Exhibit 99.1 Cobb Report

In accordance with your request, William M. Cobb & Associates, Inc. (Cobb & Associates) has estimated the proved reserves and future income as of July 1, 2012, 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. The properties are located in three fields; Eugene Island 10, Ship Shoal 263, and Vermilion 170.

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, or in other portions of this report, are not intended to necessarily represent an estimate of fair market value.



				Future Net Pre-Tax Income – M$
Reserve Category	Net Gas (MMCF)	Net NGL (MBBL)	Net Oil (MBBL)	Undiscounted	Discounted at 10%
Proved
Producing	145,100	4,170	2,799	851,035	607,101
Non-Producing	51,168	1,494	554	189,064	79,799
Undeveloped	5,111	222	-41	6,461	43,322
Total Proved	201,379	5,886	3,312	1,046,560	730,222

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.

The various categories of proved reserves have been combined in certain tables of this report for convenience and/or illustrative purposes. It should be recognized that different levels of risk and uncertainty are associated with these different reserve categories; however, the reserves and revenues presented in this report have not been adjusted for risk.

Our report, which is being filed with Contango’s Form 10-K for the fiscal year ended June 30, 2012, covers 256,565 MMCFE, or 100 percent of the total reserves presented in Contango’s Form 10-K. We have used all methods and procedures considered necessary under the circumstances 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. Contango has since drilled four more wells, the Dutch 2, 3, 4 and 5, on Federal acreage. The Dutch 1, 2, and 3 wells produce to the Chevron Eugene Island 24 platform. The Dutch 4 and 5 well produce to the Contango ‘H’ platform.

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. All five wells produce to the Contango ‘H’ platform located in Eugene Island Block 11.

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. A depletion drive system is anticipated. A full-field reservoir simulation model has been constructed and history matched to 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, 2012 using the current platform delivery pressures of 1,050 psi for the Chevron platform and 1,020 psi for the ‘H’ platform.

PDNP reserves are included for compression, which is scheduled for June, 2013. Delivery pressures with compression will be lowered to 200 psi. Capital costs for installation of flow lines and compression are $5,297,000 for flow lines and $12,735,000 for compression. Fuel charges are calculated based on a volume of 2,000 MCFPD for each platform at the current gas price.

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 77 percent of the Contango proved reserve value is attributable to the Eugene Island 10 main CibOp reservoir.

The output volumes from the full-field simulator are wet gas volumes only. We have utilized a PVT sample from the Dutch 2 well, along with predicted reservoir pressure values, to convert the wet gas volumes to sales gas, condensate, and NGL volumes.

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.

One future PUD well has been scheduled for the main CibOp reservoir. The Mary Rose 6 well is scheduled to be drilled and on production in April of 2013. This is primarily a rate acceleration well, with very little incremental recovery.

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 7.6 BCF of gas and 507 MBBL condensate. The well is currently producing at a rate of about 4.3 MMCF per day with 300 barrels of condensate. Proved reserves are based on a reservoir simulation model history matched to actual production and pressure performance.

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 17.7 MMCFPD with 500 barrels of condensate. Cumulative production to date is approximately 5.3 BCF of gas and 187 MBBL condensate. Proved reserves are based on a reservoir simulation model history matched to actual production and pressure performance.

Projections of proved reserves contained in this report utilize constant product prices of $3.13 per MMBTU of gas and $96.07 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 54.8 percent of the oil price for the wells producing to the Chevron platform and 52.2 percent for wells producing to the ‘H’ platform.

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:

For the Dutch 1 through 3 wells at Eugene Island 10, Contango pays fees to Chevron for production handling at the EI-24 platform. Based on historical data provided by Contango, the transportation and processing fees are $0.066 per MCF of produced gas, $1.659 per barrel of oil, and $4.034 per barrel of NGL. Additionally, a fixed operating cost of $171,522 per month per well was scheduled. The gas shrinkage factor applied for the removal of NGL’s from the gas stream was determined to be 0.8904 MCF of sales gas per MCF of produced gas.

For the Mary Rose 1 through 4 wells and the Dutch 4 and 5 wells, which produce to the Contango ‘H’ platform, a total fixed operating cost of $854,084 per month was scheduled along with certain transportation and processing fees. Transportation and processing fees of $1.082 per barrel of oil and $2.926 per barrel of NGL were scheduled. A gas processing fee of $0.045 per MCF was also scheduled. The gas shrinkage factor applied for the removal of NGL’s from the gas stream was determined to be 0.8793 MCF of sales gas per MCF of produced gas.

For Ship Shoal 263, a fixed operating cost of $232,046 per month was scheduled based on historical data provided by Contango. Variable costs were also scheduled as follows: $0.041 per MCF of gas, $3.548 per barrel of oil, and $2.606 per barrel of NGL. NGL production is based on a projected yield of 9.712 BBL per MCF and the resulting gas shrinkage factor is 0.9671 MCF of sales gas per MCF of produced gas. NGL price is scheduled as 60.3 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 $129,875 was scheduled. Variable costs of $0.023 per MCF of gas, $3.246 per barrel of oil, and $0.856 per barrel of NGL were scheduled. NGL production is based on a projected yield of 34.912 BBL per MCF and the resulting gas shrinkage factor is 0.8492 MCF of sales gas per MCF of produced gas. NGL price is scheduled as 44.3 percent of the oil price.

Figures 1 and 2 are included to highlight various conclusions regarding the Contango reserves. Figure 1 is a pie chart which shows the distribution reserve volumes and value (PV10) by reserve category for the total proved reserves. Figure 2 presents a projection of future net cash flow versus time for each proved reserve category and for the total proved reserves.

A summary economic projection for the Contango total proved reserves may be found in Table 2. Tables 3 through 18 contain economic projections for the Contango PDP reserves, with Table 3 being a total PDP summary. Similar economic projections for the Contango PDNP reserves

may be found in Tables 18 through 32, and for the PUD projections in Tables 33 through 34. All economic evaluations are made without consideration of federal income taxes.

Our definition of reserves may be found behind the tab entitled, “Reserve Definitions”. 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. 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.