March 2, 2020

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, 2020, 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.  This report is an evaluation of Contango legacy properties and the properties acquired from Will Energy (Will legacy) and White Star Petroleum (White Star legacy) by Contango in October and November 2019.     

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 2 summarizes our estimate of the proved oil and gas reserves and their pre-federal income tax value undiscounted and discounted at ten percent using the December 31, 2019 NYMEX strip price. 

TABLE 1

TABLE 2

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 and Table 2 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 for the SEC price case.  Appendix B includes a cash flow and one-line summary of reserves by region and field and reserve category for the SEC price case.    Appendix C includes the cash flow projections and one-line summary by category for the strip price case.  Cash flow projections and a one-line summary for the strip price case, by region and field and reserve category are detailed in Appendix D. 

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 60o 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, 2019 (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 legacy properties attribute 41 percent of the total proved discounted present value and are located in state and federal waters offshore Louisiana in the  Gulf of Mexico, and onshore in Texas, Louisiana, and Wyoming.  In a transaction that closed on November 1, 2019, Contango acquired White Star Petroleum.  The White Star legacy properties attribute 50 percent of the total proved discounted

present value and are located in Oklahoma.  Will Energy was acquired by Contango in a transaction that closed on October 25, 2019.  The Will legacy properties attribute the remaining nine percent of the total proved discounted present value.  These properties are located in Oklahoma and north Louisiana. 

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 2019 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, 2020 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.   

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.  All five of the Dutch wells are currently active.

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 May 2020.

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 11 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.  This program is divided into two areas, Bullseye and north east Bullseye.  In the Bullseye area, 14 wells have been drilled and completed and are carried as proved developed producing (PDP) in this report.  Three wells have been drilled and completed and are currently producing as of January 1, 2020 in the north east Bullseye area. 

To supplement decline curve analysis, simulation software was used to develop production curves for each well taking in account bottom hole pressures and additional reservoir data.    Proved undeveloped (PUD) locations were assigned to each lease such that there are a maximum of six wells total per lease at both Bullseye and north east Bullseye areas.  Reserves were assigned to the PUD locations using a type curve developed from an analysis of the PDP wells and offsetting wells in the surrounding leases and average PDP assigned recoveries.

OIL AND GAS PRICING

For the SEC price case, projections of proved reserves contained in this report utilize constant product prices of $2.52 per MMBTU of gas and $55.69 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. 

Table 3 shows the average yearly price for the December 31, 2019 NYMEX strip used in the report. 

TABLE 3

For the SEC price case, after applying appropriate differentials for each field, the weighted average realized product prices for 2020 were $54.24 per barrel of oil and $2.18 per MCF of gas, resulting in average 2020 differentials of negative $1.45 per barrel and negative $0.34 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 legacy properties were analyzed by field where available.  For the Contango Legacy properties LOE data for the 12-month period ending June 30, 2019 was used to determine costs.  The White Star and Will legacy properties had data available through September 2019.  Using the statements provided 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. 

In 2019 Contango analyzed LOE data and identified areas where operating cost reductions could be made.  The LOE assignments for fixed and variable costs were reduced by amounts provided by Contango.  These adjustments included reductions in equipment rental fees, headcount, and other costs.  Additionally, cost estimates were increased in items where costs were expected to increase over the next year.  These adjustments were implemented in the second quarter of 2019.  LOE data provided for the second quarter of 2019 reflects a decrease of overall costs.

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 2020 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.

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 Professional Engineer and a  senior vice president 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.