January 17, 2017

Mr. Steve Mengle

Contango Oil & Gas Company

717 Texas Avenue, Suite 2900

Houston, TX  77002

Dear Mr. Mengle:

In accordance with your request, William M. Cobb & Associates, Inc. (Cobb & Associates) has estimated the proved reserves and future income as of January 1, 2017, attributable to the interest of Contango Oil & Gas Company and its subsidiaries (Contango) in certain oil and gas properties located in state and federal waters of the Gulf of Mexico and onshore in Mississippi. This report was completed on January 13, 2017.

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.  Values shown are 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 necessarily 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. 

TABLE 1

CONTANGO  - NET RESERVES AND VALUE

AS OF JANUARY 1, 2017

CONSTANT SEC OIL AND GAS PRICES

Total proved reserves as of January 1, 2017 are 92,212 MMCFE.  This amount is calculated using a  six MCF per barrel ratio applied to condensate and NGL volumes.

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.

Our 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 ended December 31, 2016 (the “Form 10-K”), covers
92,212 MMCFE, or 60.8 percent of the total reserves presented in Contango’s Form 10-K.  We have used all assumptions, data, methods, and procedures considered necessary and appropriate to prepare this report.

DISCUSSION

Eugene Island 10

Eugene Island 10 is located in federal and 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. 

Contango’s Louisiana State leases in this field 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, produce from the main CibOp sand.  The Mary Rose 5 well produces from a separate, and much smaller, CibOp reservoir.

All wells now produce to the Contango ‘H’ platform located in Eugene Island Block 11.  The
Dutch 1, 2, and 3 wells previously produced to the Chevron EI-24 platform but were switched to the Contango ‘H’ platform in 2013.

Proved reserves for the Eugene Island 10 main CibOp sand are based on P/Z performance plots, supplemented by volumetric calculations of original-gas-in-place (OGIP) using all available well log data coupled with 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.  Contango plans to install a second stage of compression in the third quarter of 2017, which will lower the compressor inlet pressure to 200 psig or below.    The Mary Rose 3 and 4 wells have forecasts that are modeled to increase at the time that the second stage is expected online.  There are no remaining capital or start up costs for compression on the ‘H’ platform.    The custody transfer meter is downstream of the compressor and other supply and fuel gas, so engineered and forecasted volumes already have these compressor and other fuel volumes removed, at an estimated total of 1,493 MCFD.   The P/Z analysis was performed prior to compression being installed, so those ultimate reserves are reduced by a fuel volume allocated to each well based on its proportion of current gas production to the field total.

Contango’s working interest ownership is approximately 55 percent in the Dutch wells and 53 percent in the Mary Rose 1 through 3 wells.  The Contango working interest in the Mary Rose 4 and 5 wells is approximately 35 and 38 percent, respectively.  Based on future net income, discounted at ten percent (PV10), approximately 99.7 percent of the evaluated Contango proved reserve value is attributable to the Eugene Island 10 wells.

Two wells on the State acreage originally produced from gas reservoirs separate from the main CibOp reservoir.  The Eloise 3 well produced and depleted a lower RobL sand and was recompleted to  an isolated CibOp sand during the last quarter of 2011.  This stray CibOp producer, now called the Mary Rose 5, began producing in January 2012.    The Eloise 5 well has also produced and depleted a lower RobL sand and was recompleted to the main CibOp reservoir mid-year 2011.  The Eloise 5 was renamed the Dutch 5 well and began producing from the main CibOp reservoir in July 2011.

Ship Shoal 263

Contango drilled the Ship Shoal 263 B-1 well in 2009 and completed the well for production in a gas sand at 15,850 feet.  The well began producing on June 30, 2010 and has produced approximately
8.5 BCF of gas and 561 MBBL of condensate to date.  The well is currently shut-in and is expected to be plugged and abandoned in mid-2017.

Vermilion 170

Contango drilled the OCS-G-33596 #1 in March of 2011 and successfully completed the well in the Big A sand at a depth of approximately 13,800 feet.  Production started in September 2011 upon installation of a production platform in 87 feet of water.  Current production rates are 7.3 MMCF per day with 61 barrels of condensate.  Cumulative production to date is approximately 20.5 BCF of gas and 437 MBBL of condensate.  Proved producing reserves,  which include benefits of recently installed compression, are based on a reservoir simulation model history matched to actual production and pressure performance.

South Timbalier 17-1

In mid to late-2013, Contango drilled and tested a well on its South Timbalier 17 lease.  The South Timbalier 17-1 was drilled to a total measured depth of 11,432 feet, and was completed in a sand from 11,174 - 11,200 feet.  The well tested in September of 2013 at a rate of 12.7 MMCF per day, but required facilities to be brought to normal production.    Facilities were installed in 2014 and the well commenced production in July of 2014, with peak daily rates of 15.0 MMCF per day with 166 BBL of condensate.  Current production rates are 1.1 MMCF per day with 2 barrels of condensate.  Cumulative production to date is approximately 3.1 BCF of gas and 19.6 MBBL of condensate.  Proved reserves included in this report are based on volumetric calculations to lowest known gas (LKG) in the
17-1 wellbore.

Tuscaloosa Marine Shale Wells

Contango owns a working interest in four Tuscaloosa Marine Shale (TMS) wells drilled from 2012 to 2014, which are operated by Goodrich Petroleum.  The wells are located in Wilkinson and Amite Counties, Mississippi, and they produce from the Cretaceous aged TMS at a true vertical depth of approximately 12,000 feet.  The wells were drilled horizontally with variable lateral lengths that

average approximately 6,000’.  The wells were hydraulically fracture stimulated to increase well deliverability.  Peak oil rates for the wells ranged from 225 to 875 BBL of oil per day, and averaged 585 BBL of oil per day.  The wells are on hydraulic pump and in September of 2016, they produced at a combined rate of approximately 168  BBL of oil per day with 166 MCF of solution gas per day.  The wells have a combined cumulative recovery through September of 2016 of approximately 555 MBBL of oil and 407 MMCF of solution gas.  The TMS wells no longer flow gas to sales, so their only revenue streams are provided by oil sales.

OIL AND GAS PRICING

Projections of proved reserves contained in this report utilize constant product prices of $2.49 per MMBTU of gas and $42.75 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.    Table 2 summarizes these values. 

TABLE 2

CONTANGO – PRODUCT PRICE DIFFERENTIALS

AND NGL YIELD BY FIELD

OPERATING COSTS

Future operating costs for each of the Contango wells are held constant at current values for the life of the property.  Following is a brief description of the gross operating cost projections for each of the Contango properties:

For the 11 months of lease operating expense (LOE) data analyzed, the five Dutch wells had an average monthly operating cost of $345,479, or $69,096 per producing well.  The Mary Rose 1 through 4 wells had an average monthly operating cost of $297,792, or $74,448 per producing well, and were assumed to carry the expenses for the low rate Mary Rose 5 well.

Certain transportation and processing fees are applied to the wells producing to the ‘H’ platform, which were calculated using 11 months of LOE data.    For the Dutch wells, transportation and processing fees of $6.170 per net barrel of oil  and $2.422 per net barrel of NGL were scheduled.   A gas

processing fee of $0.083 per net produced MCF was also scheduled.  For the Mary Rose wells, transportation and processing fees of $5.606 per net barrel of oil and $2.222 per net barrel of NGL were scheduled. A gas processing fee of $0.075 per net produced MCF was also scheduled. 

For Ship Shoal 263,  a  fixed operating cost of $25,000 per month was estimated as the cost for insurance and a weekly platform visit, while the well awaits plugging and platform abandonment.

For Vermilion 170, operating costs were determined using the available historical expense data provided by Contango.  A fixed monthly operating cost of $135,153 was scheduled.  Variable costs of $0.053 per net MCF of produced gas, $1.570 per net barrel of oil, and $5.371 per net barrel of NGL were scheduled.

For South Timbalier 17-1, an operating cost of $14,282 per month was calculated from available historical expense data, with additional production and handling fees (PHA) applied.  Total PHA fees applied to historical gas volumes resulted in a modeled PHA fee of $0.471 per MCF of produced gas.  In addition to the PHA fees, product transportation and processing fees of $0.631 per net MCF of produced gas and $0.097 per net barrel of oil were scheduled. 

The Crosby Minerals 12-1, Foster Creek 20-7, Foster Creek 24-13, and Huff 18-7 had fixed operating costs of $22,457, $21,110,  $21,840, and $25,161 per month, respectively.  There were no variable costs as all costs were considered fixed; additional history and LOE detail may allow for some fixed costs to be moved to variable.

CAPITAL COSTS

All of the Contango properties are classified as developed-producing.  Therefore, no development costs are required.  However, abandonment costs, as provided by Contango, have been scheduled.  Platform abandonment costs are net of anticipated salvage value.  No salvage value for the individual wells has been considered.

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.  This report was prepared by associates of the firm who are licensed professional engineers with 14 to 40 years of experience in the estimation, assessment, and evaluation of oil and gas reserves. Frank J. Marek, a Registered Texas Professional Engineer and 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.