CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE SIX MONTHS ENDED JUNE 30, ~~2020~~2021

TABLE OF CONTENTS



		Page
PART I—FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets ~~(unaudited)~~ as of June 30, ~~2020~~2021 (unaudited) and December 31, ~~2019~~2020	3
	Consolidated Statements of Operations (unaudited) for the three and six months ended June 30, ~~2020~~2021 and ~~2019~~2020	4
	Consolidated Statements of Cash Flows (unaudited) for the six months ended June 30, ~~2020~~2021 and ~~2019~~2020	5
	Consolidated Statement of Shareholders’ Equity (unaudited) for the six months ended June 30, ~~2020~~2021 and ~~2019~~2020	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	4045
Item 4.	Controls and Procedures	4045

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	4146
Item 1A.	Risk Factors	4146
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4150
Item 3.	Defaults upon Senior Securities	4150
Item 4.	Mine Safety Disclosures	4250
Item 5.	Other Information	4250
Item 6.	Exhibits	4251

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.

2

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,


2020

2019


(unaudited)

CURRENT ASSETS:

Cash and cash equivalents

$
404

$
1,624

Accounts receivable, net

25,672

39,567

Prepaid expenses

1,363

1,191

Current derivative asset

16,826

3,819

Inventory

1,710

186

Total current assets

45,975

46,387

PROPERTY, PLANT AND EQUIPMENT:

Oil and natural gas properties, successful efforts method of accounting:

Proved properties

1,315,040

1,306,916

Unproved properties

20,901

27,619

Other property and equipment

1,668

1,655

Accumulated depreciation, depletion and amortization

(1,206,957)

(1,045,070)

Total property, plant and equipment, net

130,652

291,120

OTHER NON-CURRENT ASSETS:

Investments in affiliates

6,879

6,766

Long-term derivative asset

4,395

357

Right-of-use lease assets

5,691

5,885

Debt issuance costs

1,939

3,311

Total other non-current assets

18,904

16,319

TOTAL ASSETS

$
195,531

$
353,826

CURRENT LIABILITIES:

Accounts payable and accrued liabilities

$
77,143

$
104,593

Current derivative liability

908

3,951

Current asset retirement obligations

2,291

2,003

Total current liabilities

80,342

110,547

NON-CURRENT LIABILITIES:

Long-term debt

82,537

72,768

Long-term derivative liability

917

2,020

Asset retirement obligations

45,581

49,662

Lease liabilities

2,156

2,789

Deferred tax liability

376

—

Total non-current liabilities

131,567

127,239

TOTAL LIABILITIES

211,909

237,786

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

Additional paid-in capital

472,814

471,778

Treasury shares at cost (70,612 shares at June 30, 2020 and 7,330 shares at December 31, 2019)

(198)

(18)

Accumulated deficit

(494,265)

(360,976)

Total shareholders’ equity (deficit)

(16,378)

116,040

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY (DEFICIT)

$
195,531

$
353,826


	June 30,		December 31,
	2021		2020
	(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	2,177	$	1,383
Accounts receivable, net		65,937		37,862
Prepaid expenses		6,142		3,360
Current derivative asset		—		2,996
Inventory		531		442
Deposits and other		—		763
Total current assets		74,787		46,806
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, successful efforts method of accounting:
Proved properties		1,502,215		1,274,508
Unproved properties		20,857		16,201
Other property & equipment		1,912		1,669
Accumulated depreciation, depletion, amortization and impairment		(1,176,134)		(1,190,475)
Total property, plant and equipment, net		348,850		101,903
OTHER NON-CURRENT ASSETS:
Investments in affiliates		5,989		6,793
Long-term derivative asset		—		497
Right-of-use lease assets		7,385		5,448
Debt issuance costs		3,873		1,782
Deposits		1,813		7,038
Total other non-current assets		19,060		21,558
TOTAL ASSETS	$	442,697	$	170,267

CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	132,527	$	83,970
Current derivative liability		41,176		1,317
Current asset retirement obligations		4,700		4,249
Total current liabilities		178,403		89,536
NON-CURRENT LIABILITIES:
Long-term debt		72,369		12,369
Long-term derivative liability		17,493		1,648
Asset retirement obligations		106,256		48,523
Lease liabilities		3,805		2,624
Total non-current liabilities		199,923		65,164
TOTAL LIABILITIES		378,326		154,700
COMMITMENTS AND CONTINGENCIES (NOTE 12)
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 400,000,000 shares authorized, 201,438,451 shares issued and 201,182,259 shares outstanding at June 30, 2021, 173,830,390 shares issued and 173,737,816 shares outstanding at December 31, 2020		8,045		6,941
Additional paid-in capital		620,595		535,192
Treasury shares at cost (256,192 shares at June 30, 2021 and 92,574 shares at December 31, 2020)		(1,016)		(248)
Accumulated deficit		(563,253)		(526,318)
Total shareholders’ equity		64,371		15,567
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	442,697	$	170,267

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

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Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

Three Months Ended

Six Months Ended

June 30,

June 30,


2020

2019

2020

2019

(unaudited)

(unaudited)

REVENUES:

Oil and condensate sales

$
7,930

$
7,439

$
30,712

$
13,845

Natural gas sales

6,618

3,857

14,789

9,499

Natural gas liquids sales

3,294

1,466

6,915

3,429

Total revenues

17,842

12,762

52,416

26,773

EXPENSES:

Operating expenses

17,139

5,694

38,621

10,886

Exploration expenses

11,173

249

11,571

473

Depreciation, depletion and amortization

5,092

7,573

17,946

15,129

Impairment and abandonment of oil and gas properties

—

1,247

145,878

1,834

General and administrative expenses

5,713

4,456

11,138

9,461

Total expenses

39,117

19,219

225,154

37,783

OTHER INCOME (EXPENSE):

Gain (loss) from investment in affiliates, net of income taxes

(173)

427

113

457

Gain from sale of assets

4,406

421

4,433

409

Interest expense

(2,151)

(1,079)

(3,365)

(2,171)

Gain (loss) on derivatives, net

(8,804)

2,065

37,895

(813)

Other income

332

89

1,136

3

Total other income (expense)

(6,390)

1,923

40,212

(2,115)

NET LOSS BEFORE INCOME TAXES

(27,665)

(4,534)

(132,526)

(13,125)

Income tax provision

(369)

(427)

(763)

(454)

NET LOSS

$
(28,034)

$
(4,961)

$
(133,289)

$
(13,579)

NET LOSS PER SHARE:

Basic

$
(0.21)

$
(0.15)

$
(1.01)

$
(0.40)

Diluted

$
(0.21)

$
(0.15)

$
(1.01)

$
(0.40)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:

Basic

131,449

33,909

131,394

33,840

Diluted

131,449

33,909

131,394

33,840


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020

	(unaudited)				(unaudited)
REVENUES:
Oil and condensate sales	$	56,209	$	7,930	$	93,202	$	30,712
Natural gas sales		14,823		6,618		29,315		14,789
Natural gas liquids sales		12,279		3,294		20,560		6,915
Other operating revenues		329		—		513		—
Total revenues		83,640		17,842		143,590		52,416
EXPENSES:
Operating expenses		36,509		15,016		63,985		34,272
Exploration expenses		87		11,173		284		11,571
Depreciation, depletion and amortization		11,457		5,092		20,599		17,946
Impairment and abandonment of oil and natural gas properties		451		—		454		145,878
General and administrative expenses		13,483		7,836		24,842		15,487
Total expenses		61,987		39,117		110,164		225,154
OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates, net of income taxes		(804)		(173)		(804)		113
Gain from sale of assets		131		4,406		348		4,433
Interest expense		(1,361)		(2,151)		(2,558)		(3,365)
Gain (loss) on derivatives, net		(53,480)		(8,804)		(69,561)		37,895
Other income		1,035		332		2,569		1,136
Total other income (expense)		(54,479)		(6,390)		(70,006)		40,212
NET LOSS BEFORE INCOME TAXES		(32,826)		(27,665)		(36,580)		(132,526)
Income tax benefit (provision)		184		(369)		(355)		(763)
NET LOSS	$	(32,642)	$	(28,034)	$	(36,935)	$	(133,289)
NET LOSS PER SHARE:
Basic	$	(0.16)	$	(0.21)	$	(0.19)	$	(1.01)
Diluted	$	(0.16)	$	(0.21)	$	(0.19)	$	(1.01)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		198,722		131,449		195,714		131,394
Diluted		198,722		131,449		195,714		131,394

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

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Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

Six Months Ended

June 30,

2020

2019

(unaudited)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net loss

$
(133,289)

$
(13,579)

Adjustments to reconcile net loss to net cash provided by operating activities:

Depreciation, depletion and amortization

17,946

15,129

Impairment of oil and natural gas properties

145,878

1,079

Exploration expenditures - dry hole costs

10,878

—

Amortization of debt issuance costs

1,372

—

Deferred income taxes

—

424

Gain on sale of assets

(4,433)

(409)

Gain from investment in affiliates

(113)

(457)

Stock-based compensation

616

1,637

Unrealized loss (gain) on derivative instruments

(21,192)

2,078

Changes in operating assets and liabilities:

Decrease in accounts receivable & other receivables

13,614

1,530

Decrease (increase) in prepaids

(172)

298

Increase in inventory

(1,560)

—

Increase (decrease) in accounts payable & advances from joint owners

(17,132)

8,592

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

CASH FLOWS FROM INVESTING ACTIVITIES:

Oil and natural gas exploration and development expenditures

$
(19,719)

$
(14,604)

Additions to furniture & equipment

(77)

(17)

Sale of oil & gas properties

339

—

Net cash used in investing activities

$
(19,457)

$
(14,621)

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

—

Net proceeds (costs) from equity offering

435

(41)

Purchase of treasury stock

(180)

(236)

Net cash provided by (used in) financing activities

$
10,024

$
(277)

NET CHANGE IN CASH AND CASH EQUIVALENTS

$
(1,220)

$
—

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

1,624

—

CASH AND CASH EQUIVALENTS, END OF PERIOD

$
404

$
—


	Six Months Ended
	June 30,
	2021		2020

	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(36,935)	$	(133,289)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		20,599		17,946
Impairment and abandonment of oil and natural gas properties		27		145,878
Exploration expenditures - dry hole costs		—		10,878
Amortization of debt issuance costs		434		1,372
Gain on sale of assets		(348)		(4,433)
Loss (gain) from investment in affiliates		804		(113)
Stock-based compensation		4,889		616
Non-cash mark-to-market loss (gain) on derivative instruments		60,740		(21,192)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable & other receivables		(19,291)		13,614
Increase in prepaid expenses		(2,557)		(172)
Increase in inventory		(89)		(1,560)
Increase (decrease) in accounts payable & advances from joint owners		20,753		(17,132)
Increase (decrease) in other accrued liabilities		8,053		(4,636)
Decrease in income taxes receivable, net		268		281
Increase (decrease) in income taxes payable		(451)		119
Decrease in deposits and other		7,138		36
Net cash provided by operating activities	$	64,034	$	8,213
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas exploration and development expenditures	$	(5,598)	$	(19,719)
Acquisition of oil & natural gas properties		(117,555)		—
Sale of oil & natural gas properties		2,775		339
Additions to furniture & equipment		—		(77)
Net cash used in investing activities	$	(120,378)	$	(19,457)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Credit Agreement	$	158,300	$	55,000
Repayments under Credit Agreement		(98,300)		(48,600)
Paycheck Protection Program loan		—		3,369
Net proceeds from equity offering		432		435
Purchase of treasury stock		(768)		(180)
Debt issuance costs		(2,526)		—
Net cash provided by financing activities	$	57,138	$	10,024
NET CHANGE IN CASH AND CASH EQUIVALENTS	$	794	$	(1,220)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		1,383		1,624
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	2,177	$	404

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

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Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

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

For the six months ended June 30, ~~2020~~2021

(in thousands, except number of shares)

Series C

Additional

Total

Preferred Stock

Common Stock

Paid-in

Treasury

Accumulated

Shareholders’


Shares

Amount

Shares

Amount

Capital

Stock

Deficit

Equity (Deficit)

(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)

Treasury shares at cost

—

—

(49,474)

—

—

(157)

—

(157)

Restricted shares activity

—

—

77,485

3

(3)

—

—

—

Stock-based compensation

—

—

—

—

350

—

—

350

Net loss

—

—

—

—

—

—

(105,255)

(105,255)

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)


				Additional						Total
	Common Stock			Paid-in		Treasury		Accumulated		Shareholders’
	Shares	Amount		Capital		Stock		Deficit		Equity

	(unaudited)
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	(33,587)		—		—		(166)		—		(166)
Restricted shares activity	37,041		2		(2)		—		—		—
Stock-based compensation	—		—		1,797		—		—		1,797
Net loss	—		—		—		—		(4,293)		(4,293)
Balance at March 31, 2021	199,267,434	$	7,963	$	615,949	$	(414)	$	(530,611)	$	92,887
Equity offering - common stock	60,613		2		(22)		—		—		(20)
Mid-Con Acquisition	143,769		6		448		—		—		454
Stock issuance for prospect costs	387,011		16		1,096		—		—		1,112
Treasury shares at cost	(131,894)		—		—		(602)		—		(602)
Restricted shares activity	1,455,326		58		(58)		—		—		—
Stock-based compensation	—		—		3,182		—		—		3,182
Net loss	—		—		—		—		(32,642)		(32,642)
Balance at June 30, 2021	201,182,259	$	8,045	$	620,595	$	(1,016)	$	(563,253)	$	64,371

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 months ended June 30, ~~2019~~2020

(in thousands, except number of shares)

Additional

Total

Common Stock

Paid-in

Treasury

Accumulated

Shareholders’


Shares

Amount

Capital

Stock

Deficit

Equity (Deficit)

(unaudited)

Balance at December 31, 2018

34,158,492

$
1,573

$
339,981

$
(129,030)

$
(72,135)

$
140,389

Equity offering costs

—

—

(86)

—

—

(86)

Treasury shares at cost

(49,415)

—

—

(186)

—

(186)

Restricted shares activity

307,650

12

(12)

—

—

—

Stock-based compensation

—

—

1,052

—

—

1,052

Net loss

—

—

—

—

(8,618)

(8,618)

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


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

	(unaudited)
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	—		—	(49,474)		—		—		(157)		—		(157)
Restricted shares activity	—		—	77,485		3		(3)		—		—		—
Stock-based compensation	—		—	—		—		350		—		—		350
Net loss	—		—	—		—		—		—		(105,255)		(105,255)
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)

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

7

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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~~utilize 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:~~2021:

~~Location~~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, Offshore Gulf of Mexico	~~Offshore~~ properties in water depths off of Louisiana ~~- water depths~~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⁾others

~~(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~~failure by the Organization of Petroleum Exporting Countries (“OPEC”), and Russia ~~and other oil producing nations,~~to reach an agreement on lower production quotas until April 2020, resulted in oil prices declining significantly beginning in late February 2020. While there has been ~~a modest recovery~~an improvement in ~~oil~~commodity prices ~~the length of this demand disruption is unknown,~~since early 2020, prices remain volatile, and there is still significant uncertainty regarding the long-term impact toof the COVID-19 pandemic on global oil demand ~~which has negatively impacted the Company’s results of operations~~ and ~~planned 2020 capital activities.~~prices. 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 suspended its onshore drilling program in the Southern Delaware Basin in the first quarter of 2020. The Company further suspended all drilling in the second quarter of 2020, before resuming drilling in the second quarter of 2021. During this time, the Company has focused on certain measures that include, but have not been limited to, the following:

●

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

●

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;

●

the identification of more cost-efficient drilling and completion strategies by the Company’s technical teams and the possible commencement of a conservative drilling/completion program on undeveloped opportunities in the Company’s portfolio should oil prices, and market stability, continue to improve and provide appropriate risk-weighted returns; and

●

the extensive review of assets acquired in recent transactions for cost reduction opportunities, as well as opportunities to return to production wells that had been shut-in by the previous owners due to limited capital resources.

Corporate Overview and Capital Allocation

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 ~~any~~drilling in this area in response to the dramatic decline in oil prices and further ~~plans for~~suspended all drilling in the second quarter of 2020. Due to strengthening oil prices and the Company’s identification of more efficient methods of drilling and completing its Permian Basin wells, in the second quarter of 2021, the Company resumed its onshore drilling program in ~~2020.~~

the Southern Delaware Basin. In May 2021, the Company began drilling the first of three single-pad wells originally planned in the Southern Delaware Basin in the Permian region. Based on recent success by

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~~Management Services~~offset operators to the Company’s position, the Company decided to drill one of the three wells in this first pad to the Second Bone Spring formation, which will be the first Company well being drilled to that formation. The Company expects to bring these wells online in the third quarter of 2021. Due to the success and efficiency in the drilling of these first three wells and the improved oil price market, the Company commenced spudding a second three-well pad in July 2021 as part of its 2021 Permian drilling program. During the six months ended June 30, 2021, the Company incurred capital drilling expenditures of approximately $5.2 million related to the Southern Delaware Basin wells. As of June 30, 2021, the Company was producing from 18 wells over its approximate 16,200 gross operated (7,500 company net) acre position in its Permian region, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations. During the first half of 2021, the Company also incurred approximately $6.4 million in expenditures for redevelopment activities primarily related to recently acquired properties in the Midcontinent, Permian and Rockies regions and $1.9 million in unproved offshore prospect costs, of which $1.1 million was paid for with the proceeds of an issuance of Company common stock, pursuant to a joint development agreement between the Company and Juneau Oil & Gas, LLC.

The Company currently forecasts its 2021 capital expenditure budget to be a total of $30.0 - $34.0 million for recompletions, facility upgrades, waterflood development and the select drilling in the West Texas Permian (expected 3 net locations, 6 gross locations), among other things. The planned capital expenditures also include development opportunities with respect to certain properties acquired by the Company as part of the Mid-Con Acquisition and the Silvertip Acquisition (both as defined below). The capital expenditure program will continue to be evaluated for revision throughout the year. The Company believes that its internally generated cash flow will be more than adequate to fund its 2021 capital expenditure budget and any increase to such 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, while continuing to pursue its strategy of asset consolidation by evaluating acquisition opportunities that may arise in this challenging commodity price environment. 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 recently 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)~~, 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 25,552,933 shares of Contango common stock were issued as consideration in the Mid-Con Acquisition. Effective upon the closing of the 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 Dispositions” 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 ~~July~~date of August 1, 2020 and the closing date, the net consideration paid was approximately $53.2 million. See Note 3 – “Acquisitions and Dispositions” for more information.

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 ~~provide operational services as operator of record on Mid-Con’s oil~~all employees including the Company’s named executive officers. The policy provides an eligible participant with certain payments and ~~gas properties~~benefits in ~~exchange for an annual services fee 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~~event that the ~~agreement~~participant experiences a qualifying termination event within the 12-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 ~~effect (not to exceed $2 million), to be paid in a lump sum upon termination of~~control, 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 sonCompany’s Chief Executive Officer and the Company’s President ~~of Goff Capital, Inc.~~would become entitled to receive 250%, ~~serves on~~and the ~~board of directors of the general partner of Mid-Con.~~

~~Authorized Shares of Common Stock~~Company’s Senior Vice President and ~~Conversion of Series C Contingent Convertible Preferred Stock~~

~~On June 10, 2020, the Company filed an amendment (the “Charter Amendment”)~~Chief Financial Officer would become entitled to its Amended and Restated Certificate of Formation with the Secretary of State of the State of Texas to increase the number of authorized shares of common stock, par value of $0.04 per share (the “common stock”)receive 200%, of the ~~Company from 200,000,000~~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

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(4) any outstanding unvested PSU equity awards (defined below) held by the executive will remain outstanding and vest based on the greatest of (a) actual performance through the execution date of the definitive documentation governing the change in control, (b) actual performance through the date of 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 ~~400,000,000 shares. The Charter Amendment~~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 ~~conversion~~executive became subject to excise taxes under Section 4999 of ~~2,700,000 shares~~the Code.

On April 28, 2021, the Company 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 change in control. The Severance Plan provides an eligible participant with payments and benefits in the 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 Company’s ~~Series C contingent convertible preferred stock, par value $0.04 per share (the “Series C contingent convertible preferred stock”)~~Chief Executive Officer and the Company’s President, 150%, ~~into 2,700,000 shares~~and in the case of the Company’s ~~common stock were approved~~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 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; (4) all outstanding unvested time-based equity awards held by the ~~stockholders~~executive will 100% accelerate and become exercisable or settle (as applicable); and (5) a pro-rated portion of any outstanding unvested PSU awards held by the ~~Company~~executive will remain outstanding and vest based on ~~June 8, 2020, at~~actual performance over the Company’s 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 of the Series C contingent convertible preferred stock included John Goff, Wilkie Colyer and Farley Dakan, the Company’s current president.

~~Open Market Sale Agreement~~

applicable performance period.

On ~~June 24, 2020,~~May 3, 2021, the Company entered into ~~an Open Market Sale~~the Fifth Amendment to the Credit Agreement (the ~~“Sale Agreement”~~“Fifth Amendment”) which provided for, among other things, an increase in the Company’s borrowing base from $120.0 million to $250.0 million, effective May 3, 2021, and expanded the bank group from nine to eleven banks. The Fifth Amendment also includes less restrictive hedge requirements and certain modifications to financial covenants. See Note 10 – “Long-Term Debt” for more information.

On June 7, 2021, the Company ~~and Jefferies~~entered into a definitive agreement to combine with Independence Energy, LLC (“Independence”) in an all-stock transaction (the ~~“Sales Agent”~~“Pending Independence Merger”). ~~Pursuant~~Independence is a diversified, well-capitalized upstream oil and gas business built and managed by KKR’s Energy Real Assets team with a scaled portfolio of low-decline, producing assets with meaningful reinvestment opportunities for low-risk growth across the Eagle Ford, Rockies, Permian and Mid-Continent regions. The closing of the Pending Independence Merger is conditioned upon approval by a majority of Contango’s shareholders, among certain other closing conditions. Upon completion of the Pending Independence Merger, Independence shareholders are expected to own approximately 76% and Contango shareholders are expected to own approximately 24% of the combined company. If approved, the Pending Independence Merger is expected to close in the fourth quarter of 2021. See Note 3 – “Acquisitions and Dispositions” for further details.

On July 7, 2021, the Company entered into a purchase and sale agreement with ConocoPhillips to acquire low decline, conventional gas assets in the Wind River Basin of Wyoming (the “Pending Wind River Basin Acquisition”). Upon closing, Contango will acquire approximately 446 Bcfe of PDP reserves (unaudited) for a total purchase price of $67.0 million in cash, subject to customary purchase price adjustments. Closing of the Pending Wind River Basin Acquisition is expected to occur in the third quarter of 2021, subject to the ~~terms~~satisfaction of certain closing conditions set forth in the Sale Agreement, the Company may sell from time to time through the Sales Agent, shares of the Company’s common stock, having an aggregate public offering price of up to $100,000,000 (the “Shares”). The Company intends to use the net proceeds from the offering, after deducting the Sales Agent’s commissionpurchase and ~~the Company’s offering expenses, to repay borrowings under its Credit Agreement (as defined below) and~~sale agreement. See 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.

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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.

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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, a corresponding decrease in commodity prices, and reduced the demand for all commodity products. Consequently, during the ~~three~~six months ended ~~March 31,~~June 30, 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 impact of the lower prices on 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.

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. The Company recorded a $0.2 million non-cash charge for unproved impairment expense during the six months ended June 30, 2021 related to expiring leases in the Company’s Permian region. The Company recorded a $2.6 million non-cash charge for unproved impairment expense during the six months ended June 30, 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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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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Merger with Independence

On June 7, 2021, the Company entered into a definitive agreement to combine with Independence in an all-stock transaction. Independence is a diversified, well-capitalized upstream oil and gas business built and managed by KKR’s Energy Real Assets team with a scaled portfolio of low-decline, producing assets with meaningful reinvestment opportunities for low-risk growth across the Eagle Ford, Rockies, Permian and Mid-Continent regions. The closing of the Pending Independence Merger is conditioned upon approval by a majority of Contango’s shareholders, among certain other closing conditions. Upon completion of the Pending Independence Merger, Independence shareholders are expected to own approximately 76% and Contango shareholders are expected to own approximately 24% of the combined company. If approved, the Pending Independence Merger is expected to close in the fourth quarter of 2021.

Mid-Con Acquisition

On October 25, 2020, the Company entered into an Agreement and Plan of Merger 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 conflicts committee of 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 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 Mid-Con issued and 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 25,552,933 shares of Contango common stock were issued as consideration in the Mid-Con Acquisition. As of January 21, 2021, John C. Goff, Chairman of the Board of Directors of the Company, beneficially owned approximately 56.4% of the common units of Mid-Con, and Travis Goff, John C. Goff’s son and the President of Goff Capital, Inc., served on the board of directors of the general partner of Mid-Con. The 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.

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 in determining the fair value of the oil and natural gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and natural gas reserves, expectations for the timing and amount of future development and operating costs, future plugging and abandonment 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 Mid-Con Acquisition.

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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:
Mid-Con outstanding units		14,602
Exchange ratio of Contango shares for Mid-Con common units		1.75
Contango common stock to be issued to Mid-Con unitholders		25,553
Issue price	$	3.13
Stock consideration		79,979
Cash consideration in lieu of fractional shares		4
Payment of revolving credit facility		68,667
Total consideration	$	148,650

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		174,331
Other property and equipment		243
Other non-current assets		1,150
Total fair value of assets acquired	$	185,794

Silvertip Acquisition

On November 27, 2020, the Company entered into a 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 approximately $58.0 million in cash. In ~~November 2019,~~connection with the ~~FASB issued ASU 2019-12 – Income Taxes (“Topic 740”): Simplifying~~execution of the ~~Accounting~~Purchase Agreement, the Company paid $7.0 million as a deposit for ~~Income Taxes.~~its obligations under the Purchase Agreement, which is included in the consolidated balance sheet as of December 31, 2020. The ~~amendments in ASU 2019-12 are part~~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 as an ~~initiative to reduce complexity in accounting standards and simplify~~asset acquisition under ASC 805. Under the accounting for ~~income taxes by removing certain exceptions from Topic 740~~asset acquisitions, the Silvertip Acquisition was recorded using a cost accumulation and ~~making minor improvements~~allocation model under which the cost of the acquisition was allocated on a relative fair value basis to the ~~codification. The amendments in this update~~assets acquired and liabilities assumed. As an asset acquisition, acquisition-related transaction costs 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~~capitalized as 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~~component of the ~~Effects~~cost of ~~Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional expedients~~the assets acquired.

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A summary of the consideration paid and ~~exceptions for applying GAAP to contract modifications~~the preliminary relative fair value of the assets acquired and ~~hedging relationships,~~liabilities assumed, which is subject to ~~meeting certain criteria, that reference LIBOR or another rate~~change based upon the final settlement statement that is expected to be ~~discontinued. ASU 2020-04~~provided to Contango in the third 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)

Dispositions

During the six months ended June 30, 2021, the Company sold certain non-core Powder River Basin producing properties in ~~effect through December 31, 2022. We are currently assessing~~Wyoming, which were acquired in the ~~potential impact~~first quarter of ~~ASU 2020-04 on our consolidated financial statements.~~2021 as part of the Silvertip Acquisition. The Company also sold certain non-core, legacy and recently acquired producing and non-producing properties located in its Midcontinent, Permian and Other regions. These properties were sold for a collective total of approximately $2.8 million in cash and the buyers’ assumption of approximately $4.6 million in plugging and abandonment liabilities, resulting in a net gain of $0.3 million recorded during the six months ended June 30, 2021.

~~3. Dispositions~~

OnDuring the six months ended June 1,30, 2020, the Company ~~closed on the sale of~~sold certain producing and non-producing properties located in its ~~Central Oklahoma and Western Anadarko regions.~~Midcontinent region. These properties were ~~acquired~~sold for approximately $0.5 million in cash and the ~~Will Energy acquisition and were sold in exchange for the buyer’s~~buyers’ assumption of ~~the~~approximately $5.0 million in plugging and abandonment liabilities ~~of these properties~~ and revenue held in suspense. The Company recorded a gain of ~~$4.2~~$4.4 million, primarily as a result of the ~~buyer’s~~buyers’ assumption of the asset retirement obligations associated with the sold properties.

On April 1, 2020, the Company closed on the sale 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 result of the buyer’s assumption of the asset retirement obligations associated with the sold properties.

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On June 10, 2019, the Company sold certain minor, non-core operated assets located in Lavaca and Wharton counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.4 million as a result of the buyer’s assumption of the asset retirement obligations associated with the sold properties.

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.

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.~~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~~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	$	—	$	—	$	—	$	—	$	—
Commodity price contracts - liabilities	$	(1,825)	$	—	$	(1,825)	$	—	$	(58,669)	$	—	$	(58,669)	$	—

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,~~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.

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Table of Contents

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 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,~~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.

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


					Weighted Average
Commodity	Period	Derivative	Volume/Quarter		Price/Unit					Fair Value
Oil	Q3 2021	Swap	579,941	Bbls	$	57.15			⁽¹⁾		(8,833)
Oil	Q4 2021	Swap	547,251	Bbls	$	57.06			⁽¹⁾		(7,039)
Oil	Q1 2022	Swap	585,000	Bbls	$	56.34			⁽¹⁾		(6,821)
Oil	Q2 2022	Swap	473,000	Bbls	$	52.92			⁽¹⁾		(6,377)
Oil	Q3 2022	Swap	417,000	Bbls	$	51.27			⁽¹⁾		(5,664)
Oil	Q4 2022	Swap	407,000	Bbls	$	51.86			⁽¹⁾		(4,776)
Oil	Q1 2023	Swap	380,000	Bbls	$	53.15			⁽¹⁾		(3,570)
Oil	Q2 2023	Swap	150,000	Bbls	$	58.43			⁽¹⁾		(564)
Oil	Q3 2021	Collar	60,941	Bbls	$	52.00	-	58.80	⁽¹⁾		(840)
Oil	Q4 2021	Collar	60,251	Bbls	$	52.00	-	58.80	⁽¹⁾		(727)
Natural Gas	Q3 2021	Swap	3,140,000	MMBtus	$	2.71			⁽²⁾		(2,898)
Natural Gas	Q4 2021	Swap	3,000,000	MMBtus	$	2.63			⁽²⁾		(3,134)
Natural Gas	Q1 2022	Swap	3,090,000	MMBtus	$	2.69			⁽²⁾		(3,037)
Natural Gas	Q2 2022	Swap	2,425,000	MMBtus	$	2.51			⁽²⁾		(1,061)
Natural Gas	Q3 2022	Swap	2,300,000	MMBtus	$	2.51			⁽²⁾		(1,058)
Natural Gas	Q4 2022	Swap	2,250,000	MMBtus	$	2.65			⁽²⁾		(945)
Natural Gas	Q1 2023	Swap	1,500,000	MMBtus	$	2.72			⁽²⁾		(776)
Natural Gas	Q4 2021	Collar	400,000	MMBtus	$	3.00	-	3.41	⁽¹⁾		(175)
Natural Gas	Q1 2022	Collar	510,000	MMBtus	$	3.00	-	3.41	⁽²⁾		(234)
Natural Gas	Q1 2023	Collar	550,000	MMBtus	$	2.63	-	3.01	⁽²⁾		(140)
Total net fair value of derivative instruments (in thousands)										$	(58,669)

Commodity

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

Oil

Aug 2020 - Dec 2020

Swap

35,000
Bbls

$
54.58
⁽¹⁾

$
2,617

Oil

Jan 2021 - March 2021

Swap

19,000
Bbls

$
50.00
⁽¹⁾

$
568

Oil

April 2021 - July 2021

Swap

12,000
Bbls

$
50.00
⁽¹⁾

$
462

Oil

Aug 2021 - Sept 2021

Swap

10,000
Bbls

$
50.00
⁽¹⁾

$
187

Oil

Jan 2021 - July 2021

Swap

62,000
Bbls

$
52.00
⁽¹⁾

$
5,106

Oil

Aug 2021 - Sept 2021

Swap

55,000
Bbls

$
52.00
⁽¹⁾

$
1,248

Oil

Oct 2021 - Dec 2021

Swap

64,000
Bbls

$
52.00
⁽¹⁾

$
2,136

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

~~(1)~~
(1) Based on West Texas Intermediate oil prices.
(2) Based on Henry Hub NYMEX natural gas prices.

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

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~~In addition~~Subsequent to the ~~above financial derivative instruments,~~end of the second quarter of 2021, the Company ~~also had a costless swap agreement with a Midland WTI – Cushing oil differential swap price of $0.05 per barrel of oil. The agreement fixes~~entered into 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.~~following additional derivative contracts:


					Weighted Average
Commodity	Period	Derivative	Volume/Quarter		Price/Unit
Natural Gas	Q3 2021	Swap	725,000	MMBtus	$	3.71	⁽¹⁾
Natural Gas	Q4 2021	Swap	975,000	MMBtus	$	3.71	⁽¹⁾
Natural Gas	Q1 2022	Swap	900,000	MMBtus	$	3.10	⁽¹⁾
Natural Gas	Q2 2022	Swap	1,950,000	MMBtus	$	3.10	⁽¹⁾
Natural Gas	Q3 2022	Swap	1,350,000	MMBtus	$	3.10	⁽¹⁾
Natural Gas	Q4 2022	Swap	1,550,000	MMBtus	$	3.10	⁽¹⁾
Natural Gas	Q1 2023	Swap	1,350,000	MMBtus	$	2.73	⁽¹⁾
Natural Gas	Q2 2023	Swap	3,000,000	MMBtus	$	2.73	⁽¹⁾

(1)

Based on Henry Hub NYMEX natural gas prices.

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


	Gross		Netting ⁽¹⁾		Total
Assets	$	—	$	—	$	—
Liabilities	$	(58,669)	$	—	$	(58,669)

Gross

Netting ⁽¹⁾

Total

Assets

$
21,221

$
—

$
21,221

Liabilities

$
(1,825)

$
—

$
(1,825)

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

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Table of Contents

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
Assets	$	3,493	$	—	$	3,493
Liabilities	$	(2,965)	$	—	$	(2,965)

Gross

Netting ⁽¹⁾

Total

Assets

$
4,176

$
—

$
4,176

Liabilities

$
(5,971)

$
—

$
(5,971)

(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, ~~2020~~2021 and ~~2019~~2020 (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019		2021		2020		2021		2020
Oil contracts	$	8,461	$	286	$	11,258	$	941	$	(5,792)	$	8,461	$	(7,674)	$	11,258
Natural gas contracts		2,933		211		5,445		324		(588)		2,933		(1,147)		5,445
Realized gain	$	11,394	$	497	$	16,703	$	1,265
Realized gain (loss)									$	(6,380)	$	11,394	$	(8,821)	$	16,703

Oil contracts	$	(16,557)	$	365	$	24,170	$	(3,077)	$	(35,139)	$	(16,557)	$	(48,925)	$	24,170
Natural gas contracts		(3,641)		1,203		(2,978)		999		(11,961)		(3,641)		(11,815)		(2,978)
Unrealized gain (loss)	$	(20,198)	$	1,568	$	21,192	$	(2,078)
Non-cash mark-to-market gain (loss)									$	(47,100)	$	(20,198)	$	(60,740)	$	21,192
Gain (loss) on derivatives, net	$	(8,804)	$	2,065	$	37,895	$	(813)	$	(53,480)	$	(8,804)	$	(69,561)	$	37,895

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 “2009 Plan”) which allows for stock options, restricted stock or performance stock units to be awarded to executive officers, directors and employees as a performance-based award.

On July 14, 2021, the ~~“Plan”) in the form~~Company’s board of directors, subject to stockholder approval, approved an amendment ~~and restatement of~~to the 2009 Plan that ~~among other things, increases~~will (i) increase the number of shares of the Company’s common stock authorized for issuance pursuant to the 2009 Plan by ~~9,000,000~~11,500,000 from 12,500,000 shares to 24,000,000 shares, plus effective immediately following the closing of the Pending Independence Merger and ~~increases~~ the ~~maximum aggregate~~assumption of the 2009 Plan by New PubCo (as defined below), a number of shares equal to 2% of the outstanding shares of New PubCo Class A Common Stock (as defined below) measured as of immediately following the closing of the Pending Independence Merger and (ii) adjust the eligibility provision such that individuals who are employed by KKR Energy Assets Manager LLC or one of its partners as of the closing of the Pending Independence Merger will not be eligible to participate in the 2009 Plan unless such individual is providing services as a non-employee director to New PubCo.

Restricted Stock

During the six months ended June 30, 2021, the Company issued 54,825 restricted stock awards to the members of the board of directors, in lieu of cash fees earned during the fourth quarter of 2020 and first quarter of 2021, which vested immediately. During the six months ended June 30, 2021, the Company granted 1,415,189 shares of restricted common stock ~~that may be~~to employees, which vest ratably over three years, under the 2009 Plan, as part of their overall compensation package. The Company also granted 80,142 shares of restricted common stock related to internal reorganizational changes. The weighted average fair value of the restricted shares granted during the six months ended June 30, 2021, was $3.72 per share, with a total fair value of approximately $5.8 million and no adjustment for an estimated weighted average forfeiture rate. There were 57,789 forfeitures of restricted stock during the six months ended June 30, 2021. The aggregate intrinsic value of restricted shares forfeited during the six months ended June 30, 2021 was approximately $0.2 million. The Company recognized approximately $1.2 million in restricted stock compensation expense during the six months ended June 30, 2021, related to restricted stock previously granted to ~~any individual during any calendar year from 250,000 to 1,000,000. The Plan allows for stock options,~~its officers, employees and directors. As of June 30, 2021, an additional $6.3 million of future restricted stock ~~or performance stock units~~compensation expense remained to be ~~awarded to officers, directors and employees~~recognized over the weighted-

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Table of Contents

average vesting period of 2.6 years. Approximately 3.0 million shares remained available for grant under the 2009 Plan as ~~a performance-based award.~~of June 30, 2021, assuming PSUs (as defined below) are settled at 100% of target.

~~Restricted Stock~~

During the six months ended June 30, 2020, the Company granted 152,248 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, 2020, was $2.42 per share, with a total fair value of approximately $0.4 million and no adjustment for an estimated weighted average forfeiture rate. There were 2,539 forfeitures of restricted stock during the six 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,

16

~~Table of Contents~~

~~with a total fair value of approximately $2.3 million and no adjustment for an estimated weighted average forfeiture rate.~~ The Company recognized approximately $0.4 million in restricted stock compensation expense during the six months ended June 30, 2020, related to restricted stock previously granted to its officers, employees and directors.

Per the agreement for the Pending Independence Merger, all unvested restricted stock awards held by Contango employees, executives and directors will vest on the closing date of the Pending Independence Merger. As of June 30, ~~2020, an additional $0.8 million~~2021, the number of ~~compensation expense related to~~shares of unvested restricted stock remained to be recognized over the remaining weighted-average vesting period of 1.3 years. Approximately 10.1 million shares remained available for grant under the Amended and Restated 2009 Incentive Compensation Plan as of June 30, 2020, assuming PSUs (as defined below) are settled at 100% of target.outstanding was 2,050,357 shares.

During the six months ended June 30, 2019, the Company granted 307,650 shares of restricted common stock, which vest ratably over three years, to employees and executive officers as part of their overall compensation package. Additionally, during the six 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. The Company recognized approximately $1.4 million in restricted stock compensation expense during the six months ended June 30, 2019 related to restricted stock granted to its officers, employees and directors.

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 months ended June 30, 2020. In July 2020,~~The Company granted ~~2,608,640~~1,772,066 PSUs under the 2009 Plan to its executive officers and certain employees as part of their overall compensation ~~package.~~package during the six months ended June 30, 2021. The performance period will be measured between ~~January~~May 1, ~~2020~~2021 and ~~December 31, 2022.~~April 30, 2024. These ~~granted PSUs~~PSU awards were valued at a weighted average fair value of ~~$4.90~~$8.25 per unit. ~~In January 2020, 77,485 shares~~There were 16,334 forfeitures of PSUs during the six months ended June 30, 2021. The Company recognized approximately $3.3 million in stock compensation expense related to previously granted PSUs ~~granted in 2017 vested,~~during the six months ended June 30, 2021. As of ~~which 22,972~~June 30, 2021, an additional $22.9 million of future compensation expense related to PSUs remained to be recognized over the weighted-average vesting period of 2.4 years.

There were ~~withheld for taxes, and are included with the restricted stock activity in the consolidated statement~~0 grants or forfeitures of ~~shareholders’ equity. No~~ PSUs ~~were forfeited~~ during the six months ended June 30, 2020. The Company recognized approximately $0.2 million in stock compensation expense related to PSUs during the six months ended June 30, 2020.

Per the agreement for the Pending Independence Merger, all unvested PSUs held by Contango employees and executives will vest on the closing date of the Pending Independence Merger, at the maximum payout percentage (for then current employees assuming sufficient shares then available under the 2009 Plan to settle such awards). As of June 30, ~~2020, an additional $0.5 million~~2021, the number of ~~compensation expense related to~~unvested PSU grants was 4,718,977, assuming settlement at 100%. The maximum payout of these PSUs ~~remained to be recognized over the remaining weighted-average vesting period~~is 300%, or 14,156,931 shares of ~~1.4 years.~~common stock.

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.

17

~~Table of Contents~~

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 months ended June 30, ~~2020~~2021 and ~~2019,~~2020, there was no0 excess tax benefit recognized.

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Table of Contents

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. NoNaN stock options were granted or exercised during the six months ended June 30, ~~2020~~2021 or ~~2019.~~2020.

During the six months ended June 30, ~~2020, no~~2021, 0 stock options ~~were exercised and stock options for 411 shares~~ were forfeited by former ~~employees.~~employees, and 19,268 stock options expired. During the six months ended June 30, ~~2019, no~~2020, 0 stock options ~~were exercised and stock options for 12,052 shares~~ were forfeited by former ~~employees.~~employees, and 411 stock options expired. As of June 30, 2021, there were 579 stock options vested and exercisable. The exercise price for such options ranges from $35.00 to $38.98 per share, with an average remaining contractual life of 0.8 years. All outstanding stock options were granted under the Company’s 2005 Stock Incentive Plan.

Per the agreement for the Pending Independence Merger, all stock options held by Contango employees and executives will vest and be deemed exercised on the closing date of the Pending Independence Merger; however, stock options with an exercise price per share that equals or exceeds the fair market value of a share of common stock will be cancelled for no consideration on the closing date of the Pending Independence Merger.

77.. Leases

During the six months ended June 30, ~~2020,~~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,~~2021, the Company’s operating leases ~~were for~~included compressors and office space, ~~at its two corporate offices~~ and ~~three field offices, while~~ the Company’s finance leases ~~were for~~included vehicles, compressors and office equipment.

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~~2021 and December 31, ~~2019~~2020 (in thousands):


	June 30, 2021		December 31, 2020
Operating lease right of use asset ⁽¹⁾	$	3,206	$	2,452

Operating lease liability - current⁽²⁾	$	(2,255)	$	(1,832)
Operating lease liability - long-term⁽³⁾		(911)		(522)
Total operating lease liability	$	(3,166)	$	(2,354)

Financing lease right of use asset⁽¹⁾	$	4,179	$	2,996

Financing lease liability - current⁽²⁾	$	(1,364)	$	(940)
Financing lease liability - long-term⁽³⁾		(2,894)		(2,102)
Total financing lease liability	$	(4,258)	$	(3,042)

June 30, 2020

December 31, 2019

Operating lease right of use asset ⁽¹⁾
$
3,993

$
4,316

Operating lease liability - current⁽²⁾
$
(2,897)

$
(2,597)

Operating lease liability - long-term⁽³⁾

(1,045)

(1,738)

Total operating lease liability
$
(3,942)

$
(4,335)

Financing lease right of use asset⁽¹⁾
$
1,698

$
1,569

Financing lease liability - current⁽²⁾
$
(605)

$
(524)

Financing lease liability - long-term⁽³⁾

(1,111)

(1,051)

Total financing lease liability
$
(1,716)

$
(1,575)

(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~~2021 and December 31, ~~2019:~~2020:


	June 30, 2020	December 31, 2019	June 30, 2021	December 31, 2020
Weighted Average Remaining Lease Terms (in years):
Operating leases	1.81	2.16	1.57	1.47
Financing leases	3.14	3.14	3.13	3.24

Weighted Average Discount Rate:
Operating leases	5.75%	6.04%	6.02%	5.72%
Financing leases	5.90%	6.24%	5.85%	5.92%

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

June 30, 2020

Operating Leases

Financing Leases

2020 (remaining after June 30, 2020)
$
3,040

$
690

2021

702

552

2022

168

475

2023

171

156

2024

72

7

Total future minimum lease payments

4,153

1,880

Less: imputed interest

(211)

(164)

Present value of lease liabilities
$
3,942

$
1,716


	June 30, 2021
	Operating Leases		Financing Leases
2021 (remaining after June 30, 2021)	$	2,377	$	1,576
2022		710		1,465
2023		173		1,112
2024		69		522
2025		—		2
Total future minimum lease payments		3,329		4,677
Less: imputed interest		(163)		(419)
Present value of lease liabilities	$	3,166	$	4,258

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


	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020
Operating lease cost ^{(1) (2)}	$	1,043	$	743
Financing lease cost - amortization of right-of-use assets		331		155
Financing lease cost - interest on lease liabilities		61		27
Administrative lease cost⁽³⁾		17		19
Short-term lease cost ^{(1) (4)}		367		615
Total lease cost	$	1,819	$	1,559

Three Months Ended June 30, 2020

Three Months Ended June 30, 2019

Operating lease cost ^{(1) (2)}
$
743

$
100

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

155

-

Financing lease cost - interest on lease liabilities

27

-

Administrative lease cost⁽³⁾

19

18

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

615

2,068

Total lease cost
$
1,559

$
2,186

(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~~2021 and ~~2019~~2020 (in thousands):


	Six Months Ended June 30, 2020		Six Months Ended June 30, 2019		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Operating lease cost ^{(1) (2)}	$	1,430	$	471	$	1,900	$	1,430
Financing lease cost - amortization of right-of-use assets		284		-		603		284
Financing lease cost - interest on lease liabilities		52		-		114		52
Administrative lease cost⁽³⁾		38		37		36		38
Short-term lease cost ^{(1) (4)}		1,053		2,578		791		1,053
Total lease cost	$	2,857	$	3,086	$	3,444	$	2,857

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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 months ended June 30, 2021, there were $2.0 million and $0.7 million in cash payments related to the Company’s operating leases and financing leases, respectively. During the six months ended June 30, 2020, there were $1.5 million and $0.3 million in cash payments related to the Company’s operating leases and financing leases, respectively. During the six months ended June 30, 2019, there were $0.1 million in cash payments related to operating leases. No cash payments were made for the financing leases during the six months ended June 30, 2019.

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, 2021		December 31, 2020
Accounts receivable:
Trade receivables ⁽¹⁾	$	47,580	$	20,306
Receivable for Alta Resources distribution		1,712		1,712
Joint interest billings		18,915		15,637
Income taxes receivable		—		268
Other receivables		—		2,209
Allowance for doubtful accounts		(2,270)		(2,270)
Total accounts receivable	$	65,937	$	37,862

Prepaid expenses:
Prepaid insurance	$	5,475	$	2,825
Other ⁽²⁾		667		535
Total prepaid expenses	$	6,142	$	3,360

Accounts payable and accrued liabilities:
Royalties and revenue payable⁽¹⁾	$	38,755	$	23,701
Legal suspense related to revenues⁽¹⁾⁽³⁾		30,718		27,983
Advances from partners⁽⁴⁾		5,160		76
Accrued exploration and development⁽⁴⁾		6,157		490
Trade payables⁽¹⁾		30,910		14,273
Accrued general and administrative expenses		5,407		6,191
Accrued operating expenses		6,777		5,755
Accrued operating and finance leases		3,618		2,772
Other accounts payable and accrued liabilities		5,025		2,729
Total accounts payable and accrued liabilities	$	132,527	$	83,970

June 30, 2020

December 31, 2019

Accounts receivable:

Trade receivables ⁽¹⁾

$
9,527

$
21,110

Receivable for Alta Resources distribution

1,712

1,712

Joint interest billings

12,220

13,104

Income taxes receivable

268

509

Other receivables

2,939

4,126

Allowance for doubtful accounts

(994)

(994)

Total accounts receivable

$
25,672

$
39,567

Prepaid expenses:

Prepaid insurance

$
335

$
683

Other ⁽²⁾

1,028

508

Total prepaid expenses

$
1,363

$
1,191

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

Accrued operating and finance leases

3,502

3,120

Other accounts payable and accrued liabilities

1,548

4,969

Total accounts payable and accrued liabilities

$
77,143

$
104,593

(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.~~payees or some other payment dispute.

(4)

~~Decrease in 2020 due~~Increase primarily related to ~~a decrease in~~the Company’s resumed drilling ~~and completion activity. In January 2020, the Company brought one West Texas well online but suspended further drilling~~program in the ~~area,~~second quarter of 2021 and the NE Bullseye wells in ~~its other onshore areas, in response to~~ the ~~dramatic decline in oil prices during the year.~~Permian region.

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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.~~

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


		Six Months Ended June 30,
		2021		2020
Cash payments:
Interest payments	$	1,733	$	2,006
Income tax payments	$	1,332	$	83
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$	5,667	$	(7,095)

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 25,552,933 shares of Contango common stock at the closing of the Mid-Con Acquisition. See Note 3 – “Acquisitions and Dispositions” 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~~2021 was approximately ~~$6.9~~$6.0 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.

The Company’s share in Exaro’s results of operations recognized for the three and six months ended June 30, ~~2020 and 2019~~2021 was a loss of ~~$0.2~~$0.8 million, net of no0 tax ~~expense and a gain of $0.4 million, net of no tax expense, respectively.~~expense. The Company’s share in Exaro’s results of operations recognized for the three and six months ended June 30, 2020 was a loss of $0.2 million, net of 0 tax expense, and ~~2019 was~~ a gain of $0.1 million, net of ~~no tax expense, and a gain of $0.7 million, net of no~~0 tax expense, respectively.

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 and Dispositions” for more information. The ~~Second~~Third Amendment ~~redetermined~~provided for, among other things, (i) a 25 basis point increase in the applicable margin at each level of the borrowing base ~~at $95~~utilization-based pricing grid, (ii) an increase of the borrowing base from $75.0 million ~~pursuant~~to $130.0 million on the effective date of the Third Amendment, with a $10.0 million automatic stepdown in the borrowing base on March 31, 2021, (iii) certain modifications to the ~~regularly scheduled redetermination process.~~ 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 three new banks to the lender group. The ~~Second~~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. On May 3, 2021, the Company entered into the Fifth Amendment to the Credit Agreement, which increased the borrowing base from $120.0 million to $250.0 million and expanded the bank group from nine to eleven banks, effective May 3, 3021. The Fifth Amendment also provides for, among other things, ~~further $10 million automatic reductions in~~(i) the ~~borrowing base on each~~reinstatement of ~~June 30, 2020 and September 30, 2020.~~ ~~As a result,~~ the ~~borrowing base was $85 million~~minimum current ratio covenant calculation of 1.0:1.0 beginning as of June 30, ~~2020. The borrowing base may also be adjusted by certain events, including~~2021, (ii) a decrease in the ~~incurrence~~maximum Total Debt/EBITDAX leverage ratio calculation from 3.5:1.0 to 3.25:1.0, and (iii) a decrease in the Company’s minimum hedging covenant resulting in requiring hedging for at least 70% of ~~any senior unsecured debt, material asset dispositions or liquidation~~the Company’s projected PDP volumes for 12 full calendar months from the date of ~~hedges~~delivery of each reserve report and at least 50% of the Company’s projected PDP volumes for months 13 through 24 from the date of delivery of each reserve report and other minor changes which are more administrative in ~~excess~~nature.

As of ~~certain thresholds. The~~June 30, 2021, under the Credit Agreement, ~~matures on September 17, 2024.~~the Company had $69.0 million borrowings outstanding, $2.9 million in outstanding letters of credit and borrowing availability of approximately $178.1 million. As of December 31,

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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. NoNaN 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. The Company incurred $1.6 million in fees related to the Fifth Amendment, which became effective on May 3, 2021, and will be amortized over the remaining term of the Credit Agreement. During the six months ended June 30, 2021, the Company amortized debt issuance costs of $0.4 million related to the Credit Agreement. As of June 30, 2021, the remaining amortizable balance of these fees was $3.9 million and will be amortized through September 17, 2024.

Total interest expense under the Company’s Credit Agreement, including commitment fees, was approximately $1.4 million and $2.6 million for the three and six months ended June 30, 2021, respectively. Total interest expense under the Company’s Credit Agreement, including commitment fees, was approximately $2.2 million and $3.4 million, for the three and six months ended June 30, 2020, respectively. Included in the ~~Company expensed~~2020 interest expense is $1.0 million ~~of the fees discussed above,~~in debt issuance costs which originally were to be amortized over the life of the loan, but were immediately expensed due to ~~the~~a reduction in the borrowing base ~~per~~under the Second Amendment. ~~As of June 30, 2020, the remaining amortizable balance of these fees was $1.9 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, including commitment fees and the additional $1.0 million in expensed loan fees discussed above, for the three and six months ended June 30, 2020

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was approximately $2.2 million 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.

The weighted average interest rates in effect at June 30, ~~2020~~2021 and December 31, ~~2019~~2020 were ~~4.0%~~3.5% 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~~Fifth Amendment 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, both as defined in the Credit Agreement. The Second Amendment includes a waiver of the Current Ratio requirement until the quarter ending March 31, 2022. 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.3.25:1.0. The Credit Agreement also contains typical 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,~~2021, the Company was in compliance with all of its covenants under the Credit Agreement.

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 Debt”~~“Long-term debt” on the Company’s consolidated balance sheet.

The PPP Loan ~~matures~~was set to mature 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~~commenced after the six-month anniversary of the funding date. The promissory note evidencing the PPP Loan ~~provides~~provided 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 July 12, 2021, submitted its updated

26

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application for forgiveness of ~~all or part of~~the total amount outstanding under the PPP Loan in accordance with the updated application terms of the CARES Act and related guidance. In

On August 6, 2021, the ~~event~~Company received notice from the Small Business Administration that the PPP ~~Loan or any portion thereof is~~loan was forgiven ~~the amount forgiven is applied to the outstanding principal.~~in its entirety.

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11. Income Taxes

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


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019		2021		2020		2021		2020
Current tax provision:
Current tax provision (benefit)
Federal	$	—	$	—	$	275	$	—	$	(254)	$	—	$	(254)	$	275
State		(7)		427		112		454		70		(7)		609		112
Total	$	(7)	$	427	$	387	$	454	$	(184)	$	(7)	$	355	$	387
Deferred tax provision:
Federal	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
State		376		—		376		—		—		376		—		376
Total	$	376	$	—	$	376	$	—	$	—	$	376	$	—	$	376
Total tax provision:
Total tax provision (benefit)
Federal	$	—	$	—	$	275	$	—	$	(254)	$	—	$	(254)	$	275
State		369		427		488		454		70		369		609		488
Total income tax provision:	$	369	$	427	$	763	$	454
Total income tax provision (benefit):									$	(184)	$	369	$	355	$	763

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 primarily 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 Federal income tax benefit for the ~~CARES Act,~~current period results from applying the ~~Company will benefit from an amendment~~estimated annual effective tax rate 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~~year-to-date pre-tax loss, less amounts recorded 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~~of 2021, plus a small true-up of a previously recorded alternative minimum 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.refund was reflected.

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,~~2021, the Company had federal net operating loss (“NOL”) carryforwards of approximately ~~$398.7~~$402.7 million and state NOLs of ~~$32.7~~$26.4 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 ~~quarter~~Ownership Changes, the Company has recorded a valuation allowance against substantially all of its NOLs and other deferred tax assets. The Company determined that no Section 382 Ownership Change from share activity occurred in the six months ended June 30, 2021. The valuation allowance balances at June 30, 2021 for federal and state purposes are approximately $146.8 million and approximately $4.4 million, respectively.

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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 contains numerous tax incentives and extensions for businesses. One such provision is a change in the deductibility of expenses for meals purchased from a restaurant, where, in calendar years 2021 and 2022, there is no reduction in deductibility (compared to a prior 50% limitation). For the six months ended June 30, 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 suspension of the Section 172 limitation because the Company incurred tax losses in each of the carryback years.

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.

~~Throughput Contract Commitment~~13. Subsequent Events

~~The~~On July 7, 2021, the Company ~~signed~~entered into a ~~throughput~~purchase and sale agreement with ConocoPhillips to acquire low decline, conventional gas assets in the Wind River Basin of Wyoming. Upon closing, Contango will acquire approximately 446 Bcfe of PDP reserves (unaudited) for a ~~third-party pipeline owner/operator that constructed a natural gas gathering pipeline~~total purchase price of $67.0 million in ~~Southeast Texas that allows~~cash, subject to customary purchase price adjustments. Closing of the Pending Wind River Basin Acquisition is expected to occur in the third quarter of 2021, subject to the satisfaction of certain closing conditions set forth in the purchase and sale agreement.

On August 6, 2021, the Company ~~to defray~~received notice from the ~~cost of building~~Small Business Administration that the ~~pipeline itself. Beginning~~Company’s PPP loan for approximately $3.4 million was forgiven in ~~late 2016,~~its entirety. The PPP Loan to the Company ~~was unable to meet~~is included in “Long-term debt” on the ~~minimum monthly gas volume deliveries through this line in Southeast Texas and continued to not meet the minimum throughput requirements under the agreement through the expiration~~Company’s consolidated balance sheet as of the throughput commitment in March 2020. As of December 31, 2019, the Company recorded a $1.0 million loss contingency through the expiration of the contract on March 31, 2020, which is to be paid in three equal monthly installments beginning in August of 2020.June 30, 2021.

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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, our Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, 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~~risks related to ~~execute our new corporate strategy of offering a “fee for service” property~~the recently announced Pending Independence Merger, including the risk that the Pending Independence Merger will not be completed on the timeline or terms currently contemplated, the businesses will not be integrated successfully, that the anticipated cost savings, synergies and growth from the Pending Independence Merger may not be fully realized or may take longer to realize than expected, and that management ~~service for oil and gas companies;~~attention will be diverted;

●

~~our financial position;~~potential liability resulting from any future litigation related to the Pending Independence Merger and the Pending Wind River Basin Acquisition;

●

risks related to the ~~impact of our derivative instruments;~~recently announced Pending Wind River Basin Acquisition, including the risk that the Pending Wind River Basin Acquisition will not be completed on the timeline or terms currently contemplated, the businesses and assets will not be integrated successfully, that the anticipated cost savings, synergies and growth from the acquisition may not be fully realized or may take longer to realize than expected, and that management attention will be diverted;

●

~~our business strategy,~~the impact of the climate change initiative by President Biden’s administration and Congress, including ~~execution~~but not limited to: the January 2021 executive order imposing a moratorium on new oil and natural gas leasing on federal lands and offshore waters pending completion of ~~any changes in our strategy;~~a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices, the Biden administration’s announcement that the United States will aim to cut its greenhouse gas emissions from 2005 levels by 50% by 2030; and the Biden administration efforts to put the United State on a path to 100 percent carbon-free electricity by 2035;

●

our financial position;

●

the potential impact of our derivative instruments;

●

our business strategy, including our ability to successfully execute on our consolidation strategy or make any desired changes in our 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;

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●

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;

●

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.

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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. 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~~utilize 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 June 30, 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, Offshore Gulf of Mexico properties in water depths off of Louisiana in less than 300 feet and others

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 failure by the OPEC and Russia to reach an agreement on lower production quotas until April 2020, resulted in oil prices declining significantly beginning in late February 2020. While there has been an improvement in commodity prices since early 2020, prices remain volatile, and there is still significant uncertainty regarding the long-term impact of the COVID-19 pandemic on global oil demand and prices. Moreover, the OPEC and Russia recently reached an agreement in July 2021 to increase production over the next several months beginning in August 2021, which may further increase volatility Due to the extreme volatility in oil prices and the impact of the COVID-19 pandemic on the financial condition of our upstream peers, we suspended our onshore drilling program in the Southern Delaware Basin in the first quarter of 2020. We further suspended all drilling in the second quarter of 2020, before resuming drilling in the second quarter of 2021. During this time, we have focused on certain measures that include, but have not been limited to, the following:

●

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

●

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;

●

the identification of more cost-efficient drilling and completion strategies by our technical teams and the possible commencement of a conservative drilling/completion program on undeveloped opportunities in our portfolio should oil prices, and market stability, continue to improve and provide appropriate risk-weighted returns; and

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●

the extensive review of assets acquired in recent transactions for cost reduction opportunities, as well as opportunities to return to production wells that had previously been shut-in by the previous owners due to limited capital resources.

Corporate Overview

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 drilling in this area in response to the dramatic decline in oil prices and further suspended all drilling in the second quarter of 2020. Due to strengthening oil prices in 2021, and our identification of more cost-efficient methods of drilling and completing our Permian Basin wells, in the second quarter of 2021, we resumed our onshore drilling program in the Southern Delaware Basin. In May 2021, we began drilling the first of three single-pad wells originally planned in the Permian region. Based on recent success by offset operators to our position, we decided to drill one of the three wells in this first pad to the Second Bone Spring formation, which will be our first well being drilled to that formation. We expect to bring these wells online in the third quarter of 2021. Due to the success and efficiency in the drilling of these first three wells and the improved oil price market, we commenced spudding a second three-well pad in July 2021 as part of our 2021 Permian drilling program. As of June 30, ~~2020,~~2021, we were producing from eighteen wells over our approximate 16,200 gross operated (7,500 company net) acre position in ~~West Texas,~~our Permian region, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

~~During the fourth quarter of 2019,~~On January 21, 2021, we closed on the ~~acquisitions~~acquisition 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”), 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 25,552,933 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 ~~provide operational services as operator~~$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 Dispositions” and Item 1. Note 10 – “Long-Term Debt” for further details.

On February 1, 2021, we closed on the acquisition of ~~record on Mid-Con’s~~certain oil and natural gas properties located in ~~exchange~~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 ~~an annual services fee~~aggregate consideration of ~~$4 million, additional fees upon termination~~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 ~~warrants~~the closing date, the net consideration paid was approximately $53.2 million. See Item 1. Note 3 – “Acquisitions and Dispositions” for more information.

On April 28, 2021, the Board of Directors of the Company (the “Board”) increased the size of the Board from five to ~~align~~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 appointed to the Compensation Committee and Nominating Committee of the Board, and Ms. Simon was appointed to the Audit Committee and Nominating Committee of the Board. The Board determined that Ms. Pasque and Ms. Simon are both ~~parties~~independent directors under the applicable rules and ~~create value for shareholders. See~~regulations of the SEC and within the meaning of the NYSE American listing standards.

On April 28, 2021, we adopted the Contango Oil & Gas Company Change in Control Severance Plan and the Contango Oil & Gas Company Executive Severance Plan. For a description of these plans, see Item 1. Note 1 – “Organization and ~~Business”~~Business.”

On May 3, 2021, we entered into the Fifth Amendment to the Credit Agreement (the “Fifth Amendment”), which provided for, ~~additional information.~~

~~The following table lists our primary producing areas~~among other things, an increase in the Company’s borrowing base from $120.0 million to $250.0 million, effective May 3, 2021, expanded the bank group from nine to eleven banks and reinstated the Current Ratio and Leverage Ratio requirements beginning 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~~202. The Fifth Amendment also includes less restrictive hedge requirements 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 ledcertain modifications 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 limited to, the following:~~

●

~~work from home initiatives for 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”)covenants. 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~~further information onregarding the ~~terms~~Fifth Amendment.

On June 7, 2021, we entered into a definitive agreement to combine with Independence Energy, LLC (“Independence”) in an all-stock transaction (the “Pending Independence Merger”). Independence is a diversified, well-capitalized upstream oil and gas business built and managed by KKR’s Energy Real Assets team with a scaled portfolio

32

Table of Contents

of low-decline, producing assets with meaningful reinvestment opportunities for low-risk growth across the Eagle Ford, Rockies, Permian and Mid-Continent regions. The closing of the ~~PPP Loan. We also benefited from~~Pending Independence Merger is conditioned upon approval by a majority of Contango’s shareholders, among certain ~~income tax-related provisions~~other closing conditions. Upon completion of the ~~CARES Act.~~Pending Independence Merger, Independence shareholders are expected to own approximately 76% and Contango shareholders are expected to own approximately 24% of the combined company. If approved, the Pending Independence Merger is expected to close in the fourth quarter of 2021. See Item 1. Note 113 – ~~“Income Taxes”~~“Acquisitions and Dispositions” for ~~additional~~more information.

~~We continue~~On July 7, 2021, we entered into a purchase and sale agreement with ConocoPhillips to ~~assess~~acquire low decline, conventional gas assets in the ~~global impacts~~Wind River Basin of Wyoming (the “Pending Wind River Basin Acquisition”). Closing of the ~~COVID-19 pandemic~~Pending Wind River Basin Acquisition is expected to occur in the third quarter of 2021, for a total purchase price of $67.0 million in cash, subject to the satisfaction of certain closing conditions set forth in the purchase and ~~expect to continue to modify~~sale agreement. See Item 1. Note 13 – “Subsequent Events” for further details.

On August 6, 2021, we received notice from the Small Business Administration that our ~~plans as more clarity around~~loan received from the ~~full economic impact of COVID-19 becomes available. See Part II, Item 1A. “Risk Factors”~~Paycheck Protection Program in ~~our Quarterly Report on Form 10-Q for the period ended March 31,~~ 2020 for approximately $3.4 million was forgiven in its entirety. See Item 1. Note 13 – “Subsequent Events” for further ~~discussion.~~information.

Capital Expenditures

~~Beginning~~We currently forecast our 2021 capital expenditure budget to be a total of approximately $30.0 - $34.0 million for recompletions, facility upgrades, waterflood development and select drilling in the ~~second quarter of 2020, in response~~West Texas Permian (expected 3 net locations, 6 gross locations), among other things. This forecast does not account for the Pending Independence Merger or the Pending Wind River Basin Acquisition. The planned capital expenditures also include development opportunities with respect to ~~the decrease in commodity prices,~~certain properties we ~~have suspended any further plans for onshore drilling in 2020.~~ ~~The offshore Iron Flea prospect in the shallow waters off~~acquired as part of the ~~Louisiana~~ ~~coast in~~ ~~Grand Isle~~ ~~was spud in late May 2020. On June 12, 2020, the target drilling depth was reached,~~Mid-Con Acquisition and the ~~prospect was determined unsuccessful. As a result, we recorded $10.9 million in dry hole exploration expenses during~~Silvertip Acquisition. The capital expenditure program will continue to be evaluated for revision throughout the ~~three~~year.

During the six months ended June 30, ~~2020.~~2021, we incurred capital expenditures of approximately $13.8 million, of which $5.2 million related to the drilling of the Southern Delaware Basin wells. We also incurred approximately $6.4 million in expenditures primarily related to redevelopment activities of recently acquired properties in our Midcontinent, Permian and Rockies regions and $1.9 million in unproved offshore prospect costs, of which $1.1 million was paid for with the proceeds of an issuance of Company common stock, pursuant to a joint development agreement between the Company and Juneau Oil & Gas, LLC. We believe that our current financial resources will be more than adequate to fund our 2021 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.

~~For 2020, we plan~~We intend to continue to ~~identify~~make balance sheet strength a priority in 2021, while continuing to pursue our strategy of asset consolidation by evaluating acquisition opportunities ~~for cost reductions~~that may arise in this challenging commodity price environment. 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 ~~operating efficiencies in all areas~~newly acquired assets, reducing general and administrative expenses, improving cash margins and lowering our exposure to asset retirement obligations through the possible sale of our operations, while also searching for new resource acquisition opportunities. Acquisition efforts, if any, will be focused on areas in which we can leverage our geological and operational experience and expertise to exploit identified drilling opportunities and where we can develop an inventory of additional drilling prospects that we believe will enable us to economically grow production and add reserves.non-core properties.

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 related to proved properties during the six months ended June 30, 2021. We recorded a $0.2 million non-cash charge for unproved impairment expense during the six months ended June 30, 2021 related to expiring leases in our Permian region.

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,

33

Table of Contents

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~~six months ended ~~March 31,~~June 30, 2020, we

29

~~Table of Contents~~

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 impact of the lower prices 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 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 related to acquired 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~~2020, related to ~~impairment of certain unproved properties, primarily due to~~ expiring ~~leases.~~leases in our Midcontinent region.

Summary Production Information

Our production sales for the three months ended June 30, ~~2020~~2021, were ~~approximately 83% onshore and 17% offshore, volumetrically, and was~~ comprised of ~~56%~~41% oil, 38% natural gas, ~~24% oil~~ and ~~20%~~21% natural gas ~~liquids. During the second quarter of 2020, due~~liquids, in comparison 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. Ourour production sales for the three months ended June 30, ~~2019~~2020, of approximately 24% oil, 56% natural gas and 20% natural gas liquids. Our production sales for the six months ended June 30, 2021, were ~~41% onshore and 59% offshore, volumetrically, and was~~ comprised of ~~approximately 55%~~39% oil, 42% natural gas, ~~26% oil~~ and 19% natural gas liquids, in comparison to our production sales for the six months ended June 30, 2020, of approximately 27% oil, 53% natural gas and 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
	June 30,	September 30,	December 31,	March 31,	June 30,
	2020	2020	2020	2021 ⁽⁴⁾	2021 ⁽⁴⁾
Midcontinent⁽¹⁾	11.6	12.6	9.6	11.1	12.2
Permian⁽²⁾	0.9	0.7	1.4	2.6	4.8
Rockies	—	0.1	—	2.6	4.4
Other ⁽³⁾	3.6	3.8	3.4	3.4	2.7
Total daily production sales volumes	16.1	17.2	14.4	19.7	24.1

Three Months Ended


June 30, 2019

September 30, 2019

December 31, 2019

March 31, 2020

June 30, 2020

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

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

~~(2)~~

~~Decrease in production~~Production sales during the three months ended ~~June~~September 30, 2020 ~~due to allocating~~included approximately 50,000 Bbls (0.5 MBoe/d) of second quarter 2020 oil production (net to the Company) to, which was held as inventory ~~storage (0.5 Mboe/d).~~

~~(3)~~

~~Increase~~and later sold in the third quarter of 2020 at higher prices. The decrease in production sales during the three months ended December 31, ~~2019~~2020 was primarily due to downtime related to workovers and routine repair and maintenance. The increase in production sales during the three months ended March 31, 2021 and June 30, 2021 was due to ~~new~~the properties acquired as part of the Mid-Con Acquisition.

(2)

The decrease in production sales beginning in the second quarter of 2020 was 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. The increase in production sales during the three months ended March 31, 2021 and June 30, 2021 was due to the properties acquired as part of the Silvertip Acquisition.

(3)	Includes our offshore Gulf of Mexico wells ~~coming online.~~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)

The increase in production sales during the three months ended March 31, 2021 and June 30, 2021 was due to the Mid-Con Acquisition and the Silvertip Acquisition. The Mid-Con Acquisition reflects production sales beginning January 21, 2021, impacting the 2021 first quarter production for the Midcontinent and Rockies regions by 1.7 MBoe/d and 0.4 MBoe/d, respectively, and the 2021 second quarter production for the Midcontinent and Rockies regions by 2.5 MBoe/d and 0.6 MBoe/d, respectively, The Silvertip Acquisition reflects production sales beginning February 1, 2021, impacting the 2021 first quarter production for the Permian and Rockies regions by 1.9 MBoe/d and 2.1 MBoe/d, respectively, and the 2021 second quarter production for the Permian and Rockies regions by 3.9 MBoe/d and 3.7 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,~~2021, Exaro had ~~645~~650 producing wells ~~on production~~ over its 5,760 gross acres (1,040 net), with a working 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 and six months ended June 30, ~~2020. As a result~~2021. We recognized an investment loss of approximately $0.8 million, net of no tax expense, attributable to our equity ~~nvestment~~investment in Exaro wefor the three and six months ended June 30, 2021. We recognized an investment loss of approximately $0.2 million, net of no tax expense, and an 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~~attributable to our equity investment ~~gain of approximately $0.7 million, net of no tax expense,~~in Exaro for the three and six months ended June 30, 2020, ~~and 2019,~~ respectively. See Item 1. Note 9 – “Investment in Exaro Energy III LLC” for additional details related to this equity investment.

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Table of Contents

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

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"~~(“NGLs”) from operations for the three and six months ended June 30, ~~2020~~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 June 30,						Six Months Ended June 30,
	2021		2020		% Change		2021		2020		% Change

Revenues (thousands):
Oil and condensate sales	$	56,209	$	7,930	609	%	$	93,202	$	30,712	203	%
Natural gas sales		14,823		6,618	124	%		29,315		14,789	98	%
NGL sales		12,279		3,294	273	%		20,560		6,915	197	%
Other operating revenues		329		—	100	%		513		—	100	%
Total revenues	$	83,640	$	17,842	369	%	$	143,590	$	52,416	174	%

Production Sales Volumes:
Oil and condensate (thousand barrels)
Midcontinent		427		231	85	%		781		598	31	%
Permian		158		69	129	%		292		158	85	%
Rockies		274		4	*	%		399		10	*	%
Other		33		42	(21)	%		69		100	(31)	%
Total oil and condensate		892		346	158	%		1,541		866	78	%
Natural gas (million cubic feet)
Midcontinent		2,657		3,451	(23)	%		5,247		7,095	(26)	%
Permian		758		31	*	%		1,292		81	*	%
Rockies		552		—	100	%		1,108		—	100	%
Other		1,076		1,431	(25)	%		2,378		2,939	(19)	%
Total natural gas		5,043		4,913	3	%		10,025		10,115	(1)	%
Natural gas liquids (thousand barrels)
Midcontinent		244		247	(1)	%		458		524	(13)	%
Permian		149		6	*	%		163		15	987	%
Rockies		30		—	100	%		44		—	100	%
Other		41		52	(21)	%		92		98	(6)	%
Total natural gas liquids		464		305	52	%		757		637	19	%
Total (thousand barrels of oil equivalent)
Midcontinent		1,114		1,053	6	%		2,113		2,304	(8)	%
Permian		433		80	441	%		670		186	260	%
Rockies		396		4	*	%		628		10	*	%
Other		253		332	(24)	%		558		689	(19)	%
Total production sales volumes		2,196		1,469	49	%		3,969		3,189	24	%

Daily Production Sales Volumes:
Oil and condensate (thousand barrels per day)
Midcontinent		4.7		2.5	88	%		4.3		3.2	34	%
Permian		1.7		0.8	113	%		1.6		0.9	78	%
Rockies		3.0		—	100	%		2.2		0.1	*	%
Other		0.4		0.4	—	%		0.4		0.6	(33)	%
Total oil and condensate		9.8		3.7	165	%		8.5		4.8	77	%
Natural gas (million cubic feet per day)
Midcontinent		29.2		37.9	(23)	%		29.0		39.1	(26)	%
Permian		8.3		0.3	*	%		7.1		0.4	*	%
Rockies		6.1		—	100	%		6.1		—	100	%
Other		11.8		15.8	(25)	%		13.2		16.1	(18)	%
Total natural gas		55.4		54.0	3	%		55.4		55.6	(0)	%

3135

Table of Contents

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)
%


	Three Months Ended June 30,						Six Months Ended June 30,
	2021		2020		% Change		2021		2020		% Change

Natural gas liquids (thousand barrels per day)
Midcontinent		2.7		2.8	(4)	%		2.5		2.9	(14)	%
Permian		1.6		0.1	*	%		0.9		0.1	800	%
Rockies		0.3		—	100	%		0.2		—	100	%
Other		0.5		0.5	—	%		0.6		0.6	—	%
Total natural gas liquids		5.1		3.4	50	%		4.2		3.6	17	%
Total (thousand barrels of oil equivalent per day)
Midcontinent		12.2		11.6	5	%		11.7		12.7	(8)	%
Permian		4.8		0.9	433	%		3.7		1.0	270	%
Rockies		4.4		—	100	%		3.5		0.1	*	%
Other		2.7		3.6	(25)	%		3.0		3.8	(21)	%
Total daily production sales volumes		24.1		16.1	50	%		21.9		17.6	24	%

Average Sales Price:
Oil and condensate (per barrel)	$	63.03	$	22.94	175	%	$	60.47	$	35.46	71	%
Natural gas (per thousand cubic feet)	$	2.94	$	1.35	118	%	$	2.92	$	1.46	100	%
Natural gas liquids (per barrel)	$	26.46	$	10.81	145	%	$	27.17	$	10.85	150	%
Total (per barrels of oil equivalent)	$	37.93	$	12.14	212	%	$	36.05	$	16.43	119	%

Expenses (thousands):
Operating expenses	$	36,509	$	15,016	143	%	$	63,985	$	34,272	87	%
Exploration expenses	$	87	$	11,173	(99)	%	$	284	$	11,571	(98)	%
Depreciation, depletion and amortization	$	11,457	$	5,092	125	%	$	20,599	$	17,946	15	%
Impairment and abandonment of oil and natural gas properties	$	451	$	—	100	%	$	454	$	145,878	(100)	%
General and administrative expenses	$	13,483	$	7,836	72	%	$	24,842	$	15,487	60	%
Gain (loss) from investment in affiliates (net of taxes)	$	(804)	$	(173)	365	%	$	(804)	$	113	(812)	%

Selected data per Boe:
Operating expenses	$	16.62	$	10.23	62	%	$	16.12	$	10.75	50	%
General and administrative expenses	$	6.14	$	5.33	15	%	$	6.26	$	4.86	29	%
Depreciation, depletion and amortization	$	5.22	$	3.47	50	%	$	5.19	$	5.63	(8)	%

*Greater than 1,000%

Three Months Ended June 30, ~~2020~~2021 Compared to Three Months Ended June 30, ~~2019~~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 and, while there have been modest recoveries of commodity prices, downward pressure on, and volatility in, commodity prices continued during the second quarter of 2020. Our production volumes are subject to significant variation as a result of new operations, weather events,

32

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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

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.

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

~~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 meaningful commodity price improvement since 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~~$83.6 million for the ~~six~~three months ended June 30, ~~2020,~~2021, compared to revenues of ~~$26.8~~$17.8 million for the ~~six~~three months ended June 30, ~~2019, an~~2020. The current year increase is attributable ~~primarily~~to the increases in commodity prices in 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 $16.6 million in the second

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Table of Contents

quarter of 2021, and the revenues related to the properties acquired in the Silvertip Acquisition were approximately $26.9 million in the second quarter of 2021.

Total production sales for the three months ended June 30, 2021 were approximately 2.2 MMBoe (62% liquids), or 24.1 MBoe/d, compared to approximately 1.5 MMBoe (44% liquids), or 16.1 MBoe/d in the prior year quarter. The increase in 2021 production sales is attributable 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 oil production ~~was 17.6 Mboe/d~~sales were approximately 9,800 barrels per day for the ~~six~~three months ended June 30, ~~2020,~~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.quarter. Net natural gas production ~~for~~sales increased to approximately 55.4 MMcf per day during the ~~current year was approximately 55.6 Mmcf/d,~~three months ended June 30, 2021, compared with approximately ~~19.5 Mmcf/d~~54.0 MMcf per day during the three months ended June 30, 2020. Net NGL production sales were approximately 5,100 barrels per day during the three months ended June 30, 2021, compared to approximately 3,400 barrels per day 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~~2021 was ~~$16.43~~$37.93 per Boe compared to ~~$26.00~~$12.14 per Boe for the ~~six~~three months ended June 30, ~~2019.~~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 oil and natural gas. The increase in domestic vaccination programs have helped reduce the spread of COVID-19 in 2021, which has contributed to an improvement in the economy and higher realized commodity ~~products, which caused a global supply/demand imbalance for oil that resulted~~prices 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 quarter of 2020.~~2021. The

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~~Table of Contents~~

realized price of oil averaged ~~$35.46~~$63.03 per Bbl in the ~~current year,~~second quarter of 2021 compared to an average of ~~$54.78~~$22.94 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 natural gas averaged ~~$1.46~~$2.94 per Mcf in the ~~current year~~second quarter of 2021 compared to an average of ~~$2.70~~$1.35 per Mcf in the prior year quarter, and the realized price of NGLs averaged ~~$10.85~~$26.46 per Bbl in the ~~current year~~second quarter of 2021 compared to an average of ~~$18.05~~$10.81 per Bbl in the prior ~~year.~~year quarter. Also contributing to the improvement in the average sales price per barrel of oil equivalent, period over period, was the increase in the percentage of our total production that came from the higher value of crude oil and NGL production sales.

Other Operating Revenues

We reported $0.3 million of other operating revenues during the three months ended June 30, 2021 specifically related to the plant and pipeline acquired in the Mid-Con Acquisition. We did not report any other operating revenues during the prior year period.

Operating Expenses

~~Operating~~Total operating expenses for the ~~six~~three months ended June 30, ~~2020~~2021 were approximately ~~$38.6~~$36.5 million, or ~~$12.11~~$16.62 per Boe, compared to ~~$10.9~~$15.0 million, or ~~$10.57~~$10.23 per Boe, for the ~~six~~three months ended June 30, ~~2019.~~2020. The table below provides additional detail of total operating expenses for the ~~six~~three month periods:


	Six Months Ended June 30,						Three Months Ended June 30,
	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	$	18,435	$ 8.39	$	9,014	$ 6.14
Production & ad valorem taxes		2,574	0.81		1,043	1.01		6,351	2.89		828	0.56
Transportation & processing costs		10,131	3.18		1,197	1.16		8,372	3.81		4,579	3.12
Workover costs		1,729	0.55		1,332	1.30		2,894	1.32		595	0.41
Other operating expenses								457	0.21		—	—
Total operating expenses	$	38,621	12.11	$	10,886	$ 10.57	$	36,509	$ 16.62	$	15,016	$ 10.23

Lease operating expenses (“LOE”) were ~~$24.2~~$18.4 million and ~~$7.3~~$9.0 million for the ~~six~~three months ended June 30, ~~2020~~2021 and June 30, ~~2019, respectively, an increase primarily due~~2020, respectively. The LOE related to the ~~addition~~properties acquired in the Mid-Con Acquisition was approximately $6.2 million, or $22.26 per Boe, and the LOE related to the properties acquired in the Silvertip Acquisition was approximately $6.2 million, or $8.93 per Boe, in the second quarter of ~~our Will Energy~~2021, which is the primary reason for the increase in LOE expense and ~~White Star~~rate per Boe in the current year quarter compared to the prior year quarter.

Transportation and processing costs were approximately $8.4 million compared to $4.6 million for the three months ended June 30, 2021 and 2020, respectively. The properties acquired ~~properties.~~in the Silvertip Acquisition incurred transportation and processing costs of approximately $2.9 million, or $4.23 per Boe, in the second quarter of 2021, which

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Table of Contents

is the primary reason for the increase in transportation and processing costs and rate per Boe in the current year quarter compared to the prior year quarter.

Production and ad valorem taxes were ~~$2.6 million~~$6.4 and ~~$1.0~~$0.8 million for the ~~six~~three months ended June 30, ~~2020~~2021 and June 30, ~~2019, respectively, an increase primarily~~2020, respectively. The production and ad valorem taxes related to the ~~additional production~~acquired properties in ~~2020 from~~ the second quarter of 2021 were approximately $1.4 million, or $5.05 per Boe, for those acquired ~~Will Energy~~in the Mid-Con Acquisition and ~~White Star properties.~~

~~Transportation and processing costs were $10.1~~approximately $2.3 million, ~~and $1.2 million~~or $4.92 per Boe, for those acquired in the ~~six months ended June 30, 2020 and June 30, 2019, respectively, an increase primarily due~~Silvertip Acquisition, both of which contributed to the ~~addition of our Will Energy~~increase in expense and ~~White Star acquired properties and~~rate per Boe in the ~~related higher transportation costs in our Central Oklahoma region.~~

~~Exploration Expense~~

~~Exploration expense was $11.6 million for the six months ended June 30, 2020,~~current year quarter compared to the prior year ofquarter.

We reported $0.5 million ~~an increase primarily due~~of other operating expenses during the three months ended June 30, 2021 specifically related to the plant and pipeline acquired in the Mid-Con Acquisition. We did not report any other operating expenses during the prior year period.

Exploration Expense

Exploration expense was $0.1 million for the three months ended June 30, 2021, compared to $11.2 million in the prior year period, which included $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 of the Grand Isle area of the Gulf of Mexico.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense for the three months ended June 30, 2021 was approximately $11.5 million, or $5.22 per Boe. This compares to approximately $5.1 million, or $3.47 per Boe, for the three months ended June 30, 2020. The higher depletion expense and rate per Boe for the three months ended June 30, 2021 is attributable to the properties from the Mid-Con Acquisition and the Silvertip Acquisition. The second quarter 2021 expense related to the acquired properties was approximately $2.4 million, or $8.65 per Boe, for those acquired in the Mid-Con Acquisition and approximately $4.4 million, or $9.43 per Boe, for those acquired in the Silvertip Acquisition.

Impairment and Abandonment Expenses

During the ~~six~~three months ended June 30, ~~2020,~~2021, we recorded a $143.3 million non-cash charge for proved property impairment of our onshore properties due to 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 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 recorded a $2.6~~ million non-cash charge for unproved impairment expense related ~~primarily~~ to ~~acquired~~expiring leases in our ~~Central Oklahoma and Western Anadarko regions, which will be expiring in 2020, and which we have no current plans~~Permian region. We did not record any impairment expense related to ~~develop as a result of~~proved properties during the ~~current commodity price environment. During the six~~three 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.~~2021.

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~~Table of Contents~~

~~Depreciation, Depletion and Amortization~~

~~Depreciation, depletion and amortization expense for~~During the ~~six~~three months ended June 30, 2020, ~~was approximately $17.9 million, or $5.63 per Boe. This compares~~we did not record any impairment related 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.our properties.

General and Administrative Expenses

Total general and administrative expenses for the ~~six~~three months ended June 30, 2021 were approximately $13.5 million, compared to $7.8 million for the three months ended June 30, 2020, ~~were approximately $11.1 million, compared~~with the current quarter increase primarily attributable to ~~$9.5 million for~~ the ~~six months ended June 30, 2019.~~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:


	Three Months Ended June 30,
	2021		2020

	(in thousands)
Wages and employee benefits ⁽¹⁾	$	5,547	$	3,366
Non-cash stock-based compensation ⁽²⁾		3,110		266
Professional fees⁽³⁾		1,325		2,039
Professional fees - special ⁽⁴⁾		1,911		551
Recouped overhead ⁽⁵⁾		(2,231)		(638)
Other ⁽⁶⁾		3,821		2,252
Total general and administrative expenses	$	13,483	$	7,836

Six Months Ended June 30,

2020

2019

(in thousands)

Wages, bonuses and employee benefits ⁽¹⁾

$
5,934

$
2,571

Non-cash stock-based compensation ⁽²⁾

616

1,637

Professional fees⁽³⁾

3,655

2,128

Professional fees - special ⁽⁴⁾

1,334

1,736

Recouped overhead ⁽⁵⁾

(5,668)

(514)

Other ⁽⁶⁾

5,267

1,903

Total general and administrative expenses

$
11,138

$
9,461

(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 31, 2019.~~June 30, 2021 due to additional employees acquired by the Company in connection with the Mid-Con Acquisition.

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Table of Contents

(2)

~~Lower~~Higher stock-based compensation expense for the ~~six~~three months ended June 30, ~~2020,~~2021, due to restricted stock and PSU grants being awarded in the second quarter of 2021 as compared to the third quarter of 2020, as ~~compared to~~part of annual incentive bonus compensation, as well as an increase in the ~~first quarter~~number of ~~2019.~~PSUs granted in 2021 and 2020 and the 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 assets from the ~~White Star~~Mid-Con Acquisition. See Item 1. Note 3 – “Acquisitions and ~~Will Energy assets acquired during the three months ended December 31, 2019.~~Dispositions” for further details.

(5)

These credits relate to overhead ~~for~~we recoup from working interest partners on our operated 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.

Loss from Affiliates

For the three months ended June 30, 2021, we recorded a loss from affiliates of approximately $0.8 million, net of no tax expense, attributable to our equity investment in Exaro. For the three months ended June 30, 2020, we recorded a loss from affiliates of approximately $0.2 million, net of no tax expense, attributable to our equity investment in Exaro.

Gain from Sale of Assets

During the three months ended June 30, 2021, we sold certain non-core Powder River Basin producing properties in Wyoming, which we acquired in the first quarter of 2021 as part of the Silvertip Acquisition. We also sold certain non-core, legacy and recently acquired producing and non-producing properties located in our Midcontinent, Permian and Other regions. These properties were sold for a collective total of approximately $2.6 million in cash and the buyers’ assumption of approximately $4.6 million in plugging and abandonment liabilities resulting in a net gain of $0.1 million recorded during the three months ended June 30, 2021.

During the three months ended June 30, 2020, we sold non-core producing and non-producing properties located in our Midcontinent region. These properties were sold for approximately $0.5 million in cash and the buyers’ assumption of approximately $5.0 million in plugging and abandonment liabilities and revenue held in suspense. We recorded a gain of $4.4 million during the three months ended June 30, 2020, primarily as a result of the buyers’ assumption of the asset retirement obligations associated with the sold properties.

Loss on Derivatives

During the three months ended June 30, 2021, we recorded a loss on derivatives of $53.5 million. Of this amount, $47.1 million was a non-cash reduction in the mark-to-market value of our hedges as commodity prices improved during 2021, and $6.4 million were realized losses during the second quarter of 2021. 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 mark-to-market losses, and $11.4 million were realized gains.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

Oil, Natural Gas 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. While those factors generally kept downward pressure and instability on the 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 meaningful commodity price improvement in 2021. Our production 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 $143.6 million for the six months ended June 30, 2021 compared to revenues of $52.4 million for the six months ended June 30, 2020. The current year increase is attributable to the increases in commodity prices in 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.

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The revenues related to acquired properties in the Mid-Con Acquisition were approximately $27.1 million, and the revenues related to the properties acquired in the Silvertip Acquisition were approximately $41.1 million for the six months ended June 30, 2021.

Total production sales for the six months ended June 30, 2021 were approximately 4.0 MMBoe (58% liquids), or 21.9 MBoe/d, compared to approximately 3.2 MMBoe (47% liquids), or 17.6 MBoe/d in the prior year period. Net oil production sales were approximately 8,500 barrels per day for the six months ended June 30, 2021, compared to approximately 4,800 barrels per day in the prior year period, an increase attributable to the production from the properties acquired in the Mid-Con Acquisition and the Silvertip Acquisition. Net natural gas production sales were approximately 55.4 MMcf per day during the six months ended June 30, 2021, compared with approximately 55.6 MMcf per day during the six months ended June 30, 2020. The 2021 natural gas production sales were comparable to the prior year period, despite the additional production from the 2021 acquisitions, due to the harsh winter storms in February 2021 and the related downtime in the first quarter of 2021. Net NGL production sales increased to approximately 4,200 barrels per day during the six months ended June 30, 2021 compared to approximately 3,600 barrels per day in the prior year period, an increase attributable to the production from the properties acquired in the Mid-Con Acquisition and the Silvertip Acquisition.

Average Sales Prices

The average equivalent sales price realized for the six months ended June 30, 2021 was $36.05 per Boe compared to $16.43 per Boe for the six months ended June 30, 2020. The lower prior year equivalent price was a result of the decline in all realized commodity prices in early 2020, as a result of the initial spread of the COVID-19 pandemic and its negative impact on the global demand for oil and natural gas. The increase in domestic vaccination programs have helped reduce the spread of COVID-19 in 2021, which has contributed to an improvement in the economy and higher realized commodity prices in 2021. The realized price of oil averaged $60.47 per Bbl in the first half of 2021 compared to an average of $35.46 per Bbl in the prior year period. The realized price of natural gas averaged $2.92 per Mcf in the first half of 2021 compared to an average of $1.46 per Mcf in the prior year period, and the realized price of NGLs averaged $27.17 per Bbl in the first half of 2021 compared to an average of $10.85 per Bbl in the prior year period. Also contributing to the improvement in the average sales price per barrel of oil equivalent, period over period, was the increase in the percentage of our total production that came from the higher value of crude oil and NGL production sales.

Other Operating Revenues

We reported $0.5 million of other operating revenues during the six months ended June 30, 2021 specifically related to the plant and pipeline acquired in the Mid-Con Acquisition. We did not report any other operating revenues during the prior year period.

Operating Expenses

Total operating expenses for the six months ended June 30, 2021 were approximately $64.0 million, or $16.12 per Boe, compared to $34.3 million, or $10.75 per Boe, for the six months ended June 30, 2020. The table below provides additional detail of total operating expenses for the six month periods:


	Six Months Ended June 30,
	2021			2020
		(in thousands)	(per Boe)		(in thousands)	(per Boe)
Lease operating expenses	$	34,928	$ 8.80	$	19,838	$ 6.21
Production & ad valorem taxes		9,891	2.49		2,574	0.81
Transportation & processing costs		14,148	3.56		10,131	3.18
Workover costs		4,268	1.08		1,729	0.55
Other operating expenses		750	0.19		—	—
Total operating expenses	$	63,985	$ 16.12	$	34,272	$ 10.75

Lease operating expenses (“LOE”) were $34.9 million and $19.8 million for the six months ended June 30, 2021 and June 30, 2020, respectively. The LOE related to the properties acquired in the Mid-Con Acquisition was approximately $10.7 million, or $22.79 per Boe, and the LOE related to the properties acquired in the Silvertip Acquisition was approximately $10.0 million, or $9.49 per Boe in the first half of 2021, which is the primary reason for the increase in LOE expense and rate per Boe, in the current year period compared to the prior year period.

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Transportation and processing costs were approximately $14.1 million compared to $10.1 million for the six months ended June 30, 2021 and 2020, respectively. The properties acquired in the Silvertip Acquisition incurred transportation and processing costs of approximately $3.9 million, or $3.66 per Boe in the second quarter of 2021, which is the primary reason for the increase in transportation and processing costs and rate per Boe in the current year period compared to the prior year period.

Production and ad valorem taxes were $9.9 million and $2.6 million for the six months ended June 30, 2021 and June 30, 2020, respectively. The production and ad valorem taxes related to the acquired properties in the first half of 2021 were approximately $2.3 million, or $4.92 per Boe, for those acquired in the Mid-Con Acquisition and approximately $3.7 million, or $3.49 per Boe, for those acquired in the Silvertip Acquisition, both of which contributed to the increase in production and ad valorem tax expense and rate per Boe in the current year period compared to the prior year period.

We reported $0.8 million of other operating expenses during the six months ended June 30, 2021 specifically related to the plant and pipeline acquired in the Mid-Con Acquisition. We did not report any other operating expenses during the prior year period.

Exploration Expense

Exploration expense was $0.3 million for the six months ended June 30, 2021, compared to $11.6 million in the prior year period, which included $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 of the Grand Isle area of the Gulf of Mexico.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense for the six months ended June 30, 2021 was approximately $20.6 million, or $5.19 per Boe. This compares to approximately $17.9 million, or $5.63 per Boe, for the six months ended June 30, 2020. The higher depletion expense for the current year period was related to the acquired properties and included approximately $4.4 million, or $9.43 per Boe, for the properties acquired in the Mid-Con Acquisition and approximately $5.1 million, or $4.87 per Boe, for the properties acquired in the Silvertip Acquisition.

Impairment and Abandonment Expenses

During the six months ended June 30, 2021, we recorded a $0.2 million non-cash charge for unproved impairment expense related to expiring leases in our Permian region. We did not record any impairment expense related to proved properties during the six months ended June 30, 2021.

During the six months ended June 30, 2020, we recorded a $143.3 million non-cash charge for proved property impairment of our onshore properties as a result of the dramatic decline in commodity prices, the impact of the lower prices on the PV-10 of our proved reserves, and the associated change in our then forecasted development plans for proved, undeveloped locations. We also recorded a $2.6 million non-cash charge for unproved impairment expense during the six months ended June 30, 2020, related to acquired leases in our Midcontinent region that expired in 2020.

General and Administrative Expenses

Total general and administrative expenses for the six months ended June 30, 2021 were approximately $24.8 million, compared to $15.5 million for the six months ended June 30, 2020, with the current year increase primarily attributable to the Mid-Con Acquisition and the related additional expenses.

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


	Six Months Ended June 30,
	2021		2020

	(in thousands)
Wages and employee benefits ⁽¹⁾	$	10,011	$	5,934
Non-cash stock-based compensation ⁽²⁾		4,889		616
Professional fees⁽³⁾		2,639		3,655
Professional fees - special ⁽⁴⁾		3,757		1,334
Recouped overhead ⁽⁵⁾		(3,393)		(1,319)
Other ⁽⁶⁾		6,939		5,267
Total general and administrative expenses	$	24,842	$	15,487

(1)	Higher wages and employee benefits during the six months ended June 30, 2021 due to additional employees acquired by the Company in connection with the Mid-Con Acquisition.

(2)

Higher stock-based compensation expense for the six months ended June 30, 2021, due to restricted stock and PSU grants being awarded in the second quarter of 2021 as compared to the third quarter of 2020, as part of annual incentive bonus compensation, as well as an increase in the number of PSUs granted in 2021 and 2020 and the 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 integration of assets from the Mid-Con Acquisition. See Item 1. Note 3 – “Acquisitions and Dispositions” for further details.

(5)

These credits relate to overhead we recoup from working interest partners on our operated properties and offset against our other general and administrative costs. The increase in the current year ~~expense~~credit is ~~primarily~~ due to the additional ~~expenses~~overhead related to the acquired ~~Will Energy~~properties.

(6)	Includes fees related to insurance, office costs and ~~White Star properties, offices and employees.~~other company expenses.

Gain (Loss) from Affiliates

For the six months ended June 30, ~~2020 and June 30, 2019,~~2021, we recorded a ~~gain~~loss from affiliates of approximately ~~$0.1 million and $0.7~~$0.8 million, net of no tax expense, ~~respectively, related~~attributable 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~~from affiliates of ~~assets~~approximately $0.1 million, net of ~~$4.4 million related~~no tax expense, attributable to ~~the divestiture~~our equity investment in Exaro.

Gain from Sale 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. Assets

During the six months ended June 30, ~~2019,~~2021, we sold certain non-core Powder River Basin producing properties in Wyoming, which we acquired in the first quarter of 2021 as part of the Silvertip Acquisition. We also sold certain non-core, legacy and recently acquired producing and non-producing properties located in our Midcontinent, Permian and Other regions. These properties were sold for a collective total of approximately $2.8 million in cash and the buyers’ assumption of approximately $4.6 million in plugging and abandonment liabilities, resulting in a net gain of $0.3 million recorded during the six months ended June 30, 2021.

During the six months ended June 30, 2020, we sold non-core producing and non-producing properties located in our Midcontinent region. These properties were sold for approximately $0.5 million in cash and the buyers’ assumption of approximately $5.0 million in plugging and abandonment liabilities and revenue held in suspense. We recorded a gain ~~on sales~~ of ~~assets~~$4.4 million during the six months ended June 30, 2020, primarily as a result of ~~$0.4 million primarily related to post-closing adjustments from sales~~the buyers’ assumption of ~~non-core properties during 2019. See Item 1. Note 3 – “Dispositions” for additional information regarding these sales.~~the asset retirement obligations associated with the sold properties.

Gain (Loss) on Derivatives

During the six months ended June 30, 2021, we recorded a loss on derivatives of $69.6 million. Of this amount, $60.7 million was a non-cash reduction in the mark-to-market value of our hedges as commodity prices improved during 2021, and $8.8 million were realized losses during the first half of 2021. During the six months ended June 30, 2020, we recorded a gain on derivatives of $37.9 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 million were realized ~~gains as derivative contracts were settled each month during the period. During the six~~gains.

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months ended June 30, 2019, we recorded a loss on derivatives of $0.8 million. Of this amount, $2.1 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 Operating Activities

Cash flows provided by operating activities were approximately $64.0 million and $8.2 million for the six months ended June 30, 2021 and 2020, respectively. The table below provides additional detail of cash flows from operating activities for the six months ended June 30, 2021 and 2020:


	Six Months Ended June 30,
	2021		2020

	(in thousands)
Cash flows from operating activities, exclusive of changes in working capital accounts	$	50,210	$	17,663
Changes in operating assets and liabilities		13,824		(9,450)
Net cash provided by operating activities	$	64,034	$	8,213

Cash Used in Investing Activities

Net cash flows used in investing activities were $120.4 million and $19.5 million for the six months ended June 30, 2021 and 2020, respectively. The 2021 activity is primarily related to the Mid-Con Acquisition and the Silvertip Acquisition, as discussed below. The 2020 activity was primarily related to an offshore exploratory prospect and completion and infrastructure costs in the Southern Delaware Basin.

On January 21, 2021, we closed on the Mid-Con Acquisition and issued a total of 25,552,933 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 and Dispositions” 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 and Dispositions” for further details.

During the six months ended June 30, ~~2020,~~2021, we incurred ~~onshore~~capital expenditures of approximately $13.8 million, of which $5.2 million onrelated to the drilling of the Southern Delaware Basin wells. We also incurred approximately $6.4 million in expenditures primarily related to redevelopment activities of recently acquired properties in our Midcontinent, Permian and Rockies regions and $1.9 million in unproved offshore prospect costs, of which $1.1 million was paid for with the proceeds of an issuance of Company common stock, pursuant to our joint development agreement with Juneau Oil & Gas, LLC. The capital ~~projects, including $2.6 million~~expenditures in the prior year period primarily related to the offshore dry hole exploratory prospect and completion and infrastructure costs in the Southern Delaware ~~Basin~~Basin.

We currently forecast our 2021 capital expenditure budget to ~~bring one well on production~~be a total of approximately $30.0 - $34.0 million for recompletions, facility upgrades, waterflood development and ~~to drill a salt water disposal well, as well as $0.8 million in leasehold acquisition costs~~select drilling in the ~~same region.~~West Texas Permian (expected 3 net locations, 6 gross locations), among other things. The ~~remaining incurred onshore~~planned capital expenditures ~~related primarily~~also include development opportunities in our acquired properties as part of the Mid-Con Acquisition and the Silvertip Acquisition. The capital expenditure program will continue to ~~capitalized workovers.~~be evaluated for revision throughout the year. We believe that we will have the financial resources to increase the currently planned 2021 capital expenditure budget, when and if deemed appropriate, including as a result of changes in commodity prices, economic conditions or operational factors.

~~During~~Cash Provided by Financing Activities

Cash flows provided by financing activities for the six months ended June 30, 2021 and 2020 ~~we recorded exploration expenses~~were approximately $57.1 million and $10.0 million, respectively. The 2021 activity is primarily related to net borrowings under our Credit Agreement and also includes the issuance of ~~$10.9~~387,011 shares of the Company’s common stock, in lieu of cash, as payment

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for $1.1 million in offshore prospect costs pursuant to our joint development agreement with Juneau Oil & Gas, LLC. The 2020 activity includes $6.4 million related to t~~he drilling~~net borrowings outstanding under our Credit Agreement and approximately $3.4 million related to proceeds from the PPP Loan (defined below) we received under the CARES Act in April 2020.

In 2020, we entered into an Open Market Sale Agreement (the “Sale Agreement”) with Jefferies LLC (the “Sales Agent”). Pursuant to the terms of the ~~unsuccessful offshore exploratory Iron Flea prospect drilled~~Sale Agreement, we may sell, from time to time through the Sales Agent in the ~~shallow waters~~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 ~~Gulf~~net proceeds from any sales through the ATM Program, after deducting the Sales Agent’s commission and 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 Sale Agreement, we sold 117,571 shares for net proceeds of ~~Mexico. $2.7~~$0.5 million ofduring the ~~exploration expense related to the acquisition costs incurred in 2019 which were reclassified to exploration expense in 2020 as a result of the dry hole.~~

Our total capital expenditure program for the year 2020 is forecast at approximately $19.0 million, including the expenses associated with the Iron Flea exploratory prospect. Due to the low and volatile commodity price environment, the Company has suspended any further plans for drilling and completions in 2020. For 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 earlysix months ended June 30, 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.other factors.

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.

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. ~~The~~The 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. Theredetermination process. The semi-annual redeterminations will occur on or around May 1^st and November 1^st of each ~~year.~~ year. Upon the close of the Mid-Con Acquisition on January 21, 2021, our borrowing base increased to $130.0 million with an automatic $10.0 million stepdown in the borrowing base on March 31, 2021. On ~~June 9, 2020,~~May 3, 2021, we entered into the ~~Second~~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~~provided for, among other things, ~~further $10 million automatic reductions~~an increase in ~~our~~the Company’s borrowing base ~~on each~~from $120.0 million to $250.0 million, effective May 3, 2021, and expanded the bank group from nine to eleven banks. The Fifth Amendment also includes less restrictive hedge requirements and certain modifications to the financial covenants. See Item 1. Note 10 – “Long-Term Debt” for more information. As of June 30, ~~2020~~2021, we had $69.0 million outstanding under the Credit Agreement and ~~September 30, 2020. Accordingly, t~~he$2.9 million in outstanding letters of credit, with borrowing ~~base was $85 million as~~availability 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. approximately $178.1 million.

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~~Fifth Amendment reinstated the Current Ratio and Leverage Ratio requirements beginning as of June 30, 2021, and 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, both as defined in the Credit Agreement. The Second Amendment includes a waiver of the Current Ratio requirement until the quarter ending March 31, 2022. Additionally, the Second Amendment provides for, among other things, the increase in the Applicable Margin grid on borrowings outstanding by 50 basis points, 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 to a consolidated cash balance in excess of $5.0 million.~~3.25:1.0. As of June 30, ~~2020,~~2021, we were in compliance with all financial covenants under the Credit Agreement.

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 Debt”~~“Long-term debt” on ~~our~~the Company’s consolidated balance sheet.

The PPP Loan was set to 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~~commenced 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~~

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Table of ~~the PPP Loan at any time without incurring any prepayment charges.~~Contents

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 July 12, 2021, submitted our updated application for forgiveness of ~~all or part of~~the total amount outstanding under the PPP Loan in accordance with the updated application terms of the CARES Act and ~~applicable~~related guidance. InOn August 6, 2021, we received notice from the ~~event the~~Small Business Administration that our PPP ~~Loan or any portion thereof is~~loan was forgiven ~~the amount forgiven is applied to outstanding principal.~~in its entirety.

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,~~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.~~2021. Based upon that evaluation, our Chief Executive Officer and our Chief Financial and Accounting Officer concluded that, as of June 30, ~~2020,~~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.

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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. ~~There~~Other than such changes, there was no change in our internal control over financial reporting during the ~~three~~six months ended June 30, ~~2020~~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~~Except as set forth below, there have been no material changes from the risk factors disclosed in Item 1A. of Part 1 of our ~~2019~~2020 Form ~~10-K~~ 10-K.

RISKS RELATING TO THE PENDING INDEPENDENCE MERGER

We may failto completethe Pending Independence Merger if certainrequired conditions,many of whichare outsideourcontrol,are not satisfied.

Completionof the Pending Independence Mergeris subjectto variouscustomaryclosingconditions,including,but not limitedto:

●

approvaland adoptionof the Pending Independence Mergeragreement (the “Transaction Agreement”) by our stockholders;

●

the expirationor terminationof any applicablewaitingperiodunder the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended;

●

the absenceof any orderof injunctionprohibitingthe consummationof the Pending Independence Merger;

●

no materialadverseeffect (“MAE”) occurringwith respectto us or Independence;

●

subjectto certainexceptionsand materialityand MAEstandards,the accuracyof the representations and warrantiesof the partiesto the Transaction Agreement;

●

performanceand complianceby the partiesto the TransactionAgreementin allmaterialrespectswith agreementsand covenantscontainedin the TransactionAgreement;and

●

the registrationstatementon Form S-4 will have becomeeffectiveunder the SecuritiesAct, and no stop ordersuspendingitseffectivenessmay be in effector threatened.

Many of the conditionsto completionof the Pending Independence Mergerare not within our control,and ~~Item 1A.~~we cannot predictwhen,or if, theseconditionswill be satisfied.If any of ~~Part II~~ theseconditions are not satisfiedor waived priorto January7, 2022, it is possiblethatthe TransactionAgreementmay be terminated.Although Contango and Independencehave agreedin the TransactionAgreementto use reasonable best efforts,they may not be able to satisfyor receivethe variousclosingconditionsand obtainthe necessary approvalsin a timelyfashionor at all.

Failure to completethe Pending Independence Merger could negativelyimpactour stock priceandfuture businesses andfinancialresults.

If the Pending Independence Merger is not completed,we will be subjectto severalrisks,includingthe following:

●

we may experience negative reactions from our customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners;

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●

we may be liable to Independence under the terms and conditions of the Transaction Agreement, including a termination fee in certain circumstances;

●

payment for certain costs relating to the Pending Independence Merger, whether or not the Pending Independence Merger is completed, such as legal, accounting, financial advisor and printing fees;

●

negative reactions from the financial markets, including declines in the price of our stock due to the fact that current prices may reflect a market assumption that the Pending Independence Merger will be completed;

●

diverted attention of company management to the Pending Independence Merger rather than to our operations and pursuit of other opportunities that could have been beneficial to us; and

●

we may face litigation related to any failure to complete the Pending Independence Merger or related to any enforcement proceeding commenced against Contango to perform its obligations pursuant to the Transaction Agreement.

If the Pending Independence Merger is not completed,the risksdescribedabove may materializeand they may have a material adverseeffecton our resultsof operations,cash flows, financialpositionand stock price.

Shares of Class Acommon stock, par value $0.0001 per share, of NewPubCo (“New PubCo Class A Common Stock”) receivedby ourstockholdersas a resultof the Pending Independence Merger will have differentrightsfromshares of ourcommon stock andwill have less influence over management.

Uponclosing of the Pending Independence Merger, our stockholderswill no longerbe stockholdersof Contango. Our stockholderswho receivethe mergerconsiderationwill becomestockholdersof IE PubCo Inc., a Delaware corporation (“New PubCo”), and theirrightsas NewPubCo stockholderswill be governed by the termsof NewPubCo’s charterand bylaws. There will be important differencesbetween the currentrightsof our ~~Quarterly Report on Form 10-Q~~stockholdersand the rightsto which such stockholderswill be entitledas NewPubCostockholders.Unlike commonequityin traditionalcorporatestructures,includingour existingstructure, holdersof NewPubCo’s commonstock will not vote for the ~~period ended March 31, 2020.~~electionof directors. Asa result,holdersof NewPubCo’s commonstock will have lessabilityto influenceNewPubCo’s business than would the holdersof commonequityin a traditionalcorporatestructuresuch as ours.

Wewill be subjectto various uncertaintiesandcontractualrestrictionswhile the Pending Independence Merger is pending that could adversely affectourbusiness andoperations.

Uncertaintyabout the effectof the Pending Independence Merger on customers,suppliersand vendors may have an adverseeffect on our business,financialconditionand resultsof operations.It is possiblethatsome customers, suppliersand otherpersonswith whom we have businessrelationshipsmay delay or defercertainbusiness decisions,or mightdecideto seek to terminate,change or renegotiatetheirrelationshipwith us as a result of the Pending Independence Merger,which could negativelyaffectour financialresults,as well as the marketpriceof our stock, regardlessof whether the Pending Independence Merger is completed.

Additionally,under the termsof the TransactionAgreement,we are subjectto certainrestrictionson the conduct of ourbusinesspriorto completingthe Pending Independence Merger.The TransactionAgreement obligatesus to operate ourbusinessin the ordinarycourseconsistentwith past practiceand to use our reasonablebest effortsto preserveintactourbusinessorganization,preserveourassets,rightsand propertiesin good repairand condition,preserveourexistingrelationshipswith governmentalauthoritiesand preserveour relationshipswith customers,suppliers,contractors,licensors,licensees,distributorsand othershaving business dealingswith us. These restrictionscould preventContango frompursuingcertainbusinessopportunitiesthat arisepriorto the completion of the Pending Independence Merger and are outsidethe ordinarycourseof business.Such limitationscould negativelyaffectour businessesand operationspriorto the completionof the Transactions. “Transactions” as used herein shall mean the transactions contemplated by the Transaction Agreement.

Wemay have difficultyattracting,motivatingandretainingexecutivesandother employeesin lightof the Pending Independence Merger.

Uncertaintyabout the effectof the Pending Independence Mergeron our employeesmay impairourabilityto attract,retain and motivatepersonneluntilthe Pending Independence Merger is completed.Employeeretentionmay be particularlychallenging during the pendency of the Pending Independence Merger,as employeesmay feeluncertainabout theirfutureroleswith the combinedorganization.In addition,we may have to provideadditionalcompensationin order

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to retain employees.If employeesdepartbecauseof issuesrelatingto the uncertaintyand difficultyof integrationor a desirenot to becomeemployeesof the combinedcompany, the combinedcompany’sabilityto realizethe anticipatedbenefitsof the Transactionscould be adverselyaffected.

In connection with the Pending Independence Merger,Independence, Contangoand/or the combinedcompany may be required to take write-downs or write-offs,restructuringandimpairmentor other charges that could negativelyaffectthe business, assets,liabilities,prospects,outlook, financialconditionandresultsof operationsof Independence,Contangoand/or NewPubCo.

Although Independenceand Contango have conductedextensivedue diligencein connectionwith the Pending Independence Merger,we cannot assureyou thatthisdiligencerevealedallmaterialissuesthatmay be present,thatit would be possibleto uncover allmaterialissuesthrough a customaryamountof due diligence,or thatfactors outsideof Contango’s and Independence’scontrolwill not laterarise.Even if Contango’s and Independence’s due diligencesuccessfullyidentifiescertainrisks,unexpectedrisksmay ariseand previouslyknownrisksmay materializein a mannernot consistentwith Contango’s and Independence’spreliminaryriskanalysis.Further,as a resultof the Pending Independence Merger,purchaseaccounting,and the proposed operationof the combinedcompany going forward,Independence,Contango and/orthe combinedcompany may be requiredto take write-offsor write- downs,restructuringand impairmentor othercharges.Asa result,Independence,Contango and/orthe combined company may be forcedto write-downor write-offassets,restructureitsoperations,or incurimpairmentor other chargesthatcould negativelyaffectthe business,assets,liabilities,prospects,outlook, financialconditionand resultsof operationsof Independence,Contango and/orthe combinedcompany.

If the Pending Independence Merger,does not qualifyas a “reorganization”within the meaning of Section 368(a) of the Code,ourstockholdersmaybe requiredto pay substantialU.S.federalincometaxes.

The Pending Independence Merger is intendedto qualifyas a “reorganization”within the meaningof Section368(a) of the Code,and we intendto reportthe Pending Independence Mergerconsistentwith such qualification.

However, it is not a conditionto completethe Pending Independence Merger thatitbe treatedas a “reorganization,”and neitherNewPubConor Contango intends to obtaina rulingfromthe IRSwith respectto the tax consequencesof the mergers.If the IRSor a court determinesthatthe mergers,taken together,should not be treatedas a “reorganization”within the meaningof Section368(a)of the Code,a U.S.holderof our stockholders would generallyrecognizetaxablegain or loss upon the exchange of our common stock for NewPubCoClass ACommon Stock.

The Transaction Agreement limits our ability to pursue alternatives to the Pending Independence Merger and requires us, in specified circumstances, to pay a termination fee if we do so, which may discourage other bidders from making a favorable alternative transaction proposal.

The Transaction Agreement restricts our ability, subject to specified exceptions, from initiating, encouraging, soliciting or entering into discussions with any third party regarding alternative acquisition proposals. This prohibition limits Contango’s ability to pursue offers from other possible acquirers that may be superior from a financial point of view. In addition, if the Transaction Agreement is terminated under certain specified circumstances, we would be required to pay a $33,375,989 termination fee to Independence.

These provisions could discourage a potential third-party acquirer that might have an interest in acquiring all or a significant portion of our stock or assets from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher per share cash or market value than the market value proposed to be received or realized in the Transactions. Similarly, these provisions might result in a potential third-party acquirer proposing to pay a lower price to our stockholders than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances. If the Transaction Agreement is terminated and we determine to seek another business combination, we may not be able to negotiate a transaction with another party on terms comparable to, or better than, the terms of the Transactions.

We may be a target of securities class action and derivative lawsuits, which could result in substantial costs and may delay or prevent the Pending Independence Merger from being completed.

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Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on Contango’s and Independence’s respective liquidity and financial condition.

Lawsuits that may be brought against us could also seek, among other things, injunctive relief or other equitable relief, including a request to rescind parts of the Transaction Agreement already implemented and to otherwise enjoin the parties from consummating the Pending Independence Merger. One of the closing conditions to is that no order or injunction issued by any court or other governmental entity of competent jurisdiction or other legal restraint or prohibition has been entered and continues to be in effect and no law has been adopted or is effective, in either case, that prohibits or makes illegal the closing of the Pending Independence Merger. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Pending Independence Merger, that injunction may delay or prevent the Transactions from being completed within the expected timeframe or at all, which may adversely affect our business, financial position and results of operation. We, or Independence, may terminate the Transaction Agreement if any court of competent jurisdiction or other governmental entity issues any judgment, order, injunction, rule or decree, or takes any other action restraining, enjoining or otherwise prohibiting any of the Transactions contemplated by the Transaction Agreement, and such judgment, order, injunction, rule, decree or other action becomes final and nonappealable, so long as the party seeking to terminate the Transaction Agreement has used its reasonable best efforts to contest, appeal and remove such judgment, order, injunction, rule, decree, ruling or other action in accordance with the terms of the Transaction Agreement.

There can be no assurance that any of the defendants will be successful in the outcome of any potential lawsuits. The defense or settlement of any lawsuit or claim that remains unresolved at the time the Pending Independence Merger is completed may adversely affect our business, financial condition, results of operations and cash flows.

RISKS RELATED TO THE PENDING WIND RIVER BASIN ACQUISITION

We may be unable to integrate the assets purchased in the Pending Wind River Basin Acquisition successfully or realize the anticipated benefits thereof.

On July 7, 2021, we entered into a purchase and sale agreement (the “PSA”) with Burlington Resources Oil & Gas Company LP, Burlington Resources Trading LLC, ConocoPhillips Company, Inexco Oil Company and The Louisiana Land and Exploration Company LLC to acquire certain assets located in the Wind River Basin of Wyoming for a purchase price of $67.0 million, subject to customary purchase price adjustments. The combination of independent businesses and assets is complex, costly and time consuming. Potential difficulties that we may encounter as part of the integration process include the following:

●	the inability to successfully combine and integrate these assets in a manner that permits us to achieve, on a timely basis or at all, the enhanced revenue opportunities and cost savings and other benefits and synergies anticipated to result from the Pending Wind River Basin Acquisition;

●	diversion of resources and management attention from our legacy business and the Pending Wind River Basin Acquisition;

●	complexities associated with managing the purchased assets, including the challenge of integrating complex systems, technology, networks and other assets in a seamless manner that minimizes any adverse impact on customers, suppliers, employees and other constituencies;

●	the assumption of contractual obligations with less favorable or more restrictive terms;

●	potential unknown liabilities and unforeseen increased expenses or delays associated with the Pending Wind River Basin Acquisition; and

●	the disruption of, or the loss of momentum in, our ongoing businesses or inconsistencies in standards, controls, procedures and policies.

Any of these issues could adversely affect our ability to maintain relationships with customers, suppliers, employees and other constituencies or achieve the anticipated benefits of the Pending Wind River Basin Acquisition, or could reduce our earnings or otherwise adversely affect our business and financial results.

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The Pending Wind River Basin Acquisition may not be completed and the PSA may be terminated in accordance with its terms. Failure to complete the Pending Wind River Basin Acquisition could negatively impact the price of shares of our common stock, as well as our future business and financial results.

The Pending Wind River Basin Acquisition is expected to close in the third quarter of 2021, subject to a number of conditions that must be satisfied, or waived, in each case prior to the completion of the Pending Wind River Basin Acquisition. These conditions to the completion of the Pending Wind River Basin Acquisition, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all, and, accordingly, the Pending Wind River Basin Acquisition may be delayed or may not be completed. The PSA may also be terminated under certain circumstances. If the transactions contemplated by the PSA are not completed for any reason, our ongoing businesses and financial results may be adversely affected.

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

On May 18, 2021, the Company issued 170,345 shares of its common stock, in lieu of cash, as payment for $0.7 million in offshore prospect costs as part of the Company’s joint development agreement with Juneau Oil & Gas, LLC. Such securities were issued pursuant to the exemption from registration contained in [Section 4(a)(2) of the Securities Act.

The Company withheld the following shares from employees during the quarter ended June 30, ~~2020~~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	Average Price		Purchased as Part of		of Shares that May Yet
Period	Shares Withheld	Per Share		Publicly Announced Program		be Purchased Under Program

April 2021	11,736	$	5.06	—	$	—
May 2021	—	$	—	—	$	—
June 2021	120,158	$	4.52	—	$	—
Total	131,894	$	4.57	—	$	31.8 million ⁽¹⁾

Total Number of Shares

Approximate Dollar Value

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

April 2020

12,498

$
1.63

—

$
—

May 2020

1,310

$
1.91

—

$
—

June 2020

—

$
—

—

$
—

Total

13,808

$
1.65

—

$
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.~~2021. As of June 30, ~~2020,~~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.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number		Description
2.1		Transaction Agreement dated as of June 7, 2021, by and among Contango Oil & Gas Company, Independence Energy LLC, IE PubCo Inc., IE OpCo LLC, IE C Merger Sub Inc. and IE L Merger Sub LLC Amended and Restated Certificate of Formation of Contango Oil & Gas Company (filed as Exhibit 2.1 to the Company’s Report on Form 8-K dated June 8, 2021, as filed with the Securities and Exchange Commission on June 8, 2021 and incorporated by reference herein).
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~~ Contango Oil &and Gas Company Change in Control Severance Plan (filed as Exhibit ~~3.4~~10.5 to the Company’s Quarterly Report on Form ~~8-K~~10-Q dated ~~June 14, 2019,~~May 13, 2021, as filed with the Securities and Exchange Commission on ~~June 14, 2019~~May 13, 2021 and incorporated by reference herein).
~~10.1~~10.2*		~~Second Amendment to Credit Agreement, dated June 9, 2020, by and among~~ Contango Oil &and Gas Company ~~JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders Signatory hereto~~Executive Severance Plan (filed as Exhibit ~~10.1~~10.6 to the Company’s Quarterly Report on Form ~~8-K~~10-Q dated ~~June 15, 2020,~~May 13, 2021, as filed with the Securities and Exchange Commission on ~~June 15, 2020~~May 13, 2021 and incorporated by reference herein).
~~10.2~~		~~Amended and Restated 2009 Stock Incentive 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~~The following financial statements from the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statement of Shareholders’ Equity, and (v) Notes to the Consolidated Financial Statements. †
104		The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, formatted in Inline XBRL (included as Exhibit 101).†

* Indicates a management contract or compensatory plan or arrangement

†	Filed herewith.

††	Furnished 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~~11, 2021	By:	/s/ WILKIE S. COLYER
		Wilkie S. Colyer
		Chief Executive Officer
		(Principal Executive Officer)


Date: August ~~19, 2020~~11, 2021	By:	/s/ E. JOSEPH GRADY
		E. Joseph Grady
		Senior Vice President and Chief Financial and Accounting Officer
		(Principal Financial and Accounting Officer)

4352

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)

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


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


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


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


	Three Months Ended June 30, 2020		Three Months Ended June 30, 2019
Operating lease cost ^{(1) (2)}	$	743	$	100
Financing lease cost - amortization of right-of-use assets		155		-
Financing lease cost - interest on lease liabilities		27		-
Administrative lease cost⁽³⁾		19		18
Short-term lease cost ^{(1) (4)}		615		2,068
Total lease cost	$	1,559	$	2,186


	Three Months Ended
	June 30, 2019	September 30, 2019	December 31, 2019	March 31, 2020	June 30, 2020
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