Exh991COISECJuly2013080913-2 (1)

In accordance with your request, William M. Cobb & Associates, Inc. (Cobb & Associates) has estimated the proved reserves and future income as of July 1, 2013, 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 August 7, 2013.

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 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.



				Future Net Pre-Tax Income – M$
Reserve Category	Net Gas (MMCF)	Net NGL (MBBL)	Net Oil (MBBL)	Undiscounted	Discounted at 10%
Proved
Producing	98,510	2,764	1,608	517,815	403,233
Non-Producing	48,008	1,314	689	230,147	120,537
Undeveloped	2,489	66	31	16,258	26,566
Total Proved	149,007	4,144	2,328	764,220	550,336

Total proved reserves expressed as MMCFE as of July 1, 2013 is 187,839. 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 60^o Fahrenheit and the legal pressure base for the specific location of the gas reserves.

It should be recognized that different levels of risk and uncertainty are associated with different reserve categories; however, the reserves and revenues presented in this report have not been adjusted for risk.

Our report, which was filed with Contango’s Form 10-K for the fiscal year ended June 30, 2013, covers 187,839 MMCFE, or 86.2 percent of the total reserves presented in Contango’s Form 10-K. The remaining 13.8 percent is attributable to Contango’s investment in Exaro Energy, LLC. We have used all assumptions, data, methods and procedures considered necessary and appropriate to prepare this report.

Eugene Island 10 is located in federal and state waters of the Gulf of Mexico. Water depth is 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.

Proved reserves for the Eugene Island 10 main CibOp sand are based on a field-wide P/Z performance plot, 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. A full-field reservoir simulation model has been constructed and history matched to rate

and pressure data from the field. Projections of future gas rates from the simulation model are utilized in this report. Our PDP projection is for the wells actually producing on July 1, 2013 using the current platform delivery pressure of 1,020 psi for the ‘H’ platform.

PDNP reserves are included for compression, which is scheduled for the Mary Rose wells in July, 2014. Compression will be initiated on the Dutch wells in October, 2015. Delivery pressures with compression will be initially lowered to 700 psi, eventually going to 200 psi. Remaining capital and start up costs for compression on the ‘H’ platform are approximately $1,500,000. Fuel charges are calculated based on a volume of 1,900 MCFPD, which is allocated to individual wells on compression at any point in time.

Contango has scheduled the Mary Rose 6 well as a PUD acceleration well in the main CibOp reservoir. This well provides significant acceleration benefits but minimal incremental reserves. The incremental net PV10% for this well is 26,566 M$. However, the incremental net reserves are 2,489 MMCF of gas, 31 MBBL of condensate, and 66 MBBL of NGL.

The Mary Rose 6 well is projected to recover more than 49 gross BCF of gas, or about 16.6 BCF net to Contango. However, the well is in communication with other wells in the main CibOp sand and much of the gas produced by this well comes from the existing producing wells. Only 2,489 MMCF of the 16.6 BCF net gas produced by the Mary Rose 6 well is incremental recovery. The main benefit of drilling this well is the rate acceleration, which results in an incremental PV10% value of 26,566 M$.

Contango’s working interest ownership is approximately 47 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 well is approximately 35 percent. Based on future net income, discounted at ten percent (PV10), approximately 89.6 percent of the 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.

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

660 MCF per day with 40 barrels of condensate. This well has minimal remaining reserves and is projected to be abandoned later this year.

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 12 MMCFPD with 285 barrels of condensate. Cumulative production to date is approximately 8.9 BCF of gas and 276 MBBL condensate. Proved reserves are based on a reservoir simulation model history matched to actual production and pressure performance.

Contango owns a working interest in the Crosby Minerals 12-1 well drilled and operated by Goodrich Petroleum. The well is located in Wilkinson County, Mississippi, and it produces from the Tuscaloosa Marine Shale at a depth of approximately 12,000 feet. The well was drilled as a horizontal well with a lateral length of about 6,900’. The well was hydraulically fractured in 25 stages. The well was recently place on a hydraulic pump and is producing at a rate of approximately

Projections of proved reserves contained in this report utilize constant product prices of $3.44 per MMBTU of gas and $91.57 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 and BTU factors were applied to each property. The NGL price was scheduled at 35.5 percent of the oil price based on recent data from wells producing to the ‘H’ platform. The average realized prices for the reserves presented in this report are $3.58 per MCF of gas, $111.25 per barrel of oil (condensate), and $39.50 per barrel of NGL.

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

The ‘H’ platform has a fixed monthly operating cost of $925,184. For compression in the PDNP and PUD cases, the platform receives $0.22 per MCF of gas as a fee charged back to the individual wells. Additionally for compression, there is a one-time expense of $187,046 scheduled in 2014 for compressor start-up and training and a yearly operating expense of $462,800 which is escalated at

For wells producing to the Contango ‘H’ platform, certain transportation and processing fees are applied. Transportation and processing fees of $2.075 per barrel of oil and $2.660 per barrel of NGL were scheduled. A gas processing fee of $0.070 per MCF was also scheduled. The gas shrinkage factor applied for the removal of NGL’s from the gas stream was determined to be 0.8795 MCF of sales gas per MCF of produced gas, and the NGL yield is 23.284 BBL/MMCF. When compression is

initiated on the ‘H’ platform, the wells are charged a $0.22 per MCF compression fee and their proportional value of the total 1.9 MMCFPD fuel gas burned by the compressor. The compressor fuel gas is charged at the prevailing gas price.

For Ship Shoal 263, a fixed operating cost of $70,847 per month was scheduled based on historical data provided by Contango. Variable costs were also scheduled as follows: $0.042 per MCF of gas, $3.199 per barrel of oil, and $3.978 per barrel of NGL. NGL production is based on a projected yield of 12.155 BBL per MCF and the resulting gas shrinkage factor is 0.9569 MCF of sales gas per MCF of produced gas. NGL price is scheduled as 48.1 percent of the oil price.

For Vermilion 170, operating costs were determined using the available historical expense data from Contango. A fixed monthly operating cost of $130,921 was scheduled. Variable costs of $0.099 per MCF of gas, $2.711 per barrel of oil, and $1.398 per barrel of NGL were scheduled. NGL production is based on a projected yield of 34.235 BBL per MCF and the resulting gas shrinkage factor is

Our definition of reserves may be found in Appendix A of this report. It is similar to and consistent with reserve definitions used throughout the industry. We have not made any field examination of the Contango properties; therefore, operating ability and condition of the production equipment have not been considered. No consideration was given in this report to potential environmental liabilities which may exist, nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices.

In evaluating the information at our disposal concerning this appraisal, we have excluded from our 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 such conclusions necessarily represent only informed professional judgments.

The reserves included in this report are estimates only and should not be construed as being exact quantities. The revenues from such reserves and the actual costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the prices actually received for the reserves evaluated in this report, and the costs incurred in recovering such reserves, may vary from the price and cost assumptions used in this report. Our

estimates are based upon the assumption that the properties will be operated in a prudent manner and that no government regulations and controls will be instituted that would impact the ability of Contango to recover the reserves. In any case, estimates of reserves may increase or decrease as a result of future operations.

Titles to the appraised properties have not been examined by Cobb & Associates, nor has the actual degree of interest owned been independently confirmed. The data used in our evaluation were obtained from Contango and the nonconfidential files of Cobb & Associates and were considered accurate. Basic field performance data, together with our engineering work sheets, are maintained on file in our office.

Proved 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 existing economic and operating conditions and current regulatory practices. Reserves are considered proved when commercial production has been established by actual production or well tests. The portion of the reservoir considered proved is the area delineated by drilling and reasonable interpretation of available data after considering fluid contacts, if any. Proved reserves may be developed or undeveloped.

Proved developed producing reserves are those reserves which are expected to be produced from existing completion intervals now open for production in existing wells.

Proved developed non-producing reserves are (1) those reserves expected to be produced from existing completion intervals in existing wells, but due to pending pipeline connections, regulatory agency considerations, or other mechanical or contractual requirements, hydrocarbon sales have not yet commenced or have been interrupted, and (2) other non-producing reserves which exist behind the casing of existing wells, or at minor depths below the present bottom of such wells, which are expected to be produced through these wells in the predictable future, where the cost of making such oil and gas available for production should be moderate when compared to the cost of a new well.

Proved undeveloped reserves are those reserves which are relatively certain to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required. Undeveloped reserves are considered proved when the interpretation of available geologic information, well test data, and production performance indicate the presence of commercial hydrocarbons that cannot be recovered from presently producing wells. Proved reserves on undrilled acreage are usually limited to proration units that offset wells that have established the existence of commercial quantities of hydrocarbons.

Probable reserves are those reserves which geological and engineering data demonstrate to be potentially recoverable, but where a higher element of risk or insufficient data prevent classification as proved. Probable reserves may include extensions of proved reservoirs or other reservoirs that have not been tested at commercial rate of flow.

Possible reserves are those less well defined reserves estimated beyond proved and probable reserves where geologic and engineering data suggest the presence of additional reserves, but where risk is relatively high.

drilling and reasonable interpretation of available data after considering fluid contacts, if any. Proved reserves may be developed or undeveloped.

Proved developed producing reserves are those reserves which are expected to be produced from existing completion intervals now open for production in existing wells.