March 12, 2002

Exhibit 99.1

William M. Cobb & Associates, Inc.

Worldwide Petroleum Consultants

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

Dallas, Texas‌Fax: (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	Oil	Gas	NGL	Undisc.	Disc. 10%
Category	(MBBL)	(MMCF)	(MBBL)	(M$)	(M$)
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

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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

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methodology was used for the reserve assignments are discussed in more detail. These fields include Eugene Island 11 and properties in west Texas.

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

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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.

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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

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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.