Exhibit 99.1

WILLIAM M. COBB & ASSOCIATES, INC.

Worldwide Petroleum Consultants

August 20, 2013

Mr. Joseph J. Romano

Contango Oil & Gas Company

3700 Buffalo Speedway, Suite 960

Houston, TX 77098

Dear Mr. Romano:

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. This report was initially completed on August 18, 2012 and is being amended on August 20, 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.

TABLE 1

CONTANGO—NET RESERVES AND VALUE

AS OF JULY 1, 2012

CONSTANT OIL AND GAS PRICES

Mr. Joseph J. Romano

August 20, 2013

Page 2

Total proved reserves expressed as MMCFE as of July 1, 2012 is 256,564.984. This amount is calculated using 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, 2012, covers 256,565 MMCFE, or 100 percent of the total reserves presented in Contango’s Form 10-K. This amended report is being filed with Contango’s form 10-K/A for the fiscal year ended June 30, 2012. 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. 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 wells 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.

Mr. Joseph J. Romano

August 20, 2013

Page 3

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 43,322 M$. However, the incremental net reserves are 5,111 MMCF and a negative 41 MBBL of condensate.

The main CibOp reservoir is a depletion drive retrograde gas reservoir. The producing condensate yield has declined, and will continue to decline as reservoir pressure declines. Our reservoir simulation model indicates that the timing of the pressure depletion, and the distribution of that depletion across the field, will have an effect on all of the wells in communication with the Mary Rose 6 well. The effect of accelerating the pressure depletion, and changing the take points in the reservoir, is that more of the condensate “condenses” in the reservoir before it can be produced into the wellbores.

The Mary Rose 6 PUD reserves are calculated incrementally. The field-wide simulation model is run first without the Mary Rose 6 well to generate a total field gas and condensate projection for the PDP+PDNP reserve case. The model is then run again with the Mary Rose 6 well included as the total proved reserve case. The difference between these two cases, then, is the incremental PUD reserve case. The Mary Rose 6 well is projected to produce gross (8/8) volumes of 79,042 MMCF of gas and 1,233 MBBL of condensate. However, 66,568 MMCF of the Mary Rose 6 gas recovery comes from other wells in the field, such that the incremental 8/8 gas recovery for the Mary Rose 6 well is 12,474 MMCF.

In the field-wide prediction for the PDP+PDNP case, remaining condensate reserves (8/8) are 6,566 MBBL. When the Mary Rose 6 well is scheduled, total field condensate production is predicted to be 6,442 MBBL, 124 MBBL less than in the PDP+PDNP case. Thus, the incremental recovery for the Mary Rose 6 is a negative 124 MBBL (8/8). When Contango’s net revenue is applied to the affected wells, the net incremental condensate PUD reserves are a negative 41 MBBL. This is due to retrograde condensation occurring in the reservoir with accelerated pressure depletion caused by the Mary Rose 6 well.

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.

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.

Mr. Joseph J. Romano

August 20, 2013

Page 4

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 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.

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 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.

OIL AND GAS PRICING

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. The average realized prices for the reserves presented in this report are $3.22 per MCF of gas, $115.14 per barrel of oil (condensate), and $59.39 per barrel of NGL.

OPERATING COSTS

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.

Mr. Joseph J. Romano

August 20, 2013

Page 5

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.

OTHER

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 they 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.

Mr. Joseph J. Romano

August 20, 2013

Page 6

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.