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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended July 31, 2009

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from  _____ to _____

COMMISSION FILE NUMBER 000-52738

DORAL ENERGY CORP.
(Exact name of registrant as specified in its charter)

NEVADA	98-0555508
State or other jurisdiction of incorporation or organization	(I.R.S. Employer Identification No.)
415 West Wall, Suite 500
Midland, TX	79701
(Address of principal executive offices)	(Zip Code)
Registrant's telephone number, including area code:	(432) 789-1180
Securities registered pursuant to Section 12(b) of the Act:	NONE.
Securities registered pursuant to Section 12(g) of the Act:	Common Stock, $0.001 Par Value Per Share.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.
Yes [   ]    No [X]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [   ]    No [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X]    No [   ]   

Indicate by check mark whether the registrant has submitted electronically and posted on it’s corporate Web site, if any, every
Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during
the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files. Yes [   ]    No [   ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (s229.405 of this chapter) is not
contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [   ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller
reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule
12b-2 of the Exchange Act.

Large accelerated filer [   ]		Accelerated filer                      [   ]
Non-accelerated filer   [   ]	(Do not check if a smaller reporting company)	Smaller reporting company [X]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [   ]    No [X]

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to
the price at which the common equity was sold, or the average bid and asked price of such common equity, as of the last business
day of the registrant’s most recently completed second fiscal quarter: $23,832,724 based on a price of $3.05, being the last price
at which the shares of the Registrant's common stock were sold on the OTC Bulletin Board prior to the end of the most recently
completed second fiscal quarter.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
As of November 12, 2009, the Registrant had 87,116,480 shares of common stock outstanding.

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DORAL ENERGY CORP.

ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED JULY 31, 2009

TABLE OF CONTENTS

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PART I

The information in this discussion contains forward-looking statements. These forward-looking statements involve risks and uncertainties, including statements regarding the Company's capital needs, business strategy and expectations. Any statements contained herein that are not statements of historical facts may be deemed to be forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as "may," "will," "should," "expect," "plan," "intend," "anticipate," "believe," "estimate,” "predict," "potential" or "continue," the negative of such terms or other comparable terminology. Actual events or results may differ materially. In evaluating these statements, you should consider various factors, including the risks described below, and, from time to time, in other reports the Company files with the United States Securities and Exchange Commission (the “SEC”). These factors may cause the Company's actual results to differ materially from any forward-looking statement. The Company disclaims any obligation to publicly update these statements, or disclose any difference between its actual results and those reflected in these statements.

As used in this Annual Report, the terms “we,” “us,” “our,” “Doral,” “Doral Energy”, and the “Company” mean Doral Energy Corp. and its wholly owned subsidiary, unless otherwise indicated. All dollar amounts in this Annual Report are expressed in U.S. dollars, unless otherwise indicated.

ITEM 1.              BUSINESS

General

Doral Energy Corp. was incorporated on October 25, 2005 under the laws of the State of Nevada under the name “Language Enterprises Corp.” On January 7, 2008, we completed a 25-for-1 forward stock split of our common stock. As a result of the stock split, our authorized capital increased from 100,000,000 shares of common stock, with a par value of $0.001 per share, to 2,500,000,000 shares of common stock, with a par value of $0.001 per share (the "2008 Forward Split"). On April 28, 2008, we changed our name from “Language Enterprises Corp.” to “Doral Energy Corp.” To effect the name change, we incorporated a wholly-owned subsidiary (“SubCo”) and completed a merger of SubCo with and into the Company, with the Company continuing as the surviving entity. Other than the name change, no changes were made to our articles of incorporation as a result of the merger. On January 12, 2009, we completed a 6.25 -for-1 reverse split of our common stock, decreasing our authorized share capital from 2,500,000,000 shares of common stock, par value $0.001 per share, to 400,000,000 shares of common stock, par value $0.001 per share (the "2009 Reverse Split"). On September 14, 2009, we completed a 5-for-1 forward split of our common stock, increasing our authorized capital to 2,000,000,000 shares of common stock, par value $0.001 per share (the "2009 Forward Split"). Pursuant to the Nevada Revised Statutes, shareholder approval of the above actions was not required.

As Language Enterprises Corp., we previously operated a translation brokerage business, acting as an intermediary between clients and independent, professional translators. In early 2008, as Doral Energy Corp., we changed our business focus from translation services to the oil and gas industry. We are now an oil and gas exploitation and production company focused on identifying, acquiring and operating under-performing and under-producing oil and gas properties in the Permian Basin of West Texas and New Mexico with the goal of creating value by improving the performance and production of those properties. Our business strategy is to seek out and acquire oil and gas properties with proven, low risk reserves that are underperforming or are under-exploited due to such reasons as poor production and completion practices, the use of outdated and obsolete equipment, a lack of regular maintenance, or a lack of the necessary capital to develop proved developed non-producing (“PDNP”) and proved undeveloped (“PUD”) reserves.

Our principal executive offices are located at 415 West Wall Street, Suite 500, Midland, Texas 79701, and our telephone number is (432) 789-1180. Our internet website can be found at www.doralenergy.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 will be available through our internet website as soon as reasonably practical after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

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Business Development

From our inception, we have built our asset base primarily through property acquisitions and we plan to continue building our asset base in this manner. Our acquisitions are geographically focused in the Permian Basin of western Texas and southeastern New Mexico, which we have identified as the most attractive region in which to develop our business. The Permian Basin has been a top US oil and gas producing region for over 80 years. Because of its long history as a top producing region, the Permian Basin has attracted a wide spectrum of energy producing companies. In addition to hosting operations from virtually every major oil and gas company, the Permian Basin is also home to many independent operators of varying sizes.

Our plan is to seek out and acquire under-performing and under-producing oil and gas properties owned by independent operators with the goal of creating value by improving the performance and production of those properties. Our goal is to focus on the acquisition of producing properties with strong proven reserves and considerable undrilled proved undeveloped, shallow, low-risk reserves that can be developed with reasonably low levels of forward risk. By targeting properties with predominately shallow, low-risk, in fill proved undeveloped drilling locations and reserves, geological and reserve risks can be effectively mitigated. Further, our business development strategy involves finding acquisitions that can be paid for with a combination of cash and shares of our common stock, with an emphasis toward minimizing the cash outlay at the time of acquisition in order to preserve available cash for the exploitation and development of our properties in order to enhance production and create value. In order to increase the overall success of our acquisitions effort, we use our headquarters here in Midland and our industry contacts to seek out acquisitions through negotiated sales, avoiding bid situations, which also tends to reduce our acquisition costs when compared to industry metrics.

As of July 31, 2009, our estimated total proved reserves had a pre-tax PV10 (present value of future net revenues before income taxes discounted at 10%) of approximately $56.5 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $39.6 million. The difference between these two amounts is the effect of income taxes. We are presenting the pre-tax PV-10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Annual Report when comparing our asset base and performance to other comparable oil and gas companies.

As of July 31, 2009, we have a portfolio of oil and natural gas reserves, with approximately 91.9% of our proved reserves consisting of oil and 8.1% consisting of natural gas. Of those reserves, approximately 15.7% of our proved reserves are classified as proved developed producing, or “PDP”, approximately 4.8% of our proved reserves are classified as proved developed non-producing, or “PDNP”, and approximately 79.5% of our proved reserves are classified as proved undeveloped, or “PUD”.

Hedging Transactions

In August 2008, we entered into a “costless collar” hedging position, which provided us with partial protection against variations in the price of crude oil. The net effect of the costless collar was to set a floor of $100 on the price to be received for each barrel of production covered and a ceiling of $131 for each barrel of production covered.

During December 2008, we re-structured our hedge position to guarantee more near-term income by closing out our old position and using the value realized to enter into a combination of a swap and a costless collar, with more volume hedged in the near term. The swap, with a fixed price of $94 per barrel, covers the period from January 2009 through June 2010 and effectively guarantees us $94 per barrel on an average of our first 2,250 barrels of production each month. From July 2010 through December 2011, there is a costless collar in effect on an average of 1,850 barrels per month, guaranteeing a minimum of $60 per barrel and a maximum of $94 per barrel.

A “costless collar” or “zero cost collar” involves the simultaneous purchase of a put option and sale of a call option. The put option sets a floor for the covered position, while the call option sets a cap for the covered position. There is no net cost in entering into the costless collar as the cost of purchasing the put is offset by the proceeds of the call.

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Competitive Business Conditions

We operate in the oil and gas industry, which is a highly competitive environment. Competition is particularly intense with respect to the acquisition of desirable producing properties, the acquisition of oil and gas prospects suitable for enhanced production efforts, marketing oil and natural gas, and the hiring of experienced personnel. Our competitors in oil and gas acquisition, development, and production include the major oil companies in addition to numerous independent oil and gas companies, individual proprietors and drilling programs. Many of these competitors possess and employ financial and personnel resources substantially greater than those which are available to us and may be able to pay more for desirable producing properties and prospects and to define, evaluate, bid for, and purchase a greater number of producing properties and prospects than we can. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate, and select suitable properties and to consummate transactions in such a highly competitive environment, in competition with these companies. Also, there is substantial competition for capital available for investment in the oil and gas industry.

The actual price range of crude oil is largely established by major crude oil purchasers and commodities trading. Pricing for natural gas is based on regional supply and demand conditions. To this extent, we work to insure that we receive competitive oil and natural gas prices comparable to other producers in the areas which we operate. There is little risk of domestic overproduction at current prices is not deemed to be significant. We view our primary pricing risk to be related to a potential decline in oil and natural gas prices to a level which could render our current production uneconomical.

We are presently committed to using the services and existing gas gathering systems of the companies that purchase our natural gas production. This commitment is tied to existing natural gas purchasing contracts associated with our production. This commitment potentially gives such gathering companies certain short-term relative monopolistic powers to set gathering, transportation, and treating costs, because obtaining the services of an alternative gathering company would require substantial additional costs since an alternative gathering company would be required to lay a new pipeline and/or obtain new rights-of-way to any lease from which we are selling production. We are not subject to such third-party gathering systems for our oil production. A very small amount of our oil production is sold through a crude oil purchaser oil pipeline. All other oil production is transported by the oil purchaser by trucks with competitive trucking costs in the area.

Major Customers

For the fiscal year 2009, ending July 31, 2009, we had oil and natural gas sales to four customers, Navajo Refining Company, ConocoPhillips Company, DCP Midstream LP, and Frontier Field Services, which represented approximately 91.0%, 6.9%, 2.0%, and 0.1% of our oil and natural gas revenues, respectively. However, we believe that the loss of these customers would not materially impact our business, because we could readily find other purchasers for our oil and natural gas produced.

Government and Environmental Regulation

The oil and gas industry is subject to heavy regulation at the federal, state and local levels. These regulations include regulations:

• requiring permits for the drilling of wells,
• requiring the posting of bonds for drilling and/or operating wells,
• governing the location of wells,
• governing the methods used to drill wells,
• governing surface area usage and the restoration of the land upon which wells are drilled,
• governing the plugging and abandoning of wells and the disposal of waste materials used in or generated in drilling operations, and
• setting certain environmental conservation restrictions.

The cost of complying with these regulations is high and these regulations can have the effect of limiting our ability to engage in oil and gas exploration activities and when or where those activities take place. Some of these laws and regulations, including the federal Comprehensive Environmental Response, Compensation and Liability Act (also known as CERCLA or the “Superfund” law), may impose strict liability for environmental

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damage caused by hazardous wastes released during oil and gas exploration and production activities. As a result, we could become liable for the costs of environmental cleanups, environmental damages and, in some cases, consequential damages, regardless of whether or not there was any negligence or fault on our part. In some cases, regulations may also require oil and gas production levels to be kept at a level that is lower than what would be economically optimal. In other cases, we may be completely prohibited from drilling exploratory or production wells in certain environmentally sensitive areas even if we believe that there are economically viable oil and gas deposits in those areas. If we violate any of these environmental laws or regulations, we could become subject to heavy fines or sanctions and/or be required to incur significant costs for environmental clean up and remediation. In addition, neighboring landowners and other third parties could file claims for personal injury claims or for damage to property or natural resources caused by oil and gas exploration activities.

We believe that we are currently in substantial compliance with all applicable environmental laws and regulations. To date, we have not been required to expend substantial amounts of money in complying with these laws and regulations and we anticipate that the costs associated with future compliance will not have a materially adverse effect on our financial position. However, the laws and regulations governing the oil and gas industry are subject to constant change as environmental issues relating this industry remain highly politicized. Proposals and proceedings affecting oil and gas exploration activities are periodically presented to Congress and federal regulatory bodies as well as to state legislative and regulatory bodies. We cannot predict when or whether such proposals may become effective. There is no assurance that the future regulatory environment for oil and gas activities will be consistent with the current regulatory environment. We will need to constantly monitor developments in environmental and other laws and regulations applicable to oil and gas activities in order to ensure compliance. There is no assurance that we will be able to meet the costs associated with regulatory compliance in the future.

Employees

As of July 31, 2009, we employed 10 full-time employees. Our employees are not represented by a labor unit. We consider our relations with our employees to be satisfactory and have never experienced a work stoppage or strike.

We retain certain engineers, geologists, landmen, pumpers, and other personnel on a contract or fee basis as necessary for our field and office operations.

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ITEM 1A.            RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, financial condition or results of operation.

We have an operating deficit and have incurred losses since inception.

To date, our operations have not been profitable and we may never be able to achieve profitability.

We have not met all of our obligations under the Macquarie Credit Agreement and Macquarie could exercise its security rights on our properties. We will require additional financing to repay the amounts owed under the Macquarie Credit Agreement.

We did not meet our minimum quarterly operating cash flow and minimum quarterly production volume targets for the period ended October 31, 2008, and we did not meet our minimum quarterly operating cash flow targets for the periods ending January 31, 2009 and April 30, 2009, as set under the Macquarie Credit Agreement. As a result, Macquarie has the right to terminate its commitments under the Macquarie Credit Agreement and to declare the amounts owed to be immediately due and payable. If they exercise this right, Macquarie will also have the right to seize any of our properties over which they have a security interest, including the Eddy County Properties. The amounts owed by us under the Macquarie Credit Agreement are currently due and payable, and we do not currently have sufficient financial resources to repay the amounts owed. We have entered into a forbearance agreement, pursuant to which Macquarie has agreed not exercise their rights or remedies with respect to our failure to pay until at least January 29, 2009 (the “Forbearance Period”). There is no assurance that we will be able to pay the amounts due to Macquarie by the end of the Forbearance Period and there is no assurance that Macquarie will not exercise their rights and remedies in the future.

Our future performance depends upon our ability to obtain capital to find or acquire additional oil and natural gas reserves that are economically recoverable.

Unless we successfully replace the reserves that we produce, our reserves will decline, resulting eventually in a decrease in oil and natural gas production and lower revenues and cash flows from operations. The business of exploring for, developing or acquiring reserves is capital intensive. Our ability to make the necessary capital investment to maintain or expand our oil and natural gas reserves is limited by our relatively small size. Further, we may commence drilling operations on our Hanson Project Properties and any other properties that we acquire in an effort to increase production, which would require more capital than we have available from cash flow from operations or our existing debt facilities. In such case, we would be required to seek additional sources of financing or limit our participation in the additional drilling. In addition, our drilling activities are subject to numerous risks, including the risk that no commercially productive oil or gas reserves will be encountered.

The successful implementation of our business plan is subject to risks inherent in the oil and gas business, which if not adequately managed could result in additional losses.

Our oil and gas operations will be subject to the economic risks typically associated with exploitation and development activities, including the necessity of making significant expenditures to locate and acquire properties and to drill development wells. In addition, the availability of drilling rigs and the cost and timing of drilling, completing and, if warranted, operating wells is often uncertain. In conducting exploitation and development activities, the presence of unanticipated formation pressure or irregularities in formations, miscalculations or accidents may cause our exploitation, development and, if warranted, production activities to be unsuccessful. This could result in a total loss of our investment in a particular well. If exploitation and development efforts are unsuccessful in establishing proved reserves and development activities cease, the amounts accumulated as unproved costs will be charged against earnings as impairments.

In addition, the availability of a ready market for our oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines and other facilities. Our ability to market such production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, in most cases owned and operated by third parties. A failure to

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obtain such services on acceptable terms could materially harm our proposed oil and gas business. We may be required to shut in wells for lack of a market or because of inadequacy or unavailability of pipelines or gathering system capacity. If that occurs, we would be unable to realize revenue from those wells until arrangements are made to deliver such production to market.

Our future performance is dependent upon our ability to identify, acquire and develop oil and gas properties, the failure of which could result in under use of capital and losses.

The future performance of our oil and gas business will depend upon an ability to identify, acquire and develop oil and gas reserves that are economically recoverable. Success will depend upon the ability to acquire working and net revenue interests in properties upon which oil and gas reserves are ultimately discovered in commercial quantities, and the ability to develop prospects that contain proven oil and gas reserves to the point of production. Without successful acquisition, exploitation, and development activities, we will not be able to develop oil and gas reserves or generate revenues. There are no assurances oil and gas reserves will be identified or acquired on acceptable terms, or that oil and gas deposits will be discovered in sufficient quantities to enable us to recover our exploitation and development costs or sustain our business.

The successful acquisition and development of oil and gas properties requires an assessment of recoverable reserves, future oil and gas prices and operating costs, potential environmental and other liabilities, and other factors. Such assessments are necessarily inexact and their accuracy inherently uncertain. In addition, no assurances can be given that our exploitation and development activities will result in the discovery of any reserves. Operations may be curtailed, delayed or canceled as a result of lack of adequate capital and other factors, such as lack of availability of rigs and other equipment, title problems, weather, compliance with governmental regulations or price controls, mechanical difficulties, or unusual or unexpected formation pressures, and or work interruptions. In addition, the costs of exploitation and development may materially exceed our initial estimates.

The oil and gas exploration and production industry historically is a cyclical industry and market fluctuations in the prices of oil and gas could adversely affect our business.

Prices for oil and gas tend to fluctuate significantly in response to factors beyond our control. These factors include, but are not limited to:

(a)	weather conditions in the United States and elsewhere;
(b)	economic conditions, including demand for petroleum-based products, in the United States and elsewhere;
(c)	actions by OPEC, the Organization of Petroleum Exporting Countries;
(d)	political instability in the Middle East and other major oil and gas producing regions;
(e)	governmental regulations, both domestic and foreign;
(f)	domestic and foreign tax policy;
(g)	the pace adopted by foreign governments for the exploration, development, and production of their national reserves;
(h)	the price of foreign imports of oil and gas;
(i)	the cost of exploring for, producing and delivering oil and gas; the discovery rate of new oil and gas reserves;
(j)	the rate of decline of existing and new oil and gas reserves;
(k)	available pipeline and other oil and gas transportation capacity;
(l)	the ability of oil and gas companies to raise capital;
(m)	the overall supply and demand for oil and gas; and
(n)	the availability of alternate fuel sources.

Changes in commodity prices may significantly affect our capital resources, liquidity and expected operating results. Price changes will directly affect revenues and can indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in non-cash charges to earnings due to impairment. Changes in commodity prices may also significantly affect our ability to estimate the value of producing properties for acquisition and divestiture and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on the value of the properties. Price volatility

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also makes it difficult to budget for and project the return on acquisitions and the development and exploitation of projects. Commodity prices are expected to continue to fluctuate significantly in the future.

Hedging transactions may limit potential gains on increases to oil and gas prices.

We have entered into hedging transactions for a portion of our expected production to reduce the risk of fluctuations in oil and gas prices. Although these hedging transactions provide us with some protection in the event of a decrease in oil and gas prices, they may also limit our potential gains in the event that oil and gas prices increase. If we choose not to engage in hedging arrangements in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors, who may or may not engage in hedging arrangements.

We may encounter difficulty in obtaining equipment and services.

Higher oil and natural gas prices and increased oil and natural gas drilling activity generally stimulate increased demand and result in increased prices and unavailability for drilling rigs, crews, associated supplies, equipment and services. While we have recently been successful in acquiring or contracting for services, we could experience difficulty obtaining drilling rigs, crews, associated supplies, equipment and services in the future. These shortages could also result in increased costs or delays in timing of anticipated development or cause interests in oil and natural gas leases to lapse. We cannot be certain that we will be able to implement our drilling plans or at costs that will be as estimated or acceptable to us.

Our ability to produce oil and gas from our oil and gas assets may be adversely affected by a number of factors outside of our control.

The business of exploring for and producing oil and gas involves a substantial risk of investment loss. Drilling oil and gas wells involves the risk that the wells may be unproductive or that, although productive, the wells may not produce oil or gas in economic quantities. Other hazards, such as unusual or unexpected geological formation pressures, fires, blowouts, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well. Adverse weather conditions can also hinder drilling operations. A productive well may become uneconomic if excessive water or other deleterious substances are encountered that impair or prevent the production of oil or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances. There can be no assurance that oil and gas will be produced from the properties in which we have interests. In addition, the marketability of oil and gas that may be acquired or discovered may be influenced by numerous factors beyond our control. These factors include the proximity and capacity of oil and gas, gathering systems, pipelines and processing equipment, market fluctuations in oil and natural gas prices, taxes, royalties, land lease tenure, allowable production volumes, and environmental protection regulations.

If we are unable to maintain our working interests in leases, our business will be adversely affected.

Our oil and gas assets are held under oil and gas leases. A failure to meet the specific requirements of each lease may cause that lease to terminate or expire. There are no assurances the obligations required to maintain those leases will be met and that we will be able to meet the rental obligations under federal, state and private oil and gas leases. If we are unable to make rental payments and satisfy any other conditions on a timely basis, we may lose our rights in the properties that we may acquire.

Title deficiencies could render our leases worthless.

The existence of a material title deficiency can render a lease worthless and can result in a large expense to our business. In acquiring oil and gas leases or undivided interests in oil and gas leases we may forgo the expense of retaining lawyers to examine the title to the oil or gas interest to be placed under lease or already placed under lease. Instead, we may rely upon the judgment of oil and gas landmen who perform the field work in examining records in the appropriate governmental office before attempting to place under lease specific oil or gas interest. This is customary practice in the oil and gas industry. As a result, we may be unaware of deficiencies in the marketability of the title to the lease. Such deficiencies could render the lease worthless.

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If we fail to maintain adequate operating insurance, our business could be materially and adversely affected.

Our oil and gas operations are subject to risks inherent in the oil and gas industry, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution, earthquakes and other environmental risks. These risks could result in substantial losses due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage, and suspension of operations. We could be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could have a material adverse effect on our financial condition and results of operations. Any prospective drilling contractor or operator which we hire will be required to maintain insurance of various types to cover its operations with policy limits and retention liability customary in the industry. We maintain well control, re-drill, environmental cleanup, and liability insurance on all of our field production and future drilling operations. However, the occurrence of a significant adverse event on such prospects that would happen to be not fully covered by insurance could result in the loss of all or part of our investment in a particular prospect which could have a material adverse effect on our financial condition and results of operations.

Complying with environmental and other government regulations could be costly and could negatively impact prospective production.

The oil and gas business is governed by numerous laws and regulations at various levels of government. These laws and regulations govern the operation and maintenance of our facilities, the discharge of materials into the environment and other environmental protection issues. Such laws and regulations may, among other potential consequences, require that we acquire permits before commencing drilling and restrict the substances that can be released into the environment with drilling and production activities. Under these laws and regulations, we could be liable for personal injury, clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. Prior to commencement of drilling operations, we may secure limited insurance coverage for sudden and accidental environmental damages as well as environmental damage that occurs over time. However, we do not believe that insurance coverage for the full potential liability of environmental damages is available at a reasonable cost. Accordingly, we could be liable, or could be required to cease production on properties, if environmental damage occurs.

The costs of complying with environmental laws and regulations in the future may harm our business. Furthermore, future changes in environmental laws and regulations could occur, resulting in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on our financial condition or results of operations.

The oil and gas industry is highly competitive, and we may not have sufficient resources to compete effectively.

The oil and gas industry is highly competitive. We will be competing with oil and natural gas companies and other individual producers and operators, many of which have longer operating histories and substantially greater financial and other resources than it does, as well as companies in other industries supplying energy, fuel and other needs to consumers. Larger competitors, by reason of their size and relative financial strength, can more easily access capital markets than we can and may enjoy a competitive advantage in the recruitment of qualified personnel. They may be able to absorb the burden of any changes in laws and regulation in the jurisdictions in which we do business and handle longer periods of reduced prices for oil and gas more easily than we can. Competitors may be able to pay more for oil and gas leases and properties and may be able to define, evaluate, bid for and purchase a greater number of leases and properties than we can. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to acquire oil and gas properties will depend upon its ability to conduct efficient operations, evaluate and select suitable properties, implement advanced technologies and consummate transactions in a highly competitive environment.

The loss of our key persons, or our failure to attract and retain additional personnel could adversely affect our business.

Our success depends largely upon the efforts, abilities, and decision-making of Paul C. Kirkitelos, Chairman of our Board, Chief Financial Officer, Treasurer, and Secretary; Everett Willard Gray II, Chief Executive Officer and

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Vice-Chairman; H. Patrick Seale, President and Chief Operating Officer; and C. Martin Bloodworth, Vice President of Operations. The loss of these individuals would have an adverse effect on our business prospects. We do not currently maintain "key-man" life insurance and there is no contract in place assuring the services of Dr. Kirkitelos, Mr. Gray, Mr. Seale, or Mr. Bloodworth for any length of time. In the event that we should lose our officers and we are unable to find suitable replacements, we may not be able to develop our business, in which case investors might lose all of their investment.

Our management currently owns a large portion of our outstanding stock and may act to influence certain types of corporate actions, to the detriment of other stockholders.

Our management currently owns approximately 35.7% of our outstanding stock, with Dr. Paul C. Kirkitelos owning approximately 27.3%, and Mr. Everett Willard Gray, II owning approximately 6.7% . Accordingly, they may exercise significant influence over all matters requiring stockholder approval, including the election of directors and the determination of significant corporate actions. This concentration could also have the effect of delaying or preventing a change in control that could otherwise be beneficial to our stockholders.

If we issue additional shares of common stock in the future this may result in dilution to our existing stockholders.

Our articles of incorporation authorize the issuance of 2,000,000,000 shares of common stock. Our board of directors has the authority to issue additional shares of common stock up to the authorized capital stated in the articles of incorporation. Our board of directors may choose to issue some or all of such shares to provide additional financing in the future. The issuance of any such shares may result in a reduction of the book value or market price of the outstanding shares of our common stock. It will also cause a reduction in the proportionate ownership and voting power of all other stockholders.

We have never paid dividends and do not intend to pay any in the foreseeable future, which may delay or prevent recovery of your investment.

We have never paid any cash dividends and currently do not intend to pay any dividends in the foreseeable future. If we do not pay dividends, this may delay or prevent recovery of your investment. To the extent that we require additional funding currently not provided for in our financing plan, it is possible that our funding sources might prohibit the payment of dividends.

The trading price of our common stock may be volatile, with the result that an investor may not be able to sell any shares acquired at a price equal to or greater than the price paid by the investor.

Our common stock is quoted on the OTC Bulletin Board under the symbol "DRLY.” Companies quoted on the OTC Bulletin Board have traditionally experienced extreme price and volume fluctuations. In addition, our stock price may be adversely affected by factors that are unrelated or disproportionate to our operating performance. Market fluctuations, as well as general economic, political and market conditions such as recessions, interest rates or international currency fluctuations may adversely affect the market price of our common stock. As a result of this potential price and volume volatility, an investor may have difficulty selling any of our common stock that they acquire that a price equal or greater than the price paid by the investor.

Because our stock is a penny stock, stockholders will be more limited in their ability to sell their stock.

The SEC has adopted rules that regulate broker-dealer practices in connection with transactions in penny stocks. Penny stocks are generally equity securities with a price of less than $5.00, other than securities registered on certain national securities exchanges or quoted on the Nasdaq system, provided that current price and volume information with respect to transactions in such securities is provided by the exchange or quotation system.

Because our securities constitute "penny stocks" within the meaning of the rules, the rules apply to us and to our securities. The rules may further affect the ability of owners of shares to sell our securities in any market that might develop for them. As long as the trading price of our common stock is less than $5.00 per share, the common stock will be subject to Rule 15g-9 under the Securities Exchange Act of 1934 (the “Exchange Act”). The penny stock rules require a broker-dealer, prior to a transaction in a penny stock, to deliver a standardized risk disclosure document prepared by the SEC, that:

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1.	contains a description of the nature and level of risk in the market for penny stocks in both public offerings and secondary trading;
2.	contains a description of the broker's or dealer's duties to the customer and of the rights and remedies available to the customer with respect to a violation to such duties or other requirements of securities laws;
3.	contains a brief, clear, narrative description of a dealer market, including bid and ask prices for penny stocks and the significance of the spread between the bid and ask price;
4.	contains a toll-free telephone number for inquiries on disciplinary actions;
5.	defines significant terms in the disclosure document or in the conduct of trading in penny stocks; and
6.	contains such other information and is in such form, including language, type, size and format, as the SEC shall require by rule or regulation.

The broker-dealer also must provide, prior to effecting any transaction in a penny stock, the customer with: (a) bid and offer quotations for the penny stock; (b) the compensation of the broker-dealer and its salesperson in the transaction; (c) the number of shares to which such bid and ask prices apply, or other comparable information relating to the depth and liquidity of the market for such stock; and (d) a monthly account statements showing the market value of each penny stock held in the customer's account. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from those rules; the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser's written acknowledgment of the receipt of a risk disclosure statement, a written agreement to transactions involving penny stocks, and a signed and dated copy of a written suitably statement. These disclosure requirements may have the effect of reducing the trading activity in the secondary market for our stock.

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ITEM 2.              PROPERTIES

GENERAL BACKGROUND

From our inception, we have built our asset base primarily through property acquisitions that are geographically focused in the Permian Basin of West Texas and southeastern New Mexico, which we have identified as the most attractive region in which to develop our business.

As of July 31, 2009, our estimated proved reserves had a pre-tax PV10 (present value of future net revenues before income taxes discounted at 10%) of approximately $56.5 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $39.6 million. All of these reserves and values are currently contained in our Hanson Project, located in Eddy County, New Mexico.

The following table summarizes our total net proved reserves, pre-tax PV10 values, and Standardized Measure of Discounted Future Net Cash Flows as of July 31, 2009.

Proved Reserves

Our estimates of total proved reserves as of July 31, 2009 (“SEC Reserves”) are based on an independent, third-party reserve assessment and report prepared by Russell Hall & Associates of Midland, Texas, independent petroleum engineers, in accordance with the provisions of SFAS 69, “Disclosures About Oil and Gas Producing Activities”. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploitation and development, price changes, and other factors.

Our 3,351,031 BOE of total proved SEC Reserves, which consist of approximately 91.9% oil and 8.1% natural gas, are summarized below as of July 31, 2009, on a pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flow basis. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).

As of July 31, 2009, all of our proved reserves are located in the State of New Mexico. Approximately 15.7% of the total proved reserves have been classified as proved developed producing, or “PDP”. Proved developed non-producing, or “PDNP” reserves make up approximately 4.8% of the total proved reserves. Proved undeveloped, or “PUD” reserves constitute approximately 79.5% of the total proved reserves as of July 31, 2009.

Our total proved SEC Reserves had a net pre-tax PV10 value as of July 31, 2009 of approximately $56.5 million and a Standardized Measure of Future Net Cash Flows (the “Standardized Measure”) of approximately $39.6 __ million. PDP reserves represent a PV10 value of approximately $8.3 million, or 14.7% of the pre-tax PV10 value, and a Standardized Measure of $5.8 million. PDNP reserves represent an additional pre-tax PV10 value of $2.3 million, or 4.1%, and a Standardized Measure of $1.6 million. The remaining $45.9 million of pre-tax PV10, or 81.2%, and $32.1 million of Standardized Measure are associated with the PUD reserves. On October 28, 2009, we acquired a 40% working interest in certain oil and gas properties in Eddy County, New Mexico that we refer to as the Cave Pool Project. The SEC Reserves presented in this Annual Report do not include the Cave Pool Project as those properties were acquired after our fiscal year ended July 31, 2009.

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These total proved SEC Reserves were evaluated using fixed prices of $65.12/Bbl and $3.628/MCF, the actual prices received as of July 31, 2009. The SEC Reserves compare favorably to Doral’s independent third-party proved reserves prepared in accordance with the standards set by the Society of Petroleum Engineers (“SPE Reserves) also by Russell Hall & Associates, independent petroleum engineers, as of July 1, 2009. Our SPE Reserves were evaluated using NYMEX oil and gas prices $50.00/Bbl & $3.75/MMBtu for 2009, $55.00/Bbl & $4.00/MMBtu for 2010, $60.00/Bbl & $4.50/MMBtu for 2011, and $65.00/Bbl & $5.00/MMBtu thereafter, respectively, with no further escalation. Doral’s total proved SPE Reserves as of July 1, 2009 (as reported in August 2009) were 4,064,441 Bbls oil and 2,473,586 MCF gas (4,476,705 BOE); with PDP SPE Reserves of 514,481 Bbls and 61,715 MCF (524,767 BOE – 11.7% of total proved); PDNP SPE Reserves of 139,052 Bbls and 135,075 MCF (161,564 BOE – 3.6% of total proved); and PUD SPE Reserves of 3,410,908 Bbls and 2,276,796 MCF (3,790,374 BOE – 84.7% of total proved).

Our SEC Reserves differ from our SPE Reserves mainly in the area of PUD reserves where only 81 of the 138 PUD locations contained in our SPE Reserves case were developed in the SEC Reserves due to the capital constraints imposed on future development drilling under the SEC guidelines.

SUMMARY OF OIL AND NATURAL GAS PROPERTIES AND PROJECTS

Hanson Project – Eddy County, New Mexico

The Hanson Project, our first producing acquisition, was acquired in July 2008 from Hanson Energy, a small independent operator based in Artesia, New Mexico. The Hanson Project is comprised of 66 leases which cover a leasehold of approximately 7,868 acres, all of which is located on the northwestern end of the Permian Basin along the Artesia-Vacuum Trend, in eastern Eddy County, east of the city of Artesia, NM. Doral Energy Corp. is the Operator of all leases in the Hanson Project. At the time of the acquisition, the Hanson Project contained a total of 186 wells: 161 producing wells (143 oil wells & 18 gas wells), 12 shut-in wells, and 13 water injection wells. The Artesia-Vacuum Trend is generally viewed as consisting of thirteen reservoirs along the Upper San Andres and Grayburg Platform. While the Artesia-Vacuum Trend is a relatively mature play, recent development of lower permeability Grayburg sandstones in the Grayburg Jackson Pool reservoir has reversed the decline of

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production and is an active focus of current development. Our Hanson Project leases convey the shallow rights, generally extending from the surface to a depth of approximately 3,500 feet, generally down through the Grayburg and San Andres formations along with the Fren, Seven Rivers, Queen, Loco Hills, Premier, and other productive zones generally found within this stratigraphic column.

As of July 31, 2009, the Hanson Project contains total proved SEC Reserves of 3.078 million barrels of oil (“MMBO”) and 1.636 billion cubic feet of natural gas (“BCFG”), equal to 3.35 million barrels of oil equivalent (“MMBOE”). Of these total proved reserves, 0.52 MMBOE are classified as proved developed producing (“PDP”) reserves, 0.16 MMBOE are classified as proved developed non-producing (“PDNP”) reserves, and 2.67 MMBOE are classified as proved undeveloped (“PUD”) reserves. These SEC Reserves contain 81 PUD drilling locations on the Hanson Project leasehold, which represent 58.7% of the 138 PUD locations contained in our SPE Reserves evaluation, and 47.1% of the 172 undeveloped locations that we have identified on the Hanson Project leases and carry in our in-house reserves.

We currently own a 100% working interest (“WI”) and an average net revenue interest (“NRI”) of 74.70% in 55 of the 66 leases in the Hanson Project. We also own an average working interest of 84.40% and an average net revenue interest of 67.10% in the remaining 11 leases in the Hanson Project. For the Hanson Project overall, we own an average 97.5% WI and an average 73.5% NRI in the 66 leases when considered as a whole.

The Hanson Project properties were acquired from Hanson Energy in July 2008 for the following consideration:

	(a)	$5,000,000 in cash;
	(b)	5,600,000 post 2009 Reverse Split and 2009 Forward Split shares of our common stock; and
	(c)	An overriding royalty interest of 2.5% of 8/8ths of the oil and gas produced from the Hanson Project properties.

To complete the acquisition of the Hanson Project properties, on July 29, 2008, Doral entered into a Senior First Lien Secured Credit Agreement (the “Macquarie Credit Agreement”) with Macquarie Bank Limited (“Macquarie”). Under the terms of the Macquarie Credit Agreement, Macquarie agreed to provide Doral with: (i) a maximum of $25,000,000 under a revolving loan (the “Revolving Loan”); and (ii) a maximum of $25,000,000 under a term loan (the “Term Loan”). The amounts owed by us under the Macquarie Credit Agreement were due on July 30, 2009, however, Macquarie has agreed to forbear from exercising any of its remedies under the Macquarie Credit Agreement until at least January 29, 2010. The details of the Macquarie Credit Agreement are set out under heading “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation.” We are currently seeking to refinance the amounts owed by us under the Macquarie Credit Agreement.

In connection with entering into the Macquarie Credit Agreement, we granted to Macquarie Investment, LLC (“MAC”), a subsidiary of Macquarie, a net profits interest (the “MAC NPORRI”) over the Hanson Project properties. The MAC NPORRI entitles MAC to 35% of the net profits from the Hanson Project properties (proceeds less associated production and capital costs) beginning after all amounts due under the Macquarie Credit Agreement have been repaid. Once MAC has earned $5,000,000 under the MAC NPORRI, the MAC NPORRI net profits interest automatically reduces to 20%.

Over the past year, our improvement efforts in the Hanson Project have primarily involved:

	(a)	the inspection and evaluation of existing Project wells, pumping units, and production facilities to ascertain and ensure operational efficiency;
	(b)	testing of producing wells to ascertain accurate daily oil, gas and water production rates, and the testing of water injection rates to determine injectivity rates and pressures;
	(c)	performing mechanical repair job workovers to restore non-productive wells to production;
	(d)	performing repair and clean-out workovers, including well chemical treatments and acid stimulations to improve production rates; and
	(e)	improving downhole pump designs and improving production facility equipment, piping, and flowlines to increase operational efficiencies.

During our July 31, 2009 fiscal year, we completed the Phase 0 Initial Well Repair Job Work Program, a first stage improvement work program which carried out mechanical repair jobs on 17 wells in the Hanson Project from November 2008 through January 2009. Post-job well tests on these 17 wells showed that the mechanical repair jobs restored 64.5 barrels of oil production per day (“BOPD”) to the Hanson Project’s daily production,

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which was 164% of the pre-job estimate of 39.3 BOPD. In repairing these 17 wells, we found that none of the downhole pumps were working, and more over, all of the pumps were of the wrong type (highly inefficient travelling-barrel design pumps), the wrong size (1-1/2” diameter instead of the proper 1-1/4” diameter pumps for these types of wells), and set at the wrong depth in the wells (above instead of below the perforations). Additionally, all of the wells exhibited very heavy paraffin in the tubing, in the casing, and in the pumps themselves. The 17 wells were restored to production with the proper 1-1/4” bottom-hold-down downhole pumps, installed proper the depth below the perforations, set to pump at the proper pumping speed pump strokes per minute, and optimizing pumping time intervals to efficiently pump the oil and water from the wells based on the amount of inflow from the formation. The repair jobs also carried out the cutting and removing paraffin from the tubing and wellbore, replacing bad rods and tubing where required, replacing and repairing wellheads, and repairing flowlines. The total gross expenditures for the work program were $278,931 which was 87.1% of the AFE estimates. Since the initial program was completed, we have carried out mechanical repair jobs on an additional 14 wells in the Hanson Project with similar results. We estimate that an additional 75 wells in the Hanson Project are currently in need of similar repairs to restore production to more optimum rates, representing a significant opportunity to further increase Hanson Project’s daily production.

In addition to increasing production through repair jobs and improvements on existing wells, it is our long-term goal to create additional value by implementing an infill development drilling program on the Hanson Project properties. Almost all of the current producing wells in the Hanson Project were drilled on 40-acre well spacing per well. Over the past 20-30 years, offset operators along the Artesia-Vacuum Trend have determined that shallow wells like those in the Hanson Project actually drain less than 20 acres in these shallow reservoirs like the Grayburg, San Andres, Premier, Fren, and others. These operators have successfully carried out infill drilling programs on 20-acre spacing with very good success, accessing and developing oil and gas reserves that would not have been produced otherwise by the original wells drilled on 40-acre spacing patterns. By carrying out an infill development drilling program to redevelop the Hanson Project leases on 20-acre well spacing, we anticipate that we will increase production from the Hanson Project properties. We have identified over 250 potential 20-acre infill drilling locations on the Eddy County Properties, and 172 of these locations have been classified as proved undeveloped locations in our in-house reserves. In completing the independent third-party SEC Reserve report for the Hanson Project as of July 31, 2009, Russell Hall & Associates included 81 (47.2%) of these 172 undrilled infill locations as PUD locations due to capital constraints imposed of PUD development capital under SEC reserve guidelines. An infill development drilling program for the Hanson Project is expected to take several years to complete.

In 2008, our engineers and geologists worked to develop the initial infill development drilling program for the Hanson Project properties (the “Phase 1 Development Program”). The proposed Phase 1 Development Program called for the drilling and completion of 21 infill development wells on 20-acre spacing at an estimated cost of approximately $9.6 million in order to develop gross reserves of approximately 1.98 MMBOE (million barrels of oil equivalent) in 2009. However, when we presented this very detailed Phase 1 Development Program to Macquarie Bank in November 2008 (as required under the terms of the Macquarie Credit Agreement), Macquarie informed us that the bank was not funding any new drilling programs at that time due to uncertainties arising from the precipitous drop in the price of oil over the last half of 2008 and a lack of available capital. As a result, our management and Macquarie agreed that we would withdraw the Phase 1 Development Program at that time and re-submit it in early 2010.

We anticipate that the Phase 1 Development Program or an infill 20-acre development drilling program with the same or similar wells and targets will move forward in the coming months, hopefully beginning in early 2010. In addition, drilling costs have decreased significantly in recent months, making the capital investment required smaller and thus making the drilling program more economic. Also, continuing work by our engineers and geologists has shown that a majority of the drilling in the Hanson Project can be achieved using air drilling instead of conventional fluid drilling which will reduce our drilling costs even further. In any event, the selection and timing of infill wells to be drilled under any infill development drilling program in the Hanson Project will be made based on: (i) continuing new geological interpretations and structure and net pay maps of the pay zones being prepared; (ii) updated development drilling well reserves based on both the cumulative production to-date and estimated ultimate recovery of offset wells from the target reservoirs; (iii) the presence of previously undeveloped and un-produced intervals in target pay zones present on the lease; (iv) volumetric reserve calculations where appropriate; (v) the status of lease production facilities and capacities; and (vi) access to gas sales markets for casinghead gas production. Readers are cautioned, however, that there is no assurance that the infill development plan will proceed when scheduled, as currently proposed, or at all.

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Production History

The following table shows our net production volumes (net of royalties and amounts due to others), the average daily total net production rate, the average sales prices received, the average production costs (lifting costs) for oil and natural gas for the Hanson Project properties for the periods indicated.

During the fiscal year ending July 31, 2009, our gross production totalled 46,166 Bbls oil and 12,164 MCF gas (48,193 BOE), which resulted in Doral net production totals of 33,701 Bbls oil and 8,880 MCF gas (35,181 BOE). The average oil price receive during the year was $53.48/BO, and the average gas price received was $2.29/MCF, yielding an average total price of $52.02/BOE. Total lease operating expenses during the fiscal year of $2.046 million yielded an average production cost of $58.16/BOE for the fiscal year ending July 31, 2009. The average production tax rate paid during the fiscal year was $7.55/BOE.

The average sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold in barrels. The average gas sales price amounts above are calculated by dividing revenue from gas sales by the volume of gas sold, in MCF. The total average sales price amounts are calculated by dividing total revenues by total volume sold, BOE. The average production costs above are calculated by dividing production costs by total production in BOE.

Productive Wells

The following table represents our ownership of gross and net productive oil and gas wells as of July 31, 2008.

(1)	Gross wells refers to the number of wells in which Doral owns a working interest.
(2)	Net wells represents the number of wells attributable to our proportionate working interest in the respective gross wells.

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Developed and Undeveloped Acreage

The following table summarizes the approximate gross and net developed and undeveloped acreage owned by Doral as of July 31, 2009. Net acreage is our working interest percentage ownership of gross acreage. Acreage in which our interest is limited to a royalty or overriding royalty interest only is excluded from this table.

(1)	Developed acreage consists of spacing unit acres spaced assignable to productive wells.
(2)	Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains underlying proved reserves.
(3)	Gross acres refers to the number of acres in which we own a working interest.
(4)	Net acres represents the number of acres attributable to our proportionate working interest ownership in the gross acreage.

Drilling Activities

The following table shows the number of gross and net productive and dry development wells and exploratory wells drilled by us during the last three fiscal years. We did not drill any development or exploratory wells during the fiscal year ending July 31, 2009, and have not drilled any development or exploratory wells over the past 3 fiscal years.

Present Activities

As of July 31, 2009, we were not in the process of drilling any development or exploratory wells or conducting completion operations on any development or exploratory well.

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We are currently in the process of carrying out recompletion operations on one previously suspended well, the Mustang 28 Federal #1 well, located on the Company’s Federal S lease of the Hanson Project, approximately 0.5 mile south of Loco Hills, NM. This well was originally drilled to 5,490’ as a Paddock test well by Anadarko Petroleum Corp. in October 2001 and had been suspended since Anadarko ceased Paddock testing in early 2002. The wellbore was acquired by Doral as part of the Hanson Project which included rights from the surface to a depth of 4,000’ on the Federal S lease. Doral is in the process of recompleting this well as a Grayburg-San Andres completion in the Grayburg Jackson Pool.

Delivery Commitments

As of July 31, 2009, the Company had no obligations or delivery commitments under any existing contracts.

Other Projects and Properties

Cave Pool Project – Eddy County, New Mexico

On October 28, 2009, Doral West Corp. (“Doral West”), a wholly owned subsidiary of Doral Energy Corp., entered into an agreement (the “Blugrass Agreement”) with Blugrass Energy Inc. (“Blugrass”) to purchase a 40% working interest in certain oil and gas properties (the “Cave Pool Unit Properties”) located in and around the Cave Pool Unit in Eddy County, New Mexico approximately 5 miles northwest of Loco Hills, New Mexico. The effective date of the acquisition is October 12, 2009. The Cave Pool Unit Properties are comprised of the Cave Pool Unit and ten (10) leases that make up approximately 2,800 gross acres of leasehold, which Doral now designates as the Cave Pool Project. The Cave Pool Project currently produces approximately 10 BOEPD from a total of 39 wells completed in the Grayburg formation in the Grayburg Jackson Pool.

The Cave Pool Unit Properties are located adjacent to 3 leases that are a part of our Hanson Project, which contain 6 wells producing from the Grayburg and San Andres formations and 9 PUD locations in the Square Lake Field. As operator of the Cave Pool Project, we envision a re-development of the Cave Pool Unit Properties as a 20-acre 5-spot Grayburg waterflood project which has the potential to develop significant undeveloped reserves.

The Cave Pool Unit Properties were acquired by Blugrass from Robinhood LLC on October 12, 2009. Under the terms of the Blugrass Agreement, we have acquired a 40% interest is all of Blugrass’ right, title and interest in the Cave Pool Unit Properties, including the production on-hand and sales generated from the properties after the effective date of October 12, 2009. In consideration for this interest Doral has agreed to:

	1.	Share with Blugrass access to appropriate Doral proprietary geological and engineering data and information to enhance the re-development of the Cave Pool Unit Properties;
	2.	Pay for and cause the preparation of an independent third-party reserve report on the Cave Pool Unit Properties to be prepared;
	3.	Pay for and obtain title opinions for the leases contained in the Cave Pool Project; and
	4.	Be assigned as the Operator of the Cave Pool Project.

For their part, Blugrass has agreed to pay for the first $200,000 of well repairs and workovers on the Cave Pool Unit Properties, with Doral West and Blugrass proportionately sharing the cost of all repairs and workovers thereafter. An initial 10 Cave Pool Project wells have been identified for repair jobs and will be re-worked by Doral in the near future, adding to the daily production from the Project.

In addition, the Blugrass Agreement provides that, if Blugrass chooses to sell their remaining interest in the Cave Pool Unit Properties, Doral will have a preferential right to purchase that interest at the greater of:

	(a)	$2,000,000; or
	(b)	$40,000 per producing net barrel of oil equivalent per day (“BOEPD”) from the Cave Pool Unit Properties.

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The following table shows the effect of the acquisition of the Cave Pool Project on our productive wells after October 12, 2009. The Cave Pool Project will increase our number of Oil Wells to 179 wells (gross) and 153.50 wells (net); our Gas Wells to 19 wells (gross) and 18.40 wells (net); and our Total Productive Wells to 198 wells (gross) and 172.00 wells (net).

	(1)	Gross wells refers to the number of wells in which Doral owns a working interest.
	(2)	Net wells represents the number of wells attributable to our proportionate working interest in the respective gross wells.

Correspondingly, the following table shows the effect of the acquisition of the Cave Pool Project on our Developed and Undeveloped Acreage after October 12, 2009. The Cave Pool Project will increase our Developed Acreage to 7,329 acres (gross) and 6,436.5 acres (net); our Undeveloped Acreage to 3,139 acres (gross) and 2,247.9 acres (net); and our Total Acreage to 10,468 acres (gross) and 8,684.4 acres (net) in Eddy County, New Mexico.

	(1)	Developed acreage consists of spacing unit acres spaced assignable to productive wells.
	(2)	Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains underlying proved reserves.
	(3)	Gross acres refers to the number of acres in which we own a working interest.
	(4)	Net acres represents the number of acres attributable to our proportionate working interest ownership in the gross acreage.

Miltex Properties – Cochran County, Texas

On January 15, 2009, we entered into an agreement (the “Miltex Agreement”) with Miltex Oil Company (“Miltex”) for the acquisition of six (6) San Andres waterflood units located in Cochran County, Texas (the “Miltex Properties”). Pursuant to the terms of the Miltex Agreement and pursuant to amendment agreements dated February 23, 2009, March 31, 2009, and April 21, 2009, we paid to Miltex a total of $245,000 in cash and a total of 250,000 post 2009 Forward Split shares towards the purchase of the Miltex Properties.

On July 30, 2009, we assigned our right to purchase the Miltex Properties to Legacy Reserves LP in consideration for a total of $750,000 in cash, consisting of $600,000 for the assignment of our right to purchase the Miltex Properties, plus an additional $150,000 to reimburse us for amounts due to a third party for brokering the sale of the Miltex Properties.

Slape Oil Company, Inc. and Flaming S, Inc. – Cochran & Hockley Counties, Texas

On May 5, 2009 and May 15, 2009, respectively, we entered into agreements for the acquisition of Flaming S, Inc. (“Flaming S”) and Slape Oil Company, Inc. (“Slape Oil”). Flaming S and Slape Oil are oil and gas corporations with producing properties in Cochran and Hockley Counties, Texas. In July 2009, the agreements

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to acquire Flaming S and Slape Oil were cancelled. A total of 400,000 shares of Doral restricted common stock issued to the shareholders of Flaming S and Slape Oil as deposits were returned to the Company.

ITEM 3.                LEGAL PROCEEDINGS

We are not a party to any legal proceedings outside of ordinary routine proceedings incidental to our business and which, in the aggregate, do not involve amounts greater than 10% of our current assets.

ITEM 4.                SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to our security holders during the fourth quarter of our fiscal year ended July 31, 2009.

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PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Quotations for our common stock were entered on the OTC Bulletin Board (the “OTCBB”) under the symbol LNGG beginning on April 20, 2007. Our symbol was changed to LNGE on January 8, 2008 upon completion of our 25-for-1 forward stock split. As a result of our name change to Doral Energy Corp., our symbol was changed to DENG on April 30, 2008. On January 23, 2009, as a result of our 1-for-6.25 reverse stock split, our symbol was changed to DEGY. On September 14, 2009, as a result of our 5-for-1 forward stock split, our symbol was changed to DRLY.

The high and the low bid prices for our shares for the last two fiscal years as reported by the OTCBB were:

The above quotations have been adjusted to reflect the 2008 Forward Split, the 2009 Reverse Split and the 2009 Forward Split. Quotations provided by the OTCBB reflect inter-dealer prices, without retail mark-up, markdown or commission and may not represent actual transactions.

Holders

As of November 12, 2009, there were 87,116,470 shares of our common stock issued and outstanding that are held of record by 31 registered stockholders. We believe that a number of stockholders hold their shares of our common stock in brokerage accounts and registered in the name of stock depositories.

Dividends

We have not declared any dividends on our common stock since our inception. There are no dividend restrictions that limit our ability to pay dividends on our common stock in our Articles of Incorporation or Bylaws. Our governing statute, Chapter 78 of the Nevada Revised Statutes (the “NRS”), does provide limitations on our ability to declare dividends. Section 78.288 of the NRS prohibits us from declaring dividends where, after giving effect to the distribution of the dividend:

(a)	we would not be able to pay our debts as they become due in the usual course of business; or
(b)	our total assets would be less than the sum of our total liabilities plus the amount that would be needed, if we were to be dissolved at the time of distribution, to satisfy the preferential rights upon dissolution of stockholders who may have preferential rights and whose preferential rights are superior to those receiving the distribution (except as otherwise specifically allowed by our Articles of Incorporation).

Recent Sales of Unregistered Securities

All unregistered sales of our equity securities made during the year ended July 31, 2009 have been reported by us in our Quarterly Reports or in our Current Reports filed with the SEC during the year.

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RESULTS OF OPERATION

Summary of Year End Results
		Year Ended July 31						Percentage
		2009			2008			Increase / (Decrease)
Revenue	$	1,832,146		$	-			n/a
Expenses		(4,235,933	)		(493,929	)		757.6%
Gain on Sale of Oil and Gas Properties		131,288			-			n/a
and Other
Interest Expense		(947,705	)		(9,943	)		9,431.4%
Price Risk Management Activities		1,317,839			-			n/a
Income Tax Expense		9,602			-			n/a
Net Loss	$	(1,911,967	)	$	(503,872	)		279.5%

Revenues

During the year ended July 31, 2009 we recognized revenues from the sale of crude oil and natural gas of $1,832,146. Revenues recognized from the Eddy County Properties were lower than those recognized for the year ended July 31, 2008 by the previous operators, Hanson Energy. See Note 3 to the unaudited financial statements included in this Annual Report. We believe that the primary reason that revenues were lower for the year ended July 31, 2009 is that the average price of crude oil was significantly lower during the year ended July 31, 2009 as compared to the comparable year ended July 31, 2008. This decrease was partially offset by an increase in the volume of oil produced. Revenues from the sale of oil and gas are recognized based on the actual volume of oil and gas sold to purchasers. Although we have begun to incrementally increase production from the Hanson Project Properties by making improvements to existing well facilities, our revenues are also subject to fluctuations in the market price of crude oil and natural gas. Although we have entered into hedging positions that provide us with partial protection against price decreases, prolonged downturns in the price of crude oil and natural gas will have an adverse effect on our revenues. See “Risk Factors.”

Under the terms of the Macquarie Credit Agreement, we are required, on a monthly basis, to pay to Macquarie 100% of our net operating cash flows from all sources (including, but not limited to the Hanson Project Properties) less an allocated amount for our general and administrative expenses, until all amounts advanced under the Macquarie Credit Agreement have been repaid. The amount allocated for our general and administrative expenses was equal to $125,000 per month up to March 31, 2009, and since that date has been equal to 10% of our net operating cash flows for the month. The amounts paid to Macquarie are applied to interest and principal payable under the Macquarie Credit Agreement.

Operating Expenses

Our operating expenses for the years ended July 31, 2009 and 2008, consisted of the following:

		Year Ended July 31,						Percentage
		2009			2008			Increase / (Decrease)
Operating Costs	$	1,780,266		$	-			n/a
Production Taxes		265,780			-			n/a
Depreciation, Depletion, and Amortization		451,994			144			313,784.7%
Accretion Expense		74,820			-			n/a
General and Administrative		1,663,073			493,785			236.8%
Total	$	4,235,933		$	493,929			757.6%

Our expenses for the year ended July 31, 2009 increased substantially as compared to the year ended July 31, 2008. Operating costs are the costs associated with our oil and gas production activities for the period.

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Production taxes are severance and ad valorem taxes payable in respect of the oil and gas production from our properties.

Our expenses for the year ended July 31, 2008 were significantly lower as we had little to no operations during that period. Expenses for the year ended July 31, 2009 are expected to be more indicative of our future expenses. However, expenses in future periods may be significantly greater depending upon the extent of any developmental activities that we engage in on our properties.

Price Risk Management Activities

We previously entered into a “costless collar” hedging position, which provides us with partial protection against variations in the price of crude oil. The net effect of the costless collar was to set a floor of $100 on the price to be received for each barrel of production covered and a ceiling of $131 for each barrel of production covered. The number of barrels of our production covered by the costless collar for production months through July 2011 was as follows:

Aug 2008 - Dec 2008: 1,900 barrels per month
Jan 2009 - Dec 2009: 1,700 barrels per month
Jan 2010 - Dec 2010: 1,600 barrels per month
Jan 2011 - Jul 2011: 1,400 barrels per month

During December 2008, we re-structured our hedge position to guarantee more near-term income by closing out our old position and using the value realized to enter into a combination of a swap and a costless collar, with more volume hedged in the near term. The swap, with a fixed price of $94, covers the period from January 2009 through June 2010 and effectively guarantees us $94 per barrel on an average of our first 2,250 barrels of production each month. From July 2010 through December 2011, there is a costless collar in effect on an average of 1,850 barrels per month, guaranteeing a minimum of $60 a barrel and a maximum of $94 a barrel.

Included in price risk management activities for the year ended July 31, 2009 are hedge settlements of $903,960. These settlements represent the difference between the hedge prices of $100 and the actual price received for the volumes hedged for the months of August – December 2008 and the difference between the hedge price of $94 and the actual price received for the volumes hedged for the months of January 2009 through July 2009.

During the year ended July 31, 2009, we recognized a derivative asset of $413,879, with the change in fair value reflected in other income.

LIQUIDITY AND CAPITAL RESOURCES

Working Capital
								Percentage
		At July 31, 2009			At July 31, 2008			Increase / (Decrease)
Current Assets	$	1,310,324		$	687,136			90.7%
Current Liabilities		(7,538,514	)		(271,251	)		2,679.2%
Working Capital (Deficit)	$	(6,228,190	)	$	415,885			(1,397.6)%

Cash Flows
		Year Ended			Year Ended
		July 31, 2009			July 31, 2008
Cash Flows Used in Operating Activities	$	(868,000	)	$	(294,632	)
Cash Flows Used in Investing Activities		(375,578	)		(5,097,090	)
Cash Flows From Financing Activities		1,625,884			5,415,000
Net Increase (Decrease) in Cash During Period	$	382,306		$	23,278

As at July 31, 2009, we had a working capital deficit of $6,228,190.

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Although the Hanson Project Properties generate cash flows, under the terms of our Macquarie Credit Agreement with Macquarie, until we have repaid all amounts advanced by Macquarie, we are required to pay Macquarie 100% of our net operating cash flows from all sources, less an allocated amount for our general administrative expenses. As such, until such time as we have repaid all amounts advanced to us by Macquarie, we expect that our primary sources of financing will be additional advances from Macquarie under the Macquarie Credit Agreement, other forms of debt financing, and proceeds from the sale of our common stock. We are currently seeking to refinance our existing debt, including the amounts owed under the Macquarie Credit Agreement. However, there is no assurance that we will be able to refinance our existing debt or that we will be able to obtain additional financing in the future. If we sell additional shares of our common stock, existing stockholders will experience a dilution of their proportionate interests in our Company.

Macquarie Credit Agreement

Under the terms of the Macquarie Credit Agreement, Macquarie agreed to provide us with: (i) a maximum of $25,000,000 under a revolving loan (the “Revolving Loan”); and (ii) a maximum of $25,000,000 under a term loan (the “Term Loan”). Advances under the Macquarie Credit Agreement were used to fund our acquisition of, and improvements on, the Hanson Project Properties and for working capital purposes. Future advances are subject to prior approval by Macquarie, and we are required to submit to Macquarie an estimate of expenses for work to be performed on our properties.

We did not meet our minimum quarterly operating cash flow and minimum quarterly production volume targets for the period ended October 31, 2008, and we did not meet our minimum quarterly operating cash flow targets for the periods ending January 31, 2009 and April 30, 2009. Under the terms of the Macquarie Credit Agreement, Macquarie has the right to declare us in default of our obligations and to declare the amounts due under the Macquarie Credit Agreement to be immediately payable. Macquarie has not yet exercised these rights and has not provided us with any indications that it intends to do so at this time. However, there is no assurance that Macquarie will not exercise its right to declare us in default in the future.

Due to our management’s decision to temporarily postpone our proposed Infill Development Plan for the Hanson Project Properties in response to the precipitous decline in the price of oil from mid-2008, the due date for the amounts owed by us under the Macquarie Credit Agreement was moved up from July 30, 2011 to July 30, 2009. Macquarie has agreed to forbear from exercising its remedies under the Macquarie Credit Agreement until at least January 29, 2010. To obtain Macquarie’s agreement to forbear from exercising its remedies, we:

	(a)	paid Macquarie a fee of $25,000;
	(b)	agreed to an increased interest rate on amounts owed under the Macquarie Credit Agreement to:
		(i)	with respect to the Revolving Loan, 3.5% over LIBOR in respect of amounts earning interest tied to LIBOR, and 1.75% over prime in respect of amounts earning interest tied to the prime rate, and
		(ii)	with respect to the Term Loan, 7.0% over LIBOR in respect of amounts earning interest tied to LIBOR, and 5.25% over prime in respect of amounts earning interest tied to the prime rate.

In addition, the terms of the forbearance agreement provide that, if we do not receive a valid offer to purchase some or all of the Hanson Project Properties by November 30, 2009 and we have accounts payable greater than $125,000 that are past due, we will be required to pay Macquarie an additional fee of $50,000, and interest rates under the Macquarie Credit Agreement will increase as follows:

	(i)	with respect to the Revolving Loan, 4.0% over LIBOR in respect of amounts earning interest tied to LIBOR, and 2.25% over prime in respect of amounts earning interest tied to the prime rate; and
	(ii)	with respect to the Term Loan, 7.5% over LIBOR in respect of amounts earning interest tied to LIBOR, and 5.75% over prime in respect of amounts earning interest tied to the prime rate.

If we do not receive a valid offer to purchase some or all of the Hanson Project Properties by December 31, 2009 and we have accounts payable greater than $100,000 that are past due, we will be required to pay

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Macquarie an additional fee of $100,000 and interest rates under the Macquarie Credit Agreement will increase as follows:

	(i)	with respect to the Revolving Loan, 5.5% over LIBOR in respect of amounts earning interest tied to LIBOR, and 3.75% over prime in respect of amounts earning interest tied to the prime rate; and
	(ii)	with respect to the Term Loan, 9.0% over LIBOR in respect of amounts earning interest tied to LIBOR, and 7.25% over prime in respect of amounts earning interest tied to the prime rate.

As of July 31, 2009, we owed Macquarie $5,888,196. We are currently seeking to refinance the amounts owed by us under the Macquarie Credit Agreement, however there is no assurance that we will be able to do so.

Other Debt Financings

On February 24, 2009, we borrowed $100,000 from Green Shoe Investments Ltd. (“Green Shoe”) with interest payable at a rate of 5% per annum. The loan is unsecured and due on or before March 1, 2011.

On April 29, 2009, we borrowed $87,000 from Green Shoe. The amount borrowed from Green Shoe is due on or before May 1, 2011, bears interest at a rate of 5% per annum, and is unsecured.

On May 28, 2009, we received $150,000 in debt financing from Green Shoe Investments Ltd. (“Green Shoe”) On June 10, 2009 we entered into an agreement dated effective as of May 28, 2009 (the “Green Shoe Note Agreement”) with Green Shoe whereby, in exchange for the $150,000 provided by Green Shoe, we agreed to issue a convertible note in the principal amount of $300,000. The convertible note is due 10 business days after the earlier of the maturity date of the amounts owed to Macquarie Bank Limited (“Macquarie”) under the terms of our $50,000,000 Senior First Lien Secured Credit Agreement (the “Macquarie Credit Agreement”) with Macquarie (including any extensions granted thereon) and the date, if any, that we are able to close a financing (or combination of financing) sufficient to enable us to repay all of the amounts owned by us under the Macquarie Credit Agreement (a “Qualified Refinancing”). The principal amount of the convertible note may be converted into shares of our common stock at a rate of $1.00 per share.

Under the terms of the Green Shoe Note Agreement, if we are able to obtain a Qualified Refinancing, the unpaid principal amount of the convertible note outstanding after the due date described above will earn interest at a rate of 18% per annum. If we are not able to obtain a Qualified Refinancing on or before the maturity date of the Macquarie Credit Agreement and we dispose of the properties acquired by us from Hanson Energy in August 2008 (including a realization by any second debtors of their security interest in these properties), no interest shall be payable on the $300,000 convertible note, however we will be required to issue to Green Shoe an additional convertible note in the principal amount of $150,000 on the same terms and conditions as the $300,000 convertible note except that no interest shall be payable on the principal amount of the $150,000 convertible note.

On August 24, 2009, we issued a convertible promissory note (the “Note”) in the principal amount of $250,000 to W.S. Oil and Gas Limited, a limited partnership controlled by Everett Willard Gray, II, our Vice Chairman and Chief Executive Officer and a holder of more than five percent of our common stock, in consideration for a loan from W.S. Oil and Gas in the principal amount of the Note. Under the terms of the Note, we shall repay to W.S. Oil and Gas a total of $500,000, payable in installments as follows:

	(i)	24 monthly installments of $16,666.67 beginning November 1, 2009; and
	(ii)	12 monthly installments of $8,333.33 beginning November 1, 2011.

In the event that we default under the terms of the Note, W.S. Oil and Gas shall have the right to convert any remaining principal and interest due under the Note into shares of our common stock at a conversion price equal to the greater of four times the fair market value of our common stock at the time the conversion right is exercised, and $0.05. A default under the Note includes a default by us under any instrument for borrowed money in excess of $50,000, provided that any default existing as of the date the Note was issued is not considered an event of default under the Note unless such default persists for a period of 6 months after the date the Note was issued.

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RESTATEMENT OF FINANCIAL STATEMENTS FOR JULY 31, 2008, OCTOBER 31, 2008, JANUARY 31, 2009 AND APRIL 30, 2009

When preparing our financial statements for the fiscal year ended July 31, 2009, we determined that the original valuation model for the net profit overriding royalty interest (the “MAC NPORRI”) granted to Macquarie in connection with the Macquarie Credit Agreement contained errors that resulted in an overstatement of the value of the MAC NPORRI. After discovering this issue, we engaged an independent economist to re-evaluate the value of the MAC NPORRI, resulting in a substantially lower value being assigned to the NPORRI at the date of grant than the value originally assigned for accounting purposes. Correcting this overvaluation is expected to result in our recording approximately $5.1 million less in interest expense and approximately $3.3 million less in net losses for the full fiscal year ended July 31, 2009 than originally anticipated

Also as a result of this correction, on November 4, 2009, our management and Board of Directors concluded that our audited financial statements for the year ended July 31, 2008, and our unaudited financial statements for the interim periods ended October 31, 2008, January 31, 2009 and April 30, 2009, (collectively, the “Relevant Periods”) should no longer be relied upon and will be restated. Correcting the above valuation error is expected to have the following effects on our financial statements for the Relevant Periods:

Year ended July 31, 2008

Three months ended October 31, 2008

Three months ended January 31, 2009

Three months ended April 30, 2009

We expect to file restated financial statements for the Relevant Periods as soon as practicable.

Our Board of Directors discussed the decision to restate our financial statements for the Relevant Periods with the Company’s independent registered public accounting firm, Malone & Bailey, PC.

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OFF-BALANCE SHEET ARRANGEMENTS

We have no significant off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenue or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our stockholders.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in conformity with generally accepted accounting principles (”GAAP”) in the United States has required our management to make assumptions, estimates and judgments that affect the amounts reported in the financial statements, including the notes thereto, and related disclosures of commitments and contingencies, if any. Our significant accounting policies are disclosed in the notes to the audited financial statements for the fiscal year ended July 31, 2009 included in this Annual Report on Form 10-K.

The consolidated financial statements presented with this Quarterly Report on Form 10-Q have been prepared in accordance with generally accepted accounting principles in the United States of America for interim financial information. These financial statements do not include all information and footnote disclosures required for an annual set of financial statements prepared under United States generally accepted accounting principles. In the opinion of our management, all adjustments (consisting solely of normal recurring accruals) considered necessary for a fair presentation of the financial position, results of operations and cash flows as at April 30, 2009, and for all periods presented in the attached financial statements, have been included. Interim results for the period ended April 30, 2009 are not necessarily indicative of the results that may be expected for the fiscal year as a whole.

Our significant accounting policies are disclosed at Note 2 to the unaudited financial statements included in this Quarterly Report.

Derivatives

Derivative financial instruments, utilized to manage or reduce commodity price risk related to our production, are accounted for under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and for Hedging Activities”, and related interpretations and amendments. Under this statement, derivatives are carried on the balance sheet at fair value. Effective August 2008, if the derivative is not designated as a hedge, changes in the fair value are recognized in other income (expense).

We adopted Financial Accounting Standards Board (FASB) Staff Position (FSP) FASB Interpretation (FIN)No. 39-1, "Amendment of FASB Interpretation No. 39," (FSP FIN No. 39-1) which effectively amends FIN No. 39, "Offsetting of Amounts Related to Certain Contracts." FSP FIN No. 39-1 permits the netting of fair values of derivative assets and liabilities for financial reporting purposes, if such assets and liabilities are with the same counterparty and subject to a master netting arrangement. We have elected to employ net presentation of derivative assets and liabilities when FSP FIN No. 39-1 conditions are met. FSP FIN No. 39-1 also requires that when derivative assets and liabilities are presented net, the fair value of the right to reclaim collateral assets (receivable) or the obligation to return cash collateral (payable) is also offset against the net fair value of the corresponding derivative.

We routinely exercise our contractual right to net realized gains against realized losses when settling with our swap and option counterparties. At April 30, 2009, derivative assets include the net market value of derivative assets and liabilities due to the right of offset in the settlement of these contracts.

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ITEM 8.                FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Financial Statements of Doral Energy Corp.
Report of Independent Registered Public Accounting Firm of Malone & Bailey PC, Certified Public Accountants and Business Consultants;	F-1
Consolidated Balance Sheets as of July 31, 2009 and 2008	F-3
Consolidated Statements of Expenses for the years ended July 31, 2009 and 2008	F-4
Consolidated Statements of Stockholders’ Equity for the years ended July 31, 2009 and 2008	F-5
Consolidated Statements of Cash Flows for the years ended July 31, 2009 and 2008	F-6
Notes to the Consolidated Financial Statements	F-7

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Index to Financial Statements:
Audited financial statements as of July 31, 2009, including:

Financial Statements of Doral Energy Corp.

Report of Independent Registered Public Accounting Firm of Malone & Bailey PC	F-1
Consolidated Balance Sheets as of July 31, 2009 and 2008	F-2
Consolidated Statements of Expenses for the years ended July 31, 2009 and 2008	F-3
Consolidated Statements of Stockholders’ Equity for the years ended July 31, 2009 and 2008	F-5
Consolidated Statements of Cash Flows for the years ended July 31, 2009 and 2008	F-6
Notes to the Consolidated Financial Statements	F-7

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors
Doral Energy Corp.
Midland, Texas

We have audited the accompanying consolidated balance sheets of Doral Energy Corp. as of July 31, 2009 and 2008 and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Doral Energy Corp. as of July 31, 2009 and 2008 and the results of their operations and cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that Doral will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, Doral has negative working capital and recurring losses from operations, which raises substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters are described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 4 to the financial statements, the Company's oil and gas properties and notes payable at July 31, 2008 were understated. This discovery was made subsequent to the issuance of the fiscal 2008 financial statements. The financial statements have been restated to increase the oil and gas properties and the notes payable.

/s/ Malone & Bailey, PC

www.malone-bailey.com
Houston, Texas

November 13, 2009

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Doral Energy Corp.
Consolidated Balance Sheets
July 31, 2009 and 2008

		2009			2008
					(Restated)
ASSETS
Current assets
Cash and cash equivalents	$	436,806		$	54,500
Accounts receivable, net of allowance for doubtful accounts of $-		232,934			-
Restricted cash – note proceeds restricted as to use		170,377			566,960
Current derivative asset		468,607			-
Prepaid insurance		1,600			65,676
Total current assets		1,310,324			687,136
Office equipment, net of depreciation		247,111			104
Oil and gas properties- Proved, using full cost method of accounting , net of
accumulated depreciation, depletion and amortization of $419,068 and $0,
respectively		19,897,062			19,834,246
Deferred federal income tax		85,213			-
Deferred financing cost		-			58,040
Security deposit		210,087			1,105
Total assets	$	21,749,797		$	20,580,631
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	333,698		$	201,947
Accounts payable – related party		81,183			50,919
Accrued interest payable		55,537			9,943
Current portion of long term debt		6,636,372			-
Current portion of notes payable to related party		150,000			-
Convertible note payable, net of discount of $118,523 and $0,
respectively		181,477			-
Deferred income tax		94,144			-
Other current liabilities		6,103			8,442
Total current liabilities		7,538,514			271,251
Notes payable, net of discount of $0 and $181,746, respectively		480,784			5,738,254
Notes payable to related party, net of discount of $250,000 and $0,
respectively		100,000			-
Noncurrent derivative liability		54,728			-
Asset retirement obligation		903,654			918,902
Total liabilities		9,077,680			6,928,407
STOCKHOLDERS’ EQUITY
Common stock, $0.001 par value, 400,000,000 shares authorized, 86,937,470
and 85,862,000 shares issued and outstanding, respectively		86,937			85,862
Additional paid-in capital		15,119,274			14,188,489
Accumulated deficit		(2,534,094	)		(622,127	)
Total stockholders’ equity		12,672,117			13,652,224
Total liabilities and stockholders’ equity	$	21,749,797		$	20,580,631

The accompanying notes are an integral part of these consolidated financial statements.

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Doral Energy Corp.
Consolidated Statements of Operations
For the years ended July 31, 2009 and 2008

		2009			2008
Oil and gas sales revenue	$	1,832,146		$	-
Expenses:
Operating costs		1,780,266			-
Production taxes		265,780			-
Depreciation, depletion and amortization		451,994			144
Accretion expense		74,820			-
General and administrative		1,663,073			493,785
Total expense		4,235,933			493,929
Operating loss		(2,403,787	)		(493,929	)
Other income (expense):
Gain on sale of oil and gas properties and other		131,288			-
Interest expense		(947,705	)		(9,943	)
Price risk management activities		1,317,839			-
Loss before income taxes		(1,902,365	)		(503,872	)
Income tax expense		9,602			-
Net loss	$	(1,911,967	)	$	(503,872	)
Net loss per share:
Basic and diluted	$	(0.02	)	$	(0.01	)
Weighted average shares outstanding:
Basic and diluted		86,132,823			80,242,022

The accompanying notes are an integral part of these consolidated financial statements

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Doral Energy Corp.
Consolidated Statements of Cash Flows
For the years ended July 31, 2009 and 2008

		2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(1,911,967	)	$	(503,872	)
Adjustments to reconcile net loss to cash used by operating
activities
Depreciation, depletion and amortization		451,994			144
Accretion		74,820			-
Change in value of derivative asset and liability		(413,879	)		-
Gain on sale of oil and gas properties and other		(131,288	)		-
Share based compensation		174,600			-
Stock options exercised in exchange for service		206,735
Contribution of rent and salary		-			10,501
Non-cash interest expense		540,886			9,943
Changes in operating assets and liabilities:
Accounts receivable		(232,934	)		-
Prepaid expenses and other current assets		64,076			(65,676	)
Deposits		(3,244	)		(1,105	)
Accounts payable		229,751			209,055
Accounts payable – related party		30,264			46,378
Accrued interest payable		45,594			-
Other current liabilities		(2,339	)		-
Deferred tax liability		8,931			-
NET CASH USED BY OPERATING ACTIVITIES		(868,000	)		(294,632	)
CASH FLOWS FROM INVESTING ACTIVITIES
Deposits paid to acquire Miltex properties		(325,000	)		-
Net proceeds from sale of right to purchase Miltex		600,000			-
properties
Purchase of property and equipment		(78,626	)		-
Purchases of oil and gas properties		(571,952	)		(5,097,090	)
CASH FLOWS USED IN INVESTING ACTIVITIES		(375,578	)		(5,097,090	)
CASH FLOWS FROM FINANCING ACTIVITIES
Amounts due to related party		-			-
Proceeds from issuance of notes payable		1,566,348			5,920,000
Repayments of notes payable		(166,711	)		-
Deferred financing costs incurred		(119,623	)		(53,000	)
Change in note proceeds restricted as to use		396,583			(572,000	)
Proceeds from sale of common stock		30,025			120,000
Deposit paid to investor advisor		(80,738	)		-
CASH FLOWS PROVIDED BY FINANCING		1,625,884			5,415,000
ACTIVITIES
NET INCREASE(DECREASE) IN CASH AND CASH
EQUIVALENTS		382,306			23,278
Effect of unrealized exchange rate changes		-			(46	)
Cash and cash equivalents, beginning of period		54,500			31,268
Cash and cash equivalents, end of period	$	436,806		$	54,500
Supplemental disclosures of cash flow information:
Interest paid	$	(364,754	)		-
Income taxes paid		-		$	-

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Noncash investing and financing activities:
Fixed assets acquired through the issuance of notes	$	197,519		$	-
payable
Stock issued for deposit—CK Cooper		125,000			-
Stock issued to extend closing of Miltex acquisition		147,500			-
Stock issued for purchase of oil and gas properties					14,000,000
Asset retirement obligation incurred					918,902

The accompanying notes are an integral part of these consolidated financial statements

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Doral Energy Corp.
Consolidated Statements of Stockholders’ Equity
For the years ended July 31, 2009 and 2008

*

The common stock issued has been retroactively restated to reflect a reverse stock split of four new shares of common stock for 25 old shares of common stock, effective January 23, 2009 and a forward stock split of five new shares of common stock for one old share of common stock, effective September 14, 2009. The number of authorized shares and the par value per share, as well as certain per share information, as referred to in these financial statements have been restated where applicable to give retroactive effect of the forward stock split.

The accompanying notes are an integral part of these consolidated financial statements.

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Doral Energy Corp.
Notes to Consolidated Financial Statements

NOTE 1 – ORGANIZATION AND BUSINESS OPERATIONS

We were incorporated under the laws of Nevada, USA, on October 25, 2005 as Language Enterprises Corp. Our principal executive offices are in Midland, Texas. In February 2008, we formed Doral West Corp., a wholly owned subsidiary to participate in future acquisitions. Effective April 28, 2008, Language Enterprise Corp. changed its name to Doral Energy Corp.

On July 29, 2008, we acquired certain oil and gas properties and changed their business focus to that of a company engaged in the acquisition, operation, exploration and development of oil and gas properties and prospects. The future plan is to acquire additional producing properties with strong proven reserves and considerable undrilled inventory that can be explored and developed with reasonable levels of forward risk. We anticipate financing these acquisitions with a combination of cash and shares of common stock.

The Company is a licensed oil and gas operator in the state of New Mexico.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The financial statements of the Company have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and the Securities and Exchange Commission Act 1934.

Use of estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could materially differ from those estimates.

Management believes that it is reasonably possible the following material estimates affecting the financial statements could significantly change in the coming year: (1) estimates of proved oil and gas reserves, and (2) forecast forward price curves for natural gas and crude oil. The oil and gas industry in the United States has historically experienced substantial commodity price volatility, and such volatility is expected to continue in the future. Commodity prices affect the level of reserves that are considered commercially recoverable; significantly influence Doral’s current and future expected cash flows; and impact the PV10 derivation of proved reserves presented in Doral supplemental oil and gas reserve disclosures made herein.

Reclassification

Certain prior period amounts have been reclassified to conform to current period presentation.

Principles of consolidation

The consolidated financial statements include the accounts of Doral Energy Corp. and its 100% owned subsidiary Doral West Corporation.

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Cash and cash equivalents

For purposes of the balance sheet and statement of cash flows, we consider all highly liquid debt instruments purchased with maturity of three months or less to be cash equivalents. At July 31, 2009 and 2008, we had no cash equivalents. We may, in the normal course of operations, maintain cash balances in excess of federally insured limits. As of July 31, 2009, we had cash balances of $186,806 in excess of federally insured limits.

Restricted cash – note proceeds restricted as to use

At July 31, 2009, we had $170,377 of restricted cash. The restricted cash represents proceeds from the revolving loan payable to Macquarie (See Note 7) which are restricted as to use under the terms of the credit agreement. These funds may be used to pay lease operating expenses, note interest, certain fees associated with obtaining the note and certain general and administrative expenses.

Deferred financing cost

In connection with debt financing, we paid $190,970 in fees, of which $58,040 was paid in prior year. These fees were written off to interest expense during the year ended July 31, 2009. (See Note 7)

Concentrations of Credit Risk

All of our receivables are due from oil and natural gas purchasers. We sold approximately 90% and 6% of our oil and natural gas production to two customers during the year ended July 31, 2009. At July 31, 2009, these two customers accounted for approximately 60% and 7%, respectively of accounts receivable.

Office equipment

Property and equipment is stated at cost. Depreciation is computed on a straight-line basis over the estimated useful lives ranging from three to five years.

Oil and gas properties

We follow the full cost method of accounting for its oil and natural gas properties, whereby all costs incurred in connection with the acquisition, exploration for and development of petroleum and natural gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on non-producing leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized to income.

Depletion and depreciation of proved oil and gas properties is calculated on the units-of-production method based upon estimates of proved reserves. Such calculations include the estimated future costs to develop proved reserves. Oil and gas reserves are converted to a common unit of measure based on the energy content of 6,000 cubic feet of gas to one barrel of oil. Costs of unevaluated properties are not included in the costs subject to depletion. These costs are assessed periodically for impairment.

Ceiling test

In applying the full cost method, we perform an impairment test (ceiling test) at each reporting date, whereby the carrying value of oil and gas property and equipment is limited to the “estimated present value” of the future net revenues from its proved reserves, discounted at a 10-percent interest rate and based on current economic and operating conditions, plus the cost of properties not being amortized, plus the lower of cost or fair market value of unproved properties included in costs being amortized, less the income tax effects related to any book and tax basis differences of the properties. As of July 31, 2009, no impairment of oil and gas properties was recorded.

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Asset retirement obligation

In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations”, we record the fair value of a liability for asset retirement obligations (“ARO”) in the period in which an obligation is incurred and records a corresponding increase in the carrying amount of the related long-lived asset. Our asset retirement obligations primarily relate to the abandonment of oil and gas properties. The present value of the estimated asset retirement cost is capitalized as part of the carrying amount of oil and gas properties and is depleted over the useful life of the asset. The settlement date fair value is discounted at our credit adjusted risk-free rate in determining the abandonment liability. The abandonment liability is accreted with the passage of time to its expected settlement fair value. Revisions to such estimates are recorded as adjustments to ARO and capitalized asset retirement costs and are charged to operations in the period in which they become known. At the time the abandonment cost is incurred, we are required to recognize a gain or loss if the actual costs do not equal the estimated costs included in ARO.

The amounts recognized for ARO are based upon numerous estimates and assumptions, including future abandonment costs, future recoverable quantities of oil and gas, future inflation rates, and the credit adjusted risk free interest rate.

Derivatives

Derivative financial instruments, utilized to manage or reduce commodity price risk related to our production, are accounted for under the provisions of SFAS No. 133, “Accounting for Derivative Instruments and for Hedging Activities”. Under this pronouncement, derivatives are carried on the balance sheet at fair value. If the derivative is not designated as a hedge, changes in the fair value are recognized in other income (expense).

We are permitted to net the fair values of derivative assets and liabilities for financial reporting purposes, if such assets and liabilities are with the same counterparty and subject to a master netting arrangement. We have elected to employ net presentation of derivative assets and liabilities when these conditions are met. When derivative assets and liabilities are presented net, the fair value of the right to reclaim collateral assets (receivable) or the obligation to return cash collateral (payable) is also offset against the net fair value of the corresponding derivative. We routinely exercise our contractual right to net realized gains against realized losses when settling with our swap counterparty. At July 31, 2009, derivative assets include the net market value of derivative assets and liabilities due to the right of offset in the settlement of these contracts.

Environmental

The Company is subject to environmental laws and regulations of various U.S. jurisdictions. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.

Environmental costs that relate to current operations are expensed or capitalized as appropriate. Costs are expensed when they relate to an existing condition caused by past operations and will not contribute to current or future revenue generation. Liabilities related to environmental assessments and/or remedial efforts are accrued when property or services are provided or can be reasonably estimated.

Future income taxes

Income taxes are accounted for using the asset/liability method of income tax allocation. Future income taxes are recognized for the future income tax consequences attributable to differences between the carrying values of assets and liabilities and their respective income tax bases. Future income tax assets and liabilities are measured using income tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on future income tax assets and liabilities of a change in income tax rates is included in earnings in the period that such change in income tax rates is enacted. Future income tax assets are recorded in the financial statements if realization is considered more likely than not.

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Revenue and cost recognition

We use the sales method to account for sales of crude oil and natural gas. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. The volumes sold may differ from the volumes to which Doral is entitled based on the interest in the properties. These differences create imbalances which are recognized as a liability only when the imbalance exceeds the estimate of remaining reserves. We had no production, revenue or imbalances as of July 31, 2009. Costs associated with production are expensed in the period incurred.

Loss per share

Basic net loss per common share is computed by dividing net loss by the weighted-average number of common shares outstanding during the period. Diluted net loss per common share is determined using the weighted-average number of common shares outstanding during the period, adjusted for the dilutive effect of common stock equivalents. In periods when losses are reported, the weighted-average number of common shares outstanding excludes common stock equivalents, because their inclusion would be anti-dilutive.

Fair value of financial instruments

The carrying value of cash and cash equivalents, accounts payable and accrued expenses and other liabilities approximates fair value due to the short term maturity of these instruments. The carrying value of the notes payable are believed to approximate their fair value as of July 31, 2009 based upon the relatively short period these instruments have been outstanding.

New Accounting Pronouncements

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162” (“SFAS 168”). The FASB Accounting Standards Codification, (“Codification” or “ASC”) became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of SFAS 168, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification became non-authoritative.

Following SFAS 168, the FASB will no longer issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts; instead, it will issue Accounting Standards Updates (ASU’s). The FASB will not consider ASU’s as authoritative in their own right; rather these updates will serve only to update the Codification, provide background information about the guidance, and provide the bases for conclusions on the change(s) in the Codification. SFAS No. 168 is incorporated in ASC Topic 105, Generally Accepted Accounting Principles. We will adopt SFAS No. 168 in the first quarter of fiscal 2010, and the Company will provide reference to both the Codification topic reference and the previously authoritative references related to Codification topics and subtopics, as appropriate.

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted stand for the management of petroleum resources that was developed by several industry organizations. Key revisions include changes to the pricing used to estimate reserves utilizing a 12-month average price rather than a single day spot price which eliminates the ability to utilize subsequent prices to the end of a reporting period when the full cost ceiling was exceeded and subsequent pricing exceeds pricing at the end of the reporting period, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, and permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. We will adopt the provisions of this

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pronouncement effective August 1, 2009, and we are currently assessing the impact that the adoption will have on our disclosures, operating results, financial position and cash flows.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS 161”), an amendment of FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). SFAS 161 requires entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged but not required. SFAS 161 will be effective for us on August 1, 2009. SFAS 161 also requires entities to disclose more information about the location and amounts of derivative instruments in financial statements how derivatives and related hedges are accounted for under SFAS 133 and how the hedges affect the entity’s financial position, financial performance, and cash flows. We are currently evaluating whether the adoption of SFAS 161 will have an impact on our financial position or results of operations.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits companies to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS 159, a company may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at initial recognition of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only to specified risks, cash flows or portions of that instrument. SFAS No. 159 does not affect any existing accounting standards that require certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. We adopted SFAS No. 159 effective August 1, 2008 and did not elect the fair value option for any existing eligible items.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not impose fair value measurements on items not already accounted for at fair value; rather it applies, with certain exceptions, to other accounting pronouncements that either require or permit fair value measurements. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal or most advantageous market. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In February 2008, the FASB issued FASB Staff Position No. 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”), which delays the effective date of SFAS 157 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, until fiscal years beginning after November 15, 2008. These non-financial items include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and asset retirement obligations initially measured at fair value. Effective August 1, 2008, we adopted SFAS 157 for fair value measurements not delayed by FSP FAS No. 157-2. The adoption resulted in additional disclosures as required by the pronouncement (See Note 13 –Fair Value Measurements) related to our fair value measurements for oil and gas derivatives but no change in our fair value calculation methodologies. Accordingly, the adoption had no impact on our financial condition or results of operations.

NOTE 3 - GOING CONCERN

As of July 31, 2009 We intend to raise additional working capital either through private placements, public offerings and/or bank financing. We are actively pursuing such alternatives in conjunction with its financial advisor, C.K. Cooper & Company, Inc. We are also identifying merger and/or acquisition candidates of strategic and financial benefit to our plans for growth. As of July 31, 2009, no acquisition or merger agreements have yet been closed. To the extent that funds generated from any private placements, public offerings and/or bank financing are insufficient, Doral will have to raise additional working capital through other channels. No assurance can be given that additional financing will be available, or if available, will be on terms acceptable to Doral.

This factor raises substantial doubt about our ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern.

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NOTE 4 – RESTATEMENT

When preparing our financial statements for the fiscal year ended July 31, 2009, we determined that the original valuation model for the net profit overriding royalty interest (the “MAC NPORRI”) granted to Macquarie in connection with the Macquarie Credit Agreement contained errors that resulted in an overstatement of the value of the MAC NPORRI. After discovering this issue, we engaged an independent economist to re-evaluate the value of the MAC NPORRI at its inception, resulting in a substantially lower value being assigned to the NPORRI at the date of grant than the value originally assigned for accounting purposes. The value of the NPORRI originally resulted in a discount to the oil and gas properties and notes payable by $5.3 million. Correcting this overvaluation resulted in our increasing the value of oil and gas properties and notes payable by approximately $5.1 million as of July 31, 2008.

NOTE 5 – OIL AND GAS PROPERTIES

Acquisition of Eddy County Properties

On July 29, 2008, the Company acquired a working interest in 66 producing oil fields and approximately 186 wells (the “Eddy County Properties”) in and around Eddy County, New Mexico. The acquisition of the Eddy County Properties was completed pursuant to the terms of the Purchase and Sale Agreement dated April 25, 2008, as amended on July 17, 2008, (the “Hanson Energy Agreement”) between J. Warren Hanson, an individual doing business as Hanson Energy, and his wife, Kathie Hanson, and the Company. Under the terms of the Hanson Energy Agreement, Hanson Energy transferred to Doral all of its right, title and interest in and to the Eddy County Properties, together with all of Hanson Energy’s right, title and interest in and to the lands, wells and hydrocarbons associated with the Eddy County Properties, and to the oil and gas sales contracts related thereto (collectively, the “Assets”).

The Eddy County Properties consist of approximately 7,800 acres and are located along the Artesia-Vacuum Trend near the northwestern edge of the Permian Basin. As a result of the acquisition of the Eddy County Properties, Doral currently holds a 100% working interest and an average of a 74.7% net revenue interest in 55 of the 66 leases. In addition, the Company holds an average of an 84.4% working interest and an average of a 67.1% net revenue interest in the remaining 11 leases. Doral’s leasehold rights vary between leases, but they generally extend from the surface to approximately 3,500 feet in depth. Doral has been entitled to production from the Eddy County Properties since August 1, 2008.

As consideration for the Assets, Doral paid to Hanson Energy the following consideration:

(a)	Upon execution of the Hanson Energy Agreement, a deposit (the “Deposit”) of $100,000 in cash plus and 80,000 shares of common stock;
(b)	Upon execution of the Amendment Agreement to the Hanson Energy Agreement dated July 17, 2008, an amount of $150,000 in cash, paid as an increase to the Deposit amount;
(c)	Upon closing, $4,750,000 in cash and 1,040,000 shares of our common stock, and an overriding royalty interest of 2.5% of 8/8 on the oil and gas produced from the Assets; and
(d)	On November 24, 2008, $463,408 in cash as a final purchase price adjustment.

The total purchase price was as follows:
Cash paid to Hanson Energy	$	5,000,000
Common stock issued to Hanson Energy (7,000,000 shares valued at		14,000,000
$2.00 per share based on last traded stock price)
Cash paid for other acquisition costs		97,090
Asset retirement obligation incurred		918,902
Total purchase price		20,015,992
Less: Net profits overriding royalty interest		(181,746	)
Net purchase price	$	19,834,246

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The total purchase price was allocated to proved oil and gas properties, as this was the only asset purchased.

The following table reflects selected pro forma financial information as if the acquisition of the Eddy County Properties had occurred as of the beginning of the year ended July 31, 2008:

The pro forma financial information above includes the actual results of Doral for the year ended July 31, 2008 adjusted by the following:

• Revenue and direct operating expenses of the Eddy County Properties for the year ended July 31, 2008;
• Incremental depreciation, depletion and accretion expense, using units of production method, resulting from the purchase of the Eddy County Properties;
• Estimated increase in general and administrative expense as a result of the purchase of the Eddy County Properties;
• Interest expense and amortization of deferred financing costs; and
• Shares issued for the acquisition of the Eddy County Properties.

Oil and gas properties

We recognized depletion expense of $419,068 during the year ended July 31, 2009.

NOTE 6 – ASSET RETIREMENT OBLIGATION

Asset retirement obligation activity for the years ended July 31, 2009 and 2008 are as follows:

		2009			2008
Asset retirement obligations, beginning of period	$	918,902		$	-
Asset retirement obligation incurred		-			918,902
Change in estimate		(90,068	)		-
Accretion expense		74,820			-
Asset retirement obligations, end of period	$	903,654		$	918,902

NOTE 7 – NOTES PAYABLE

Notes payable consist of the following as of July 31, 2009 and 2008:

		2009			2008
Little Bay Consulting	$	520,000		$	320,000
Green Shoe Investments, net of discount of $118,523		668,477			300,000
Macquarie Ltd.		5,888,196			5,118,254
Note payable to related party, net of discount of $250,000		250,000			-
Other		40,000			-
Vehicle and trailer notes		181,960			-
Total notes payable		7,548,633			5,738,254
Less: current portion		6,917,849			-
Noncurrent notes payable	$	630,784		$	5,738,254

Repayments are as follows:

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* amount includes $118,523 unamortized discount for Green Shoe Investments

** amount includes $250,000 unamortized discount for related party note payable

Little Bay Notes Payable

On March 7, 2008, Doral entered into a loan agreement with Little Bay Consulting SA (“Little Bay”) pursuant to which Little Bay agreed to loan the Company $220,000. On July 18, 2008, Doral received an additional $100,000 from Little Bay. The loans from Little Bay are unsecured, carry an annual interest rate of 5.0%, are due July 1, 2010, and July 18, 2010 respectively and are nonconvertible.

During October 2008, Doral borrowed $200,000 from Little Bay Consulting SA. The loans are unsecured, carry an annual interest rate of 5.0%, and are due October 1, 2010.

Green Shoe Investments

In May 2008, Doral signed loan agreements for $250,000 with Greenshoe Investments Ltd. (“Greenshoe”). On July 18, 2008, Doral received an additional $50,000 of loan from Greenshoe. The loans from Greenshoe are unsecured, carry an annual interest rate of 5.0%, are due July 1, 2010, and July 18, 2010 respectively and are nonconvertible.

During February and April 2009, Doral borrowed a total of $187,000 from Green Shoe Investments. The loans are unsecured and carry an annual interest rate of 5.0% . The notes mature $100,000 on March 1, 2011 and $87,000 on May 1, 2011.

In May 2009, Doral borrowed $150,000 and agreed to repay $300,000 to Greenshoe Investments Ltd. The loan is unsecured, carries an annual interest rate of 0.0%, is due August 10, 2009 and is convertible at $1 per share. The difference in proceeds and the repayment amount resulted in a discount of $150,000 that is being amortized over the term using the effective interest method. As of July 31, 2009, $181,477 was amortized leaving $118,523 to be amortized in fiscal 2010. This loan is currently in default.

Macquarie Credit Agreement

On July 29, 2008, the Company entered into a Senior First Lien Secured Credit Agreement (the “Credit Agreement”) with Macquarie Bank Limited (“Macquarie”). Under the terms of the Credit Agreement, Macquarie has agreed to provide Doral with: (i) a maximum of $25,000,000 under a revolving loan (the “Revolving Loan”); and (ii) a maximum of $25,000,000 under a term loan (the “Term Loan”). Upon closing of the Credit Agreement, Macquarie advanced $2,500,000 of the Revolving Loan and $2,800,000 of the Term Loan. These advances are subject to an upfront advance fee of 1.00% of the total amount advanced. The advances were used to fund the acquisition of the Eddy County Properties and for working capital purposes. Future advances are subject to the approval of Macquarie.

The Term Loan and the Revolving Loan are secured by all of the assets of the Company. Interest accrued on the Term Loan and the Revolving Loan is payable monthly beginning on September 20, 2008. The Credit Agreement requires that Doral must pay 100 percent of net operating cash flow to Macquarie monthly beginning on September 20, 2008. This payment will be applied first to accrued interest and fees, second to principal on the Term Loan and last to principal on the Revolving Loan. At July 31, 2009, the applicable interest rate under the Term Loan and the Revolving Loan was 6.785% and 3.285%, respectively. The effective interest rates on the Term and Revolving Loans combined is approximately 130%.

Provided that the Company submitted a Development Plan (as such term is defined in the Credit Agreement) acceptable to Macquarie (at its sole discretion) by January 15, 2009, the Credit Agreement would have matured on July 30, 2011. Since the Company failed to submit an acceptable Development Plan to Macquarie, the maturity date

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has been moved up to July 30, 2009. In connection with the Credit Agreement, Doral granted Macquarie a net profits overriding royalty interest (“NPORRI”) in the Eddy County Properties. Beginning on the maturity date of the Credit Agreement, or earlier if all amounts advanced under the Credit Agreement are repaid before that date, Doral will pay Macquarie 35% of its net profits on the Eddy County Properties. After Macquarie has received $5,000,000, this percentage will drop to 20% in perpetuity. We valued the NPORRI at $181,476 resulting in a discount of $181,746 on the Term and Revolving loans at July 31, 2008 with a corresponding reduction in proved oil and gas properties. The discount on the notes payable was initially being amortized over the life of the debt using the effective interest method. The unamortized amount of the discount was written off to interest expense in the second quarter of 2009 as a result of our technical default on certain covenants of the loan agreement.

The NPORRI is convertible into our common stock contingent on the following conditions being met:

• Doral’s Common Stock is listed on the American Stock Exchange or another exchange approved by Macquarie;
• No more than 65 percent of Doral’s common stock is held by affiliates or insiders of the Company; and
• The average trading volume of the shares of common stock on the exchange is equal to or greater than 50% of the outstanding shares of common stock;

The NPORRI is convertible at Doral or Macquarie’s option after the conversion requirements listed above are met. After either party issues a notice of conversion, the NPORRI will be valued by investment bankers approved by both parties. The number of shares to be issued will be determined by dividing the value of the NPORRI by the volume weighted average trading price of the common stock for the 60 days prior to conversion. The conversion feature expires on July 29, 2018. Because the conversion option is contingent on future events, no value has been assigned to this conversion feature.

The Credit Agreement also contains events of default which are customary for such financings. The events of default include, but are not limited to, default of payment; failure to comply with any term, condition or covenant of the Credit Agreement; bankruptcy or insolvency related defaults; judgment pertaining to receivership or liquidation; federal tax lien or judgment against us of more than $100,000; our failure to comply with any government regulations on our properties; the operator is removed or withdraws and no replacement is acceptable to Macquarie; a change in control occurs; or a material adverse event occurs.

We have failed to meet the minimum quarterly operating cash flow and minimum quarterly sales volume requirements set out in the Credit Agreement for the year ended July 31, 2009. Under the terms of the Credit Agreement, Macquarie has the right to declare us in default of our obligations and to declare the amounts due under the Credit Agreement to be immediately payable. Macquarie has not yet exercised these rights and has not provided us with any indications that it intends to do so at this time. However, there is no assurance that Macquarie will not exercise its right to declare us in default in the future. As a result of the failure to meet these minimum requirements, we reclassified amounts due under the notes to current liabilities, and we wrote off all unamortized deferred financing costs and unamortized discounts on the notes.

Upon an event of default, Macquarie has the right under the Credit Agreement to: (i) accelerate payment on all outstanding promissory notes and loans due; (ii) sell any collateral; and (iii) carry out our rights under our operating agreements with respect to our Eddy County Properties.

On November 11, 2009, we entered into an agreement with Macquarie dated November 9, 2009, pursuant to which Macquarie agreed not to exercise their rights or remedies with respect to our failure to pay the amounts due under the Macquarie Credit Agreement until at least January 29, 2010.

To obtain Macquarie’s agreement to forbear from exercising its remedies, we:

	(a)	paid Macquarie a fee of $25,000;
	(b)	agreed to an increased interest rate on amounts owed under the Macquarie Credit Agreement to:
		(i)	with respect to the Revolving Loan, 3.5% over LIBOR in respect of amounts earning interest tied to LIBOR, and 1.75% over prime in respect of amounts earning interest tied to the prime rate, and

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(ii)

with respect to the Term Loan, 7.0% over LIBOR in respect of amounts earning interest tied to LIBOR, and 5.25% over prime in respect of amounts earning interest tied to the prime rate.

In addition, the terms of the forbearance agreement provide that, if we do not receive a valid offer to purchase some or all of the Hanson Project Properties by November 30, 2009 and we have accounts payable greater than $125,000 that are past due, we will be required to pay Macquarie an additional fee of $50,000, and interest rates under the Macquarie Credit Agreement will increase as follows:

	(i)	with respect to the Revolving Loan, 4.0% over LIBOR in respect of amounts earning interest tied to LIBOR, and 2.25% over prime in respect of amounts earning interest tied to the prime rate; and
	(ii)	with respect to the Term Loan, 7.5% over LIBOR in respect of amounts earning interest tied to LIBOR, and 5.75% over prime in respect of amounts earning interest tied to the prime rate.

If we do not receive a valid offer to purchase some or all of the Hanson Project Properties by December 31, 2009 and we have accounts payable greater than $100,000 that are past due, we will be required to pay Macquarie an additional fee of $100,000 and interest rates under the Macquarie Credit Agreement will increase as follows:

	(i)	with respect to the Revolving Loan, 5.5% over LIBOR in respect of amounts earning interest tied to LIBOR, and 3.75% over prime in respect of amounts earning interest tied to the prime rate; and
	(ii)	with respect to the Term Loan, 9.0% over LIBOR in respect of amounts earning interest tied to LIBOR, and 7.25% over prime in respect of amounts earning interest tied to the prime rate.

During the year ended July 31, 2009, we borrowed an additional $739,348 under the Credit Agreement in order to pay the additional purchase price adjustment for the acquisition of the Hanson Properties and for other working capital purposes.

Note payable to related party

In July 2009, we borrowed $250,000 from W.S. Oil and Gas Limited, a partnership which is controlled by our CEO. The note has a stated interest rate of 0% and matures November 1, 2012. We are required to make 24 monthly payments of $16,667 beginning November 1, 2009 and then 12 monthly payments of $8,333 thereafter. The payments total $500,000 resulting in an effective interest rate of 49%. The difference in proceeds and the repayment amount resulted in a discount of $250,000 that is being amortized over the term using the effective interest method. As of July 31, 2009, $0 was amortized leaving $250,000 to be amortized in fiscal 2010 - 2012.

On November 11, 2009, we agreed with W.S. Oil and Gas Limited to amend the terms of the convertible promissory note issued to them. As amended, in the event of a default under the terms of the note, WS Oil and Gas shall have the right to convert any remaining principal and interest due under the note into shares of our common stock at a conversion price equal to the greater of (a) four times the fair market value of our common stock at the time the conversion right is exercised; and (b) $0.05.

Other

In May 2009, the Company received $40,000 from Citibank. The amount carries no interest, is unsecured and is due 90 days after a closing with Macquarie Bank Limited, which has not yet occurred.

Vehicle and trailer notes

During the year ended July 31, 2009, we entered into two note agreements to finance the acquisition of a vehicle and an office trailer. These notes require monthly payments of principal and interest, bear interest at rates between 5.75% and 9.69%, are secured by the assets they financed, and mature in five years.

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Convertible note payable

On May 28, 2009, we received $150,000 in debt financing from Green Shoe Investments Ltd. (“Green Shoe”) On June 10, 2009 we entered into an agreement dated effective as of May 28, 2009 (the “Green Shoe Note Agreement”) with Green Shoe whereby, in exchange for the $150,000 provided by Green Shoe, we agreed to issue a convertible note in the principal amount of $300,000. The convertible note is due 10 business days after the earlier of the maturity date of the amounts owed to Macquarie Bank Limited (“Macquarie”) under the terms of our $50,000,000 Senior First Lien Secured Credit Agreement (the “Macquarie Credit Agreement”) with Macquarie (including any extensions granted thereon) and the date, if any, that we are able to close a financing (or combination of financing) sufficient to enable us to repay all of the amounts owned by us under the Macquarie Credit Agreement (a “Qualified Refinancing”). The principal amount of the convertible note may be converted into shares of our common stock at a rate of $1.00 per share.

Under the terms of the Green Shoe Note Agreement, if we are able to obtain a Qualified Refinancing, the unpaid principal amount of the convertible note outstanding after the due date described above will earn interest at a rate of 18% per annum. If we are not able to obtain a Qualified Refinancing on or before the maturity date of the Macquarie Credit Agreement and we dispose of the properties acquired by us from Hanson Energy in August 2008 (including a realization by any second debtors of their security interest in these properties), no interest shall be payable on the $300,000 convertible note, however we will be required to issue to Green Shoe an additional convertible note in the principal amount of $150,000 on the same terms and conditions as the $300,000 convertible note except that no interest shall be payable on the principal amount of the $150,000 convertible note.

NOTE 8 — COMMITMENTS AND CONTINGENCIES

From time to time Doral may become involved in litigation in the ordinary course of business. At the present time the Company’s management is not aware of any such litigation.

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of July 31, 2009, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Cochran County Properties Agreement

On January 15, 2009, Doral entered into a letter agreement with Miltex Oil Company (“Miltex”) to acquire three oil and gas leases located in Cochran County, Texas for a total purchase price of $2.2 million. Under the terms of the letter agreement, Doral paid a deposit of $100,000 in January 2009 and must pay the remaining $2.1 million by February 27, 2009. In February 2009, Doral paid an additional $100,000 to extend the closing date of the transaction to March 31, 2009, increasing the total purchase price of the properties to $2.3 million. The $100,000 deposit is included in deposits on the balance sheet at April 30, 2009.

On March 31, 2009, the Company entered into an agreement to modify the terms of their letter agreement with Miltex to increase the purchase price by $125,000. Of this increase, Doral paid $25,000 in earnest money and an additional $100,000 was added to the purchase price due at closing, making the total purchase price $2,425,000. Doral has until April 21, 2009 to complete the acquisition of the Cochran County Properties. In order to complete the acquisition of the Cochran County Properties, Doral will be required to pay Miltex an additional $2,235,981.90 by April 21, 2009. The required payment amount includes $2,200,000 for the remainder of the purchase price and $35,981.90 for the value of oil in Miltex’s storage tanks as of March 1, 2009. The $25,000 deposit is included in deposits on the balance sheet at April 30, 2009.

On April 21, 2009, Doral entered into an agreement to modify the terms of their letter agreement with Miltex. The deadline for Doral’s proposed acquisition of the Miltex Properties has been changed from April 21, 2009 to May 29,

---

2009, with extension clauses to adjust the closing date to July 31, 2009, if necessary. The effective date of the proposed Miltex Properties acquisition, however, remains at the original date of March 1, 2009. If closing occurs by the May 29, 2009 scheduled closing date, the revised total acquisition cost of the Miltex Properties will be $2,635,000 plus 25,000 shares of the Company’s common stock, of which $2,400,000 will be payable to Miltex at closing. If the closing date is extended to June 30, 2009, the Company will pay an additional $10,000 to Miltex and will issue an additional 25,000 shares of the Company’s common stock. If the closing date is extended to July 31, 2009, the Company will pay to Miltex an additional $50,000. The shares to be issued to Miltex will be issued pursuant to the registration exemptions provided by Regulation D of the Securities Act of 1933 (the “Securities Act”). The Company has granted piggy-back registration rights to Miltex.

On May 22, 2009, Doral notified Miltex of its intention to extend the closing date of the proposed acquisition of Cochran County Properties owned by Miltex. Under the amended terms of Doral’s agreement with Miltex, Doral has the right to extend the closing date for the Miltex Properties from May 29, 2009 to June 30, 2009 by paying Miltex and additional $10,000 and issuing to Miltex an additional 25,000 shares of its common stock. These amounts were paid subsequent to year end and included in deposit on the balance sheet April 30, 2009.

On June 26, 2009, Doral extended the closing date of the proposed acquisition to July 31, 2009. To extend the closing date, the Company paid Miltex $50,000 as provided under the amended terms of its agreement with Miltex.

On July 30, 2009, Doral entered into an agreement (the “Assignment Agreement”) whereby it agreed to assign its right to purchase Miltex Properties from Miltex. Under the terms of the Assignment Agreement, the assignee (the “Assignee”) agreed to pay the Company an aggregate of $633,472 in consideration for the Company agreeing to assign its rights under the Assignment Agreement.

Closing of the assignment was completed on July 31, 2009, the same day that the Assignee completed the acquisition of the Miltex Properties. Prior to closing, the Company and the Assignee verbally agreed to amend the terms of the Assignment Agreement such that the Assignee paid to the Company $600,000 for the assignment of the Company’s right to purchase the Miltex Properties plus an additional $150,000 to reimburse the Company for amounts due to a third party for brokering the sale of the Miltex Properties.

Miltex agreed to the assignment in consideration for the Company agreeing that, if the Company sells any of its oil and gas properties located in Eddy County, New Mexico on or before October 21, 2009, Miltex may require the Company to repurchase the 50,000 shares of the Company’s common stock previously issued to Miltex under the terms of their agreement for the purchase and sale of the Miltex Properties. The Company has agreed to repurchase the shares issued to Miltex at the greater of $3.00 per share or the current market price of the Company’s common stock. If the Company does not have sufficient funds to repurchase the shares, the Company has agreed to file a registration statement for the resale of those shares. The Company did not sell any of its Eddy County properties and has not been required to repurchase any shares of stock. Doral recognized a gain of $127,500 on the sale.

Investment advisory agreement

On January 26, 2009, Doral entered into an investment advisory agreement with a financial advisor. Under the terms of the agreement, Doral has agreed to pay $125,000 in cash, of which $25,000 was paid upon execution of the agreement with the remaining $100,000 payable in 11 equal monthly installments and 50,000 shares of common stock. The shares were valued at $125,000 based on the market value of the stock on the date of the agreement. The $25,000 cash payment and the $125,000 paid in shares of common stock has been included in deposits on the balance sheet at April 30, 2009, based on management’s expectation that the financial advisor will be successful in obtaining additional financing for the Company.

NOTE 9 – INCOME TAXES

Deferred income taxes are recorded at the expected tax rate of 35%. SFAS No. 109 “Accounting for Income Taxes” requires that deferred tax assets be reduced by a valuation allowance if it is more or likely than not that some portion or all of the deferred tax asset will not be realized.

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Reconciliation between actual tax expense (benefit) and income taxes computed by applying the combined U.S. federal income tax rate and state income tax rate to net loss is as follows:

		2009			2008
Computed at U.S. and State statutory rates	$	(667,524	)		(176,355	)
Changes in valuation allowance		677,126			176,355
Total	$	9,602			-
		July 31,			July 31,
		2009			2008
Deferred tax asset attributable to:
Other items	$	(9,602	)		-
Net operating loss	$	677,126
					217,749
Less: valuation allowance		(677,126	)		(217,749	)
Total	$	(9,602	)		-

The components giving rise to the deferred tax assets described above have been included in the accompanying consolidated balance sheet as noncurrent assets. As of July 31, 2009 and 2008, the deferred tax assets are net of a valuation allowance of $677,126 and $217,749 respectively, based on the amount that management believes will ultimately be realized. Realization of deferred tax assets is dependent upon sufficient future taxable income during the period that deductible temporary differences and carryforwards are expected to be available to reduce taxable income. At July 31, 2009, Doral had loss carryforwards of approximately $1,900,000 for tax purposes which will begin to expire in 2026.

NOTE 10 – STOCKHOLDERS’ EQUITY

Effective January 7, 2008, the Company amended its Articles of Incorporation by splitting its issued and authorized capital on a 25-for-1 basis. Accordingly, the Company’s authorized capital of common stock has been increased from 100,000,000 shares to 2,500,000,000 shares of common stock, $0.001 par value per share, and the Company’s issued and outstanding shares were increased on a 25-for-1 basis such that each shareholder now holds twenty five shares for each one share previously held. As a result of the stock split, the number of Company shares outstanding increased from 4,003,500 to 107,087,500 on January 7, 2008. All share and per-share data (except par value) have been adjusted to reflect the retroactive effect of the forward stock split for all periods presented.

Effective January 23, 2009, the Company amended its Articles of Incorporation by a reverse split of its issued and authorized capital on a 4-for-25 basis. Accordingly, the Company’s outstanding shares were decreased on a 4-for-25 basis such that each shareholder now holds four shares for each 25 shares previously held. All share and per-share data (except par value) have been adjusted to reflect the retroactive effect of the reverse stock split for all periods presented.

Effective September 14, 2009, the Company amended its Articles of Incorporation by a forward split of its issued and authorized capital on a 5-for-1 basis. Accordingly, the Company’s outstanding shares were increased on a 5-for-1 basis such that each shareholder now holds five shares for each one share previously held. All share and per-share data (except par value) have been adjusted to reflect the retroactive effect of the reverse stock split for all periods presented.

In June 2008, Doral completed a private placement of 192,000 shares of common stock at a price of $0.63 per share and received total cash proceeds of $120,000.

In August 2008, Doral completed an additional private placement of 8,040 shares of common stock at a price of $0.63 per share and received total cash proceeds of $5,025.

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In January 2009, Doral issued 250,000 shares of common stock at a price of $0.50 per share and received services totaling $125,000.

In March 2009, Doral received subscription proceeds of $25,000 for the sale of 71,430 shares of common stock under Doral’s $0.35 per share offering. The shares subscribed for have not yet been issued by the Company; however, they are reflected in outstanding shares for accounting purposes.

In April 2009, Doral entered into an agreement to modify the terms of their letter agreement with Miltex. Doral issued 125,000 shares of the company’s common stock at a price of $0.57 in exchange for an extension of the closing date of their agreement. In May 2009, Doral issued an additional 125,000 shares of the Company’s common stock at a price of $0.61 per share in exchange for an additional extension of the closing date of their agreement.

In June 2009, Doral issued 300,000 shares of its common stock in exchange for services. The shares were valued at $0.58 per share for a total of $174,600 based on the market value of the shares on the date of grant.

In June and July 2009, Doral issued 196,000 shares of its common stock as a result of the exercise of stock options with a strike price of $0.50 per share or $98,000 total. Doral and the holder of the option agreed to offset amounts payable for legal fees of $98,000 in lieu of the receipt of cash for the exercise price.

Stock Options

There were no options outstanding prior to July 31, 2008.

Stock option activity summary is presented in the table below:

								Weighted-
								average
					Weighted-			Remaining			Aggregate
		Number of			average			Contractual			Intrinsic
		Shares			Exercise Price			Term (years)			Value
Outstanding at July 31, 2008		-		$	-			-		$	-
Granted		500,000		$	0.50
Exercised		(196,000	)		0.50
Forfeited		-		$	-
Expired		-			-
Outstanding at July 31, 2009		304,000		$	0.50			4.90		$	30,400

In June 2009, Doral granted options to purchase 500,000 shares of common stock at an exercise price of $0.50 per share for a term of five years to a third party in exchange for services. The options were fully vested upon issuance and were valued at $206,735.

The fair value of the options granted during 2009 was estimated at the date of grant using the Black-Scholes option-pricing model with the following assumptions:

Estimated market value of stock on grant date	$ 0.58
Risk-free interest rate	2.71%
Dividend yield	0.00%
Volatility factor	126%
Expected life	2.5 years

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NOTE 11 – RELATED PARTY TRANSACTIONS

During the year ended July 31, 2008, directors of the Company contributed management services with a value of $7,501 and rent with a value of $3,000. These items were charged to operations and credited to additional paid-in capital during the respective periods.

At July 31, 2008, Doral had accounts payable to the CEO of the Company in the amount of $50,919. These amounts represent unpaid salary and expense reimbursements.

As of July 31, 2009, Doral had accounts payable to the Chairman of the Board and CFO of the Company in the amount of $80,919. These amounts represent unpaid salary and expense reimbursements.

As more fully discussed in Note 7, we borrowed $250,000 from a partnership controlled by our Chief Executive Officer during the year ended July 31, 2009.

NOTE 12 – DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES

On August 6, 2008, in accordance with a requirement of the Credit Agreement, Doral entered into a Costless Collar with Macquarie. The net effect of the costless collar is that if the monthly average price of NYMEX WTI Crude Oil futures drops below $100 per barrel, the Company effectively receives $100 for each barrel of production covered by the costless collar. If the NYMEX WTI Crude Oil futures price rises above $131 per barrel, the Company receives $131 per barrel for each barrel of production covered by the costless collar. The result is a “floor” on the price of $100 and a “ceiling” of $131.

In December 2008, we re-structured our hedge position to guarantee more near-term income by closing out our old position and using the value realized to enter into a combination of a swap and a costless collar, with more volume hedged in the near term. The swap, with a fixed price of $94, covers the period from January 2009 through June 2010 and effectively guarantees us $94 per barrel on an average of our first 2250 barrels of production each month. From July 2010 through December 2011, there is a costless collar in effect on an average of 1850 barrels per month, guaranteeing a minimum of $60 a barrel.

SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of each derivative is recorded each period in current earnings or other comprehensive income, depending on whether the derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. To make this determination, management formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed, and a description of the method of measuring effectiveness. This process includes linking all derivatives that are designated as cash-flow hedges to specific cash flows associated with assets and liabilities on the balance sheet or to specific forecasted transactions.

Based on the above, management has determined the swaps noted above do not qualify for hedge accounting treatment. For the year ended July 31, 2009, we recognized a net derivative asset of $413,879 with the change in fair value reflected in other income (expense). Realized hedge gains totaled $903,960 for the year ended July 31, 2009.

NOTE 13 – FAIR VALUE MEASUREMENTS

Doral’s commodity derivatives are measured at fair value in the financial statements. Doral’s financial assets and liabilities are measured using input from three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

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	Level 1 –	Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Doral has the ability to access at the measurement date.
	Level 2 –	Inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
	Level 3 –	Unobservable inputs reflect Doral’s judgments about the assumptions market participants would use in pricing the asset of liability since limited market data exists. Doral develops these inputs based on the best information available, using internal and external data.

The following table presents Doral’s assets and liabilities recognized in the balance sheet and measured at fair value on a recurring basis as of July 31, 2009:

		Input Levels for Fair Value Measurements
Description		Level 1			Level 2			Level 3			Total
Assets:
Commodity derivatives	$	-		$	413,879		$	-		$	413,879
	$	-		$	413,879		$	-		$	413,879

The fair value of commodity derivatives is determined using forward price curves derived from market price quotations, externally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers and direct communication with market participants.

Note 14 – OPERATING LEASES

The Company leased certain office building spaces as its principle executive office. Future minimum lease payments under non-cancellable operating leases are as follows:

NOTE 15 – SUBSEQUENT EVENTS

Subsequent events have been reviewed through November 12, 2009.

In October 2009, Doral granted options to purchase 200,000 shares of common stock at an exercise price of $0.33 per share for a term of five years to a third party in exchange for services.

Subsequent to year end, we issued 179,000 shares of common stock upon exercise of stock options.

Cave Pool Project – Eddy County, New Mexico

On October 28, 2009, Doral West entered into an agreement (the “Blugrass Agreement”) with Blugrass Energy Inc. (“Blugrass”) to purchase a 40% working interest in certain oil and gas properties (the “Cave Pool Unit Properties”) located in and around the Cave Pool Unit in Eddy County, New Mexico approximately 5 miles northwest of Loco Hills, New Mexico. The effective date of the acquisition is October 12, 2009. The Cave Pool Unit Properties are comprised of the Cave Pool Unit and ten (10) leases that make up approximately 2,800 gross acres of leasehold, which Doral now designates as the Cave Pool Project. The Cave Pool Project currently produces approximately 10 BOEPD from a total of 39 wells completed in the Grayburg formation in the Grayburg Jackson Pool.

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The Cave Pool Unit Properties are located adjacent to 3 leases that are a part of our Hanson Project, which contain 6 wells producing from the Grayburg and San Andres formations and 9 PUD locations in the Square Lake Field. As operator of the Cave Pool Project, we envision a re-development of the Cave Pool Unit Properties as a 20-acre 5-spot Grayburg waterflood project which has the potential to develop significant undeveloped reserves.

The Cave Pool Unit Properties were acquired by Blugrass from Robinhood LLC on October 12, 2009. Under the terms of the Blugrass Agreement, we have acquired a 40% interest is all of Blugrass’ right, title and interest in the Cave Pool Unit Properties, including the production on-hand and sales generated from the properties after the effective date of October 12, 2009. In consideration for this interest Doral has agreed to:

	1.	Share with Blugrass access to appropriate Doral proprietary geological and engineering data and information to enhance the re-development of the Cave Pool Unit Properties;
	2.	Pay for and cause the preparation of an independent third-party reserve report on the Cave Pool Unit Properties to be prepared;
	3.	Pay for and obtain title opinions for the leases contained in the Cave Pool Project; and
	4.	Be assigned as the Operator of the Cave Pool Project.

For their part, Blugrass has agreed to pay for the first $200,000 of well repairs and workovers on the Cave Pool Unit Properties, with Doral West and Blugrass proportionately sharing the cost of all repairs and workovers thereafter. An initial 10 Cave Pool Project wells have been identified for repair jobs and will be re-worked by Doral in the near future, adding to the daily production from the Project.

In addition, the Blugrass Agreement provides Doral with a preferential right to purchase all of Blugrass’ remaining interest in the Cave Pool Unit Properties if they choose to sell the properties. The purchase price would be the greater of:

	(a)	$2,000,000; or
	(b)	$40,000 per producing net barrel of oil equivalent per day (“BOEPD”) from the Cave Pool Unit Properties.

NOTE 16 - SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The Company retained an independent reserve engineer to perform an evaluation of proved reserves as of July 31, 2009. The Company retained an in-house reserve engineer, to perform an evaluation of proved reserves as of July 31, 2008. Results of drilling, testing and production subsequent to the date of the estimates may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. All of the Company’s reserves are located in the United States.

The following supplemental unaudited information regarding Doral’s oil and gas activities is presented pursuant to the disclosure requirements of SFAS No. 69. The standardized measure of discounted future net cash flows is computed by applying fiscal year-end prices of oil and gas to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on fiscal year-end cost estimates assuming continuation of existing economic conditions) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on fiscal year-end statutory tax rates) to be incurred on pre-tax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows.

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Capitalized Costs Relating to Oil and Gas Producing Activities as of July 31, 2009 and 2008:

		2009			2008
Proved properties
Mineral interests	$	-		$	-
Wells, equipment and facilities		20,316,131			19,834,246
Total proved properties		20,316,131			19,834,246
Unproved properties
Mineral interests	$	-		$	-
Uncompleted wells, equipment and facilities		-			-
Total unproved properties		-			-
Less: accumulated depreciation, depletion and amortization		-			-
Net capitalized costs	$	20,316,131		$	19,834,246

Costs Incurred in Oil and Gas Producing Activities for the Years Ended July 31, 2009 and 2008:

		2009			2008
Acquisition of proved properties	$	571,953		$	18,915,344
Acquisition of unproved properties		-			-
Development costs		363,566			-
Exploration costs		-			-
Total costs incurred	$	935,519		$	18,915,344

Results of Operations for Oil and Gas Producing Activities for the Year Ended July 31, 2009 and 2008:

		2009			2008
Revenues	$	1,832,146		$	-
Production costs		2,046,043			-
Exploration expenses		-			-
Depreciation, depletion and amortization		419,068			-
Accretion expense		74,820			-
Income before income tax		(707,785	)		-
Income tax		-			-
Results of operations from oil and gas producing activities	$	(707,785	)	$	-

Proved Reserves:

Doral’s proved oil and natural gas reserves have been estimated by independent petroleum engineers. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history; acquisitions of oil and natural gas properties; and changes in economic factors. All proved reserves are located in the United States. Proved reserves as of July 31, 2009 and 2008 are summarized in the table below:

Proved Natural Gas and Oil Reserves at July 31, 2009:

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		Oil			Gas
		(Bbls)			(Mcf)
Proved reserves - beginning of period		4,928,090			3,222,420
Production		(33,701	)		(8,880	)
Net changes in reserves		(1,816,083	)		(1,577,190	)
Proved reserves - end of period		3,078,306			1,636,350
Proved developed reserves - end of period		516,679			50,639

Proved Natural Gas and Oil Reserves at July 31, 2008:

		Oil			Gas
		(Bbls)			(Mcf)
Proved reserves - beginning of period		-			-
Purchase of minerals in place		4,928,090			3,222,420
Production		-			-
Proved reserves - end of period		4,928,090			3,222,420
Proved developed reserves - end of period		964,460			92,930

Standardized Measure of Discounted Future Net Cash Flows at July 31, 2009 and 2008:

		2009			2008
Future cash inflows	$	206,396,306			568,253,760
Future production costs		(48,313,327	)		(148,942,130	)
Future development costs		(24,167,676	)		(30,984,280	)
Future income taxes		(40,049,802	)		(130,763,975	)
10% annual discount for estimated timing of cash flows		(54,256,189	)		(156,739,882	)
Standardized measure of discounted future net cash flows:	$	39,609,312			100,823,493

Future cash inflows are computed by applying year-end commodity prices, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. In our 2009 year-end reserve report, we used the July 31, 2009 NYMEX oil price of $50.00 per barrel and the NYMEX gas price of $3.75 per Mmbtu, adjusted by property for energy content, quality, transportation fees and regional price differentials. The weighted average price over the lives of the properties was $65.12 per Bbl for oil and $3.63 per Mcf for gas. In our 2008 year-end reserve report, we used the July 31, 2008 WTI Cushing spot price of $124.17 per Bbl and Henry Hub spot natural gas price of $9.26 per MMbtu, adjusted by property for energy content, quality, transportation fees, and regional price differentials. The weighted average price over the lives of the properties was $127.76 per Bbl for oil and $7.66 per Mcf for gas.

Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on the year-end costs, and assuming continuation of existing economic conditions. While the Company believes that future operating costs can be reasonably estimated, future prices are difficult to estimate since market prices are influenced by events beyond its control. Future global economic and political events will most likely result in significant fluctuations in future oil prices, while future U.S. natural gas prices will continue to be influenced by primarily domestic market factors, including supply and demand, weather patterns and public policy .

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to the Company’s proved crude oil and natural gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to tax credits and allowances, but do not reflect the impact of general and administrative costs and exploration expenses of ongoing operations relating to the Company’s proved crude oil and natural gas reserves.

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Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended July 31, 2009 and 2008:

		2009			2008
Beginning of period	$	100,823,493		$	-
Purchase of minerals in place					152,011,208
Net changes in prices and production costs		(98,826,251	)		-
Sales of oil and gas produced, net of production		213,897			-
costs
Net change in income taxes		34,287,522			(51,187,715	)
Timing and other		3,110,651
End of period	$	39,609,312		$	100,823,493

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On January 22, 2008, Morgan & Company, Chartered Accountants, resigned as our independent public accountants.

Morgan & Company stated that they were resigning as our independent auditors due to the relocation of our offices and management from Canada to the United States. Because of this relocation, Morgan & Company felt that it was not appropriate for them to continue as our auditors. Following the resignation of Morgan & Company, we appointed Malone & Bailey PC, Certified Public Accountants and Business Consultants, of 601 W. Riverside Avenue, Suite 1940, Spokane, WA 99201 as our new independent registered public accounting firm on January 26, 2008.

Morgan & Company’s reports on our financial statements for the period from inception (October 25, 2005) to July 31, 2006 and for the fiscal year ended July 31, 2007 did not contain an adverse opinion or disclaimer of opinion, nor were they modified or qualified as to uncertainty, audit scope or accounting principles.

During the period from inception (October 25, 2005) to July 31, 2007 and the subsequent interim period up to and including the date of Morgan & Company’s resignation, there were no disagreements between the Company and Morgan & Company on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which, if not resolved to the satisfaction of Morgan & Company, would have caused them to make reference to the subject matter of the disagreement in connection with Morgan & Company’s report for the financial statements for the past year and any subsequent interim period up to and including to the date of Morgan & Company’s resignation.

ITEM 9AT.              CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. It should be noted that the design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were not effective due to the fact that the Macquarie net profits overriding royalty had been valued incorrectly. This resulted in the need to restate the financial statements for the year ended July 31, 2008 and subsequent interim periods. Management is implementing additional oversight controls to ensure this does not occur in the future.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, for the Company.

As of the end of the period covered by this Annual Report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive and Chief Financial Officer, of the effectiveness of the design and operation of our internal control over financial reporting. The Company's management based its evaluation on criteria set forth in the framework in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, management has concluded that the Company's internal control over financial reporting was not effective as of July 31, 2009 due to the fact that the Macquarie net profits overriding royalty had been valued incorrectly. This resulted in the need to restate the financial statements for the year ended July 31, 2008 and subsequent interim periods. Management is implementing additional oversight controls to ensure this does not occur in the future.

This Annual Report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered

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public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the year ended July 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.              OTHER INFORMATION

Other than the events described below, all information required to be disclosed in a report on Form 8-K since the end of our third fiscal quarter ended April 30, 2009 has been previously reported.

Forbearance Agreement – Macquarie Credit Agreement

On November 11, 2009, we entered into an agreement with Macquarie dated November 9, 2009, pursuant to which Macquarie agreed not to exercise their rights or remedies with respect to our failure to pay the amounts due under the Macquarie Credit Agreement until at least January 29, 2010.

To obtain Macquarie’s agreement to forbear from exercising its remedies, we:

	(a)	paid Macquarie a fee of $25,000;
	(b)	agreed to an increased interest rate on amounts owed under the Macquarie Credit Agreement to:
		(i)	with respect to the Revolving Loan, 3.5% over LIBOR in respect of amounts earning interest tied to LIBOR, and 1.75% over prime in respect of amounts earning interest tied to the prime rate, and
		(ii)	with respect to the Term Loan, 7.0% over LIBOR in respect of amounts earning interest tied to LIBOR, and 5.25% over prime in respect of amounts earning interest tied to the prime rate.

In addition, the terms of the forbearance agreement provide that, if we do not receive a valid offer to purchase some or all of the Hanson Project Properties by November 30, 2009 and we have accounts payable greater than $125,000 that are past due, we will be required to pay Macquarie an additional fee of $50,000, and interest rates under the Macquarie Credit Agreement will increase as follows:

	(i)	with respect to the Revolving Loan, 4.0% over LIBOR in respect of amounts earning interest tied to LIBOR, and 2.25% over prime in respect of amounts earning interest tied to the prime rate; and
	(ii)	with respect to the Term Loan, 7.5% over LIBOR in respect of amounts earning interest tied to LIBOR, and 5.75% over prime in respect of amounts earning interest tied to the prime rate.

If we do not receive a valid offer to purchase some or all of the Hanson Project Properties by December 31, 2009 and we have accounts payable greater than $100,000 that are past due, we will be required to pay Macquarie an additional fee of $100,000 and interest rates under the Macquarie Credit Agreement will increase as follows:

	(i)	with respect to the Revolving Loan, 5.5% over LIBOR in respect of amounts earning interest tied to LIBOR, and 3.75% over prime in respect of amounts earning interest tied to the prime rate; and
	(ii)	with respect to the Term Loan, 9.0% over LIBOR in respect of amounts earning interest tied to LIBOR, and 7.25% over prime in respect of amounts earning interest tied to the prime rate.

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Amendment to W.S. Oil and Gas Limited Convertible Note

On November 11, 2009, we agreed with W.S. Oil and Gas Limited to amend the terms of the convertible promissory note issued to them. As amended, in the event of a default under the terms of the note, WS Oil and Gas shall have the right to convert any remaining principal and interest due under the note into shares of our common stock at a conversion price equal to the greater of (a) four times the fair market value of our common stock at the time the conversion right is exercised; and (b) $0.05.

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PART III

ITEM 10.              DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Our executive officers and directors and their ages and titles are as follows:

Name	Age	Position
Everett Willard Gray, II	34	Vice-Chairman, Chief Executive Officer and Director
Paul C. Kirkitelos	40	Chairman, Chief Financial Officer, Secretary, Treasurer and Director
H. Patrick Seale	55	President, Chief Operating Officer and Director

Set forth below is a brief description of the background and business experience of our executive officers and directors:

Everett Willard Gray, II has been our Vice Chairman, Chief Executive Officer and a member of our Board of Directors since December 10, 2008. Mr. Gray is a seasoned executive who has been extensively involved in entrepreneurial ventures in oil field production as an angel investor and advisor/consultant to exploration and production start ups. Mr. Gray also has a diverse background gained from sales and marketing positions with a number of Fortune 500 companies, including Prudential Financial, Pharmacia Corp., Medtronic Inc., and Guidant Corporation.

In April 2007, Mr. Gray founded WS Oil & Gas Limited, which provides merger and acquisition and capital raising consulting services to businesses in the energy sector. From August 2006 to March 2007, Mr. Gray was the CEO and President of Well Renewal Inc., a micro-cap exploration and production company quoted on the Pink Sheets. Mr. Gray was also a director of Well Renewal Inc. from April 2006 to March 2007. From July 2002 to July 2006, Mr. Gray worked as a sales representative for, in turn, Medtronic Inc., Guidant Corporation and FoxHollow Technologies Inc.

Mr. Gray received his B.S. in Business Management from Texas State University. While attending Texas State, Mr. Gray was a member of the golf team, earning Southland Conference All-Academic Honors, as well as being a member of the Southland Conference Golf Championship team.

Paul C. Kirkitelos has been our Chief Financial Officer, Secretary and Treasurer since November 21, 2007 and a member of our Board of Directors since December 24, 2007. Dr. Kirkitelos was also our Chief Executive Officer and President from November 21, 2007 to December 10, 2008. Dr. Kirkitelos has 12 years of management consulting, R&D, finance, and operations experience. Dr. Kirkitelos was most recently Chief Operating Officer of Nutragenetics, a nutritional science and product company. Prior to Nutragenetics, he co-founded Rabbitt Capital Management, a hedge fund based on quantitative stock market models. Dr. Kirkitelos also co-founded Web Event Broadcasting, an Internet video company, where he served as CFO. Previously, with the strategic consulting firm McKinsey & Company, Dr. Kirkitelos served high tech and industrial clients on strategy, corporate finance, and operations studies. Prior to McKinsey, Dr. Kirkitelos was the Director of Applications Development at Chromavision Medical Systems, where he managed applications development, supported clinical trials, and managed the FDA approval for the company's cellular evaluation instrument. This regulatory approval was the foundation for the company's successful initial public offering (IPO) on Nasdaq. Dr. Kirkitelos holds M.S. and Ph.D. degrees in Engineering Physics from University of Virginia, where he worked as a Research Fellow with the NASA Goddard Space Flight Center studying the nonlinear dynamics of astrophysical plasma waves. He earned B.S. degrees in both Electrical Engineering and Physics with Highest Distinction from Worcester Polytechnic Institute.

H. Patrick Seale has been our Chief Operating Officer since August 11, 2008 and subsequently our President and a member of our Board of Directors since December 10, 2008. Mr. Seale has more than 33 years of experience in the domestic and international petroleum industry. Mr. Seale was previously the President and Executive Vice President of SPI Operations LLC, of Midland, Texas, where he was a founder and spent seven years directing SPI's production and reserve growth. While at SPI, Mr. Seale was responsible for the management and direction of SPI’s engineering, development, production, and field operations. SPI's reserves eventually reached 15 million barrels of oil equivalent (BOE) in ten West Texas projects. SPI achieved its growth through strategic acquisitions of under-producing and under-developed properties with potential for exploitation

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of both existing wells and proved undeveloped reserves. Prior to his departure, Mr. Seale engineered the sale of a majority interest in SPI's largest project.

Previously, Mr. Seale was Vice President of Engineering for the North American Oil and Gas Unit of NatWest Markets, the corporate and investment banking division of National Westminster Bank, PLC. In this role, Mr. Seale evaluated the economic feasibility of energy projects and helped determine the size of the bank's reserve-based lending facilities for projects throughout the world.

Mr. Seale previously gained international operations and development experience as Vice President of Operations for both Concept Energy Corporation in Colombia and Frontera Resources Corporation in the Republic of Georgia and the Azerbaijan Republic. In these roles he created development and drilling plans, managed production and drilling operations, and worked with international banks and investors to obtain equity and debt financing. He was also Vice President of Engineering for Cabot Oil & Gas Corp. (NYSE: COG), managing the 800 Bcfe reserve base. Mr. Seale began his career with Exxon Company USA after graduating with Highest Honors in Petroleum Engineering from the University of Texas at Austin.

Term of Office

Members of our Board of Directors are appointed to hold office until the next annual meeting of our stockholders or until his or her successor is elected and qualified, or until he or she resigns or is removed in accordance with the provisions of the Nevada Revised Statutes (the “NRS”). Our officers are appointed by our Board of Directors and hold office until removed by the Board.

Significant Employees

Clifton Martin Bloodworth, P.E. was hired as our Operations Manager on October 13, 2008 and was subsequently appointed our Vice President of Operations on February 16, 2009. Mr. Bloodworth is responsible for managing our operations for the Eddy Country Properties. Mr. Bloodworth has more than 31 years of experience in the petroleum industry. His experience includes management and direct supervision of technical and field personnel and operations; production engineering; drilling engineering; reservoir engineering and reserves determination; secondary and tertiary recovery programs and techniques; San Andres waterflood operations in West Texas and New Mexico; production facility design and operation; field production optimization; mergers and acquisitions; and artificial lift design and operation. Mr. Bloodworth previously served as Senior Operations Engineer for Concho Oil & Gas, LLC; Senior Production Engineer for Bass Enterprises Production Co.; Operations Manager for SPI Operations LLC; Area Supervision and Joint Interest Manager of Southwest Royalties Inc.; Operations Engineer for Cross Timbers Operating Co.; and District Manager and District Engineer for Damson Oil Corporation. Mr. Bloodworth began his career with Mobil Oil Corp. after receiving his Bachelor of Science in Petroleum Engineering from Texas Tech University. Mr. Bloodworth is a licensed professional engineer in the State of Texas and a member of the Society of Petroleum Engineers.

Audit Committee and Audit Committee Financial Expert

Our Board of Directors does not maintain a separately designated standing audit committee. As a result, our entire Board of Directors acts as our audit committee. Our Board of Directors does not have an audit committee charter. None of our directors meets the definition of an "audit committee financial expert." We may explore the appointment of a financial expert to our Board of Directors in the future; however, the cost of doing so may be prohibitive.

CODE OF ETHICS

We adopted a Code of Ethics applicable to our principal executive officer and principal financial officer and certain other finance executives, which is a “code of ethics” as defined by applicable rules of the SEC. Our Code of Ethics is attached as an exhibit to our Annual Report on Form 10-KSB filed with the SEC on October 30, 2007. If we make any amendments to our Code of Ethics other than technical, administrative, or other non-substantive amendments, or grant any waivers, including implicit waivers, from a provision of our Code of Ethics to our principal executive officer and principal financial officer, or certain other finance executives, we will disclose the nature of the amendment or waiver, its effective date and to whom it applies in a Current Report on Form 8-K filed with the SEC.

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COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT

Section 16(a) of the Exchange Act requires our executive officers and directors, and persons who beneficially own more than 10% of our equity securities (collectively, the “Reporting Persons”), to file reports of ownership and changes in ownership with the SEC. Reporting Persons are required by SEC regulations to furnish us with copies of all forms they file pursuant to Section 16(a). Based on our review of the copies of such forms received by us, other than as described below, no other reports were required for those persons.

During the fiscal year ended July 31, 2009, the following persons have failed to file, on a timely basis, the identified reports required by Section 16(a) of the Exchange Act:

	Number of Late	Transactions Not	Known Failures to
Name and Principal Position	Reports	Timely Reported	File a Required Form
Paul C. Kirkitelos	0	0	None
Chairman, Chief Financial Officer, Secretary,
Treasurer and Director
H. Patrick Seale	1	1	None
President, Chief Operating Officer and Director
Everett Willard Gray, II	0	0	None
Vice-Chairman, Chief Executive Officer and
Director

ITEM 11.              EXECUTIVE COMPENSATION

SUMMARY COMPENSATION TABLE

The following table sets forth total compensation paid to or earned by our named executive officers, as that term is defined in Item 402(m)(2) of Regulation S-K during the fiscal years ended July 31, 2009 and 2008.

Notes:

(1)	Pursuant to a verbal agreement, we paid Dr. Kirkitelos $15,000 per month for his services during fiscal 2008. During fiscal 2009, Dr. Kirkitelos has worked without salary or other compensation.

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(2)	Mr. Gray was appointed as our CEO and Vice-Chairman on December 10, 2008. Pursuant to a verbal agreement, we pay Mr. Gray a salary of $180,000 per year, beginning May 23, 2009. In addition, we provide Mr. Gray with a vehicle allowance in the amount of $1,048.86 per month.
(3)	Mr. Seale was appointed as our President and Chief Operating Officer on August 11, 2008. Pursuant to a verbal agreement, we pay Mr. Seale $15,000 per month for his services.
(4)	Mr. Moore served as our executive officer from October 25, 2005 to November 21, 2007 and as a Director from October 25, 2005 to December 24, 2007. We did not pay any compensation to Mr. Moore. However during the fiscal year ended July 31, 2008, for accounting purposes, we recorded in our financial statements the fair value of management services provided to us at no cost as contributed management services.
(5)	Mrs. Moore served as our Secretary until November 21, 2007 and as a Director until December 24, 2007. We did not pay any compensation to Mrs. Moore. However during the fiscal year ended July 31, 2008, for accounting purposes, we recorded in our financial statements the fair value of management services provided to us at no cost as contributed management services.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

As of our fiscal year ended July 31, 2009, no equity awards had been granted to our named executive officers as that term is defined in Item 402(m)(2) of Regulation S-K.

DIRECTOR COMPENSATION TABLE

See "Summary Compensation Table."

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

EQUITY COMPENSATION PLANS

The following table sets forth certain information concerning all equity compensation plans previously approved by stockholders and all previous equity compensation plans not previously approved by stockholders, as of the most recently completed fiscal year.

Equity Compensation Plan Information

2009 Stock Incentive Plan

Effective April 29, 2009, our Board of Directors adopted our 2009 Stock Incentive Plan (the "2009 Plan"). The purpose of the 2009 Plan is to enhance our long-term stockholder value by offering opportunities to our directors, officers, employees and eligible consultants (“Participants”) to acquire and maintain stock ownership in us in order to give these persons the opportunity to participate in our growth and success, and to encourage them to remain in our service.

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The 2009 Plan allows us to grant awards to our officers, directors and employees. In addition, we may grant awards to individuals who act as consultants to us, so long as those consultants do not provide services connected to the offer or sale of our securities in capital raising transactions and do not directly or indirectly promote or maintain a market for our securities.

A total of 8,500,000 (1,700,000 pre-split) shares of our common stock are available for issuance under the 2009 Plan. However, under the terms of the 2009 Plan, at any time after August 1, 2009, the authorized number of shares available under the 2009 Plan may be increased by our Board of Directors, provided that the total number of shares issuable under the 2009 Plan cannot exceed 10% of the total number of shares of common stock outstanding.

Awards may be granted in the form of options to purchase shares of our common stock (“Option Awards”) or in the form of shares of our common stock (“Stock Awards”). Option Awards granted under the 2009 Plan may be made in the form of incentive stock options and non-qualified stock options. Incentive stock options granted under the 2009 Plan are those intended to qualify as “incentive stock options” as defined under Section 422 of the Internal Revenue Code. However, in order to qualify as “incentive stock options” under Section 422 of the Internal Revenue Code, the 2009 Plan must be approved by our stockholders within 12 months of its adoption. The 2009 Plan has not been approved by our stockholders and there is no assurance that the 2009 Plan will be approved by our stockholders. Non-qualified stock options granted under the 2009 Plan are option grants that do not qualify as incentive stock options under Section 422 of the Internal Revenue Code. Stock Awards may be made subject to such terms, conditions and restrictions as the plan administrator may, in its sole discretion, decide, including transfer restrictions and vesting provisions.

The above description of the 2009 Plan does not purport to be complete, and is qualified in its entirety by reference to the full text of the 2009 Plan, which was attached as an exhibit to our Current Report on Form 8-K filed with the SEC on May 5, 2009 and is incorporated by reference herein.

On May 26, 2009, we filed a Registration Statement on Form S-8 (Registration Number 333-159480) under the Securities Act of 1933, as amended, to register 8,500,000 (1,700,000 pre-split) shares of our common stock available for issuance under the 2009 Plan.

In addition to the 2009 Stock Incentive Plan, Mr. Bloodworth’s employment contract entitles him to 200,000 post-split shares of our common stock. These shares have not yet been issued to Mr. Bloodworth.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information concerning the number of shares of our common stock owned beneficially as of November 12, 2009 by: (i) each person (including any group) known to us to own more than five percent (5%) of any class of our voting securities, (ii) each of our directors and each of our named executive officers, and (iii) officers and directors as a group. Unless otherwise indicated, the shareholders listed possess sole voting and investment power with respect to the shares shown.

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(1)	Under Rule 13d-3, a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares; and (ii) investment power, which includes the power to dispose or direct the disposition of shares. Certain shares may be deemed to be beneficially owned by more than one person (if, for example, persons share the power to vote or the power to dispose of the shares). In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares (for example, upon exercise of an option) within 60 days of the date as of which the information is provided. In computing the percentage ownership of any person, the amount of shares outstanding is deemed to include the amount of shares beneficially owned by such person (and only such person) by reason of these acquisition rights. As a result, the percentage of outstanding shares of any person as shown in this table does not necessarily reflect the person’s actual ownership or voting power with respect to the number of shares of common stock actually outstanding on November 12, 2009. As of November 12, 2009, there were 88,116,480 shares of our common stock issued and outstanding.
(2)	Everett Willard Gray, II holds the shares listed as beneficially owned by him indirectly through WS Oil & Gas Limited, a limited partnership controlled by Mr. Gray. In addition, WS Oil & Gas owns a convertible promissory note issued by us in the amount of $500,000. The shares issuable upon conversion of this note have not been listed as beneficially owned by Mr. Gray as the conversion rights cannot be exercised at this time.
(3)	H. Patrick Seale holds the shares listed as beneficially owned by him indirectly through Seale Energy Partners LP, a limited partnership controlled by Mr. Seale.

CHANGES IN CONTROL

We are not aware of any arrangement that might result in a change in control.

ITEM 13.              CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

RELATED TRANSACTIONS

Except as disclosed below, none of the following persons has, during the last two fiscal years, had any material interest, direct or indirect, in any transaction with us or in any presently proposed transaction that has or will materially affect us:

(a)	any director or officer;
(b)	any proposed nominee for election as a director;

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(c)	any person who beneficially owns, directly or indirectly, shares carrying more than 5% of the voting rights attached to the Company's Common Stock;
(d)	any promoters; or
(e)	any relative or spouse of any of the foregoing persons, or any relative of such spouse, who has the same house as such person or who is a director or officer of any parent or subsidiary.

Acquisition of Hanson Project Properties

On July 29, 2008, we completed our acquisition of the Hanson Project Properties pursuant to the terms and conditions of the Hanson Energy Agreement. As consideration for the Hanson Project Properties, we paid and issued to J. Warren Hanson, doing business as Hanson Energy, and his wife Kathie Hanson the following consideration:

	(i)	An aggregate of $5,000,000 in cash;
	(ii)	An aggregate of 5,600,000 post 2009 Reverse Split and 2009 Forward Split shares of our common stock, issued to Hanson Energy and its nominees; and
	(iii)	An overriding royalty interest of 2.5% of 8/8 on the oil and gas produced from the Hanson Project Properties.

Mr. and Mrs. Hanson are the joint owners of more than 5% of our outstanding common stock.

Diamond Spring Prospect

On April 10, 2008, we entered into the Diamond Springs Letter Agreement with G2 Petroleum, LLC (“G2”), a company which E. Willard Gray (a holder of more than five percent of our common stock and our Vice Chairman and Chief Executive Officer) is the managing director, to purchase an interest in an oil and gas prospect covering approximately 3,300 acres located in Fremont County, Wyoming, known as the Diamond Springs Prospect. We did not proceed with the acquisition of the Diamond Springs Prospect.

Gary McCright

On January 9, 2009, we hired G&L Mac Services LLC and its principal Gary McCright to act as a drilling superintendent at our Hanson Project. We paid to Mr. McCright consulting fees in the amount of $60,000 and issued to Mr. McCright 300,000 post-2009 Forward Split shares of our common stock under our 2009 Stock Incentive Plan. At the time of grant, the approximate value of the shares granted to Mr. McCright was $174,600. Mr. McCright is the uncle of the wife of Everett Willard Gray, II, our Vice Chairman and Chief Executive Officer.

Issuance of Convertible Promissory Note to W.S. Oil and Gas Limited

On August 24, 2009, we issued a convertible promissory note (the “Note”) in the principal amount of $250,000 to W.S. Oil and Gas Limited, a limited partnership controlled by Everett Willard Gray, II, our Vice Chairman and Chief Executive Officer and a holder of more than five percent of our common stock, in consideration for a loan from W.S. Oil and Gas in the principal amount of the Note. Under the terms of the Note, we shall repay to W.S. Oil and Gas a total of $500,000, payable in installments as follows:

	(iii)	24 monthly installments of $16,666.67 beginning November 1, 2009; and
	(iv)	12 monthly installments of $8,333.33 beginning November 1, 2011.

In the event that we default under the terms of the Note, W.S. Oil and Gas shall have the right to convert any remaining principal and interest due under the Note into shares of our common stock at a conversion price equal to the greater of (a) four times the fair market value of our common stock at the time the conversion right is exercised; and (b) $0.05. A default under the Note includes a default by us under any instrument for borrowed money in excess of $50,000, provided that any default existing as of the date the Note was issued is not considered an event of default under the Note unless such default persists for a period of 6 months after the date the Note was issued.

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DIRECTOR INDEPENDENCE

Our common stock is quoted on the OTC Bulletin Board inter-dealer quotation system, which does not have director independence requirements. Under NASDAQ Rule 5605(a)(2), a director is not considered to be independent if he or she is also an executive officer or employee of the corporation. There is no member of our Board who is not an executive officer or employee. As a result, we have no independent directors.

As a result of our limited operating history and minimal resources, our management believes that it will have difficulty in attracting independent directors. In addition, we would likely be required to obtain directors and officers insurance coverage in order to attract and retain independent directors. Our management believes that the costs associated with maintaining such insurance is prohibitive at this time.

ITEM 14.              PRINCIPAL ACCOUNTING FEES AND SERVICES

The aggregate fees billed for the fiscal years ended July 31, 2009 and 2008 for professional services rendered by the principal accountant for the audit of the Corporation’s annual financial statements and review of the financial statements included in our Quarterly Reports on Form 10-QSB or Form 10-Q and services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements for these fiscal periods were as follows:

	Year Ended July 31, 2009	Year Ended July 31, 2008
Audit Fees	$67,500	$46,000(1)
Audit-Related Fees	$0	$0
Tax Fees	$0	$0
All Other Fees	$0	$0
Total	$67,500	$46,000(1)

(1)

An additional $2,438 CDN was billed by our former auditors Morgan & Company, Chartered Accounts during the year ended July 31, 2008 for work related to the review of our financial statements.

Policy on Pre-Approval by Audit Committee of Services Performed by Independent Auditors

Our Board of Directors pre-approves all audit and non-audit services performed by our independent auditors during the fiscal year.

No non-audit services were provided by our independent auditors during the last two fiscal years.

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ITEM 15.              EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

Exhibit
Number	Description of Exhibits
2.1	Agreement and Plan of Merger dated April 21, 2008 between Language Enterprises Corp. (as surviving entity) and Doral Energy Corp. (as merging entity) and changing the name of the surviving entity to Doral Energy Corp.(6)
3.1	Articles of Incorporation.(1)
3.2	Certificate of Change Pursuant to NRS 78.209 increasing the authorized capital of common stock to 2,500,000,000 shares, par value $0.001 per share (25-for-1 Stock Split).(3)
3.3	Articles of Merger between Language Enterprises Corp. (as surviving entity) and Doral Energy Corp. (as merging entity).(6)
3.4	Certificate of Change Pursuant to NRS 78.209 decreasing the authorized capital of common stock to 400,000,000 shares, par value $0.001 per share (1-for-6.25 Reverse Split).(18)
3.5	Certificate of Change Pursuant to NRS 78.209 increasing the authorized capital of common stock to 2,000,000,000 shares, par value $0.001 per share (5-for-1 Stock Split).(29)
3.6	Bylaws.(1)
10.1	Loan Agreement dated as of March 7, 2008 with Little Bay Consulting SA.(4)
10.2	Letter Agreement dated April 10, 2008 with G2 Petroleum, LLC.(5)
10.3	Purchase and Sale Agreement dated April 25, 2008 with J. Warren Hanson, doing business as Hanson Energy, and his wife Kathie Hanson.(7)
10.4	Loan Agreement between the Company (as borrower) and Green Shoe Investments Ltd. (as lender) dated May 9, 2008 for the amount of $100,000.(8)
10.5	Loan Agreement between the Company (as borrower) and Green Shoe Investments Ltd. (as lender) dated May 23, 2008 for the amount of $150,000.(9)
10.6	Title Work Agreement dated May 12, 2008 with Arena Resources, Inc.(10)
10.7	Amendment Agreement to Share Purchase Agreement dated July 17, 2008 between J. Warren Hanson, doing business as Hanson Energy, his wife Kathie Hanson, and Doral Energy Corp. (formerly Language Enterprises Corp.)(11)
10.8	Loan Agreement dated July 18, 2008 between Doral Energy Corp. and Little Bay Consulting SA.(11)
10.9	Loan Agreement dated July 18, 2008 between Doral Energy Corp. and Green Shoe Investments Ltd.(11)
10.10	Credit Agreement dated July 29, 2008 between Doral Energy Corp. and Macquarie Bank Limited.(12)
10.11	Security Agreement dated July 29, 2008 between Doral Energy Corp. and Macquarie Bank Limited.(12)
10.12	Subordination Agreement dated July 29, 2008 between Doral Energy Corp., Green Shoe Investments Ltd. and Macquarie Bank Limited.(12)
10.13	Subordination Agreement dated July 29, 2008 between Doral Energy Corp., Little Bay Consulting SA and Macquarie Bank Limited.(12)
10.14	Net Profits Overriding Royalty Interest Conveyance dated July 29, 2008 between Doral Energy Corp. and Macquarie Investments, LLC.(12)
10.15	Conversion Agreement dated July 29, 2008 between Doral Energy Corp. and Macquarie Investments, LLC.(12)
10.16	Limited Forbearance Agreement dated December 10, 2008 between Macquarie Bank Limited and Doral Energy Corp.(15)
10.17	Loan Agreement dated October 3, 2008 between Doral Energy Corp. and Little Bay Consulting SA.(13)
10.18	First Amendment to Credit Agreement between Doral Energy Corp. and Macquarie Bank Limited dated November 19, 2008.(16)
10.19	Second Amendment to Credit Agreement between Doral Energy Corp. and Macquarie Bank Limited dated January 9, 2009.(16)
10.20	Letter Agreement dated January 15, 2009 between Doral Energy Corp. and Miltex Oil Company.(17)

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Exhibit
Number	Description of Exhibits
10.21	Engagement Agreement dated January 26, 2009 between Doral Energy Corp. and C.K. Cooper & Company, Inc.(19)
10.22	Debt Advisory Agreement dated January 30, 2009 between Doral Energy Corp. and C.K. Cooper & Company, Inc.(19)
10.23	Loan Agreement dated February 24, 2009 between Doral Energy Corp. (as borrower) and Green Shoe Investments Ltd. (as lender) in the amount of $100,000 USD.(20)
10.24	Amendment Agreement dated February 13, 2009 to Engagement Agreement between Doral Energy Corp. and C.K. Cooper & Company, Inc.(20)
10.25	Amendment Agreement dated March 31, 2009, 2009 to Letter Agreement between Doral Energy Corp. and Miltex Oil Company.(21)
10.26	Amendment Agreement dated April 21, 2009, 2009 to Letter Agreement between Doral Energy Corp. and Miltex Oil Company.(22)
10.27	2009 Stock Incentive Plan.(23)
10.28	Loan Agreement dated April 29, 2009 between Doral Energy Corp. and Green Shoe Investments Ltd. (24)
10.29	Sale and Purchase Agreement dated May 5, 2009 between Doral Energy Corp. and Flaming S, Inc. (24)
10.30	Sale and Purchase Agreement dated May 15, 2009 between Doral Energy Corp. and Slape Oil Company, Inc.(24)
10.31	Convertible Note Agreement dated May 28, 2009 between Doral Energy Corp. and Green Shoe Investments Ltd.(25)
10.32	Assignment Agreement dated July 30, 2009.(26)
10.33	Consent to Assignment Agreement dated for July 29, 2009.(26)
10.34	Macquarie Forbearance Agreement dated July 30, 2009.(26)
10.35	Convertible Promissory Note dated August 24, 2009 in the principal amount of $250,000 issued to W.S. Oil and Gas Limited.(27)
10.36	Macquarie Forbearance Agreement dated August 28, 2009.(28)
10.37	Macquarie Forbearance Agreement dated November 9, 2009.
10.38	Amendment Agreement to Convertible Promissory Note between W.S. Oil and Gas Limited and Doral Energy Corp.
14.1	Code of Ethics.(2)
21.1	List of Subsidiaries.
23.1	Consent of Malone & Bailey PC, Certified Public Accountants and Business Consultants.
31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(1)	Filed as an exhibit to our Registration Statement on Form SB-2 filed on September 11, 2006.
(2)	Filed as an exhibit to our Annual Report on Form 10-KSB for the year ended July 31, 2007 filed on October 30, 2007.
(3)	Filed as an exhibit to our Current Report on Form 8-K filed on January 9, 2008.
(4)	Filed as an exhibit to our Current Report on Form 8-K filed on March 12, 2008.
(5)	Filed as an exhibit to our Current Report on Form 8-K filed on April 16, 2008.
(6)	Filed as an exhibit to our Current Report on Form 8-K filed on April 28, 2008.
(7)	Filed as an exhibit to our Current Report on Form 8-K filed on May 1, 2008.
(8)	Filed as an exhibit to our Current Report on Form 8-K filed on May 13, 2008.
(9)	Filed as an exhibit to our Current Report on Form 8-K filed on May 21, 2008.

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(10)	Filed as an exhibit to our Current Report on Form 8-K filed on May 27, 2008.
(11)	Filed as an exhibit to our Current Report on Form 8-K filed on July 23, 2008.
(12)	Filed as an exhibit to our Current Report on Form 8-K filed on August 4, 2008.
(13)	Filed as an exhibit to our Current Report on Form 8-K filed on October 22, 2008.
(14)	Filed as an exhibit to our Annual Report on Form 10-K filed on October 29, 2008
(15)	Filed as an exhibit to our Current Report on Form 8-K filed on December 11, 2008.
(16)	Filed as an exhibit to our Current Report on Form 8-K filed on January 14, 2009.
(17)	Filed as an exhibit to our Current Report on Form 8-K filed on January 22, 2009.
(18)	Filed as an exhibit to our Current Report on Form 8-K filed on January 29, 2009.
(19)	Filed as an exhibit to our Current Report on Form 8-K filed on February 9, 2009.
(20)	Filed as an exhibit to our Current Report on Form 8-K filed on February 25, 2009.
(21)	Filed as an exhibit to our Current Report on Form 8-K filed on April 6, 2009.
(22)	Filed as an exhibit to our Current Report on Form 8-K filed on April 27, 2009.
(23)	Filed as an exhibit to our Current Report on Form 8-K filed on May 5, 2009.
(24)	Filed as an exhibit to our Current Report on Form 8-K filed on June 2, 2009.
(25)	Filed as an exhibit to our Quarterly Report on Form 10-Q filed on June 15, 2009.
(26)	Filed as an exhibit to our Current Report on Form 8-K filed on August 5, 2009.
(27)	Filed as an exhibit to our Current Report on Form 8-K filed on August 28, 2009.
(28)	Filed as an exhibit to our Current Report on Form 8-K filed on September 2, 2009.
(29)	Filed as an exhibit to our Current Report on Form 8-K filed on September 14, 2009.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

				DORAL ENERGY CORP.
Date:	November 13, 2009		By:	/s/ Everett Willard Gray, II
				EVERETT WILLARD GRAY, II
				Vice-Chairman & Chief Executive Officer
				(Principal Executive Officer)
Date:	November 13, 2009		By:	/s/ Paul C. Kirkitelos
				PAUL C. KIRKITELOS
				Chairman, Chief Financial Officer, Secretary &
				Treasurer
				(Principal Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date:	November 13, 2009		By:	/s/ Everett Willard Gray, II
				EVERETT WILLARD GRAY, II
				Vice-Chairman, Chief Executive Officer and Director
Date:	November 13, 2009		By:	/s/ Paul C. Kirkitelos
				PAUL C. KIRKITELOS
				Chairman, Chief Financial Officer, Secretary,
				Treasurer and Director
Date:	November 13, 2009		By:	/s/ H. Patrick Seale
				H. PATRICK SEALE
				Chief Operating Officer, President and Director

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