Contango Oil & Gas 10Q 2021 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2021


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

For the transition period from to

Commission file number 001-16317

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

TEXAS		95-4079863

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

111 E. 5^th Street, Suite 300 Fort Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

(817) 529-0059

(Registrant’s telephone number, including area code)

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

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

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

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

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


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

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

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

The total number of shares of common stock, par value $0.04 per share, outstanding as of November 10, 2021 was 201,338,567.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2021

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		Page
PART I—FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets as of September 30, 2021 (unaudited) and December 31, 2020	3
	Consolidated Statements of Operations (unaudited) for the three and nine months ended September 30, 2021 and 2020	4
	Consolidated Statements of Cash Flows (unaudited) for the nine months ended September 30, 2021 and 2020	5
	Consolidated Statements of Shareholders’ Equity (unaudited) for the nine months ended September 30, 2021 and 2020	6
	Notes to the Consolidated Financial Statements (unaudited)	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	49
Item 4.	Controls and Procedures	49

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 3.	Defaults upon Senior Securities	50
Item 4.	Mine Safety Disclosures	50
Item 5.	Other Information	50
Item 6.	Exhibits	51

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.

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Item 1. Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except number of shares)


	September 30,		December 31,
	2021		2020
	(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	3,084	$	1,383
Accounts receivable, net		101,271		37,862
Prepaid expenses		6,801		3,360
Current derivative asset		—		2,996
Inventory		571		442
Deposits and other		—		763
Total current assets		111,727		46,806
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, successful efforts method of accounting:
Proved properties		1,610,533		1,274,508
Unproved properties		14,146		16,201
Other property & equipment		2,855		1,669
Accumulated depreciation, depletion, amortization and impairment		(1,183,606)		(1,190,475)
Total property, plant and equipment, net		443,928		101,903
OTHER NON-CURRENT ASSETS:
Investments in affiliates		4,896		6,793
Long-term derivative asset		—		497
Right-of-use lease assets		7,137		5,448
Debt issuance costs		3,582		1,782
Deposits		1,813		7,038
Total other non-current assets		17,428		21,558
TOTAL ASSETS	$	573,083	$	170,267

CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	173,608	$	83,970
Current derivative liability		71,702		1,317
Current asset retirement obligations		5,193		4,249
Total current liabilities		250,503		89,536
NON-CURRENT LIABILITIES:
Long-term debt		118,000		12,369
Long-term derivative liability		22,467		1,648
Asset retirement obligations		126,076		48,523
Lease liabilities		3,673		2,624
Total non-current liabilities		270,216		65,164
TOTAL LIABILITIES		520,719		154,700
COMMITMENTS AND CONTINGENCIES (NOTE 12)
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 400,000,000 shares authorized, 201,435,797 shares issued and 201,175,841 shares outstanding at September 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		623,796		535,192
Treasury shares at cost (259,956 shares at September 30, 2021 and 92,574 shares at December 31, 2020)		(1,024)		(248)
Accumulated deficit		(578,453)		(526,318)
Total shareholders’ equity		52,364		15,567
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	573,083	$	170,267

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020

	(unaudited)				(unaudited)
REVENUES:
Oil and condensate sales	$	56,044	$	17,415	$	149,246	$	48,127
Natural gas sales		26,241		7,930		55,556		22,718
Natural gas liquids sales		15,175		5,003		35,735		11,918
Other operating revenues		2,467		1,000		2,980		1,000
Total revenues		99,927		31,348		243,517		83,763
EXPENSES:
Operating expenses		44,916		14,586		108,901		48,859
Exploration expenses		174		(227)		458		11,344
Depreciation, depletion and amortization		9,792		6,185		30,391		24,131
Impairment and abandonment of oil and natural gas properties		258		47		712		145,925
General and administrative expenses	��	14,599		8,699		39,441		24,186
Total expenses		69,739		29,290		179,903		254,445
OTHER INCOME (EXPENSE):
Loss from investment in affiliates, net of income taxes		(1,093)		(126)		(1,897)		(13)
Gain from sale of assets		113		38		461		4,471
Interest expense		(1,598)		(1,057)		(4,156)		(4,421)
Gain (loss) on derivatives, net		(48,390)		(7,369)		(117,951)		30,526
Gain on extinguishment of debt		3,369		—		3,369		—
Other income		1,145		319		3,714		1,456
Total other income (expense)		(46,454)		(8,195)		(116,460)		32,019
NET LOSS BEFORE INCOME TAXES		(16,266)		(6,137)		(52,846)		(138,663)
Income tax benefit (provision)		1,066		(668)		711		(1,431)
NET LOSS	$	(15,200)	$	(6,805)	$	(52,135)	$	(140,094)
NET LOSS PER SHARE:
Basic	$	(0.08)	$	(0.05)	$	(0.26)	$	(1.07)
Diluted	$	(0.08)	$	(0.05)	$	(0.26)	$	(1.07)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		199,136		131,686		196,867		131,493
Diluted		199,136		131,686		196,867		131,493

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Nine Months Ended
	September 30,
	2021		2020

	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(52,135)	$	(140,094)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		30,391		24,131
Impairment and abandonment of oil and natural gas properties		72		145,938
Exploration expenditures - dry hole costs		—		10,421
Amortization of debt issuance costs		734		1,486
Deferred income taxes		—		676
Gain on sale of assets		(461)		(4,471)
Loss from investment in affiliates		1,897		13
Stock-based compensation		8,090		2,378
Non-cash mark-to-market loss (gain) on derivative instruments		96,240		(8,155)
Gain on extinguishment of debt		(3,369)		—
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable & other receivables		(49,529)		7,489
Increase in prepaid expenses		(3,216)		(1,894)
Increase in inventory		(129)		(305)
Increase (decrease) in accounts payable & advances from joint owners		32,549		(2,122)
Increase (decrease) in other accrued liabilities		21,971		(9,000)
Decrease in income taxes receivable, net		268		281
Increase (decrease) in income taxes payable		(2,026)		119
Decrease (increase) in deposits and other		7,138		(328)
Net cash provided by operating activities	$	88,485	$	26,563
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas exploration and development expenditures	$	(11,040)	$	(22,209)
Acquisition of oil & natural gas properties		(183,724)		—
Proceeds from sales of oil & natural gas properties		2,800		339
Additions to furniture & equipment		(942)		(171)
Net cash used in investing activities	$	(192,906)	$	(22,041)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Credit Agreement	$	267,800	$	58,000
Repayments under Credit Agreement		(158,800)		(64,768)
Paycheck Protection Program loan		—		3,369
Net proceeds from equity offering		432		410
Purchase of treasury stock		(776)		(188)
Debt issuance costs		(2,534)		—
Net cash provided by (used in) financing activities	$	106,122	$	(3,177)
NET CHANGE IN CASH AND CASH EQUIVALENTS	$	1,701	$	1,345
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		1,383		1,624
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	3,084	$	2,969

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

For the nine months ended September 30, 2021

(in thousands, except number of shares)


				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
Treasury shares at cost	(1,901)		—		—		(8)		—		(8)
Restricted shares activity	(4,517)		—		—		—		—		—
Stock-based compensation	—		—		3,201		—		—		3,201
Net loss	—		—		—		—		(15,200)		(15,200)
Balance at September 30, 2021	201,175,841	$	8,045	$	623,796	$	(1,024)	$	(578,453)	$	52,364

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

For the nine months ended September 30, 2020

(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

	(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)
Equity offering - common stock	—		—	8,900		—		(27)		—		—		(27)
Treasury shares at cost	—		—	(3,678)		—		—		(8)		—		(8)
Restricted shares activity	—		—	1,011,699		41		(41)		—		—		—
Stock-based compensation	—		—	—		—		1,764		—		—		1,764
Net loss	—		—	—		—		—		—		(6,805)		(6,805)
Balance at September 30, 2020	—	$	—	133,013,678	$	5,312	$	474,510	$	(206)	$	(501,070)	$	(21,454)

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and Business

Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Fort Worth, Texas based independent oil and natural gas 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 and 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 regions as of September 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, Frontier, Fort Union, Lance, Mesa Verde, Codey, 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 Organization of Petroleum Exporting Countries (“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. 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, further suspended all drilling in the second quarter of 2020, and then focused on certain measures that included, 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 such as 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

Drilling Program

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. 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 and further suspended all drilling in the second quarter of 2020. Due to strengthening oil prices in 2021 and the Company’s identification of more cost-efficient methods of drilling and completing its Permian Basin wells, the Company resumed a

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conservative one-rig drilling program in the Southern Delaware Basin in the second quarter of 2021. 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 other operators adjacent 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 is the first Company well drilled to that formation. 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. The first two wells, both drilled to the Wolfcamp A formation, were drilled to an average total measured depth of 20,440 feet with an average lateral length of 9,700 feet and 48 stages of fracture stimulation. The third well, drilled to the Second Bone Spring formation, was drilled to a total measured depth of 19,090 feet with a lateral length of 9,574 feet and 47 stages of fracture stimulation. These three wells were brought online in mid-October and are still being evaluated at this time. The Company plans to begin completion operations on the second three wells in late November, with first production expected in January 2022. As of September 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 nine months ended September 30, 2021, the Company incurred capital drilling and completion expenditures of approximately $13.2 million related to the Southern Delaware Basin wells. The Company also incurred approximately $10.2 million in expenditures for redevelopment activities primarily related to acquired properties in the Midcontinent, Permian and Rockies regions and $2.3 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 (3 net locations, 6 gross locations), among other things. This forecast does not account for the Pending Independence Merger. 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 for the remainder of 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.

For the remainder of 2021, the Company plans to continue to make balance sheet strength a priority. 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.

Acquisitions

On January 21, 2021, the Company closed on the acquisition of Mid-Con Energy Partners, LP (“Mid-Con”), in an all-stock merger transaction in which Mid-Con became a direct, wholly owned subsidiary of Contango (the “Mid-Con Acquisition”). A total of 25,552,933 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 date of August 1, 2020 and the closing date, the net consideration paid was approximately $53.3 million. See Note 3 – “Acquisitions and Dispositions” for more information.

On June 7, 2021, the Company 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-

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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 remains subject to the approval of the Company’s stockholders at the Special Meeting of the Stockholders to be held on December 6, 2021, and is expected to be completed in December 2021. The Pending Independence Merger agreement includes certain restrictions on the conduct of the business of the Company until the closing, such as a requirement to operate in the ordinary course of business and limitations on, among other things, the Company’s ability to make acquisitions, declare or pay dividends, issue or sell equity or incur debt. Upon completion of the Pending Independence Merger, existing Independence shareholders are expected to own approximately 76% and existing Contango shareholders are expected to own approximately 24% of the combined company. See Note 3 – “Acquisitions and Dispositions” and Note 13 – “Subsequent Events” for further details.

On August 31, 2021, the Company closed on the acquisition of low decline, conventional gas assets in the Wind River Basin of Wyoming (the “Wind River Basin Acquisition”). Upon closing, Contango acquired approximately 446 Bcfe of PDP reserves (unaudited) for a total purchase price of $67.0 million in cash. After customary closing adjustments, including the results of operations during the period between the effective date of June 1, 2021 and the closing date, the net consideration paid was approximately $62.6 million, subject to customary purchase price adjustments. See Note 3 – “Acquisitions and Dispositions” for further details.

Other

On April 28, 2021, the Company adopted the Contango Oil & Gas Company Change in Control Severance Plan (the “Change in Control Plan”), which provides “double trigger” severance payments and benefits to all employees including the Company’s named executive officers. The policy provides an eligible participant with certain payments and benefits in the event that the participant experiences a qualifying termination event within the 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 control, the Company’s Chief Executive Officer and the Company’s President would become entitled to receive 250%, and the Company’s Senior Vice President and Chief Financial Officer would become entitled to receive 200%, of the sum of the executive’s annual base salary and target annual cash bonus. In addition, the executive would receive (1) any unpaid cash bonus for the year preceding the year of termination based on actual performance; (2) Company-paid COBRA continuation coverage for up to 18 months following the date of termination; (3) reimbursement for up to $10,000 in outplacement services; and (4) any outstanding unvested PSU equity awards (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 an executive may be reduced if doing so would put the executive in a more advantageous after-tax provision than if payments were not reduced and the executive became subject to excise taxes under Section 4999 of the Code.

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 Chief Executive Officer and the Company’s President, 150%, and in the case of the Company’s Senior Vice President and Chief Financial Officer, 100%, of the sum of the participant’s annual base salary and target bonus. In addition, the participant would receive (1) any unpaid annual cash bonus for the year preceding 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 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 executive will remain outstanding and vest based on actual performance over the applicable performance period.

On May 3, 2021, the Company entered into the Fifth Amendment to the Credit Agreement (the “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

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also includes less restrictive hedge requirements and certain modifications to financial covenants. See Note 10 – “Long-Term Debt” for more information.

In light of the Pending Independence Merger, on October 28, 2021, the Company, JPMorgan Chase Bank, N.A. and the lenders under the Credit Agreement entered into a waiver letter which, among other things, postpones the November 2021 scheduled redetermination of the Company’s borrowing base until on or about February 1, 2022. See Note 10 – “Long-Term Debt” and Note 13 – “Subsequent Events” for 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, 2020 (“2020 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2020 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this interim report.

Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2020 Form 10-K. These unaudited interim consolidated results of operations for the nine months ended September 30, 2021 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2021.

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

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

Oil and Natural Gas Properties - Successful Efforts

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

The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive, but then actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment and/or impairment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil or natural gas field are typically treated as development costs and capitalized, but often these

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seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory.

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

Impairment of Long-Lived Assets

Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field-by-field basis to the unamortized capitalized cost of the assets in that field. If the estimated future undiscounted cash flows, based on the Company’s estimate of future reserves, oil and natural gas prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. Additionally, the Company may use appropriate market data to determine fair value. NaN impairment of proved properties was recorded during the nine months ended September 30, 2021.

In the first quarter of 2020, the COVID-19 pandemic and the resulting deterioration in the global demand for oil, combined with the failure by OPEC and Russia to reach an agreement on lower production quotas until April 2020, caused a dramatic increase in the supply of oil, a corresponding decrease in commodity prices, and reduced the demand for all commodity products. Consequently, during the nine months ended September 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, 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 then forecasted development plans for its proved, undeveloped locations. As a result of the improvement in commodity prices during 2021 and that impact on the value of the Company’s proved reserves, no impairment of proved properties has been recorded for the nine months ended September 30, 2021.

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 nine months ended September 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 nine months ended September 30, 2020 related to expiring leases in the Company’s Midcontinent region.

Net Loss Per Common Share

Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. The Company excluded 4,914 shares or units and 53,106 shares or units of potentially dilutive securities during the three and nine months ended September 30, 2021, respectively, as they were antidilutive. The Company excluded 924,082 shares or units and 480,426 shares or units of potentially dilutive securities during the three and nine months ended September 30, 2020, respectively, as they were antidilutive.

Subsidiary Guarantees

Contango Oil & Gas Company, as the parent company of its subsidiaries, filed a registration statement on Form S-3 on December 18, 2020 with the SEC to register, among other securities, debt securities that the Company may issue from time to time. Contango Resources, Inc., Contango Midstream Company, Contango Operators, Inc., Contaro Company, Contango Alta Investments, Inc. and any other of the Company’s future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”) are co-registrants with the Company under the registration statement, and the registration statement also registered guarantees of debt securities by such Subsidiary Guarantors. The Subsidiary Guarantors are wholly-owned by the Company, either directly or indirectly, and any guarantee by the

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Subsidiary Guarantors will be full and unconditional. The Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Company. Finally, the Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party.

Revenue Recognition

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

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

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

Leases

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

Recent Accounting Pronouncements

In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The new guidance aligns the requirement for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirement for capitalizing implementation costs incurred to develop or obtain internal-use-software (and hosting arrangements that include an internal-use software license). ASU 2018-15 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2019. The Company adopted ASU 2018-15 on January 1, 2020 on a prospective basis. Accordingly, the Company capitalized $0.8 million in implementation costs incurred in a cloud computing arrangement that is a service contract which are included in “Prepaid expenses” on the Company’s consolidated balance sheet as of September 30, 2021. Such capitalized costs will be amortized over the term of the hosting arrangement, commencing when the capitalized asset is ready for its intended use, which is expected to be in early 2022. Costs related to preliminary project activities and post-implementation activities are expensed as incurred.

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

3. Acquisitions and Dispositions

Wind River Basin Acquisition

On August 31, 2021, the Company closed on the acquisition of low decline, conventional gas assets in the Wind River Basin of Wyoming. Upon closing, Contango acquired approximately 446 Bcfe of PDP reserves (unaudited) for a total purchase price of $67.0 million in cash. After customary closing adjustments of $4.4 million, including the results of operations during the period between the effective date of June 1, 2021 and the closing date, the net consideration paid was approximately $62.6 million, subject to customary purchase price adjustments.

The Wind River Basin Acquisition was accounted for as an asset acquisition under FASB ASC 805, Business Combinations (“ASC 805”). Under the accounting for asset acquisitions, the Wind River Basin Acquisition was recorded using a cost accumulation and allocation model under which the cost of the acquisition was allocated on a relative fair value basis to the assets acquired and liabilities assumed. As an asset acquisition, acquisition-related transaction costs are capitalized as a component of the cost of the assets acquired.

Pending Independence Merger

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 remains subject to the approval of the Company’s stockholders at the Special Meeting of the Stockholders to be held on December 6, 2021, and is expected to be completed in December 2021. The Pending Independence Merger agreement includes certain restrictions on the conduct of the business of the Company until the closing, such as a requirement to operate in the ordinary course of business and limitations on, among other things, the Company’s ability to make acquisitions, declare or pay dividends, issue or sell equity or incur debt. Upon completion of the Pending Independence Merger, existing Independence shareholders are expected to own approximately 76% and existing Contango shareholders are expected to own approximately 24% of the combined company. See Note 13 – “Subsequent Events” for further details.

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 connection with the execution of the Purchase Agreement, the Company paid $7.0 million as a deposit for its obligations under the Purchase Agreement, which is included in the consolidated balance sheet as of December 31, 2020. The Silvertip Acquisition closed on February 1, 2021. After customary closing adjustments of $4.7

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million, including the results of operations during the period between the effective date of August 1, 2020 and the closing date, the net consideration paid was approximately $53.3 million, including the deposit previously paid in 2020. The Silvertip Acquisition was accounted for as an asset acquisition under ASC 805.

A summary of the consideration paid and the preliminary relative fair value of the assets acquired and liabilities assumed, which is subject to change based upon the final settlement statement, 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

In July of 2021, the Company paid $2.4 million in cash to purchase additional working interest in certain wells which were originally acquired in the Silvertip Acquisition and located in the Company’s Rockies region.

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 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

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
		(unaudited)
Revenues	$	202,442
Net loss	$	(191,975)
Basic loss per share	$	(0.97)
Diluted loss per share	$	(0.97)

Dispositions

During the nine months ended September 30, 2021, the Company sold certain non-core Powder River Basin producing properties in Wyoming, which were acquired in the first quarter of 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

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million in cash and the buyers’ assumption of approximately $5.1 million in plugging and abandonment liabilities, resulting in a net gain of $0.5 million recorded during the nine months ended September 30, 2021.

During the nine months ended September 30, 2020, the Company sold certain producing and non-producing properties located in its 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. The Company recorded a gain of $4.5 million, primarily as a result of the buyers’ assumption of the asset retirement obligations associated with the sold properties.

4. Fair Value Measurements

The 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 consolidated balance sheets, but also the impact of the 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 September 30, 2021. A financial 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 September 30, 2021 (in thousands):


	Total		Fair Value Measurements Using
	Carrying Value		Level 1		Level 2		Level 3
Derivatives
Commodity price contracts - assets	$	—	$	—	$	—	$	—
Commodity price contracts - liabilities	$	(94,169)	$	—	$	(94,169)	$	—

Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset or liability” on the Company’s consolidated balance sheets 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 September 30, 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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Impairments

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

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

Asset Retirement Obligations

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and natural gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and 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 program in light of changes in production, market conditions, commodity price forecasts and requirements under its Credit Agreement.

As of September 30, 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 September 30, 2021, the Company’s oil derivative contracts include hedges for 0.6 MMBbls of remaining 2021 production with an average floor price of $56.56 per barrel and 1.9 MMBbls of 2022 production with an average floor price of $53.39 per barrel. As of September 30, 2021, the Company’s natural gas derivative contracts include 4.4 Bcf of remaining 2021 production with an average floor price of $2.90 per MMBtu and 16.3 Bcf of 2022 production with an average floor price of $2.78 per MMBtu. Approximately 95% of the Company’s hedges are swaps, and the Company has no three-way collars or short puts.

As of September 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	Q4 2021	Swap	547,251	Bbls	$	57.06			⁽¹⁾		(9,535)
Oil	Q1 2022	Swap	585,000	Bbls	$	56.34			⁽¹⁾		(9,628)
Oil	Q2 2022	Swap	473,000	Bbls	$	52.92			⁽¹⁾		(8,551)
Oil	Q3 2022	Swap	417,000	Bbls	$	51.27			⁽¹⁾		(7,426)
Oil	Q4 2022	Swap	407,000	Bbls	$	51.86			⁽¹⁾		(6,363)
Oil	Q1 2023	Swap	380,000	Bbls	$	53.15			⁽¹⁾		(4,837)
Oil	Q2 2023	Swap	150,000	Bbls	$	58.43			⁽¹⁾		(987)
Oil	Q4 2021	Collar	60,251	Bbls	$	52.00	-	58.80	⁽¹⁾		(955)
Natural Gas	Q4 2021	Swap	3,975,000	MMBtus	$	2.89			⁽²⁾		(11,948)
Natural Gas	Q1 2022	Swap	3,990,000	MMBtus	$	2.78			⁽²⁾		(12,222)
Natural Gas	Q2 2022	Swap	4,375,000	MMBtus	$	2.77			⁽²⁾		(4,886)
Natural Gas	Q3 2022	Swap	3,650,000	MMBtus	$	2.73			⁽²⁾		(4,244)
Natural Gas	Q4 2022	Swap	3,800,000	MMBtus	$	2.57			⁽²⁾		(4,508)
Natural Gas	Q1 2023	Swap	2,850,000	MMBtus	$	2.73			⁽²⁾		(3,902)
Natural Gas	Q2 2023	Swap	3,000,000	MMBtus	$	2.73			⁽²⁾		(1,315)
Natural Gas	Q4 2021	Collar	400,000	MMBtus	$	3.00	-	3.41	⁽²⁾		(1,022)
Natural Gas	Q1 2022	Collar	510,000	MMBtus	$	3.00	-	3.41	⁽²⁾		(1,284)
Natural Gas	Q1 2023	Collar	550,000	MMBtus	$	2.63	-	3.01	⁽²⁾		(556)
Total net fair value of derivative instruments (in thousands)										$	(94,169)

(1)

Based on West Texas Intermediate oil prices.

(2)

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 September 30, 2021 (in thousands):


	Gross		Netting ⁽¹⁾		Total
Assets	$	—	$	—	$	—
Liabilities	$	(94,169)	$	—	$	(94,169)

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

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


	Gross		Netting ⁽¹⁾		Total
Assets	$	3,493	$	—	$	3,493
Liabilities	$	(2,965)	$	—	$	(2,965)

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

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The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the three and nine months ended September 30, 2021 and 2020 (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Oil contracts	$	(8,512)	$	3,959	$	(16,186)	$	15,217
Natural gas contracts		(4,378)		1,709		(5,525)		7,154
Realized gain (loss)	$	(12,890)	$	5,668	$	(21,711)	$	22,371

Oil contracts	$	(3,069)	$	(6,329)	$	(51,994)	$	17,840
Natural gas contracts		(32,431)		(6,708)		(44,246)		(9,685)
Non-cash mark-to-market gain (loss)	$	(35,500)	$	(13,037)	$	(96,240)	$	8,155
Gain (loss) on derivatives, net	$	(48,390)	$	(7,369)	$	(117,951)	$	30,526

6. Stock-Based Compensation

2009 Incentive Compensation Plan

The Company has in place the Contango Oil & Gas Company Third Amended and Restated 2009 Incentive Compensation Plan (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 Company’s board of directors, subject to stockholder approval, approved an amendment to the 2009 Plan that will increase the number of shares of the Company’s common stock authorized for issuance pursuant to the 2009 Plan by 11,500,000 from 12,500,000 shares to 24,000,000 shares, effective immediately following the closing of the Pending Independence Merger.

Restricted Stock

During the nine months ended September 30, 2021, the Company granted 1,415,189 shares of restricted common stock to employees, which vest ratably over three years, under the 2009 Plan, as part of their overall compensation package. Additionally, during the nine months ended September 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. The Company also granted 80,142 shares of restricted common stock related to internal reorganizational changes during the nine months ended September 30, 2021. The weighted average fair value of the restricted shares granted during the nine months ended September 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 62,306 forfeitures of restricted stock during the nine months ended September 30, 2021. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2021 was approximately $0.2 million. The Company recognized approximately $2.2 million in restricted stock compensation expense during the nine months ended September 30, 2021, related to restricted stock previously granted to its officers, employees and directors. As of September 30, 2021, the number of shares of unvested restricted common stock outstanding was 2,039,165 shares, with an additional $5.7 million of future restricted stock compensation expense remaining to be recognized over the weighted average vesting period of 2.4 years. Approximately 3.0 million shares remained available for grant under the 2009 Plan as of September 30, 2021, assuming PSUs (as defined below) are settled at 100% of target. In October 2021, the Company granted 162,726 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan as a result of their re-election to the board at the annual shareholders’ meeting.

During the nine months ended September 30, 2020, the Company granted 1,041,365 shares of restricted common stock to employees, which vest ratably over three years, under the 2009 Plan, as part of their overall compensation package and 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 nine months ended September 30, 2020, was $2.26 per share, with a total fair value of approximately $2.7 million and no adjustment for an estimated weighted average forfeiture rate. There were 32,205 forfeitures of restricted stock during the nine months ended September 30, 2020. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2020 was approximately $0.1 million. The Company recognized approximately $0.8 million in restricted stock

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compensation expense during the nine months ended September 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 November 10, 2021, the number of shares of unvested restricted common stock outstanding was 2,201,891 shares.

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 the PSUs may range from 0% to 300% of the targeted number of PSUs stated in the award agreements, contingent upon the achievement of certain share price appreciation targets compared to share appreciation of a specific peer group or peer group index over a three-year period. The PSUs vest at the end of the three-year performance period, with the final number of shares to be 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 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.

The Company granted 1,772,066 PSUs under the 2009 Plan to its executive officers and certain employees as part of their overall compensation package during the nine months ended September 30, 2021. The performance period will be measured between May 1, 2021 and April 30, 2024. These PSU awards were valued at a weighted average fair value of $8.25 per unit. There were 16,334 forfeitures of PSUs during the nine months ended September 30, 2021. The Company recognized approximately $5.9 million in stock compensation expense related to previously granted PSUs during the nine months ended September 30, 2021. As of September 30, 2021, the number of unvested PSU grants outstanding was 4,718,977, assuming settlement at the target threshold of 100%, with an additional $20.4 million of future compensation expense related to PSUs remaining to be recognized over the weighted average vesting period of 2.2 years.

The Company granted 2,846,140 PSUs to its executive officers and certain employees as part of their overall compensation package during the nine months ended September 30, 2020. The performance period will be measured between May 1, 2020 and April 30, 2023. These PSU awards were valued at a weighted average fair value of $4.90 per unit. NaN PSUs were forfeited during the nine months ended September 30, 2020. The Company recognized approximately $1.6 million in stock compensation expense related to previously granted PSUs during the nine months ended September 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 November 10, 2021, the number of unvested PSU grants was 4,718,977, assuming settlement at the target threshold of 100%. The maximum payout on these PSUs is 300% of target, or 14,156,931 shares of common stock.

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 nine months ended September 30, 2021 and 2020, there was 0 excess tax benefit recognized.

Compensation expense related to stock option grants 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. NaN stock options were granted or exercised during the nine months ended September 30, 2021 or 2020.

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During the nine months ended September 30, 2021, 0 stock options were forfeited by former employees, and 19,268 stock options expired. During the nine months ended September 30, 2020, 0 stock options were forfeited by former employees, and 869 stock options expired. As of September 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 0.4 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. As of November 10, 2021, there were 579 stock options vested and exercisable with price ranges between $35.00 and $38.98 per share.

7. Leases

During the nine months ended September 30, 2021, the Company acquired several contracts in the Mid-Con Acquisition and the Silvertip Acquisition related to compressors, vehicle leases and office space with terms of twelve months or more, which qualify as operating or finance leases. The number of contracts the Company acquired in the Wind River Basin Acquisition which qualified as operating or finance leases were minimal, as most contracts were month-to-month or less than twelve months. The Company also entered into new contracts related to office space, IT equipment and compressors during the nine months ended September 30, 2021. As of September 30, 2021, the Company’s operating leases included compressors and office space, and the Company’s finance leases 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 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 September 30, 2021 and December 31, 2020 (in thousands):


	September 30, 2021		December 31, 2020
Operating lease right of use asset ⁽¹⁾	$	2,853	$	2,452

Operating lease liability - current⁽²⁾	$	(2,041)	$	(1,832)
Operating lease liability - long-term⁽³⁾		(775)		(522)
Total operating lease liability	$	(2,816)	$	(2,354)

Financing lease right of use asset⁽¹⁾	$	4,284	$	2,996

Financing lease liability - current⁽²⁾	$	(1,480)	$	(940)
Financing lease liability - long-term⁽³⁾		(2,898)		(2,102)
Total financing lease liability	$	(4,378)	$	(3,042)

(1)

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

(2)

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

(3)

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

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.

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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 September 30, 2021 and December 31, 2020:


	September 30, 2021	December 31, 2020
Weighted Average Remaining Lease Terms (in years):
Operating leases	1.55	1.47
Financing leases	3.22	3.24

Weighted Average Discount Rate:
Operating leases	6.02%	5.72%
Financing leases	5.82%	5.92%

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


	September 30, 2021
	Operating Leases		Financing Leases
2021 (remaining after September 30, 2021)	$	2,147	$	1,641
2022		547		1,509
2023		182		1,184
2024		45		447
2025		18		17
2026		29		-
Total future minimum lease payments		2,968		4,798
Less: imputed interest		(152)		(420)
Present value of lease liabilities	$	2,816	$	4,378

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


	Three Months Ended September 30, 2021		Three Months Ended September 30, 2020
Operating lease cost ^{(1) (2)}	$	775	$	843
Financing lease cost - amortization of right-of-use assets		350		197
Financing lease cost - interest on lease liabilities		62		39
Administrative lease cost⁽³⁾		5		19
Short-term lease cost ^{(1) (4)}		341		562
Total lease cost	$	1,533	$	1,660

(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 generators and compressor agreements with lease terms of more than one month and less than one year.

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


	Nine Months Ended September 30, 2021		Nine Months Ended September 30, 2020
Operating lease cost ^{(1) (2)}	$	2,674	$	2,212
Financing lease cost - amortization of right-of-use assets		927		450
Financing lease cost - interest on lease liabilities		173		88
Administrative lease cost⁽³⁾		41		56
Short-term lease cost ^{(1) (4)}		1,132		1,614
Total lease cost	$	4,947	$	4,420

(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 generators and compressor agreements with lease terms of more than one month and less than one year.

During the nine months ended September 30, 2021, there were $2.7 million and $1.2 million in cash payments related to the Company’s operating leases and financing leases, respectively. During the nine months ended September 30, 2020, there were $2.4 million and $0.6 million in cash payments related to the Company’s operating leases and financing leases, respectively.

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8. Other Financial Information

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


	September 30, 2021		December 31, 2020
Accounts receivable:
Trade receivables ⁽¹⁾	$	73,719	$	20,306
Receivable for Alta Resources distribution		1,712		1,712
Joint interest billings ⁽¹⁾		27,868		15,637
Income taxes receivable		—		268
Other receivables		242		2,209
Allowance for doubtful accounts		(2,270)		(2,270)
Total accounts receivable	$	101,271	$	37,862

Prepaid expenses:
Prepaid insurance	$	4,859	$	2,825
Other ⁽²⁾		1,942		535
Total prepaid expenses	$	6,801	$	3,360

Accounts payable and accrued liabilities ⁽¹⁾:
Royalties and revenue payable	$	44,858	$	23,701
Legal suspense related to revenues ⁽³⁾		30,760		27,983
Advances from partners⁽⁴⁾		7,290		76
Accrued exploration and development⁽⁴⁾		17,739		490
Trade payables		41,150		14,273
Accrued general and administrative expenses ⁽⁵⁾		10,700		6,191
Accrued operating expenses		12,520		5,755
Accrued operating and finance leases		3,521		2,772
Other accounts payable and accrued liabilities		5,070		2,729
Total accounts payable and accrued liabilities	$	173,608	$	83,970

(1)	Increase in 2021 primarily due to the Mid-Con Acquisition, the Silvertip Acquisition and the Wind River Basin Acquisition.

(2)	Other prepaids primarily includes software licenses and the implementation costs related to a cloud computing arrangement for the Company’s accounting system.

(3)	Suspended revenues primarily relate to amounts for which there is some question as to valid ownership, unknown addresses of payees or some other payment dispute.

(4)	Increase primarily related to the Company’s resumed drilling program in the second quarter of 2021 in the NE Bullseye area in the Permian region.

(5)	The September 30, 2021 balance includes an accrual of $2.8 million for a legal judgment that was paid in October 2021. See Note 12 – “Commitments and Contingencies” for more information.

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


		Nine Months Ended September 30,
		2021		2020
Cash payments:
Interest payments	$	2,767	$	2,991
Income tax payments	$	1,332	$	233
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$	17,249	$	(7,113)

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.

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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 September 30, 2021 was approximately $4.9 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 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 nine months ended September 30, 2021 was a loss of $1.1 million, net of 0 tax expense and a loss of $1.9 million, net of 0 tax expense, respectively. The Company’s share in Exaro’s results of operations recognized for the three and nine months ended September 30, 2020 was a loss of $0.1 million, net of 0 tax expense, and a loss of $13 thousand, net of 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 matures on 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 October 30, 2020, the Company entered into the Third Amendment to the Credit Agreement, 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 Third Amendment provided for, among other things, (i) a 25 basis point increase in the applicable margin at each level of the borrowing base utilization-based pricing grid, (ii) an increase of the borrowing base from $75.0 million to $130.0 million on the effective date of the Third Amendment, with a $10.0 million automatic stepdown in the borrowing base on March 31, 2021, (iii) certain modifications to the Company’s minimum hedging covenant including requiring hedging for at least 75% of the Company’s projected PDP volumes for 24 full calendar months on or prior to 30 days after the effective date of the Third Amendment and on April 1 and October 1 of each calendar year and (iv) the addition of three new banks to the lender group. The Company’s borrowing base was decreased to $120.0 million on March 31, 2021, per the Third Amendment. On January 21, 2021, the Company entered into the Fourth Amendment to the Credit Agreement, which was related to the transfer of a letter of credit for Mid-Con. 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, 2021. The Fifth Amendment also provided for, among other things, (i) the reinstatement of the minimum current ratio covenant calculation of 1.0:1.0 beginning as of June 30, 2021, (ii) a decrease in the 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 the Company’s projected PDP volumes for 12 full calendar months from the date of 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 nature.

In light of the Pending Independence Merger, on October 28, 2021, the Company, JPMorgan Chase Bank, N.A (the “Administrative Agent”) and the lenders under the Credit Agreement entered into a waiver letter which, among other things, (i) waives the Company’s obligation under its Credit Agreement to deliver the reserve report otherwise due in October 2021 and (ii) postpones the November 2021 scheduled redetermination of the Company’s borrowing base until on or about February 1, 2022, subject to the Company providing the Administrative Agent by December 31, 2021 with a reserve report evaluating the Company’s proved reserves as of December 1, 2021.

As of September 30, 2021, under the Credit Agreement, the Company had $118.0 million borrowings outstanding, $2.9 million in outstanding letters of credit and borrowing availability of approximately $129.1 million. As of December 31, 2020, the Company had approximately $9.0 million outstanding under the Credit Agreement, $1.9 million in an outstanding letter of credit and borrowing availability of approximately $64.1 million.

The Company initially incurred $1.8 million of arrangement and upfront fees in connection with the Credit Agreement. The Company has incurred an additional $4.2 million in fees for amendments to the Credit Agreement, of which $2.5 million in fees were incurred in 2021 in relation to the Third Amendment and Fifth Amendment. These fees are to be amortized over the remaining term of the Credit Agreement. During the nine months ended September 30, 2021,

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the Company amortized debt issuance costs of $0.7 million related to the Credit Agreement. As of September 30, 2021, the remaining amortizable balance of these fees was $3.6 million and will be amortized through September 17, 2024.

Total interest expense under the Company’s Credit Agreement, including commitment fees, was approximately $1.2 million and $3.2 million for the three and nine months ended September 30, 2021, respectively. Total interest expense under the Company’s Credit Agreement, including commitment fees, was approximately $1.1 million and $4.4 million, for the three and nine months ended September 30, 2020, respectively. Included in the 2020 interest expense is $1.0 million in debt issuance costs which originally were to be amortized over the life of the loan, but were immediately expensed due to a reduction in the borrowing base under the Second Amendment.

The weighted average interest rates in effect at September 30, 2021 and December 31, 2020 were 3.5% and 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 Fifth Amendment requires a Current Ratio of greater than or equal to 1.0:1.0 and a Leverage Ratio of less than or equal to 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 September 30, 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 administered by the U.S. Small Business Administration. The PPP Loan to the Company was made through JPMorgan Chase Bank, N.A and is included in “Long-term debt” on the Company’s consolidated balance sheet as of December 31, 2020.

The PPP Loan 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), commenced after the six-month anniversary of the funding date. The promissory note evidencing the PPP Loan provided for customary events of default, including, among others, those relating to failure to make payment, bankruptcy, breaches of representations and material adverse effects.

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 utilized the PPP Loan amount for qualifying expenses during the 24-week coverage period, and on July 12, 2021, submitted its updated application for forgiveness of the total amount outstanding under the PPP Loan in accordance with the updated application terms of the CARES Act and related guidance. On August 6, 2021, the Company received notice from the Small Business Administration that the PPP loan was forgiven in its entirety. For the three and nine months ended September 30, 2021, the Company recorded other income of $3.4 million for the PPP loan forgiveness within “Gain on extinguishment of debt” on its consolidated statements of operations.

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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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Current tax provision (benefit)
Federal	$	(1,384)	$	—	$	(1,638)	$	274
State		318		369		927		481
Total	$	(1,066)	$	369	$	(711)	$	755
Deferred tax provision:
Federal	$	—	$	—	$	—	$	—
State		—		299		—		676
Total	$	—	$	299	$	—	$	676
Total tax provision (benefit)
Federal	$	(1,384)	$	—	$	(1,638)	$	274
State		318		668		927		1,157
Total income tax provision (benefit):	$	(1,066)	$	668	$	(711)	$	1,431

State income tax expense relates to income taxes for the quarter 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. The Federal income tax benefit for the nine months ended September 30, 2021 results from applying the estimated annual effective tax rate to the year-to-date pre-tax loss, less amounts recorded in the first and second quarters of 2021, plus a small true-up of a previously recorded alternative minimum tax 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.

As of September 30, 2021, the Company had federal net operating loss (“NOL”) carryforwards of approximately $404.7 million and state NOL carryforwards of $26.4 million. The Federal NOL carryforwards 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 2020, due to lower commodity prices 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. As a result of the Ownership Changes, the Company has recorded a valuation allowance against substantially all of its NOLs and other deferred tax assets. The Company determined that no Section 382 Ownership Change from share activity occurred in the nine months ended September 30, 2021. The valuation allowance balances at September 30, 2021 for federal and state purposes are approximately $150.6 million and approximately $3.1 million, respectively.

The Consolidated Appropriations Act of 2021 was signed into law on December 27, 2020 to provide a response by the Federal government to the pandemic and 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 nine months ended September 30, 2021, the Company is claiming a 100% benefit for qualifying meal expenses.

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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 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 judgment plus fees and interest. The Company filed an appeal with the appellate court for a review of the initial trial court’s decision. On January 23, 2021, the appellate court notified both parties that it would begin reviewing the merits of the case beginning on February 23, 2021. On March 3, 2021, the appellate court affirmed the trial court’s decision. The Company filed a petition with the Texas Supreme Court requesting a review of the appellate court’s decision, and on September 24, 2021, the Texas Supreme Court notified both parties that it would not be reviewing the case. As a result, during the three months ended September 30, 2021, the Company recorded an additional $0.7 million liability for the final judgment plus interest. The total judgment, interest and fees of $3.9 million were paid in October 2021.

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

13. Subsequent Events

On November 3, 2021, the Company filed and mailed its definitive proxy statement for the Special Meeting of the Stockholders of the Company in connection with the Pending Independence Merger. The Special Meeting of the Stockholders to vote on the approval of the Pending Independence Merger has been scheduled for December 6, 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 and with our 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 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, in our 2020 Form 10-K, Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 and those factors summarized below:

●

volatility 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;

●

risks related to the Pending Independence Merger, including the risk that the Pending Independence Merger will not be completed on the timeline or terms currently contemplated or at all, the length of time necessary to close the Pending Independence Merger, the ability to obtain the requisite Contango stockholder approvals, 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 attention will be diverted;

●

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

●

risks related to the Wind River Basin Acquisition, including the risk that 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;

●

the impact of the climate change initiative by President Biden’s administration and Congress, including 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 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; the Biden administration efforts to put the United State on a path to 100% carbon-free electricity by 2035; and the Biden administration’s coordination of a U.S. and European pledge to cut methane emissions.

●

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 2021 capital expenditure budget;

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

●

the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations, including Russia, 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 Permian Basin and Midcontinent region, and realize the benefits associated therewith;

●

increased costs and risks associated with our exploration and development in the Gulf of 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 Permian Basin, including lower than expected production attributable to down spacing of wells;

●

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 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, 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 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

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

Any of these factors and other factors described in this report could cause our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. Although we believe our estimates and assumptions to be reasonable when made, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. Our assumptions about future events may prove to be inaccurate. 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, our 2020 Form 10-K, or Quarterly Report on Form 10-Q for the quarter ended June 30, 2021. 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.

Overview

We are a Fort Worth, Texas based, independent oil and natural gas 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 and 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 September 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, Frontier, Fort Union, Lance, Mesa Verde, Codey, 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 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, OPEC and Russia 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, further suspended all drilling in the second quarter of 2020, and then focused on certain measures that included, but have not been limited to, the following:

●

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

●

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.

Drilling Program

From our initial entry into the Southern Delaware Basin in 2016 and through early 2019, we were focused on the development of our Southern Delaware Basin acreage in Pecos County, Texas. 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 drilling in this area in the first quarter of 2020 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 a conservative one-rig 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 other operators adjacent to our position, we decided to drill one of the three wells in this first pad to the Second Bone Spring formation, which is our first well drilled to that formation. 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. The first two wells, both drilled to the Wolfcamp A formation, were drilled to an average total measured depth of 20,440 feet with an average lateral length of 9,700 feet and 48 stages of fracture stimulation. The third well, drilled to the Second Bone Spring formation, was drilled to a total measured depth of 19,090 feet with a lateral length of 9,574 feet and 47 stages of fracture stimulation. These three wells were brought online in mid-October and are still being evaluated at this time. We plan to begin completion operations on the second three wells in late November, with first production expected in January 2022. As of September 30, 2021, we were producing from eighteen wells over our approximate 16,200 gross operated (7,500 company net) acre position in our Permian region, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

Acquisitions

On January 21, 2021, we closed on the acquisition of Mid-Con Energy Partners, LP (“Mid-Con”), in an all-stock merger transaction in which Mid-Con became a direct, wholly owned subsidiary of Contango (the “Mid-Con Acquisition”). A total of 25,552,933 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 $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 certain oil and natural gas properties located in the Big Horn Basin in Wyoming and Montana, in the Powder River Basin in Wyoming and in the Permian Basin in West Texas and New Mexico (collectively the “Silvertip Acquisition”) for aggregate consideration of approximately $58.0 million. After customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date, the net consideration paid was approximately $53.3 million. See Item 1. Note 3 – “Acquisitions and Dispositions” for more information.

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 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 remains subject to the approval of our stockholders at the Special Meeting of the Stockholders to be held on December 6, 2021, and is expected to be completed in December 2021. The Pending Independence Merger agreement includes certain restrictions on the conduct of the business of the Company until the closing, such as a requirement to operate in the ordinary course of business and limitations on, among other things, our ability to make acquisitions, declare or pay dividends, issue or sell equity or incur debt. Upon completion of the Pending Independence Merger, existing Independence shareholders are expected to own approximately 76% and existing Contango shareholders are expected to own approximately 24% of the combined company. See Item 1. Note 3 – “Acquisitions and Dispositions” and Item 1. Note 13 – “Subsequent Events” for further details.

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On August 31, 2021, we closed on the acquisition of low decline, conventional gas assets in the Wind River Basin of Wyoming (the “Wind River Basin Acquisition”). Upon closing, we acquired approximately 446 Bcfe of PDP reserves (unaudited) for a total purchase price of $67.0 million in cash. After customary closing adjustments, including the results of operations during the period between the effective date of June 1, 2021 and the closing date, the net consideration paid was approximately $62.6 million, subject to customary purchase price adjustments. See Item 1. Note 3 – “Acquisitions and Dispositions” for further details.

Other

On April 28, 2021, the Board of Directors of the Company (the “Board”) increased the size of the Board from five to seven directors and appointed Karen Simon and Janet Pasque to fill the vacancies created by the expansion of the Board, effective on April 28, 2021. Concurrent with their election as directors of the Company, Ms. Pasque was 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 independent directors under the applicable rules and 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.”

On May 3, 2021, we entered into the Fifth Amendment to the Credit Agreement (the “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, expanded the bank group from nine to eleven banks and reinstated the Current Ratio and Leverage Ratio requirements beginning as of June 30, 2021. The Fifth Amendment also includes less restrictive hedge requirements and certain modifications to financial covenants. See Item 1. Note 10 – “Long-Term Debt” for further information regarding the Fifth Amendment.

On August 6, 2021, we received notice from the Small Business Administration that our loan received from the Paycheck Protection Program in 2020 for approximately $3.4 million was forgiven in its entirety. See Item 1. Note 10 – “Long-Term Debt” for further information.

In light of the Pending Independence Merger, on October 28, 2021, we entered into a waiver letter with the lenders of the Credit Agreement which, among other things, postpones the November 2021 scheduled redetermination of the Company’s borrowing base until on or about February 1, 2022. See Item 1. Note 10 – “Long-Term Debt” and Item 1. Note 13 – “Subsequent Events” for further details.

Capital Expenditures

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 West Texas Permian (3 net locations, 6 gross locations), among other things. This forecast does not account for the Pending Independence Merger. The planned capital expenditures also include development opportunities with respect to certain properties we acquired as part of the Mid-Con Acquisition and the Silvertip Acquisition. The capital expenditure program will continue to be evaluated for revision for the remainder of the year.

During the nine months ended September 30, 2021, we incurred capital expenditures of approximately $25.9 million, of which $13.2 million related to the drilling and completion of the Southern Delaware Basin wells. We also incurred approximately $10.2 million in expenditures primarily related to redevelopment activities of recently acquired properties in our Midcontinent, Permian and Rockies regions and $2.3 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 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.

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For the remainder of 2021, we intend to continue to make balance sheet strength a priority. 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 recently acquired assets, reducing general and administrative expenses, improving cash margins and lowering our exposure to asset retirement obligations through the possible sale of non-core properties.

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 field basis to the unamortized capitalized cost of the 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 nine months ended September 30, 2021. We recorded a $0.2 million non-cash charge for unproved impairment expense during the nine months ended September 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 OPEC and Russia to reach an agreement on lower production quotas until April 2020, caused a dramatic increase in the supply of oil and a corresponding decrease in commodity prices, and lowered the demand for all commodity products. Consequently, during the nine months ended September 30, 2020, we 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 then forecasted development plans for our proved, undeveloped locations. We recorded a $2.6 million non-cash charge for unproved impairment expense during the nine months ended September 30, 2020 related to expiring leases in our Midcontinent region.

Summary Production Information

Our production sales for the three months ended September 30, 2021, were comprised of 35% oil, 48% natural gas, and 17% natural gas liquids, in comparison to our production sales for the three months ended September 30, 2020, of approximately 28% oil, 52% natural gas and 20% natural gas liquids. Our production sales for the nine months ended September 30, 2021, were comprised of 37% oil, 45% natural gas, and 18% natural gas liquids, in comparison to our production sales for the nine months ended September 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/d for each of our regions for each of the periods indicated:


	Three Months Ended
	September 30,	December 31,	March 31,	June 30,	September 30,
	2020	2020	2021 ⁽³⁾	2021 ⁽⁴⁾	2021 ⁽⁵⁾
Midcontinent⁽¹⁾	12.6	9.6	11.1	12.2	12.4
Permian	0.7	1.4	2.6	4.8	4.3
Rockies	0.1	—	2.6	4.4	7.2
Other ⁽²⁾	3.8	3.4	3.4	2.7	2.5
Total daily production sales volumes	17.2	14.4	19.7	24.1	26.4

(1)

Production sales during the three months ended September 30, 2020 included approximately 50,000 Bbls (0.5 MBoe/d) of second quarter 2020 oil production (net to the Company), which was held as inventory and later sold in the third quarter of 2020 at higher prices. The decrease in production sales during the three months ended December 31, 2020 was primarily due to downtime related to workovers and routine repair and maintenance. The increase in production sales in 2021 was due to the properties acquired as part of the Mid-Con Acquisition.

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

(3)

The increase in production sales during the three months ended March 31, 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. The Silvertip Acquisition reflects production sales beginning February 1, 2021, impacting the 2021 first quarter production for the Permian and

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Rockies regions by 1.9 MBoe/d and 2.1 MBoe/d, respectively

(4)

The Mid-Con Acquisition impacted 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 impacted the 2021 second quarter production for the Permian and Rockies regions by 3.9 MBoe/d and 3.7 MBoe/d, respectively.

(5)

The Mid-Con Acquisition impacted the 2021 third quarter production for the Midcontinent and Rockies regions by 2.5 MBoe/d and 0.7 MBoe/d, respectively. The Silvertip Acquisition impacted the 2021 third quarter production for the Permian and Rockies regions by 3.6 MBoe/d and 2.2 MBoe/d, respectively. The 2021 third quarter production in the Rockies region also includes 4.3 MBoe/d of production sales from the Wind River Basin Acquisition beginning September 1, 2021.

Other Investments

Jonah Field - Sublette County, Wyoming

Our wholly owned subsidiary, Contaro Company, owns a 37% ownership interest in Exaro Energy III LLC (“Exaro”). As of September 30, 2021, Exaro had 650 producing wells 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 2.3 MBoe/d, net to Exaro, during the three months ended September 30, 2021 and 2.4 MBoe/d, net to Exaro, during the nine months ended September 30, 2021. We recognized an investment loss of approximately $1.1 million, net of no tax expense, and an investment loss of approximately $1.9 million, net of no tax expense, attributable to our equity investment in Exaro for the three and nine months ended September 30, 2021, respectively. We recognized an investment loss of approximately $0.1 million, net of no tax expense, and an investment loss of $13 thousand, net of no tax expense, attributable to our equity investment in Exaro for the three and nine months ended September 30, 2020, respectively. See Item 1. Note 9 – “Investment in Exaro Energy III LLC” for additional details related to this equity investment.

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Results of Operations for the Three and Nine Months Ended September 30, 2021 and 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”) from operations for the three and nine months ended September 30, 2021 and 2020. The 2021 results include the properties acquired in the Mid-Con Acquisition, the Silvertip Acquisition and the Wind River Basin Acquisition that closed on January 21, 2021, February 1, 2021 and August 31, 2021, respectively. 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 September 30,						Nine Months Ended September 30,
	2021		2020		% Change		2021		2020		% Change

Revenues (thousands):
Oil and condensate sales	$	56,044	$	17,415	222	%	$	149,246	$	48,127	210	%
Natural gas sales		26,241		7,930	231	%		55,556		22,718	145	%
NGL sales		15,175		5,003	203	%		35,735		11,918	200	%
Other operating revenues		2,467		1,000	147	%		2,980		1,000	198	%
Total revenues	$	99,927	$	31,348	219	%	$	243,517	$	83,763	191	%

Production Sales Volumes:
Oil and condensate (thousand barrels)
Midcontinent		432		345	25	%		1,212		943	29	%
Permian		154		45	242	%		445		203	119	%
Rockies		214		6	*	%		613		16	*	%
Other		32		47	(32)	%		103		147	(30)	%
Total oil and condensate		832		443	88	%		2,373		1,309	81	%
Natural gas (million cubic feet)
Midcontinent		2,731		3,320	(18)	%		7,978		10,415	(23)	%
Permian		805		42	*	%		2,097		123	*	%
Rockies		2,581		—	100	%		3,689		—	100	%
Other		939		1,591	(41)	%		3,317		4,530	(27)	%
Total natural gas		7,056		4,953	42	%		17,081		15,068	13	%
Natural gas liquids (thousand barrels)
Midcontinent		256		269	(5)	%		713		793	(10)	%
Permian		107		9	*	%		270		24	*	%
Rockies		18		—	100	%		63		—	100	%
Other		37		40	(8)	%		129		139	(7)	%
Total natural gas liquids		418		318	31	%		1,175		956	23	%
Total (thousand barrels of oil equivalent)
Midcontinent		1,142		1,167	(2)	%		3,255		3,471	(6)	%
Permian		395		61	548	%		1,065		248	329	%
Rockies		662		6	*	%		1,290		16	*	%
Other		227		353	(36)	%		785		1,041	(25)	%
Total production sales volumes		2,426		1,587	53	%		6,395		4,776	34	%

Daily Production Sales Volumes:
Oil and condensate (thousand barrels per day)
Midcontinent		4.7		3.8	24	%		4.4		3.4	29	%
Permian		1.7		0.5	240	%		1.6		0.7	129	%
Rockies		2.3		0.1	*	%		2.2		0.1	*	%
Other		0.3		0.4	(25)	%		0.5		0.6	(17)	%
Total oil and condensate		9.0		4.8	88	%		8.7		4.8	81	%

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2021		2020		% Change		2021		2020		% Change

Natural gas (million cubic feet per day)
Midcontinent		29.7		36.1	(18)	%		29.2		38.0	(23)	%
Permian		8.8		0.5	*	%		7.7		0.4	*	%
Rockies		28.1		—	100	%		13.5		—	100	%
Other		10.1		17.2	(41)	%		12.2		16.6	(27)	%
Total natural gas		76.7		53.8	43	%		62.6		55.0	14	%
Natural gas liquids (thousand barrels per day)
Midcontinent		2.8		2.9	(3)	%		2.6		2.9	(10)	%
Permian		1.2		0.1	*	%		1.0		0.1	900	%
Rockies		0.2		—	100	%		0.2		—	100	%
Other		0.3		0.5	(40)	%		0.5		0.5	—	%
Total natural gas liquids		4.5		3.5	29	%		4.3		3.5	23	%
Total (thousand barrels of oil equivalent per day)
Midcontinent		12.4		12.6	(2)	%		11.9		12.7	(6)	%
Permian		4.3		0.7	514	%		3.9		0.9	333	%
Rockies		7.2		0.1	*	%		4.7		0.1	*	%
Other		2.5		3.8	(34)	%		2.9		3.7	(22)	%
Total daily production sales volumes		26.4		17.2	53	%		23.4		17.4	34	%

Average Sales Price:
Oil and condensate (per barrel)	$	67.39	$	39.30	71	%	$	62.89	$	36.76	71	%
Natural gas (per thousand cubic feet)	$	3.72	$	1.60	133	%	$	3.25	$	1.51	115	%
Natural gas liquids (per barrel)	$	36.30	$	15.73	131	%	$	30.42	$	12.47	144	%
Total (per barrels of oil equivalent)	$	40.18	$	19.13	110	%	$	37.62	$	17.33	117	%

Expenses (thousands):
Operating expenses	$	44,916	$	14,586	208	%	$	108,901	$	48,859	123	%
Exploration expenses	$	174	$	(227)	(177)	%	$	458	$	11,344	(96)	%
Depreciation, depletion and amortization	$	9,792	$	6,185	58	%	$	30,391	$	24,131	26	%
Impairment and abandonment of oil and natural gas properties	$	258	$	47	449	%	$	712	$	145,925	(100)	%
General and administrative expenses	$	14,599	$	8,699	68	%	$	39,441	$	24,186	63	%
Loss from investment in affiliates (net of taxes)	$	(1,093)	$	(126)	767	%	$	(1,897)	$	(13)	*	%

Selected data per Boe:
Operating expenses	$	18.50	$	9.20	101	%	$	17.03	$	10.24	66	%
General and administrative expenses	$	6.02	$	5.48	10	%	$	6.17	$	5.06	22	%
Depreciation, depletion and amortization	$	4.03	$	3.90	3	%	$	4.75	$	5.05	(6)	%

*Greater than 1,000%

Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020

Oil, Natural Gas and NGL Sales and Production

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improvement since the first quarter of 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 $99.9 million for the three months ended September 30, 2021, compared to revenues of $31.3 million for the three months ended September 30, 2020. The current year quarter increase is attributable to the increases in commodity prices in 2021, the additional production sales from the properties acquired in the Mid-Con Acquisition, the Silvertip Acquisition and the Wind River Basin 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 acquired properties in the third quarter of 2021 were as follows: $19.1 million attributable to the Mid-Con Acquisition, $23.7 million attributable to the Silvertip Acquisition and $9.1 million attributable to the Wind River Basin Acquisition (which only includes one month of production sales, as the Wind River Basin Acquisition closed on August 31, 2021).

Total production sales for the three months ended September 30, 2021 were approximately 2.4 MMBoe (52% liquids), or 26.4 MBoe/d, compared to approximately 1.6 MMBoe (48% liquids), or 17.2 MBoe/d in the prior year quarter. The increase in the third quarter 2021 production sales is attributable to the production from the acquired properties as follows: 3.2 MBoe/d attributable to the Mid-Con Acquisition, 5.8 MBoe/d attributable to the Silvertip Acquisition and 4.3 MBoe/d attributable to the Wind River Basin Acquisition (which only includes one month of production sales, as the Wind River Basin acquisition closed on August 31, 2021), with the overall increase in production sales partially offset by 2021 property sales. Net oil production sales were approximately 9,000 barrels per day for the three months ended September 30, 2021, compared to approximately 4,800 barrels per day in the prior year quarter. The production sales in the prior year quarter also included approximately 500 barrels per day of second quarter 2020 oil production (net to the Company), which was held as inventory and later sold in the third quarter of 2020 at higher prices. Net natural gas production sales increased to approximately 76.7 MMcf per day during the three months ended September 30, 2021, compared with approximately 53.8 MMcf per day during the three months ended September 30, 2020. Net NGL production sales were approximately 4,500 barrels per day during the three months ended September 30, 2021, compared to approximately 3,500 barrels per day in the prior year quarter.

Average Sales Prices

The average equivalent sales price realized for the three months ended September 30, 2021 was $40.18 per Boe compared to $19.13 per Boe for the three months ended September 30, 2020. The increase in the third quarter 2021 realized prices is primarily attributable to an improvement in the economy and higher realized commodity prices in 2021 brought about by domestic vaccination programs that have helped reduce the spread of COVID-19. The lower prior year prices were attributable to 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 realized price of oil averaged $67.39 per Bbl in the third quarter of 2021 compared to an average of $39.30 per Bbl in the prior year quarter. The realized price of natural gas averaged $3.72 per Mcf in the third quarter of 2021 compared to an average of $1.60 per Mcf in the prior year quarter, and the realized price of NGLs averaged $36.30 per Bbl in the third quarter of 2021 compared to an average of $15.73 per Bbl in the prior 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 $2.5 million of other operating revenues during the three months ended September 30, 2021 related to sulfur revenues from the properties we acquired in the Wind River Basin Acquisition and plant and pipeline revenues from the properties we acquired in the Mid-Con Acquisition. We reported $1.0 million of other operating revenues during the three months ended September 30, 2020 related to a fee for service agreement we had with Mid-Con prior to the Mid-Con Acquisition.

Operating Expenses

Total operating expenses for the three months ended September 30, 2021 were approximately $44.9 million, or $18.50 per Boe, compared to $14.6 million, or $9.20 per Boe, for the three months ended September 30, 2020.

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The table below provides additional detail of total operating expenses for the comparative three month periods:


	Three Months Ended September 30,
	2021			2020
	(in thousands)		(per Boe)	(in thousands)		(per Boe)
Lease operating expenses	$	24,266	$ 10.00	$	6,105	$ 3.85
Production & ad valorem taxes		6,928	2.86		1,533	0.97
Transportation & processing costs		9,438	3.89		5,670	3.57
Workover costs		3,528	1.45		1,278	0.81
Other operating expenses		756	0.30		—	—
Total operating expenses	$	44,916	$ 18.50	$	14,586	$ 9.20

Lease operating expenses (“LOE”) were $24.3 million and $6.1 million for the three months ended September 30, 2021 and September 30, 2020, respectively. The increase in the third quarter 2021 LOE was primarily related to the acquired properties, and the expenses were as follows: $6.7 million, or $22.76 per Boe, attributable to the Mid-Con Acquisition, $6.9 million, or $13.12 per Boe, attributable to the Silvertip Acquisition and $3.0 million, or $7.50 per Boe, attributable to the Wind River Basin Acquisition (which only includes one month of LOE, as the Wind River Basin Acquisition closed on August 31, 2021).

Production and ad valorem taxes were $6.9 million and $1.5 million for the three months ended September 30, 2021 and September 30, 2020, respectively. The increase in the third quarter 2021 production and ad valorem taxes was primarily attributable to the acquired properties, and the expenses were as follows: $1.6 million, or $5.48 per Boe, attributable to the Mid-Con Acquisition, $2.5 million, or $4.73 per Boe, attributable to the Silvertip Acquisition and $0.4 million, or $1.00 per Boe, attributable to the Wind River Basin Acquisition (which only includes one month of production sales, as the Wind River Basin Acquisition closed on August 31, 2021).

Transportation and processing costs were approximately $9.4 million compared to $5.7 million for the three months ended September 30, 2021 and 2020, respectively. The three months ended September 30, 2021 expense includes $3.4 million, or $6.43 per Boe, in transportation and processing costs related to the properties acquired in the Silvertip Acquisition, which is the primary reason for the increase in expense and rate per Boe in the current year quarter compared to the prior year quarter.

Workover expenses were approximately $3.5 million compared to $1.3 million for the three months ended September 30, 2021 and 2020, respectively. The increase in the current year quarter workover expense was a result of higher commodity prices in 2021 and includes $0.6 million related to the properties acquired in the Mid-Con Acquisition and $0.8 million related to the properties acquired in the Silvertip Acquisition.

We reported $0.8 million of other operating expenses during the three months ended September 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.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense for the three months ended September 30, 2021 was approximately $9.8 million, or $4.03 per Boe. This compares to approximately $6.2 million, or $3.90 per Boe, for the three months ended September 30, 2020. The higher depletion expense and rate per Boe for the three months ended September 30, 2021 is attributable to the properties from the Mid-Con Acquisition and the Silvertip Acquisition. The third quarter 2021 expense related to the acquired properties was approximately $2.0 million, or $6.71 per Boe, for those acquired in the Mid-Con Acquisition, approximately $2.5 million, or $4.72 per Boe, for those acquired in the Silvertip Acquisition, and $0.8 million, or $2.13 per Boe, attributable to the Wind River Basin Acquisition (which only includes one month of expense, as the Wind River Basin Acquisition closed on August 31, 2021).

Impairment and Abandonment Expenses

We did not record any impairment expense related to proved or unproved properties during the three months ended September 30, 2021 and 2020.

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General and Administrative Expenses

Total general and administrative expenses for the three months ended September 30, 2021 were approximately $14.6 million, compared to $8.7 million for the three months ended September 30, 2020. The increase in the current year quarter expense is primarily attributable to $2.7 million in non-recurring fees related to the Pending Independence Merger and $1.4 million in higher stock-based compensation due to an increase in the number of annual equity grants awarded to all employees in 2021.

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


	Three Months Ended September 30,
	2021		2020

	(in thousands)
Wages and employee benefits ⁽¹⁾	$	4,352	$	3,499
Non-cash stock-based compensation ⁽²⁾		3,201		1,764
Professional fees⁽³⁾		1,859		1,857
Professional fees - special ⁽⁴⁾		2,914		326
Recouped overhead ⁽⁵⁾		(1,938)		(1,075)
Office costs⁽⁶⁾		1,796		1,267
Legal judgements ⁽⁷⁾		708		90
Other ⁽⁸⁾		1,707		971
Total general and administrative expenses	$	14,599	$	8,699

(1)	Higher wages and employee benefits during the three months ended September 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 three months ended September 30, 2021 due to an increase in the number of equity awards granted to all employees in 2021 as part of the annual incentive bonus compensation and the related increase in expense.

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

(4)

Special professional fees are transaction-specific fees incurred in conjunction with our pursuit of strategic initiatives, including the integration of assets from our acquisitions and transaction costs associated with the evaluation and closing of acquisitions categorized as business combinations. The three months ended September 30, 2021 includes $2.7 million in fees related to the Pending Independence Merger. See Item 1. Note 3 – “Acquisitions and Dispositions” for further details.

(5)

These credits relate to overhead we recoup pursuant to joint operating agreements with working interest partners on our operated properties, and which are recorded as an offset to our other general and administrative costs. The increase in the current year credit is due to the overhead recouped on recently acquired properties.

(6)	Primarily includes office rent, office supplies and software licenses for IT applications.

(7)	The 2021 third quarter expense includes an accrual for additional interest related to a final judgment received in September 2021, which was paid in October 2021. See Item 1. Note 12 – “Commitments and Contingencies” for further details.

(8)	Includes fees related to insurance and other company expenses.

Loss from Affiliates

For the three months ended September 30, 2021, we recorded a loss from affiliates of approximately $1.1 million, net of no tax expense, attributable to our equity investment in Exaro. For the three months ended September 30, 2020, we recorded a loss from affiliates of approximately $0.1 million, net of no tax expense, attributable to our equity investment in Exaro.

Loss on Derivatives

During the three months ended September 30, 2021, we recorded a loss on derivatives of $48.4 million. Of this amount, $35.5 million was a non-cash charge to reflect the change in the mark-to-market value of our hedges as commodity prices increased during 2021, and $12.9 million were realized losses on monthly settlements on expiring contracts during the third quarter of 2021. During the three months ended September 30, 2020, we recorded a loss on derivatives of $7.4 million. Of this amount, $13.0 million were non-cash mark-to-market losses, and $5.6 million were realized gains.

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Gain on Extinguishment of Debt

During the three months ended September 30, 2021, we recorded a $3.4 million gain on extinguishment of debt related to the PPP loan forgiveness. See Item 1. Note 10 – “Long-Term Debt” for further details.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 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 have varied significantly from year to year depending on production volumes and changes in commodity prices, each of which can 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 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 $243.5 million for the nine months ended September 30, 2021, compared to revenues of $83.8 million for the nine months ended September 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, the Silvertip Acquisition and the Wind River Basin 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 acquired properties for the nine months ended September 30, 2021 were as follows: $46.2 million attributable to the Mid-Con Acquisition, $64.8 million attributable to the Silvertip Acquisition and $9.1 million attributable to the Wind River Basin Acquisition (which only includes one month of production sales, as the Wind River Basin Acquisition closed on August 31, 2021).

Total production sales for the nine months ended September 30, 2021 were approximately 6.4 MMBoe (55% liquids), or 23.4 MBoe/d, compared to approximately 4.8 MMBoe (47% liquids), or 17.4 MBoe/d in the prior year period. The increase in 2021 production sales is attributable to the production from the acquired properties as follows: 2.8 MBoe/d attributable to the Mid-Con Acquisition, 5.8 MBoe/d attributable to the Silvertip Acquisition and 1.4 MBoe/d attributable to the Wind River Basin Acquisition (which only includes one month of production sales, as the Wind River Basin Acquisition closed on August 31, 2021), with the overall increase in production sales partially offset by 2021 property sales. Net oil production sales were approximately 8,700 barrels per day for the nine months ended September 30, 2021, compared to approximately 4,800 barrels per day in the prior year period. Net natural gas production sales were approximately 62.6 MMcf per day during the nine months ended September 30, 2021, compared with approximately 55.0 MMcf per day during the nine months ended September 30, 2020. Net NGL production sales increased to approximately 4,300 barrels per day during the nine months ended September 30, 2021 compared to approximately 3,500 barrels per day in the prior year period.

Average Sales Prices

The average equivalent sales price realized for the nine months ended September 30, 2021 was $37.62 per Boe compared to $17.33 per Boe for the nine months ended September 30, 2020. The increase in the 2021 realized prices is primarily attributable to an improvement in the economy and higher realized commodity prices in 2021 brought about by domestic vaccination programs that have helped reduce the spread of COVID-19. 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 realized price of oil averaged $62.89 per Bbl in the current year period compared to an average of $36.76 per Bbl in the prior year period. The realized price of natural gas averaged $3.25 per Mcf in the current year period compared to an average of $1.51 per Mcf in the prior year period, and the realized price of NGLs averaged $30.42 per Bbl in the current year period compared to an average of $12.47 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.

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Other Operating Revenues

We reported $3.0 million of other operating revenues during the nine months ended September 30, 2021 related to sulfur revenues from the properties we acquired in the Wind River Basin Acquisition and plant and pipeline revenues from the properties we acquired in the Mid-Con Acquisition. We reported $1.0 million of other operating revenues during the nine months ended September 30, 2020 related to a fee for service agreement we had with Mid-Con prior to the Mid-Con Acquisition.

Operating Expenses

Total operating expenses for the nine months ended September 30, 2021 were approximately $108.9 million, or $17.03 per Boe, compared to $48.9 million, or $10.24 per Boe, for the nine months ended September 30, 2020.

The table below provides additional detail of total operating expenses for the comparative nine month periods:


	Nine Months Ended September 30,
	2021			2020
		(in thousands)	(per Boe)		(in thousands)	(per Boe)
Lease operating expenses	$	59,194	$ 9.26	$	25,943	$ 5.43
Production & ad valorem taxes		16,819	2.63		4,107	0.86
Transportation & processing costs		23,586	3.69		15,801	3.31
Workover costs		7,796	1.22		3,008	0.64
Other operating expenses		1,506	0.23		—	—
Total operating expenses	$	108,901	$ 17.03	$	48,859	$ 10.24

Lease operating expenses (“LOE”) were $59.2 million and $25.9 million for the nine months ended September 30, 2021 and September 30, 2020, respectively. The increase in the current year period LOE was primarily related to the acquired properties, and the expenses were as follows: $17.4 million, or $22.78 per Boe, attributable to the Mid-Con Acquisition, $17.0 million, or $10.70 per Boe, attributable to the Silvertip Acquisition and $3.0 million, or $7.50 per Boe, attributable to the Wind River Basin Acquisition (which only includes one month of LOE, as the Wind River Basin Acquisition closed on August 31, 2021).

Production and ad valorem taxes were $16.8 million and $4.1 million for the nine months ended September 30, 2021 and September 30, 2020, respectively. The increase in the current year period production and ad valorem taxes was primarily related to the acquired properties, and the expenses were as follows: $3.9 million, or $5.13 per Boe, attributable to the Mid-Con Acquisition, $6.2 million, or $3.90 per Boe, attributable to the Silvertip Acquisition and $0.4 million, or $1.00 per Boe, attributable to the Wind River Basin Acquisition (which only includes one month of production sales, as the Wind River Basin Acquisition closed on August 31, 2021).

Transportation and processing costs were approximately $23.6 million compared to $15.8 million for the nine months ended September 30, 2021 and 2020, respectively. The current year period includes $7.3 million, $4.58 per Boe, in transportation and processing costs related to the properties acquired in the Silvertip Acquisition, which is the primary reason for the increase in expense and rate per Boe in the current year period compared to the prior year period

Workover expenses were approximately $7.8 million compared to $3.0 million for the nine months ended September 30, 2021 and 2020, respectively. The increase in the current year period workover expense was a result of higher commodity prices in 2021 and includes $0.6 million related to the properties acquired in the Mid-Con Acquisition and $1.7 million related to the properties acquired in the Silvertip Acquisition.

We reported $1.5 million of other operating expenses during the nine months ended September 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.

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Exploration Expense

Exploration expense was $0.5 million for the nine months ended September 30, 2021, compared to $11.3 million in the prior year period, which included $10.4 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 nine months ended September 30, 2021 was approximately $30.4 million, or $4.75 per Boe. This compares to approximately $24.1 million, or $5.05 per Boe, for the nine months ended September 30, 2020. The higher depletion expense for the current year period was related to the acquired properties and included approximately $6.4 million, or $8.37 per Boe, for the properties acquired in the Mid-Con Acquisition, approximately $7.6 million, or $4.82 per Boe, for the properties acquired in the Silvertip Acquisition, and $0.8 million, or $2.13 per Boe, attributable to the Wind River Basin Acquisition (which only includes one month of expense, as the Wind River Basin Acquisition closed on August 31, 2021).

Impairment and Abandonment Expenses

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

During the nine months ended September 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 nine months ended September 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 nine months ended September 30, 2021 were approximately $39.4 million, compared to $24.2 million for the nine months ended September 30, 2020. The increase in the 2021 expense is primarily attributable to $5.7 million in higher stock-based compensation due to an increase in the number of annual equity grants awarded to all employees in 2021, $3.4 million in non-recurring fees related to the Mid-Con Acquisition and $3.0 million in non-recurring fees related to the Pending Independence Merger.

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


	Nine Months Ended September 30,
	2021		2020

	(in thousands)
Wages and employee benefits ⁽¹⁾	$	14,364	$	9,433
Non-cash stock-based compensation ⁽²⁾		8,090		2,378
Professional fees⁽³⁾		4,503		4,026
Professional fees - special ⁽⁴⁾		6,667		2,553
Recouped overhead ⁽⁵⁾		(5,331)		(2,395)
Office costs⁽⁶⁾		4,724		4,056
Legal judgements ⁽⁷⁾		708		246
Other ⁽⁸⁾		5,716		3,889
Total general and administrative expenses	$	39,441	$	24,186

(1)	Higher wages and employee benefits during the nine months ended September 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 nine months ended September 30, 2021 due to an increase in the number of equity awards granted to all employees in 2021 as part of the annual incentive bonus compensation and the related increase in expense.

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

(4)

Special professional fees are transaction-specific fees incurred in conjunction with our pursuit of strategic initiatives, including the integration of assets from our acquisitions and transaction costs associated with the evaluation and closing of acquisitions categorized as business combinations. The nine months ended September 30, 2021 primarily includes $3.4 million related to the integration of assets from the Mid-Con Acquisition and $3.0 million in fees related to the Pending Independence Merger. See Item 1. Note 3 – “Acquisitions and Dispositions” for further details.

(5)

(6)	Primarily includes office rent, office supplies and software licenses for IT applications.

(7)	The current year expense includes an accrual for a final judgment received in September 2021, which was paid in October 2021. See Item 1. Note 12 – “Commitments and Contingencies” for further details.

(8)	Includes fees related to insurance and other company expenses.

Loss from Affiliates

For the nine months ended September 30, 2021, we recorded a loss from affiliates of approximately $1.9 million, net of no tax expense, attributable to our equity investment in Exaro. For the nine months ended September 30, 2020, we recorded a loss from affiliates of approximately $13,000, net of no tax expense, attributable to our equity investment in Exaro.

Gain from Sale of Assets

During the nine months ended September 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 $2.8 million in cash and the buyers’ assumption of approximately $5.1 million in plugging and abandonment liabilities, resulting in a net gain of $0.5 million recorded during the nine months ended September 30, 2021.

During the nine months ended September 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 $4.5 million during the nine months ended September 30, 2020, primarily as a result of the buyers’ assumption of the asset retirement obligations associated with the sold properties.

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Gain (Loss) on Derivatives

During the nine months ended September 30, 2021, we recorded a loss on derivatives of $118.0 million. Of this amount, $96.2 million was a non-cash charge related to the change in the mark-to-market value of our hedges as commodity prices increased during 2021, and $21.7 million were realized losses as a result of monthly settlements on expiring contracts. During the nine months ended September 30, 2020, we recorded a gain on derivatives of $30.5 million. Of this amount, $8.2 million were non-cash mark-to-market gains, and $22.3 million were realized gains.

Gain on Extinguishment of Debt

During the nine months ended September 30, 2021, we recorded a $3.4 million gain on extinguishment of debt related to the PPP loan forgiveness. See Item 1. Note 10 – “Long-Term Debt” for further details.

Capital Resources and Liquidity

Our primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions and principal and interest payments on 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 $88.5 million and $26.6 million for the nine months ended September 30, 2021 and 2020, respectively. The lower 2020 change in operating assets and liabilities is primarily related to the suspension of our onshore operated drilling program beginning in the first quarter of 2020 and further suspension of all drilling in the second quarter of 2020, in response to the decrease in commodity prices. The table below provides additional detail of cash flows from operating activities for the nine months ended September 30, 2021 and 2020:


	Nine Months Ended September 30,
	2021		2020

	(in thousands)
Cash flows from operating activities, exclusive of changes in working capital accounts	$	81,459	$	32,323
Changes in operating assets and liabilities		7,026		(5,760)
Net cash provided by operating activities	$	88,485	$	26,563

Cash Used in Investing Activities

Net cash flows used in investing activities were $192.9 million and $22.0 million for the nine months ended September 30, 2021 and 2020, respectively. The 2021 activity is primarily related to the Mid-Con Acquisition, the Silvertip Acquisition, and the Wind River Basin Acquisition as discussed below. The 2020 activity was primarily related to an offshore exploratory prospect and drilling, 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. After customary closing adjustments of $4.7 million, including the results of operations during the period between the effective date of August 1, 2020 and the closing date, the net consideration paid was approximately $53.3 million, including the deposit previously paid in 2020. See Item 1. Note 3 – “Acquisitions and Dispositions” for further details.

On August 31, 2021, we closed on the Wind River Basin Acquisition for $67.0 million. After customary closing adjustments, including the results of operations during the period between the effective date of June 1, 2021 and the closing date, the net consideration paid was approximately $62.6 million, subject to customary purchase price adjustments. See Item 1. Note 3 – “Acquisitions and Dispositions” for further details.

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We 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 West Texas Permian (3 net locations, 6 gross locations), among other things. This forecast does not account for the Pending Independence Merger. The planned capital expenditures also include development opportunities with respect to certain properties we acquired as part of the Mid-Con Acquisition and the Silvertip Acquisition. The capital expenditure program will continue to be evaluated for revision for the remainder of 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.

Cash Provided by Financing Activities

Cash flows provided by financing activities for the nine months ended September 30, 2021 were approximately $106.1 million, and cash flows used in financing activities for the nine months ended September 30, 2020 were approximately $3.2 million. The 2021 activity is primarily related to $109.0 million in net borrowings under our Credit Agreement, which were primarily used for our 2021 acquisitions, and also includes the issuance of 387,011 shares of the Company’s common stock, in lieu of cash, as payment for $1.1 million in offshore prospect costs pursuant to our joint development agreement with Juneau Oil & Gas, LLC. The 2020 activity includes $6.8 million related to 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 Sale Agreement, we may sell, from time to time through the Sales Agent in the open market, subject to satisfaction of certain conditions, shares of our common stock having an aggregate offering price of up to $100,000,000 (the “ATM Program”). We intend to use the net proceeds from any sales through the ATM Program, after deducting the Sales Agent’s commission and 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 drilling. Under the Sale Agreement, we sold 117,571 shares for net proceeds of $0.5 million during the nine months ended September 30, 2021.

We believe that our internally generated cash flow and availability under 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. Our ability to execute on our growth strategy will be determined, in large part, by our cash flow and the availability of debt and equity capital at that time. Any decision regarding a financing transaction, and our ability to complete such a transaction, will depend on prevailing market conditions and other factors.

Credit Agreement

On September 17, 2019, we entered into a 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 thereafter amended to add additional banks to the lender group, to provide for certain modifications to the Company’s minimum hedging covenants, cash requirements and financial covenants and adjust the borrowing base pursuant to the regularly scheduled semi-annual redetermination process. The semi-annual redeterminations will occur on or around May 1^st and November 1^st of each 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 May 3, 2021, we entered into the Fifth Amendment to the Credit Agreement 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 the financial covenants. See Item 1. Note 10 – “Long-Term Debt” for more information. As of September

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30, 2021, we had $118.0 million outstanding under the Credit Agreement and $2.9 million in outstanding letters of credit, with borrowing availability of approximately $129.1 million.

The Credit Agreement matures on September 17, 2024. The Credit Agreement contains customary and typical restrictive covenants. The 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 1.0:1.0 and a Leverage Ratio of less than or equal to 3.25:1.0. As of September 30, 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”), signed into law on March 27, 2020, and is administered by the U.S. Small Business Administration. The PPP Loan to the Company was made through JPMorgan Chase Bank, N.A.

The PPP Loan 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), 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 utilized the PPP Loan amount for qualifying expenses during the 24-week coverage period, and on July 12, 2021, submitted our updated application for forgiveness of the total amount outstanding under the PPP Loan in accordance with the updated application terms of the CARES Act and related guidance. On August 6, 2021, we received notice from the Small Business Administration that our PPP loan was forgiven in its entirety. For the three and nine months ended September 30, 2021, we recorded other income of $3.4 million for the PPP loan forgiveness within “Gain on extinguishment of debt” on our consolidated statements of operations.

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 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.”

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Off Balance Sheet Arrangements

We may enter into off balance sheet arrangements that can give rise to off-balance sheet obligations. As of September 30, 2021, our off balance sheet arrangements consisted of delay rentals, surface damage payments and rental payments associated with salt water disposal contracts, as discussed in our 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

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

Changes in Internal Control Over Financial Reporting

The Company is in the final stages of completing the integration of the accounting for the operating results of the assets acquired in the Mid-Con Acquisition and 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. The Company is in the process of integrating the accounting for the operating results of the assets acquired in the Wind River Basin Acquisition into the Company’s internal control structure over financial reporting, and in conjunction with that process, and where deemed appropriate or necessary, has incorporated controls similar to Company controls currently existing. As a result of these integration activities, certain controls have been evaluated and revised where deemed appropriate. Other than such changes, there was no change in our internal control over financial reporting during the nine months ended September 30, 2021 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. of Part 1 of our 2020 Form 10-K and Item 1A. of Part II of our Quarterly Report on Form 10-Q for the period ended June 30, 2021.

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

The Company withheld the following shares from employees during the quarter ended September 30, 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

July 2021	1,901	$	4.15	—	$	—
August 2021	—	$	—	—	$	—
September 2021	—	$	—	—	$	—
Total	1,901	$	4.15	—	$	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 September 30, 2021. As of September 30, 2021, the Company has $31.8 million available under its share repurchase program, however, those repurchases could be limited by provisions of the Company’s Credit Agreement.

Item 3. Defaults upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number		Description
3.1		Amended and Restated Certificate of Formation of Contango Oil & Gas Company (filed as Exhibit 3.3 to the Company’s Report on Form 8-K dated June 14, 2019, as filed with the Securities and Exchange Commission on June 14, 2019 and incorporated by reference herein).
3.2		Bylaws of Contango Oil & Gas Company (filed as Exhibit 3.4 to the Company’s Report on Form 8-K dated June 14, 2019, as filed with the Securities and Exchange Commission on June 14, 2019 and incorporated by reference herein).
3.3		Certificate of Amendment to the Amended and Restated Certificate of Formation of Contango Oil & Gas Company, dated June 10, 2020 (filed as Exhibit 3.1 to the Company’s Report on Form 8-K dated June 11, 2020, as filed with the Securities and Exchange Commission on June 11, 2020 and incorporated by reference herein).
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. ††
101		The following financial statements from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements 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 September 30, 2021, formatted in Inline XBRL (included as Exhibit 101).†

* Indicates a management contract or compensatory plan or arrangement

†	Filed herewith.

††	Furnished herewith.

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SIGNATURES

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


		CONTANGO OIL & GAS COMPANY


Date: November 15, 2021	By:	/s/ WILKIE S. COLYER, JR.
		Wilkie S. Colyer, Jr.
		Chief Executive Officer
		(Principal Executive Officer)


Date: November 15, 2021	By:	/s/ E. JOSEPH GRADY
		E. Joseph Grady
		Senior Vice President and Chief Financial and Accounting Officer
		(Principal Financial and Accounting Officer)

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Contango Oil & Gas (MCF) 10-Q2021 Q3 Quarterly report

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