Eagle Ford 8-K

Exhibit 99.1

Eagle Ford Oil & Gas Corporation (EFOGC) Estimated Future Reserves and Revenues East Pearsall Project 3,684 Acre Lease Block Frio County, Texas September 14, 2012 Prepared By Ronald A. Bain, PhD Eagle Ford Oil and Gas Corporation

Table of Contents Purpose of Report Summary Reserves Estimate Approach EUR and IP assumptions (Expected Case) Composite Production Profiles – Austin Chalk, Eagle Ford Shale, Buda Limestone Cash Flow Model (Expected Case) Individual Well Economics by Reservoir Cash Flow Model Assumptions “Expected Case” Development Plan Gross Future Possible Oil Reserves “Expected Case” “Upside Case” Estimated Net Revenues “Expected Case” “Upside Case” Well Costs Product Pricing Operating Expenses Values Not Considered Report Qualifications Examples of Data Sources Legacy Well Log Database Texas Railroad Commission Well & Production Database (DrillingInfo) Information from Shareholder Presentations

EFOGC Leasehold Plat Development Horizontal Well Pattern Plat Oil and Gas Reserves Definitions Curriculum Vitae – Ronald A. Bain. PhD Medallion Oil Company’s Concurrence Letter Oil and Gas Reserve Disclaimer The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only reserves that comply with the definitions presented at Rule 4 -10(a) of Regulation S-X. We use certain terms in this press release that the SEC's guidelines strictly prohibit us from including in filings with the SEC. Examples of such disclosures would be statements regarding "probable," "possible," "recoverable" or "proven" "reserves" and "resources" among others. U.S. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K, File No. 000-51656 and film no: 12969484 available from us at Eagle Ford Oil and Gas Corp., 1110 Nasa Pkwy, Suite 311, Houston, Texas 77058. Forward Looking Statements This report contains forward-looking statements (as defined in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended) concerning future events and the Company's growth and busin ess strategy. Words such as "expects," "will," "intends," "plans," "believes," "anticipates," "hopes," "estimates," and variations on such words and similar expressions are intended to identify forward-looking statements. Although the Company believes that the expectations reflected in such forward - looking statements are reasonable, no assurance can be given that such expectations will prove to have been correct. These statements involve known and unknown risks and are based upon a number of assumptions and estimates that are inherently subject to significant uncertainties and contingencies, many of which are beyond the control of the Company. Actual results may differ materially from those expressed or implied by such forward - looking statements. Factors that could cause actual results to differ materially include, but are not limited to, risks associated with drilling and production programs resulting from geological, technical, drilling, seismic and other unforeseen problems; unexpected results of exploration and development drilling and related activities; continued availability of capital and financing; increases in operating costs; risks associated with oil and gas operations in general; availability of skilled personnel; unpredictable weather conditions; and other factors listed from time to time in the Company's filings with the Securities and Exchange Commission. The Company expressly disclaims any obligations or undertaking to release publicly any updates or revisions to any forward -looking statements contained herein to reflect any change in the Company's expectations with respect thereto or any change in events, conditions or circumstances on which any statement is based.

Purpose of Report The purpose of this report is to provide to potential investors best estimates of possible hydrocarbon volumes and projected future net revenues from the lease block based upon analyses of currentl y available, pertinent data utilizing sound geological and engineering practices. Summary The expected case future oil and gas reserves and projected associated future net revenues have been estimated for the East Pearsall Project’s 3,684 acre lease block located in Frio County, Texas, of which 85% working interest is owned by Eagle Ford Oil & Gas. As current production has not been established on the lease block, no prove d producing reserves are currently present. Possible reserve calculations are based on nearby well production and industry-wide historical production versus time decline curves. The current wave of industry drilling activity in Frio County ramped up in 2010 and continues at high intensity. Industry estimates of ultimate recoveries from the reservoirs of interest continue to be updated and EFOGC actively monitors all pertinent drilling and comp letion activities.Based on the company’s geologic and engineering analyses as of September 14, 2012, the “Expected Case” reserves estimate and associated economic evaluation is as follows: Gross (100% WI) Future Possible Oil Equivalent (6,000cfg = 1 bo) Reserves (BOE) Estimated Net Revenues (NR) Revenues (and well costs) are based on 85% Working Interest; 63.75 Net Revenue Interest and non-escalated commodity pricing at $95.00 per Barrel Oil and $3.60/Mcf (BTU adjusted). Revenues and well costs are stated in $M.

Reserve Estimates Approach No current production from the lease block has been established. Possible reserve calculations are based on legacy lease (Austin Chalk) and nearby well production, industry-wide historical production versus time decline curves as well as shareholder presentations of publicly-traded operating companies. For each reservoir, a Composite Production Profile (CPP) was established for projection of production. The CPP’s were used for the production decline curves for the Austin Chalk, Eagle Ford Shale and Buda Limestone. In the “Expected Case”, per well EUR’s, oil and associated gas (and oil IP’s) are assumed to be: Below are the Composite Production Profiles for each reservoir used for the production forecasts.

Cash Flow Model – “Expected Case” A model cash flow economics of a n individual well was calculated for each of the Austin Chalk, Eagle Ford Shale and Buda Limestone formations. Cash Flow Model Assumptions: 1. 5 Year Cash Flow Model, even though the wells continue to produce substantial revenue for a total of 14 years. 2. 40 wells drilled (Austin Chalk - 12, Eagle Ford Shale – 6, Buda Lime - 22) beginning in QTR2 for 3 years at 160 acre spacing. Included is mechanical/dry hole values. 3. 63.75 NRI (85% Working Interest) 4. Oil Price: $95/bbl; Gas Price ( BTU adj): $3.60 5. EUR’s by reservoir (Buda 200 mbbls, 300 mmcf; Austin Chalk 150 mbbls, 225 mmcf; Eagle Ford 350 mbbls, 525 mmcf)

East Pearsall Project “Expected Case” Development Drilling Plan (40 Wells)

“Upside Case” Possible Oil and Gas Reserves In addition to the “Expected Case” reserve scenario, EFOGC has evaluated an “Upside Case” which includes 6 additional Austin Chalk and 6 additional Eagle Ford Shale wells. The technical rationale is based upon the possibility of economic production from these two formations at shallower depths in the northern portion of the leasehold. Also included are 10 wells completed in the deeper, gas condensate-rich Pearsall Shale which has been proven by historical drilling to be present within the leasehold. The Pearsall Shale is the latest of the formations to be targeted by industry in Frio County. Although the added depth increases well costs substantially, the industry is aggressively leasing rights to the Pearsall Shale contiguous to EFOGC’s leasehold. Although the industry holds detailed production information very confidentially, Cabot Oil and Gas and Cheyenne Petroleum have drilled wells in the vicinity that have flowed substantial amounts of gas and gas condensate in the range of 5MMcfpd and 500bcpd. Although great uncertainty exists due to the newness of the play, b ased upon available IP data and considering minimum economic requirements for the more expensive wells, EFOGC has estimated the per well EUR to be 3Bcfg and 240Mbc. For purpose of economic modeling, the Composite Production Profile for the Eagle Ford Shale has been applied to the Pearsall Shale. Using fracture stimulation techniques similar to the Eagle Ford Shale, a completed Pearsall Shale well is estimated to cost $10MM. A summary of the resultant “Upside Case” is: Gross (100% WI) Future Possible Oil Equivalent (6,000cfg = 1 bo) Reserves (BOE)

Well Costs Horizontal well costs for drilling and completing in the Austin Chalk, Eagle Ford Shale, Buda Limestone and Pearsall Shale were estimated. Drill depths to the reservoirs range from approximately 5000’ to 9,000’. Because the true vertical depth between the Austin Chalk and Buda Limestone is about 500’, the drilling and completion costs are approximately the same. The Eagle Fo rd Shale requires multi-stage hydraulic fracturing whereas the Austin Chalk and Buda Limestone require only an acid stimulation treatment. The horizontal length of the producing lateral is assumed to average 4,000’, although industry has drilled lateral lengths between 3,000’ and 7,000’. The Pearsall Shale well cost is based on deeper drilling and using fracture stimulation techniques similar to the Eagle Ford Shale. The industry continues to develop efficiencies in drilling and completion techniques. T he result is a continual downward trend in drilling and completion costs. Therefore, EFOGC believes that its current estimated drilling and completion costs likely represent a “high side” cost structure.

Product Pricing Product prices of $95.00 per barrel of oil and $3.00 per Mcf gas (Btu adjusted to $3.60/Mcf) were used in the cash flow models and economics calculations. No escalation of the oil or gas pricing was used over the life of the production. Operating Expenses For the Austin Chalk, Eagle Ford Shale and Buda Lime wells, the direct operating expenses were assumed to be $5,000 per month per well (non-escalated) with a $1.50 per barrel of oil water hauling costs, based on information for current operations in the area. This assumes that for each barrel of oil a barrel of water is produced (50% water cut). For the Pearsall Shale “upside case”, the direct operating expenses were assumed to be $3,000 per month per well (non -escalated) with a $1.50 per barrel of oil water hauling costs. Values Not Considered In all cases, attempts were made to accounts for all deductions from gross revenues except for the following items: Federal income tax and ad valorem taxes Depreciation, depletion, and/or amortization, if any Plugging and abandonment costs in excess of salvage value Land Costs Report Qualifications The future net revenues were based on projections of recoverable hydrocarbons, rates of production, direct taxes, and product prices. All estimated future net revenues present in this repor t are after the deduction of royalties, production costs, and development costs. This evaluation does not include indirect costs such as administrative, overhead, and other miscellaneous expenses.

EFOGC Leasehold Eagle Ford Oil & Gas 3,684 acre lease block, Frio County, Texas

Development Horizontal Well Pattern on Leasehold, Applicable to Austin Chalk, Eagle Ford Shale and Buda Limestone Reservoirs

Data Sources Historical production data were obtained from public sources, such as DrillingInfo and Lasser Production Data Services. Data including basic well information, geological interpretations, product prices, operating costs, initial test rates were obtained from various public sources, such as the Texas Railroad Commission, shareholder presentations and other private sources. Examples of Legacy Wells Database

Examples of Texas Railroad Commission Well and Production Database (DrillingInfo)

Examples of Information from Shareholder Presentations

Oil and Gas Reserve Definitions Approved by the Board of Directors, Society of Petroleum Engineers (SPE) Inc., and the Executive Board, World Petroleum Congresses (WPC), March 1997 Definition Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. The intent of the Society of Petroleum Engineers (SPE) and World Petroleum Congress (WPC) in approving additional classifications beyond proved reserves is to facilitate consistency among professionals using such terms. In presenting these definitions, neither organization is recommending public disclosure of reserves classified as unproved. Public disclosure of the quantities classified as unproved reserves is left to the discretion of the countries or companies involved. Estimation of reserves is done under conditions of uncertainty. The method of estimation is called deterministic if a single best estimate of reserves is made based on known geological, engineering, and economic data. The method of estimation is called probabilistic when the known geological, engineering, and economic data are used to generate a range of estimates and their associated probabilities. Identifying reserves as proved, probable, and possible has been the most frequent classification method and gives an indication of the probability of recovery. Because of potential differences in uncertainty, caution should be exercised when aggregating reserves of different classifications. Reserves estimates will generally be revised as additional geologic or engineering data becomes available or as economic conditions change. Reserves do not include quantities of petroleum being held in inventory, and may be reduced for usage or processing losses if required for financial reporting. Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. Proved Reserves Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods, and government regulations. Proved reserves can be categorized as developed or undeveloped. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. Establishment of current economic conditions should include relevant historical petroleum prices and associated costs and may involve an averaging period that is consistent with the purpose of the reserve estimate, appropriate contract obligations, corporate procedures, and government regulations involved in reporting these reserves. In general, reserves are considered proved if the commercial producibility of the reservoir is supported by actual production or formation tests. In this context, the term proved refers to the actual quantities of petroleum reserves and not just the productivity of the well or reservoir. In certain cases, proved reserves may be assigned on the basis of well logs and/or core analysis that indicate the subject reservoir is hydrocarbon bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. The area of the reservoir considered as proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) the undrilled portions of the reservoir that can reasonably be judged as commercially productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known occurrence of hydrocarbons controls the proved limit unless otherwise indicated by definitive geological, engineering or performance data. Reserves may be classified as proved if facilities to process and transport those reserves to market are operational at the time of the estimate or there is a reasonable expectation that such facilities will be installed. Reserves in undeveloped locations may be classified as proved undeveloped provided (1) the locations are direct offsets to wells that have indicated commercial production in the objective formation, (2) it is reasonably certain such locations are within the known proved productive limits of the objective formation, (3) the locations conform to existing well spacing regulations where applicable, and (4) it is reasonably certain the locations will be developed. Reserves from other locations are categorized as proved undeveloped only where interpretations of

Reserves which are to be produced through the application of established improved recovery methods are included in the proved classification when (1) successful testing by a pilot project or favorable response of an installed program in the same or an analogous reservoir with similar rock and fluid properties provides support for the analysis on which the project was based, and, (2) it is reasonably certain that the project will proceed. Reserves to be recovered by improved recovery methods that have yet to be established through commercially successful applications are included in the proved classification only (1) after a favorable production response from the subject reservoir from either (a) a representative pilot or (b) an installed program where the response provides support for the analysis on which the project is based and (2) it is reasonably certain the project will proceed. Unproved Reserves Unproved reserves are based on geologic and/or engineering data similar to that used in estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. Unproved reserves may be further classified as probable reserves and possible reserves. Unproved reserves may be estimated assuming future economic conditions different from those prevailing at the time of the estimate. The effect of possible future improvements in economic conditions and technological developments can be expressed by allocating appropriate quantities of reserves to the probable and possible classifications. Probable Reserves Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves. In general, probable reserves may include (1) reserves anticipated to be proved by normal stepout drilling where sub-surface control is inadequate to classify these reserves as proved, (2) reserves in formations that appear to be productive based on well log characteristics but lack core data or definitive tests and which are not analogous to producing or proved reservoirs in the area, (3) incremental reserves attributable to infill drilling that could have been classified as proved if closer statutory spacing had been approved at the time of the estimate, (4) reserves attributable to improved recovery methods that have been established by repeated commercially successful applications when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics appear favorable for commercial application, (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and the geologic interpretation indicates the subject area is structurally higher than the proved area, (6) reserves attributable to a future workover, treatment, re-treatment, change of equipment, or other mechanical procedures, where such procedure has not been proved successful in wells which exhibit similar behavior in analogous reservoirs, and (7) incremental reserves in proved reservoirs where an alternative interpretation of performance or volumetric data indicates more reserves than can be classified as proved. Possible Reserves Possible reserves are those unproved reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves. In this context, when probabilistic methods are used, there should be at least a 10% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible reserves. In general, possible reserves may include (1) reserves which, based on geological interpretations, could possibly exist beyond areas classified as probable, (2) reserves in formations that appear to be petroleum bearing based on log and core analysis but may not be productive at commercial rates, (3) incremental reserves attributed to infill drilling that are subject to technical uncertainty, (4) reserves attributed to improved recovery methods when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics are such that a reasonable doubt exists that the project will be commercial, and (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and geological interpretation indicates the subject area is structurally lower than the proved area. Reserve Status Categories Reserve status categories define the development and producing status of wells and reservoirs. Developed: Developed reserves are expected to be recovered from existing wells including reserves behind pipe. Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Developed reserves may be sub-categorized as producing or non-producing. Producing: Reserves subcategorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. Non-Producing: Reserves subcategorized as non-producing include shut-in and behind-pipe reserves. Shut-in reserves are

expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. Undeveloped Reserves: Undeveloped reserves are expected to be recovered: (1) from new wells on undrilled acreage, (2) from deepening existing wells to a different reservoir, or (3) where a relatively large expenditure is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

Curriculum Vitae - Dr. Ronald A. Bain Dr. Bain has been involved in the oil and gas exploration business for over thirty -eight years. Dr. Bain spent more than eighteen years of his extensive career at Anadarko Petroleum where he was responsible for Offshore and Onshore Gulf of Mexico Exploration, International Exploration, Exploration Technology and Planning , in addition to holding such prestigious positions as corporate Chief Geophysicist and Vice President and General Manager of Anadarko China. After retiring from Anadarko in 2001, Dr. Bain helped found Endeavour International, a publicly-traded E&P company focused on the North Sea. Following retirement from Endeavour International, he has consulted for various oil and gas companies in the US and internationally. Dr. Bain holds several degrees including a B.S. in Physics (University of Texas – Austin), M.S. in Physics (University of Pittsburgh) and a Ph.D. in Physics (University of Texas – Austin). Dr. Bain's expertise in oil and gas in enhanced by his knowledge as a geophys icist and also through his greater than thirty -eight years of experience in exploration, planning and development of oil and gas interests domestically and internationally. Dr. Bain has been an elected member of the University of Texas Geology Foundation A dvisory Council since 2000. Currently, Dr. Bain serves as Vice President, Geosciences for Eagle Ford Oil and Gas Corporation.

MEDALLION OIL COMPANY’S CONCURRENCE LETTER