2020, the World Health Organization declared COVID-19 a pandemic, and the President of the United States declared the COVID-19 outbreak a national emergency. The COVID-19 pandemic has significantly affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the COVID-19 pandemic has resulted in travel restrictions, business closures and other restrictions that have disrupted the demand for oil throughout the world and, when combined with the oil supply increase attributable to the battle for market share among the Organization of Petroleum Exporting Countries (“OPEC”), Russia and other oil producing nations, resulted in oil prices declining significantly beginning in late February 2020. While there has been a modest recovery in oil prices in recent months, the length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil ~~demand, which has negatively impacted the Company’s results of operations and planned 2020 capital activities.~~demand. Due to the extreme volatility in oil prices and the impact of the COVID-19 pandemic on the financial condition of the Company’s upstream peers, the Company ~~has~~ suspended ~~any further plans for~~its onshore drilling program in ~~2020.~~the Southern Delaware Basin in the first quarter of 2020 and further suspended all drilling in the second quarter of 2020 and has focused since then on certain measures that included, but were not limited to, the following:

●

work from home initiatives for all but critical staff and the implementation of social distancing measures;

●

a company-wide effort to cut costs throughout the Company’s operations;

●

utilization of the Company’s available storage capacity to temporarily store a portion of its production for later sale at higher prices when advantageous to do so;

●

suspension of all drilling from the second-half of 2020 through the quarter ended March 31, 2021, with the expectation to recommence value added drilling in 2021;

●

potential acquisitions of PDP-heavy assets, with attractive, discounted valuations, in stressed/distressed scenarios or from non-natural owners like investment or lender firms that obtained ownership through a corporate restructuring.

Capital Allocation Strategy

From the Company’s initial entry into the Southern Delaware Basin in 2016 and through early 2019, the Company was focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas. In the first quarter of 2020, the Company suspended further drilling in this area in response to the dramatic decline in oil prices and further suspended all drilling in the second quarter of 2020. As of March 31, 2021, the Company was producing from eighteen wells over its approximate 16,200 gross operated (7,500 company net) acre position in West Texas, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

The Company’s planned 2021 capital expenditure budget has increased to $24 - $27 million from previous guidance of $13 - $16 million for recompletions, facility upgrades, waterflood development and select drilling in West Texas (expected 1.5 net locations, 3 gross locations), among other things. The increase in planned capital expenditures

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~~Management Services~~reflects, in part, development opportunities in the Company’s recently acquired properties as part of the Mid-Con Acquisition and the Silvertip Acquisition (both as defined below), coupled with recent strength in crude oil prices. The capital expenditure program will continue to be evaluated for revision throughout the year. During the three months ended March 31, 2021, the Company incurred capital expenditures of approximately $1.6 million primarily related to redevelopment activities of newly acquired properties in its Midcontinent region. The Company believes that its internally generated cash flow will be more than adequate to fund its initial capital expenditure budget and any increase to such initial 2021 capital expenditure budget, when and if such increase is deemed appropriate. The Company plans to retain the flexibility to be more aggressive in its drilling plans should results exceed expectations, commodity prices continue to improve or if the Company reduces drilling and completion costs in certain areas, thereby making an expansion of its drilling program an appropriate business decision.

The Company plans to continue to make balance sheet strength a priority in 2021 and intends to continue to evaluate certain acquisition opportunities that may arise in this challenging commodity price environment. The Company will also aim to pursue additional “fee for service” opportunities similar to that entered into with Mid-Con (defined below) in June 2020 prior to its later acquisition, as well as pursue growth through the acquisition of PDP-heavy assets. Any excess cash flow will likely be used to reduce borrowings outstanding under the Company’s Credit Agreement (as defined below). The Company intends to keenly focus on continuing to reduce lease operating costs on its legacy and newly-acquired assets, reducing general and administrative expenses, improving cash margins and lowering its exposure to asset retirement obligations through the possible sale of non-core properties.

On ~~June 5, 2020,~~January 21, 2021, the Company ~~announced~~closed on the ~~addition~~acquisition of a new corporate strategy that includes offering a property management service (or a “fee for service”) for oil and gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs. As part of this service offering, the Company entered into a Management Services Agreement with Mid-Con Energy Partners, LP (“Mid-Con”) ~~(Nasdaq: MCEP)~~, ~~effective July 1, 2020, to provide operational services as operator~~in an all-stock merger transaction in which Mid-Con became a direct, wholly owned subsidiary of ~~record on Mid-Con’s oil and gas properties in exchange for an annual services fee~~Contango (the “Mid-Con Acquisition”). A total of $4 million, paid ratably over the twelve month period, plus reimbursement of certain costs and expenses, a deferred fee of $166,666 per month for each month that the agreement is in effect (not to exceed $2 million), to be paid in a lump sum upon termination of the agreement, and warrants to purchase a minority equity ownership in Mid-Con (with amount and terms of the warrants to be disclosed upon execution of the Warrant Agreement). Both the Company and Mid-Con and their employees have indemnification rights in this fee for service arrangement. As of June 4, 2020, John C. Goff, Chairman of the Board of Directors of the Company, beneficially owned approximately 56% of the common units in Mid-Con, and Travis Goff, John C. Goff’s son and the President of Goff Capital, Inc., serves on the board of directors of the general partner of Mid-Con.

~~Authorized Shares of Common Stock and Conversion of Series C Contingent Convertible Preferred Stock~~

On June 10, 2020, the Company filed an amendment (the “Charter Amendment”) to its Amended and Restated Certificate of Formation with the Secretary of State of the State of Texas to increase the number of authorized25,409,164 shares of common stock, par value of $0.04 per share (the “common stock”), of the Company from 200,000,000 shares to 400,000,000 shares. The Charter Amendment and the conversion of 2,700,000 shares of the Company’s Series C contingent convertible preferred stock, par value $0.04 per share (the “Series C contingent convertible preferred stock”), into 2,700,000 shares of the Company’sContango common stock were ~~approved by~~issued as consideration in the ~~stockholders~~Mid-Con Acquisition. Effective upon the closing of the ~~Company on June 8, 2020, at~~Mid-Con Acquisition, the Company’s borrowing base under its Credit Agreement increased from $75.0 million to $130.0 million, with an automatic $10.0 million reduction in the borrowing base on March 31, 2021. See Note 3 – “Acquisitions” and Note 10 – “Long-Term Debt” for further details.

On February 1, 2021, the Company closed on the acquisition of certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in West Texas and New Mexico (collectively the “Silvertip Acquisition”) for aggregate consideration of approximately $58.0 million. After customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 Annual Meeting of Stockholders. The shares of Series C contingent convertible preferred stock were issued in a private placement completed concurrently with a private placement of common stock in December of 2019. Purchasers ofand the ~~Series C contingent convertible preferred stock included John Goff, Wilkie Colyer and Farley Dakan,~~closing date, the ~~Company’s current president.~~

~~Open Market Sale Agreement~~net consideration paid was approximately $53.2 million. See Note 3 – “Acquisitions” for more information.

On ~~June 24, 2020,~~May 3, 2021, the Company entered into ~~an Open Market Sale Agreement (the “Sale Agreement”) among~~ the ~~Company and Jefferies LLC (the “Sales Agent”). Pursuant~~Fifth Amendment to the ~~terms of the Sale~~Credit Agreement ~~the Company may sell from time to time through the Sales Agent, shares of~~which provides for, among other things, an increase in the Company’s ~~common stock, having an aggregate public offering price of up~~borrowing base from $120.0 million to ~~$100,000,000 (the “Shares”)~~$250.0 million, effective May 3, 2021, expands the bank group from nine to eleven banks and includes less restrictive hedge requirements and certain modifications to financial covenants. The Company intends to use the net proceeds from the offering, after deducting the Sales Agent’s commission and the Company’s offering expenses, to repay borrowings under its Credit Agreement (as defined below) andSee Note 13 – “Subsequent Events” for general corporate purposes, including, but not limited to, acquisitions and exploratory drilling. Under the Sale Agreement, the Company sold 155,029 Shares during the three months ended June 30, 2020 for net proceeds of $0.5 million.further details.

2. Summary of Significant Accounting Policies

The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 (“~~2019~~2020 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the ~~2019~~2020 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this interim report.

Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2020 Form 10-K. These unaudited interim

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~~The consolidated financial statements should be read in conjunction with the 2019 Form 10-K. These unaudited interim~~ consolidated results of operations for the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 are not necessarily indicative of the results that may be expected for the full year ending December 31, ~~2020.~~2021.

The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The Company’s investment in Exaro Energy III LLC (“Exaro”), through its wholly owned subsidiary, Contaro Company, is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results, production or reserves in those reported for the Company’s consolidated results of operations.

Certain amounts in prior-period financial statements have been reclassified to conform to the current period’s presentation. On the consolidated statements of operations, the Company’s working interest percentage share of the overhead billed to the 8/8s joint account for wells it operates has been reclassified from operating expenses to general and administrative expenses.

Oil and Natural Gas Properties - Successful Efforts

The Company’s application of the successful efforts method of accounting for its oil and natural gas exploration and production activities requires judgment as to whether particular wells are developmental or exploratory, since ~~exploratory~~lease acquisition costs and all development costs are capitalized, whereas exploratory drilling costs are continuously capitalized until the ~~costs related to exploratory wells that~~results are ~~determined to not have~~determined. If proved reserves ~~must be expensed, whereas developmental~~are not discovered, the drilling costs are ~~capitalized.~~ expensed as exploration costs. Other exploration related costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred.

The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive, ~~and~~but then actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment and/or impairment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil or natural gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. During the quarter ended June 30, 2020, the Company drilled an unsuccessful exploratory well in the Gulf of Mexico, resulting in a charge of $10.9 million for drilling and prospect costs included in “Exploration expenses” in the Company’s consolidated statements of operations.

The evaluation of oil and natural gas leasehold acquisition costs included in unproved properties for write-off or impairment requires management’s judgment ofon exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Impairment of Long-Lived Assets

Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a ~~region~~field-by-field basis to the unamortized capitalized cost of the ~~asset.~~assets in that field. If the estimated future undiscounted cash flows, based on the Company’s estimate of future reserves, oil and natural gas prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. Additionally, the Company may use appropriate market data to determine fair value. No impairment of proved properties was recorded during the three months ended March 31, 2021.

In the first quarter of 2020, the COVID-19 pandemic and the resulting deterioration in the global demand for oil, combined with the failure by OPEC and Russia to reach an agreement on lower production quotas until April 2020, caused a dramatic increase in the supply of oil, a corresponding decrease in commodity prices, and reduced the demand for all commodity products. Consequently, during the three months ended March 31, 2020, the Company recorded a $143.3 million non-cash charge for proved property impairment of its onshore properties related to the dramatic decline in commodity prices, ~~as discussed above,~~ the “PV-10” (present value, discounted at a 10% rate) of its proved reserves, and the associated change in its ~~current~~then forecasted development plans for its proved, undeveloped locations. The Company conducted an impairment test for the three months ended June 30, 2020, but no additional impairment was recorded. During the six months ended June 30, 2019, the company recognized $0.2 million in non-cash proved property impairment related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018.

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Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value of those properties, with any such impairment charged to expense in the period. No impairment of unproved properties was recorded during the three months ended March 31, 2021. The Company recorded a $2.6 million non-cash charge for unproved impairment expense during the ~~six~~three months ended ~~June 30,~~March 31, 2020 ~~all of which was recorded during the first quarter of 2020. The impairment primarily~~ related to ~~acquired~~expiring leases in the Company’s ~~Central Oklahoma and Western Anadarko regions which will be expiring in 2020, and which the Company has no current plans to develop~~

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as a result of the current commodity price environment. The Company recognized non-cash impairment expense of approximately $0.4 million and approximately $0.9 million for three and six months ended June 30, 2019, respectively, related to impairment of certain unproved properties primarily due to expiring leases.Midcontinent region.

Net Loss Per Common Share

Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. The Company excluded ~~506,325~~42,518 shares or units, and ~~414,383~~366,749 shares or units of potentially dilutive securities during the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020, respectively, ~~as they were antidilutive. For the three and six months ended June 30, 2019, the company excluded 648,170 shares or units and 561,164 shares or units, respectively, of potentially dilutive securities,~~ as they were antidilutive.

Subsidiary Guarantees

Contango Oil & Gas Company, as the parent company of ~~certain~~its subsidiaries, ~~(the “Parent Company”), has~~ filed a registration statement on Form S-3 on December 18, 2020 with the SEC to register, among other securities, debt securities that the ~~Parent~~ Company may issue from time to time. ~~Any such debt securities would likely be guaranteed on a joint~~Contango Resources, Inc., Contango Midstream Company, Contango Operators, Inc., Contaro Company, Contango Alta Investments, Inc. and ~~several and full and unconditional basis by each~~any other of the ~~Parent~~ Company’s ~~current subsidiaries and any~~ future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”)~~. Each~~ are co-registrants with the Company under the registration statement, and the registration statement also registered guarantees of ~~the current~~debt securities by such Subsidiary Guarantors. The Subsidiary Guarantors ~~is wholly owned~~are wholly-owned by the ~~Parent~~ Company, either directly or ~~indirectly.~~indirectly, and any guarantee by the Subsidiary Guarantors will be full and unconditional. The ~~Parent~~ Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the ~~Parent~~ Company. ~~The Parent~~Finally, the Company’s ~~wholly owned~~wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the ~~Parent~~ Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party.

Revenue Recognition

Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the Company’s gas at the inlet of the plant, and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product.

Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company receives purchaser statements from the majority of its customers, but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. Based upon the Company’s past experience with its current purchasers and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently.

The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process. The Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment.

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Leases

The Company recognizes a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet. The Company does not include leases with an initial term of less than twelve months ~~or less~~ on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated ~~statement~~statements of operations. The Company has modified procedures to its existing internal controls to review any new contracts which contain a physical asset on a quarterly basis and determine if an arrangement is, or contains, a lease at inception. The Company will continue to review all new or modified contracts on a quarterly basis for proper treatment. See Note 7 – “Leases” for additional information.

Recent Accounting Pronouncements

In June 2016, the FASB issued ASU 2016-13, – Financial Instruments –- Credit Losses ~~(“Topic 326”)~~(Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint interest billing receivables. Allowances are to be measured using a current expected credit loss model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. Initially, ASU 2016-13 was effective for all public companies for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The FASB subsequently issued ASU 2019-04 (“ASU 2019-04”):, Codification Improvements to ~~Topic 326,~~ Financial Instruments –- Credit Losses ~~Topic 815,~~(Topic 326), Derivatives (Topic 815) and ~~Topic 825,~~ Financial Instruments (Topic 825) and ASU 2019-05 (“ASU 2019-05”):, Financial ~~Instruments-Credit~~Instruments - Credit Losses (Topic 326) –: Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to implementation of ASU 2016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. In November 2019, the FASB issued ASU 2019-10, – Financial Instruments –- Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates. This amendment deferred the effective date of ASU 2016-13 from January 1, 2020 to January 1, 2023 for calendar year-end smaller reporting companies, which includes the Company. The Company plans to defer the implementation of ASU 2016-13, and the related updates.

In November 2019, the FASB issued ASU 2019-12 – Income Taxes (“Topic 740”): Simplifying the Accounting for Income Taxes. The amendments in ASU 2019-12 are part of an initiative to reduce complexity in accounting standards and simplify the accounting for income taxes by removing certain exceptions from Topic 740 and making minor improvements to the codification. The amendments in this update are effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference LIBOR or another rate that is expected to be discontinued. ASU 2020-04 will be in effect through December 31, 2022. ~~We are~~In January 2021, the FASB issued ASU 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), which further clarifies certain topics in ASU 2020-04, such as expedients and exceptions. The Company is currently assessing the potential impact of ASU 2020-04 and ASU 2021-01 on ~~our~~its consolidated financial statements.

3. ~~Dispositions~~ Acquisitions

Mid-Con Acquisition

On ~~June 1,~~October 25, 2020, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement’) with Mid-Con and Mid-Con Energy GP, LLC, the general partner of Mid-Con (“Mid-Con GP”), pursuant to which Mid-Con would merge with and into Michael Merger Sub LLC, a Delaware limited liability company and a wholly-owned, direct subsidiary of the Company. The Mid-Con Acquisition, which closed on January 21, 2021, was unanimously approved by the ~~sale~~conflicts committee of ~~certain producing~~the board of directors of Mid-Con, by the full board of directors of Mid-Con, by the disinterested directors of the board of directors of the Company and ~~non-producing properties located~~was subject to shareholder and unitholder approvals and other customary conditions to closing. At the effective time of the Mid-Con Acquisition (the “Effective Time”), each common unit representing limited partner interests in ~~its Central Oklahoma~~Mid-Con issued and ~~Western Anadarko regions. These properties~~outstanding immediately prior to the Effective Time (other than treasury units or units held by Mid-Con GP) was converted automatically into the right to receive 1.75 shares of the Company’s common stock. A total of 25,409,164 shares of Contango common stock were ~~acquired~~issued as consideration in the ~~Will Energy acquisition and were sold in exchange for the buyer’s assumption~~Mid-Con Acquisition. As of January 21, 2021, John C. Goff, Chairman of the ~~plugging and abandonment liabilities~~Board of ~~these properties and revenue held in suspense. The Company recorded a gain of $4.2 million as a result~~Directors of the ~~buyer’s assumption~~Company, beneficially owned approximately 56.4% of the ~~asset retirement obligations associated with~~common units of Mid-Con, and Travis Goff, John C. Goff’s son and the ~~sold properties.~~

~~On April 1, 2020, the Company closed~~President of Goff Capital, Inc., served on the ~~sale~~board of certain non-producing properties located in its Central Oklahoma region. These properties were acquired in the White Star acquisition and were sold for approximately $0.5 million. The Company recorded a gain of $0.2 million as a resultdirectors of the ~~buyer’s assumption~~general partner of ~~the asset retirement obligations associated with the sold properties.~~Mid-Con. The

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Company’s senior management team is running the combined company, and Contango’s board of directors remains intact as the board of directors of the combined company. The combined company is headquartered in Fort Worth, Texas.

~~On June 10, 2019,~~The Mid-Con Acquisition was accounted for as a business combination using the acquisition method of accounting under FASB ASC 805, Business Combinations (“ASC 805”). Therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by the Company ~~sold certain minor, non-core operated assets located~~ in ~~Lavaca~~determining the fair value of the oil and ~~Wharton counties, Texas in exchange~~natural gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and natural gas reserves, expectations for the ~~buyer’s assumption~~timing and amount of ~~the~~future development and operating costs, future plugging and abandonment ~~liabilities~~costs and a risk adjusted discount rate. The preliminary purchase price assessment remains an ongoing process and is subject to change for up to one year subsequent to the closing of the ~~properties.~~ Mid-Con Acquisition.

The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date (in thousands):


	Purchase Price Allocation
Consideration:
Cash	$	14,520
Exchange ratio of Contango shares for Mid-Con common units		1.75
Contango common stock to be issued to Mid-Con unitholders		25,409
Issue price	$	3.13
Stock consideration		79,530
Payment of revolving credit facility		68,667
Total consideration	$	148,197

Fair value of liabilities assumed:
Accounts payable	$	8,892
Asset retirement obligations		28,252
Total fair value of liabilities assumed	$	37,144

Fair value of assets acquired:
Cash and cash equivalents	$	3,110
Accounts receivable		5,191
Current derivative asset		1,544
Prepaid expenses		225
Proved oil and natural gas properties		173,878
Other property and equipment		243
Other non-current assets		1,150
Total fair value of assets acquired	$	185,341

Silvertip Acquisition

On November 27, 2020, the Company ~~recorded~~entered into a ~~gain~~purchase agreement (“the Purchase Agreement”) to acquire certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in West Texas and New Mexico, for aggregate consideration of ~~$0.4~~approximately $58.0 million in cash. In connection with the execution of the Purchase Agreement, the Company paid $7.0 million as a ~~result~~deposit for its obligations under the Purchase Agreement, which is included in the consolidated balance sheet as of December 31, 2020. The Silvertip Acquisition closed on February 1, 2021, and a balance of $46.2 million was paid upon closing, after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date.

The Silvertip Acquisition was accounted for using the accounting for asset acquisitions under ASC 805. Under the accounting for asset acquisitions, the Silvertip Acquisition was recorded using a cost accumulation and allocation model under which the cost of the ~~buyer’s assumption~~acquisition was allocated on a relative fair value basis to the assets acquired and liabilities assumed. For asset acquisitions under ASC 805, acquisition-related transaction costs are capitalized as a component of the ~~asset retirement obligations associated with~~cost of the ~~sold properties.~~assets acquired.

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A summary of the consideration paid and the preliminary relative fair value of the assets acquired and liabilities assumed, which is subject to change based upon the final settlement statement that is expected to be provided to Contango in the second quarter of 2021, is as follows (in thousands):


	Purchase Price Allocation
Consideration:
Purchase price	$	58,000
Closing adjustments		(4,739)
Total consideration		53,261
Acquisition transaction costs		109
Total cash paid	$	53,370

Fair value of liabilities assumed:
Accounts payable	$	423
Lease liabilities		1,014
Asset retirement obligations		32,367
Total relative fair value of liabilities assumed	$	33,804

Fair value of assets acquired:
Proved oil and natural gas properties	$	86,160
Right-of-use lease assets		1,014
Total relative fair value of assets acquired	$	87,174

Pro Forma Information

The following unaudited pro forma combined condensed financial data for the year ended December 31, 2020 was derived from the historical financial statements of the Company after giving effect to the Mid-Con Acquisition and the Silvertip Acquisition, as if they had occurred on January 1, 2020. The below information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including the depletion of the fair-valued proved oil and natural gas properties acquired in the Mid-Con Acquisition and the Silvertip Acquisition. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the assets acquired. The pro forma consolidated statement of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the acquisition taken place on January 1, 2020 and is not intended to be a projection of future results.


(In thousands except for per share amounts)	Year Ended December 31, 2020
Revenues	$	202,442
Net loss	$	(191,975)
Basic loss per share	$	(0.97)
Diluted loss per share	$	(0.97)

4. Fair Value Measurements

The ~~Company's~~Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the ~~Company's~~Company’s consolidated balance sheets, but also the impact of the ~~Company's~~Company’s nonperformance risk on its own liabilities. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). A fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

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The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of ~~June 30, 2020.~~March 31, 2021. A financial ~~instrument's~~instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3.

Fair value information for financial assets and liabilities was as follows as of ~~June 30, 2020~~March 31, 2021 (in thousands):


	Total		Fair Value Measurements Using						Total		Fair Value Measurements Using
	Carrying Value		Level 1		Level 2		Level 3		Carrying Value		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts - assets	$	21,221	$	—	$	21,221	$	—	$	2,422	$	—	$	2,422	$	—
Commodity price contracts - liabilities	$	(1,825)	$	—	$	(1,825)	$	—	$	(13,991)	$	—	$	(13,991)	$	—

Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset or liability” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in “Gain (loss) on derivatives, net” in its consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 5 – “Derivative Instruments” for additional discussion of derivatives.

As of ~~June 30, 2020,~~March 31, 2021, the Company’s derivative contracts were all with major institutions with investment grade credit ratings which are believed to have minimal credit risk, which primarily are lenders within the Company’s bank group. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.

Estimates of the fair value of financial instruments are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Credit Agreement approximates carrying value because the facility interest rate approximates current market rates and is reset at least every quarter. See Note 10 – “Long-Term Debt” for further information.

~~Table of Contents~~

Impairments

The Company tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and natural gas properties on a ~~region~~field-by-field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure.

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period.

Asset Retirement Obligations

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and natural gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and

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expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3.

5. Derivative Instruments

The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are typically utilized to hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging ~~programs~~program in light of changes in production, market conditions, ~~and~~ commodity price ~~forecasts.~~forecasts and requirements under its Credit Agreement.

As of ~~June 30, 2020,~~March 31, 2021, the Company’s oil and natural gas derivative positions consisted of swaps and costless collars. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for oil and natural gas. A costless collar consists of a purchased put option and a sold call option, which establishes a minimum and maximum price, respectively, that the Company will receive for the volumes under the contract.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company does not post collateral, nor is it exposed to potential margin calls, under any of these contracts, as they are secured under the Credit Agreement (as defined below) or under unsecured lines of credit with non-bank counterparties. See Note 10 – “Long-Term Debt” for further information regarding the Credit Agreement.

The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Gain (loss) on derivatives, net” on the consolidated statements of operations.

~~Table~~The Company currently has derivative contracts in place to cover production periods through the first quarter of ~~Contents~~2023, which include hedges novated from Mid-Con and additional hedges entered into in the first quarter of 2021. As of March 31, 2021, the Company’s oil derivative contracts include hedges for 1.6 MMBbls of remaining 2021 production with an average floor price of $55.16 per barrel and 1.4 MMBbls of 2022 production with an average floor price of $50.24 per barrel. As of March 31, 2021, the Company’s natural gas derivative contracts include 9.2 Bcf of remaining 2021 production with an average floor price of $2.66 per MMBtu and 10.1 Bcf of 2022 production with an average floor price of $2.60 per MMBtu. Approximately 97% of the Company’s hedges are swaps, and the Company has no three-way collars or short puts.

As of ~~June 30, 2020,~~March 31, 2021, the following financial derivative instruments were in place (fair value in thousands):


Commodity	Period	Derivative	Volume/Month		Price/Unit					Fair Value		Period	Derivative	Volume/Month		Price/Unit			Fair Value
Oil	July 2020 - Oct 2020	Collar	3,442	Bbls	$	52.00	-	65.70	⁽¹⁾	$	176

Oil	July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74			⁽¹⁾	$	1,635

Oil	July 2020	Swap	5,500	Bbls	$	54.33			⁽¹⁾	$	83
Oil	Aug 2020 - Oct 2020	Swap	2,500	Bbls	$	54.33			⁽¹⁾	$	111
Oil	Nov 2020 - Dec 2020	Swap	3,500	Bbls	$	54.33			⁽¹⁾	$	102

Oil	July 2020	Swap	37,500	Bbls	$	54.70			⁽¹⁾	$	576
Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.70			⁽¹⁾	$	2,637

Oil	July 2020	Swap	37,500	Bbls	$	54.58			⁽¹⁾	$	573	April 2021 - July 2021	Swap	12,000	Bbls	$	50.00	⁽¹⁾		(429)
Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.58			⁽¹⁾	$	2,617	Aug 2021 - Sept 2021	Swap	10,000	Bbls	$	50.00	⁽¹⁾		(157)

Oil	Jan 2021 - March 2021	Swap	19,000	Bbls	$	50.00			⁽¹⁾	$	568	April 2021 - July 2021	Swap	62,000	Bbls	$	52.00	⁽¹⁾		(1,720)
Oil	April 2021 - July 2021	Swap	12,000	Bbls	$	50.00			⁽¹⁾	$	462	Aug 2021 - Sept 2021	Swap	55,000	Bbls	$	52.00	⁽¹⁾		(642)
Oil	Aug 2021 - Sept 2021	Swap	10,000	Bbls	$	50.00			⁽¹⁾	$	187	Oct 2021 - Dec 2021	Swap	64,000	Bbls	$	52.00	⁽¹⁾		(904)

Oil	Jan 2021 - July 2021	Swap	62,000	Bbls	$	52.00			⁽¹⁾	$	5,106	April 2021	Swap	20,647	Bbls	$	55.78	⁽¹⁾		(70)
Oil	Aug 2021 - Sept 2021	Swap	55,000	Bbls	$	52.00			⁽¹⁾	$	1,248	May 2021	Swap	20,563	Bbls	$	55.78	⁽¹⁾		(69)
Oil	Oct 2021 - Dec 2021	Swap	64,000	Bbls	$	52.00			⁽¹⁾	$	2,136	June 2021	Swap	20,487	Bbls	$	55.78	⁽¹⁾		(65)

Natural Gas	Aug 2020 - Oct 2020	Swap	40,000	Mmbtus	$	2.532			⁽²⁾	$	87

Natural Gas	Nov 2020 - Dec 2020	Swap	375,000	Mmbtus	$	2.696			⁽²⁾	$	136

Natural Gas	July 2020	Swap	400,000	Mmbtus	$	2.53			⁽²⁾	$	828
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	Mmbtus	$	2.53			⁽²⁾	$	768

Natural Gas	July 2020	Swap	400,000	Mmbtus	$	2.532			⁽²⁾	$	415
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	Mmbtus	$	2.532			⁽²⁾	$	770

Natural Gas	Jan 2021 - March 2021	Swap	185,000	Mmbtus	$	2.505			⁽²⁾	$	(176)
Natural Gas	April 2021 - July 2021	Swap	120,000	Mmbtus	$	2.505			⁽²⁾	$	11
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	Mmbtus	$	2.505			⁽²⁾	$	(1)

Natural Gas	Jan 2021 - March 2021	Swap	185,000	Mmbtus	$	2.508			⁽²⁾	$	(174)
Natural Gas	April 2021 - July 2021	Swap	120,000	Mmbtus	$	2.508			⁽²⁾	$	13
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	Mmbtus	$	2.508			⁽²⁾	$	(1)

Natural Gas	Jan 2021 - March 2021	Swap	650,000	Mmbtus	$	2.508			⁽¹⁾	$	(612)
Natural Gas	April 2021 - Oct 2021	Swap	400,000	Mmbtus	$	2.508			⁽¹⁾	$	4
Natural Gas	Nov 2021 - Dec 2021	Swap	580,000	Mmbtus	$	2.508			⁽²⁾	$	(178)

Natural Gas	April 2021 - Nov 2021	Swap	70,000	Mmbtus	$	2.36			⁽²⁾	$	(92)
Natural Gas	Dec 2021	Swap	350,000	Mmbtus	$	2.36			⁽²⁾	$	(130)

Natural Gas	Jan 2022 - March 2022	Swap	780,000	Mmbtus	$	2.542			⁽²⁾	$	(489)

		Total net fair value of derivative instruments								$	19,396
Oil												July 2021	Swap	20,412	Bbls	$	55.78	⁽¹⁾		(56)

~~(1) Based on West Texas Intermediate oil prices.~~

~~(2) Based on Henry Hub NYMEX natural gas prices.~~

1516

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Commodity	Period	Derivative	Volume/Month		Price/Unit					Fair Value
Oil	Aug 2021	Swap	20,301	Bbls	$	55.78			⁽¹⁾		(47)
Oil	Sept 2021	Swap	20,228	Bbls	$	55.78			⁽¹⁾		(37)
Oil	Oct 2021	Swap	20,155	Bbls	$	55.78			⁽¹⁾		(27)
Oil	Nov 2021	Swap	20,084	Bbls	$	55.78			⁽¹⁾		(19)
Oil	Dec 2021	Swap	20,012	Bbls	$	55.78			⁽¹⁾		(9)

Oil	April 2021	Collar	20,647	Bbls	$	52.00	-	58.80	⁽¹⁾		(38)
Oil	May 2021	Collar	20,563	Bbls	$	52.00	-	58.80	⁽¹⁾		(48)
Oil	June 2021	Collar	20,487	Bbls	$	52.00	-	58.80	⁽¹⁾		(49)
Oil	July 2021	Collar	20,412	Bbls	$	52.00	-	58.80	⁽¹⁾		(45)
Oil	Aug 2021	Collar	20,301	Bbls	$	52.00	-	58.80	⁽¹⁾		(40)
Oil	Sept 2021	Collar	20,228	Bbls	$	52.00	-	58.80	⁽¹⁾		(33)
Oil	Oct 2021	Collar	20,155	Bbls	$	52.00	-	58.80	⁽¹⁾		(27)
Oil	Nov 2021	Collar	20,084	Bbls	$	52.00	-	58.80	⁽¹⁾		(20)
Oil	Dec 2021	Collar	20,012	Bbls	$	52.00	-	58.80	⁽¹⁾		(12)

Oil	April 2021 - Oct 2021	Swap	25,000	Bbls	$	54.77			⁽¹⁾		(630)
Oil	Nov 2021 - Dec 2021	Swap	15,000	Bbls	$	54.77			⁽¹⁾		(52)

Oil	April 2021	Swap	50,000	Bbls	$	63.13			⁽¹⁾		198
Oil	May 2021	Swap	50,000	Bbls	$	62.71			⁽¹⁾		179
Oil	June 2021	Swap	50,000	Bbls	$	62.17			⁽¹⁾		162
Oil	July 2021	Swap	50,000	Bbls	$	61.50			⁽¹⁾		149
Oil	Aug 2021	Swap	50,000	Bbls	$	60.94			⁽¹⁾		143
Oil	Sep 2021	Swap	50,000	Bbls	$	60.38			⁽¹⁾		139
Oil	Oct 2021	Swap	50,000	Bbls	$	59.89			⁽¹⁾		137
Oil	Nov 2021	Swap	50,000	Bbls	$	59.46			⁽¹⁾		136
Oil	Dec 2021	Swap	50,000	Bbls	$	59.01			⁽¹⁾		136

Oil	April 2022 - Oct 2022	Swap	25,000	Bbls	$	42.04			⁽¹⁾		(2,098)

Oil	Jan 2022	Swap	60,000	Bbls	$	52.94			⁽¹⁾		(177)
Oil	Feb 2022	Swap	60,000	Bbls	$	52.65			⁽¹⁾		(175)
Oil	March 2022	Swap	60,000	Bbls	$	52.29			⁽¹⁾		(175)
Oil	April 2022	Swap	47,500	Bbls	$	51.98			⁽¹⁾		(139)
Oil	May 2022	Swap	45,000	Bbls	$	51.71			⁽¹⁾		(131)
Oil	June 2022	Swap	45,000	Bbls	$	51.41			⁽¹⁾		(130)
Oil	July 2022	Swap	45,000	Bbls	$	51.13			⁽¹⁾		(129)
Oil	Aug 2022	Swap	45,000	Bbls	$	50.89			⁽¹⁾		(128)
Oil	Sep 2022	Swap	45,000	Bbls	$	50.65			⁽¹⁾		(127)
Oil	Oct 2022	Swap	45,000	Bbls	$	50.45			⁽¹⁾		(128)
Oil	Nov 2022	Swap	55,000	Bbls	$	50.26			⁽¹⁾		(153)
Oil	Dec 2022	Swap	55,000	Bbls	$	50.22			⁽¹⁾		(151)
Oil	Jan 2023	Swap	57,500	Bbls	$	49.81			⁽¹⁾		(157)
Oil	Feb 2023	Swap	57,500	Bbls	$	49.63			⁽¹⁾		(155)

Oil	Jan 2022	Swap	60,000	Bbls	$	52.96			⁽¹⁾		(176)
Oil	Feb 2022	Swap	60,000	Bbls	$	52.66			⁽¹⁾		(175)
Oil	March 2022	Swap	60,000	Bbls	$	52.27			⁽¹⁾		(176)
Oil	April 2022	Swap	47,500	Bbls	$	51.96			⁽¹⁾		(140)
Oil	May 2022	Swap	45,000	Bbls	$	51.72			⁽¹⁾		(131)
Oil	June 2022	Swap	45,000	Bbls	$	51.42			⁽¹⁾		(130)
Oil	July 2022	Swap	45,000	Bbls	$	51.13			⁽¹⁾		(129)
Oil	Aug 2022	Swap	45,000	Bbls	$	50.90			⁽¹⁾		(128)

~~In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI – Cushing oil differential swap price~~17

Table of $0.05 per barrel of oil. The agreement fixes the Company’s exposure to that differential on 10,000 barrels per month for July 2020 through December 2020. The fair value of this costless swap agreement was zero as of June 30, 2020.Contents

Commodity	Period	Derivative	Volume/Month		Price/Unit			Fair Value
Oil	Sep 2022	Swap	45,000	Bbls	$	50.66	⁽¹⁾		(127)
Oil	Oct 2022	Swap	45,000	Bbls	$	50.47	⁽¹⁾		(125)
Oil	Nov 2022	Swap	55,000	Bbls	$	50.26	⁽¹⁾		(153)
Oil	Dec 2022	Swap	55,000	Bbls	$	50.01	⁽¹⁾		(152)
Oil	Jan 2023	Swap	57,500	Bbls	$	49.79	⁽¹⁾		(158)
Oil	Feb 2023	Swap	57,500	Bbls	$	49.62	⁽¹⁾		(156)

Natural Gas	April 2021 - July 2021	Swap	120,000	MMBtus	$	2.51	⁽²⁾		(66)
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	MMBtus	$	2.51	⁽²⁾		(5)

Natural Gas	April 2021 - July 2021	Swap	120,000	MMBtus	$	2.51	⁽²⁾		(69)
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	MMBtus	$	2.51	⁽²⁾		(5)

Natural Gas	April 2021 - Oct 2021	Swap	400,000	MMBtus	$	2.51	⁽²⁾		(514)
Natural Gas	Nov 2021 - Dec 2021	Swap	580,000	MMBtus	$	2.51	⁽²⁾		(448)

Natural Gas	April 2021 - Nov 2021	Swap	70,000	MMBtus	$	2.36	⁽²⁾		(197)
Natural Gas	Dec 2021	Swap	350,000	MMBtus	$	2.36	⁽²⁾		(211)

Natural Gas	April 2021 - July 2021	Swap	350,000	MMBtus	$	2.96	⁽²⁾		436
Natural Gas	Aug 2021 - Oct 2021	Swap	500,000	MMBtus	$	2.96	⁽²⁾		316
Natural Gas	Nov 2021	Swap	450,000	MMBtus	$	2.96	⁽²⁾		58

Natural Gas	Jan 2022 - March 2022	Swap	780,000	MMBtus	$	2.54	⁽²⁾		(960)

Natural Gas	April 2022 - July 2022	Swap	650,000	MMBtus	$	2.52	⁽²⁾		100
Natural Gas	Aug 2022 - Oct 2022	Swap	350,000	MMBtus	$	2.52	⁽²⁾		3

Natural Gas	Jan 2022 - March 2022	Swap	250,000	MMBtus	$	3.15	⁽²⁾		148

Natural Gas	April 2022	Swap	175,000	MMBtus	$	2.51	⁽²⁾		5
Natural Gas	May 2022 - July 2022	Swap	150,000	MMBtus	$	2.51	⁽²⁾		18
Natural Gas	Aug 2022 - Oct 2022	Swap	400,000	MMBtus	$	2.51	⁽²⁾		2

Natural Gas	Nov 2022 - Feb 2023	Swap	750,000	MMBtus	$	2.72	⁽²⁾		(105)
Total net fair value of derivative instruments (in thousands)								$	(11,569)

(1)

Based on West Texas Intermediate oil prices.

(2)

Based on Henry Hub NYMEX natural gas prices.

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The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of ~~June 30, 2020~~March 31, 2021 (in thousands):


	Gross		Netting ⁽¹⁾		Total		Gross		Netting ⁽¹⁾		Total
Assets	$	21,221	$	—	$	21,221	$	2,422	$	—	$	2,422
Liabilities	$	(1,825)	$	—	$	(1,825)	$	(13,991)	$	—	$	(13,991)

(1) Represents counterparty netting under agreements governing such derivatives.

The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, ~~2019~~2020 (in thousands):


	Gross		Netting ⁽¹⁾		Total		Gross		Netting ⁽¹⁾		Total
Assets	$	4,176	$	—	$	4,176	$	3,493	$	—	$	3,493
Liabilities	$	(5,971)	$	—	$	(5,971)	$	(2,965)	$	—	$	(2,965)

(1) Represents counterparty netting under agreements governing such derivatives.

The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the three ~~and six~~ months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~ (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended March 31,
	2020		2019		2020		2019		2021		2020
Oil contracts	$	8,461	$	286	$	11,258	$	941	$	(1,882)	$	2,797
Natural gas contracts		2,933		211		5,445		324		(559)		2,511
Realized gain	$	11,394	$	497	$	16,703	$	1,265
Realized gain (loss)									$	(2,441)	$	5,308

Oil contracts	$	(16,557)	$	365	$	24,170	$	(3,077)	$	(13,786)	$	40,727
Natural gas contracts		(3,641)		1,203		(2,978)		999		147		664
Unrealized gain (loss)	$	(20,198)	$	1,568	$	21,192	$	(2,078)
Non-cash mark-to-market gain (loss)									$	(13,639)	$	41,391
Gain (loss) on derivatives, net	$	(8,804)	$	2,065	$	37,895	$	(813)	$	(16,080)	$	46,699

6. Stock-Based Compensation

~~Amended and Restated~~ 2009 Incentive Compensation Plan

~~On June 8, 2020,~~The Company has in place the ~~stockholders of the~~Contango Oil & Gas Company ~~approved the third amendment to the~~Third Amended and Restated 2009 Incentive Compensation Plan ~~(as amended, the “Plan”~~(the “2009 Plan”) in the form of an amendment and restatement of the Plan that, among other things, increases the number of shares of the Company’s common stock authorized for issuance pursuant to the Plan by 9,000,000 shares and increases the maximum aggregate number of shares of common stock that may be granted to any individual during any calendar year from 250,000 to 1,000,000. The Planwhich allows for stock options, restricted stock or performance stock units to be awarded to executive officers, directors and employees as a performance-based award.

Restricted Stock

During the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, the Company ~~granted 152,248 shares of~~issued 37,041 restricted ~~common~~ stock ~~which vest over one year, to directors pursuant~~awards to the ~~Company’s Director Compensation Plan.~~members of the board of directors, in lieu of cash fees earned during the fourth quarter of 2020, which vested immediately. The weighted average fair value of the restricted shares granted during the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, was ~~$2.42~~$2.91 per share, with a total fair value of approximately ~~$0.4 million and no adjustment for an estimated weighted average forfeiture rate.~~$0.1 million. There were ~~2,539~~no forfeitures of restricted stock during the ~~six~~three months ended June 30, 2020. The aggregate intrinsic value of restricted shares forfeited during the six months ended June 30, 2020 was approximately $10 thousand. In July 2020, the Company granted 1,037,969 shares of restricted common stock, which vest ratably over three years, to employees as part of their overall compensation package. The weighted average fair value of the restricted shares granted in July 2020, was $2.24 per share,

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~~with a total fair value of approximately $2.3 million and no adjustment for an estimated weighted average forfeiture rate.~~March 31, 2021. The Company recognized approximately ~~$0.4~~$0.5 million in restricted stock compensation expense during the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021, related to restricted stock previously granted to its officers, employees and directors. As of ~~June 30, 2020,~~March 31, 2021, an additional ~~$0.8~~$1.9 million of compensation expense related to restricted stock remained to be recognized over the remaining weighted-average vesting period of ~~1.3~~2.0 years. Approximately ~~10.1~~6.2 million shares remained available for grant under the ~~Amended and Restated~~ 2009 Incentive Compensation Plan as of ~~June 30, 2020,~~March 31, 2021, assuming PSUs (as defined below) are settled at 100% of target.

~~During the six months ended June 30, 2019,~~In May 2021, the Company granted ~~307,650~~1,413,189 shares of restricted common stock to employees, which vest ratably over three years, ~~to employees and executive officers~~ as part of their overall compensation package. ~~Additionally,~~

There were no grants or forfeitures of restricted stock during the ~~six~~three months ended June 30, 2019, the Company granted 80,410 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the six months ended June 30, 2019, was $2.91 per share, with a total fair value of approximately $1.1 million and no adjustment for an estimated weighted average forfeiture rate. During the six months ended June 30, 2019, 38,161 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the six months ended June 30, 2019 was approximately $0.2 million.March 31, 2020. The Company recognized approximately ~~$1.4~~$0.2 million in restricted stock compensation expense during the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020, related to restricted stock previously granted to its officers, employees and directors.

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Performance Stock Units

Performance stock units (“PSUs”) represent the opportunity to receive shares of the Company’s common stock at the time of settlement. The number of shares to be awarded upon settlement of ~~these~~the PSUs may range from 0% to 300% of the targeted number of PSUs stated in the ~~agreement,~~award agreements, contingent upon the achievement of certain share price appreciation targets as compared to share appreciation of a specific peer group or peer group index over a ~~three year performance~~three-year period. The PSUs vest at the end of the ~~three year~~three-year performance period, with the final number of shares to be ~~granted~~issued determined at that time, based on the Company’s share performance during the period compared to the average performance of the peer group.

Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model, which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As it is ~~contemplated~~intended that the PSUs will be settled with shares of the Company’s common stock after three years, the PSU awards are accounted for as equity awards, and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award.

There were no grants or forfeitures of PSUs during the ~~six~~three months ended ~~June 30, 2020.~~ March 31, 2021. The Company recognized approximately $1.3 million in stock compensation expense related to previously granted PSUs during the three months ended March 31, 2021. As of March 31, 2021, an additional $10.5 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 2.1 years.

In ~~July 2020,~~May 2021, the Company granted ~~2,608,640~~1,772,066 PSUs to its executive officers and certain employees as part of their overall compensation package. The performance period will be measured between ~~January~~May 1, ~~2020~~2021 and ~~December 31, 2022. These granted PSUs were valued at a~~April 30, 2024. The weighted average fair value of ~~$4.90 per unit.~~these granted PSUs is currently undergoing evaluation via the Monte Carlo simulation model.

There were no grants or forfeitures of PSUs during the three months ended March 31, 2020. In January 2020, 77,485 shares of the PSUs granted in 2017 vested, of which 22,972 PSUs were withheld for taxes, and are included with the restricted stock activity in the consolidated statement of shareholders’ equity. ~~No PSUs were forfeited during the six months ended June 30, 2020.~~ The Company recognized approximately ~~$0.2~~$0.1 million in stock compensation expense related to PSUs during the ~~six~~three months ended ~~June 30,~~March 31, 2020. ~~As of June 30, 2020, an additional $0.5 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 1.4 years.~~

During the six months ended June 30, 2019, the Company granted 117,105 PSUs to executive officers and certain employees as part of their overall compensation package, which will be measured between January 1, 2019 and December 31, 2021, and were valued at a weighted average fair value of $6.42 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the six months ended June 30, 2019, 49,773 PSUs were forfeited due to the resignations of the Company’s former Senior Vice President of Exploration and Senior Vice President of Operations and Engineering in February 2019. The Company recognized approximately $0.3 million in stock compensation expense related to PSUs during the six months ended June 30, 2019.

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Stock Options

Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the ~~six~~three months ended ~~June 30,~~March 31, 2021 and 2020, ~~and 2019,~~ there was no excess tax benefit recognized.

Compensation expense related to stock option grants ~~are~~is recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. No stock options were granted or forfeited during the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 or ~~2019.~~

2020.

During the ~~six~~three months ended ~~June 30,~~March 31, 2021, no stock options were exercised, and 19,268 stock options expired. During the three months ended March 31, 2020, no stock options were exercised, and 329 stock options ~~for 411 shares~~expired. As of March 31, 2021, there were ~~forfeited by former employees. During the six months ended June 30, 2019, no~~579 stock options ~~were exercised~~vested and ~~stock~~exercisable. The exercise price for such options ~~for 12,052 shares were forfeited by former employees.~~ranges from $35.00 to $38.98 per share, with an average remaining contractual life of 1.0 years.

77.. Leases

During the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, the Company ~~entered into new compressor~~acquired several contracts in the Mid-Con Acquisition and the Silvertip Acquisition related to compressors, vehicle leases and office space with ~~lease~~ terms of twelve months or more, which qualify as operating or finance leases. The Company also entered into a new ~~contracts~~contract for ~~vehicles and~~its headquarters office ~~equipment with lease terms of twelve months or more, which qualify as finance leases.~~in Fort Worth, Texas. As of ~~June 30, 2020,~~March 31, 2021, the Company’s operating leases were for compressors and office space, ~~at its two corporate offices~~ and ~~three field offices, while~~ the Company’s finance leases were for vehicles, compressors and office equipment.

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The Company also has compressor contracts which are on a month-to-month basis, and while it is probable the contracts will be renewed on a monthly basis, the compressors can be easily substituted or cancelled by either party, with minimal penalties. Leases with these terms are not included on the Company’s balance sheet and are recognized on the ~~statement~~consolidated statements of operations on a straight-line basis over the lease term.

The following table summarizes the balance sheet information related to the Company’s leases as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020 (in thousands):


	June 30, 2020		December 31, 2019		March 31, 2021		December 31, 2020
Operating lease right of use asset ⁽¹⁾	$	3,993	$	4,316	$	3,920	$	2,452

Operating lease liability - current⁽²⁾	$	(2,897)	$	(2,597)	$	(2,703)	$	(1,832)
Operating lease liability - long-term⁽³⁾		(1,045)		(1,738)		(1,101)		(522)
Total operating lease liability	$	(3,942)	$	(4,335)	$	(3,804)	$	(2,354)

Financing lease right of use asset⁽¹⁾	$	1,698	$	1,569	$	3,484	$	2,996

Financing lease liability - current⁽²⁾	$	(605)	$	(524)	$	(1,161)	$	(940)
Financing lease liability - long-term⁽³⁾		(1,111)		(1,051)		(2,381)		(2,102)
Total financing lease liability	$	(1,716)	$	(1,575)	$	(3,542)	$	(3,042)

(1)

Included in “Right-of-use lease assets” on the consolidated balance sheet.

(2)

Included in “Accounts payable and accrued liabilities” on the consolidated balance sheet.

(3)

Included in “Lease liabilities” on the consolidated balance sheet.

The Company’s leases generally do not provide an implicit rate, and therefore the Company uses its incremental borrowing rate as the discount rate when measuring operating and financing lease liabilities. The incremental borrowing rate represents an estimate of the interest rate the Company would incur at lease commencement to borrow an amount equal to the lease payments on a collateralized basis over the term of a ~~lease within a particular currency environment. For leases existing prior to January 1, 2019, the incremental borrowing rate as of January 1, 2019 was used for the remaining lease term.~~lease.

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The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019:~~2020:


	June 30, 2020	December 31, 2019	March 31, 2021	December 31, 2020
Weighted Average Remaining Lease Terms (in years):
Operating leases	1.81	2.16	1.67	1.47
Financing leases	3.14	3.14	2.96	3.24

Weighted Average Discount Rate:
Operating leases	5.75%	6.04%	5.94%	5.72%
Financing leases	5.90%	6.24%	5.94%	5.92%

Maturities for the Company’s lease liabilities on the consolidated balance sheet as of ~~June 30, 2020,~~March 31, 2021, were as follows (in thousands):


	June 30, 2020				March 31, 2021
	Operating Leases		Financing Leases		Operating Leases		Financing Leases
2020 (remaining after June 30, 2020)	$	3,040	$	690
2021		702		552
2021 (remaining after March 31, 2021)					$	2,846	$	1,339
2022		168		475		843		1,206
2023		171		156		199		918
2024		72		7		110		428
2025						—		1
Total future minimum lease payments		4,153		1,880		3,998		3,892
Less: imputed interest		(211)		(164)		(194)		(350)
Present value of lease liabilities	$	3,942	$	1,716	$	3,804	$	3,542

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The following table summarizes expenses related to the Company’s leases for the three months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~ (in thousands):


	Three Months Ended June 30, 2020		Three Months Ended June 30, 2019		Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Operating lease cost ^{(1) (2)}	$	743	$	100	$	933	$	687
Financing lease cost - amortization of right-of-use assets		155		-		279		135
Financing lease cost - interest on lease liabilities		27		-		53		24
Administrative lease cost⁽³⁾		19		18		19		19
Short-term lease cost ^{(1) (4)}		615		2,068		518		437
Total lease cost	$	1,559	$	2,186	$	1,802	$	1,302

(1)

This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners.

(2)

Costs related to office leases and compressors with lease terms of twelve months or more.

(3)

Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.

(4)

Costs related primarily to ~~drilling rigs, generators and compressor agreements with lease terms of more than one month and less than one year.~~

~~The following table summarizes expenses related to the Company’s leases for the six months ended June 30, 2020 and 2019 (in thousands):~~

Six Months Ended June 30, 2020

Six Months Ended June 30, 2019

Operating lease cost ^{(1) (2)}
$
1,430

$
471

Financing lease cost - amortization of right-of-use assets

284

-

Financing lease cost - interest on lease liabilities

52

-

Administrative lease cost⁽³⁾

38

37

Short-term lease cost ^{(1) (4)}

1,053

2,578

Total lease cost
$
2,857

$
3,086

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~~(1)~~

~~This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners.~~

~~(2)~~

~~Costs related to office leases and compressors with lease terms of twelve months or more.~~

~~(3)~~

~~Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year.~~

~~(4)~~

~~Costs related primarily to drilling rigs,~~ generators and compressor agreements with lease terms of more than one month and less than one year.

During the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, there were ~~$1.5~~$1.0 million and $0.3 million in cash payments related to the Company’s operating leases and financing leases, respectively. During the ~~six~~three months ended ~~June 30, 2019,~~March 31, 2020, there were ~~$0.1~~$0.7 million and $0.2 million in cash payments related to the Company’s operating ~~leases. No cash payments were made for the~~leases and financing leases, ~~during the six months ended June 30, 2019.~~respectively.

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8. Other Financial Information

The following table provides additional detail for accounts receivable, prepaid expenses ~~inventory~~ and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands):


	June 30, 2020		December 31, 2019		March 31, 2021		December 31, 2020
Accounts receivable:
Trade receivables ⁽¹⁾	$	9,527	$	21,110	$	39,714	$	20,306
Receivable for Alta Resources distribution		1,712		1,712		1,712		1,712
Joint interest billings		12,220		13,104		13,956		15,637
Income taxes receivable		268		509		268		268
Other receivables		2,939		4,126		950		2,209
Allowance for doubtful accounts		(994)		(994)		(2,270)		(2,270)
Total accounts receivable	$	25,672	$	39,567	$	54,330	$	37,862

Prepaid expenses:
Prepaid insurance	$	335	$	683	$	3,051	$	2,825
Other ⁽²⁾		1,028		508		727		535
Total prepaid expenses	$	1,363	$	1,191	$	3,778	$	3,360

Inventory:
Oil storage ⁽³⁾	$	947	$	—
Materials and supplies		763		186
Total inventory	$	1,710	$	186

Accounts payable and accrued liabilities:
Royalties and revenue payable	$	39,950	$	49,644
Advances from partners⁽⁴⁾		868		6,733
Accrued exploration and development ⁽⁴⁾		1,463		8,210
Trade payables		15,192		14,086
Accrued general and administrative expenses ⁽⁵⁾		5,739		12,037
Accrued operating expenses		8,881		5,794
Royalties and revenue payable⁽¹⁾					$	35,000	$	23,701
Legal suspense related to revenues⁽³⁾						29,433		27,983
Advances from partners						159		76
Accrued exploration and development						240		490
Trade payables⁽¹⁾						21,429		14,273
Accrued general and administrative expenses						5,512		6,191
Accrued operating expenses ⁽¹⁾						10,264		5,755
Accrued operating and finance leases		3,502		3,120		3,863		2,772
Other accounts payable and accrued liabilities		1,548		4,969		3,923		2,729
Total accounts payable and accrued liabilities	$	77,143	$	104,593	$	109,823	$	83,970

(1)	~~Decrease~~Increase in ~~2020~~2021 primarily due to ~~lower receivables from oil sales as a result of~~ the ~~dramatic decline in oil prices in 2020.~~Mid-Con Acquisition and the Silvertip Acquisition.

(2)	Other prepaids primarily includes software ~~licenses and additional licenses purchased in relation to the properties acquired from Will Energy and White Star.~~licenses.

(3)

~~Includes approximately 50,000 Bbls~~Suspended revenues primarily relate to amounts for which there is some question as to valid ownership, unknown addresses of ~~oil (net to the Company) produced during the three months ended June 30, 2020, held as inventory in the Company’s Central Oklahoma region and sold in the third quarter of 2020.~~

~~(4)~~

~~Decrease in 2020 due to a decrease in drilling and completion activity. In January 2020, the Company brought one West Texas well online but suspended further drilling in the area, and in its~~payees or some other ~~onshore areas, in response to the dramatic decline in oil prices during the year.~~

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~~(5)~~

~~Includes accruals for legal judgments, of which $6.3 million was paid in April 2020. See Note 12 – “Commitment and Contingencies” for further information.~~payment dispute.

Included in the table below are supplemental cash flow disclosures and non-cash investing activities during the ~~six~~three months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~ (in thousands):


		Three Months Ended March 31,
		2021		2020
Cash payments:
Interest payments	$	808	$	1,267
Income tax payments	$	(60)	$	(7)
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$	158	$	(4,676)

Six Months Ended June 30,

2020

2019

Cash payments:

Interest payments
$
2,006

$
2,157

Income tax payments
$
83

$
805

Non-cash investing activities in the consolidated statements of cash flows:

Increase (decrease) in accrued capital expenditures
$
(7,095)

$
475

The Company issued a total of 25,409,164 shares of Contango common stock at the closing of the Mid-Con Acquisition. See Note 3 – “Acquisitions” for more information.

9. Investment in Exaro Energy III LLC

The Company maintains an ownership interest in Exaro of approximately 37%. The Company’s share in the equity of Exaro at ~~June 30, 2020~~March 31, 2021 was approximately ~~$6.9~~$6.8 million. The Company accounts for its ownership in Exaro using the equity method of accounting, and therefore, does not include its share of individual operating results, production or ~~production~~reserves in those reported for the Company’s consolidated results.

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The Company’s gain or loss attributable to its share in Exaro’s results of operations ~~recognized~~ for the three months ended ~~June 30, 2020 and 2019~~March 31, 2021 was de minimis. The Company recognized a ~~loss~~gain of ~~$0.2~~$0.3 million, net of no tax expense, ~~and a gain of $0.4 million, net of no tax expense, respectively. The Company’s~~attributable to its share in Exaro’s results of operations ~~recognized~~ for the ~~six~~three months ended ~~June 30, 2020 and 2019 was a gain of $0.1 million, net of no tax expense, and a gain of $0.7 million, net of no tax expense, respectively.~~March 31, 2020.

10. Long-Term Debt

Credit Agreement

On September 17, 2019, the Company entered into its new revolving credit agreement with JPMorgan Chase Bank and other lenders (as amended, the “Credit Agreement”), which established a borrowing base of $65 million. The Credit Agreement ~~was amended~~matures on November 1, 2019, in conjunction with the closing of the acquisitions of certain producing assets and undeveloped acreage from Will Energy and White Star, to add two additional lenders and increase the borrowing base thereunder to $145 million. September 17, 2024. The borrowing base is subject to semi-annual redeterminations which will occur on or around May 1^st and November 1^st of each year.

On ~~June 9,~~October 30, 2020, the Company entered into the ~~Second~~Third Amendment to the Credit Agreement, ~~(the “Second Amendment”).~~which became effective on January 21, 2021, upon the satisfaction of certain conditions, including the consummation of the Mid-Con Acquisition. See Note 3 – “Acquisitions” for more information. The ~~Second~~Third Amendment ~~redetermined the borrowing base at $95 million pursuant to the regularly scheduled redetermination process. The Second Amendment also~~ provides for, among other things, ~~further $10~~(i) a 25 basis point increase in the applicable margin at each level of the borrowing base utilization-based pricing grid, (ii) an increase of the borrowing base from $75.0 million to $130.0 million on the effective date of the Third Amendment with a $10.0 million automatic ~~reductions~~stepdown in the borrowing base on March 31, 2021, (iii) certain modifications to the Company’s minimum hedging covenant including requiring hedging for at least 75% of the Company’s projected PDP volumes for 24 full calendar months on or prior to 30 days after the effective date of the Third Amendment and on April 1 and October 1 of each calendar year and (iv) the addition of ~~June 30, 2020~~three new banks to the lender group. The Company’s borrowing base was decreased to $120.0 million on March 31, 2021, per the Third Amendment. On January 21, 2021, the Company entered into the Fourth Amendment to the Credit Agreement, which was related to the transfer of a letter of credit for Mid-Con. The semi-annual redetermination occurred in May 2021, as regularly scheduled, and ~~September 30, 2020.~~ ~~As a result,~~resulted in an increase in the borrowing base ~~was $85~~from $130.0 million ~~as of June 30, 2020. The borrowing base may also be adjusted by certain events, including~~to $250.0 million, per the ~~incurrence of any senior unsecured debt, material asset dispositions or liquidation of hedges in excess of certain thresholds. The~~Fifth Amendment to the Credit Agreement, ~~matures on September 17, 2024.~~as discussed below.

As of March 31, 2021, the Company had approximately $98.6 million outstanding under the Credit Agreement, $2.9 million in outstanding letters of credit and borrowing availability of $18.5 million under the Credit Agreement. As of December 31, 2020, the Company had approximately $9.0 million outstanding under the Credit Agreement and $1.9 million in an outstanding letter of credit.

The Company initially incurred $1.8 million of arrangement and upfront fees in connection with the Credit Agreement and incurred an additional $1.6 million in fees for the first amendment to the Credit Agreement, which is to be amortized over the ~~five year~~five-year term of the Credit Agreement. No fees were paid for the Second Amendment. ~~However,~~The Company incurred $1.0 million in fees related to the Third Amendment, which became effective upon the closing of the Mid-Con Acquisition on January 21, 2021, of which $0.1 million were incurred during the fourth quarter of 2020. During the three months ended ~~June 30, 2020~~March 31, 2021, the Company ~~expensed $1.0~~amortized debt issuance costs of $0.2 million ~~of the fees discussed above, which originally were to be amortized over the life of the loan, due~~related to the ~~reduction in the borrowing base per the Second Amendment.~~Credit Agreement. As of ~~June 30, 2020,~~March 31, 2021, the remaining amortizable balance of these fees was ~~$1.9~~$2.5 million, which will be amortized through September 17, 2024.

As of June 30, 2020, the Company had approximately $79.1 million outstanding under the Credit Agreement and $1.9 million in an outstanding letter of credit. As of December 31, 2019, the Company had approximately $72.8 million outstanding under the Credit Agreement and $1.9 million in an outstanding letter of credit. As of June 30, 2020, borrowing availability under the Credit Agreement was $4.0 million.

Total interest expense under the Company’s ~~current and previous credit agreements,~~Credit Agreement, including commitment fees, ~~and the additional $1.0~~was approximately $1.2 million ~~in expensed loan fees discussed above,~~ for each of the three ~~and six~~ months ended ~~June 30, 2020~~

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~~was approximately $2.2 million~~March 31, 2021 and $3.4 million, respectively. Total interest expense under the credit facility, including commitment fees, for the three and six months ended June 30, 2019 was approximately $1.1 million and $2.2 million, respectively.2020.

The weighted average interest rates in effect at ~~June 30, 2020~~March 31, 2021 and December 31, ~~2019~~2020 were ~~4.0%~~3.9% and ~~4.3%~~2.9%, respectively.

The Credit Agreement is collateralized by liens on substantially all of the Company’s oil and natural gas properties and other assets and security interests in the stock of its wholly owned and/or controlled subsidiaries. The Company’s wholly owned and/or controlled subsidiaries are also required to join as guarantors under the Credit Agreement.

The Credit Agreement contains customary and typical restrictive covenants. The Credit Agreement requires a Current Ratio of greater than or equal to ~~1.00~~1.0:1.0 and a Leverage Ratio of less than or equal to ~~3.50,~~3.5:1.0, both as defined in the Credit Agreement. The Second Amendment ~~includes~~included a waiver of the Current Ratio ~~requirement~~and Leverage Ratio requirements until the quarter ending March 31, 2022. However, the Fifth Amendment (as defined below), reinstates the Current Ratio

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and Leverage Ratio requirements beginning in the second quarter of 2021 and reduces the Leverage Ratio to less than or equal to 3.25:1.0. Additionally, the Second Amendment, among other things, ~~provides for an increase in the Applicable Margin grid on borrowings outstanding of 50 basis points, and~~ includes provisions requiring monthly aged accounts payable reports and typical anti-cash hoarding and cash sweep provisions with respect to a consolidated cash balance in excess of $5.0 million. The Credit Agreement also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of ~~June 30, 2020,~~March 31, 2021, the Company was in compliance with all of its covenants under the Credit Agreement.

On May 3, 2021, the Company entered into the Fifth Amendment to the Credit Agreement (the “Fifth Amendment”) which provides for, among other things, an increase in the Company’s borrowing base from $120.0 million to $250.0 million, effective May 3, 2021, expands the bank group from nine to eleven banks and includes less restrictive hedge requirements and certain modifications to the financial covenants. See Note 13 – “Subsequent Events” for further details. Adjusted for the borrowing base increase to $250.0 million, effective on May 3, 2021, the Company had approximately $86.7 million outstanding under the Credit Agreement and $2.9 million in outstanding letters of credit, with borrowing availability of $160.4 million as of April 30, 2021.

Paycheck Protection Program Loan

On April 10, 2020, the Company entered into a promissory note evidencing an unsecured loan in the amount of approximately $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), signed into law on March 27, 2020, and is administered by the U.S. Small Business Administration. The PPP Loan to the Company ~~is being~~was made through JPMorgan Chase Bank, N.A and is included in ~~“Long Term~~“Long-Term Debt” on the Company’s consolidated balance sheet.

The PPP Loan matures on the two-year anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. Monthly principal and interest payments, less the amount of any potential forgiveness (discussed below), will commence after the six-month anniversary of the funding date. The promissory note evidencing the PPP Loan provides for customary events of default, including, among others, those relating to failure to make payment, bankruptcy, breaches of representations and material adverse effects. The Company may prepay the principal of the PPP Loan at any time without incurring any prepayment charges.

Under the terms of the CARES Act, PPP loan recipients can apply for and be granted forgiveness for all or a portion of the loans granted under the PPP, subject to an audit. Under the CARES Act, loan forgiveness is available, subject to limitations, for the sum of documented payroll costs, covered mortgage interest payments, covered rent payments and covered utilities during either: (1) the eight-week period beginning on the funding date; or (2) the 24-week period beginning on the funding date. Forgiveness is reduced if full-time employee headcount declines, or if salaries and wages for employees with salaries of $100,000 or less annually are reduced by more than 25%. The Company ~~intends to use~~utilized the PPP Loan amount for qualifying expenses during the 24-week coverage period, and ~~expects to apply~~on September 30, 2020, submitted its application for forgiveness of all ~~or part~~ of the PPP Loan in accordance with the terms of the CARES Act and related guidance. The Company is currently waiting on a response from the Small Business Administration to its application for forgiveness. In the event the PPP Loan or any portion thereof is forgiven, the amount forgiven is applied to the outstanding principal.

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11. Income Taxes

The Company’s income tax provision for continuing operations consists of the following (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended March 31,
	2020		2019		2020		2019		2021		2020
Current tax provision:
Federal	$	—	$	—	$	275	$	—	$	—	$	275
State		(7)		427		112		454		539		119
Total	$	(7)	$	427	$	387	$	454	$	539	$	394
Deferred tax provision:
Federal	$	—	$	—	$	—	$	—
State		376		—		376		—
Total	$	376	$	—	$	376	$	—
Total tax provision:
Federal	$	—	$	—	$	275	$	—	$	—	$	275
State		369		427		488		454		539		119
Total income tax provision:	$	369	$	427	$	763	$	454	$	539	$	394

The Federal income tax expense results from an adjustment in the previous period of the credit for Alternative Minimum Tax (“AMT”) paid in prior years. As a result of the tax reform in 2017, the corporate AMT was repealed, and any AMT credit was made refundable. The first half of the credit was refunded when the Company filed its 2018 federal income tax return, and the second half of the credit will be refundable when the Company files its tax return for the tax year ended December 31, 2019. The CARES Act modified the timing of these refunds, allowing the Company to request an expedited refund of $0.3 million this quarter. This amount was previously accounted for as an income tax benefit when the corporate AMT was repealed. State income tax expense relates to income taxes for the quarter ~~and the six months~~ which are expected to be owed to the states of Louisiana and Oklahoma resulting from activities within those states and, in each case, that are not shielded by existing Federal tax attributes.

Additionally, under the CARES Act, the Company will benefit from an amendment to Internal Revenue Code Section 163(j) that temporarily increases deductible interest expense limitations. Specifically, the CARES Act increases the 30% Adjusted Taxable Income (“ATI”) limitation to 50% of ATI for taxable years beginning in each of 2019 and 2020. This will have the effect of allowing the Company to use a Section 163(j) carryover from the prior year that was not limited by Section 382 (discussed below). In addition, the Company used relief granted by the Oklahoma Tax Commission and the Louisiana Tax Commission to extend the due date for the first quarter estimated income tax payments to the states of Oklahoma and Louisiana to July 15, 2020. No Federal estimated tax payments for 2020 are expected. The Company does not expect to benefit from any other income tax-related provisions of the CARES Act.

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the amount of deferred tax liabilities, level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, the Company believes it is not more-likely-than-not that it will realize the benefits of these deductible differences and, therefore, adjusted valuation allowances for federal and state purposes (with the exception of Oklahoma) to $132.0 million and $1.6 million, respectively, as of June 30, 2020. Oklahoma deferred tax expense of $0.4 million was recognized during the quarter ended June 30, 2020. No Oklahoma valuation allowance has been recorded as of June 30, 2020. The $28.5 million net increase from the valuation allowance recorded at December 31, 2019, like other items in the Company’s accounting for income taxes during the current quarter, was determined using a specific June 30, 2020 cut-off date as an accurate estimate of 2020 pre-tax income or income tax expense cannot be reliably made at this time. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.differences.

As of ~~June 30, 2020,~~March 31, 2021, the Company had federal net operating loss (“NOL”) carryforwards of approximately ~~$398.7~~$407.9 million and state NOLs of ~~$32.7~~$26.5 million. The Federal NOL carryforwards ~~occurred due to~~are made up of: (i) those acquired in the merger with Crimson Exploration, Inc. in 2013 and (ii) from subsequent taxable losses during the years 2014 through ~~2019~~2020, due to lower commodity prices

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and utilization of various elections available to the Company in expensing capital expenditures incurred in the development of oil and natural gas properties.

Generally, these NOLs are available to reduce future taxable income and the related income tax liability subject to the limitations set forth in Internal Revenue Code Section 382 related to changes of more than 50% of ownership of the Company’s stock by 5% or greater shareholders over a three-year period (a Section 382 Ownership Change) from the time of such an ownership change. The Company experienced two separate Section 382 Ownership Changes in connection with two of its equity offerings occurring in 2018 and 2019, respectively (the “Ownership Changes”). Market conditions at the time of the 2019 Ownership Change had diminished from the time of the 2018 Ownership Change, thus subjecting virtually all of the Company’s tax attributes to an annual limitation of $0.7 million a year (in pre-tax dollars). This lower annual limitation resulting from the 2019 Ownership Change effectively eliminates the ability to utilize these tax attributes in the future. ~~During~~As a result of the Ownership Changes, the Company has recorded a valuation allowance against substantially all of its NOLs and other deferred tax assets. The Company determined the activity during the three months ended March 31, 2021 resulted in no Section 382 Ownership Change. The valuation allowance balances at March 31, 2021 for federal and state purposes are approximately $139.7 million and approximately $6.1 million, respectively.

The Consolidated Appropriations Act of 2021 was signed into law on December 27, 2020 to provide a response by the Federal government to the pandemic, and it contains numerous tax breaks and extensions for businesses. One such provision is a change in the deductibility of meals paid to a restaurant expense. For meals paid to a restaurant in calendar years 2021 and 2022, there is no limitation on meals (compared to a 50% prior limitation). For the quarter ended ~~June 30, 2020,~~March 31, 2021, the Company ~~had no activity resulting in an additional Section 382 Ownership Change.~~is claiming a 100% benefit for qualifying meal expenses.

The CARES Act temporarily suspends the Section 172 limitation for NOLs arising in tax years beginning in 2018, 2019 and 2020 and also allows NOLs originating in these years to be carried back five years; however, the Company does not expect to receive any federal tax refunds from the temporary suspension26

Table of ~~the Section 172 limitation because the Company incurred tax losses in each of the carryback years.~~Contents

12. Commitments and Contingencies

Legal Proceedings

From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below.

In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decades-old poorly documented transactions. Based on prior summary judgments, the trial court entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decision to the applicable state Court of Appeals, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. In the first quarter of 2018, the Company filed a motion for rehearing with the Court of Appeals, which was denied, as expected. The Company filed a petition requesting a review by the Texas Supreme Court, as the Company believes the trial and appellate courts erred in the interpretation of the law. In early October 2019, the Supreme Court notified the Company that it would not hear this case. The Company engaged additional legal representation to assist in the preparation of an amended petition requesting that the Texas Supreme Court reconsider its initial decision to not review the case. That amended petition was filed, and in mid-March 2020, the Texas Supreme Court decided they would not re-hear the case. Consequently, during the three months ended December 31, 2019, the Company recorded a $6.3 million liability for the judgment, interest and fees, with $3.5 million of such liability related to suspended funds reflected in “Accounts payable and accrued liabilities” on the Company’s consolidated balance sheet as of December 31, 2019. The judgment, interest and fees were paid in April 2020.

In January 2016, the Company was named as the defendant in a lawsuit filed in the District Court for Harris County in Texas by a third-party operator. The Company participated in the drilling of a well in 2012, which experienced serious difficulties during the initial drilling, which eventually led to the plugging and abandoning of the wellbore prior to reaching the target depth. In dispute is whether the Company is responsible for the additional costs related to the drilling difficulties and plugging and abandonment. In September 2019, the case went to trial, and the court ruled in favor of the plaintiff. Prior to the judgment, the Company had approximately $1.1 million in accounts payable related to the disputed costs associated with this case. As a result of the judgment, during the three months ended September 30, 2019, the Company recorded an additional $2.1 million liability for the final judgment plus fees and interest. The Company ~~has since prepared and~~ filed an appeal with the appellate court for a review of the initial trial court’s decision. ~~The plaintiff has petitioned~~On January 23, 2021, the appellate court ~~for an extension~~notified both parties that it would begin reviewing the merits of ~~time until late in~~ the ~~fourth quarter of 2020 in order to file briefs~~case beginning on February 23, 2021. On March 3, 2021, the appellate court affirmed the trial court’s decision. The Company has filed a petition with the ~~court. The Company~~Texas Supreme Court requesting a review of the appellate court’s decision and is awaiting ~~the court’s~~a response.

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While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely.

13. Subsequent Events

~~Throughput Contract Commitment~~Fifth Amendment to the Credit Agreement

On May 3, 2021, the Company entered into the Fifth Amendment to the Credit Agreement. The Fifth Amendment provides for, among other things, (i) an increase in the borrowing base from $120.0 million to $250.0 million, (ii) the reinstatement of the Current Ratio test of a minimum of 1.0:1.0 beginning with the quarter ending June 30, 2021, (iii) a slight reduction in the maximum Debt/Adj. EBITDAX from no greater than 3.5:1.0 to no greater than 3.25:1.0, (iv) a reduction in the Company’s rolling hedge requirements as a percentage of hedgeable oil and natural gas production on an equivalent barrel basis and other minor changes which are more administrative in nature. The Fifth Amendment also expands the bank group from nine to eleven banks and is effective as of May 3, 2021. The Company ~~signed a throughput agreement with a third-party pipeline owner/operator that constructed a natural gas gathering pipeline~~incurred $1.4 million in ~~Southeast Texas that allows~~fees related to the Fifth Amendment, which will be amortized over the remaining term of the Credit Agreement, beginning in the second quarter of 2021. Adjusted for the borrowing base increase to $250.0 million, effective on May 3, 2021, the Company ~~to defray~~had approximately $86.7 million outstanding under the ~~cost~~Credit Agreement and $2.9 million in outstanding letters of ~~building~~credit, with borrowing availability of $160.4 million as of April 30, 2021.

Newly Elected Board of Directors

On April 28, 2021, the ~~pipeline itself. Beginning in late 2016,~~Board of Directors of the Company (the “Board”) increased the size of the Board from five to seven directors and appointed Karen Simon and Janet Pasque to fill the vacancies created by the expansion of the Board, effective on April 28, 2021. Concurrent with their election as directors of the Company, Ms. Pasque was ~~unable~~appointed to ~~meet~~ the ~~minimum monthly gas volume deliveries through this line in Southeast Texas~~Compensation Committee and ~~continued~~Nominating Committee of the Board and Ms. Simon was appointed to ~~not meet~~ the ~~minimum throughput requirements~~Audit Committee and Nominating Committee of the Board. The Board determined that Ms. Pasque and Ms. Simon are both independent directors under the ~~agreement~~applicable rules and regulations of the SEC and within the meaning of the NYSE American listing standards.

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Adoption of Change of Control Severance Plan

On April 28, 2021, the Company adopted the Contango Oil & Gas Company Change in Control Severance Plan (the “Change in Control Plan”), which provides “double trigger” severance payments and benefits to all employees including the Company’s named executive officers. The policy provides an eligible participant with certain payments and benefits in the event that the participant experiences a qualifying termination event within the 18-month period following a change in control. In the event that an eligible executive’s employment is terminated without cause by the employer or for good reason by the executive within the 18-month period following the occurrence of a change in control, the Company’s Chief Executive Officer and the Company’s President would become entitled to receive 250%, and the Company’s Senior Vice President and Chief Financial Officer would become entitled to receive 200%, of the sum of the executive’s annual base salary and target annual cash bonus. In addition, the executive would receive (1) a prorated annual cash bonus for the year of termination based on actual performance; (2) Company-paid COBRA continuation coverage for up to 18 months following the date of termination; (3) reimbursement for up to $10,000 in outplacement services; and (4) any outstanding unvested PSU equity awards held by the executive will remain outstanding and vest based on the greatest of (a) actual performance through the ~~expiration~~execution date of the ~~throughput commitment~~definitive documentation governing the change in ~~March 2020. As~~control, (b) actual performance through the date of ~~December 31, 2019,~~the participant’s termination of employment, or (c) the target number of shares granted under such PSU award. The Change in Control Plan contains a modified cutback provision whereby payments payable to an executive may be reduced if doing so would put the executive in a more advantageous after-tax provision than if payments were not reduced and the executive became subject to excise taxes under Section 4999 of the Code.

Adoption of Executive Severance Plan

On April 28, 2021, the Company ~~recorded~~adopted the Contango Oil & Gas Company Executive Severance Plan (the “Severance Plan”), which provides severance payments and benefits to its named executive officers outside the context of a ~~$1.0 million loss contingency through~~change in control. The Severance Plan provides an eligible participant with payments and benefits in the ~~expiration~~event of involuntary termination without cause or other termination due to a good reason. In the event of such a qualifying termination under the Severance Plan, the participant would become entitled to receive in the case of the ~~contract~~Company’s Chief Executive Officer and the Company’s President, 150%, and in the case of the Company’s Senior Vice President and Chief Financial Officer, 100%, of the sum of the participant’s annual base salary and target bonus. In addition, the participant would receive (1) a prorated annual cash bonus for the year of termination based on ~~March 31, 2020, which is~~actual performance; (2) Company-paid COBRA continuation coverage for up to ~~be paid~~18 months following the date of termination; (3) reimbursement for up to $10,000 in ~~three equal monthly installments beginning in August~~outplacement services; (4) all outstanding unvested time-based equity awards held by the executive will 100% accelerate and become exercisable or settle (as applicable); and (5) a pro-rated portion of ~~2020.~~

any outstanding unvested PSU awards held by the executive will remain outstanding and vest based on actual performance over the applicable performance period.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and the accompanying notes and other information included elsewhere in this Quarterly Report on Form 10-Q and with our ~~2019~~2020 Form 10-K, previously filed with the Securities and Exchange Commission (“SEC”).

Available Information

General information about us can be found on our website at www.contango.com. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file or furnish them to the SEC. This report should be read together with our ~~2019~~2020 Form 10-K and our subsequent filings with the SEC. We are not including the information on our website as a part of, or incorporating it by reference into, this report.

Cautionary Statement about Forward-Looking Statements

Certain statements contained in this report may contain “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. The words and phrases “should”, “could”, “may”, “will”, “believe”, “plan”, “intend”, “expect”, “potential”, “possible”, “anticipate”, “estimate”, “forecast”, “view”, “efforts”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties that could cause actual results to differ materially from those stated. Risks and uncertainties that could cause or contribute to such differences include, without limitation, those discussed in the section entitled “Risk Factors” included in this report, ~~and~~ in our ~~2019~~2020 Form 10-K and those factors summarized below:

●

volatility and significant declines in oil, natural gas and natural gas liquids prices, including regional differentials;

●

any reduction in our borrowing base from time to time and our ability to repay any excess borrowings as a result of such reduction;

●

the impact of the COVID-19 pandemic, including reduced demand for oil and natural gas, economic slowdown, governmental and societal actions taken in response to the COVID-19 pandemic, stay-at-home orders, and interruptions to our operations;

●

our ability to execute our ~~new~~ corporate strategy of offering a “fee for service” property management service for oil and natural gas companies;

●

risks related to the recent Mid-Con Acquisition and the Silvertip Acquisition, including the risk that the businesses will not be integrated successfully, that the anticipated cost savings, synergies and growth from those acquisitions may not be fully realized or may take longer to realize than expected, and that management attention will be diverted to integration-related issues;

●

the impact of the climate change initiative by President Biden’s administration and Congress, including the January 2021 executive order imposing a moratorium on new oil and natural gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices;

●

our financial position;

●

the potential impact of our derivative instruments;

●

potential liability resulting from any future litigation related to the Mid-Con Acquisition;

●

our business strategy, including ~~execution of~~our ability to successfully execute on our consolidation strategy or make any desired changes in our ~~strategy;~~strategy from time to time;

●

meeting our forecasts and budgets, including our ~~2020~~2021 capital expenditure budget;

●

expectations regarding oil and natural gas markets in the United States and our realized prices;

●

the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations to agree to, adhere to and maintain oil price and production controls;

●

outbreaks and pandemics, even outside our areas of operation, including COVID-19;

●

operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms, pipelines and natural gas processing facilities;

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●

our ability to successfully develop our undeveloped acreage in the ~~Southern Delaware~~Permian Basin and ~~the Mid-continent area of Oklahoma,~~Midcontinent region, and realize the benefits associated therewith;

●

increased costs and risks associated with our exploration and development in the Gulf of ~~Mexico;~~Mexico or the Permian Basin;

●

the risks associated with acting as operator of deep high pressure and high temperature wells, including well blowouts and explosions, onshore and offshore;

●

the risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes, especially in prospects in which we have made a large capital commitment relative to the size of our capitalization structure;

●

the timing and successful drilling and completion of oil and natural gas wells;

●

the concentration of drilling in the ~~Southern Delaware~~Permian Basin, including lower than expected production attributable to down spacing of wells;

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●

our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations, fund our drilling program and support our acquisition efforts;

●

the cost and availability of rigs and other materials, services and operating equipment;

●

timely and full receipt of sale proceeds from the sale of our production;

●

our ability to find, acquire, market, develop and produce new oil and natural gas properties;

●

the conditions of the capital markets and our ability to access debt and equity capital markets or other non-bank sources of financing, and actions by current and potential sources of capital, including lenders;

●

interest rate volatility;

●

our ability to ~~successfully integrate the businesses, properties and assets we acquire, including those in new areas of operation;~~

●

~~our ability to~~ complete strategic dispositions or acquisitions of assets or businesses and realize the benefits of such dispositions or acquisitions;

●

uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures;

●

the need to take impairments on our properties due to lower commodity prices or other changes in the values of our ~~assets;~~assets, which results in a non-cash charge to earnings;

●

the ability to post additional collateral for current bonds or comply with new supplemental bonding requirements imposed by the Bureau of Ocean Energy Management;

●

operating hazards attendant to the oil and natural gas business including weather, environmental risks, accidental spills, blowouts and pipeline ruptures, and other risks;

●

downhole drilling and completion risks that are generally not recoverable from third parties or insurance;

●

potential mechanical failure or under-performance of significant wells, production facilities, processing plants or pipeline mishaps;

●

actions or inactions of third-party operators of our properties;

●

actions or inactions of third-party operators of pipelines or processing facilities;

●

the ability to retain key members of senior management and key technical employees and to find and retain skilled personnel;

●

strength and financial resources of competitors;

●

federal and state legislative and regulatory developments and approvals (including additional taxes and changes in environmental regulations);

●

the uncertain impact of supply of and demand for oil, natural gas and ~~NGLs;~~natural gas liquids;

●

our ability to obtain goods and services critical to the operation of our properties;

●

worldwide and United States economic conditions;

●

the ability to construct and operate infrastructure, including pipeline and production facilities;

●

the continued compliance by us with various pipeline and gas processing plant specifications for the gas and condensate produced by us;

●

operating costs, production rates and ultimate reserve recoveries of our oil and natural gas discoveries;

●

expanded rigorous monitoring and testing requirements;

●

the ability to obtain adequate insurance coverage on commercially reasonable terms; and

●

the limited trading volume of our common stock and general market volatility.

Any of these factors and other factors described in this report could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. Although we believe our estimates and assumptions to be reasonable when made, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. Our assumptions about future events may prove to be inaccurate.

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Moreover, the effects of the COVID-19 pandemic may give rise to risks that are currently unknown or amplify the risks associated with many of the factors summarized above or discussed in this report or our ~~2019~~2020 Form ~~10-K or our Quarterly Report on Form 10-Q for the period ended March 31, 2020.~~10-K. We caution you that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure you that those statements will be realized or the forward-looking events and circumstances will occur. You should not place undue reliance on forward-looking statements in this report as they speak only as of the date of this report.

All forward-looking statements, expressed or implied, in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or any person acting on our behalf may issue. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law.

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Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

We are a ~~Houston,~~Fort Worth, Texas based, independent oil and natural gas ~~company, with regional offices in Oklahoma City and Stillwater, Oklahoma.~~company. Our business is to maximize production and cash flow from our onshore properties primarily located in our Midcontinent, Permian, Rockies and other smaller onshore areas and our offshore properties in the shallow waters of the Gulf of Mexico ~~(“GOM”) and onshore Texas, Oklahoma, Louisiana and Wyoming properties~~ and use that cash flow to explore, develop and acquire oil and natural gas properties across the United States.

The following table lists our primary producing regions as of March 31, 2021:


Region		Formation
Midcontinent		Cleveland, Bartlesville, Mississippian, Woodford and others
Permian		San Andres, Yeso, Bone Springs, Wolfcamp and others
Rockies		Sussex, Shannon, Muddy, Phosphoria, Embar-Tensleep, Madison and others
Other		Woodbine, Lewisville, Buda, Georgetown, Eagleford and Offshore Gulf of Mexico properties in water depths off of Louisiana in less than 300 feet

Impact of the COVID-19 Pandemic

The coronavirus (“COVID-19”) pandemic has significantly affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the COVID-19 pandemic has resulted in travel restrictions, business closures and other restrictions that have disrupted the demand for oil throughout the world and, when combined with the oil supply increase attributable to the battle for market share among the Organization of Petroleum Exporting Countries (“OPEC”), Russia and other oil producing nations, resulted in oil prices declining significantly beginning in late February 2020. While there has been a modest recovery in oil prices in recent months, the length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil demand. Due to the extreme volatility in oil prices and the impact of the COVID-19 pandemic on the financial condition of our upstream peers, the Company suspended its onshore drilling program in the Southern Delaware Basin in the first quarter of 2020 and further suspended all drilling in the second quarter of 2020 and has focused since then on certain measures that included, but were not limited to, the following:

●

work from home initiatives for all but critical staff and the implementation of social distancing measures;

●

a company-wide effort to cut costs throughout the Company’s operations;

●

utilization of the Company’s available storage capacity to temporarily store a portion of its production for later sale at higher prices when advantageous to do so;

●

suspension of all drilling since the second-half of 2020 through the quarter ended March 31, 2021, with the expectation to recommence value added drilling in 2021;

●

From our initial entry into the Southern Delaware Basin in 2016 and through ~~mid-2019,~~early 2019, we ~~have been~~were focused on the development of our Southern Delaware Basin acreage in Pecos County, Texas. In the first quarter of 2020, we suspended further drilling in this area in response to the dramatic decline in oil prices and further suspended all drilling in the second quarter of 2020. As of ~~June 30, 2020,~~March 31, 2021, we were producing from eighteen wells over our approximate 16,200 gross

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operated (7,500 company net) acre position in West Texas, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

During the fourth quarter of 2019, we closed on the acquisitions of certain producing assets and undeveloped acreage of Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) and established an additional core strategic area, located primarily in the Central Oklahoma and Western Anadarko basins. These acquisitions were transformative as production from these acquisitions represented approximately 70% of our total net production for the three and six months ended June 30, 2020.

In the fourth quarter of 2019, we also entered into a Joint Development Agreement with Juneau Oil & Gas, LLC (“Juneau”), which provides us the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf of Mexico. The first such exploratory prospect acquired was the Iron Flea prospect located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline, which was spud in May 2020 and determined unsuccessful in June 2020.

During the three months ended June 30, 2020 we announced the addition of a new corporate strategy that includes offering a property management service (or “fee for service”) for oil and gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs. As part of this service offering, we entered into a Management Services Agreement with Mid-Con Energy Partners, LP (“Mid-Con”) to provide operational services as operator of record on Mid-Con’s oil and gas properties in exchange for an annual services fee of $4 million, additional fees upon termination and warrants to align both parties and create value for shareholders. See Item 1. Note 1 – “Organization and Business” for additional information.

~~The following table lists our primary producing areas as of June 30, 2020:~~

~~Location~~		~~Formation~~
~~Gulf of Mexico~~		~~Offshore Louisiana - water depths less than 300 feet~~
~~Mid-continent Region of Oklahoma~~		~~Mississippian, Woodford, Oswego, Cottage Grove, Chester and Red Fork~~
~~Southern Delaware Basin, Pecos County, Texas~~		~~Wolfcamp A and B~~
~~Madison and Grimes counties, Texas~~		~~Woodbine / Upper Lewisville~~
~~Zavala and Dimmit counties, Texas~~		~~Buda / Eagle Ford / Georgetown~~
~~San Augustine County, Texas~~		~~Haynesville shale, Mid Bossier shale and James Lime formations~~
~~Other Texas Gulf Coast~~		~~Conventional and smaller unconventional formations~~
~~Weston County, Wyoming~~		~~Muddy Sandstone~~
~~Sublette County, Wyoming~~		~~Jonah Field~~ ⁽¹⁾

~~(1)~~

Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this equity investment is not included in our reported production results for all periods shown in this report.

~~Impact of the COVID-19 Pandemic and 2020 Plan Changes~~

The COVID-19 pandemic has resulted in a severe worldwide economic downturn, significantly disrupting the demand for oil throughout the world, and has created significant volatility, uncertainty and turmoil in the oil and gas industry. This has led to a significant global oversupply of oil and a subsequent substantial decrease in oil prices. While global oil producers, including the Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing

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nations reached an agreement to cut oil production in April 2020, downward pressure on, and volatility in, commodity prices has remained and could continue for the foreseeable future, particularly given concerns over available storage capacity for oil. We have certain commodity derivative instruments in place to mitigate the effects of such price declines; however, derivatives will not entirely mitigate lower oil prices. While there has been a modest recovery in oil prices, the length of this demand disruption is unknown, and there is significant uncertainty regarding the long-term impact to global oil demand, which will ultimately depend on various factors and consequences beyond the Company’s control, such as the duration and scope of the pandemic, the length and severity of the worldwide economic downturn, additional actions by businesses and governments in response to both the pandemic and the decrease in oil prices, the speed and effectiveness of responses to combat the virus, and the time necessary to equalize oil supply and demand to restore oil pricing. In response to these developments, we have continued to implement measures to mitigate the impact of the COVID-19 pandemic on our employees, operations and financial position. These measures include, but are not limitedSubsequent to the ~~following:~~

●

~~work from home initiatives for~~suspension of all ~~but critical staff and social distancing measures;~~

●

~~a company-wide effort to cut costs throughout our operations;~~

●

~~a plan to utilize our available storage capacity to temporarily store a portion of our production when advantageous to do so; and~~

●

~~suspension of any further plans for onshore and offshore~~ drilling ~~in 2020.~~

Additionally, on April 10, 2020, we entered into a promissory note evidencing an unsecured loan in the amount of approximately $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) and is administered by the U.S. Small Business Administration. Under the CARES Act, the PPP Loan may be partially or wholly forgiven following an audit if the funds are used for certain qualifying expenses. We intend to use the PPP Loan amount for qualifying expenses and will continue to assess whether to apply for forgiveness of the PPP Loan in accordance with the terms of the CARES Act and related guidance. See Item 1. Note 10 – “Long-Term Debt” for additional information on the terms of the PPP Loan. We also benefited from certain income tax-related provisions of the CARES Act. See Item 1. Note 11 – “Income Taxes” for additional information.

We continue to assess the global impacts of the COVID-19 pandemic and expect to continue to modify our plans as more clarity around the full economic impact of COVID-19 becomes available. See Part II, Item 1A. “Risk Factors” in our Quarterly Report on Form 10-Q for the period ended March 31, 2020 for further discussion.

~~Capital Expenditures~~

~~Beginning~~ in the second ~~quarter~~half of 2020, ~~in response to the decrease in commodity prices,~~ we ~~have suspended any further plans for onshore drilling in 2020.~~ ~~The offshore Iron Flea prospect in the shallow waters off of the~~ ~~Louisiana~~ ~~coast in~~ ~~Grand Isle~~ was spud in late May 2020. On June 12, 2020, the target drilling depth was reached, and the prospect was determined unsuccessful. As a result, we recorded $10.9 million in dry hole exploration expenses during the three months ended June 30, 2020.

~~For 2020, we plan to continue~~continued to identify opportunities for cost reductions and operating efficiencies in all areas of our operations, while also searching for new ~~resource~~producing property acquisition opportunities. Acquisition efforts ~~if any,~~have been, and we believe will continue to be, focused on ~~areas in which~~PDP-heavy assets where we ~~can~~might also be able to leverage our geological and operational experience and expertise to ~~exploit identified~~reduce operating expenses, enhance production and identify and develop additional drilling opportunities ~~and where we can develop an inventory of additional drilling prospects~~ that we believe will enable usthe Company to economically grow production and add reserves.

On January 21, 2021, we closed on the acquisition of Mid-Con Energy Partners, LP (“Mid-Con”), in an all-stock merger transaction in which Mid-Con became a direct, wholly owned subsidiary of Contango (the “Mid-Con Acquisition”). A total of 25,409,164 shares of Contango common stock were issued as consideration in the Mid-Con Acquisition. Effective upon the closing of the Mid-Con Acquisition, our borrowing base under the Credit Agreement increased from $75.0 million to $130.0 million, with an automatic $10.0 million reduction in the borrowing base on March 31, 2021. See Item 1. Note 3 – “Acquisitions” and Item 1. Note 10 – “Long-Term Debt” for further details.

On February 1, 2021, we closed on the acquisition of certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in West Texas and New Mexico (collectively the “Silvertip Acquisition”) for aggregate consideration of approximately $58.0 million. After customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date, the net consideration paid was approximately $53.2 million. See Item 1. Note 3 – “Acquisitions” for more information.

On May 3, 2021, we entered into the Fifth Amendment to the Credit Agreement which provides for, among other things, an increase in the Company’s borrowing base from $120.0 million to $250.0 million, effective May 3, 2021, expands the bank group from nine to eleven banks and includes less restrictive hedge requirements and certain modifications to the financial covenants. See Item 1. Note 13 – “Subsequent Events” for further details.

Capital Expenditures

Our 2021 planned capital expenditure budget has increased to $24 - $27 million from previous guidance of $13 - $16 million for recompletions, facility upgrades, waterflood development and select drilling in West Texas (expected 1.5 net locations, 3 gross locations), among other things. The increase in planned capital expenditures reflects, in part, development opportunities in our recently acquired properties as part of the Mid-Con Acquisition and the Silvertip Acquisition, coupled with recent strength in crude oil prices. The capital expenditure program will continue to be evaluated for revision throughout the year.

During the three months ended March 31, 2021, we incurred capital expenditures of approximately $1.6 million primarily related to redevelopment activities of newly acquired properties in our Midcontinent region. We believe that our current financial resources will be more than adequate to fund our initial capital budget through internally generated cash flow, and any increase to such initial 2021 capital expenditure budget, when and if such increase is deemed appropriate. We plan to retain the flexibility to be more aggressive in our drilling plans should results exceed expectations, commodity prices continue to improve or we reduce drilling and completion costs in certain areas, thereby making an expansion of our drilling program an appropriate business decision.

We will continue to make balance sheet strength a priority in 2021 and intend to continue to evaluate certain acquisition opportunities that may arise in this challenging commodity price environment. We will also aim to pursue additional “fee for service” opportunities similar to that entered into with Mid-Con in June 2020 prior to its later acquisition, as well as pursue growth through the acquisition of PDP-heavy assets. Any excess cash flow will likely be used to reduce borrowings outstanding under our Credit Agreement (as defined below). We intend to keenly focus on continuing to reduce lease operating costs on our legacy and newly acquired assets, reducing general and administrative expenses, improving cash margins and lowering our exposure to asset retirement obligations through the possible sale of non-core properties.

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Impairment of Long-Lived Assets

Under GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a ~~region~~field basis to the unamortized capitalized cost of the ~~asset.~~assets in that field. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, oil and natural gas prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. We did not record any impairment expense during the three months ended March 31, 2021.

In the first quarter of 2020, the COVID-19 pandemic and the resulting deterioration in the global demand for oil, combined with the failure by the OPEC and Russia to reach an agreement on lower production quotas until April 2020, caused a dramatic increase in the supply of oil and a corresponding decrease in commodity prices, and lowered the demand for all commodity products. Consequently, during the three months ended March 31, 2020, we

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recorded a $143.3 million non-cash charge for proved property impairment of our onshore properties related to the dramatic decline in commodity prices, as discussed above, the “PV-10” (present value, discounted at a 10% rate) of our proved reserves, and the associated change in our ~~current~~then forecasted development plans for our proved, undeveloped locations. We conducted an impairment test for the three months ended June 30, 2020, but no additional impairment was recorded. We recognized non-cash proved property impairment of $0.2 million for the six months ended June 30, 2019, related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018.

We recorded a $2.6 million non-cash charge for unproved impairment expense during the three months ended March 31, ~~2020. The impairment primarily~~2020, related to ~~acquired~~expiring leases in the Company’s Central Oklahoma and Western Anadarko regions which will be expiring in 2020, and which we have no current plans to develop as a result of the current commodity price environment. No additional impairment was recorded during the three months ended June 30, 2020. During the six months ended June 30, 2019, we recorded non-cash impairment expense of $0.9 million related to impairment of certain unproved properties, primarily due to expiring leases.our Midcontinent region.

Summary Production Information

Our production sales for the three months ended ~~June 30, 2020~~March 31, 2021 were ~~approximately 83% onshore and 17% offshore, volumetrically, and was~~ comprised of ~~56%~~37% oil, 47% natural gas, ~~24% oil~~ and ~~20%~~16% natural gas liquids. During the second quarter of 2020, due to the extreme volatility in oil prices ranging from a low of ($37.63) per Bbl to a high of $40.46 per Bbl, we placed into excess storage capacity approximately 50,000 barrels of oil (net to the Company) produced during the second quarter, for later sale at higher prices. These volumes will sell in the third quarter of 2020. In July 2020, the average price was $41.15 per Bbl. Our production sales for the three months ended ~~June 30, 2019~~March 31, 2020, were ~~41% onshore and 59% offshore, volumetrically, and was~~ comprised of approximately ~~55%~~30% oil, 50% natural gas ~~26% oil~~ and ~~19%~~20% natural gas liquids.

The table below sets forth our average net daily production sales data in ~~Mboe/~~MBoe/d for each of our regions for each of the periods indicated:


	Three Months Ended					Three Months Ended
	June 30, 2019	September 30, 2019	December 31, 2019	March 31, 2020	June 30, 2020	March 31,	June 30,	September 30,	December 31,	March 31,
Offshore GOM	3.2	3.3	3.2	2.7	2.7
Central Oklahoma ^{(1) (2)}	—	—	8.1	10.9	9.1
Western Anadarko ⁽¹⁾	—	—	1.7	2.9	2.5
West Texas ⁽³⁾	1.0	0.9	1.4	1.2	0.9
Other Onshore	1.2	1.4	1.4	1.2	0.9
	5.4	5.6	15.7	18.9	16.1	2020	2020	2020	2020	2021 ⁽⁴⁾
Midcontinent⁽¹⁾						13.8	11.6	12.6	9.6	11.1
Permian⁽²⁾						1.2	0.9	0.7	1.4	2.6
Rockies ⁽³⁾						0.1	—	0.1	—	2.6
Other						3.8	3.6	3.8	3.4	3.4
Total daily production sales volumes						18.9	16.1	17.2	14.4	19.7

(1)	~~Properties acquired in the White Star and Will Energy acquisitions during the three months ended December 31, 2019.~~

~~(2)~~

Decrease in production sales during the three months ended June 30, 2020 due to allocating approximately 50,000 Bbls of oil (net to the Company) to inventory storage (0.5 ~~Mboe/~~MBoe/d). Increase in production sales during the three months ended September 30, 2020 due to the sale of this inventory.Decrease in production sales during the three months ended December 31, 2020 primarily due to downtime related to workovers and routine repair and maintenance. Increase in production sales during the three months ended March 31, 2021 due to the properties acquired as part of the Mid-Con Acquisition.

(2)

Decrease in production sales beginning in the second quarter of 2020 due to the suspension of our drilling program as a result of the dramatic decline in oil prices and the effects of the COVID-19 pandemic. Increase in production sales during the three months ended March 31, 2021 due to the properties acquired as part of the Silvertip Acquisition.

(3)	Includes our offshore Gulf of Mexico wells located in the shallow waters off the coast of Louisiana as well as our legacy onshore wells located in states near the Texas Gulf coast.

(4)

Increase in production sales during the three months ended ~~December~~March 31, ~~2019 was~~2021 due to ~~new wells coming online.~~the Mid-Con Acquisition and the Silvertip Acquisition. The Mid-Con Acquisition reflects production sales beginning January 21, 2021, impacting the Midcontinent and Rockies regions by 1.7 MBoe/d and 0.4 MBoe/d, respectively. The Silvertip Acquisition reflects production sales beginning February 1, 2021, impacting the Permian and Rockies regions by 1.4 MBoe/d and 2.5 MBoe/d, respectively.

Other Investments

Jonah Field - Sublette County, Wyoming

Our wholly owned subsidiary, Contaro Company, owns a 37% ownership interest in ~~Exaro.~~Exaro Energy III LLC (“Exaro”). As of ~~June 30, 2020,~~March 31, 2021, Exaro had ~~645~~649 wells on production over its 5,760 gross acres (1,040 net), with a working

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interest between 14.6% and 32.5%. These wells were producing at a rate of approximately ~~2.8 Mboe/~~2.4 MBoe/d, net to Exaro, during the three months ended ~~June 30, 2020. As a result of~~March 31, 2021. The gain or loss attributable to our equity ~~nvestment~~investment in Exaro during the three months ended March 31, 2021 was de minimis. During the three months ended March 31, 2020, we recognized an investment ~~loss~~gain of approximately ~~$0.2~~$0.3 million, net of no tax expense, ~~and an~~attributable to our equity investment gain of approximately $0.4 million, net of no tax expense, for the three months ended June 30, 2020 and 2019, respectively. We recognized an investment gain of approximately $0.1 million, net of no tax expense, and an investment gain of approximately $0.7 million, net of no tax expense, for the six months ended June 30, 2020 and 2019, respectively.in Exaro. See Item 1. Note 9 – “Investment in Exaro Energy III LLC” for additional details related to this equity investment.

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Results of Operations for the Three ~~and Six~~ Months ended ~~June 30,~~March 31, 2021 and 2020 ~~and 2019~~

The table below sets forth revenue, production sales data, average sales prices and average production costs associated with our sales of oil, natural gas and natural gas liquids ("NGLs") from operations for the three ~~and six~~ months ended ~~June 30, 2020~~March 31, 2021 and ~~2019. In the first quarter of 2020, we began reporting~~2020. We report in barrels of oil equivalents (“Boe”) instead of natural gas equivalents. Six thousand cubic feet (“Mcf”) of natural gas is the energy equivalent of one barrel of oil, condensate or NGL. Reported operating expenses include production taxes, such as ad valorem and severance taxes.

Three Months Ended June 30,

Six Months Ended June 30,


2020

2019

%

2020

2019

%

Revenues (thousands):

Oil and condensate sales

$
7,930

$
7,439

7
%

$
30,712

$
13,845

122
%
Natural gas sales

6,618

3,857

72
%

14,789

9,499

56
%
NGL sales

3,294

1,466

125
%

6,915

3,429

102
%
Total revenues

$
17,842

$
12,762

40
%

$
52,416

$
26,773

96
%

Production:

Oil and condensate (thousand barrels)

Offshore GOM

8

10

(20)
%

18

23

(22)
%
Central Oklahoma

174

—

100
%

463

—

100
%
Western Anadarko

57

—

100
%

135

—

100
%
West Texas

69

60

15
%

158

125

26
%
Other Onshore

38

57

(33)
%

92

105

(12)
%
Total oil and condensate

346

127

172
%

866

253

242
%
Natural gas (million cubic feet)

Offshore GOM

1,222

1,325

(8)
%

2,485

2,960

(16)
%
Central Oklahoma

2,637

—

100
%

5,479

—

100
%
Western Anadarko

814

—

100
%

1,642

—

100
%
West Texas

31

88

(65)
%

81

152

(47)
%
Other Onshore

209

215

(3)
%

428

409

5
%
Total natural gas

4,913

1,628

202
%

10,115

3,521

187
%
Natural gas liquids (thousand barrels)

Offshore GOM

37

58

(36)
%

67

124

(46)
%
Central Oklahoma

215

—

100
%

450

—

100
%
Western Anadarko

32

—

100
%

78

—

100
%
West Texas

6

15

(60)
%

15

29

(48)
%
Other Onshore

15

19

(21)
%

27

37

(27)
%
Total natural gas liquids

305

92

232
%

637

190

235
%
Total (thousand barrels of oil equivalent)

Offshore GOM

249

289

(14)
%

499

641

(22)
%
Central Oklahoma

828

—

100
%

1,827

—

100
%
Western Anadarko

225

—

100
%

486

—

100
%
West Texas

80

90

(11)
%

186

179

4
%
Other Onshore

87

111

(22)
%

191

210

(9)
%
Total production

1,469

490

200
%

3,189

1,030

210
%

Daily Production:

Oil and condensate (thousand barrels per day)

Offshore GOM

0.1

0.1

—
%

0.1

0.1

—
%
Central Oklahoma

1.9

—

100
%

2.5

—

100
%
Western Anadarko

0.6

—

100
%

0.7

—

100
%
West Texas

0.8

0.7

14
%

0.9

0.7

29
%
Other Onshore

0.3

0.6

(50)
%

0.6

0.6

—
%
Total oil and condensate

3.7

1.4

164
%

4.8

1.4

243
%


	Three Months Ended March 31,
	2021		2020		% Change

Revenues (thousands):
Oil and condensate sales	$	36,993	$	22,782	62	%
Natural gas sales		14,492		8,170	77	%
NGL sales		8,281		3,621	129	%
Other operating revenues		184		—	100	%
Total revenues	$	59,950	$	34,573	73	%

Production Sales Volumes:
Oil and condensate (thousand barrels)
Midcontinent		354		366	(3)	%
Permian		134		89	51	%
Rockies		124		7	*	%
Other		38		58	(34)	%
Total oil and condensate		650		520	25	%
Natural gas (million cubic feet)
Midcontinent		2,589		3,644	(29)	%
Permian		534		50	968	%
Rockies		556		—	100	%
Other		1,304		1,507	(13)	%
Total natural gas		4,983		5,201	(4)	%
Natural gas liquids (thousand barrels)
Midcontinent		213		278	(23)	%
Permian		14		9	56	%
Rockies		14		—	100	%
Other		52		46	13	%
Total natural gas liquids		293		333	(12)	%
Total (thousand barrels of oil equivalent)
Midcontinent		999		1,251	(20)	%
Permian		237		106	124	%
Rockies		231		7	*	%
Other		306		356	(14)	%
Total production sales volumes		1,773		1,720	3	%

Daily Production Sales Volumes:
Oil and condensate (thousand barrels per day)
Midcontinent		3.9		4.0	(3)	%
Permian		1.5		1.0	50	%
Rockies		1.4		0.1	*	%
Other		0.4		0.6	(33)	%
Total oil and condensate		7.2		5.7	26	%
Natural gas (million cubic feet per day)
Midcontinent		28.8		40.0	(28)	%
Permian		5.9		0.5	*	%
Rockies		6.2		—	100	%
Other		14.5		16.7	(13)	%
Total natural gas		55.4		57.2	(3)	%

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Three Months Ended June 30,

Six Months Ended June 30,


2020

2019

%

2020

2019

%

Natural gas (million cubic feet per day)

Offshore GOM

13.4

14.6

(8)
%

13.7

16.4

(16)
%
Central Oklahoma

29.0

—

100
%

30.1

—

100
%
Western Anadarko

8.9

—

100
%

9.0

—

100
%
West Texas

0.3

1.0

(70)
%

0.4

0.8

(50)
%
Other Onshore

2.4

2.3

4
%

2.4

2.3

4
%
Total natural gas

54.0

17.9

202
%

55.6

19.5

185
%
Natural gas liquids (thousand barrels per day)

Offshore GOM

0.4

0.6

(33)
%

0.4

0.7

(43)
%
Central Oklahoma

2.4

—

100
%

2.5

—

100
%
Western Anadarko

0.4

—

100
%

0.4

—

100
%
West Texas

0.1

0.2

(50)
%

0.1

0.2

(50)
%
Other Onshore

0.1

0.2

(50)
%

0.2

0.1

100
%
Total natural gas liquids

3.4

1.0

240
%

3.6

1.0

260
%
Total (thousand barrels of oil equivalent per day)

Offshore GOM

2.7

3.2

(16)
%

2.7

3.5

(23)
%
Central Oklahoma

9.1

—

100
%

10.0

—

100
%
Western Anadarko

2.5

—

100
%

2.7

—

100
%
West Texas

0.9

1.0

(10)
%

1.0

1.0

—
%
Other Onshore

0.9

1.2

(25)
%

1.2

1.2

—
%
Total production

16.1

5.4

198
%

17.6

5.7

209
%

Average Sales Price:

Oil and condensate (per barrel)

$
22.94

$
58.42

(61)
%

$
35.46

$
54.78

(35)
%
Natural gas (per thousand cubic feet)

$
1.35

$
2.37

(43)
%

$
1.46

$
2.70

(46)
%
Natural gas liquids (per barrel)

$
10.81

$
16.01

(32)
%

$
10.85

$
18.05

(40)
%
Total (per barrels of oil equivalent)

$
12.14

$
26.03

(53)
%

$
16.43

$
26.00

(37)
%

Expenses (thousands):

Operating expenses

$
17,139

$
5,694

201
%

$
38,621

$
10,886

255
%
Exploration expenses

$
11,173

$
249

*
%

$
11,571

$
473

*
%
Depreciation, depletion and amortization

$
5,092

$
7,573

(33)
%

$
17,946

$
15,129

19
%
Impairment and abandonment of oil and gas properties

$
—

$
1,247

*
%

$
145,878

$
1,834

*
%
General and administrative expenses

$
5,713

$
4,456

28
%

$
11,138

$
9,461

18
%
Gain (loss) from investment in affiliates (net of taxes)

$
(173)

$
427

(141)
%

$
113

$
457

(75)
%

Selected data per Boe:

Operating expenses

$
11.67

$
11.62

—
%

$
12.11

$
10.57

15
%
General and administrative expenses

$
3.89

$
9.09

(57)
%

$
3.49

$
9.19

(62)
%
Depreciation, depletion and amortization

$
3.47

$
15.46

(78)
%

$
5.63

$
14.69

(62)
%

*Greater than 1,000%

~~Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019~~

~~Natural Gas, Oil and NGL Sales and Production~~

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~~transportation and processing constraints and mechanical issues. In addition, our production from individual wells naturally declines over time as we produce our reserves.~~

We reported revenues of $17.8 million for the three months ended June 30, 2020, compared to revenues of $12.8 million for the three months ended June 30, 2019, an increase attributable primarily to the production from the properties acquired from Will Energy and White Star, offset in part by the 53% decrease in the weighted average equivalent sales price period over period.

Total equivalent production was 16.1 Mboe/d for the three months ended June 30, 2020, compared to 5.4 Mboe/d in the prior year quarter, an increase attributable to the additional production from the Will Energy and White Star properties acquired in the fourth quarter of 2019. Net oil production for the current quarter was approximately 3.7 Mbbl/d, compared with approximately 1.4 Mbbl/d in the prior year quarter. During the current year quarter, due to the extreme volatility in oil prices, which ranged from a low of ($37.63) per Bbl to a high of $40.46 Bbl, the Company placed into excess storage capacity approximately 50,000 barrels of oil (net to the Company) produced during the second quarter, for later sale at higher prices. These volumes will sell in the third quarter of 2020. In July 2020, the average price was $41.15 per Bbl. Net natural gas production for the current quarter was approximately 54.0 Mmcf/d, compared with approximately 17.9 Mmcf/d in the prior year quarter, and NGL production for the current quarter was approximately 3.4 Mbbl/d, compared with approximately 1.0 Mbbl/d in the prior year quarter.

~~Average Sales Prices~~

The average equivalent sales price realized for the three months ended June 30, 2020 was $12.14 per Boe compared to $26.03 per Boe for the three months ended June 30, 2019. The decline was attributable to the decrease in all realized commodity prices in the current year quarter. The COVID-19 pandemic continued to adversely impact demand for commodity products, which caused a global supply/demand imbalance for oil that resulted in extreme volatility in benchmark oil prices, with prices ranging from a low of ($37.63) per Bbl to a high of $40.46 per Bbl during the second quarter. The realized price of oil averaged $22.94 per Bbl in the current quarter, compared to an average $58.42 per Bbl in the prior year quarter. Natural gas prices also suffered due to the COVID-19 pandemic, ranging from a low of $1.48 per Mcf to a high of $2.13 per MCF during the current year quarter. The realized price of gas averaged $1.35 per Mcf in the current quarter compared to an average of $2.37 per Mcf in the prior year quarter, and the realized price of NGLs averaged $10.81 per Bbl in the current quarter compared to an average $16.01 per Bbl in the prior year quarter.

~~Operating Expenses~~

Operating expenses for the three months ended June 30, 2020 were approximately $17.1 million, or $11.67 per Boe, compared to $5.7 million, or $11.62 per Boe, for the three months ended June 30, 2019. The table below provides additional detail of operating expenses for the three month periods:

Three Months Ended June 30,


2020

2019


(in thousands)

(per Boe)

(in thousands)

(per Boe)

Lease operating expenses

$
11,136

$ 7.58

$
3,629

$ 7.41

Production & ad valorem taxes

828

0.56

657

1.34

Transportation & processing costs

4,579

3.12

502

1.02

Workover costs

596

0.41

906

1.85

Total operating expenses

$
17,139

11.67

$
5,694

$ 11.62


	Three Months Ended March 31,
	2021		2020		% Change

Natural gas liquids (thousand barrels per day)
Midcontinent		2.4		3.1	(23)	%
Permian		0.2		0.1	100	%
Rockies		0.2		—	100	%
Other		0.5		0.5	—	%
Total natural gas liquids		3.3		3.7	(11)	%
Total (thousand barrels of oil equivalent per day)
Midcontinent		11.1		13.7	(19)	%
Permian		2.6		1.2	117	%
Rockies		2.6		0.1	*	%
Other		3.4		3.9	(13)	%
Total daily production sales volumes		19.7		18.9	4	%

Average Sales Price:
Oil and condensate (per barrel)	$	56.95	$	43.77	30	%
Natural gas (per thousand cubic feet)	$	2.91	$	1.57	85	%
Natural gas liquids (per barrel)	$	28.31	$	10.89	160	%
Total (per barrels of oil equivalent)	$	33.72	$	20.10	68	%

Expenses (thousands):
Operating expenses	$	27,478	$	19,257	43	%
Exploration expenses	$	196	$	398	(51)	%
Depreciation, depletion and amortization	$	9,143	$	12,854	(29)	%
Impairment and abandonment of oil and natural gas properties	$	3	$	145,878	(100)	%
General and administrative expenses	$	11,359	$	7,651	48	%
Gain from investment in affiliates (net of taxes)	$	—	$	286	(100)	%

Selected data per Boe:
Operating expenses	$	15.50	$	11.20	38	%
General and administrative expenses	$	6.41	$	4.45	44	%
Depreciation, depletion and amortization	$	5.16	$	7.47	(31)	%

Lease operating expenses were $11.1 million and $3.6 million for the three months ended June 30, 2020 and June 30, 2019, respectively, an increase primarily due to the addition of our Will Energy and White Star acquired properties.

Transportation and processing costs were $4.6 million and $0.5 million for the three months ended June 30, 2020 and June 30, 2019, respectively, an increase primarily due to the addition of our Will Energy and White Star acquired properties and the related higher transportation costs in our Central Oklahoma region.

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~~Exploration Expense~~

Exploration expense was $11.2 million for the three months ended June 30, 2020, compared to the prior year quarter of $0.2 million, an increase primarily due to $10.9 million of dry hole costs related to the unsuccessful result on the drilling of the Iron Flea exploratory prospect in the shallow waters in the Grand Isle area of the Gulf of Mexico.

~~Impairment and Abandonment Expenses~~

During the three months ended June 30, 2020, we did not record any impairment related to our properties. During the three months ended June 30, 2019, we recognized $0.2 million in non-cash proved property impairment related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018.

During the three months ended June 30, 2020, we also did not record any impairment expense on unproved properties. In the 2019 quarter, we recognized non-cash unproved impairment expense of approximately $0.4 million, primarily related to expiring leases, and an abandonment expense of $0.6 million.

~~Depreciation, Depletion and Amortization~~

Depreciation, depletion and amortization expense for the three months ended June 30, 2020, was approximately $5.1 million, or $3.47 per Boe. This compares to approximately $7.6 million, or $15.46 per Boe, for the three months ended June 30, 2019. The lower depletion expense in the current quarter was a result of lower depletable property balances in the current quarter attributable to the proved property impairment recorded during the first quarter of 2020.

~~General and Administrative Expenses~~

~~Total general and administrative expenses for the three months ended June 30, 2020 were approximately $5.7 million, compared to $4.5 million for the three months ended June 30, 2019.~~

~~The table below provides additional detail of general and administrative expenses for the comparative three month periods:~~

Three Months Ended June 30,

2020

2019

(in thousands)

Wages, bonuses and employee benefits ⁽¹⁾

$
3,366

$
1,504

Non-cash stock-based compensation ⁽²⁾

266

584

Professional fees⁽³⁾

2,039

1,021

Professional fees - special ⁽⁴⁾

551

985

Recouped overhead ⁽⁵⁾

(2,761)

(298)

Other ⁽⁶⁾

2,252

660

Total general and administrative expenses

$
5,713

$
4,456

~~(1)~~

~~Higher expenses for the three months ended June 30, 2020 due to the acquisition of certain Will Energy and White Star employees during the three months ended December 31, 2019.~~

~~(2)~~

~~Lower expense for the three months ended June 30, 2020, due to restricted stock grants being awarded in the third quarter of 2020 as compared to the first quarter of 2019.~~

~~(3)~~

~~Primarily includes fees related to recurring legal counsel, technical consultants and accounting and auditing costs.~~

~~(4)~~

Non-recurring fees incurred in conjunction with our pursuit of strategic initiatives, including the integration of the White Star and Will Energy assets acquired during the three months ended December 31, 2019.

~~(5)~~

These credits relate to overhead for our properties for which we are able to bill out to partners and offset against our other general and administrative costs. The increase in the current year credit is due to the additional overhead related to the acquired Will Energy and White Star properties.

~~(6)~~

Includes fees related to insurance, office costs and other company expenses. The increase in the current quarter expense is primarily due to the additional expenses related to the acquired Will Energy and White Star properties, offices and employees.

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~~Gain (Loss) from Affiliates~~

For the three months ended June 30, 2020 and June 30, 2019, we recorded a loss from affiliates of approximately $0.2 million, net of no tax expense, and a gain of $0.4 million, net of no tax expense, respectively, related to our equity investment in Exaro.

~~Gain from Sale of Assets~~

During the three months ended June 30, 2020, we recorded a gain on sale of assets of $4.4 million related to the divestiture of non-core properties we acquired from Will Energy and White Star in the fourth quarter of 2019. The recorded gain resulted primarily from the buyer’s assumption of the asset retirement obligation on the properties. During the three months ended June 30, 2019, we recorded a gain on sales of assets of $0.4 million primarily related to post-closing adjustments from sales of non-core properties during 2019. See Item 1. Note 3 – “Dispositions” for additional information regarding these sales.

~~Gain (Loss) on Derivatives~~

During the three months ended June 30, 2020, we recorded a loss on derivatives of $8.8 million. Of this amount, $20.2 million were non-cash, unrealized mark-to-market losses as commodity prices improved from those existing at the end of the first quarter of 2020, offset in part by $11.4 million in realized gains during the second quarter. During the three months ended June 30, 2019, we recorded a gain on derivatives of $2.1 million. Of this amount, $1.6 million were non-cash, unrealized mark-to-market gains, and the remaining $0.5 million were realized gains.*Greater than 1,000%

~~Six~~Three Months Ended ~~June 30, 2020~~March 31, 2021 Compared to ~~Six~~Three Months Ended ~~June 30, 2019~~March 31, 2020

Oil, Natural Gas ~~Oil~~ and NGL Sales and Production

Our revenues are primarily from the sale of our oil, natural gas and NGL production. Our revenues may vary significantly from year to year depending on production volumes and changes in commodity prices, each of which may fluctuate widely. As discussed above, oil prices declined significantly in the first quarter of 2020 as a result of the effects of the COVID-19 pandemic and the ongoing disruptions to the global energy markets. ~~Prices recovered somewhat during~~While those factors generally kept downward pressure and instability on the ~~second~~commodity price markets in 2020, due to the increase in domestic vaccination programs and the related improvement in, and the forecast for, the economy, we have experienced commodity price improvement in the first quarter of ~~2020, but still remained below those of the prior year periods.~~2021. Our production ~~volumes~~sales are subject to significant variation as a result of new operations, weather events, transportation and processing constraints and mechanical issues. In addition, our production from individual wells naturally declines over time as we produce our reserves.

We reported revenues of ~~$52.4~~$60.0 million for the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, compared to revenues of ~~$26.8~~$34.6 million for the ~~six~~three months ended ~~June 30, 2019,~~March 31, 2020. The current year increase is attributable to the increases in commodity prices in the first quarter of 2021, the additional production sales from the properties acquired in the Mid-Con Acquisition and the Silvertip Acquisition, and the impact of the increase in the Company’s percentage of oil/liquids sales as compared to total sales. The revenues related to the properties acquired in the Mid-Con Acquisition were approximately $10.5 million in the first quarter of 2021, and the revenues related to the properties acquired in the Silvertip Acquisition were approximately $14.3 million in the first quarter of 2021.

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Total production sales for the three months ended March 31, 2021 were approximately 1.8 MMBoe (53% liquids), or 19.7 MBoe/d, compared to approximately 1.7 MMBoe (50% liquids), or 18.9 MBoe/d in the prior year quarter. Net oil production sales were approximately 7,200 barrels per day for the three months ended March 31, 2021 compared to approximately 5,700 barrels per day in the prior year quarter, an increase attributable ~~primarily~~ to the production from the properties acquired ~~from Will Energy~~in the Mid-Con Acquisition and ~~White Star, offset in part by lower prices period over period.~~

~~Total equivalent~~the Silvertip Acquisition. Net natural gas production ~~was 17.6 Mboe/d for~~sales decreased to approximately 55.4 MMcf per day during the ~~six~~three months ended ~~June 30,~~March 31, 2021, compared with approximately 57.2 MMcf per day during the three months ended March 31, 2020, due to the harsh winter storms in February 2021 and the related downtime. Net NGL production sales decreased to approximately 3,300 barrels per day during the three months ended March 31, 2021 compared to ~~5.7 Mboe/d~~approximately 3,700 barrels per day in the prior year an increase attributable to the additional production from the Will Energy and White Star properties acquired in the fourth quarter of 2019. Net oil production for the current year was approximately 4.8 Mboe/d, compared with approximately 1.4 Mboe/d in the prior year. Due to the precipitous drop in oil prices at the beginning of the second quarter of 2020, the Company placed into excess storage capacity approximately 50,000 barrels of oil (net to the Company) produced during the second quarter, for later sale at higher prices. These volumes will sell in the third quarter of 2020. In July 2020, the average price was $41.15 per Bbl. Net natural gas production for the current year was approximately 55.6 Mmcf/d, compared with approximately 19.5 Mmcf/d in the prior year, and NGL production for the current year was approximately 3.6 Mboe/d, compared with approximately 1.0 Mboe/d in the prior year.quarter.

Average Sales Prices

The average equivalent sales price realized for the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 was ~~$16.43~~$33.72 per Boe compared to ~~$26.00~~$20.10 per Boe for the ~~six~~three months ended ~~June 30, 2019.~~March 31, 2020. The ~~decline was~~lower prior year prices were attributable to the ~~decrease~~decline in all realized commodity prices in early 2020, as a result of the ~~current year. The~~initial spread of the COVID-19 pandemic ~~continued to adversely~~and its negative impact on the global demand for ~~commodity products,~~oil and natural gas. The increase in domestic vaccination programs have helped reduce the spread of COVID-19 in 2021, which ~~caused a global supply/demand imbalance~~has contributed to an improvement in the economy and higher realized prices for ~~oil that resulted~~commodities in ~~benchmark oil prices ranging from a high of $63.27 per Bbl at~~ the ~~beginning of 2020 to a low of ($37.63) per Bbl during the second~~first quarter of ~~2020.~~2021. The

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realized price of oil averaged ~~$35.46~~$56.95 per Bbl in the ~~current year,~~first quarter of 2021 compared to an average ~~of $54.78~~$43.77 per Bbl in the prior ~~year. Natural gas prices also suffered due to the COVID-19 pandemic, ranging from a low of $1.48 per Mcf to a high of $2.20 per Mcf during the current year.~~year quarter. The realized price of gas averaged ~~$1.46~~$2.91 per Mcf in the ~~current year~~first quarter of 2021 compared to an average of ~~$2.70~~$1.57 per Mcf in the prior year quarter, and the realized price of NGLs averaged ~~$10.85~~$28.31 per Bbl in the ~~current year~~first quarter of 2021 compared to an average ~~of $18.05~~$10.89 per Bbl in the prior ~~year.~~year quarter.

Other Operating Revenues

Other operating revenues are related to plant and pipeline revenues. We reported $0.2 million of other operating revenues specifically related to the properties acquired in the Mid-Con Acquisition during the three months ended March 31, 2021. We did not report any other operating revenues during the prior year period.

Operating Expenses

Operating expenses for the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 were approximately ~~$38.6~~$27.5 million, or ~~$12.11~~$15.50 per Boe, compared to ~~$10.9~~$19.3 million, or ~~$10.57~~$11.20 per Boe, for the ~~six~~three months ended ~~June 30, 2019.~~March 31, 2020. The table below provides additional detail of operating expenses for the ~~six~~three month periods:


	Six Months Ended June 30,						Three Months Ended March 31,
	2020			2019			2021			2020
		(in thousands)	(per Boe)		(in thousands)	(per Boe)	(in thousands)		(per Boe)	(in thousands)		(per Boe)
Lease operating expenses	$	24,187	$ 7.57	$	7,314	$ 7.10	$	16,493	$ 9.30	$	10,825	$ 6.29
Production & ad valorem taxes		2,574	0.81		1,043	1.01		3,541	2.00		1,746	1.02
Transportation & processing costs		10,131	3.18		1,197	1.16		5,776	3.26		5,552	3.23
Workover costs		1,729	0.55		1,332	1.30		1,375	0.78		1,134	0.66
Other operating expenses								293	0.16		—	—
Total operating expenses	$	38,621	12.11	$	10,886	$ 10.57	$	27,478	15.50	$	19,257	$ 11.20

Lease operating expenses (“LOE”) were ~~$24.2~~$16.5 million and ~~$7.3~~$10.8 million for the ~~six~~three months ended ~~June 30,~~March 31, 2021 and March 31, 2020, ~~and June 30, 2019, respectively, an increase primarily due to the addition of our Will Energy and White Star acquired properties.~~

~~Production and ad valorem taxes were $2.6 million and $1.0 million for the six months ended June 30, 2020 and June 30, 2019, respectively, an increase primarily~~respectively. The LOE related to the ~~additional production~~properties acquired in ~~2020 from~~ the Mid-Con Acquisition was approximately $4.5 million or $23.56 per Boe, and the LOE related to the properties acquired ~~Will Energy~~in the Silvertip Acquisition was approximately $3.8 million or $10.81 per Boe in the first quarter of 2021, which is the primary reason for the increase in LOE expense and ~~White Star properties.~~rate per Boe in the current year quarter compared to the prior year quarter.

Transportation and processing costs were ~~$10.1~~approximately $5.8 million ~~and $1.2~~compared to $5.6 million for the ~~six~~three months ended ~~June 30,~~March 31, 2021 and 2020, ~~and June 30, 2019,~~ respectively, ana slight increase ~~primarily~~despite the additional acquired properties, as gas sales were a lower percentage of production in the first quarter of 2021 due to the ~~addition of our Will Energy~~harsh weather conditions and ~~White Star acquired properties and~~related downtime created by the ~~related higher transportation costs~~winter storms in ~~our Central Oklahoma region.~~February 2021.

~~Exploration Expense~~37

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~~Exploration expense was $11.6~~Production and ad valorem taxes were $3.5 million and $1.7 million for the ~~six~~three months ended ~~June 30,~~March 31, 2021 and March 31, 2020, respectively. The expense related to the properties acquired in the Mid-Con Acquisition was approximately $0.9 million or $4.72 per Boe, and the expense related to the properties acquired in the Silvertip Acquisition was approximately $0.9 million or $2.48 per Boe, both of which contributed to the increase in production and ad valorem tax expense and rate per Boe in the current year quarter compared to the prior year ~~of $0.5 million, an increase primarily due~~quarter.

Other operating expenses are related to ~~$10.9~~plant and pipeline expenses. We reported $0.3 million of ~~dry hole costs~~other operating expenses specifically related to the ~~unsuccessful result on the drilling of the Iron Flea exploratory prospect~~properties acquired in the ~~shallow waters~~Mid-Con Acquisition during the three months ended March 31, 2021. We did not report any other operating expenses during the prior year period.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense for the three months ended March 31, 2021, was approximately $9.1 million, or $5.16 per Boe. This compares to approximately $12.9 million, or $7.47 per Boe, for the three months ended March 31, 2020. The lower depletion expense and rate per Boe for the three months ended March 31, 2021 were a result of lower depletable property balances attributable to the ~~Grand Isle area~~proved property impairments recorded during the first and fourth quarters of 2020, partially offset by depletion expense associated with the ~~Gulf of Mexico.~~properties from the Mid-Con Acquisition and the Silvertip Acquisition.

Impairment and Abandonment Expenses

No impairment was recorded during the three months ended March 31, 2021. During the ~~six~~three months ended ~~June 30,~~March 31, 2020, we recorded a $143.3 million non-cash charge for proved property impairment of our onshore properties ~~due to~~as a result of the dramatic decline in commodity prices, ~~and the impact of that decline on~~ the “PV-10” (present value, discounted at a 10% rate) of our proved reserves, and the associated change in our ~~current~~then forecasted development plans for proved, undeveloped locations (“PUDs”). Under GAAP, we are required to impair the balance sheet carrying cost of our proved property base to reflect that overall decrease in reserve value related to the decrease in prices and the reduction in PUDs. During the six months ended June 30, 2019, we recognized $0.2 million in non-cash proved property impairment related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018.

~~During the six months ended June 30, 2020, we~~locations. We also recorded a $2.6 million non-cash charge for unproved impairment expense during the three months ended March 31, 2020, related ~~primarily~~ to acquired leases in our ~~Central Oklahoma and Western Anadarko regions,~~Midcontinent region which ~~will be~~were expiring in 2020, and which we have no current plans to develop as a result of the current commodity price environment. During the six months ended June 30, 2019, we recognized non-cash impairment expense of $0.9 million related to impairment of certain non-core unproved properties primarily due to expiring leases.

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~~Depreciation, Depletion and Amortization~~

Depreciation, depletion and amortization expense for the six months ended June 30, 2020, was approximately $17.9 million, or $5.63 per Boe. This compares to approximately $15.1 million, or $14.69 per Boe, for the six months ended June 30, 2019. The higher depletion expense in the current year was attributable to the additional properties acquired from Will Energy and White Star. The lower rate was a result of lower depletable property balances in the current quarter as a result of the proved property impairment recorded during the first quarter of 2020.

General and Administrative Expenses

Total general and administrative expenses for the ~~six~~three months ended ~~June 30, 2020~~March 31, 2021 were approximately ~~$11.1~~$11.4 million, compared to ~~$9.5~~$7.7 million for the ~~six~~three months ended ~~June 30, 2019.~~March 31, 2020, with the current year increase primarily related to the Mid-Con Acquisition and the related additional expenses.

The table below provides additional detail of general and administrative expenses for the comparative ~~six~~three month periods:


	Six Months Ended June 30,				Three Months Ended March 31,
	2020		2019		2021		2020

	(in thousands)				(in thousands)
Wages, bonuses and employee benefits ⁽¹⁾	$	5,934	$	2,571
Wages and employee benefits ⁽¹⁾					$	4,464	$	2,568
Non-cash stock-based compensation ⁽²⁾		616		1,637		1,779		350
Professional fees⁽³⁾		3,655		2,128		1,314		1,616
Professional fees - special ⁽⁴⁾		1,334		1,736		1,846		783
Recouped overhead ⁽⁵⁾		(5,668)		(514)		(1,162)		(681)
Other ⁽⁶⁾		5,267		1,903		3,118		3,015
Total general and administrative expenses	$	11,138	$	9,461	$	11,359	$	7,651

(1)

Higher ~~expenses for the six months ended June 30, 2020 due to the acquisition of certain Will Energy~~wages and ~~White Star employees~~employee benefits during the three months ended ~~December~~March 31, ~~2019.~~2021 due to additional employees acquired by the Company in connection with the Mid-Con Acquisition.

(2)

~~Lower~~Higher stock-based compensation expense for the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021 due to ~~restricted stock grants being awarded~~an increase in the number of PSUs granted in the third quarter of 2020, as compared to previous grants, and the ~~first quarter of 2019.~~related increase in expense.

(3)	Primarily includes fees related to recurring legal counsel, technical consultants and accounting and auditing costs.

(4)

Non-recurring fees incurred in conjunction with our pursuit of strategic initiatives, including the ~~acquisition and~~ integration of the White Star and Will Energy assets acquired during the three months ended ~~December~~March 31, ~~2019.~~2020 and the integration of the assets acquired in the Mid-Con Acquisition and the Silvertip Acquisition during the three months ended March 31, 2021. See Item 1. Note 3 – “Acquisitions” for further details.

(5)

These credits relate to overhead ~~for our properties for which~~expenses we are able to bill out to partners in our operated properties and offset against our other general and administrative costs. The increase in the current year credit is due to the additional overhead related to the acquired ~~Will Energy and White Star~~ properties.

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(6)	Includes fees related to insurance, office costs and other company expenses. ~~The increase in the current year expense is primarily due to the additional expenses related to the acquired Will Energy and White Star properties, offices and employees.~~

~~Gain from Affiliates~~

For the six months ended June 30, 2020 and June 30, 2019, we recorded a gain from affiliates of approximately $0.1 million and $0.7 million, net of no tax expense, respectively, related to our equity investment in Exaro.

~~Gain from Sale of Assets~~

For the six months ended June 30, 2020, we recorded a gain on sale of assets of $4.4 million related to the divestiture of non-core properties we acquired from Will Energy and White Star in the fourth quarter of 2019. The recorded gain resulted primarily from the buyer’s assumption of the asset retirement obligation on the properties. During the six months ended June 30, 2019, we recorded a gain on sales of assets of $0.4 million primarily related to post-closing adjustments from sales of non-core properties during 2019. See Item 1. Note 3 – “Dispositions” for additional information regarding these sales.

Gain (Loss) on Derivatives

During the ~~six~~three months ended ~~June 30,~~March 31, 2021, we recorded a loss on derivatives of $16.0 million. Of this amount, $13.6 million was a non-cash reduction in the mark-to-market value of our hedges as commodity prices improved during the first quarter of 2021, and $2.4 million were realized losses during the first quarter of 2021. During the three months ended March 31, 2020, we recorded a gain on derivatives of ~~$37.9~~$46.7 million. Of this amount, ~~$21.2 million were non-cash, unrealized mark-to-market gains as commodity prices declined from 2019 year-end levels, and $16.7~~$5.3 million were realized gains, ~~as derivative contracts were settled each month during the period. During the six~~

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~~months ended June 30, 2019, we recorded a loss on derivatives of $0.8 million. Of this amount, $2.1~~and $41.4 million were non-cash ~~unrealized~~ mark-to-market ~~losses, and the remaining $1.3 million were realized~~ gains.

Capital Resources and Liquidity

Our primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions and principal and interest payments on ~~debt.~~indebtedness. Our primary sources of immediate liquidity are cash generated by operations, net of the realized effect of our hedging agreements, and amounts available to be drawn under our Credit Agreement (as defined below).

Cash Provided by (Used in) Operating Activities

Cash flows provided by operating activities were approximately $30.7 million for the three months ended March 31, 2021 compared to cash flows used in operating activities of $0.2 million for the same period in 2020. The table below provides additional detail of cash flows from operating activities for the three months ended March 31, 2021 and 2020:


	Three Months Ended March 31,
	2021		2020

	(in thousands)
Cash flows from operating activities, exclusive of changes in working capital accounts	$	20,229	$	12,300
Changes in operating assets and liabilities		10,511		(12,548)
Net cash provided by (used in) operating activities	$	30,740	$	(248)

Cash Used in Investing Activities

Net cash flows used in investing activities were $119.5 million for the three months ended March 31, 2021, compared to cash flows used in investing activities of $9.5 million for the three months ended March 31, 2020. The 2021 activity is primarily related to the Mid-Con Acquisition and the Silvertip Acquisition, as discussed below.

On January 21, 2021, we closed on the Mid-Con Acquisition and issued a total of 25,409,164 shares of Contango common stock and paid all outstanding borrowings of Mid-Con’s existing credit facility for $68.7 million. See Item 1. Note 3 – “Acquisitions” for further details.

On February 1, 2021, we closed on the Silvertip Acquisition. In connection with the execution of the purchase agreement during the fourth quarter of 2020, we paid a $7.0 million as a deposit for the Company’s obligations. A balance of $46.2 million was paid upon closing, after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date.See Item 1. Note 3 – “Acquisitions” for further details.

During the ~~six~~three months ended ~~June 30, 2020,~~March 31, 2021, we incurred ~~onshore~~capital expenditures of approximately ~~$5.2~~$1.6 million onprimarily related to redevelopment activities of newly acquired properties in our Midcontinent region. The capital ~~projects, including $2.6 million~~expenditures in the ~~Southern Delaware Basin~~prior year quarter primarily related to ~~bring one well on production~~leasehold and ~~to drill a salt water disposal well, as well as $0.8 million in leasehold acquisition~~drilling costs in the ~~same region.~~Permian Basin in West Texas.

Our 2021 planned capital expenditure budget has increased to $24 - $27 million from previous guidance of $13 - $16 million for recompletions, facility upgrades, redevelopment activities, waterflood development and select drilling in West Texas (expected 1.5 net locations, 3 gross locations), among other things. The ~~remaining incurred onshore~~increase in planned capital expenditures ~~related primarily to capitalized workovers.~~

~~During the six months ended June 30, 2020 we recorded exploration expenses of $10.9 million related to the drilling~~reflects, in part, development opportunities in our recently acquired properties as part of the ~~unsuccessful offshore exploratory Iron Flea prospect drilled~~Mid-Con Acquisition and the Silvertip Acquisition, coupled with recent strength in crude oil prices. The capital expenditure program will continue to be evaluated for revision throughout the ~~shallow waters of~~year. We believe that we will have the ~~Gulf of Mexico. $2.7 million of~~financial resources to increase the ~~exploration expense related to the acquisition costs incurred in 2019 which were reclassified to exploration expense in 2020~~currently planned 2021 capital expenditure budget, when and if deemed appropriate, including as a result of ~~the dry hole.~~changes in commodity prices, economic conditions or operational factors.

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Cash Provided by Financing Activities

~~Our total capital expenditure program~~Cash flows provided by financing activities for the ~~year~~three months ended March 31, 2021 and 2020 ~~is forecast at~~were approximately ~~$19.0~~$89.0 million ~~including the expenses associated~~and $9.8 million, respectively, and primarily related to net payments under our Credit Agreement (as defined below).

In 2020, we entered into an Open Market Sale Agreement (the “Sale Agreement”) with ~~the Iron Flea exploratory prospect. Due~~Jefferies LLC (the “Sales Agent”). Pursuant to the ~~low~~terms of the Sale Agreement, we may sell, from time to time through the Sales Agent in the open market, subject to satisfaction of certain conditions, shares of our common stock having an aggregate offering price of up to $100,000,000 (the “ATM Program”). We intend to use the net proceeds from any sales through the ATM Program, after deducting the Sales Agent’s commission and ~~volatile commodity price environment,~~any offering expenses, to repay borrowings under our Credit Agreement (as defined below) and for general corporate purposes, including, but not limited to, acquisitions and exploratory drilling. Under the ~~Company has suspended any further plans~~Sale Agreement, we sold 117,000 shares for ~~drilling and completions in 2020. For~~net proceeds of $0.5 million during the remainder of 2020, we currently expect to limit our onshore capital expenditures to $5.5 million for workovers intended to increase cashflow through enhanced production or reductions in recurring costs, required onshore plugging and abandonment activity and West Texas infrastructure. We expect that our offshore expenditures for the remainder of 2020 will be focused on the evaluation and development of another exploratory prospect that may be drilled in earlythree months ended March 31, 2021.

We believe that our internally generated cash ~~flows, combined with~~flow and availability under ~~the~~our Credit Agreement (as defined below), will be sufficient to meet the liquidity requirements necessary to fund our daily operations and planned capital development and to meet our debt service requirements for the next twelve ~~months; however, should~~months. Our ability to execute on our ~~results~~growth strategy will be determined, in large part, by our cash flow and the availability of operations be less than expected, or we experience additional reductions in our borrowing base, we may need to pursue additional sources of liquidity such as monetization of a portion of our hedge portfolio or access the debt and equity ~~markets, as available,~~capital at that time. Any decision regarding a financing transaction, and our ability to ~~finance any necessary capital development and/or repay excess borrowings under our Credit Agreement, but there can be no assurance~~complete such ~~incremental financing~~a transaction, will ~~be available to us or not result in dilution of our stockholders or increase our debt service costs. The COVID-19 pandemic~~depend on prevailing market conditions and the ongoing disruptions to the global energy markets have negatively impacted, and are expected to continue to negatively impact, cash flows from operating activities. In order to mitigate these effects, we have implemented certain cost cutting measures, such as suspending our drilling program for the remainder of 2020.

On June 24, 2020, we entered into an Open Market Sale Agreement with Jefferies LLC. Pursuant to the terms of the agreement, we may sell from time to time shares of our Common Stock having an aggregate offering price of up to $100,000,000. We intend to use the net proceeds from the offering to repay borrowings under our Credit Agreement and for general corporate purposes. Under the Open Market Sale Agreement, we sold 155,029 shares during the three months ended June 30, 2020 for net proceeds of $0.5 million.

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~~Cash From Operating Activities~~

Cash flows provided by operating activities were approximately $8.2 million for the six months ended June 30, 2020 compared to $14.9 million provided by operating activities for the same period in 2019. The table below provides additional detail of cash flows from operating activities for the six months ended June 30, 2020 and 2019:

Six Months Ended June 30,

2020

2019

(in thousands)
Cash flows from operating activities, exclusive of changes in working capital accounts

$
17,663

$
5,902
Changes in operating assets and liabilities

(9,450)

8,996
Net cash used in operating activities

$
8,213

$
14,898

~~Cash From Investing Activities~~

Net cash flows used in investing activities were $19.5 million for the six months ended June 30, 2020, which was primarily related to the offshore exploratory prospect and completion and infrastructure costs in the Southern Delaware Basin.

Net cash flows used in investing activities were $14.6 million for the six months ended June 30, 2019, substantially all of which was related to cash capital costs for leasehold and drilling and completion costs of wells in the Southern Delaware Basin and non-operated wells in the Georgetown formation in Dimmitt County, Texas.

~~Cash From Financing Activities~~

Cash flows provided by financing activities for the six months ended June 30, 2020 were approximately $10.0 million with $6.4 million related to net borrowings outstanding under our Credit Agreement (as defined below), and approximately $3.4 million related to proceeds from the PPP loan we received under the CARES Act in April 2020. See “Paycheck Protection Program Loan” below for more information. Cash flows used in financing activities for the six months ended June 30, 2019 were approximately $0.3 million, primarily related to shares withheld from employees for the payment of taxes due on vested shares of restricted stock issued.other factors.

Credit Agreement

On September 17, 2019, we entered into a new revolving credit agreement with JPMorgan Chase Bank ~~(the~~ and other lenders (as amended, the “Credit Agreement”), which established a borrowing base of $65 million. T~~The~~he Credit Agreement was thereafter amended ~~on November 1, 2019, in conjunction with the closing of the Will Energy and White Star property acquisitions,~~ to add ~~two~~ additional ~~lenders~~banks to the lender group, to provide for certain modifications to the Company’s minimum hedging covenants, cash requirements and ~~increase~~financial covenants and adjust the borrowing base ~~thereunder~~pursuant to ~~$145 million. The~~ ~~borrowing base is subject to~~the regularly scheduled semi-annual redeterminations and may also be adjusted by certain events, including the incurrence of any senior unsecured debt, material asset dispositions or liquidation of hedges in excess of certain thresholds. Tredetermination process. heThe semi-annual redeterminations will occur on or around May 1^st and November 1^st of each ~~year.~~ year~~On June 9, 2020, we entered into~~. Upon the ~~Second~~close of the Mid-Con Acquisition on January 21, 2021, the Company’s borrowing base increased to $130.0 million with an automatic $10.0 million stepdown in the borrowing base on March 31, 2021. The Company’s borrowing base was $120.0 million as of March 31, 2021. See Item 1. Note 10 – “Long-Term Debt” for more information. The semi-annual redetermination occurred in May 2021, as regularly scheduled, and resulted in the Fifth Amendment to the Credit Agreement, (the “Second Amendment”). The Second Amendment redetermined the borrowing base at $95 million pursuant to the regularly scheduled redetermination process, which was in excess of borrowings outstanding. The Second Amendment also provides for, among other things, further $10 million automatic reductions in our borrowing base on each of June 30, 2020 and September 30, 2020. Accordingly, t~~he borrowing base was $85 million~~ as ~~of June 30, 2020.~~ Should borrowings outstanding exceed the reduced borrowing base on the dates of those stepdowns in the borrowing base, we would need to repay any excess within a short period of time through additional sources of liquidity, such as monetization of a portion of our hedge portfolio or the debt or equity capital markets, as available. Although we do not expect to have borrowings in excess of the reduced borrowing base on September 30, 2020, there can be no assurance that such sources of capital will be available to us. discussed below.

The Credit Agreement matures on September 17, 2024. As of June 30, 2020, the borrowing outstanding under the Credit Agreement was $79.1 million and $1.9 million in an outstanding letter of credit, and the borrowing availability under the Credit Agreement was $4.0 million.

The Credit Agreement contains customary and typical restrictive covenants. The ~~Credit Agreement requires~~Second Amendment included a waiver of the Current Ratio requirement of greater than or equal to ~~1.00~~1.0:1:0 and athe Leverage Ratio of less than or equal to ~~3.50,~~3.5:1:0, both as defined in the Credit ~~Agreement. The Second Amendment includes a waiver of the Current Ratio requirement~~Agreement, until the quarter ending March 31, 2022. ~~Additionally,~~However, the ~~Second~~Fifth Amendment ~~provides for, among other things,~~(as defined below), reinstates the ~~increase~~Current Ratio and Leverage Ratio requirements beginning in the ~~Applicable Margin grid on borrowings outstanding by 50 basis points,~~second quarter of 2021 and reduces the ~~implementation of an accounts payable aging reporting~~

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~~covenant, and the implementation of typical anti-cash hoarding provisions and a cash sweep requirement, in certain circumstances, with respect~~Leverage Ratio to ~~a consolidated cash balance in excess of $5.0 million.~~less than or equal to 3.25:1.0. As of ~~June 30, 2020,~~March 31, 2021, we were in compliance with all financial covenants under the Credit Agreement.

The borrowing outstanding under the Credit Agreement was $98.6 million as of March 31, 2021, and we had $2.9 million in outstanding letters of credit. The borrowing availability under the Credit Agreement was $18.5 million as of March 31, 2021.

On May 3, 2021, we entered into the Fifth Amendment to the Credit Agreement (the “Fifth Amendment”) which provides for, among other things, an increase in the Company’s borrowing base from $120.0 million to $250.0 million, effective May 3, 2021, expands the bank group from nine to eleven banks and includes less restrictive hedge requirements and certain modifications to the financial covenants. See Item 1. Note 13 – “Subsequent Events” for further details. Adjusted for the borrowing base increase to $250.0 million, effective on May 3, 2021, we had approximately $86.7 million outstanding under the Credit Agreement and $2.9 million in outstanding letters of credit, with borrowing availability of $160.4 million as of April 30, 2021.

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Paycheck Protection Program Loan

On April 10, 2020, we entered into a promissory note evidencing an unsecured loan in the amount of approximately $3.4 million (the “PPP Loan”) made to the Company under the Paycheck Protection Program (the “PPP”). The PPP was established under the Coronavirus Aid, Relief, and Economic Security Act (“CARES ~~Act~~Act”), signed into law on March 27, 2020, and is administered by the U.S. Small Business Administration. The PPP Loan to the Company is being made through JPMorgan Chase Bank, N.A and is included in ~~“Long Term~~“Long-Term Debt” on ~~our~~the Company’s consolidated balance sheet.

The PPP Loan matures on the two-year anniversary of the funding date and bears interest at a fixed rate of 1.00% per annum. Monthly principal and interest payments, less the amount of any potential forgiveness (discussed below), will commence after the six-month anniversary of the funding date. The promissory note evidencing the PPP Loan provides for customary events of default, including, among others, those relating to failure to make payment, bankruptcy, breaches of representations and material adverse effects. We may prepay the principal of the PPP Loan at any time without incurring any prepayment charges.

Under the terms of the CARES Act, PPP loan recipients can apply for and be granted forgiveness for all or a portion of the loans granted under the PPP, subject to an audit. Under the CARES Act, loan forgiveness is available, subject to limitations, for the sum of documented payroll costs, covered mortgage interest payments, covered rent payments and covered utilities during either: 1)(1) the eight-week period beginning on the funding date; or 2)(2) the 24-week period beginning on the funding date. Forgiveness is reduced if full-time employee headcount declines, or if salaries and wages for employees with salaries of $100,000 or less annually are reduced by more than 25%. We ~~intend to use~~utilized the PPP Loan amount for qualifying expenses during the 24-week coverage period, and ~~expect to apply~~on September 30, 2020, submitted our application for forgiveness of all ~~or part~~ of the PPP Loan in accordance with the terms of the CARES Act and ~~applicable~~related guidance. We are currently waiting on a response from the Small Business Administration to our application for forgiveness. In the event the PPP Loan or any portion thereof is forgiven, the amount forgiven is applied to the outstanding principal.

Application of Critical Accounting Policies and Management’s Estimates

Significant accounting policies that we employ and information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate are presented in Item 1. Note 2 to our Financial Statements – “Summary of Significant Accounting Policies” of this report and in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – “Application of Critical Accounting Policies and Management’s Estimates” in our ~~2019~~2020 Form 10-K.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements, see Item 1. Note 2 to our Financial Statements – “Summary of Significant Accounting Policies.”

Off Balance Sheet Arrangements

We may enter into off balance sheet arrangements that can give rise to off-balance sheet obligations. As of ~~June 30, 2020,~~March 31, 2021, our off balance sheet arrangements ~~consist~~consisted of delay rentals, surface damage payments and rental payments associated with salt water disposal contracts, as discussed in our ~~2019~~2020 Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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Our management, with the participation of our Chief Executive Officer and our Chief Financial and Accounting Officer, evaluated the effectiveness of the Company’s “disclosure controls and procedures” as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of ~~June 30, 2020.~~March 31, 2021. Based upon that

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evaluation, our Chief Executive Officer and our Chief Financial and Accounting Officer concluded that, as of ~~June 30, 2020,~~March 31, 2021, the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial and Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

The Company is in the ~~final stages~~process of ~~completing the integration of~~integrating the accounting for the operating results of the assets ~~of Will Energy~~acquired in the Mid-Con Acquisition and ~~White Star~~the Silvertip Acquisition into the Company’s internal control structure over financial reporting, and in conjunction with that process, and where deemed appropriate or necessary, has incorporated controls similar to Company controls currently existing. As a result of these integration activities, certain controls have been evaluated and revised where deemed appropriate. Other than such changes, t~~There~~here was no change in our internal control over financial reporting during the three months ended ~~June 30, 2020~~March 31, 2021 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of legal proceedings, see Item 1. Note 12 to our Financial Statements – “Commitments and Contingencies.”

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. of Part 1 of our ~~2019~~2020 Form ~~10-K and Item 1A. of Part II of our Quarterly Report on Form 10-Q for the period ended March 31, 2020.~~10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The Company withheld the following shares from employees during the quarter ended ~~June 30, 2020~~March 31, 2021 for the payment of taxes due on shares of restricted stock that vested and were issued under its stock-based compensation plans:



				Total Number of Shares		Approximate Dollar Value				Total Number of Shares		Approximate Dollar Value
	Total Number of	Average Price		Purchased as Part of		of Shares that May Yet	Total Number of	Average Price		Purchased as Part of		of Shares that May Yet
Period	Shares Withheld	Per Share		Publicly Announced Program		be Purchased Under Program	Shares Withheld	Per Share		Publicly Announced Program		be Purchased Under Program

April 2020	12,498	$	1.63	—	$	—
May 2020	1,310	$	1.91	—	$	—
June 2020	—	$	—	—	$	—
January 2021							—	$	—	—	$	—
February 2021							—	$	—	—	$	—
March 2021							33,587	$	4.95	—	$	—
Total	13,808	$	1.65	—	$	31.8 million ⁽¹⁾	33,587	$	4.95	—	$	31.8 million ⁽¹⁾

(1)

In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases are subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market. The program does not have an expiration date. No shares were purchased for the quarter ended ~~June 30, 2020.~~March 31, 2021. As of ~~June 30, 2020,~~March 31, 2021, the Company has $31.8 million available under its share repurchase program, however, those repurchases could be limited ~~under restrictions in~~by provisions of the Company’s Credit Agreement.

Item 3. Defaults upon Senior Securities

None.

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Item 4. Mine Safety Disclosures

Not applicable.

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Item 5. Other Information

None.

Item 6. Exhibits

Exhibit Number		Description
3.1		Amended and Restated Certificate of Formation of Contango Oil & Gas Company (filed as Exhibit 3.3 to the Company’s Report on Form 8-K dated June 14, 2019, as filed with the Securities and Exchange Commission on June 14, 2019 and incorporated by reference herein).
3.2		Bylaws of Contango Oil & Gas Company (filed as Exhibit 3.4 to the Company’s Report on Form 8-K dated June 14, 2019, as filed with the Securities and Exchange Commission on June 14, 2019 and incorporated by reference herein).
3.3		Certificate of Amendment to the Amended and Restated Certificate of Formation of Contango Oil & Gas Company, dated June 10, 2020 (filed as Exhibit 3.1 to the Company’s Report on Form 8-K dated June 11, 2020, as filed with the Securities and Exchange Commission on June 11, 2020 and incorporated by reference herein).
~~3.3~~10.1		~~Bylaws of~~Fourth Amendment to Credit Agreement, dated January 21, 2021, by and among Contango Oil & Gas Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders Signatory hereto (filed as Exhibit ~~3.4~~10.22 to the Company’s Report on Form ~~8-K~~10-K dated ~~June 14, 2019,~~March 10, 2021, as filed with the Securities and Exchange Commission on ~~June 14, 2019~~March 10, 2021 and incorporated by reference herein).
~~10.1~~10.2		~~Second~~Fifth Amendment to Credit Agreement, dated ~~June 9, 2020,~~May 3, 2021, by and among Contango Oil & Gas Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders Signatory hereto (filed as Exhibit 10.1 to the Company’s Report on Form 8-K dated ~~June 15, 2020,~~May 3, 2021, as filed with the Securities and Exchange Commission on ~~June 15, 2020~~May 4, 2021 and incorporated by reference herein).
~~10.2~~10.3*		~~Amended~~Form of Contango Oil and ~~Restated 2009~~Gas Company Restricted Stock ~~Incentive~~Award Agreement. †
10.4*		Form of Contango Oil and Gas Company Performance Stock Unit Award Agreement. †
10.5*		Contango Oil and Gas Company Change in Control Severance Plan. †
10.6*		Contango Oil and Gas Company Executive Severance Plan. †
31.1		Certification of Chief Executive Officer required by Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934. †
31.2		Certification of Chief Financial Officer required by Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934. †
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *††
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of ~~2002~~2002.. * ††
101		Interactive Data Files †

* Indicates a management contract or compensatory plan or arrangement

†	Filed herewith.

††	* Furnished herewith.

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SIGNATURES

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.


		CONTANGO OIL & GAS COMPANY


Date: ~~August 19, 2020~~May 13, 2021	By:	/s/ WILKIE S. COLYER
		Wilkie S. Colyer
		Chief Executive Officer
		(Principal Executive Officer)


Date: ~~August 19, 2020~~May 13, 2021	By:	/s/ E. JOSEPH GRADY
		E. Joseph Grady
		Senior Vice President and Chief Financial and Accounting Officer
		(Principal Financial and Accounting Officer)

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	Six Months Ended June 30, 2020		Six Months Ended June 30, 2019
Operating lease cost ^{(1) (2)}	$	1,430	$	471
Financing lease cost - amortization of right-of-use assets		284		-
Financing lease cost - interest on lease liabilities		52		-
Administrative lease cost⁽³⁾		38		37
Short-term lease cost ^{(1) (4)}		1,053		2,578
Total lease cost	$	2,857	$	3,086