8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported): April 8, 2022

Crescent Energy Company

(Exact Name of Registrant as Specified in Charter)

Delaware	001-41132	87-1133610
(State or Other Jurisdiction of Incorporation)	(Commission File Number)	(I.R.S. Employer Identification Number)

600 Travis Street, Suite 7200 Houston, Texas	77002
(Address of Principal Executive Offices)	(Zip Code)

(713) 337-4600

(Registrant’s Telephone Number, Including Area Code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

☐ Written communication pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communication pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communication pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, par value $0.0001 per share	CRGY	The New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).

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.  ☐

Item 2.02. Results of Operations and Financial Condition.

As reported in a Current Report on Form 8-K filed with the U.S. Securities and Exchange Commission (“SEC”) by Crescent Energy Company (the “Company”) on December 7, 2021 (the “Original Crescent Form 8-K”), on December 7, 2021, the Company consummated the transactions (the “Transactions”) contemplated by the Transaction Agreement, dated as of June 7, 2021, among Contango Oil & Gas Company (“Contango”), Independence Energy LLC (“Independence”), the Company, IE OpCo LLC, IE L Merger Sub LLC and IE C Merger Sub Inc., pursuant to which each of Contango and Independence became consolidated subsidiaries of the Company.

This Current Report on Form 8-K provides certain historical and pro forma financial statements, as described in Item 9.01 below, each of which are incorporated into this Item 2.02 by reference. The historical financial statements of Contango are consistent with the historical financial statements of Contango filed on the Original Crescent Form 8-K and the pro forma financial statements are consistent with the pro forma financial statements furnished by the Company on March 10, 2022, and in each case are being filed on this Current Report on Form 8-K for the purposes of incorporation by reference into the Registration Statement (as defined below). This Current Report on Form 8-K should be read in connection with the Original Crescent Form 8-K, which provides a more complete description of the Transactions.

Item 7.01. Regulation FD Disclosure.

The information contained in Item 8.01 of this Current Report on Form 8-K is incorporated into this Item 7.01 by reference.

The information contained in this Item 7.01 shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended , or the Exchange Act.

Item 8.01 Other Events.

Historical and Pro Forma Financial Statements

This Current Report on Form 8-K provides certain historical and pro forma financial statements, as described in Item 9.01 below, each of which are incorporated into this Item 8.01 by reference. The historical financial statements of Contango are consistent with the historical financial statements of Contango filed on the Original Crescent Form 8-K and the pro forma financial statements are consistent with the pro forma financial statements furnished by the Company on March 10, 2022, and in each case are being filed on this Current Report on Form 8-K for the purposes of incorporation by reference into the Registration Statement (as defined below). This Current Report on Form 8-K should be read in connection with the Original Crescent Form 8-K, which provides a more complete description of the Transactions.

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Registration Statement Disclosures

On or about the date of this Current Report on Form 8-K, the Company intends to file a Registration Statement on Form S-1 (the “Registration Statement”) relating to the proposed offering by the Company of $75,000,000 of shares of its Class A common stock, par value $0.0001 per share. In connection with the filing of such Registration Statement, the Company is providing certain additional disclosures to potential investors, the relevant excerpts of which are set forth below. Capitalized terms used but not defined herein shall have the meaning assigned thereto in the Registration Statement

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Summary Reserve Data based on SEC Pricing

The following table provides historical reserves, PV-0, and PV-10 as of December 31, 2021 for the reserves acquired in the Uinta Acquisition, prepared in accordance with the SEC’s rules regarding reserve reporting currently in effect, including the use of an average price, calculated as prices equal to the 12-month unweighted arithmetic average of the first day of the month prices for each of the preceding 12 months as adjusted for location and quality differentials, unless prices are defined by contractual arrangements, excluding escalations based on future conditions (“SEC Pricing”). The reserve estimates presented in the table below are based on a report prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”).

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	Uinta Acquisition(1)
	As of December 31, 2021
Net Proved Reserves:
Oil (MBbls)		42,924
Natural gas (MMcf)		139,329
NGLs (MBbls) (2)		—
Total Proved Reserves (MBoe)		66,146
Standardized Measure (millions) (3)	$	1,027
PV-0 (millions) (3)	$	1,524
PV-10 (millions) (3)	$	1,054
Net Proved Developed Reserves:
Oil (MBbls)		24,871
Natural gas (MMcf)		92,094
NGLs (MBbls) (2)		—
Total Proved Developed Reserves (MBoe)		40,220
PV-0 (millions) (3)	$	954
PV-10 (millions) (3)	$	733
Net Proved Undeveloped Reserves:
Oil (MBbls)		18,054
Natural gas (MMcf)		47,235
NGLs (MBbls) (2)		—
Total Proved Undeveloped Reserves (MBoe)		25,926
PV-0 (millions) (3)	$	571
PV-10 (millions) (3)	$	321

(1) The Uinta Acquisition’s reserves and present value (discounted at ten percent, or PV-10) were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The base SEC oil and gas prices calculated for December 31, 2021 were $66.56 per Bbl and $3.598 per MMBtu, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2021 and the base gas price is based upon Henry Hub spot prices (Gas Daily) during 2021. Adjustments to oil and gas prices were calculated by the Company and applied as received by CG&A. For all properties, oil price differentials were forecast at -$10.26 per Bbl and gas price differentials were forecast at -$1.51 per Mcf. Adjustments may include treating costs, transportation charges, plant processing, and/or crude quality and gravity corrections. After these adjustments, the net realized prices over the life of the proved properties was estimated to be $56.30 per Bbl for oil and $2.088 per Mcf for gas. All economic factors were held constant in accordance with SEC guidelines.

(2) Natural gas reserves acquired in the Uinta Acquisition are shown in “wet” MMcf, which includes NGLs. The Company uses three-stream reserve information, with NGL reserves reported separately. As a result, reserve estimates of the Company are not comparable to reserve estimates for the Uinta Acquisition.

(3) Present value (discounted at PV-0 and PV-10) is not a financial measure calculated in accordance with U.S. generally accepted accounting principles (“GAAP”) because it does not include the effects of income taxes on future net revenues. None of PV-0 and PV-10 represent an estimate of the fair market value of our oil and natural gas properties. Our PV-0 measurement does not provide a discount rate to estimated future cash flows. PV-0 therefore does not reflect the risk associated with future cash flow projections like PV-10 does. PV-0 should therefore only be evaluated in connection with an evaluation of our PV-10 of discounted future net cash flows. We believe that the presentation of PV-0 and PV-10 is relevant and useful to its investors as supplemental disclosure to the standardized measure of future net cash flows, or after tax amount, because it presents the discounted future net cash flows attributable to our reserves prior to taking into account future income taxes and our specific tax characteristics. Standardized measure for the Uinta Acquisition is shown pro forma as if the assets acquired in the Uinta Acquisition had been owned by Crescent Energy Company as of December 31, 2021. The PV-0 and PV-10 income tax amounts included in the net proved standardized measure but not included in PV-0 and PV-10 were $39.8 million and $27.1 million, respectively. We and others in our industry use PV-0 and PV-10 as a measure to compare the relative size and value of proved reserves without regard to specific tax characteristics. Investors should be cautioned that none of PV-0 and PV-10 represent an estimate of the fair market value of our proved reserves.

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Summary Reserve Data based on NYMEX Pricing

The following table provides historical reserves, PV-0, and PV-10 as of December 31, 2021 for the Company and the reserves acquired in the Uinta Acquisition using average annual NYMEX forward-month contract pricing in effect as of March 31, 2022 (“NYMEX Pricing”). We have included this reserve sensitivity in order to provide a measure that is more reflective of the fair value of our assets and the cash flows that we expect to generate from those assets based on the market’s forward-looking pricing expectations as of March 31, 2022. The historical 12-month pricing average in our 2021 disclosures under the heading “Summary Reserve Data based on SEC Pricing” does not reflect the oil and natural gas futures. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking pricing expectations as of December 31, 2021. The historical 12-month pricing average in our 2021 disclosures under the heading “Summary Reserve Data based on SEC Pricing” does not reflect the oil and natural gas futures. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s

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forward-looking expectations of oil and natural gas prices as of a certain date. In addition, we believe strip pricing provides relevant and useful information because it is widely used by investors in our industry as a basis for comparing the relative size and value of our proved reserves to our peers and in particular addresses the impact of differentials compared with our peers. Our estimated historical reserves, PV-0, and PV-10 based on NYMEX futures were otherwise prepared on the same basis as our SEC reserves for the comparable period. Reserve estimates using NYMEX Pricing are based on the internal estimates of the management of the Company and have not been prepared or audited by an independent, third-party reserve engineer.

	Crescent Energy Company		Uinta Acquisition
	As of December 31, 2021(1)
Net Proved Reserves:
Oil (MBbls)		211,497		43,252
Natural gas (MMcf)		1,533,009		141,439
NGLs (MBbls) (3)		78,790		—
Total Proved Reserves (MBoe)		545,788		66,825
PV-0 (millions) (2)	$	11,931	$	2,025
PV-10 (millions) (2)	$	6,781	$	1,466
Net Proved Developed Reserves:
Oil (MBbls)		159,332		25,162
Natural gas (MMcf) (3)		1,467,322		94,028
NGLs (MBbls) (3)		68,653		—
Total Proved Developed Reserves (MBoe)		472,539		40,833
PV-0 (millions) (2)	$	9,681	$	1,300
PV-10 (millions) (2)	$	5,658	$	1,029
Net Proved Undeveloped Reserves:
Oil (MBbls)		52,164		18,090
Natural gas (MMcf)		65,687		47,411
NGLs (MBbls) (3)		10,137		—
Total Proved Undeveloped Reserves (MBoe)		73,429		25,992
PV-0 (millions) (2)	$	2,249	$	725
PV-10 (millions) (2)	$	1,123	$	437

(1) The NYMEX reserves, PV-0, and PV-10 of the Company and the Uinta Acquisition were determined using index prices for oil and natural gas, respectively, without giving effect to derivative transactions and were calculated based on settlement prices to better reflect the market expectations as of that date, as adjusted for our estimates of quality, transportation fees, and market differentials. The five-year average strip pricing for the reserve calculations based on NYMEX futures pricing at closing on March 31, 2022 were $79.71 per Bbl of oil and $4.267 per MMBtu of natural gas. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date. NYMEX futures prices are not necessarily a projection of future oil and gas prices. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil, natural gas and NGL reserves. While we believe the NYMEX forward-month contract pricing is the most accurate indicator of commodity prices as of the applicable date, commodity prices are volatile. As a result, actual future prices may vary significantly from the NYMEX prices used herein. The future value of the reserves eventually recovered and the amounts of reserves actually recovered may be more or less than the estimated amounts.

(2) Present value (discounted at PV-0 and PV-10) is not a financial measure calculated in accordance with GAAP because it does not include the effects of income taxes on future net revenues. Neither PV-0 nor PV-10 represent an estimate of the fair market value of our oil and natural gas properties. Our PV-0 measurement does not provide a discount rate to estimated future cash flows. PV-0 therefore does not reflect the risk associated with future cash flow projections like PV-10 does. PV-0 should therefore only be evaluated in connection with an evaluation of our PV-10 of discounted future net cash flows. We believe that the presentation of PV-0 and PV-10 is relevant and useful to our investors about the future net cash flows of our reserves in the absence of a comparable measure such as standardized measure. We and others in our industry use PV-0 and PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Investors should be cautioned that neither of PV-0 and PV-10 represent an estimate of the fair market value of our proved reserves. GAAP does not prescribe any corresponding measure for PV-10 of reserves based on pricing other than SEC Pricing. As a result, it is not practicable for us to reconcile our PV-10 using NYMEX Pricing to standardized measure as determined in accordance with GAAP.

(3) Natural gas reserves acquired in the Uinta Acquisition are shown in “wet” MMcf, which includes NGLs. The Company uses three-stream reserve information, with NGL reserves reported separately. As a result, reserve estimates of the Company are not comparable to reserve estimates for the Uinta Acquisition.

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After accounting for the Uinta Acquisition, our 2022 expected capital program, which totals between $600 million and $700 million, is approximately 95% allocated to D&C (80 to 85% to our operated assets primarily in the Eagle Ford and Uinta basins and 10 to 15% to non-operated activity) and approximately 5% to other capital expenditures.

* * * * *

On a pro forma basis for the Transactions, our capital expenditures, excluding acquisitions, incurred during the year ended December 31, 2021 totaled approximately $231.6 million. For the year ending December 31, 2022, including nine months of contribution from the Uinta Acquisition, we expect to incur approximately $600 million to $700 million, excluding acquisitions.

* * * * *

The assets associated with the Uinta Acquisition include an aggregate approximately 145,000 net acres, primarily located in Duchesne and Uintah Counties, Utah, with approximately 400 currently producing wells.

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As of March 31, 2022, our derivative portfolio had an aggregate notional value of approximately $2.2 billion. We determine the fair value of our oil and natural gas commodity derivatives using valuation techniques that utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. The following table details the Company’s open commodity derivative contracts as of March 31, 2022.

	WTI				Brent				Natural Gas				NGLs
	Volume (MBbl)		Avg Price ($/Bbl)		Volume (MBbl)		Avg Price ($/Bbl)		Volume (BBtu)		Avg Price $/MMBtu		Volume (MBbl)		Avg Price $/Bbl
Q1’22		2,862	$	61.67		123	$	56.35		22,534	$	2.79		914	$	17.20
Q2’22		3,715	$	65.20		125	$	56.35		21,690	$	2.77		873	$	17.13
Q3’22		3,580	$	64.59		126	$	56.36		20,634	$	2.76		610	$	29.87
Q4’22		3,301	$	64.08		126	$	56.36		20,180	$	2.78		587	$	29.74
FY’23		10,865	$	59.78		527	$	52.52		57,278	$	2.54		—		—
FY’24		5,721	$	63.82		276	$	68.65		9,604	$	3.56		—		—

Note: Includes hedges from January 1, 2022 through December 31, 2024. Included in the figures above are minor Henry Hub collar positions totaling 510 BBtu, 550 BBtu, and 9,150 BBtu in Q1 2022, 2023 and 2024, respectively. For the same periods, these collars have a weighted average floor price of $3.00 / MMBtu, $2.63 / MMBtu and 3.00 / MMBtu, respectively and a weighted average ceiling price of $3.41 / MMBtu, $3.01 / MMBtu and $3.87 / MMBtu, respectively. Also included in the figures above are WTI collars totaling 1,155 Mbbl for 2023 with a weighted average floor and ceiling price of $48.68 / Bbl and $57.87 / Bbl, respectively. Weighted average price for collar positions in the table above calculated using March 29, 2022 strip pricing.

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Our PDP reserves as of December 31, 2021 have estimated average five-year and ten-year annual decline rates of approximately 13% and 11%, respectively, and an estimated 2022 PDP decline rate of 22%, based on forecasts used in our reserve reports.

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Armed conflict, geopolitical risk and/or civil unrest, including as a result of the existing conflict in Ukraine, could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. For example, on February 24, 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities. As a result, the United States, the United Kingdom, the member states of the European Union and other public and private actors have levied severe economic sanctions on Russia. The geopolitical and macroeconomic consequences of this invasion and associated sanctions cannot be predicted, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our products and causing a reduction in our revenues. The markets for commodities such as oil, gas and NGLs have experienced significant volatility, which may impact demand and have other negative macroeconomic effects. Oil, natural gas and NGL related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our or our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

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This Item 8.01 incorporates by reference the report of Cawley, Gillespie & Associates, Inc., filed as Exhibit 99.4 herewith.

Item 9.01 Financial Statements and Exhibits.

(b)    Financial Statements of Businesses Acquired

• Audited consolidated financial statements of Contango as of and for the years ended December 31, 2020 and 2019, and the related notes to the consolidated financial statements, included in Contango’s Annual Report on Form 10-K for the year ended December 31, 2020, attached as Exhibit 99.1 hereto;

• Unaudited consolidated financial statements of Contango as of September 30, 2021 and December 31, 2020 and for the three and nine months ended September 30, 2021 and 2020, and the related notes to the condensed consolidated financial statements, included in Contango’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, attached as Exhibit 99.2 hereto;

(b)    Pro Forma Financial Information

The following unaudited pro forma condensed combined financial information of the Company, giving effect to the Transactions, attached as Exhibit 99.3 hereto:

• Unaudited Pro Forma Condensed Combined Statement of Operations for the year ended December 31, 2021; and

• Notes to the Unaudited Pro Forma Condensed Combined Financial Statements.

(d)    Exhibits.

Exhibit	Description
23.1	Consent of Grant Thornton LLP, relating to the financial statements of Contango Oil & Gas Company.
23.2	Consent of Cawley, Gillespie & Associates, Inc.
23.3	Consent of William M. Cobb & Associates, Inc.
23.4	Consent of W.D. Von Gonten and Company.
99.1	Historical audited consolidated financial statements of Contango Oil & Gas Company as of December 31, 2020 and 2019 and for the years ended December 31, 2020 and 2019.
99.2	Historical unaudited consolidated financial statements of Contango Oil & Gas Company as of September 30, 2021 and December 31, 2020 and for the three and nine months ended September 30, 2021 and 2020.
99.3	Unaudited pro forma condensed combined financial information for the year ended December 31, 2021.
99.4	Report of Cawley, Gillespie & Associates, Inc. – Uinta, as of December 31, 2021.
99.5	Report of William M. Cobb & Associates, Inc.
99.6	Report of W.D. Von Gonten and Company.
104	Cover Page Interactive Data File (embedded within the Inline XBRL document).

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SIGNATURE

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

Date: April 8, 2022

CRESCENT ENERGY COMPANY
By:	/s/ Bo Shi
Name:	Bo Shi
Title:	General Counsel

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EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated March 10, 2021, with respect to the consolidated financial statements of Contango Oil & Gas Company included in the Annual Report on Form 10-K of Contango Oil & Gas Company for the year ended December 31, 2020, which are included in this Current Report of Crescent Energy Company on Form 8-K. We consent to the incorporation by reference of the aforementioned report in this Current Report of Crescent Energy Company on Form 8-K.

/s/ GRANT THORNTON LLP

Houston, Texas

April 8, 2022

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

As independent petroleum consultants, we hereby consent to the incorporation by reference of our reserve report and oil, natural gas and NGL reserves estimates and forecasts of economics as of December 31, 2021, into Crescent Energy Company’s Registration Statement on Form S-8 filed with the Securities and Exchange Commission on December 10, 2021.

Austin, Texas

April 8, 2022

EX-23.3

Exhibit 23.3

WILLIAM M. COBB & ASSOCIATES, INC.

Worldwide Petroleum Consultants

12770 Coit Road, Suite 907 Tel: (972) 385-0354

Dallas, Texas 75251 Fax: (972) 788-5165

E-Mail: office@wmcobb.com

April 8, 2022

Crescent Energy Company

600 Travis Street, Suite 7200

Houston, Texas, 77002

Re:Crescent Energy Company

Gentlemen:

The firm of William M. Cobb & Associates, Inc. also hereby consents to the incorporation by reference of its projections for Crescent Energy Company’s Proved Reserves and Future Net Revenue into the Registration Statement on Form S-8 of Crescent Energy Company.

William M. Cobb & Associates, Inc. has no interests in Crescent Energy Company or in any affiliated companies or subsidiaries and is not to receive any such interest as payment for such reports and has no director, officer, or employee otherwise connected with Crescent Energy Company. Crescent Energy Company does not employ us on a contingent basis.

EX-23.4

Exhibit 23.4

W.D. VON GONTEN & CO.

April 8, 2022

Crescent Energy Company

600 Travis Street, Suite 7200

Houston, Texas, 77002

Re: Contango Oil & Gas Company

Gentlemen:

The firm of W.D. Von Gonten & Co. consents to the incorporation by reference of its report regarding Contango Oil & Gas Company’s Proved Reserves and Future Net Revenue associated with its 37% ownership interest in Exaro Energy III LLC, into Crescent Energy Company’s Registration Statement on Form S-8 filed with the Securities and Exchange Commission on December 10, 2021.

W.D. Von Gonten & Co. has no interests in Contango Oil & Gas Company or in any affiliated companies or subsidiaries and is not to receive any such interest as payment for such reports and has no director, officer, or employee otherwise connected with Contango Oil & Gas Company. Contango Oil & Gas Company does not employ us on a contingent basis.

Yours very truly,

W.D. VON GONTEN & CO.

/s/ W.D. Von Gonten, Jr.                

W.D. VON GONTEN & CO.

William D. Von Gonten, Jr.

President

Houston, Texas

EX-99.1

Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Contango Oil & Gas Company

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Contango Oil & Gas Company (a Texas corporation) and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of operations, cash flows, and shareholders’ equity for each of the two years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Depletion expense and impairment of oil and gas properties impacted by the Company’s estimation of proved reserves

As described further in Notes 2 and 5 to the financial statements, the Company accounts for its oil and gas properties using the successful efforts method of accounting which requires management to estimate reserve volumes and future net revenues to record depletion expense and to assess if there are indications the carrying value of certain properties exceed the fair value and if so, determine the fair value of its oil and gas properties to measure impairment. To estimate the volume of reserves and future net revenues, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties, and forecasting the timing and volume of production associated with the Company’s development plan for undeveloped properties. In addition, the estimation of reserves is also impacted by management’s judgments and estimates regarding the

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financial performance of wells associated with reserves to determine if wells are expected, with reasonable certainty, to be economical under the pricing assumptions required in the estimation of depletion expense and impairment evaluation and measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and the evaluation and measurement of impairment, as a critical audit matter.

The principal consideration for our determination that the estimation of reserves is a critical audit matter is that relatively minor changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s reserves, could have a significant impact on the measurement of depletion or impairment expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of proved reserves included the following, among others.

• We evaluated the level of knowledge, skill and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserves, and read the reserve reports prepared by the Company’s reservoir engineering specialists.

• We tested the accuracy of the Company’s depletion calculations and impairment evaluation and measurement that included these proved reserve reports.

• We evaluated sensitive inputs and assumptions used to determine reserve volumes and other cash flow inputs and assumptions derived from the Company’s accounting records. These assumptions included historical pricing differentials, current and future operating costs, estimated future capital costs, and ownership interests. We tested management’s process for determining the assumptions, including examining the underlying support on a sample basis for reasonableness and accuracy. Specifically, our audit procedures involved testing management’s assumptions as follows:

• Compared the estimated pricing differentials used in the reserve reports to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;

• Evaluated models used to estimate the future operating costs in the reserve reports and compared amounts to historical operating costs;

• Evaluated the method used to determine the future capital costs and compared estimated future capital costs used in the reserve reports to amounts expended for recently drilled and completed wells;

• Tested the ownership interests used in the reserve reports by inspecting land and title records;

• Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve reports by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and

• Applied analytical procedures to the forecasted production in the reserve reports by comparing to historical actual results and to the prior year or preceding period reserve reports.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2002.

Houston, Texas

March 10, 2021

2

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except shares)

	December 31, 2020			December 31, 2019
CURRENT ASSETS:
Cash and cash equivalents	$	1,383		$	1,624
Accounts receivable, net		37,862			39,567
Prepaid expenses		3,360			1,191
Current derivative asset		2,996			3,819
Inventory		442			186
Deposits and other		763			—
Total current assets		46,806			46,387
PROPERTY, PLANT AND EQUIPMENT:
Oil and natural gas properties, successful efforts method of accounting:
Proved properties		1,274,508			1,306,916
Unproved properties		16,201			27,619
Other property and equipment		1,669			1,655
Accumulated depreciation, depletion, amortization and impairment		(1,190,475	)		(1,045,070	)
Total property, plant and equipment, net		101,903			291,120
OTHER NON-CURRENT ASSETS:
Investments in affiliates		6,793			6,766
Long-term derivative asset		497			357
Right-of-use lease assets		5,448			5,885
Debt issuance costs		1,782			3,311
Deposits		7,038			—
Total other non-current assets		21,558			16,319
TOTAL ASSETS	$	170,267		$	353,826
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	83,970		$	104,593
Current derivative liability		1,317			3,951
Current asset retirement obligations		4,249			2,003
Total current liabilities		89,536			110,547
NON-CURRENT LIABILITIES:
Long-term debt		12,369			72,768
Long-term derivative liability		1,648			2,020
Asset retirement obligations		48,523			49,662
Lease liabilities		2,624			2,789
Total non-current liabilities		65,164			127,239
Total liabilities		154,700			237,786
COMMITMENTS AND CONTINGENCIES (NOTE 14)
SHAREHOLDERS’ EQUITY:
Series C convertible preferred stock, $0.04 par value, no shares authorized, issued and outstanding at December 31, 2020 and 2,700,000 shares authorized, issued and outstanding at December 31, 2019		—			108
Common stock, $0.04 par value, 400 million shares authorized, 173,830,390 shares issued and 173,737,816 shares outstanding at December 31, 2020, 128,985,146 shares issued and 128,977,816 shares outstanding at December 31, 2019		6,941			5,148
Additional paid-in capital		535,192			471,778
Treasury shares at cost (92,574 shares at December 31, 2020 and 7,330 shares at December 31, 2019)		(248	)		(18	)
Accumulated deficit		(526,318	)		(360,976	)
Total shareholders’ equity		15,567			116,040
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	170,267		$	353,826

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

3

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

	Year Ended December 31,
	2020			2019
REVENUES:
Oil and condensate sales	$	62,461		$	44,705
Natural gas sales		31,381			22,380
Natural gas liquids sales		17,078			9,427
Fee for service revenues		2,000			—
Total revenues		112,920			76,512
EXPENSES:
Operating expenses		72,847			33,205
Exploration expenses		11,594			1,003
Depreciation, depletion and amortization		30,032			39,807
Impairment & abandonment of oil and natural gas properties		168,802			128,290
General and administrative expenses		24,940			24,938
Total expenses		308,215			227,243
OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates (net of income taxes)		27			742
Gain from sale of assets		4,501			518
Interest expense		(5,022	)		(8,596	)
Gain (loss) on derivatives, net		27,585			(3,357	)
Other income		3,609			1,848
Total other income		30,700			(8,845	)
NET LOSS BEFORE INCOME TAXES		(164,595	)		(159,576	)
Income tax provision		(747	)		(220	)
NET LOSS ATTRIBUTABLE TO COMMON STOCK	$	(165,342	)	$	(159,796	)
NET LOSS PER SHARE:
Basic	$	(1.20	)	$	(2.95	)
Diluted	$	(1.20	)	$	(2.95	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		137,522			54,136
Diluted		137,522			54,136

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

4

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2020			2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(165,342	)	$	(159,796	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		30,032			39,807
Impairment of oil and natural gas properties		168,732			126,964
Exploration expenditures - dry hole costs		10,455			—
Amortization of debt issuance costs		1,603			144
Deferred income taxes		—			424
Gain on sale of assets		(4,501	)		(518	)
Gain from investment in affiliates		(27	)		(742	)
Stock-based compensation		4,270			2,352
Unrealized loss (gain) on derivative instruments		(2,321	)		5,973
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable & other		1,463			(9,903	)
Decrease (increase) in prepaid expenses		(2,169	)		451
Increase in inventory		(256	)		—
Increase (decrease) in accounts payable & advances from joint owners		(6,279	)		10,739
Increase (decrease) in other accrued liabilities		(7,477	)		13,019
Decrease (increase) in income taxes receivable, net		281			(85	)
Increase (decrease) in income taxes payable, net		233			(153	)
Deposits and other		(7,801	)		(6,966	)
Net cash provided by operating activities	$	20,896		$	21,710
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil & natural gas exploration & development expenditures	$	(21,689	)	$	(42,737	)
Acquisition of oil & natural gas properties		—			(112,075	)
Additions to furniture & equipment		(13	)		(53	)
Sale of oil and natural gas properties		349			10
Net cash used in investing activities	$	(21,353	)	$	(154,855	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Credit Agreement	$	79,700		$	256,923
Repayments under Credit Agreement		(143,468	)		(244,154	)
Payroll Protection Program Loan		3,369			—
Net proceeds from equity offerings		60,919			125,710
Purchase of treasury stock		(230	)		(255	)
Debt issuance costs		(74	)		(3,455	)
Net cash provided by financing activities	$	216		$	134,769
NET CHANGE IN CASH AND CASH EQUIVALENTS	$	(241	)	$	1,624
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		1,624			—
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	1,383		$	1,624

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

5

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the twelve months ended December 31, 2020

(in thousands, except share amounts)

	Preferred Stock						Common Stock					Additional Paid-in Capital			Treasury Stock			Accumulated Deficit			Total Shareholders’ Equity
	Shares			Amount			Shares			Amount
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	)
Equity offering - common stock		—			—			40,645,891			1,626		58,883			—			—			60,509
Treasury shares at cost		—			—			(18,284	)		—		—			(42	)		—			(42	)
Restricted shares activity		—			—			96,531			3		(3	)		—			—			—
Stock-based compensation		—			—			—			—		1,802			—			—			1,802
Net loss		—			—			—			—		—			—			(25,248	)		(25,248	)
Balance at December 31, 2020		—		$	—			173,737,816		$	6,941	$	535,192		$	(248	)	$	(526,318	)	$	15,567

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

6

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

For the twelve months ended December 31, 2019

(in thousands, except share amounts)

	Preferred Stock						Common Stock						Additional Paid-in Capital			Treasury Stock			Accumulated Deficit			Total Shareholders’ Equity
	Shares			Amount			Shares			Amount
Balance at December 31, 2018		—		$	—			34,158,492		$	1,573		$	339,981		$	(129,030	)	$	(72,135	)	$	140,389
Equity offering - common stock		—			—			—			—			(86	)		—			—			(86	)
Treasury shares at cost		—			—			(49,415	)		—			—			(186	)		—			(186	)
Restricted shares activity		—			—			307,650			12			(12	)		—			—			—
Stock-based compensation		—			—			—			—			1,052			—			—			1,052
Net loss		—			—			—			—			—			—			(8,618	)		(8,618	)
Balance at March 31, 2019		—		$	—			34,416,727		$	1,585		$	340,935		$	(129,216	)	$	(80,753	)	$	132,551
Equity offering - common stock		—			—			—			—			45			—			—			45
Treasury shares at cost		—			—			(16,133	)		—			—			(50	)		—			(50	)
Restricted shares activity		—			—			42,249			2			(2	)		—			—			—
Stock-based compensation		—			—			—			—			585			—			—			585
Net loss		—			—			—			—			—			—			(4,961	)		(4,961	)
Balance at June 30, 2019		—		$	—			34,442,843		$	1,587		$	341,563		$	(129,266	)	$	(85,714	)	$	128,170
Equity offering - preferred stock		789,474			32			—			—			7,420			—			—			7,452
Equity offering - common stock		—			—			45,922,870			2,058			44,181			—			—			46,239
Treasury shares at cost		—			—			5,524,498			(221	)		—			129,266			(129,045	)		—
Treasury shares reissuance		—			—			(25,748	)		(1	)		1			—			—			—
Stock-based compensation		—			—			—			—			558			—			—			558
Net loss		—			—			—			—			—			—			(7,838	)		(7,838	)
Balance at September 30, 2019		789,474		$	32			85,864,463		$	3,423		$	393,723		$	—		$	(222,597	)	$	174,581
Equity offering - preferred stock		3,802,838			152			—			—			26,154			—			—			26,306
Equity offering - common stock		—			—			19,000,000			760			44,942			—			—			45,702
Conversion of preferred stock to common stock		(1,892,312	)		(76	)		18,923,120			757			(629	)		—			—			52
Treasury shares at cost		—			—			(7,330	)		—			—			(18	)		—			(18	)
Restricted shares activity		—			—			(27,437	)		(1	)		1			—			—			—
Stock-based compensation		—			—			—			—			158			—			—			158
Will Energy and Juneau acquisitions		—			—			5,225,000			209			7,429			—			—			7,638
Net loss		—			—			—			—			—			—			(138,379	)		(138,379	)
Balance at December 31, 2019		2,700,000		$	108			128,977,816		$	5,148		$	471,778		$	(18	)	$	(360,976	)	$	116,040

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

7

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties primarily located in Oklahoma, Texas, Wyoming and Louisiana and use that cash flow to explore, develop and acquire oil and natural gas properties across the United States.

The following table lists the Company’s primary producing areas as of December 31, 2020:

Location	Formation
Offshore Gulf of Mexico	Offshore Louisiana - water depths less than 300 feet
Central Oklahoma	Mississippian, Woodford, Oswego, Cottage Grove, Chester, Cleveland and Red Fork
Western Anadarko	Tonkawa, Cottage Grove, Cleveland, Marmaton, Chase Sandstone, Morrow, Chester and Oswego
West Texas	Wolfcamp A and B
Other Onshore (TX, LA, WY)	Woodbine, Lewisville, Buda, Georgetown, Eagleford, and Muddy Sandstone

Impact of the COVID-19 Pandemic

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

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

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

• utilization of the Company’s available storage capacity to temporarily store a portion of its production for later sale at higher prices when advantageous to do so (such as the approximate 50,000 barrels of second quarter oil production we stored and sold during the third quarter of 2020 at higher oil prices);

• suspension of any further plans for operated onshore and offshore drilling in 2020;

• pursuit of additional “fee for service” opportunities similar to the Management Services Agreement entered into in June 2020 with Mid-Con Energy Partners, LP (“Mid-Con”) (NASDAQ:MCEP), which was terminated at the closing of the Mid-Con Acquisition (as defined below) between the Company and Mid-Con on January 21, 2021); and

• potential acquisitions of PDP-heavy assets, with attractive, discounted valuations, in stressed/distressed scenarios or from non-industry owners, such as the Silvertip Acquisition (as defined below).

8

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 initial 6,500 net acre position in Pecos County, Texas (“Bullseye”), and in December 2018, the Company purchased an additional 4,200 gross operated (1,700 net) acres and 4,000 gross non-operated (200 net) acres to the northeast of its existing acreage (“NE Bullseye”). Contango’s 2019 drilling program included the completion of one well previously drilled in the Bullseye area, the drilling and completion of a second Bullseye well, and the drilling and completion of three wells in the NE Bullseye area. In December 2019, the Company began completion operations on its fourth NE Bullseye well, which began producing in January 2020, and then suspended further drilling in the area in response to the dramatic decline in oil prices. As of December 31, 2020, the Company was producing from 18 wells over its approximate 16,200 gross operated (7,500 company net) acre position in West Texas, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations.

In September 2019, the Company entered into unrelated purchase agreements with Will Energy Corporation (“Will Energy”) and White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) to purchase certain producing assets and undeveloped acreage, primarily in Oklahoma. These transactions closed during the three months ended December 31, 2019, (the “Will Energy Acquisition” and “White Star Acquisition”) and were transformative, as production from these acquisitions represented approximately 70% of the Company’s total net production for the year ended December 31, 2020. See Note 4 – “Acquisitions and Dispositions” for more information. In conjunction with the White Star Acquisition, the Company entered into a new revolving credit agreement with JPMorgan Chase Bank, N.A. and other lenders (the “Credit Agreement”). In connection with the entry into the Credit Agreement, the Company repaid all obligations outstanding on, and terminated, its previous credit agreement with Royal Bank of Canada, which matured on October 1, 2019. The Credit Agreement has since been amended to increase the number of lenders from three to nine, and among other things, to adjust the borrowing base to $130.0 million on January 21, 2021 and $120.0 million on March 31, 2021. See Note 13 – “Long-Term Debt” for more information.

The Company completed two stock offerings in the third quarter of 2019. The Company completed an underwritten public offering (the “September 2019 Public Offering”) of 51,447,368 shares of common stock (of which 5,524,498 were reissued treasury shares) for net proceeds of approximately $46.2 million, after deducting the underwriting discount and fees and expenses. Net proceeds from the September 2019 Public Offering were used to fund the cash portion of the purchase price for the Will Energy Acquisition and to repay borrowings outstanding under the Company’s former revolving credit facility to provide incremental liquidity to support the Company’s planned acquisition efforts. In conjunction with the September 2019 Public Offering, the Company also entered into a purchase agreement with affiliates of John C. Goff, a director and significant shareholder, and current chairman of the Company, to issue and sell in a private placement (the “Series A Private Placement”) 789,474 shares of Series A contingent convertible preferred stock, which resulted in net proceeds of approximately $7.5 million.

The Company completed two additional stock offerings in the fourth quarter of 2019. In connection with the closing of the White Star Acquisition in November 2019, the Company completed a private placement of 1,102,838 shares of Series B contingent convertible preferred stock of the Company, which resulted in net proceeds of approximately $21.0 million (the “Series B Private Placement”). Net proceeds from the Series A Private Placement were used to fund a portion of the purchase price and related transaction expenses for the Will Energy Acquisition, and net proceeds from the Series B Private Placement were used to fund a portion of the purchase price and related transaction expenses for the White Star Acquisition. In December 2019, the Company also completed a private placement of 19,000,000 shares of common stock for net proceeds of approximately $45.7 million, after deducting the underwriting discount and fees and expenses (the “December 2019 Offering”). In conjunction with the December 2019 Offering, the Company also completed a private placement of 2,340,000 shares of Series C contingent convertible preferred stock (the “Series C Private Placement”) with affiliates of Mr. Goff, Wilkie S. Colyer, Jr., the Company’s chief executive officer, and others, which resulted in net proceeds of approximately $5.6 million. An additional 360,000 Series C contingent convertible preferred shares were issued in a private placement to the placement agents for the December 2019 Offering and Series C Private Placement, as partial consideration for their services in those offerings. Net proceeds from the December 2019 Offering and Series C Private Placement were used for general corporate purposes, including capital expenditures under the Company’s Joint Development Agreement with Juneau Oil & Gas, LLC (discussed below).

9

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In December 2019, the Company obtained approval from the holders of a majority of the voting power of the Company’s capital stock to increase the number of common shares authorized for issuance from 100,000,000 to 200,000,000 common shares, at which time the Series A preferred shares automatically converted into 7,894,740 shares of common stock, the Series B preferred shares automatically converted into 11,028,380 shares of common stock, and the outstanding preferred shares were cancelled.

In December 2019, the Company entered into a Joint Development Agreement with Juneau Oil & Gas, LLC (“Juneau”), which provides the Company the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf of Mexico. The first such exploratory prospect acquired by the Company, located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline, was determined to be unsuccessful in June 2020. The Company is currently evaluating for future testing a number of exploratory prospects included in the Joint Development Agreement, including its Boss Hogg prospect located in the Eugene Island 298 Area in the shallow waters off of the Louisiana coastline. The Company’s strategy and timing on the testing of the Boss Hogg will be determined during the year based on regulatory considerations, some of which are fluid at this time, and on operational considerations, including the availability of appropriate equipment.

Following the reduction in the Company’s drilling program in the latter half of 2019, which then led to the suspension of onshore drilling in the first quarter of 2020, the Company continued to identify opportunities for cost reductions and operating efficiencies in all areas of its operations, while also searching for new resource acquisition opportunities. Acquisition efforts have been, and will continue to be, focused on PDP-heavy assets where the Company might also be able to leverage its geological and operational experience and expertise to reduce operating expenses, enhance production and identify and develop additional drilling opportunities that the Company believes will enable it to economically grow production and add reserves.

On June 5, 2020, the Company announced the addition of a new corporate business line that includes offering a property management service (or a “fee for service”) for oil and natural gas companies with distressed or stranded assets, or companies with a desire to reduce administrative costs by engaging a contract operator of its oil and natural gas assets. As part of this service offering, the Company entered into a Management Services Agreement (“MSA”) with Mid-Con, effective July 1, 2020, to provide services as contract operator of record on Mid-Con’s oil and natural gas properties, along with certain administrative and management services, in exchange for an annual services fee of $4 million, paid ratably over the twelve month period, plus reimbursement of certain costs and expenses, a deferred fee of $166,666 per month for each month that the agreement is in effect (not to exceed $2 million), to be paid in a lump sum upon termination of the agreement, and warrants to purchase a minority equity ownership in Mid-Con. In connection with the Company’s acquisition of Mid-Con on January 21, 2021, the MSA was terminated, the deferred fee obligation was forgiven, and the warrants were cancelled. See Note 4 – “Acquisitions and Dispositions” for more information. The Company recorded $2.0 million in revenue during the year ended December 31, 2020 related to this MSA with Mid-Con, which is included in “Fee for services revenue” in the Company’s consolidated statements of operations.

On June 8, 2020, the stockholders of the Company, at the Company’s 2020 Annual Meeting of Stockholders, approved an amendment (the “Charter Amendment”) to its Amended and Restated Certificate of Formation with the Secretary of State of the State of Texas to increase the number of authorized shares of common stock, par value of $0.04 per share, of the Company from 200,000,000 shares to 400,000,000 shares, and also approved the conversion of the 2,700,000 shares of the Series C contingent convertible preferred stock, par value $0.04 per share, into 2,700,000 shares of the Company’s common stock. On June 10, 2020, the Company filed the Charter Amendment with the Secretary of State of the State of Texas.

On June 24, 2020, the Company entered into an Open Market Sale Agreement (the “Sale Agreement”) among the Company and Jefferies LLC (the “Sales Agent”). Pursuant to the terms of the Sale Agreement, the Company may sell, from time to time through the Sales Agent in the open market, subject to satisfaction of certain conditions, shares of the Company’s common stock, having an aggregate public offering price of up to $100,000,000 (the “Shares”) (the “ATM Program”). The Company intends to use the net proceeds from any sales through the ATM Program, after deducting the Sales Agent’s commission and the Company’s offering expenses, to repay borrowings under its Credit Agreement and for general corporate purposes, including, but not limited to, acquisitions and exploratory drilling. Under the ATM Program, the Company sold 163,929 shares during the year ended December 31, 2020 for net proceeds of $0.5 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On October 25, 2020, the Company and Mid-Con entered into an agreement and plan of merger providing for the acquisition by the Company of Mid-Con in an all-stock merger transaction in which Mid-Con would become a direct, wholly owned subsidiary of Contango (the “Mid-Con Acquisition”). On October 30, 2020, the Company entered into the Third Amendment (the “Third Amendment”) to its Credit Agreement under which, among other things, would increase the Company’s borrowing base from $75 million to $130.0 million, effective upon the closing of the Mid-Con Acquisition, with an automatic $10.0 million reduction in the borrowing base on March 31, 2021. The Mid-Con acquisition closed on January 21, 2021, with a total of 25,409,164 shares of Contango common stock issued. Upon closing of the Mid-Con Acquisition, the MSA was terminated, and the Company’s borrowing base was increased to $130.0 million. See Note 4 – “Acquisitions and Dispositions” and Note 13 – “Long-Term Debt” for further details.

Concurrently with the announcement of the Mid-Con Acquisition, the Company announced the execution of an agreement with a select group of institutional and accredited investors to sell 26,451,988 shares of common stock, which was completed on October 27, 2020. After deducting the underwriting discount and fees and expenses, the net proceeds were approximately $38.8 million, which were used for the Mid-Con Acquisition and for general corporate purposes, including the repayment of debt outstanding under the Company’s Credit Agreement.

On November 27, 2020, the Company entered into a purchase and sale agreement (the “Purchase Agreement”) with an undisclosed seller 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 Texas and New Mexico (collectively the “Silvertip Acquisition”) for aggregate consideration of approximately $58 million. 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, for a net consideration of approximately $53.2 million (including the $7.0 million deposit previously paid), after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date. See Note 4 – “Acquisitions and Dispositions” for more information.

On December 1, 2020, the Company completed another private placement of 14,193,903 shares of common stock for net proceeds of approximately $21.7 million, after deducting the underwriting discount and fees and expenses. The net proceeds were used to fund the Silvertip Acquisition and for general corporate purposes, including the repayment of debt outstanding under the Company’s Credit Agreement.

2.    Summary of Significant Accounting Policies

Basis of Presentation

The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and 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.

Other Investments

The Company has two seats on the board of directors of Exaro and has significant influence, but not control, over the company. As a result, the Company’s 37% ownership in Exaro is accounted for using the equity method. Under the equity method, the Company’s proportionate share of Exaro’s net income increases the balance of its investment in Exaro, while a net loss or payment of dividends decreases its investment. In the consolidated statements of operations, the Company’s proportionate share of Exaro’s net income is reported as a single line-item in “Gain from investment in affiliates” (net of income taxes).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.

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. 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. 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.

When sales volumes exceed the Company’s entitled share, a production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. Production imbalances have not had and currently do not have a material impact on the financial statements.

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.

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.

Cash Equivalents

Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of December 31, 2020, the Company had $1.4 million in cash and cash equivalents, after transferring cash balances at the end of each day to reduce outstanding debt under the Company’s revolving Credit Agreement to minimize debt service costs. Under the Company’s cash management system, checks issued but not yet presented to banks by the payee frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the consolidated balance sheets. At December 31, 2020, accounts payable included $2.9 million in outstanding checks that had not been presented for payment. At December 31, 2019, accounts payable included $6.1 million in outstanding checks that had not been presented for payment.

Accounts Receivable

The Company sells oil, natural gas and NGLs to a limited number of customers. In addition, the Company participates with other parties in the operation of oil and natural gas wells. Substantially all of the Company’s accounts receivables are due from either purchasers of oil, natural gas and NGLs or participants in oil and natural gas wells for which the Company serves as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions and other pertinent factors. Amounts deemed uncollectible are charged to the allowance.

Accounts receivable allowance for doubtful accounts was $2.3 million and $1.0 million as of December 31, 2020 and 2019, respectively. At December 31, 2020 and 2019, the carrying value of the Company’s accounts receivable approximated fair value.

Oil and Natural Gas Properties - Successful Efforts

The Company follows the successful efforts method of accounting for its oil and natural gas activities. 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 developmental 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 exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred.

The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil or natural gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. During the quarter ended June 30, 2020, the Company drilled an unsuccessful exploratory well in the Gulf of Mexico, resulting in a charge of $10.5 million for drilling and prospect costs included in “Exploration expenses” in the Company’s consolidated statements of operations for the year ended December 31, 2020.

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

Depreciation, depletion and amortization (“DD&A”) is calculated on a field basis using the unit of production method. Lease acquisition costs are amortized over remaining total proved reserves, and capitalized drilling and development costs of producing oil and natural gas properties, including related support equipment and facilities net of salvage value, are amortized over estimated proved developed oil and natural gas reserves. Upon sale or retirement of properties, the cost and related accumulated DD&A are eliminated from the accounts, and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least annually. Revisions are accounted for prospectively as changes in accounting estimates.

Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range between three and 10 years.

Impairment of Oil and Natural Gas Properties

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

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

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. The remainder of 2020 was further adversely affected by the continuation of the COVID-19 pandemic and the actions and measures that countries, states, localities, central banks, international financing and funding organizations, stock markets, businesses and individuals have taken to address the spread of the coronavirus and associated illnesses, the continued volatility of the oil and gas market, and the failure of OPEC and Russia to consistently and fully adhere to the quotas delineated in their agreement. Consequently, during the three months ended March 31, 2020, the Company recorded a $143.3 million non-cash charge for proved property impairment of its onshore properties related to the dramatic decline in commodity prices, the “PV-10” (present value, discounted at a 10% rate) of its proved reserves, and the associated change in its current development plans for its proved undeveloped locations. In the fourth quarter of 2020, the Company recorded an additional $21.1 million non-cash charge for proved property impairment, of which $15.6 million related to its offshore properties as a result of performance revisions in reserves and the decline in gas prices and production yield. The total non-cash proved property impairment recorded during the year ended December 31, 2020 was $164.4 million.

For the year ended December 31, 2019, the Company recognized non-cash proved property impairment expense of $117.8 million due to reserve revisions which resulted from the negative impact of performance and price related revisions to the present value of the Company’s year-end proved reserves, and the relationship of that value to the historical carrying cost of its assets on the balance sheet. Included in the impairment charge was $34.5 million related to the Company’s proved offshore Gulf of Mexico properties, primarily a result of performance revisions associated with the re-evaluation of the projected field costs and recoverable condensate volumes. In addition, the Company recognized onshore proved property impairment expense of $83.3 million. The onshore impairment was due primarily to price and performance revisions, which led to the re-evaluation of the economics and future drilling plans for the proved undeveloped locations, which then resulted in the elimination of certain proved undeveloped locations due to the SEC’s five-year development rule for such locations.

Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, with any such impairment charged to expense in the period. During the year ended December 31, 2020, the Company recorded a $4.3 million non-cash charge for unproved impairment expense related to undeveloped leases in its Central Oklahoma, Western Anadarko and Other Onshore regions. The Company recorded $2.6 million of this impairment expense in the first quarter of 2020, primarily related to leases the Company acquired from White Star and Will Energy in the fourth quarter of 2019, which were expiring in 2020, and the remaining $1.7 million of the impairment expense was recorded in the fourth quarter of 2020, due to leases expiring in 2021, all of which the Company has no plans to extend or develop as a result of the current commodity price environment and the Company’s continued focus on cost saving and production enhancing strategic initiatives.

During the year ended December 31, 2019, the Company recognized impairment expense of approximately $9.2 million related primarily to lease expirations, and near-term expirations, in the Company’s West Texas region.

Asset Retirement Obligations

Asset Retirement and Environmental Obligations (“ASC 410”) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records an asset retirement obligation (“ARO”) to reflect the Company’s legal obligation related to future plugging and abandonment of its oil

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

and natural gas wells, platforms and associated pipelines and equipment. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis, the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations are incurred. The liability is accreted to its present value each period, and the capitalized cost is depleted over the useful life of the related asset. The accretion expense is included in DD&A expense.

The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate.

Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate, changes in the remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, the Company recognizes a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and natural gas properties expense. See Note 12 – “Asset Retirement Obligation” for additional information.

Income Taxes

The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. The Company reviews its tax positions quarterly for tax uncertainties. The Company did not have significant uncertain tax positions as of December 31, 2020. As described in Note 16 – “Income Taxes” with respect to Section 382 Ownership Change, the amount of unrecognized tax benefits did not change materially from December 31, 2019. The amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on its financial position or results of operations. The Company includes interest and penalties in interest income and general and administrative expenses, respectively, in its consolidated statements of operations.

The Company files income tax returns in the United States and various state jurisdictions. The Company’s federal and state tax returns for 2009 – 2020 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable result from oil and natural gas sales or joint interest billings to a limited number of third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. See Note 3 – “Concentration of Credit Risk” for additional information.

Debt Issuance Costs

Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt. On September 17, 2019, the Company entered into the new revolving Credit Agreement with JPMorgan Chase Bank, N.A. and other lenders and incurred $1.8 million of arrangement and upfront fees in connection with the Credit Agreement. On November 1, 2019, the Credit Agreement was amended to add two additional lenders and increase the borrowing base thereunder, and the Company incurred an additional $1.6 million of debt issuance costs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On June 9, 2020, the Credit Agreement was amended to, among other things, reduce the borrowing base. No fees were incurred for the Second Amendment; however, during the three months ended June 30, 2020, the Company expensed $1.0 million of the debt issuance costs discussed above which originally were to be amortized over the life of the loan, due to the reduction in the borrowing base per the Second Amendment. On October 30, 2020, the Company entered into the Third Amendment to the Credit Agreement under which, among other things, increased the Company’s borrowing base from $75.0 million to $130.0 million, effective upon the closing of the Mid-Con Acquisition on January 21, 2021. The Company initially incurred $0.1 million in fees related to the Third Amendment during the three months ended December 31, 2020. During the year ended December 31, 2020, the Company amortized debt issuance costs of $1.6 million related to its Credit Agreement, including the $1.0 million mentioned above. As of December 31, 2020, the remaining balance of these debt issuance costs was $1.8 million, which will be amortized through September 17, 2024, with amortization expense included in the interest expense line item in the Company’s consolidated statements of operations.

In January 2021, the Company incurred an additional $0.9 million in fees related to the Third Amendment becoming effective on January 21, 2021, in connection with the closing of the Mid-Con Acquisition. These fees will also be amortized over the remaining term of the loan.

Stock-Based Compensation

The Company applies the fair value based method to account for stock based compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisite service period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each restricted stock award is estimated as of the date of grant. The fair value of the performance stock units is estimated as of the date of grant using the Monte Carlo simulation pricing model.

Inventory

Inventory consists primarily of casing and tubing stored temporarily, which will be used for drilling or completion of wells. Inventory is recorded at the lower of cost or market using specific identification method.

Derivative Instruments and Hedging Activities

The Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (“ASC 815”). ASC 815 establishes accounting and reporting requirements that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, the Company hedges a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction using variable to fixed swaps and collars. The Company elected to not designate any of its derivative positions for hedge accounting. Accordingly, the net change in the mark-to-market valuation of these positions as well as all payments and receipts on settled derivative contracts are recognized in “Gain (loss) on derivatives, net” on the consolidated statements of operations for the years ended December 31, 2020 and 2019. Derivative instruments with settlement dates within one year are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one year are included in non-current assets or liabilities. The Company calculates the asset or liability for current and non-current derivative instruments for each counterparty based on the settlement dates within the respective contracts. See Note 6 – “Derivative Instruments” for additional information.

Subsidiary Guarantees

Contango Oil & Gas Company, as the parent company (the “Parent Company”), filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent 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 the prospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants with the Parent Company under the registration statement, and the registration statement also registered guarantees of debt securities by the Subsidiary

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Guarantors. The Subsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and any guarantee by the Subsidiary Guarantors will be full and unconditional. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. Finally, the Parent 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 Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party.

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 twelve months or less on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated statements of operations. The Company accounts for lease and non-lease contract components as a lease. The Company has procedures to review any new or modified contracts which contain a physical asset on a quarterly basis and determine if an arrangement is, or contains, a lease and determines the proper treatment. See Note 9 – “Leases” for additional information.

Recent Accounting Pronouncements

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. The FASB subsequently issued ASU 2019-04 (“ASU 2019-04”): Codification Improvements to Topic 326, Financial Instruments - Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments 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 the implementation of ASU 2016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. In November 2019, the FASB issued ASU 2019-10 - Financial Instruments - Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates. This amendment deferred the effective date of ASU 2016-13 from January 1, 2020 to January 1, 2023 for calendar year-end smaller reporting companies, which includes the Company. The Company plans to defer the implementation of ASU 2016-13, and the related updates.

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

In March 2020, the FASB issued ASU 2020-04 - Reference Rate Reform (“Topic 848”): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”). ASU 2020-04 provides optional guidance, for a limited period of time, to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. The amendments in ASU 2020-04 provide optional expedients and exceptions for applying US GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this ASU apply only to contracts, hedging relationships and other transactions that reference LIBOR, or another reference rate, expected to be discontinued because of reference rate reform. The Company is currently assessing the potential impact of ASU 2020-04 on its consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3.    Concentration of Credit Risk

The customer base for the Company is concentrated in the oil and natural gas industry. The Company’s largest three purchasers contributed approximately 36% of the Company’s total production revenues for the year ended December 31, 2020. The Company’s sales to these purchasers are not secured with letters of credit, and in the event of non-payment, the Company could lose up to two months of revenues. The loss of two months of revenues would have a material adverse effect on the Company’s financial position. However, we believe our current purchasers could be replaced by other purchasers under contracts with similar terms and conditions.

4.    Acquisitions and Dispositions

Mid-Con Acquisition

On October 25, 2020, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement’) with Mid-Con and Mid-Con Energy GP, LLC, the general partner of Mid-Con (“Mid-Con GP”), pursuant to which Mid-Con will 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 25,409,164 shares of Contango common stock were issued at the closing of 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 will run the combined company, and Contango’s board of directors will remain intact as the board of directors of the combined company. The combined company is headquartered in Fort Worth, Texas.

The Mid-Con acquisition will be accounted for as a business combination. Therefore, the purchase price will be 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 gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and 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 Company expects to complete the purchase price allocation during the twelve-month period following the acquisition date. 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.

	Purchase Price Allocation
	(in thousands)
Consideration:
Cash	$	14,520
Exchange ratio of Contango shares for Mid-Con common units		1.75
Contango common stock to be issued to Mid-Con unitholders		25,409
Issue price		3.13
Total consideration	$	79,530
Liabilities Assumed:
Accounts payable	$	5,596
Other current liabilities		457
Revolving credit facility		68,487

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Purchase Price Allocation
	(in thousands)
Asset retirement obligations		29,241
Total liabilities assumed	$	103,781
Assets acquired:
Cash and cash equivalents	$	776
Accounts receivable		4,398
Current derivative asset		3,141
Prepaid expenses		162
Proved oil and natural gas properties		172,607
Other property and equipment		730
Other non-current assets		1,497
Total assets acquired	$	183,311

The following unaudited pro forma combined condensed financial data for the years ended December 31, 2020 was derived from the historical financial statements of the Company after giving effect to the Mid-Con acquisition, as if it 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 from Mid-Con. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the assets acquired. The pro forma consolidated statement of operations data has been included for comparative purposes only, is not necessarily indicative of the results that might have occurred had the acquisition taken place on January 1, 2020 and is not intended to be a projection of future results.

(In thousands except for per share amounts)	Year Ended December 31, 2020
Revenues	$	150,569
Net loss	$	(188,178	)
Basic Earnings per share	$	(1.02	)
Diluted earnings per share	$	(1.02	)

Silvertip Acquisition

On November 27, 2020, the Company entered into the Purchase Agreement with an undisclosed seller 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 Texas and New Mexico, for aggregate consideration of approximately $58 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, and a balance of $46.2 million was paid upon closing, after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date.

Juneau Joint Development Agreement

On December 23, 2019, the Company entered into a Joint Development Agreement with Juneau for aggregate consideration of $6.0 million, consisting of $1.69 million in cash and 1,725,000 shares of common stock of the Company. This agreement provides the Company the right to acquire an interest in up to six of Juneau’s exploratory prospects located in the Gulf of Mexico. The first such exploratory prospect acquired by the Company was the Iron Flea prospect located in the Grand Isle Block 45 Area in the shallow waters off of the Louisiana coastline, which was determined to be unsuccessful in June 2020. The Company is currently evaluating for future testing a number of exploratory prospects included in the Joint Development agreement, including the Boss Hogg prospect, located in the Eugene Island 298 Area in the shallow waters off of the Louisiana coastline. Management considers this Boss Hogg prospect to be an excellent complement to its PDP-oriented acquisition strategy and believes it could provide a very compelling economic value proposition, even in the current low oil price environment. The Company is currently working through regulatory considerations and operational factors, including the availability of appropriate equipment, in determining the ultimate strategy for, and timing on, the testing of that prospect.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

White Star Acquisition

On September 30, 2019, the Company entered into an asset purchase and sale agreement with White Star to acquire certain assets and liabilities, including approximately 306,000 net acres located in the STACK, Anadarko and Cherokee operating districts in Oklahoma. The closing of the White Star Acquisition occurred on November 1, 2019, for a total aggregate consideration of $132.5 million. Following adjustments for the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid was approximately $95.7 million in cash.

The White Star Acquisition was accounted for as a business combination. 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 a third-party specialist 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 following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(in thousands)
Consideration:
Cash	$	95,722
Total consideration	$	95,722
Liabilities Assumed:
Accounts payable	$	6,618
Revenue and royalties payable		11,165
Suspended revenue and royalties		22,011
Lease liabilities		3,614
Total liabilities assumed	$	43,408
Assets acquired:
Accounts receivable	$	18,037
Other current assets		1,413
Proved oil and natural gas properties		113,150
Unevaluated properties		2,611
Right-of-use lease assets		3,614
Other assets		305
Total assets acquired	$	139,130

The purchase price allocated to the assets acquired increased to $139.1 million from the previously reported $138.5 million due to an increase in the value of inventory acquired of $1.0 million and a decrease in the value of unevaluated properties acquired of $0.4 million. Approximately $21.4 million of revenues and $16.3 million of direct operating expenses attributed to the White Star Acquisition are included in the Company’s consolidated statements of operations for the period of the closing date on November 1, 2019 through December 31, 2019.

The following unaudited pro forma combined condensed financial data for the year ended December 31, 2019 was derived from the historical financial statements of the Company after giving effect to the White Star Acquisition, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the private placement of the Company’s Series B contingent convertible preferred stock and an increase in borrowings under the Company’s Credit Agreement, the proceeds of which were used to pay the purchase price of the White Star Acquisition, as well as pro forma adjustments based on then currently available information and certain assumptions that the Company believed were reasonable, including the depletion of the fair-valued proved oil and natural gas properties acquired from White Star and the exclusion of acquisition-related costs incurred by the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Company of approximately $1.9 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may have resulted from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the assets acquired. In addition, the results of operations include non-cash impairment expense for White Star based on historical costs and not the fair value of the oil and natural gas properties acquired as reflected in the allocation of the purchase price. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were not deemed material. The pro forma consolidated statements 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, 2018 and is not intended to be a projection of future results.

(In thousands except for per share amounts)	Year Ended December 31, 2019
Revenues	$	207,530
Net loss	$	(265,760	)
Basic Earnings per share	$	(4.20	)
Diluted earnings per share	$	(4.20	)

Will Energy Acquisition

On September 12, 2019, the Company announced it entered into a contribution and purchase agreement with Will Energy to acquire approximately 155,900 net acres located in North Louisiana (8,000 net acres) and the Western Anadarko Basin in Western Oklahoma and the Texas Panhandle (147,900 net acres). Closing of the Will Energy Acquisition occurred on October 25, 2019, for a total aggregate consideration of $23 million. Following adjustments for sales of non-core, non-operated Louisiana properties by Will Energy prior to closing, the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid consisted of $14.0 million in cash and 3.5 million shares of common stock.

Non-Core Assets Sales

During the years ended December 31, 2020 and 2019, the Company completed certain non-core asset sales to enhance its liquidity, eliminate marginal assets and reduce administrative costs. These asset sales provide some immediate liquidity and improve the Company’s balance sheet by removing future asset retirement obligations.

On June 1, 2020, the Company closed on the sale of certain producing and non-producing properties located in its Central Oklahoma and Western Anadarko regions. These non-core, marginally economic properties were a minor portion of the value of properties acquired from Will Energy and were sold in exchange for the buyer’s assumption of the plugging and abandonment liabilities of these properties and revenue held in suspense. The Company recorded a gain of $4.2 million as a result of the buyer’s assumption of the asset retirement obligations associated with the sold properties.

On April 1, 2020, the Company closed on the sale of certain non-producing properties located in its Central Oklahoma region. These properties were a minor portion of the value of properties acquired from White Star and were sold for approximately $0.5 million. The Company recorded a gain of $0.2 million as a result of the buyer’s assumption of the asset retirement obligations associated with the sold properties.

On July 1, 2019, the Company sold certain minor, non-core operated assets located in Frio and Zavala counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.2 million after removal of the asset retirement obligations associated with the sold properties.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5.    Fair Value Measurements

Pursuant to ASC 820, Fair Value Measurements and Disclosures (“ASC 820”), 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. ASC 820 defines fair value as 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). ASC 820 establishes a fair value hierarchy that 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.

As required by ASC 820, 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.

Derivatives are recorded at fair value at the end of each reporting period. The Company records the net change in the fair value of these positions in “Gain (loss) on derivatives, net” in the Company’s 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 the Company 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 6 – “Derivative Instruments” for additional discussion of derivatives.

During the year ended December 31, 2020, the Company’s derivative contracts were with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. As such, the Company was exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company did not anticipate any nonperformance. The Company did not post collateral under any of these contracts as they are secured under the Credit Agreement or under unsecured lines of credit with non-bank counterparties.

Estimates of the fair value of financial instruments are made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been 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 interest rate approximates current market rates and are re-set at least every three months. See Note 13 – “Long-Term Debt” for further information.

Fair value estimates used for non-financial assets are evaluated at fair value on a non-recurring basis and include oil and natural gas properties evaluated for impairment when facts and circumstances indicate that there may be an impairment. If the unamortized cost of properties exceeds the undiscounted cash flows related to the properties, the value of the properties is compared to the fair value estimated as discounted cash flows related to the risk-adjusted proved, probable and possible reserves related to the properties. Fair value measurements based on these inputs are classified as Level 3.

Impairments

Contango 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 and probable 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 ARO 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 at inception.

6.    Derivative Instruments

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

As of December 31, 2020, the Company’s oil and natural gas derivative positions consisted of “swaps”. 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. The Company has also, from time to time, entered into “costless collars” derivative positions. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put, which establishes a minimum price.

It is the Company’s practice to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company did not post collateral under any of these contracts as they are secured under the Credit Agreement or under unsecured lines of credit with non-bank counterparties.

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. See Note 5 – “Fair Value Measurements” for additional information.

The Company currently has derivative contracts in place to cover production periods through the first quarter of 2023, which include the hedges novated from Mid-Con and the additional hedges entered into in the first quarter of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2021, as discussed below. These contracts include oil hedges for 2.1 MMBbls of 2021 production with an average floor price of $54.85 per barrel and 1.4 MMBbls of 2022 production with an average floor price of $50.24 per barrel. For natural gas, the Company’s derivative contracts include 12.4 Bcf of 2021 production with an average floor price of $2.62 per MMBtu and 10.1 Bcf of 2022 production with an average floor price of $2.60 per MMBtu. Approximately 97% of the Company’s hedges are swaps, and the Company has no three-way collars or short puts.

The Company had the following financial derivative contracts in place as of December 31, 2020:

Commodity	Period	Derivative	Volume/Month		Price/Unit				Fair Value
Oil	Jan 2021 - March 2021	Swap	19,000	Bbls	$	50.00	(1	)		78
Oil	April 2021 - July 2021	Swap	12,000	Bbls	$	50.00	(1	)		71
Oil	Aug 2021 - Sept 2021	Swap	10,000	Bbls	$	50.00	(1	)		39
Oil	Jan 2021 - July 2021	Swap	62,000	Bbls	$	52.00	(1	)		1,490
Oil	Aug 2021 - Sept 2021	Swap	55,000	Bbls	$	52.00	(1	)		434
Oil	Oct 2021 - Dec 2021	Swap	64,000	Bbls	$	52.00	(1	)		840
Oil	April 2022 - Oct 2022	Swap	25,000	Bbls	$	42.04	(1	)		(784	)
Natural Gas	Jan 2021 - March 2021	Swap	185,000	MMBtus	$	2.505	(2	)		(1	)
Natural Gas	April 2021 - July 2021	Swap	120,000	MMBtus	$	2.505	(2	)		(43	)
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	MMBtus	$	2.505	(2	)		(4	)
Natural Gas	Jan 2021 - March 2021	Swap	185,000	MMBtus	$	2.508	(2	)		(3	)
Natural Gas	April 2021 - July 2021	Swap	120,000	MMBtus	$	2.508	(2	)		(44	)
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	MMBtus	$	2.508	(2	)		(4	)
Natural Gas	Jan 2021 - March 2021	Swap	650,000	MMBtus	$	2.508	(2	)		(6	)
Natural Gas	April 2021 - Oct 2021	Swap	400,000	MMBtus	$	2.508	(2	)		(400	)
Natural Gas	Nov 2021 - Dec 2021	Swap	580,000	MMBtus	$	2.508	(2	)		(402	)
Natural Gas	April 2021 - Nov 2021	Swap	70,000	MMBtus	$	2.36	(2	)		(175	)
Natural Gas	Dec 2021	Swap	350,000	MMBtus	$	2.36	(2	)		(195	)
Natural Gas	Jan 2022 - March 2022	Swap	780,000	MMBtus	$	2.542	(2	)		(865	)
Natural Gas	April 2022 - July 2022	Swap	650,000	MMBtus	$	2.515	(2	)		252
Natural Gas	Aug 2022 - Oct 2022	Swap	350,000	MMBtus	$	2.515	(2	)		71
Natural Gas	Jan 2022 - March 2022	Swap	250,000	MMBtus	$	3.149	(2	)		179
Total net fair value of derivative instruments (in thousands)									$	528

(1) Based on West Texas Intermediate oil prices.

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

The Company had the following financial derivative contracts in place as of December 31, 2019:

Commodity	Period	Derivative	Volume/Month	Price/Unit					Fair Value
Oil	Jan 2020 - June 2020	Swap	22,000	Bbls	$	57.74	(1	)		(289	)
Oil	July 2020 - Dec 2020	Swap	15,000	Bbls	$	57.74	(1	)		68
Oil	Jan 2020 - March 2020	Swap	2,700	Bbls	$	54.33	(1	)		(51	)
Oil	April 2020 - June 2020	Swap	2,500	Bbls	$	54.33	(1	)		(37	)
Oil	July 2020	Swap	5,500	Bbls	$	54.33	(1	)		(21	)
Oil	Aug 2020 - Oct 2020	Swap	2,500	Bbls	$	54.33	(1	)		(21	)
Oil	Nov 2020 - Dec 2020	Swap	3,500	Bbls	$	54.33	(1	)		(12	)
Oil	Jan 2020 - Feb 2020	Swap	42,500	Bbls	$	54.70	(1	)		(517	)
Oil	March 2020 - July 2020	Swap	37,500	Bbls	$	54.70	(1	)		(842	)
Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.70	(1	)		(354	)
Oil	Jan 2020 - Feb 2020	Swap	42,500	Bbls	$	54.58	(1	)		(527	)
Oil	March 2020 - July 2020	Swap	37,500	Bbls	$	54.58	(1	)		(864	)
Oil	Aug 2020 - Dec 2020	Swap	35,000	Bbls	$	54.58	(1	)		(373	)
Oil	Jan 2020 - Oct 2020	Collar	3,442	Bbls	$	52.00 - 65.70	(1	)		18

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Commodity	Period	Derivative	Volume/Month	Price/Unit					Fair Value
Oil	Jan 2021 - March 2021	Swap	19,000	Bbls	$	50.00	(1	)		(291	)
Oil	April 2021 - July 2021	Swap	12,000	Bbls	$	50.00	(1	)		(196	)
Oil	Aug 2021 - Sept 2021	Swap	10,000	Bbls	$	50.00	(1	)		(67	)
Oil	Jan 2021 - July 2021	Swap	62,000	Bbls	$	52.00	(1	)		(1,122	)
Oil	Aug 2021 - Sept 2021	Swap	55,000	Bbls	$	52.00	(1	)		(157	)
Oil	Oct 2021 - Dec 2021	Swap	64,000	Bbls	$	52.00	(1	)		(184	)
Natural Gas	Jan 2020 - March 2020	Swap	425,000	MMBtus	$	2.841	(2	)		856
Natural Gas	Jan 2020 - March 2020	Collar	225,000	MMBtus	$	2.45 - 3.40	(2	)		209
Natural Gas	April 2020 - July 2020	Swap	400,000	MMBtus	$	2.532	(2	)		493
Natural Gas	Aug 2020 - Oct 2020	Swap	40,000	MMBtus	$	2.532	(2	)		25
Natural Gas	Nov 2020 - Dec 2020	Swap	375,000	MMBtus	$	2.696	(2	)		134
Natural Gas	Jan 2020 - March 2020	Swap	300,000	MMBtus	$	2.53	(2	)		325
Natural Gas	April 2020 - July 2020	Swap	400,000	MMBtus	$	2.53	(2	)		490
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	MMBtus	$	2.53	(2	)		223
Natural Gas	Jan 2020 - March 2020	Swap	300,000	MMBtus	$	2.532	(2	)		327
Natural Gas	April 2020 - July 2020	Swap	400,000	MMBtus	$	2.532	(2	)		493
Natural Gas	Aug 2020 - Dec 2020	Swap	350,000	MMBtus	$	2.532	(2	)		226
Natural Gas	Jan 2021 - March 2021	Swap	185,000	MMBtus	$	2.505	(2	)		(78	)
Natural Gas	April 2021 - July 2021	Swap	120,000	MMBtus	$	2.505	(2	)		99
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	MMBtus	$	2.505	(2	)		4
Natural Gas	Jan 2021 - March 2021	Swap	185,000	MMBtus	$	2.508	(2	)		(75	)
Natural Gas	April 2021 - July 2021	Swap	120,000	MMBtus	$	2.508	(2	)		104
Natural Gas	Aug 2021 - Sept 2021	Swap	10,000	MMBtus	$	2.508	(2	)		4
Natural Gas	Jan 2021 - March 2021	Swap	650,000	MMBtus	$	2.508	(2	)		(268	)
Natural Gas	April 2021 - Oct 2021	Swap	400,000	MMBtus	$	2.508	(2	)		544
Natural Gas	Nov 2021 - Dec 2021	Swap	580,000	MMBtus	$	2.508	(2	)		20
Total net fair value of derivative instruments (in thousands)									$	(1,684	)

(1) Based on West Texas Intermediate oil prices.

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

In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI – Cushing oil differential swap price of $0.05 per barrel of oil. The agreement fixed the Company’s exposure to that differential on 12,000 barrels of oil per month for January 2020 through June 2020 and 10,000 barrels per month for July 2020 through December 2020. The fair value of this costless swap agreement was in a liability position of $0.1 million as of December 31, 2019.

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.

Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset or liability” on the Company’s consolidated balance sheet and include swaps that are carried at fair value.

25

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

	Gross			Netting (1)		Total
Assets	$	4,176		$	—	$	4,176
Liabilities	$	(5,971	)	$	—	$	(5,971	)

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

Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset or liability” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value.

The following table summarizes the effect of derivative contracts on the Consolidated Statements of Operations for the years ended December 31, 2020 and 2019 (in thousands):

	Year Ended December 31,
Contract Type	2020			2019
Crude oil contracts	$	18,561		$	1,614
Natural gas contracts		6,703			1,002
Realized gain	$	25,264		$	2,616
Crude oil contracts	$	8,120		$	(10,012	)
Natural gas contracts		(5,799	)		4,039
Unrealized gain (loss)	$	2,321		$	(5,973	)
Gain (loss) on derivatives, net	$	27,585		$	(3,357	)

In conjunction with the closing of the Mid-Con Acquisition in January 2021, the Company acquired the following additional derivative contracts via novation from Mid-Con:

Commodity	Period	Derivative	Volume/Month	Price/Unit
Oil	Jan 2021	Swap	20,883	Bbls	$	55.78	(1	)
Oil	Feb 2021	Swap	20,804	Bbls	$	55.78	(1	)
Oil	March 2021	Swap	20,725	Bbls	$	55.78	(1	)
Oil	April 2021	Swap	20,647	Bbls	$	55.78	(1	)
Oil	May 2021	Swap	20,563	Bbls	$	55.78	(1	)
Oil	June 2021	Swap	20,487	Bbls	$	55.78	(1	)
Oil	July 2021	Swap	20,412	Bbls	$	55.78	(1	)
Oil	Aug 2021	Swap	20,301	Bbls	$	55.78	(1	)
Oil	Sept 2021	Swap	20,228	Bbls	$	55.78	(1	)
Oil	Oct 2021	Swap	20,155	Bbls	$	55.78	(1	)
Oil	Nov 2021	Swap	20,084	Bbls	$	55.78	(1	)
Oil	Dec 2021	Swap	20,012	Bbls	$	55.78	(1	)
Oil	Jan 2021	Collar	20,883	Bbls	$	52.00-58.80	(1	)
Oil	Feb 2021	Collar	20,804	Bbls	$	52.00-58.80	(1	)
Oil	March 2021	Collar	20,725	Bbls	$	52.00-58.80	(1	)
Oil	April 2021	Collar	20,647	Bbls	$	52.00-58.80	(1	)
Oil	May 2021	Collar	20,563	Bbls	$	52.00-58.80	(1	)
Oil	June 2021	Collar	20,487	Bbls	$	52.00-58.80	(1	)
Oil	July 2021	Collar	20,412	Bbls	$	52.00-58.80	(1	)
Oil	Aug 2021	Collar	20,301	Bbls	$	52.00-58.80	(1	)
Oil	Sept 2021	Collar	20,228	Bbls	$	52.00-58.80	(1	)
Oil	Oct 2021	Collar	20,155	Bbls	$	52.00-58.80	(1	)
Oil	Nov 2021	Collar	20,084	Bbls	$	52.00-58.80	(1	)
Oil	Dec 2021	Collar	20,012	Bbls	$	52.00-58.80	(1	)

(1) Based on West Texas Intermediate oil prices.

26

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In the first quarter of 2021, the Company entered into the following additional derivative contracts:

Commodity	Period	Derivative	Volume/Month		Price/Unit
Oil	March 2021 - Oct 2021	Swap	25,000	Bbls	$	54.77	(1	)
Oil	Nov 2021 - Dec 2021	Swap	15,000	Bbls	$	54.77	(1	)
Oil	March 2021	Swap	50,000	Bbls	$	63.31	(1	)
Oil	April 2021	Swap	50,000	Bbls	$	63.13	(1	)
Oil	May 2021	Swap	50,000	Bbls	$	62.71	(1	)
Oil	June 2021	Swap	50,000	Bbls	$	62.17	(1	)
Oil	July 2021	Swap	50,000	Bbls	$	61.50	(1	)
Oil	Aug 2021	Swap	50,000	Bbls	$	60.94	(1	)
Oil	Sep 2021	Swap	50,000	Bbls	$	60.38	(1	)
Oil	Oct 2021	Swap	50,000	Bbls	$	59.89	(1	)
Oil	Nov 2021	Swap	50,000	Bbls	$	59.46	(1	)
Oil	Dec 2021	Swap	50,000	Bbls	$	59.01	(1	)
Oil	Jan 2022	Swap	60,000	Bbls	$	52.94	(1	)
Oil	Feb 2022	Swap	60,000	Bbls	$	52.65	(1	)
Oil	March 2022	Swap	60,000	Bbls	$	52.29	(1	)
Oil	April 2022	Swap	47,500	Bbls	$	51.98	(1	)
Oil	May 2022	Swap	45,000	Bbls	$	51.71	(1	)
Oil	June 2022	Swap	45,000	Bbls	$	51.41	(1	)
Oil	July 2022	Swap	45,000	Bbls	$	51.13	(1	)
Oil	Aug 2022	Swap	45,000	Bbls	$	50.89	(1	)
Oil	Sep 2022	Swap	45,000	Bbls	$	50.65	(1	)
Oil	Oct 2022	Swap	45,000	Bbls	$	50.45	(1	)
Oil	Nov 2022	Swap	55,000	Bbls	$	50.26	(1	)
Oil	Dec 2022	Swap	55,000	Bbls	$	50.22	(1	)
Oil	Jan 2023	Swap	57,500	Bbls	$	49.81	(1	)
Oil	Feb 2023	Swap	57,500	Bbls	$	49.63	(1	)
Oil	Jan 2022	Swap	60,000	Bbls	$	52.96	(1	)
Oil	Feb 2022	Swap	60,000	Bbls	$	52.66	(1	)
Oil	March 2022	Swap	60,000	Bbls	$	52.27	(1	)
Oil	April 2022	Swap	47,500	Bbls	$	51.96	(1	)
Oil	May 2022	Swap	45,000	Bbls	$	51.72	(1	)
Oil	June 2022	Swap	45,000	Bbls	$	51.42	(1	)
Oil	July 2022	Swap	45,000	Bbls	$	51.13	(1	)
Oil	Aug 2022	Swap	45,000	Bbls	$	50.90	(1	)
Oil	Sep 2022	Swap	45,000	Bbls	$	50.66	(1	)
Oil	Oct 2022	Swap	45,000	Bbls	$	50.47	(1	)
Oil	Nov 2022	Swap	55,000	Bbls	$	50.26	(1	)
Oil	Dec 2022	Swap	55,000	Bbls	$	50.01	(1	)
Oil	Jan 2023	Swap	57,500	Bbls	$	49.79	(1	)
Oil	Feb 2023	Swap	57,500	Bbls	$	49.62	(1	)
Natural Gas	March 2021	Swap	100,000	MMBtus	$	2.96	(2	)
Natural Gas	April 2021 - July 2021	Swap	350,000	MMBtus	$	2.96	(2	)
Natural Gas	Aug 2021 - Oct 2021	Swap	500,000	MMBtus	$	2.96	(2	)
Natural Gas	Nov 2021	Swap	450,000	MMBtus	$	2.96	(2	)
Natural Gas	April 2022	Swap	175,000	MMBtus	$	2.51	(2	)
Natural Gas	May 2022 - July 2022	Swap	150,000	MMBtus	$	2.51	(2	)
Natural Gas	Aug 2022 - Oct 2022	Swap	400,000	MMBtus	$	2.51	(2	)
Natural Gas	Nov 2022 - Feb 2023	Swap	750,000	MMBtus	$	2.72	(2	)

(1) Based on West Texas Intermediate oil prices.

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

27

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7.    Stock Based Compensation

Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under its compensation plan at the time (the “2009 Plan”) for the benefit of all employees through a Cash Incentive Bonus Plan (“CIBP”) and a Long-Term Incentive Plan (“LTIP”). The specific targeted performance measures under these sub-plans are approved by the Compensation Committee and/or the Company’s board of directors (the “Board”). Upon achieving the performance levels established each year, bonus awards under the CIBP and LTIP will be calculated as a percentage of base salary of each employee for the plan year. The CIBP and LTIP plan awards for each year are expected to be disbursed in the first quarter of the following year. Employees must be employed by the Company at the time that awards are disbursed to be eligible.

The CIBP awards will be paid in cash while LTIP awards will consist of restricted common stock, performance stock units and/or stock options. The number of shares of restricted common stock and the number of shares underlying the stock options granted will be determined based upon the fair market value of the common stock on the date of the grant.

Third Amended and Restated 2009 Incentive Compensation Plan

As of December 31, 2020, the Company had in place the Contango Oil & Gas Company Third Amended and Restated 2009 Incentive Compensation Plan (“the Third Amended 2009 Plan”) which allows for stock options, restricted stock or performance stock units to be awarded to officers, directors and employees as a performance-based award.

On March 21, 2017, the Board amended and restated the Company’s then existing incentive compensation plan through the adoption of the Second Amended 2009 Plan. The Second Amended 2009 Plan provides for both cash awards and equity awards to officers, directors, employees or consultants of the Company. On June 8, 2020 the Board amended and restated the Second Amended 2009 Plan through the adoption of the Third Amended 2009 Plan, which, among other things, increased the number of shares of the Company’s common stock authorized for issuance pursuant to the Third Amended 2009 Plan by 9,000,000 shares and increased the maximum aggregate number of shares of common stock that may be granted to any individual during any calendar year from 250,000 to 1,000,000. Awards made under the Third Amended 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board.

Under the terms of the Third Amended 2009 Plan, shares of the Company’s common stock may be issued for plan awards. Stock options under the Third Amended 2009 Plan must have an exercise price of each option equal to or greater than the market price of the Company’s common stock on the date of grant. The Company may grant officers and employees both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified as incentive stock options. Options granted generally expire after five or ten years. The vesting schedule for all equity awards varies from immediately to over a three-year period. As of December 31, 2020, the Company had approximately 6.2 million shares of equity awards available for future grant under the Third Amended 2009 Plan, assuming performance stock units are settled at 100% of target.

2005 Stock Incentive Plan

The 2005 Plan was adopted by the Company’s Board in conjunction with the merger with Crimson Exploration, Inc. This plan expired on February 25, 2015, and therefore, no additional shares are available for grant.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Stock Options

A summary of stock options as of and for the years ended December 31, 2020 and 2019 is presented in the table below (dollars in thousands, except per share data):

	Year Ended December 31,
	2020					2019
	Shares Under Options			Weighted Average Exercise Price		Shares Under Options			Weighted Average Exercise Price
Outstanding, beginning of the period		20,964		$	58.53		33,637		$	55.82
Exercised		—		$	—		—		$	—
Expired / Forfeited		(1,117	)	$	39.00		(12,673	)	$	51.34
Outstanding, end of year		19,847		$	59.62		20,964		$	58.53
Aggregate intrinsic value	$	—				$	—
Exercisable, end of year		19,847		$	59.62		20,964		$	58.53
Aggregate intrinsic value	$	—				$	—
Available for grant, end of the period*		6,240,312					1,480,389
Weighted average fair value of options granted during the period	$	—				$	—

* Assumes performance stock units are settled at 100% of target.

During the years ended December 31, 2020 and 2019, the Company did not issue any stock options. During the years ended December 31, 2020 and December 31, 2019, 1,117 and 12,673 stock options previously issued were forfeited by former employees, respectively.

As of December 31, 2020, there were 19,847 stock options vested and exercisable under the 2005 Plan. The exercise price for such options ranges from $28.96 to $60.33 per share, with an average remaining contractual life of 0.2 years.

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 years ended December 31, 2020 and 2019, there was no excess tax benefit recognized. See Note 2 – “Summary of Significant Accounting Policies”.

Compensation expense related to employee stock option grants are 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.

During the years ended December 31, 2020 and 2019, the Company did not recognize any stock option expense. The aggregate intrinsic value of stock options exercised/forfeited during each of the years ended December 31, 2020 and 2019 was zero.

Restricted Stock

During the year ended December 31, 2020, the Company issued 1,041,365 restricted stock awards to new and existing employees, which vest over three years, as part of their overall compensation package. During the year ended December 31, 2020, the Company issued 152,248 restricted stock awards to the members of the board of directors, which vest on the one-year anniversary of the date of grant, as well as an additional 50,914 restricted stock awards, in lieu of cash fees earned for the third quarter of 2020, which vested immediately. During the year ended December 31, 2020, 55,064 restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares granted during the year was $2.22, with a total grant date fair value of approximately $2.8 million with no adjustment for an estimated weighted average forfeiture rate.

During the year ended December 31, 2019, the Company issued 307,650 restricted stock awards to new and existing employees, which vest over three years, plus an additional 80,410 restricted stock awards to the members of the board of directors, which vest on the one-year anniversary of the date of grant, as part of their overall compensation package. During the year ended December 31, 2019, 91,346 restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares granted during the year was $2.91, with a total grant date fair value of approximately $1.1 million with no adjustment for an estimated weighted average forfeiture rate.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Restricted stock activity as of December 31, 2020 and 2019 and for the years then ended is presented in the table below (dollars in thousands, except per share data):

	2020							2019
	Restricted Shares			Weighted Average Fair Value		Aggregate Intrinsic Value		Restricted Shares			Weighted Average Fair Value		Aggregate Intrinsic Value
Outstanding, beginning of the period		403,221		$	3.66	$	214		459,621		$	7.26	$	662
Granted		1,244,527			2.22		65		388,060			2.91		—
Vested		(289,636	)		3.48		700		(353,114	)		7.41		1,171
Canceled / Forfeited		(55,064	)		2.45		16		(91,346	)		4.08		41
Not vested, end of the period		1,303,048			2.38		228		403,221			3.66		214

The Company recognized approximately $1.3 million and $1.9 million in restricted stock compensation expense during the years ended December 31, 2020 and 2019, respectively, for restricted shares granted to its officers, employees and directors. The lower 2020 expense is primarily related to the issuance of stock in the third quarter of 2020 as compared to stock issued in the first quarter of 2019. As of December 31, 2020, there were 1,303,048 shares of unvested restricted stock outstanding, and an additional $2.3 million of compensation expense related to restricted stock remains to be recognized over the remaining vesting period of 2.1 years.

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 the Compensation Committee intends to settle the PSUs 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.

During the year ended December 31, 2020, the Company granted 2,846,140 PSUs to executive officers and certain employees as part of their overall compensation package. The performance period will be measured between May 1, 2020 and April 30, 2023. These granted PSUs were valued at a weighted average fair value of $4.90 per unit. All fair value prices were determined using the Monte Carlo simulation model. In January 2020, 77,485 shares of the PSUs granted in 2017 vested, of which 22,972 PSUs were withheld for taxes, and are included with the restricted stock activity in the consolidated statement of shareholders’ equity. In December 2020, 68,476 shares of the PSUs granted in 2018 vested, of which 18,284 PSUs were withheld for taxes and are included with the restricted stock activity in the consolidated statement of shareholders’ equity. No PSUs were forfeited during the year ended December 31, 2020. The Company recognized approximately $3.0 million in stock compensation expense related to PSUs during 2020. As of December 31, 2020, an additional $11.7 million of compensation expense related to PSUs remained to be recognized over the remaining vesting period of 2.3 years.

During the year ended December 31, 2019, the Company granted 117,105 PSUs to executive officers and employees as part of their overall compensation package, which will be measured between January 1, 2019 and December 31, 2021, and were valued at a weighted average fair value of $6.42 per unit. All fair value prices were

30

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

determined using the Monte Carlo simulation model. During the year ended December 31, 2019, 71,945 PSUs were forfeited by former employees, including 49,773 PSU forfeitures due to the resignations of the Company’s former Senior Vice President of Exploration and Senior Vice President of Operations and Engineering in February 2019. The Company only recognized approximately $0.5 million in stock compensation expense related to PSUs during 2019, primarily due to the expiration of PSUs which failed to meet their target as of December 31, 2018 and the above referenced forfeitures.

8.    Share Repurchase Program

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 or through privately negotiated transactions. Purchases are made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market, and when the Company believes its stock price to be undervalued. Repurchased shares of common stock become authorized but unissued shares and may be issued in the future for general corporate and other purposes. No shares were purchased during the years ended December 31, 2020 and 2019. As of December 31, 2020, the Company had $31.8 million available under the share repurchase program for future purchases; however, repurchases could be limited by provisions of the Company’s Credit Agreement.

9.    Leases

As of January 1, 2019, the Company adopted Accounting Standards Codification Topic 842 – Leases (“ASC 842”), which requires lessees to recognize 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.

During the year ended December 31, 2020, the Company entered into new compressor contracts with lease terms of twelve months or more, which qualify as operating leases. The Company also entered into new contracts for vehicles and office equipment with lease terms of twelve months or more, which qualify as finance leases. As of December 31, 2020, the Company’s operating leases were for compressors and office space for two corporate offices and three field offices, while the Company’s finance leases were for vehicles and office equipment. These leases do not have a material net impact on the Company’s consolidated financial statements.

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

	December 31, 2020			December 31, 2019
Operating lease right of use asset (1)	$	2,452		$	4,316
Operating lease liability - current (2)	$	(1,832	)	$	(2,597	)
Operating lease liability - long-term (3)		(522	)		(1,738	)
Total operating lease liability	$	(2,354	)	$	(4,335	)
Financing lease right of use asset (1)	$	2,996		$	1,569
Financing lease liability - current (2)	$	(940	)	$	(524	)
Financing lease liability - long-term (3)		(2,102	)		(1,051	)
Total financing lease liability	$	(3,042	)	$	(1,575	)

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

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

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

The Company’s leases generally do not provide an implicit rate, and therefore the Company uses its incremental borrowing rate as the discount rate when measuring operating 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. For operating leases existing prior to January 1, 2019, the incremental borrowing rate as of January 1, 2019 was used for the remaining lease term.

31

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

	December 31, 2020			December 31, 2019
Weighted Average Remaining Lease Terms (in years):
Operating leases		1.47			2.16
Financing leases		3.24			3.14
Weighted Average Discount Rate:
Operating leases		5.72	%		6.04	%
Financing leases		5.92	%		6.24	%

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

	December 31, 2020
	Operating Leases			Financing Leases
2021	$	1,906		$	1,094
2022		240			980
2023		170			823
2024		158			459
Total future minimum lease payments		2,474			3,356
Less: imputed interest		(120	)		(314	)
Present value of lease liabilities	$	2,354		$	3,042

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

	Three Months Ended December 31, 2020		Three Months Ended December 31, 2019
Operating lease cost (1) (2)	$	843	$	542
Financing lease cost - amortization of right-of-use assets		231		87
Financing lease cost - interest on lease liabilities		47		17
Administrative lease cost (3)		19		19
Short-term lease cost (1) (4)		360		741
Total lease cost	$	1,500	$	1,406

(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 of more.

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

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

The following table summarizes expenses related to the Company’s leases for the years ended December 31, 2020 and December 31, 2019 (in thousands):

	Year Ended December 31, 2020		Year Ended December 31, 2019
Operating lease cost (1) (2)	$	3,055	$	742
Financing lease cost - amortization of right-of-use assets		642		92
Financing lease cost - interest on lease liabilities		131		18
Administrative lease cost (3)		75		75
Short-term lease cost (1) (4)		1,974		4,101
Total lease cost	$	5,877	$	5,028

(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.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(2) Costs related to office leases and compressors with lease terms of twelve months of more. Higher costs in 2020 due to additional leases related to the properties acquired from Will Energy and White Star during the three months ended December 31, 2019.

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

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

There were $3.2 million and $0.9 million in cash payments related to operating leases and financing leases, respectively, during the year ended December 31, 2020. There were $0.8 million and $0.1 million in cash payments related to operating leases and financing leases, respectively, during the year ended December 31, 2019.

10.    Other Financial Information

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

	December 31, 2020			December 31, 2019
Accounts receivable:
Trade receivables	$	20,306		$	21,110
Receivable for Alta Resources distribution		1,712			1,712
Joint interest billings		15,637			13,104
Income taxes receivable		268			509
Other receivables		2,209			4,126
Allowance for doubtful accounts (1)		(2,270	)		(994	)
Total accounts receivable	$	37,862		$	39,567
Prepaid Expenses:
Prepaid insurance	$	2,825		$	683
Other (2)		535			508
Total Prepaid Expenses	$	3,360		$	1,191
Accounts payable and accrued liabilities:
Royalties and revenue payable	$	23,701		$	15,905
Legal suspense related to revenues (3)		27,983			33,739
Advances from partners (4)		76			6,733
Accrued exploration and development (4)		490			8,210
Trade payables		14,273			14,086
Accrued general and administrative expenses (5)		6,191			12,037
Accrued operating expenses		5,755			5,794
Accrued operating and finance leases		2,772			3,120
Other accounts payable and accrued liabilities		2,729			4,969
Total accounts payable and accrued liabilities	$	83,970		$	104,593

(1) Increase in 2020 primarily due to the additional properties acquired from Will Energy and White Star.

(2) Other prepaids primarily includes software licenses.

(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) Decrease in 2020 due to a decrease in drilling and completion activity. In response to the dramatic decline in commodity prices in the first quarter of 2020, the Company suspended further operated drilling in its West Texas area, and in its other onshore areas.

(5) The December 31, 2019 balance includes an accrual of $6.3 million for a legal judgment that was paid in April 2020. See Note 14 – “Commitment and Contingencies” for further information.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the years ended December 31, 2020 and 2019, in thousands:

	Year Ended December 31,
	2020			2019
Cash payments:
Interest payments	$	3,592		$	7,761
Income tax payments, net of cash refunds		293			668
Non-cash items excluded from investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures		(7,615	)		1,841

11.    Investment in Exaro Energy III LLC

Through the Company’s wholly-owned subsidiary, Contaro Company (“Contaro”), the Company committed to invest up to $67.5 million in Exaro for an ownership interest of approximately 37%. The aggregate commitment of all the Exaro investors was approximately $183 million. The Company did not make any contributions during the year ended December 31, 2020 and has no plans to invest additional funds in Exaro, as the commitment to invest in Exaro expired on March 31, 2017. As of December 31, 2020, the Company had invested approximately $46.9 million. Contango’s share in the equity of Exaro at December 31, 2020 was approximately $6.8 million.

The Company’s share in Exaro’s results of operations recognized for the years ended December 31, 2020 and 2019 was a gain of approximately $27,000, net of zero tax expense and a gain of approximately $1.0 million, net of zero tax, respectively.

12.    Asset Retirement Obligation

The Company accounts for its retirement obligation of long lived assets by recording the net present value of a liability for an ARO in the period in which it is incurred. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

Activities related to the Company’s ARO during the years ended December 31, 2020 and 2019 were as follows (in thousands):

	Year Ended December 31,
	2020			2019
Balance as of the beginning of the period	$	51,665		$	13,497
Liabilities incurred during period		5			256
Liabilities settled during period		(338	)		(1,380	)
Accretion		2,702			1,062
Sales		(5,239	)		(816	)
Acquisitions		—			37,596
Change in estimate		3,978			1,450
Balance as of the end of the period	$	52,773		$	51,665

All of the total liabilities incurred during the years ended December 31, 2020 and 2019 were related to new wells drilled during the period. All of the total liabilities settled during the years ended December 31, 2020 and 2019 were related to wells plugged and abandoned during the period. The acquisitions refer to new liabilities assumed from the properties acquired in 2019 from White Star and Will Energy. The change in estimate relates to year-end adjustments for updated estimated plugging and abandonment costs, primarily in the Company’s Central Oklahoma and Western Anadarko regions.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13.    Long-Term Debt

Credit Agreement

On September 17, 2019, the Company entered into its new revolving Credit Agreement with JPMorgan Chase Bank, N.A. and other lenders, which established a borrowing base of $65 million.

The borrowing base is subject to semi-annual redeterminations which will occur on or around May 1st and November 1st of each year. The Credit Agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy Acquisition and White Star Acquisition, to add two additional lenders and increase the borrowing base thereunder to $145 million. On June 9, 2020, the Company entered into the Second Amendment to the Credit Agreement (the “Second Amendment”). The Second Amendment redetermined the borrowing base at $95 million, among other things, pursuant to the regularly scheduled redetermination process. The Second Amendment also provided for further $10 million automatic reductions in the borrowing base on each of June 30, 2020 and September 30, 2020. 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 4 – “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 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, (iv) addition of three new lenders to the lender group. As of December 31, 2020, the borrowing base was $75 million. In connection with the closing of the Mid-Con Acquisition on January 21, 2021, the borrowing base increased automatically to $130.0 million. The next regularly scheduled borrowing base redetermination is on or before May 1, 2021.

Initially, the Company incurred $1.8 million of arrangement and upfront fees in connection with the Credit Agreement and incurred an additional $1.6 million in fees for the first amendment to the Credit Agreement, all to be amortized over the remaining term of the Credit Agreement. No fees were incurred for the Second Amendment; however, during the three months ended June 30, 2020, the Company expensed $1.0 million of the debt issuance costs discussed above, which originally were to be amortized over the life of the loan, due to the reduction in the borrowing base per the Second Amendment. The Company initially incurred $0.1 million in fees related to the Third Amendment during the three months ended December 31, 2020. During the year ended December 31, 2020, the Company amortized debt issuance costs of $1.6 million related to the Credit Agreement, including the $1.0 million mentioned above. As of December 31, 2020, the remaining balance of these fees was $1.8 million, which will be amortized through September 17, 2024. In January 2021, the Company incurred an additional $0.9 million in fees related to the Third Amendment that became effective on January 21, 2021, in connection with the closing of the Mid-Con Acquisition. These fees will also be amortized over the remaining term of the loan.

As of December 31, 2020, the Company had $9.0 million outstanding under the Credit Agreement and $1.9 million in outstanding letters of credit. As of December 31, 2019, the Company had $72.8 million outstanding under the Credit Agreement and $1.9 million in outstanding letters of credit. As of December 31, 2020, borrowing availability under the Credit Agreement was $64.1 million.

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.

Borrowings under the Credit Agreement bear interest at LIBOR, the U.S. prime rate, or the federal funds rate, plus a 1.75% to 3.75% margin, dependent upon the amount outstanding. Total interest expense under the Company’s Credit Agreement, including commitment fees, the additional $1.0 million in expensed loan fees discussed above and other financing fees was approximately $5.0 million for the year ended December 31, 2020. Total interest expense under the Company’s current and previous credit agreements, including commitment fees and other financing fees, was approximately $8.6 million for the year ended December 31, 2019.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The weighted average interest rates in effect at December 31, 2020 and December 31, 2019 were 2.9% and 4.3% under the Credit Agreement, respectively.

The Credit Agreement contains customary and typical restrictive covenants. The Credit Agreement requires a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit Agreement. The Second Amendment includes a waiver of the Current Ratio requirement until the quarter ending March 31, 2022. Additionally, the Second Amendment, among other things, provides for an increase in the Applicable Margin grid on borrowings outstanding of 50 basis points, and includes provisions requiring monthly aged accounts payable reports and typical anti-cash hoarding and cash sweep provisions with respect to a consolidated cash balance in excess of $5.0 million. The Credit Agreement also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of December 31, 2020, the Company was in compliance with all of its covenants under the Credit Agreement.

Paycheck Protection Program Loan

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

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

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

14.    Commitments and Contingencies

Contango leases its office space, compressors, vehicles and certain other equipment, which are considered operating and finance leases. See Note 9 – “Leases” for more information. The Company also incurs commitments on its oil and natural gas leases, such as delay rentals, surface damage payments and rental payments associated with salt water disposal contracts.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of December 31, 2020, minimum future operating and finance lease payments and other commitments listed above for Contango’s fiscal years are as follows (in thousands):

Fiscal years ending December 31,
2021	$	3,941
2022		2,163
2023		1,872
2024		1,496
2025 and thereafter		879
Total	$	10,351

The amounts incurred under operating and finance leases and payments related to delay rentals, surface use and salt water disposal contracts during the years ended December 31, 2020 and 2019 were approximately $4.3 million and $1.5 million, respectively. The increase in 2020 payments is due to the properties acquired in the Will Energy Acquisition and the White Star Acquisition.

Throughput Contract Commitment

The Company had a signed a throughput agreement with a third-party pipeline owner/operator that constructed a natural gas gathering pipeline in Southeast Texas that allowed the Company to defray the cost of building the pipeline itself. Beginning in late 2016, the Company was unable to meet the minimum monthly gas volume deliveries through this line in Southeast Texas and continued to not meet the minimum throughput requirements under the agreement through the expiration of the throughput commitment on March 31, 2020. As of December 31, 2019, the Company recorded a $1.0 million loss contingency through the end of the contract in March 2020, which was paid in three equal monthly installments in 2020. As the remaining throughput commitment fees of $1.0 million were accrued during the year ended December 31, 2019, the Company incurred no expense related to this commitment in 2020.

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.

On November 16, 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decades-old poorly documented transactions. Based on prior summary judgments, the trial court entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decision to the applicable state Court of Appeals, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. In the first quarter of 2018, the Company filed a motion for rehearing with the Court of Appeals, which was denied, as expected. The Company filed a petition requesting a review by the Texas Supreme Court, as the Company believes the trial and appellate courts erred in the interpretation of the law. In early October 2019, the Texas Supreme Court notified the Company that it would not hear this case. The Company engaged additional legal representation to assist in the preparation of an amended petition requesting that the Texas Supreme Court reconsider its initial decision to not review the case. That amended petition was filed, and in mid-March 2020, the Texas Supreme Court decided they would not re-hear the case. Consequently, during the three months ended December 31, 2019, the Company recorded a $6.3 million liability for the judgment, interest and fees, with $3.5 million of such liability related to suspended funds reflected in “Accounts payable and accrued liabilities” on the Company’s consolidated balance sheet for the year ended December 31, 2019. The judgment, interest and fees were paid in April 2020.

On January 14, 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

37

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

costs related to the drilling difficulties and plugging and abandonment. In September 2019, the case went to trial, and, in October 2019, the court ruled in favor of the plaintiff. Prior to the judgment, the Company had approximately $1.1 million in accounts payable related to the disputed costs associated with this case. As a result of the judgment, during the three months ended September 30, 2019, the Company recorded an additional $2.1 million liability for the final judgment plus fees and interest. The Company also prepared and filed an appeal with the appellate court for a review of the initial trial court decision The plaintiff petitioned the appellate court for an extension of time to file briefs with the court until late in the fourth quarter of 2020. 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 plans to appeal the decision to the Supreme Court.

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.

15.    Net Loss Per Common Share

A reconciliation of the components of basic and diluted net loss per common share for the years ended December 31, 2020 and 2019 is presented below (in thousands):

	Year Ended December 31, 2020
	Net Loss			Shares		Per Share
Basic Earnings per Share:
Net loss attributable to common stock	$	(165,342	)		137,522	$	(1.20	)
Diluted Earnings per Share:
Effect of potential dilutive securities:
Weighted average of incremental shares (stock options, restricted stock and PSUs)		—			—		—
Net loss attributable to common stock	$	(165,342	)		137,522	$	(1.20	)

	Year Ended December 31, 2019
	Net Loss			Shares		Per Share
Basic Earnings per Share:
Net loss attributable to common stock	$	(159,796	)		54,136	$	(2.95	)
Diluted Earnings per Share:
Effect of potential dilutive securities:
Weighted average of incremental shares (stock options, restricted stock and PSUs)		—			—		—
Net loss attributable to common stock	$	(159,796	)		54,136	$	(2.95	)

The numerator for basic earnings per share is net loss attributable to common stockholders. The numerator for diluted earnings per share is net loss available to common stockholders.

Potential dilutive securities (stock options, restricted stock and PSUs) have not been considered when their effect would be antidilutive. The potentially dilutive shares would have been 529,508 shares and 613,506 shares for the years ended December 31, 2020 and 2019, respectively.

16.    Income Taxes

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statements and income tax reporting. Numerous judgments and

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

assumptions are inherent in the determination of deferred income tax assets and liabilities as well as income taxes payable in the current period. The Company is subject to taxation in several jurisdictions, and the calculation of its tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions.

Income Tax Computation

Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 21 percent for the years ended December 31, 2020 and 2019, respectively, to pretax income as follows (dollars in thousands):

	Year Ended December 31,
	2020					2019
Benefit at statutory tax rate	$	(34,663	)	21.00	%	$	(33,561	)	21.00	%
State income tax provision, net of federal benefit		467		(0.28	)%		555		(0.35	)%
State deferred tax benefit		(5,553	)	3.36	%		—		—	%
Permanent differences		26		(0.02	)%		30		(0.02	)%
Stock based compensation		81		(0.05	)%		979		(0.61	)%
Valuation allowance		40,059		(24.27	)%		34,239		(21.42	)%
Other		330		(0.20	)%		(2,022	)	1.26	%
Income tax provision	$	747		(0.46	)%	$	220		(0.14	)%

The effective tax rate for the years ended December 31, 2020 and 2019 varies from the statutory rate primarily as a result of recording a valuation allowance.

The provision (benefit) for income taxes for the periods indicated are comprised of the following (in thousands):

	Year Ended December 31,
	2020		2019
Current tax provision (benefit):
Federal	$	275	$	(335	)
State		472		555
Total	$	747	$	220
Deferred tax benefit:
Federal	$	—	$	—
State		—		—
Total	$	—	$	—
Total tax provision (benefit):
Federal	$	275	$	(335	)
State		472		555
Total	$	747	$	220
Included in gain from investment in affiliates	$	—	$	—
Total income tax provision	$	747	$	220

The Federal income tax expense results from an adjustment in the previous period of the credit for Alternative Minimum Tax (“AMT”) paid in prior years. As a result of the tax reform in 2017, the corporate AMT was repealed, and any AMT credit was made refundable. The first half of the credit was refunded when the Company filed its 2018 federal income tax return, and the second half of the credit was refunded when the Company filed its 2019 federal tax return. The CARES Act modified the timing of these refunds, allowing the Company to request an expedited refund of $0.3 million during the quarter ended June 30, 2020. This amount was previously accounted for as an income tax benefit when the corporate AMT was repealed. State income tax expense relates to income taxes for the quarter and the nine months which are expected to be owed to the states of Louisiana and Oklahoma resulting from activities within those states and, in each case, that are not shielded by existing Federal tax attributes.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Additionally, under the CARES Act, the Company will benefit from an amendment to Internal Revenue Code Section 163(j) that temporarily increases deductible interest expense limitations. Specifically, the CARES Act increases the 30% Adjusted Taxable Income (“ATI”) limitation to 50% of ATI for taxable years beginning in each of 2019 and 2020. This will have the effect of allowing the Company to use a Section 163(j) carryover from the prior year that was not limited by Section 382 (discussed below). The Company does not expect to benefit from any other income tax-related provisions of the CARES Act.

The net deferred tax is comprised of the following (in thousands):

	December 31,
	2020			2019
Deferred tax assets:
Net operating loss carryforward	$	84,982		$	80,617
Deferred compensation		447			—
Derivative instruments		—			377
State deferred tax assets		6,507			954
Oil and gas properties		39,081			11,436
Investment in affiliates		752			2,799
Recognized built in loss carryforward		9,987			6,718
163(j) Carryforward		1,828			1,585
Other		1,796			964
Total deferred tax assets before valuation allowance	$	145,380		$	105,450
Valuation allowance		(145,269	)		(105,212	)
Net deferred tax assets	$	111		$	238
Deferred tax liability:
Deferred compensation	$	—		$	(238	)
Derivative instruments		(111	)		—
Deferred tax liability	$	(111	)	$	(238	)
Total net deferred tax	$	—		$	—

Accounting for uncertainty in income taxes prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities.

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the amount of deferred tax liabilities, level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, the Company believes it is not more-likely-than-not that it will realize the benefits of these deductible differences and has recorded a valuation allowance for federal and state purposes of approximately $138.8 million and approximately $6.5 million, respectively.

As of December 31, 2020, the Company had federal net operating loss (“NOL”) carryforwards of approximately $404.7 million and state NOLs of $26.4 million. The Federal NOL carryforwards are made up of: (i) those acquired in the merger with Crimson Exploration, Inc. (“Crimson”) in 2013 (the “Merger”) 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. Recently passed legislation, however, temporarily suspends the Section 172 limitation for NOLs arising in a tax year beginning in 2018, 2019 or 2020 and also allows these NOLs to be carried back five years.

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On November 19, 2018, the Company completed a follow-on offering (the “2018 Offering”) of 7.5 million additional shares of common stock. Prior to December 18, 2018, the underwriters exercised their Green Shoe option purchasing an additional approximate 1.1 million shares, resulting in a total of approximately 8.6 million primary shares issued in the Offering. This issuance resulted in a Section 382 Ownership Change (the “2018 Ownership Change”) which limits the Company’s future ability to use its NOLs. As such, the Company is limited in use of NOLs for amounts incurred prior to November 20, 2018 in an amount estimated to be approximately $2.4 million per year (plus any recognized built in gains during the next five years) or until expiration of each annual vintage of NOL (generally, 20 years for each annual vintage of NOLs incurred prior to 2018).

On September 12, 2019, as discussed in Note 1 – “Organization and Business”, the Company completed the September 2019 Public Offering which also resulted in a Section 382 Ownership Change on that date (the “2019 Ownership Change” and, together with the 2018 Ownership Change, the “Ownership Changes”). Due to changing market conditions, the Company’s ability to utilize pre-2018 NOLs on that date could be limited to $700,000 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.

The Company is also affected by the limitation in Section 163(j) on interest taken in any given tax year. As of December 31, 2020, the Company had a limitation of $2.4 million which will carry over indefinitely. Additionally, the Company’s post-2017 NOLs of $132.7 million are also not subject to expiration, but are limited to offsetting 80% of the Company’s taxable income in any year of usage after December 31, 2020. These carryovers are subject to any applicable Section 382 limitation (discussed above).

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 valuation allowance balance at December 31, 2020 is $145.3 million.

ASC 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. As a result of the Merger, the Company acquired certain tax positions taken by Crimson in prior years. These positions are not expected to have a material impact on results of operations, financial position or cash flows. A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows (in thousands):

	Unrecognized Tax Benefits
Balance at December 31, 2019	$	—
Additions based on tax positions related to the current year		—
Additions based on tax positions related to prior years		—
Additions due to acquisitions		—
Reductions due to a lapse of the applicable statute of limitations		—
Change in rate due to remeasurement		—
Balance at December 31, 2020	$	—

The Company’s policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in the Company’s consolidated statements of operations. The Company had no interest or penalties related to unrecognized tax benefits for the year ended December 31, 2020 or any prior years. The total amount of unrecognized tax benefit, if recognized, that would affect the effective tax rate was zero.

Generally, the Company’s income tax years of 2009 through 2020 remain open and subject to examination by Federal tax authorities, and the tax years of 2009 through 2020 remain open and subject to examination by the tax authorities in Texas, Louisiana and Oklahoma, which are the jurisdictions where the Company carries its principal operations. These audits can result in adjustments of taxes due or adjustments of the NOL carryforwards that are available to offset future taxable income. The Company currently has no ongoing tax audits and has not been

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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

notified of pending activity by taxing jurisdictions. The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of the statute of limitations prior to December 31, 2020.

17.    Subsequent Events

Mid-Con Acquisition

On January 21, 2021, the Company closed the Mid-Con Acquisition in an all-stock merger transaction. At the time of close, each common unit representing limited partner interests in Mid-Con issued and outstanding (other than treasury units or units held by Mid-Con GP) was converted automatically into the right to receive 1.75 shares of the Company’s common stock. A total of 25,409,164 shares of Contango common stock were issued at the closing of the Mid-Con Acquisition. See Note 4 – “Acquisitions and Dispositions” for more information.

Silvertip Acquisition

On February 1, 2021, the Company closed the Silvertip Acquisition 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 Texas and New Mexico, for aggregate consideration of approximately $58 million in cash. The Company previously paid a $7.0 million deposit during the three months ended December 31, 2020, in connection with the execution of the purchase agreement, and a balance of $46.2 million was paid upon closing of the Silvertip Acquisition, after customary closing adjustments, including the results of operations during the period between the effective date of August 1, 2020 and the closing date. See Note 4 – “Acquisitions and Dispositions” for more information.

42

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)

In accordance with U.S. GAAP for disclosures regarding oil and natural gas producing activities, and SEC rules for oil and natural gas reporting disclosures, we are making the following disclosures regarding our oil and natural gas reserves and exploration and production activities.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The following table presents information regarding our net capitalized costs related to oil and natural gas producing activities as of the date indicated (in thousands):

	December 31,
	2020			2019
Proved oil and gas properties	$	1,274,508		$	1,306,916
Unproved oil and gas properties		16,201			27,619
		1,290,709			1,334,535
Less accumulated depreciation, depletion, amortization and impairment		(1,190,359	)		(1,043,668	)
Net capitalized costs	$	100,350		$	290,867

Costs Incurred

The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated (in thousands):

	Year Ended December 31,
	2020		2019
Property acquisition costs:
Unproved	$	1,508	$	12,486
Proved		—		168,838
Exploration costs		11,594		1,003
Development costs		5,819		41,273
Total costs incurred	$	18,921	$	223,600

Oil and Natural Gas Reserves

Proved reserves are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and current regulatory practices. Proved developed reserves are proved reserves which are expected to be produced from existing completion intervals with existing equipment and operating methods.

Proved oil and natural gas reserve quantities at December 31, 2020, 2019 and 2018, and the related discounted future net cash flows before income taxes are based on estimates prepared by William M. Cobb & Associates, Inc. and Netherland, Sewell & Associates, Inc. All estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.

43

The below table summarizes the Company’s net ownership interests in estimated quantities of proved oil, natural gas and natural gas liquids (“NGLs”) reserves and changes in net proved reserves as of December 31, 2020, 2019 and 2018, all of which are located in the continental United States.

	Oil and Condensate			Natural Gas			NGLs			Total
	(MBbls)			(MMcf)			(MBbls)			(Mboe)
Proved Developed and Undeveloped Reserves as of:
December 31, 2018		9,434			54,206			3,517			21,985
Sale of minerals in place		(1	)		(371	)		(12	)		(75	)
Acquisitions		7,718			91,765			9,103			32,115
Extensions and discoveries		9,788			9,581			1,457			12,842
Revisions of previous estimates		(7,063	)		(14,359	)		(1,689	)		(11,146	)
Production		(791	)		(9,522	)		(612	)		(2,990	)
December 31, 2019		19,085			131,300			11,764			52,731
Sale of minerals in place		(142	)		(4,754	)		(238	)		(1,172	)
Acquisitions		—			—			—			—
Extensions and discoveries		2,074			423			184			2,328
Revisions of previous estimates		(6,339	)		(23,520	)		(3,294	)		(13,552	)
Production		(1,674	)		(18,967	)		(1,262	)		(6,097	)
December 31, 2020		13,004			84,482			7,154			34,238
Proved Developed Reserves as of:
December 31, 2018		3,103			46,840			2,297			13,206
December 31, 2019		9,819			122,691			10,484			40,752
December 31, 2020		7,166			82,788			6,595			27,558
Proved Undeveloped Reserves as of:
December 31, 2018		6,331			7,366			1,220			8,779
December 31, 2019		9,266			8,609			1,280			11,979
December 31, 2020		5,838			1,694			559			6,680

During the year ended December 31, 2020, our proved reserves decreased by approximately 18.5 MMBoe primarily due to a 21.1 MMBoe decrease related to negative revisions related to lower commodity prices, a 1.0 MMBoe decrease related to property sales in our Central Oklahoma and Western Anadarko regions and 2020 production of 6.1 MMBoe, partially offset by a 7.5 MMBoe increase related to positive performance revisions primarily in our Central Oklahoma and West Texas regions and a 2.3 MMBoe increase attributable to new PUD locations in our West Texas area.

During the year ended December 31, 2019, our proved reserves increased by approximately 30.7 MMBoe primarily due to the 32.1 MMBoe increase related to the White Star Acquisition and Will Energy Acquisition, as well as an increase in total reserves attributable to our recently drilled wells in the NE Bullseye area of West Texas, offset by 2019 production and a downward revision in Bullseye PUDs in West Texas related to the impact of the low commodity price environment on economics in the area, and the related timeline for expected development of those PUD locations over the next five years.

Standardized Measure

The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved oil and natural gas reserves as of December 31, 2020 and 2019 are shown below (in thousands):

	As of December 31,
	2020			2019
Future cash inflows	$	721,395		$	1,519,882
Future production costs		(411,069	)		(782,031	)
Future development costs		(101,723	)		(217,782	)
Future income tax expenses		(18,901	)		(43,913	)
Future net cash flows		189,702			476,156
10% annual discount for estimated timing of cash flows		(74,115	)		(218,314	)
Standardized measure of discounted future net cash flows	$	115,587		$	257,842

44

Future cash inflows represent expected revenues from production and are computed by applying certain prices of oil and natural gas to estimated quantities of proved oil and natural gas reserves. Prices are based on the first-day-of-the-month prices for the previous 12 months. As of December 31, 2020, future cash inflows were based on unadjusted prices of $39.57 per barrel of oil, $2.14 per MMBtu of natural gas and $12.43 per barrel of NGL. As of December 31, 2019, future cash inflows were based on unadjusted prices of $55.69 per barrel of oil, $2.52 per MMBtu of natural gas and $16.95 per barrel of NGL.

Realized Prices

The average realized prices for the year ended December 31, 2020 production were $37.31 per barrel of oil, $1.65 per MCF of gas and $13.54 per barrel of NGL. Sales are based on market prices and do not include the effects of realized derivative hedging gains of $25.3 million for the year ended December 31, 2020.

The average realized prices for the year ended December 31, 2019 production were $56.55 per barrel of oil, $2.35 per MCF of gas and $15.39 per barrel of NGL. Sales are based on market prices and do not include the effects of realized derivative hedging gains of $2.6 million for the year ended December 31, 2019.

Future production and development costs are estimated expenditures to be incurred in developing and producing the Company’s proved oil and natural gas reserves based on historical costs and assuming continuation of existing economic conditions. Future development costs relate to compression charges at our platforms, abandonment costs, recompletion costs and additional development costs for new facilities.

Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s oil and natural gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates of oil and natural gas producing operations.

Change in Standardized Measure

Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves are summarized below (in thousands):

	Year Ended December 31,
	2020			2019
Changes in standardized measure due to current year operation:
Sales of oil and natural gas produced during the period, net of production expenses	$	(68,787	)	$	(55,868	)
Extensions and discoveries		4,729			54,308
Net change in prices and production costs		(78,046	)		(67,470	)
Changes in estimated future development costs		9,360			16,223
Revisions in quantity estimates		(48,609	)		(77,309	)
Purchase of reserves		—			177,007
Sale of reserves		(3,259	)		(246	)
Previously estimated development costs incurred		—			2,958
Accretion of discount		28,655			22,051
Changes in income taxes		17,922			(27,148	)
Change in the timing of production rates and other		(4,220	)		(5,608	)
Net change		(142,255	)		38,898
Beginning of year		257,842			218,944
End of year	$	115,587		$	257,842

45

During the year ended December 31, 2020, our proved reserves decreased by approximately 18.5 MMBoe, and our standardized measure decreased by approximately $142.3 million. This decrease is primarily attributable to lower commodity prices and the sales of non-core producing assets.

During the year ended December 31, 2019, our proved reserves increased by approximately 30.7 MMBoe, and our standardized measure increased by approximately $38.9 million. This increase is primarily attributable to the Will Energy Acquisition and White Star Acquisition.

46

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY RESULTS OF OPERATIONS (Unaudited)

Quarterly Results of Operations

The following table sets forth the results of operations by quarter for the fiscal years ended December 31, 2020 and 2019 (in thousands, except per share amounts):

	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
Year ended December 31, 2020:
Revenues	$	34,573		$	17,842		$	31,348		$	29,157
Operating Loss (1)	$	(151,465	)	$	(21,275	)	$	2,058		$	(24,614	)
Net loss attributable to common stock (2)	$	(105,255	)	$	(28,034	)	$	(6,805	)	$	(25,248	)
Net loss per share (3):
Basic:	$	(0.80	)	$	(0.21	)	$	(0.05	)	$	(0.16	)
Diluted:	$	(0.80	)	$	(0.21	)	$	(0.05	)	$	(0.16	)
Year ended December 31, 2019:
Revenues	$	14,011		$	12,762		$	12,547		$	37,193
Operating Loss (1)	$	(4,553	)	$	(6,457	)	$	(8,794	)	$	(130,926	)
Net loss attributable to common stock (2)		(8,618	)		(4,961	)		(7,838	)		(138,379	)
Net loss per share (3):
Basic:	$	(0.26	)	$	(0.15	)	$	(0.19	)	$	(1.32	)
Diluted:	$	(0.26	)	$	(0.15	)	$	(0.19	)	$	(1.32	)

(1) Represents oil, natural gas and NGL sales and fee for service revenues, less operating expenses, exploration expenses, depreciation, depletion and amortization, lease expirations and relinquishments, impairment of oil and natural gas properties and general and administrative expense.

(2) Represents oil, natural gas and NGL sales, less operating expenses, exploration expenses, depreciation, depletion and amortization, lease expirations and relinquishments, impairment of oil and natural gas properties, general and administrative expense, and other income and expense after income taxes.

(3) The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share as each quarterly computation is based on the income for that quarter and the weighted average number of common shares outstanding during that quarter.

47

EX-99.2

Exhibit 99.2

Item 1. Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except number of shares)

	September 30, 2021			December 31, 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

1

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended 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

2

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

3

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)

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

4

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

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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 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 eighteen 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.

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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-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

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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 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.

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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 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. No 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.

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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 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

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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.

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.

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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 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.

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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.

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

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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.

	Year Ended December 31, 2020
	(In thousands except for per share amounts)
	(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 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.

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Fair value information for financial assets and liabilities was as follows as of September 30, 2021 (in thousands):

				Fair Value Measurements Using
	Total 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.

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.

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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.

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):

Commodity	Period	Derivative	Volume/Quarter		Weighted Average 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)

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Commodity	Period	Derivative	Volume/Quarter		Weighted Average Price/Unit		Fair Value
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.

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

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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 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.

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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. No 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 no 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. No stock options were granted or exercised during the nine months ended September 30, 2021 or 2020.

During the nine months ended September 30, 2021, no stock options were forfeited by former employees, and 19,268 stock options expired. During the nine months ended September 30, 2020, no 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.

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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.

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	%

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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.

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	)

23

The Company issued a total of 25,552,933 shares of Contango common stock at the closing of the Mid-Con Acquisition. See Note 3 – “Acquisitions and Dispositions” for more information.

9.    Investment in Exaro Energy III LLC

The Company maintains an ownership interest in Exaro of approximately 37%. The Company’s share in the equity of Exaro at 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 no tax expense and a loss of $1.9 million, net of no 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 no tax expense, and a loss of $13 thousand, net of no 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 1st and November 1st 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.

24

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, 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%.

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.

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.

26

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.

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

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.

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EX-99.3

Exhibit 99.3

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENT

Defined terms included below shall have the same meaning as terms defined and included within the proxy statement/prospectus (File No. 333-258157), dated November 3, 2021 (the “Proxy Statement/Prospectus”).

On December 7, 2021 (the “Closing Date”), Crescent Energy Company (“Crescent” or the “Company”), Contango, Independence, OpCo and certain entities formed by the Company (C Merger Sub and L Merger Sub) completed the transactions contemplated by the Transaction Agreement dated June 7, 2021 pursuant to which, (1) OpCo was recapitalized such that after giving effect to such recapitalization, all of the equity interest in OpCo consisting of 127,536,463 OpCo Units (the “OpCo Recapitalization”), Independence distributed all of the OpCo Units held by it, and all of the shares of Crescent Class B Common Stock held by it to the members of Independence in accordance with its organizational documents (the “Distribution”), and immediately following the Distribution, Independence merged with and into OpCo with OpCo surviving (the “Independence Merger”), (2) immediately following the Independence Merger, C Merger Sub merged with and into Contango, with Contango surviving the merger as a direct wholly owned corporate subsidiary of the Company (the “Contango Merger”), (3) as a result of the Contango Merger, each outstanding share of Contango Common Stock was converted into the right to receive a number of shares of Crescent Class A Common Stock equal to the Exchange Ratio, (4) immediately following the Contango Merger, Contango merged with and into L Merger Sub, with L Merger Sub surviving the merger as a direct wholly owned limited liability company subsidiary of the Company (the “LLC Merger”), (5) immediately following the LLC Merger, the Company contributed 100% of the equity interests in L Merger Sub to OpCo in exchange for certain Opco Units (the “Contribution”), and (6) immediately following the Contribution, OpCo contributed L Merger Sub to Energy Finance. Each of these transactions contemplated by the Transaction Agreement and completed on the Closing Date is collectively referred to hereafter as the “Merger Transactions.” Subject to the terms and conditions within the Transaction Agreement, holders of eligible shares of Contango Common Stock received 0.20 shares of Crescent Class A common stock in exchange for each share of Contango Common Stock held.

The following unaudited pro forma condensed combined financial statement (the “pro forma financial statement”) has been prepared from the respective historical consolidated financial statements of Crescent for the year ended December 31, 2021 and Contango for the period from January 1, 2021 through December 6, 2021, adjusted to give effect to the Merger Transactions. Additionally, the pro forma financial statement includes adjustments associated with the April 2021 Exchange, the Noncontrolling Interest Carve-out, the DJ Basin Acquisition, the acquisition of certain operated producing oil and natural gas properties predominately located in the Central Basin Platform in Texas and New Mexico (the “Central Basin Platform Acquisition”), the Independence Refinancing, and the February 2022 issuance of an additional $200.0 million in aggregate principal of our 7.250% senior notes due 2026 and the use of proceeds therefrom to repay amounts outstanding under our New Credit Agreement (the “Crescent Refinancing” and together with the April 2021 Exchange, the Noncontrolling Interest Carve-out, the DJ Basin Acquisition, the Central Basin Platform Acquisition, and the Independence Refinancing, the “Crescent Transactions”). Further, Contango completed the Mid-Con Acquisition, the Grizzly Acquisition, and the Wind River Basin Acquisition (collectively, the “Contango Transactions”) during the period presented.

The unaudited pro forma condensed combined statement of operations (the “pro forma statement of operations”) for the year ended December 31, 2021 gives effect to each of the Merger Transactions, the Crescent Transactions and the Contango Transactions (together with the Merger Transactions and the Crescent Transactions, the “Pro Forma Transactions”) as if they had been consummated on January 1, 2021.

The following pro forma financial statement is based on, and should be read in conjunction with the Company’s historical audited combined and consolidated financial statements for the year ended December 31, 2021 included in the Company’s Annual Report on Form 10-K.

The accompanying pro forma financial statement was derived by making certain transaction accounting adjustments to the historical financial statements noted above. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual impact of the Pro Forma Transactions may differ from the adjustments made to the pro forma financial statement. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects for the periods presented as if the Pro Forma Transactions had been consummated earlier, and that all adjustments necessary to present fairly the pro forma financial statement have been made.

A final determination of the fair value of Contango’s assets and liabilities will be based on the actual assets and liabilities of Contango that existed as of the Closing Date and will be finalized before the end of the measurement period. The pro forma adjustments have been made solely for the purpose of providing the unaudited pro forma financial statement presented below. Any increases or decreases in the fair value of assets acquired and liabilities assumed upon completion of the final valuations will result in adjustments to the pro forma statements of operations. The final purchase price allocation may be materially different than that reflected in the pro forma purchase price allocation presented herein.

The pro forma financial statement and related notes are presented for illustrative purposes only and should not be relied upon as an indication of the financial condition or the operating results that the Company would have achieved if the Transaction Agreement had been entered into and the Pro Forma Transactions had taken place on the assumed dates. The pro forma financial statement does not reflect future events that may occur after the consummation of the Transactions, including, but not limited to, the anticipated realization of ongoing savings from potential operating efficiencies, asset dispositions, cost savings, or economies of scale that the Company may achieve with respect to the combined operations. As a result, future results may vary significantly from the results reflected in the pro forma financial statement and should not be relied on as an indication of the future results of the Company.

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Year Ended December 31, 2021

(in thousands, except per share data)

	Crescent (Historical)			Crescent Transaction Adjustments					Crescent As Adjusted			Contango1 (Historical)			Contango2 (Historical)			Contango Transaction Adjustments					Contango As Adjusted			Reclassif- ications					Transaction Adjustments					Crescent Pro Forma Combined
Revenues:
Oil	$	883,087		$	22,527		(a	)	$	905,614		$	149,246		$	50,182		$	6,982		(d	)	$	206,410		$	—				$	—				$	1,112,024
Natural gas		354,298			715		(a	)		355,013			55,556			45,179			95,043		(d	)		195,778			—					—					550,791
Natural gas liquids		185,530			1,391		(a	)		186,921			35,735			12,201			743		(d	)		48,679			—					—					235,600
Midstream and other		54,062			(538	)	(a	)		53,524			—			—			7,765		(d	)		7,765			8,132		(e	)		—					69,421
Other revenue		—			—					—			2,980			5,152			—					8,132			(8,132	)	(e	)		—					—
Total revenues		1,476,977			24,095					1,501,072			243,517			112,714			110,533					466,764			—					—					1,967,836
Expenses:
Operating expense		596,334			5,751		(a	)		602,085			108,901			40,760			43,720		(d	)		193,381			—					—					795,466
Depreciation, depletion and amortization		312,787			4,823		(a	)		317,610			30,391			7,633			8,608		(d	)		46,632			—					51,918		(f	)		416,160
Impairment and abandonment of oil and natural gas properties		—			—					—			712			49			—					761			—					—					761
Exploration expense		1,180			(3	)	(a	)		1,177			458			25			1		(d	)		484			—					—					1,661
Midstream operating expense		13,389			(132	)	(a	)		13,257			—			2,098			—					2,098			—					—					15,355
General and administrative expense		78,342			(195	)	(a	)		78,147			39,441			26,555			97		(d	)		66,093			—					12,279		(g	)		171,327
																																14,808		(h	)
Gain on sale of assets		(8,794	)		—					(8,794	)		—			—			—					—			(438	)	(e	)		—					(9,232	)
Total expenses		993,238			10,244					1,003,482			179,903			77,120			52,426					309,449			(438	)				79,005					1,391,498
Other income (expense):
Interest expense		(50,740	)		377		(a	)		(64,405	)		(4,156	)		(4,753	)		(384	)	(d	)		(9,293	)		—					—					(73,698	)
					(14,042	)	(b	)
Loss on derivatives		(866,020	)		—					(866,020	)		(117,951	)		14,909			(1,597	)	(d	)		(104,639	)		—					—					(970,659	)
Income (loss) from equity method investments		368			—					368			(1,897	)		—			—					(1,897	)		—					—					(1,529	)
Gain from sale of assets		—			—					—			461			(23	)		—					438			(438	)	(e	)		—					—
Gain on extinguishment of debt		—			—					—			3,369			—			—					3,369			—					—					3,369
Other income (expense)		120			(5	)	(a	)		115			3,714			2,097			—					5,811			—					—					5,926
Total other income (expense)		(916,272	)		(13,670	)				(929,942	)		(116,460	)		12,230			(1,981	)				(106,211	)		(438	)				—					(1,036,591	)
Income (loss) before taxes		(432,533	)		181					(432,352	)		(52,846	)		47,824			56,126					51,104			—					(79,005	)				(460,253	)
Income tax benefit (expense)		306			1		(a	)		307			711			1			—					712			—					24,542		(i	)		25,561
Net income (loss)		(432,227	)		182					(432,045	)		(52,135	)		47,825			56,126					51,816			—					(54,463	)				(434,692	)
Less: net (income) loss attributable to Predecessor		339,168			—					339,168			—			—			—					—			—					(339,168	)	(j	)		—
Less: net (income) loss attributable to noncontrolling interests		14,922			(8,716	)	(a	)		3,570			—			—			—					—			—					—					3,570
					(2,636	)	(c	)
Less: net loss attributable to redeemable noncontrolling interests		58,761			—					58,761			—			—			—					—			—					274,837		(k	)		333,598
Net loss attributable to Crescent Energy	$	(19,376	)	$	(11,170	)			$	(30,546	)	$	(52,135	)	$	47,825		$	56,126				$	51,816		$	—				$	(118,794	)			$	(97,524	)
Net Loss per Share:
Class A - basic and diluted	$	(0.46	)																																	$	(2.32	)	(l	)
Class B - basic and diluted	$	—																																		$	—		(l	)
Weighted Average Common Shares Outstanding
Class A - basic and diluted		41,954																																			41,954		(l	)
Class B - basic and diluted		127,536																																			127,536		(l	)

¹  Reflects the historical operations of Contango for the nine months ended September 30, 2021.

²  Reflects the historical operations of Contango for the period from October 1, 2021 through December 6, 2021.

Notes to unaudited pro forma condensed combined financial statements

NOTE 1 – Basis of pro forma presentation

The pro forma financial statement has been derived from the historical financial statements of Crescent and Contango. The pro forma statements of operations for the year ended December 31, 2021 gives effect to the Pro Forma Transactions as if they had occurred on January 1, 2021.

The pro forma financial statement reflects pro forma adjustments that are based on available information and certain assumptions that management believes are reasonable. However, actual results may differ from those reflected in these statements. In management’s opinion, all adjustments known to date that are necessary to present fairly the pro forma information have been made. The pro forma financial statement does not purport to represent what the combined entity’s financial position or results of operations would have been if the Pro Forma Transactions had actually occurred on the dates indicated above, nor are they indicative of the Company’s future financial position or results of operations.

These pro forma financial statement should be read in conjunction with the Company’s historical financial statements for the year ended December 31, 2021 included in the Company’s Annual Report on Form 10-K.

NOTE 2 – Purchase price allocation

The Merger Transactions was accounted for using the acquisition method of accounting for business combinations with the Company considered to be the accounting acquirer. The allocation of the purchase price for Contango was based upon management’s estimates of and assumptions related to the fair value of assets to be acquired and liabilities to be assumed as of the Closing Date using currently available information. Because the pro forma financial statement has been prepared based on estimates, the final purchase price allocation and the resulting effect on the Company’s financial position and results of operations may differ significantly from the pro forma amounts included in this exhibit to the Company’s Current Report on Form 8-K. The Company expects to finalize its allocation of the purchase price during the second half of 2022.

The determination of consideration transferred, fair value of assets acquired and liabilities recorded were as follows (in thousands, except exchange ratio, share, and per share data):

Consideration transferred:
Shares of Contango common stock outstanding		199,136,676
NYSE American Closing price per share on December 7, 2021	$	3.22
Fair value of Contango common stock		641,220
Settlement of Restricted Stock Awards		7,090
Settlement of PSU Awards		6,306
Settlement of Company Stock Option Awards		—
Consideration transferred	$	654,616
Fair value of assets acquired:
Cash and cash equivalents	$	14,202
Accounts receivable, net		145,727
Prepaid and other current assets		8,275
Oil and natural gas properties - proved
Oil and natural gas properties - proved		1,002,165
Unproved properties		—
Field and other property and equipment		6,955
Goodwill		76,564
Other assets		3,514
Total assets acquired		1,257,402
Fair value of liabilities assumed:
Accounts payable and accrued liabilities		(186,689	)
Derivative liabilities – current		(44,002	)
Long-term debt		(140,000	)
Deferred tax liability		(83,250	)
Derivative liabilities – noncurrent		(14,592	)
Asset retirement obligations		(142,100	)
Other liabilities		(7,200	)
Total liabilities assumed		(617,833	)
Assets acquired and liabilities assumed	$	654,616

Under the Transaction Agreement, Contango stockholders received 0.20 shares of Crescent Class A Common Stock for each share of Contango Common Stock issued and outstanding immediately prior to the Closing Date. This resulted in the Company issuing approximately 39.8 million shares of Crescent Class A Common Stock in exchange for 199.1 million outstanding shares of Contango Common Stock and 3.3 million shares of Crescent Class A Common Stock in settlement of Contango’s equity compensation awards, a portion of which was recognized as expense in the statement of operations for the Company. As Contango Common Stock were listed and actively traded on an exchange as of the Closing Date, the trading price of Contango Common Stock was used to estimate the fair value of consideration transferred.

NOTE 3 – Adjustments to the pro forma financial statement

The pro forma financial statement has been prepared to illustrate the effect of the Pro Forma Transactions and have been prepared for informational purposes only.

The following pro forma financial statement has been prepared in accordance with Article 11 of Regulation S-X as amended by the final rule, Release No. 33-10786 “Amendments to Financial Disclosures about Acquired and Disposed Businesses.” Release No. 33-10786 replaces the existing pro forma adjustment criteria with simplified requirements to depict the accounting for the transaction (“Transaction Accounting Adjustments”) and allows for supplemental disclosure of the reasonably estimable synergies and other transaction effects that have occurred or are reasonably expected to occur (“Management Adjustments”). Management has elected not to disclose Management Adjustments.

The pro forma provision for income taxes does not necessarily reflect the amounts that would have resulted had the combined company filed consolidated income tax returns during the periods presented.

The pro forma net loss per share amounts presented in the pro forma statements of operations are based upon the number of shares of Crescent Class A Common Stock and Crescent Class B Common Stock outstanding, assuming the Pro Forma Transactions occurred on January 1, 2021.

Pro forma statement of operations adjustments

The adjustments included in the pro forma statements of operations for the year ended December 31, 2021 are as follows:

Crescent Transaction Adjustments

(a) Reflects the impact on the pro forma statements of operations reflect for acquisitions and divestitures during the period presented, including the Noncontrolling Interest Carve-out, the DJ Basin Acquisition, and the Central Basin Platform Acquisition, which are summarized below (in thousands):

	Year Ended December 31, 2021
Crescent Acquisitions and Carve-out	Noncontrolling Interest Carve-Out			DJ Basin Acquisition		Central Basin Platform Acquisition		Total
Oil and condensate sales	$	(7,564	)	$	1,770	$	28,321	$	22,527
Natural gas sales		(2,292	)		528		2,480		715
Natural gas liquids sales		(1,200	)		15		2,575		1,391
Midstream and other		(538	)		—		—		(538	)
Operating expense		(5,827	)		418		11,160		5,751
Depreciation, depletion and amortization		(3,478	)		822		7,479		4,823
Exploration expense		(3	)		—		—		(3	)
Midstream operating expense		(132	)		—		—		(132	)
General and administrative expense		(195	)		—		—		(195	)
Interest expense		377			—		—		377
Other income (expense)		(5	)		—		—		(5	)
Loss on derivatives		10,302			—		—		10,302
Income tax benefit (expense)		1			—		—		1
Net income (loss)		8,716			1,073		14,737		24,526
Less: net (income) loss attributable to noncontrolling interests		(8,716	)		—		—		(8,716	)
Net income (loss) attributable to Crescent Energy	$	—		$	1,073	$	14,737	$	15,810

(b) Reflects pro forma adjustments to interest expense related to the Independence Refinancing and the Crescent Refinancing. The proceeds received from the Crescent Refinancing in February 2022 were used to repay amounts outstanding under our New Credit Agreement, and as such, result in no net adjustment, on a pro forma basis, to our balance sheet as of December 31, 2021.

(c) Reflects the impact on the pro forma statements of operations for the April 2021 Exchange.

Contango Transaction Adjustments

(d) Reflects adjustments to the pro forma statements of operations for the Mid-Con Acquisition, Grizzly Acquisition, and Wind River Basin Acquisition consummated by Contango on January 21, 2021, February 1, 2021, and August 31, 2021, respectively, which are summarized below (in thousands):

	Year Ended December 31, 2021
Contango Transaction Adjustments	Mid-Con Acquisition			Grizzly Acquisition		Wind River Basin Acquisition			Total
Oil and condensate sales	$	2,554		$	4,403	$	25		$	6,982
Natural gas sales		48			663		94,332			95,043
Natural gas liquids sales		—			743		—			743
Midstream and other		43			—		7,722			7,765
Operating expense		1,243			1,991		40,486			43,720
Depreciation, depletion and amortization		620			793		7,195			8,608
Exploration expense		—			—		1			1
General and administrative expense		97			—		—			97
Interest expense		(327	)		—		(57	)		(384	)
Gain (loss) on derivatives		(1,597	)		—		—			(1,597	)
Net income (loss)	$	(1,239	)	$	3,025	$	54,340		$	56,126

Reclassifications

(e) The following reclassifications were made to conform Contango’s financial statement presentation to the Company’s financial statement presentation:

• The reclassification of $8.1 million of Contango’s other operating revenues to midstream and other; and

• The reclassification of $0.4 million of Contango’s gain from sale of assets within other income (expense) to (gain) loss on sale of assets within operating expenses.

Transaction Adjustments

(f) Reflects the pro forma depletion expense calculated in accordance with the successful efforts method of accounting for oil and gas properties, which was based on the preliminary purchase price allocation.

(g) Reflects the impact of the Management Compensation pursuant to the Management Agreement executed by and between the Company and Manager entered into as of December 7, 2021.

(h) Reflects the impact of the Incentive Compensation pursuant to the Management Agreement executed by and between the Company and Manager on December 6, 2021.

(i) Reflects the income tax effect of the pro forma adjustments presented. The tax rate applied to the pro forma adjustments was the estimated combined statutory rate after the effect of noncontrolling interests of 6.0%, for the year ended December 31, 2021. The effective rate of the Company could be significantly different (either higher or lower) depending on post-Closing activities.

(j) Reflects the elimination of net loss attributable to Predecessor for the period prior to the Merger Transactions as the Pro Forma Transactions are assumed to occur on January 1, 2021.

(k) Reflects the impact of the issuance of Crescent Class A common stock and Class B common stock as a result of the Contango Merger and the Distribution, respectively, on the allocation of net loss attributable to redeemable noncontrolling interests and net loss attributable to the Company.

(l) Reflects the impact of the recapitalization of the Company as a result of the Pro Forma Transactions on basic and diluted net loss per share.

The computation of the impact of the pro forma adjustments on the Company’s common stock outstanding and basic and diluted net loss per share of common stock is summarized below:

	Year Ended December 31, 2021
Net loss per share (in thousands, except per share data)	Crescent Pro Forma Combined			Crescent Class A			Crescent Class B
Numerator:
Pro forma net loss	$	(434,692	)
Less: Pro forma net loss attributable to noncontrolling interests		3,570
Less: Pro forma net loss attributable to redeemable noncontrolling interests		333,598
Pro forma net loss attributable to the Company	$	(97,524	)	$	(97,524	)	$	—
Denominator:
Pro forma weighted-average shares of common stock outstanding – basic and diluted					41,954			127,536
Pro forma net loss per share of common stock – basic and diluted				$	(2.32	)	$	—

NOTE 4 – Supplemental pro forma oil and natural gas reserves information

Oil and natural gas reserves

The following tables present the estimated pro forma combined net proved developed and undeveloped oil, natural gas, and NGLs reserves information as of December 31, 2021 for our consolidated operations, along with a summary of changes in quantities of net remaining proved reserves for the year ended December 31, 2021 for our consolidated operations. Immaterial amounts for proved developed oil, natural gas, and NGLs of our equity affiliates totaling 3.7 MMBoe as of December 31, 2021 have been omitted from presentation below. The estimates below are in certain instances presented on a “barrels of oil equivalent or “Boe” basis. To determine Boe in the following tables, natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.

The following estimated pro forma oil and natural gas reserves information is not necessarily indicative of the results that might have occurred had the Pro Forma Transactions been completed on January 1, 2021 and is not intended to be a projection of future results. Crescent Transaction Adjustments reflect adjustments to oil and natural gas reserves information for the Noncontrolling Interest Carve-out, the DJ Basin Acquisition, and the Central Basin Platform Acquisition (together with the DJ Basin Acquisition, the “Crescent Acquisitions”). Specifically, (i) the Crescent Acquisitions result in positive reserve additions as of December 31, 2020, with an offsetting decrease to purchases of reserves in place during the year ended December 31, 2021 and (ii) the Noncontrolling Interest Carve-out results in negative adjustments as of December 31, 2020 to account for the reduction in reserves that occurred when certain non-controlling interests in our subsidiaries were redeemed in exchange for a proportionate interest in our subsidiaries’ oil and gas properties and associated reserves. In each case these transactions resulted in corresponding adjustments to the Standardized Measure as set forth in tables further below. Contango Transaction Adjustments reflect adjustments to oil and natural gas reserves information for the Mid-Con Acquisition, the Grizzly Acquisition, and the Wind River Basin Acquisition. Each of these adjustments are further discussed within Note 3 – Adjustments to the pro forma financial statement. Future results may vary significantly from the results reflected because of various factors, including those discussed in “Risk Factors” included in the Company’s Annual Report on Form 10-K.

	Oil and Condensate (MBbls)
	Crescent (Historical)			Crescent Transaction Adjustments						Crescent As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Crescent Pro Forma Combined
				Noncontrolling Interest Carve-out			Crescent Acquisitions
Proved Developed and Undeveloped Reserves as of:
December 31, 2020		167,190			(6,015	)		4,883			166,058			13,004			29,916			42,920			208,978
Revisions of previous estimates		9,147			—			—			9,147			1,990			—			1,990			11,137
Extensions, discoveries, and other additions		7,007			—			—			7,007			756			—			756			7,763
Sales of reserves in place		(6,333	)		5,866			—			(467	)		(387	)		—			(387	)		(854	)
Purchases of reserves in place		46,386			—			(4,429	)		41,957			(12,329	)		(29,628	)		(41,957	)		—
Production		(13,237	)		149			(454	)		(13,542	)		(3,034	)		(288	)		(3,322	)		(16,864	)
December 31, 2021		210,160			—			—			210,160			—			—			—			210,160
Proved Developed Reserves as of:
December 31, 2020		92,024			(3,359	)		4,883			93,548			7,166			26,324			33,490			127,038
December 31, 2021		158,091			—			—			158,091			—			—			—			158,091
Proved Undeveloped Reserves as of:
December 31, 2020		75,166			(2,656	)		—			72,510			5,838			3,592			9,430			81,940
December 31, 2021		52,069			—			—			52,069			—			—			—			52,069

	Natural Gas (MMcf)
	Crescent (Historical)			Crescent Transaction Adjustments						Crescent As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Crescent Pro Forma Combined
				Noncontrolling Interest Carve-out			Crescent Acquisitions
Proved Developed and Undeveloped Reserves as of:
December 31, 2020		822,864			(27,679	)		16,765			811,950			84,482			370,462			454,944			1,266,894
Revisions of previous estimates		316,572			—			—			316,572			26,734			—			26,734			343,306
Extensions, discoveries, and other additions		17,247			—			—			17,247			458			—			458			17,705
Sales of reserves in place		(48,977	)		26,708			—			(22,269	)		(3,957	)		—			(3,957	)		(26,226	)
Purchases of reserves in place		451,702			—			(15,782	)		435,920			(82,174	)		(353,746	)		(435,920	)		—
Production		(89,455	)		971			(983	)		(89,467	)		(25,543	)		(16,716	)		(42,259	)		(131,726	)
December 31, 2021		1,469,953			—			—			1,469,953			—			—			—			1,469,953
Proved Developed Reserves as of:
December 31, 2020		748,496			(26,491	)		16,765			738,770			82,788			370,462			453,250			1,192,020
December 31, 2021		1,404,570			—			—			1,404,570			—			—			—			1,404,570
Proved Undeveloped Reserves as of:
December 31, 2020		74,368			(1,188	)		—			73,180			1,694			—			1,694			74,874
December 31, 2021		65,383			—			—			65,383			—			—			—			65,383

	NGLs (MBbls)
	Crescent (Historical)			Crescent Transaction Adjustments						Crescent As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Crescent Pro Forma Combined
				Noncontrolling Interest Carve-out			Crescent Acquisitions
Proved Developed and Undeveloped Reserves as of:
December 31, 2020		55,324			(1,601	)		1,086			54,809			2,766			7,263			10,029			64,838
Revisions of previous estimates		16,480			—			—			16,480			2,566			—			2,566			19,046
Extensions, discoveries, and other additions		2,093			—			—			2,093			86			—			86			2,179
Sales of reserves in place		(3,265	)		1,542			—			(1,723	)		(249	)		—			(249	)		(1,972	)
Purchases of reserves in place		11,960			—			(988	)		10,972			(3,709	)		(7,263	)		(10,972	)		—
Production		(6,099	)		59			(98	)		(6,138	)		(1,460	)		—			(1,460	)		(7,598	)
December 31, 2021		76,493			—			—			76,493			—			—			—			76,493
Proved Developed Reserves as of:
December 31, 2020		44,307			(1,368	)		1,086			44,025			2,207			6,704			8,911			52,936
December 31, 2021		66,402			—			—			66,402			—			—			—			66,402
Proved Undeveloped Reserves as of:
December 31, 2020		11,017			(233	)		—			10,784			559			559			1,118			11,902
December 31, 2021		10,091			—			—			10,091			—			—			—			10,091

	Total (Mboe)
	Crescent (Historical)			Crescent Transaction Adjustments						Crescent As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Crescent Pro Forma Combined
				Noncontrolling Interest Carve-out			Crescent Acquisitions
Proved Developed and Undeveloped Reserves as of:
December 31, 2020		359,658			(12,230	)		8,748			356,176			34,238			94,536			128,774			484,950
Revisions of previous estimates		78,389			—			—			78,389			9,012			—			9,012			87,401
Extensions, discoveries, and other additions		11,975			—			—			11,975			918			—			918			12,893
Sales of reserves in place		(17,762	)		11,860			—			(5,902	)		(1,295	)		—			(1,295	)		(7,197	)
Purchases of reserves in place		133,630			—			(8,046	)		125,584			(34,121	)		(91,463	)		(125,584	)		—
Production		(34,245	)		370			(702	)		(34,577	)		(8,752	)		(3,073	)		(11,825	)		(46,402	)
December 31, 2021		531,645			—			—			531,645			—			—			—			531,645
Proved Developed Reserves as of:
December 31, 2020		261,079			(9,143	)		8,748			260,684			27,559			90,385			117,944			378,628
December 31, 2021		458,588			—			—			458,588			—			—			—			458,588
Proved Undeveloped Reserves as of:
December 31, 2020		98,579			(3,087	)		—			95,492			6,679			4,151			10,830			106,322
December 31, 2021		73,057			—			—			73,057			—			—			—			73,057

Standardized measure of discounted future net cash flows

The following tables present the estimated pro forma standardized measure of discounted future net cash flows (the “pro forma standardized measure”) at December 31, 2021. The pro forma standardized measure information set forth below gives effect to the Pro Forma Transactions as if they had been completed on January 1, 2021. Crescent Transaction Adjustments reflect adjustments to the standardized measure of discounted future net cash flows for the Noncontrolling Interest Carve-out and the Crescent Acquisitions. Contango Transaction Adjustments reflect adjustments to the standardized measure of discounted future net cash flows for the Mid-Con Acquisition, the Grizzly Acquisition, and the Wind River Basin Acquisition. Transaction Adjustments reflect adjustments related to the tax restructuring of the Company resulting from the Transactions. Each of these adjustments are further discussed within Note 3 – Adjustments to the pro forma financial statement. The disclosures below were determined by referencing the “Standardized Measure of Discounted Future Net Cash Flows” reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2021. An explanation of the underlying methodology applied, as required by SEC regulations, can be found within the historical financial statements. The calculations assume the continuation of existing economic, operating and contractual conditions at December 31, 2021. Immaterial amounts for the pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves of our equity affiliates totaling $23.2 million as of December 31, 2021 have been omitted from presentation below.

Therefore, the following estimated pro forma standardized measure is not necessarily indicative of the results that might have occurred had the Pro Forma Transactions been completed on January 1, 2021 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected because of various factors, including those discussed in “Risk Factors” included in the Company’s Annual Report on Form 10-K.

The pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves of our consolidated operations as of December 31, 2021 is as follows:

	(in thousands)
	Crescent (Historical)			Crescent Transaction Adjustments				Crescent As Adjusted			Contango (Historical)		Contango Transaction Adjustments		Contango As Adjusted		Crescent Pro Forma Combined
				Noncontrolling Interest Carve-out		Crescent Acquisitions
Future cash inflows	$	21,063,117		$	—	$	—	$	21,063,117		$	—	$	—	$	—	$	21,063,117
Future production costs		(10,194,648	)		—		—		(10,194,648	)		—		—		—		(10,194,648	)
Future development costs (1)		(1,477,562	)		—		—		(1,477,562	)		—		—		—		(1,477,562	)
Future income taxes		(352,136	)		—		—		(352,136	)		—		—		—		(352,136	)
Future net cash flows		9,038,771			—		—		9,038,771			—		—		—		9,038,771
Annual discount of 10% for estimated timing		(4,080,471	)		—		—		(4,080,471	)		—		—		—		(4,080,471	)
Standardized measure of discounted future net cash flows as of December 31, 2021	$	4,958,300		$	—	$	—	$	4,958,300		$	—	$	—	$	—	$	4,958,300

⁽¹⁾  Future development costs include future abandonment and salvage costs.

Changes in standardized measure

The changes in the pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves of our consolidated operations for the year ended December 31, 2021 are as follows:

	(in thousands)
	Crescent (Historical)			Crescent Transaction Adjustments						Crescent As Adjusted			Contango (Historical)			Contango Transaction Adjustments			Contango As Adjusted			Transaction Adjustments			Crescent Pro Forma Combined
				Noncontrolling Interest Carve-out			Crescent Acquisitions
Balance at December 31, 2020	$	1,327,860		$	(49,250	)	$	101,377		$	1,379,987		$	115,586		$	377,727		$	493,313		$	(159,547	)	$	1,713,753
Net change in prices and production costs		3,330,299			—			73,538			3,403,837			271,462			477,843			749,305			—			4,153,142
Net change in future development costs		117,333			—			—			117,333			(19,898	)		—			(19,898	)		—			97,435
Sales and transfers of oil and natural gas produced, net of production expenses		(872,521	)		5,229			(24,111	)		(891,403	)		(198,438	)		(59,048	)		(257,486	)		—			(1,148,889	)
Extensions, discoveries, additions and improved recovery, net of related costs		162,657			—			—			162,657			27,928			—			27,928			—			190,585
Purchases of reserves in place		1,236,388			—			(153,955	)		1,082,433			(279,825	)		(802,608	)		(1,082,433	)		—			—
Sales of reserves in place		(84,095	)		44,021			—			(40,074	)		(12,930	)		—			(12,930	)		—			(53,004	)
Revisions of previous quantity estimates		(295,234	)		—			—			(295,234	)		85,643			—			85,643			—			(209,591	)
Previously estimated development costs incurred		95,879			—			—			95,879			—			—			—			—			95,879
Net change in taxes		(184,419	)		—			—			(184,419	)		10,790			—			10,790			174,464			835
Accretion of discount		124,153			—			10,138			134,291			11,811			38,599			50,410			(14,917	)		169,784
Changes in timing and other		—			—			(6,987	)		(6,987	)		(12,129	)		(32,513	)		(44,642	)		—			(51,629	)
Balance at December 31, 2021	$	4,958,300		$	—		$	—		$	4,958,300		$	—		$	—		$	—		$	—		$	4,958,300

EX-99.4

Exhibit 99.4

March 15, 2022

Mr. Brett Knight

Director, Corporate Reserves

Crescent Energy Company

600 Travis, Suite 7200

Houston, Texas 77002

Re:   Evaluation Summary

        Crescent Energy Company Interests

        (EP Energy Acquisition)

        Total Proved Reserves

        Certain Properties in Utah

        As of December 31, 2021

        Pursuant to the Guidelines of the Securities and

        Exchange Commission for Reporting Corporate

        Reserves and Future Net Revenue

Dear Mr. Knight:

As requested by Crescent Energy Company (“Company”), this report was prepared on March 15, 2022 for the purpose of submitting our estimates of total proved reserves and forecasts of economics attributable to the EP Energy acquisition interests, pending closing on March 31, 2022. We evaluated 100% of the proved reserves, which are made up of certain oil and gas properties located in Utah. The effective date of the acquisition is December, 31 2021, therefore, this evaluation utilized an effective date of December 31, 2021. This report was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (SEC). A composite summary of the results of this evaluation are presented below:

		Proved		Proved
		Developed		Developed		Proved		Total
		Producing		Non-Producing		Undeveloped		Proved
Net Reserves
Oil	-Mbbl		21,158.1		3,712.8		18,053.5		42,924.4
Gas	-MMcf		82,087.1		10,006.9		47,234.5		139,328.6
MBOE/6	-Mbbl		34,839.3		5,380.6		25,925.9		66,145.8
Revenue
Oil	-M$		1,191,201.6		209,029.9		1,016,412.3		2,416,643.8
Gas	-M$		171,398.0		20,894.4		98,625.7		290,918.1
Severance Taxes	-M$		70,855.2		11,956.1		57,982.0		140,793.2
Ad Valorem Taxes	-M$		16,017.6		2,702.8		13,107.5		31,827.9
Operating Expenses	-M$		358,351.7		15,739.5		74,271.3		448,362.3
Future Development Costs	-M$		96,573.3		66,536.6		399,071.8		562,181.8
Net Operating Income (BFIT)	-M$		820,801.9		132,989.4		570,605.2		1,524,396.9
Discounted @ 10%	-M$		638,499.0		94,923.7		320,698.3		1,054,120.9

Crescent Energy Company Interests (EP Energy Acquisition)

March 15, 2022

Page 2

Proved Developed reserves are the summation of the Proved Developed Producing (“PDP”) and Proved Developed Non-Producing (“PDNP”) estimates. Proved Developed reserves were estimated at 24,870.9 Mbbl oil and 92,094.0 MMcf gas. Of the Proved Developed reserves, 34,839.3 MBOE was attributed to producing zones in existing wells and 5,380.6 MBOE was attributed to zones in existing wells not producing.

Future revenue was calculated prior to deducting state production taxes and ad valorem taxes; however, future net cash flow (net operating income) was calculated after deducting these taxes, future capital costs and operating expenses, but before federal income taxes. Future net cash flow has been discounted at an annual rate of ten (10) percent, in accordance with SEC guidelines, to determine its “present worth”. Present worth indicates the time value of money and should not be construed to represent an estimate of the fair market value of the properties by Cawley, Gillespie & Associates, Inc. (“CG&A”).

The oil reserves include oil and condensate. Oil volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base. BOE (barrels of oil equivalent) is expressed as oil volumes in barrels plus gas volumes in Mcf divided by six (6) to convert to barrels.

Hydrocarbon Pricing

The base SEC oil and gas prices calculated for December 31, 2021 were $66.56/bbl and $3.598/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2021 and the base gas price is based upon Henry Hub spot prices (Gas Daily) during 2021.

Adjustments to oil and gas prices were calculated by the Company and applied as received by CG&A. For all properties, oil price differentials were forecast at -$10.26 per BBL and gas price differentials were forecast at -$1.51 per MCF. Adjustments may include treating costs, transportation charges, plant processing, and/or crude quality and gravity corrections. After these adjustments, the net realized prices over the life of the proved properties was estimated to be $56.30 per BBL for oil and $2.088 per MCF for gas. All economic factors were held constant in accordance with SEC guidelines.

Economic Parameters

Operating expenses, 3rd party COPAS and capital expenditures (future development costs) were not escalated in accordance with SEC guidelines. Lease operating expenses and 3rd party COPAS fees were applied on a per property basis as estimated by the Company from lease operating statements from January 2020 through February 2021. Lease operating expenses (LOE) and future development costs were provided by the Company and audited by us at a summary level. Our audit determined that the commercial parameters being applied were reasonable and appropriate, and therefore no changes were made to cost parameters. Variable operating expenses were applied to all wells to capture gas and/or liquids transportation costs plus water disposal costs and 3rd party revenue from water disposal operations. Severance tax values were determined by applying normal state severance tax rates. Ad valorem tax rates were forecast as provided at approximately 1.24% of revenue.

For the non-producing and undeveloped properties, LOE was also scheduled in a similar manner as horizontal producing properties, as provided. Future development capital information was provided by the Company based upon recent drilling and completion activities performed by operators in the area. Future development costs were applied by lateral length and completion type for all Uteland Butte locations.

Crescent Energy Company Interests (EP Energy Acquisition)

March 15, 2022

Page 3

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages three (3) and four (4) of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

CG&A evaluated 478 PDP properties for this report, most with daily and monthly production data through 12/31/2021 as provided by the Company. We also evaluated a “Non-Drill Capital” cost case as part of the PDP value. This report also includes 12 PDNP properties, each drilled and at various stages of completion as of the effective date of this report.

In addition, CG&A evaluated 63 commercial PUD drilling opportunities all targeting the Uteland Butte reservoir. All PUD drills were modeled as horizontal wells offsetting production from existing horizontal producers. Reserves for each PUD location were assigned by type curve area depending upon the region and nearby analogous production. Each of these drilling locations proposed as part of the Company’s development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Company has indicated they have every intent to complete this development plan within the next five years. Furthermore, the Company has demonstrated that they have the proper staffing, financial backing and prior development success to ensure this five year development plan will be fully executed.

Reserve Estimation Methods

The methods employed in estimating reserves are described on page two (2) in the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for the Company properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment has been included in this evaluation, as provided by the Company.

Crescent Energy Company Interests (EP Energy Acquisition)

March 15, 2022

Page 4

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. This evaluation was supervised by W. Todd Brooker, President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties, EP Energy, Crescent Energy Company or its subsidiaries and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office. This report supersedes the report published by Cawley, Gillespie & Associates for the Company on March 11, 2022.

EX-99.5

Exhibit 99.5

WILLIAM M. COBB & ASSOCIATES, INC.

Worldwide Petroleum Consultants

12770 Coit Road, Suite 907 Dallas, Texas (972) 385-0354 Fax: (972) 788-5165 E-Mail: office@wmcobb.com

February 25, 2021

Ms. Christie Schultz

Contango Oil & Gas Company

717 Texas Avenue, Suite 2900

Houston, TX 77002

Dear Ms. Schultz:

In accordance with your request, William M. Cobb & Associates, Inc. (Cobb & Associates) has estimated the proved reserves and future income as of January 1, 2021, attributable to the interest of Contango Oil & Gas Company and its subsidiaries (Contango) in certain oil and gas properties located in Oklahoma, Texas, Louisiana, state and federal waters of the Gulf of Mexico, Wyoming, Mississippi, and Kansas.

Reserves presented in this report are classified as proved and are further categorized as proved developed producing (PDP), proved non-producing (PNP), proved shut-in (PSI), and proved undeveloped (PUD).

Table 1 summarizes our estimate of the proved oil and gas reserves and their pre-federal income tax value undiscounted and discounted at ten percent using SEC pricing.

TABLE 1

CONTANGO OIL AND GAS COMPANY

TOTAL PROVED RESERVES AND CASH FLOW SUMMARY

AS OF JANUARY 1, 2021

YEAR-END 2020 SEC PRICE

	Net Reserves						Future Net Cash Flow
Reserves Category	Oil (MBBL)		Gas (MMCF)		NGL (MBBL)		Undisc. (M$)		Disc. 10% (M$)
PDP		7,163		82,257		6,562		158,852		111,943
PNP		4		531		32		202		160
PSI		0		0		0		0		0
PUD		5,838		1,694		559		49,548		14,273
TOTAL PROVED		13,004		84,482		7,154		208,602		126,376

Page 1

Values shown were determined utilizing constant oil and gas prices and well operating expenses. The discounted present worth of future income values shown in Table 1 are not intended to represent an estimate of fair market value. These estimates were prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Certification Topic 932, Extraction Activities – Oil and Gas.

Reserve and cash flow summary projections and a one-line summary for total proved reserves by category are detailed in Appendix A. Appendix B includes a cash flow and one-line summary of reserves by region, field, and reserve category.

Oil and NGL volumes are expressed in thousands of stock tank barrels (MBBL). A stock tank barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of standard cubic feet (MMCF) as determined at 60^o Fahrenheit and the legal pressure base for the specific location of the gas reserves.

This report, which was prepared for Contango’s use in filing with the SEC and will be filed with Contango’s Form 10-K for fiscal year ending December 31, 2020 (the “Form 10-K”) and covers 100 percent of the total company present value discounted at ten percent (PV10) presented in Contango’s Form 10-K. All assumptions, data, methods, and procedures considered necessary and appropriate were used to prepare this report.

DISCUSSION

The Contango properties are divided into five regions: Central Oklahoma, Offshore, Onshore, Western Anadarko, and West Texas. The Central Oklahoma and Western Anadarko properties are located in Oklahoma and north west Texas and 47.5 and 12.5 percent, respectively, of the total proved discounted present value are attributable to these properties. These properties were acquired from White Star Petroleum and Will Energy in late 2019. The onshore properties are located in Louisiana, Mississippi, east Texas, and Wyoming and make up 5.3 percent of the total proved discounted value. The offshore properties are located in Louisiana state and federal waters of the Gulf of Mexico and contribute 7.5 percent of the total proved discounted value. The west Texas properties are located in Pecos County in the Delaware Basin and provide 27.2 percent of the total proved discounted value.

Reserve estimates were prepared using generally accepted petroleum engineering principles and practices. The method, or combination of methods, utilized in the study of each property or reservoir included an assessment of the stage of reservoir development, quality of data, and length of production history. Geologic and engineering data was obtained from Contango, public sources, and the non-confidential files of Cobb & Associates.

Performance data through December of 2020 was used to forecast reserves for all producing properties where available. Reserve classification was based on the status of each well as of January 1, 2021 for operated wells, and on the most recently available information for non-operated wells.

For most regions in the report, the PDP reserve estimates were based on decline curve analysis. Some of the properties have produced for only a short period of time and did not exhibit an identifiable performance decline trend. In these cases, reserve estimates were based primarily on geological interpretation, mapping, and analogy to offset producers. Past performance, and offsetting performance data were used to estimate behind pipe and undeveloped reserves. Fields where additional analysis or methodology was used for the reserve assignments are discussed in more detail. These fields include Eugene Island 11 and properties in west Texas.

Page 2

Offshore - Eugene Island 11

Eugene Island 11 is located in federal and Louisiana state waters of the Gulf of Mexico, at a water depth of approximately 13 feet. Production is primarily from a single CibOp sand, the JRM-1 sand, at a depth of approximately 15,000 feet. The field was discovered in September, 2006 by the Contango Operators Dutch 1 well. Contango has since drilled four more wells, the Dutch 2, 3, 4 and 5, on Federal acreage. The Dutch 5 well is depleted and is scheduled for abandonment in December 2021.

Contango also has properties in Louisiana state waters in this field. These properties are referred to as the Mary Rose prospect. Five Mary Rose wells have been drilled to date. Four Mary Rose wells, numbers 1 through 4, have produced from the main CibOp sand. The Mary Rose 4 well is depleted and has been abandoned. The Mary Rose 3 is also depleted, with abandonment scheduled for December 2021.

The Mary Rose 5 well produced from a separate, and much smaller, CibOp reservoir that is now depleted. Abandonment of the Mary Rose 5 was completed in 2019.

Proved reserves for the Eugene Island 10 main CibOp sand are based on analysis of historical rate versus time decline curves and P/Z performance plots, supplemented by volumetric calculations of original-gas-in-place (OGIP) using all available well log and 3D seismic data. The reservoir has been effectively drilled to the lowest structural datum and no significant aquifer has been found. Performance to date indicates a depletion drive system.

All Dutch and Mary Rose wells now flow to compression on the ‘H’ platform, allowing for a decrease in producing flowing tubing pressures. This two-stage compression lowers line pressure to approximately 200 psi. There are no remaining capital or startup costs for compression on the ‘H’ platform. Abandonment costs were provided by Contango and scheduled at the end-of-project life for all wells and the ‘H’ platform.

West Texas – Bullseye and North East Bullseye

During 2017, Contango embarked on a drilling program for Wolfcamp Shale wells in Pecos County, Texas. In the Bullseye area, 14 wells have been drilled and completed and are carried as proved developed producing (PDP) in this report. In December 2019, Contango acquired additional acres and designated this as the north east Bullseye area. Four wells have been drilled and completed and are currently producing as of January 1, 2021 in the north east Bullseye area.

There are three prospective formations in the north east Bullseye area, from the deepest to the shallowest, these are the Wolfcamp B, Wolfcamp A, and the 2^nd Bone Springs. One bench of wells in the Wolfcamp B and the 2^nd Bone Springs have been planned as well as two benches of wells in the Wolfcamp A.

Traditional decline curve analysis has difficulty predicting the well-to-well interactions between long horizontal wells in the shale plays. As a result, to improve the long-term prediction of PUD reserves, advanced simulation software and automatic parameter variation within certain ranges based on the estimated range and uncertainty in the reservoir and completion properties in the area was used to

Page 3

develop probabilistic history matches for the existing wells. The history matches were based on the optimal matches to oil, gas, and water production and bottom hole pressure data for each well.

The reservoir properties from these matches were then used to study the optimal well spacing for the north east Bullseye development. Based on the results from this study, the optimum well spacing was determined to be 1,100 ft in the Wolfcamp formation. With the available space in a typical unit with dimensions of one mile by two miles and the 1,100 ft well spacing there are space for five locations in the Wolfcamp A and four locations in the Wolfcamp B.

The second part of the simulation study assessed the well-to-well interactions in order to develop a type curve that accounted for these interactions. A model with an existing Wolfcamp A well and an existing Wolfcamp B well was used for this evaluation. A large number of simulations were run with different reservoir properties to generate a probabilistic reserve distribution for the Wolfcamp PUD locations. These were then analyzed and a P50 profile was generated for each location. These location profiles were then averaged to generate a type curve to be used for the Wolfcamp A and Wolfcamp B. Locations within the Contango five-year capital plan taking into account market uncertainty were booked as PUD reserves in this report.

OIL AND GAS PRICING

Projections of proved reserves contained in this report utilize constant product prices of $2.14 per MMBTU of gas and $39.57 per barrel of oil. These are the average first-of-month prices for the prior 12-month period for Henry Hub gas and West Texas Intermediate (WTI) oil. Appropriate oil and gas pricing differentials, residue gas shrink, NGL yields, and NGL pricing as a fraction of WTI were calculated for each field using 12 months of revenue data where available. After applying appropriate differentials for each property, the weighted average realized product prices for 2021 were $36.74 per barrel of oil and $1.87 per MCF of gas, resulting in average 2021 differentials of negative $2.83 per barrel and negative $0.27 per MCF.

OPERATING COSTS

Future operating costs for each of the Contango wells are held constant at current values for the life of the property. These costs were calculated using 12-month lease operating expense (LOE) statements provided by Contango. In general, the LOE statements for each of the properties were analyzed by field or production area. LOE data was available for most areas through the second quarter of 2020 for most areas. Each well was assigned a fixed monthly operating cost, variable costs for oil and gas, and water handling costs per produced barrel of water. Oil, gas, and NGL transportation and processing fees were also assigned to each well by product purchaser using net revenue data in a similar manner that product differentials were determined.

LOE data for the Eugene Island 11 properties was analyzed at a well level. Fixed operating costs were divided into three categories: producing well, non-producing well, and platform expenses. Non-producing wells are wells that are awaiting abandonment in 2021 and had costs attributable to insurance. Platform expenses include shared compression equipment rental and operating costs, pipeline costs, and other costs that were assigned to platform cost centers.

For the west Texas Delaware Basin properties, LOE was also analyzed at a well or cost center level. An additional water operating cost for shared water handling facilities was calculated and assigned per barrel of produced water.

Page 4

CAPITAL COSTS

Capital expenditures to recomplete behind-pipe zones in existing wells, re-activate or work over existing wells, drill new wells, and install production facilities were provided by Contango and appear to be reasonable.

PROFESSIONAL GUIDELINES

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years, from known reservoirs under expected economic and operating conditions. Reserves are considered proved if economic productivity is supported by either actual production or conclusive formation tests.

Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves, but more certain to be recovered than possible reserves. Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.

The reserve definitions used by Cobb & Associates are consistent with definitions set forth in the PRMS and approved by the Society of Petroleum Engineers and other professional organizations.

The reserves included in this report are estimates only and should not be construed as being exact quantities. Governmental policies, uncertainties of supply and demand, the prices actually received for the reserves, and the costs incurred in recovering such reserves, may vary from the price and cost assumptions in this report. Estimated reserves using price escalations may vary from values obtained using constant price scenarios. In any case, estimates of reserves, resources, and revenues may increase or decrease as a result of future operations.

Cobb & Associates has not examined titles to the appraised properties nor has the actual degree of interest owned been independently confirmed. The data used in this evaluation were obtained from Contango Oil & Gas Company and the non-confidential files of Cobb & Associates and were considered accurate.

We have not made a field examination of the Contango properties, therefore, operating ability and condition of the production equipment have not been considered. Also, environmental liabilities, if any, caused by Contango or any other operator have not been considered, nor has the cost to restore the property to acceptable conditions, as may be required by regulation, been taken into account.

In evaluating available information concerning this appraisal, Cobb & Associates has excluded from its consideration all matters as to which legal or accounting interpretation, rather than engineering, may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data and conclusions necessarily represent only informed professional judgments.

William M. Cobb & Associates, Inc. is an independent consulting firm founded in 1983. Its compensation is not contingent on the results obtained or reported. Frank J. Marek, a Registered Texas

Page 5

Professional Engineer and a senior technical advisor of William M. Cobb & Associates, Inc., is primarily responsible for overseeing the preparation of the reserve report. His professional qualifications meet or exceed the qualifications of reserve estimators set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include: Bachelor of Science degree in Petroleum Engineering from Texas A&M University 1977; member of the Society of Petroleum Engineers; member of the Society of Petroleum Evaluation Engineers; and 40 years of experience in estimating and evaluating reserve information and estimating and evaluating reserves.

Cobb & Associates appreciates the opportunity to be of service to you. If you have any questions regarding this report, please do not hesitate to contact us.

Page 6

EX-99.6

Exhibit 99.6

January 26, 2021

Mr. John P. Atwood

Senior Vice President

Exaro Energy III, LLC

5850 San Felipe, Suite 500

Houston, Texas 77057

Re:  Engineering Evaluation

Estimate of Reserves & Revenues

Year End 2020 SEC Pricing

“As of” January 1, 2021

Dear Mr. Atwood:

At your request, W.D. Von Gonten & Co. has estimated future reserves and projected net revenues attributable to certain oil and gas interests currently owned by Exaro Energy III, LLC (Exaro). The properties represented herein are located in the Jonah field of Sublette County, Wyoming. A summary of the discounted future net revenue attributable to Exaro’s Proven reserves, “As of” January 1, 2021, is as follows:

Report Preparation

Purpose of Report – The purpose of this report is to provide Exaro with a projection of future reserves and revenues attributable to certain Proved oil and gas interests presently owned.

Scope of Report – W.D. Von Gonten & Co. was engaged by Exaro to estimate the reserves and revenues associated with the properties included in this report. Once reserves were estimated, future revenue projections were generated utilizing SEC pricing guidelines.

Reporting Requirements – The Society of Petroleum Engineers (SPE) requires Reserves to be economically recoverable with prices and costs in effect on the “as of” date of the report. In conjunction with World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), Society of Petroleum Evaluation Engineers (SPEE), Society of Exploration Geophysicists (SEG), Society of Petrophysicists and Well Log Analysts (SPWLA), and the European Associated of Geoscientists and Engineers (EAGE), the SPE has issued Petroleum Resources Management System (2018 ed.), which sets forth the definitions and requirements associated with the determination and classification of both Reserves and Resources. In addition, the SPE has issued Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information (2019 ed.), which sets requirements for the qualifications and independence of qualified reserves evaluators and auditors.

Securities and Exchange Commission (SEC) Regulation S-K, Item 102 and Regulation S-X, Rule 4-10, and Financial Accounting Standards Board (FASB) Statement No. 69 requires oil and gas reserve information to be reported by publicly held companies as supplemental financial information. These regulations and standards provide for estimates of Proved reserves and revenues discounted at 10% and based on constant prices and costs.

The estimated Proved Reserves herein have been prepared in conformance with all SPE definitions and requirements in the above referenced publications.

Projections – The attached reserve and revenue projections are on a calendar year basis with the first time period being January 1 through December 31, 2021.

Property Discussion

Exaro signed an Earning and Development Agreement (EDA) with Ovintiv Inc. (Ovintiv), previously known as Encana Oil & Gas, in April 2012 that allowed them to gradually obtain increasing levels of ownership in the Jonah field. As part of the EDA, Exaro’s interest in each well drilled prior to the April 2012 agreement (old Proved Developed Producing (PDP) wells) continued to increase as Ovintiv drilled additional wells (new wells) within the field. Exaro’s interest in the new wells stayed constant for the life of each well. For each new well drilled within the EDA, Exaro paid for 100% of the capital costs and earned 32.5% of Ovintiv’s interest in the new wellbore until Exaro was fully earned into their devoted interest. In addition, for each new well drilled, Exaro earned 0.40% interest in the old PDP wells and related leasehold if Ovintiv’s working interest in the new well location was 100% and a proportional share if not.

As of the date of this report, Ovintiv has sold its ownership to Jonah Energy, LLC (Jonah Energy). Exaro notified Jonah Energy of its intent to terminate the EDA effective May 12, 2014, and thereafter participate under the existing Joint Operating Agreements (JOA’s) going forward. Exaro currently has no locations left under the EDA.

Production in this area is primarily from the Lance sand which can range from 8,000’ to 11,000’ in depth and approach 3000’ in gross interval thickness.

Beginning in 2014, Jonah Energy began drilling horizontal wells across the eastern sections of Exaro’s acreage. To date, there are six horizontal wells currently producing.

Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – January 26, 2021 - Page 2

Starting in February 2015, Jonah Energy began line pressure reduction projects in the field on varying groups of wells. They started by lowering the pressure from 200 psi to 50 psi in seventeen wells located in section 35. Lowering the pressure caused an increase to the production rate and reserves on most of the connected wells. Based on provided daily production data, W.D. Von Gonten & Co. was able to assign these wells a minor uplift. Jonah Energy has since begun and maintained several similar projects throughout Exaro’s acreage.

Figure 1 displays the comparison of Exaro’s historical monthly net production and W.D. Von Gonten & Co.’s forecasted net monthly production beginning January 1, 2021.

Figure 1: Historical Net Production and PDP Reserves Forecast as of January 1, 2021

Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – January 26, 2021 - Page 3

Figure 2 below is a graphical comparison of Exaro’s October 2019 through September 2020 historical net revenue and W.D. Von Gonten & Co.’s forecasted net revenue beginning January 1, 2021.

Figure 2: Historical Net Revenue and Forecasted Net Revenue as of January 1, 2021

Reserves Discussion

Reserves estimates represented herein were generally determined through the implementation of various methods including, but not limited to, performance decline, analogy, and type curve analysis. Based on the amount of available data, one or more of the above methods was utilized as deemed appropriate.

Reserves and schedules of production included in this report are only estimates. The amount of available data, reservoir and geological complexity, reservoir drive mechanism, and mechanical aspects can have a material effect on the accuracy of these reserve estimates. Due to inherent uncertainties in future production rates, commodity prices, and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom, and/or the actual costs incurred could be more or less than the estimated amounts.

Product Prices Discussion

SEC pricing is determined by averaging the first day of each month’s closing price for the previous calendar year using published benchmark oil and gas prices. This method, as applied for the purposes of this report, renders a price of $39.54 per barrel of oil and $2.03 per MMBtu of gas. These prices were held constant throughout the life of the properties as per SEC guidelines.

Pricing differentials were applied on a field basis to reflect the actual prices received at the wellhead. Differentials typically account for transportation costs, geographical differentials, marketing bonuses or deductions, and any other factors that may affect the price actually received at the wellhead. W.D. Von Gonten & Co. determined the historical pricing differentials from lease operating data provided by Exaro representing the time period October 2019 through September 2020.

Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – January 26, 2021 - Page 4

Figures 3 and 4 illustrate the comparison between historical differentials versus those projected.

Figure 3: Historical and Forecasted Oil Differential

Figure 4: Historical and Forecasted Gas Differential

W.D. Von Gonten & Co. has included the historical NGL revenue and processing fees within the gas price differential for the new wells only. Due to existing and new contracts, the old wells do not include any NGL revenues or fees.

Operating Expenses and Capital Costs Discussion

Projected monthly operating expenses associated with the Jonah properties were based on the review of lease operating data provided by Exaro for the time period October 2019 through September 2020. Using the supplied data, W.D. Von Gonten & Co. applied a gross direct expense to each well on an individual basis. The horizontal wells have an increased monthly expense compared to vertical wells based on historical observations. A gross variable deduct, which covers gathering fees, has been applied to all wells. In addition, a salt water disposal (SWD) expense supplied by Exaro has been applied to each well. All direct and variable operating expenses were held constant for the economic life of each property.

Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – January 26, 2021 - Page 5

Figure 5 below is a graphical comparison of historical net lease operating expenses for October 2019 through September 2020 versus comparable forecasted expenses for the subsequent twelve months. June 2020 is showing a negative expense which can be attributed to the SWD.

Figure 5: Historical and Forecasted Lease Operating Expense

There are no capital costs associated with any of the properties included herein. Currently, Exaro has no knowledge of anticipated work efforts scheduled by the operator.

Other Considerations

Abandonment Costs – Cost estimates regarding future plugging and abandonment liabilities associated with these properties were supplied by Exaro for the purposes of this report. As we have not inspected the properties personally, W.D. Von Gonten & Co. expresses no warranties as to the accuracy or reasonableness of these assumptions. A third party study would be necessary in order to accurately estimate all future abandonment liabilities.

Data Sources – Data furnished by Exaro included basic well information, lease operating statements, ownership, pricing, and production information on certain leases. IHS Energy archives was utilized to view the monthly production for some of the wells included in this report.

Context – We specifically advise that any particular reserve estimate for a specific property not be used out of context with the overall report. The revenues and present worth of future net revenues are not represented to be market value either for individual properties or on a total property basis.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the January 1, 2021 estimated oil and gas volumes. The reserves in this report can be produced under current regulatory guidelines. Actual future commodity prices may differ substantially from the utilized pricing scenario which may or may not extend or limit the estimated reserves and revenue quantities presented in this report.

Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – January 26, 2021 - Page 6

We have not inspected the properties included in this report, nor have we conducted independent well tests. W.D. Von Gonten & Co. and our employees have no direct ownership in any of the properties included in this report. Our fees are based on hourly expenses, and are not related to the reserve and revenue estimates produced in this report. The responsible technical personnel referenced below have obtained the qualifications and meet the requirements of objectivity for Qualified Reserves Evaluator employed internally by W.D. Von Gonten & Co. as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information (2019 ed.) promulgated by the SPE.

Thank you for the opportunity to assist Exaro Energy III, LLC with this project.

	Respectfully submitted,
	Phillip Hunter, P.E.
	TX #96590

Jamie Foster

Reviewed by:

W.D. Von Gonten, Jr., P.E.

TX #73244

Exaro Energy III, LLC – Reserves and Revenues – SEC Pricing – January 26, 2021 - Page 7

XML

Document and Entity Information	Apr. 08, 2022
Cover [Abstract]
Entity Registrant Name	Crescent Energy Co
Amendment Flag	false
Entity Central Index Key	0001866175
Document Type	8-K
Document Period End Date	Apr. 08, 2022
Entity Incorporation State Country Code	DE
Entity File Number	001-41132
Entity Tax Identification Number	87-1133610
Entity Address, Address Line One	600 Travis Street
Entity Address, Address Line Two	Suite 7200
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	(713)
Local Phone Number	337-4600
Written Communications	false
Soliciting Material	false
Pre Commencement Tender Offer	false
Pre Commencement Issuer Tender Offer	false
Security 12b Title	Class A Common Stock, par value $0.0001 per share
Trading Symbol	CRGY
Security Exchange Name	NYSE
Entity Emerging Growth Company	false