Edgar Filing: Conquest Petroleum Inc

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

__________________________

FORM 10-K/A

(Amendment No. 1)

x	ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the year ended: December 31, 2009

¨	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from: to

Commission File No.: 000-53093

__________________________

Conquest Petroleum Incorporated

(Exact name of registrant as specified in its charter)

__________________________


TEXAS	20-0650828
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

24900 Pitkin Road, Suite 308

Spring, Texas 77386

www.conquestpetroleum.com

(Address of principal executive offices)

Registrant’s Telephone Number, Including Area Code: (281) 466-1530

Former Name and Address

Maxim TEP, Inc.

9400 Grogan’s Mill Road, Suite 205

The Woodlands, TX 77380

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 ¨ No x

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting Company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer ¨	Smaller reporting Company x
(Do not check if a smaller reporting Company)

Indicate by check mark whether the registrant is a shell Company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The number of shares of the registrant’s common stock outstanding as of May 17, 2010 44,676,993 shares.

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of exchange on which registered
Common Stock, par value $0.00001 per share	OCTBB

Securities registered pursuant to Section 12(g) of the Act: None

At December 31, 2009, the aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $3,381,636 based on the closing price of such stock on such date of $0.12.

CONQUEST PETROLEUM INCORPORATED

Table of Contents

			Page

PART I
	Item 1.	Business	3
	Item 1A.	Risk Factors	4
	Item 1B.	Unresolved Staff Comments	12
	Item 2.	Properties	12
	Item 3.	Legal Proceedings	18
	Item 4.	Submission of Matters to a Vote of Security Holders	19
PART II
	Item 5.	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer	19
	Item 6.	Selected Financial Data	19
	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	19
	Item 8.	Financial Statements and Supplementary Data	26
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	52
	Item 9A.	Controls and Procedures	52
	Item 9B.	Other Information	53
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	53
	Item 11.	Executive Compensation	56
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	62
	Item 14.	Principal Accountant Fees and Services	62
PART IV			63
	Item 15.	Exhibits and Financial Statement Schedules
SIGNATURES			64

Cautionary Notice Regarding Forward Looking Statements

Conquest Petroleum Incorporated desires to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. This report contains a number of forward-looking statements that reflect management's current views and expectations with respect to business, strategies, future results and events and financial performance. All statements made in this Annual Report other than statements of historical fact, including statements that address operating performance, events or developments that management expects or anticipates will or may occur in the future, including statements related to revenues, cash flow, profitability, adequacy of funds from operations, statements expressing general optimism about future operating results and non-historical information, are forward looking statements. In particular, the words “believe,” “expect,” “intend,” “anticipate,” “estimate,” “may,” “will,” variations of such words, and similar expressions identify forward-looking statements, but are not the exclusive means of identifying such statements and their absence does not mean that the statement is not forward-looking.

Readers should not place undue reliance on these forward-looking statements, which are based on management’s current expectations and projections about future events, are not guarantees of future performance, are subject to risks, uncertainties and assumptions and apply only as of the date of this report. Conquest’s actual results, performance or achievements could differ materially from the results expressed in, or implied by, these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below in “Risk Factors” as well as those discussed elsewhere in this report, and the risks discussed in press releases and other communications to stockholders issued by Conquest from time to time which attempt to advise interested parties of the risks and factors that may affect the business. Except as may be required under the federal securities laws, Conquest undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I

ITEM 1.BUSINESS

Company Overview

Conquest Petroleum Incorporated (“Conquest” or the “Company”), is headquartered in Spring, Texas, a suburb of Houston. The Company is an oil and natural gas exploration, development and production (E&P) company geographically focused on the onshore United States. The Company’s operational focus is the acquisition, through the most cost effective means possible, of production or near production of oil and natural gas field assets. Targeted fields generally have existing wells that are often past primary energy recovery, but whose enhancement through secondary and possibly tertiary recovery methods could revitalize them. Targeted fields also have the availability of additional drilling sites. The Company seeks to have an inventory of existing wells to enhance and a number of new drilling sites to maintain growth, while increasing reserves and cash flow. The Company uses both conventional and non-conventional methods to bring non-producing wells back into production and to minimize operational costs.

Business Strategy

The following are key elements of our business strategy:

Phase One – Acquisition Phase

The Company sought financing for its Phase One which was to acquire low risk, mature fields with proven and probable reserves. The Company secured initial funding from several accredited investors, and set out to acquire fields with existing wells and infill development drilling opportunities, and now currently owns the rights to oil and natural gas leases in Kentucky and Louisiana.

In buying existing oil and natural gas fields, the Company set out to extensively study the fields, the formations in which oil and natural gas were found, the history of sales from the field and the history of all surrounding fields, and their production. From this information, a better assessment could be made as to the value of the target property.

Phase Two – Completion of Existing Wells Phase

In Phase Two, the Company’s strategy was exploitation of its fields by investing in low risk work-over programs on existing wells’ and monetization of significant upside in work-over wells on already proved assets, and develop proved developed non-producing wells (PDNP) into proved developed producing (PDP’s) assets with no associated exploration risk. The Company is nearing completion of its restoration programs in the Delhi Field and Belton Fields.

Currently, the Company has active operations on its fields located in Louisiana and Kentucky. The Company began an active fourteen well work-over program on its largest field, the Delhi Field in Louisiana. Of the fourteen wells, eight are completed in the Mengel Sand and there are six water injection wells in the Mengel Sand in operation. The Company has 515 small productive natural gas wells in its Marion field in Louisiana that it received from the purchase of this field along with over 110 miles of natural gas gathering pipeline. It has plans to repair the existing pipeline to more efficiently capture additional natural gas from these existing wells as well as other remedial programs such as the installation of hub compressors, installing packer holes in casings and swabbing existing wells. Lastly, the Company began a 5 well work over program in its Belton Field in Kentucky. Due to limited funding, in December 2009, the Company was delayed in completion of these planned 2009 activities and foresees the plan to extend to mid-year 2010.

Phase Three – Development Drilling on Proved Assets

In Phase Three, the Company’s strategy is to execute infill drilling of its oil and gas assets. The company will develop proved undeveloped (PUD’s) assets into proved developed and producing (PDP’s) assets with no associated exploration risk. The Company has identified over 300 infill prospects in the Marion, Field (with another 600 locations possible). It has identified four development oil opportunities in the Mengel Sand and six development opportunities in the Z Sand in its Delhi field. The Company has identified 72 probable gas opportunities in the New Albany Shale with another 123 locations possible.

All of the planned development drilling and enhancements assume that the Company is successful in securing its 2010 funding that will support a drilling and development budget. The actual number of wells drilled will vary depending upon various factors, including the availability and cost of drilling rigs, any working interest partner issues, our ability to raise additional capital, the success of our drilling programs, weather delays and other factors. Our ability to drill the number of wells we have budgeted for 2010 and 2011 is heavily dependent upon the timely access to oilfield services, particularly drilling rigs.

Phase Four – Expansion Phase

In the Phase Four development of The Company, an effort will be made to expand the company’s oil and natural gas reserves through the acquisition of fields, wells or working interest in oil and gas assets.

ITEM 1A. RISK FACTORS

Risks Related to Our Business, Industry and Strategy:

We have had operating losses and limited revenues to date and may experience continued losses in the future.

We have operated at a loss each year since inception. Net losses for the fiscal years ended December 31, 2009 and 2008 were $23.3 million and $6.03 million, respectively.

Our ability to generate net income will be strongly affected by, among other factors, our ability to successfully drill undeveloped reserves as well as the market price of crude oil and natural gas. If we are unsuccessful in drilling productive wells or the market price of crude oil and natural gas declines, we may report additional losses in the future. Consequently, future losses may adversely affect our business, prospects, financial condition, results of operations and cash flows.

Liquidity

The global financial and credit crisis has and may continue to impact our liquidity and financial condition. The continued credit crisis and related turmoil in the global financial system may have a material impact on our liquidity and our financial condition, and we may ultimately face major challenges if conditions in the financial markets do not improve. Our ability to access the capital markets or borrow money may be restricted at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Additionally, the current economic situation could lead to reduced demand for natural gas and oil, or further reductions in the prices of natural gas and oil, or both, which could have a negative impact on our financial position, results

of operations and cash flows. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.

We have substantial capital requirements that, if not met, may hinder operations.

We have and expect to continue to have substantial capital needs as a result of our active exploration, development, and acquisition programs. We expect that additional external financing will be required in the future to fund our growth. We may not be able to obtain additional financing, and we have no financing under existing or new credit facilities and these may not be available in the future. Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition, and results of operations.

Natural gas and oil prices are highly volatile, and lower prices will negatively affect our financial results.

Our revenue, profitability, cash flow, oil and natural gas reserves value, future growth, and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of natural gas and oil. Historically, the markets for natural gas and oil have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future natural gas and oil price movements with certainty. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty, and a variety of additional factors beyond our control. These factors include:

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the level of consumer product demand;

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the domestic and foreign supply of oil and natural gas;

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overall economic conditions;

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weather conditions;

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domestic and foreign governmental regulations and taxes;

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the price and availability of alternative fuels;

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political conditions in or affecting oil and natural gas producing regions;

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the level and price of foreign imports of oil and liquified natural gas; and

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the ability of the members of the Organization of Petroleum Exporting Countries and other

state controlled oil companies to agree upon and maintain oil price and production controls.

Declines in natural gas and oil prices may materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and results of operations and may reduce the amount of oil and natural gas that we can produce economically.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our success largely depends on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are a common risk that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling operations, including the following:

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delays imposed by or resulting from compliance with regulatory requirements;

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pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment and qualified personnel;

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equipment failures or accidents;

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adverse weather conditions;

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reductions in oil and natural gas prices; and

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oil and natural gas property title problems.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reported reserves. In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires that economic assumptions be made about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices received, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our drilling prospects are in various stages of evaluation. There is no way to predict in advance of drilling and testing whether any particular drilling prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

The near-term focus of our development activities will be concentrated in three core asset areas, which exposes us to risks associated with prospect concentration. The relative concentration of our near-term activities in three core asset areas means that any impairments or material reductions in the expected size of the reserves attributable to our wells, any material harm to the producing reservoirs or associated surface facilities from which these wells produce or any significant governmental regulation with respect to any of these fields, including curtailment of production or interruption of transportation of production, could have a material adverse effect on our financial condition and results of operations.

Special geological characteristics of the New Albany Shale play will require us to use less-common drilling technologies in order to determine the economic viability of our development efforts. New Albany Shale reservoirs are complex, often containing unusual features that are not well understood by drillers and producers. Successful operations in this area require specialized technical staff with specific expertise in horizontal drilling, with respect to which we have limited experience.

The New Albany Shale play contains vertical fractures. Results of past drilling in the New Albany Shale have been mixed and are generally believed to be related to whether or not a particular well bore intersects a vertical fracture. While wells have been drilled into the New Albany Shale for years, most of those wells have been drilled vertically. Where vertical fractures have been encountered, production has been better. It is expected that horizontal drilling will allow us to encounter more fractures by drilling perpendicular to the fracture planes. While it is believed that the New Albany Shale is subject to some level of vertical fracturing throughout the Illinois Basin, certain areas will be more heavily fractured than others. If the areas in which we hold an interest are

not subject to a sufficient level of vertical fracturing, then our plan for horizontal drilling might not yield commercially viable results.

Gas and water are produced together from the New Albany Shale. Water is often produced in significant quantities, especially early in the producing life of a well. We plan to dispose of this produced water by means of injecting it into other porous and permeable formations via disposal wells located adjacent to producing wells in accordance with approved practices by appropriate regulatory agencies. If we are unable to find such porous and permeable reservoirs into which to inject this produced water or if we are prohibited from injecting because of governmental regulation, then our cost to dispose of produced water could increase significantly, thereby affecting the economic viability of producing the New Albany Shale wells.

Seismic studies do not guarantee that hydrocarbons are present or, if present, will produce in economic quantities.

We may rely on seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities.

We depend on successful exploration, development and acquisitions to maintain revenue in the future.

In general, the volume of production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing, or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired. In addition, we may be required to find partners for any future exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we will be adversely affected.

Our future acquisitions may yield revenues and/or production that vary significantly from our projections.

In acquiring producing properties we assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to such properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities.

We may not inspect every well, and we may not be able to identify structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.

We cannot assure you that:

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we will be able to identify desirable natural gas and oil prospects and acquire leasehold or other ownership interests in such prospects at a desirable price;

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any completed, currently planned, or future acquisitions of ownership interests in natural gas and oil prospects will include prospects that contain proved natural gas or oil reserves;

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we will have the ability to develop prospects which contain proven natural gas or oil reserves;

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we will have the financial ability to consummate additional acquisitions of ownership interests in natural gas and oil prospects or to develop the prospects which we acquire to the point of production; or

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that we will be able to consummate such additional acquisitions on terms favorable to us.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and preliminarily scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These scheduled drilling locations represent a significant component of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

We may experience difficulty in achieving and managing future growth.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

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our ability to obtain leases or options on properties;

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our ability to acquire geological & geophysical data;

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our ability to identify and acquire new development prospects;

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our ability to develop existing prospects;

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our ability to continue to retain and attract skilled personnel;

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our ability to maintain or enter into new relationships with project partners and independent contractors;

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the results of our drilling program;

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hydrocarbon prices; and

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our access to capital.

We may not be successful in upgrading our technical, operations, and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations.

We face strong competition from other natural gas and oil companies.

We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proved properties. Our competitors include major integrated natural gas and oil companies and numerous independent natural gas and oil companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for productive natural gas and oil properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. We may not be able to conduct our operations, evaluate, and select suitable properties and consummate transactions successfully in this highly competitive environment.

Our business may suffer if we lose our Chief Executive Officer or our Chief Financial Officer.

Our success will be dependent on our ability to continue to employ and retain experienced skilled personnel. We depend to a large extent on the services of Robert D. Johnson, our Chief Executive Officer and Chairman. Mr. Johnson has 40 years experience and possesses the expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and, marketing oil and natural gas production.

Further, Robert C. Johnson serves as the Company’s Chief Financial Officer. He has over 30 years experience in the oil and gas industry with major corporations and independent oil and gas companies. His expertise covers all spectrums of the industry to include: production operations, drilling, pipeline activity, and the financial arena. He is also a successful businessman having built a small manufacturing company which he subsequently sold.

The Company has employment agreements with both parties which provides for notice before they may resign. We do not, and likely will not, maintain key-man life insurance with respect to them or any of our employees. Having both parties with such experience provides for redundancy in the case of a loss of one or the other.

The unavailability or high cost of drilling rigs, equipment, supplies or personnel could affect adversely our ability to execute on a timely basis our exploration and development plans within budget, which could have a material adverse effect on our financial condition and results of operations.

Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or affect adversely our exploration and development operations, which could have a material adverse effect on our financial condition and results of operations. Demand for drilling rigs, equipment, supplies, and personnel are currently very high in the areas in which we operate. An increase in drilling activity in the areas in which we operate could further increase the cost and decrease the availability of necessary drilling rigs, equipment, supplies and personnel.

We cannot control activities on properties that we do not operate and are unable to ensure their proper operation and profitability.

We may not operate certain of the properties in the future in which we obtain an interest. As a result, we would have a limited ability to exercise influence over, and control the risks associated with, the operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:

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timing and amount of capital expenditures;

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expertise and financial resources;

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inclusion of other participants in drilling wells; and

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use of technology.

The marketability of our natural gas production depends on facilities that we typically do not own or control, which could result in a curtailment of production and revenues.

The marketability of our natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through gas gathering systems and gas pipelines that we may not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our gas may be interrupted due to capacity constraints on the applicable system, due to maintenance or repair of the system, or for other reasons as dictated by the particular agreements. Our ability to produce and market natural gas on a commercial basis could be harmed by any significant change in the cost or availability of such markets, systems or pipelines.

We may not be able to keep pace with technological developments in our industry.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introduction of new products and services which utilize new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other natural gas and oil companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we are able to. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. Because our properties serve as collateral for advances under our existing credit facility, a write down in the carrying values of our properties could require us to repay debt earlier than would otherwise be required. A write-down would also constitute a non-cash charge to earnings. It is likely that the effect of such a write-down could also negatively impact the trading price of our securities.

We account for our oil and gas properties using the successful efforts method of accounting. Under this method, all development costs and acquisition costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively. Costs of drilling exploratory wells are initially capitalized, but charged to expenses if and when a well is determined to be unsuccessful. We evaluate impairment of our proved oil and gas properties whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and gas prices are low or volatile. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

The exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with such governmental regulations. Matters subject to regulation include:

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natural disasters;

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permits for drilling operations;

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drilling and plugging bonds;

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reports concerning operations;

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the spacing and density of wells;

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unitization and pooling of properties;

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environmental maintenance and cleanup of drill sites and surface facilities; and

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Protection of human health.

From time to time, regulatory agencies have also imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity in order to conserve supplies of natural gas and oil.

Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

Our operations may cause us to incur substantial liabilities for failure to comply with environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit or other authorizations before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, require permitting or authorization for release of pollutants into the environment, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas, and impose substantial liabilities for pollution resulting from historical and current operations. Failure to comply with these laws and regulations may result

in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as on the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, some of which may owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.

Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

The financial condition of our operators could negatively impact our ability to collect revenues from operations.

We may not operate all of the properties in the future in which we have working interests. In the event that an operator of our properties experiences financial difficulties, this may negatively impact our ability to receive payments for our share of net production that we are entitled to under our contractual arrangements with such operator. While we seek to minimize such risk by structuring our contractual arrangements to provide for production payments to be made directly to us by first purchasers of the hydrocarbons, there can be no assurances that we can do so in all situations covering our non-operated properties.

We may not have enough insurance to cover all of the risks that we face and operations of prospects in which we participate may not maintain or may fail to obtain adequate insurance.

In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impacts of Hurricanes Katrina, Rita and Ike have resulted in escalating insurance costs and less favorable coverage terms.

Oil and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. We do not operate all of the properties in which we have an interest. In the projects in which we own a non-operating interest directly or own an equity interest in a limited partnership which in turn owns a non- operating interest, the operator for the prospect maintains insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect which could have a material adverse effect on our financial condition and results of operations.

Terrorist attacks aimed at our energy operations could adversely affect our business.

The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These

developments have subjected our oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, those of our customers, the infrastructure we depend on for transportation of our products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.

Any failure to meet our debt obligations could harm our business, financial condition, results of operations or cash flows.

We face significant interest expenses as a result of our outstanding notes and we are in default on some of these notes. Our ability to generate cash flows from operations and to make scheduled payments on our indebtedness, including the notes, will depend on our future financial performance. Our future performance will be affected by a range of economic, competitive, legislative, operating and other business factors, many of which we cannot control, such as general economic and financial conditions in our industry or the economy at large. A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition, or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our business, financial condition, results of operations and prospects and our ability to service our debt, including the notes, and other obligations.

If we are unable to service our indebtedness, we will be forced to adopt an alternative strategy that may include actions such as reducing or delaying acquisitions and capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking equity capital. We cannot assure you that any of these alternative strategies could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments of interest on and principal of our debt in the future, including payments on the notes, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair our liquidity. Failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms.

We may issue additional shares of capital stock that could adversely affect holders of shares of our common stock and, as a result, holders of our notes convertible into shares of common stock.

Our board of directors is authorized to issue additional classes or series of shares of our capital stock without any action on the part of our stockholders, subject to the restrictive covenants of the indenture governing the notes. Our board of directors also has the power, without stockholder approval and subject to such restrictive covenants, to set the terms of any such classes or series of shares of our capital stock that may be issued, including voting rights, dividend rights, conversion features, preferences over shares of our existing class of common stock with respect to dividends or if we liquidate, dissolve or wind up our business and other terms. If we issue shares of our capital stock in the future that have preference over shares of our existing class of common stock with respect to the payment of dividends or upon our liquidation, dissolution or winding up, or if we issue shares of capital stock with voting rights that dilute the voting power of shares of our existing class of common stock, the rights of holders of shares of our common stock or the trading price of shares of our common stock and, as a result, the market value of the notes convertible into shares of common stock could be adversely affected.

The market price of our common stock may be volatile.

As we are in the early stages of being a publically traded stock, the trading price of our common stock and the price at which we may sell common stock in the future are subject to large fluctuations in response to any of the following:

•

limited trading volume in our common stock;

•

quarterly variations in operating results;

•

our involvement in litigation;

•

general financial market conditions;

•

the prices of natural gas and oil;

•

announcements by us and our competitors;

•

our liquidity;

•

our ability to raise additional funds;

•

changes in government regulations; and

•

other events.

Moreover, our common stock does not have substantial trading volume. As a result, relatively small trades of our common stock may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock.

Because of the possibility of limited trading volume of our common stock and the price volatility of our common stock, you may be unable to sell your shares of our common stock when you desire or at the price you desire. The inability to sell your shares of our common stock in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss.

We have not previously paid dividends on the shares of our common stock and do not anticipate doing so in the foreseeable future.

We have not in the past paid any dividends on the shares of our common stock and do not anticipate that we will pay any dividends on our common stock in the foreseeable future. Any future decision to pay a dividend on our common stock and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our bank credit facility and the Secured Notes. A default, if not cured or waived, could result in acceleration of all indebtedness outstanding under our bank credit facility and the Secured Notes. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it. Even if new Financing were then available, it may not be on terms that are acceptable to us. See "Description of Other Indebtedness" and "Description of the Secured Notes if Defaults."

If we fail to meet our payment obligations under our secured indebtedness, the note holder(s) could foreclose on, and acquire control of a portion of our assets.

The lenders under these Secured Notes will have a lien on substantially all our assets. As a result of this lien, if we fail to meet our payments or other obligations under this secured indebtedness, that lenders/lender would be entitled to foreclose on our assets our assets and liquidate those assets. Under those circumstances, we may not have sufficient funds to Sinking Fund Deposits and interest on the Secured Notes. As a result, you may lose a portion of or the entire value of your investment.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. PROPERTIES

The Company has acquired the following leases and mineral rights to recover oil and natural gas within the United States:

The Delhi Field - Richland Parish, Louisiana

In December 2006, the Company acquired mineral right leases on 1,400 acres in the Delhi Field, in north-east Louisiana. The Company’s lease encompasses a portion of approximately 13,636 acres comprising the Delhi Holt Bryant Unit and Mengel Unit. This field has produced since 1946. As of recent, oil production in this field has utilized secondary recovery in which water is injected into the reservoir formation to displace residual oil. The water from injection wells will increase reservoir pressure and physically sweep the displaced oil to adjacent production wells. Current production is 40 barrels of oil per day and increasing. The Company’s 2010 development program involves bringing into production 8 existing wells in the Mengel Sand as well as 4 infill drilling possibilities of proved but undeveloped opportunities in the Mengel Sand with an additional six development locations in the Z Sand. In 2009, 6 existing wellbores were completed as water injection wells which will enhance the efficiency of the water flood and increase production while allowing a higher percentage of residual oil to be produced. The company has a 95.8% Working Interest and 82.7% Net Revenue.

The Marion Field - Union Parish, Louisiana

In December 2005, the Company acquired shallow mineral rights (down to 3,200 feet) on approximately 21,500 acres in Union Parrish, Louisiana, which is a natural gas field currently producing approximately 600 MCF a day from approximately 500 wells from the Arkadelphia Gas Zones sand. The wells are currently producing on 40 acre spacing. The Company and third party engineers believe that there is great infill development drilling potential after drilling 4 wells with virgin pressure on 20 acre spacing in 2007 and 2008. The field can be optimized at 10 acre spacing, creating a total of 800 eventual development opportunities. The company forecasts a 300 well program for the next 4 and a half years. The Marion field is part of the larger Monroe Gas Field which was the largest gas field in the United States in the early-to-mid 1900's. It is located in Northeast Louisiana, in Union Parish, which has 8,558 wells. The oil producing Cotton Valley and Smackover formations are also present within the leasehold. In addition, the Company has leased deep mineral rights (down to 9,500 feet) on approximately 8,000 acres of the 21,500 acres that will allow the Company to explore the deeper zones. The Company believes that a remedial program to fix the infrastructure from pipeline leakages to hub compressors can result in an increase in production. The company has a 100% Working Interest and 71% Net Revenue Interest in this field.

Belton Field - Muhlenberg County, Kentucky

In April 2004, the Company purchased the mineral rights on approximately 3,008 acres in Muhlenberg County, an oil and gas field in the Illinois Basin, in west-central Kentucky. In 2006 and 2007, the Company leased the mineral rights to an additional 6,317 acres. Oil was discovered in this basin about 150 years ago. When the Company acquired the rights on the original 3,008 acres, the above-the-ground pumping and storage units had fallen into disrepair and the field was idle. The field was originally discovered in 1939 and developed to produce oil from shallow zones. The first well was completed in the McCloskey Limestone (TD 1,541’). Coal was discovered on the property and much of that coal was “mined-out” during strip mining operations. All mining operations ceased decades ago and the mines were reclaimed and are now pastures. Natural gas was discovered in the northwest corner of the field in the 1980’s and continued to produce natural gas until recently. There are four possible producing horizons on the property. These include (1) the New Albany Gas Shale; (2) the upper-Mississippian-period’s Jackson Sandstone that has significant gas indicated in two wells drilled on the northeast border of the property (the upper McCloskey zone); (3) the lower-Mississippian-period’s St. Genevieve Limestone (the oil-bearing McCloskey zone) and (4) a deep Silurian oil-bearing zone. The Company is in the process of bringing into production up to 5 existing upper McCloskey wells. The Company’s 2010 and 2011 drilling program includes the drilling of 72 New Albany Shale wells that are classified as Probable. The Company will endeavor to farm out the deep Silurian zones. The Company has a 100% working Interest and approximately 76.5% Net Revenue Interest in this field.

The Company divested the following fields in 2009 and 2008 in an effort to enhance its balance sheet, relieve debt, and exit non strategic geographical core areas:

- A 50% Working Interest and 42% Net Revenue Interest in the South Belridge Field, Kern County, California

- A 75% Working Interest and 50.51% Net Revenue Interest in the Days Creek Field, Miller County, Arkansas

- A 24% Working Interest and 16.5% Net Revenue Interest in the Stephens Field at Smackover, Ouachita County, Arkansas

- A 100% working interest in 1280 acres in the Hospah and Lone Pine Fields, Mckinley County New Mexico

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2009. “Developed Acreage” refers to acreage on which wells have been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities. “Undeveloped Acreage” refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities whether or not the acreage contains proved reserves.

	Average
	Working			Developed Acreage				Undeveloped Acreage				Total Acreage
	Interest			Gross		Net		Gross		Net		Gross		Net
Marion-LA		100	%		10,300		10,300		11,200		11,200		21,500		21,500
Delhi-LA		95.77	%		520		498		880		843		1,400		1,341
Belton-KY		100	%		110		110		9,215		9,215		9,325		9,325
Total					10,930		10,908		21,295		21,258		32,225		32,166

Oil and Natural Gas Reserves

The reserves as of December 31, 2009 were derived from reserve estimates prepared by independent reserve engineers; Huddleston V. Co., Inc. The PV-10 value was derived using average prices throughout the calendar year, discounted at 10% per annum on a pretax basis, and is not intended to represent the current market value of the estimated oil and natural gas reserves owned by the Company.

The following table sets forth our estimated net proved oil and natural gas reserves and the PV-10 value of such reserves as of December 31, 2009.

	Proved Reserves
	Developed
Oil and condensate (Bbls)		45,000
Natural gas (MMcf)		576
Total proved reserves (BOE)		141,017
PV-10 Value	$	1,156,314

(1)	The PV 10% Value as of December 31, 2009 is pre-tax and was determined by using the average of the preceding, 12-month-first-of-month product prices, which were $61.80 per Bbl for Oil and $4.21 MCF for gas pursuant to SEC guidelines. Management believes that the presentation of PV-10 value may be considered a non-GAAP financial measure. Therefore, we have included a reconciliation of the most directly comparable GAAP financial measure (standard measure of discounted net cash flows in Note 2 below). Management believes that the presentation of PV-10 value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies.

(2)	Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and natural gas properties and in evaluating acquisition candidates. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by us. The PV-10 value should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
(3)	In late 2009 Conquest implemented a water injection project in the Mengel formation at the Delhi Field. However, due to the performance of the six existing producing wells as of January 1, 2010, we have not attempted to quantify any upside potential of the water injection project now in progress in the Mengel Sand. There are potential undeveloped drilling locations in the Z Sand in the Delhi Field that were not included because of the SEC guidelines regarding available capital for the implementation of such projects.
(4)	Further, the Company has additional drilling locations in the Marion and Belton Fields that also cannot be valued and included because of the SEC guidelines regarding available capital for the implementation of such projects..

Productive Wells

Productive wells are producing wells or wells capable of production. This does not include water source wells, water injection wells or water disposal wells. Productive wells do not include any wells in the process of being drilled and completed that are not yet capable of production, but does include old productive wells that are currently shut-in, because they are still capable of production. The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2009.

	Total
	Gross		Net
Oil		10		8
Natural Gas		515		515
Total		525		523

Delivery Commitments

We are not obligated to provide a fixed and determinable quantity of oil or natural gas in the near future under existing contracts or agreements. Furthermore, during the last three years we had no significant delivery commitments.

Trademarks and Other Intellectual Property

The Company purchased exclusive North American rights for a non-conventional lateral drilling technology invented by Carl Landers, a Director of the Company from inception. The patents comprising this lateral drilling technology are: US Patent Number 5,413,184 Method and Apparatus for Horizontal Well Drilling , issued May 9, 1995; US Patent Number 5,853,056 Method and Apparatus for Horizontal Well Drilling , issued December 12, 1998; and US Patent Number 6,125,949 Method and Apparatus for Horizontal Well Drilling , issued October 3, 2000. There can be no assurance that these patents and the related technology will perform to the Company’s expectations. Further, there can be no assurance that these patents and related technology do not infringe upon the intellectual property rights of others. On April 16, 2009, the Company sold its Technology Patents to WES Technologies for $250,000, in cash and Promissory Note.

Distribution Methods

Each of our fields that produce oil distributes all of the oil that it produces through one purchaser for each field. We do not have a written agreement with some of these oil purchasers. These oil purchasers pick up oil from our tanks and pay us according to market prices at the time the oil is picked up at our tanks. There is significant demand for oil and there are several companies in our operating areas that purchase oil from small oil producers.

Each of our fields that produce natural gas distributes all of the natural gas that it produces through one purchaser for each field. We have distribution agreements with these natural gas purchasers that provide us a tap into a distribution line of a natural gas distribution company and to be paid for our natural gas at either a market price at the beginning of the month or market price at the time of delivery, less any transportation cost charged by the natural gas distribution company. These charges can range widely from 2 percent to 20 percent or more of the market value of the natural gas depending on the availability of competition and other factors.

Competitive Business Conditions

We encounter competition from other oil and natural gas companies in all areas of our operations. Because of record high prices for oil and natural gas, there are many companies competing for the leasehold rights to good oil and natural gas prospects. And, because so many companies are again exploring for oil and natural gas, there is often a shortage of equipment available to do drilling and workover projects. Many of our competitors are large, well-established companies that have been engaged in the oil and natural gas business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. We may not be able to conduct our operations, evaluate and select properties and consummate transactions successfully in this highly competitive environment.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

Source and Availability of Raw Materials

We have no significant raw materials. However, we make use of numerous oil field service companies in the drilling and workover of wells. We currently operate in areas where there are numerous oil field service and drilling companies that are available to us.

Dependence on One or a Few Customers

There is a ready market for the sale of crude oil and natural gas. Each of our fields currently sells all of its oil production to one purchaser for each field and all of its natural gas production to one purchaser for each field. However, because alternate purchasers of oil and natural gas are readily available at similar prices, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results.

The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues as follows:

	Twelve Months Ended December 31,

	2009			2008

Interconn Resources, Inc. (l)		76	%		62	%

Plains (1)		22	%		24	%

Orchard Petroleum		-			14	%

(1) The Company does not have a formal purchase agreement with these customers, but sells production
on a month-to-month basis at spot prices adjusted for field differentials

Government Regulations

Our facilities in the United States are subject to federal, state and local environmental laws and regulations. Compliance with these provisions has not had, and we do not expect such compliance to have, any material adverse effect upon our capital expenditures, net earnings or competitive position.

Regulation of transportation of oil

Sales of crude oil, condensate, natural gas and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Regulation of transportation and sale of natural gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

The FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on shore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase our costs of getting gas to point of sale locations.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. Such regulations govern conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental, health and safety regulation

Our operations are subject to stringent and complex federal, state, local and provincial laws and regulations governing environmental protection, health and safety, including the discharge of materials into the environment. These laws and regulations may, among other things:

	•	require the acquisition of various permits before drilling commences;
	•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;
	•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
	•	require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.

The following is a summary of the material existing environmental, health and safety laws and regulations to which our business operations are subject.

Waste handling. The Resource Conservation and Recovery Act, or “RCRA”, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or “EPA”, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA”, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, in connection with the release of a hazardous substance into the environment. Persons potentially liable under CERCLA include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance to the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We own and lease, and may in the future operate, numerous properties that have been used for oil and natural gas exploitation and production for many years. Hazardous substances may have been released on, at or under the properties owned, leased or operated by us, or on, at or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been or are operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances were not under our control. These properties and the substances disposed or released on, at or under them may be subject to CERCLA, RCRA and analogous state laws. In certain circumstances, we could be responsible for the removal of previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination. In addition, federal and state trustees can also seek substantial compensation for damages to natural resources resulting from spills or releases.

Water discharges . The Federal Water Pollution Control Act, or the “Clean Water Act”, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and other substances generated by our operations, into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Safe Drinking Water Act, or “SDWA”, and analogous state laws impose requirements relating to underground injection activities. Under these laws, the EPA and state environmental agencies have adopted regulations relating to permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as prohibitions against the migration of injected fluids into underground sources of drinking water.

Air emissions . The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA and certain states have developed and continue to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and analogous state laws and regulations.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has not acted upon recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations.

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or “NEPA”. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All exploration and production activities on federal

lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects on federal lands.

Health safety and disclosure regulation . We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA” and comparable state statutes. The OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and similar state statutes require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations.

We expect to incur capital and other expenditures related to environmental compliance. Although we believe that our compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operation.

ITEM 3. LEGAL PROCEEDINGS

The Company is subject to litigation and claims that have arisen in the ordinary course of business, the majority of which have resulted from its thorough restructuring efforts. Many of these claims have been resolved. Management believes individually such litigation and claims will not have a material adverse impact on our financial position or our results of operations but these matters are subject to inherent uncertainties and management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position and the results of operations for the period in which the effect becomes reasonably estimable.

The following describes legal action being pursued against the Company outside the ordinary course of business:

•

In the suit, Raymond Thomas, et al. vs. Ashley Investment Company, et al., in the 5th Judicial District Court for Richmond Parish, Louisiana, numerous present and former owners of property were seeking damages in an unspecified amount for alleged soil, groundwater and other contamination, allegedly resulting from oil and gas operations of multiple companies in the Delhi Field in Richmond Parish, Louisiana over a time period exceeding fifty years. Originally consisting of 14,000 acres upon discovery of the field in 1952, the Company acquired an interest in leases covering 1,400 acres in 2006. Although the suit was filed in 2005, and was pending when the Company acquired its interest in 2006, as part of the acquisition terms, the Company agreed to indemnify predecessors in title, including its grantor, against ultimate damages related to the prior operations, with the exception of Sun Oil, which is now Anadarko. As part of the Company’s purchase terms, a Site Specific Trust Account was established with the State of Louisiana Department of Natural Resources intended to provide funds for remediation of the lands involved in its acquired interest. The lawsuit was settled in June 2009 with the Company being required to complete the remediation of the alleged damages. To that time, the Company had spent $750,000 on legal fees and remediation. Subsequently, the Company incurred and paid an additional $500,000 in clean-up costs. At December 31, 2009, the Company accrued $89,092 for remaining remediation costs. The Company does not anticipate additional remediation costs

•

Vanguard Energy Services sued for $340,000 for use of their drilling rigs in 2006 and 2007. The Company has settled the claims to include two sister Companies, Recompletion Finance Corporation and Edge Capital. Each party was mutually released. The lawsuit was settled with a cash obligation of $160,000 and 500,000 shares of common stock.

•

In the suit, LFU Fort Pierce, Inc. d/b/a Labor Finders, our subsidiary Tiger Bend Drilling was sued for $284,988. This has been expensed in 2007 and is reflected in our accounts payable in 2009 and 2008. In connection with this suit, an additional 25% attorney fees and interest are owed and have been accrued at December 31, 2009.

•

The law firm Maloney Martin & Mitchell is seeking payment for services rendered with regards to the GEF/ South Belridge settlement. At this point the amount and probability of payment is not determinable.

•

In a suit with Pannell Kerr Forster of Texas PC (AKA PKF Texas) and PKF (UK) LLP were seeking payment for services rendered. We retained an expert witness in this field to opine on what the Company was charged and the ethics associated with PKF’s performance. This lawsuit was settled for a sum of $281,818, payable in 24 monthly installments. If the Company defaults on monthly installment, the entire outstanding balance of $563,636 becomes due.

•

During 2009, Dougherty Trucking Service, et al filed liens against the Mud River property for non payment for services rendered. In 2010, Dougherty Trucking Services,et al were paid in full and all liens were released.

•

During 2009, a former employee filed a claim with the Texas Workforce Commission for back wages and severance pay. The Texas Workforce Commission awarded $284,166 to be paid on behalf of the former employee and the wages and severance pay were accrued at December 31, 2009.

ITEM 4 SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS

The following matters approved by the security holders at the June 24, 2009 annual meeting

•

Election of Board of Directors – Robert D. Johnson, Robert C. Johnson, Harvey Pensack.

•

Name Change from Maxim TEP, Inc. to Conquest Petroleum Incorporated.

•

Revise Corporate Structure to Eliminate Subsidiaries.

•

Review the Financial Status of the Company. Authorize the Board of Directors to take any action they deem fit to provide for the survival of the Company to include; but, not limited to:

•

Reverse 10 to 1 Split of Common Stock

•

Merger

•

Sale of Substantially all of the Company’s assets

Pursuant to the bylaws of the Company, the Board of Directors has the sole and complete authority on all other financial matters, including bankruptcy.

ITEM 5 MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Not Applicable

ITEM 6 SELECTED FINANCIAL DATA

Not Applicable

ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this Annual Report. Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.

The following is management’s discussion and analysis of certain significant factors that have affected certain aspects of the Company’s financial position and results of operations during the periods included in the accompanying audited consolidated financial statements. You should read this in conjunction with the discussion under “Financial Information” and the audited consolidated financial statements included in the Company’s Annual Report on Form 10-K, for the years ended December 31, 2009 and 2008 and the unaudited consolidated financial statements included elsewhere herein.

Forward Looking Statements

This Annual Report on Form 10-K contains forward-looking statements concerning our beliefs, plans, objectives, goals, expectations, anticipations, estimates, intentions, operations, future results and prospects, including statements that include the words “may,” “could,” “should,” “would,” “believe,” “expect,” “will,” “shall,” “anticipate,” “estimate,” “intend,” “plan” and similar expressions. These forward-looking statements are based upon current expectations and are subject to risk, uncertainties and assumptions. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, estimated, expected, projected, intended, committed or believed. We provide the following cautionary statement identifying important factors (some of which are beyond our control) which could cause the actual results or events to differ materially from those set forth in or implied by the forward-looking statements and related assumptions.

General Overview

We are an independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties geographically focused on the onshore United States. The Company’s operational focus is the acquisition, through the most cost effective means possible, of production or near production oil and natural gas field assets. Our areas of operation include Louisiana and Kentucky.

Going Concern

As presented in the consolidated financial statements, the Company has incurred a net loss of $23,262,729 during the twelve months ended December 31, 2009, and losses are expected to continue in the near term. Current liabilities exceeded current assets by $17,951,298 and the accumulated deficit is $118,536,343 at December 31, 2009. Amounts outstanding and payable to creditors are in arrears and the Company is in negotiations with certain creditors to obtain extensions and settlements of outstanding amounts. The Company is currently in default on most of its debt obligations and the Company has no future borrowings or funding sources available under existing financing arrangements. Management anticipates that significant additional capital expenditures will be necessary to develop the Company’s oil and natural gas properties, which consist primarily of proved reserves that are non-producing, before significant positive operating cash flows will be achieved.

Management's plans to alleviate these conditions include the renegotiation of certain trade payables, settlements of debt amounts with stock, deferral of certain scheduled payments, and sales of certain non-core properties, as considered necessary. In addition, management is pursuing business partnering arrangements for the acquisition and development of its properties as well as debt and equity funding through private placements. Without outside investment from the sale of equity securities, debt financing or partnering with other oil and natural gas companies, operating activities and overhead expenses will be reduced to a pace that available operating cash flows will support.

The accompanying consolidated financial statements are prepared as if the Company will continue as a going concern. The consolidated financial statements do not contain adjustments, including adjustments to recorded assets and liabilities, which might be necessary if the Company were unable to continue as a going concern.

Results of Operations

Twelve Months Ended December 31, 2009 Compared to the Twelve Months Ended December 31, 2008

Oil and Natural Gas Revenues: Oil and natural gas revenues for the twelve months ended December 31, 2009 and 2008 were $905,781 and $1,822,893, respectively, a decrease of 50.03%. This decrease was attributed to oil and gas prices being higher in 2008 and production in fields was limited due to lack of funds for drilling.

License Fees, Royalties & Related Service Revenue: License fees, royalties and related services for the twelve months ended December 31, 2009 and 2008 were $9,000 and $163,458, respectively. The Company sold it technology to a third party during the second quarter of 2009 and does not anticipate revenue relating to license fees.

Production and Lease Operating Expenses: Production and lease operating expenses for the twelve months ended December 31, 2009 and 2008 were $1,365,878 and $1,295,693, respectively, an increase of 5.1%. This increase in expenses is due to funding received in the third and fourth quarter to begin substantial workover on wells in the Delhi fields.

Drilling Operating Expenses: Drilling operating expenses for the twelve months ended December 31, 2009 and 2008 were nill and $4,628, respectively. The drilling Company sold its drilling rigs in 2006 and now only leases a rig and sub-contracts a crew for short periods of time when drilling wells for its own account and will not provide any drilling services to third parties.

Depletion, Depreciation and Amortization: Depletion, depreciation, and amortization for the twelve months ended December 31, 2009 and 2008 were $1,368,758 and $1,993,100, respectively, a decrease of 624,342. The decrease was due to the decrease in depletion and depreciation of the reserve basis in the Marion and Belton fields.

Impairment of Oil and Natural Gas Properties. Impairment of oil and natural gas properties for 2009 and 2008 was $4,913,349 and $5,291,298, respectively.

General and Administrative Expense: General and administrative expenses for the twelve months ended December 31, 2009 and 2008 were $12,992,340 and $12,066,402, respectively. This net increase of $925,938 reflects non-cash expenses for compensation of $3,990,386 and $6,141,610 for third party services.

Interest Expense, net: Interest expense, net for the twelve months ended December 31, 2009 and 2008 was $3,376,308 and $2,222,429, respectively. Interest expense increased due to amortization on discounts on debt in 2009.

Gain From Discontinued Operations: During April 2008, the Company sold its South Belridge Field in a three party transaction that involved Mercuria Partners, a majority shareholder in Orchard Petroleum, and Conquest TEP, PLC as an all inclusive deal to eliminate all debt, joint interest rights and obligations amongst all three parties, for a cash consideration of $35,781,654 and the issuance of 2,170,000 shares of common stock of the Company issued to Conquest TEP, PLC. The total field sales price plus the additional debt relieved resulted in total consideration of $43,477,199. The net cost basis of the field at the time of closing was $4,366,422. In addition, the Company incurred additional expenses of $16,275,000 from the issuance of common stock at $0.75 per share. This amounted to a gain of $20,823,141.

Income Taxes: There is no provision for income tax recorded for either the 2009 or 2008 periods due to operating losses in both periods. The Company has available Federal income tax net operating loss (“NOL”) carry forwards of approximately $35 million at December 31, 2009. The Company’s NOL generally begins to expire in 2024. The Company recognizes the tax benefit of NOL carry forwards as assets to the extent that management believes that the realization of the NOL carry forward is more likely than not. The realization of future tax benefits is dependent on the Company’s ability to generate taxable income within the carry forward period. This valuation allowance is provided for all deferred tax assets.

Net Loss: The Company had net loss for the twelve months ended December 31, 2009 of $23,262,729 and a net loss of $6,029,503 for the same period in 2008 specifically due to reasons discussed above.

Liquidity and Capital Resources

The global financial and credit crisis may have impacts on our liquidity and financial condition that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system may have a material impact on our liquidity and our financial condition, and we may ultimately face major challenges if conditions in the financial markets do not improve. Our ability to access the capital markets or borrow money may be restricted at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Additionally, the current economic situation could lead to reduced demand for natural gas and oil, or further reductions in the prices of natural gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.

At December 31, 2009, the Company had a working capital deficit of $17,951,298 compared to a working capital deficit of $11,397,281 at December 31, 2008. Current liabilities increased to $18,191,546 at December 31, 2009 from $11,714,205 at December 31, 2008 primarily due to new loans from third parties in the third and fourth quarter of 2009 and balloon payments owed related to these loans.

Net cash used in operating activities totaled $3,030,792 and $964,344 for the twelve months ended December 31, 2009 and 2008, respectively. Net cash used in operating activities for the 2009 period consists primarily of the net loss from continuing operations of $23, 262,729.

Net cash used in investing activities totaled $130,417 for the twelve months ended December 31, 2009, compared to cash used of $1,341,505 for the twelve months ended December 31, 2008. Net cash provided by investing activities for the 2009 period consists primarily of proceeds from sale of fixed assets offset by the purchase of fixed assets.

Net cash provided by financing activities totaled $3,183,520 for the twelve months ended December 31, 2009, compared to $2,198,265 for the twelve months ended December 31, 2008. Net cash provided by financing activities for the 2009 period consists of funds provided by BlueRock for the Marion Field Expenses and other borrowings.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that we are required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on the operating activities of the Company.

Recently Issued Accounting Pronouncements

Recent Accounting Pronouncements

In October 2009, the FASB issued new revenue recognition standards for arrangements with multiple deliverables, where certain of those deliverables are non-software related. The new standards permit entities to initially use management’s best estimate of selling price to value individual deliverables when those deliverables do not have Vendor Specific Objective Evidence of fair value or when third-party evidence is not available. Additionally, these new standards modify the manner in which the transaction consideration is allocated across the separately identified deliverables by no longer permitting the residual method of allocating arrangement consideration. These new standards are effective for annual periods ending after June 15, 2010 and early adoption is permitted. The Company is currently evaluating the impact of adopting this standard on the Company’s consolidated financial position, results of operations and cash flows.

In June 2009, the FASB issued guidance establishing the ASC as the source of authoritative U.S. Generally Accepted Accounting Principles (“U.S. GAAP”) recognized by the FASB to be applied by non-governmental entities. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. The Codification supersedes all existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. The FASB will no longer issue new standards in the form of Statements, FASB Staff Positions or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the Codification, provide background information about the guidance and provide the bases for conclusions on changes in the Codification. All content in the Codification carries the same level of authority, and the U.S. GAAP hierarchy was modified to include only two levels of U.S. GAAP: authoritative and non-authoritative. The Codification is effective for the Company’s interim and annual periods beginning with the Company’s year ending December 31, 2009. Adoption of the Codification affected disclosures in the Consolidated Financial Statements by eliminating references to previously issued accounting literature, such as SFASs, EITFs and FSPs.

In June 2009, the FASB issued amended standards for determining whether to consolidate a variable interest entity. These new standards amend the evaluation criteria to identify the primary beneficiary of a variable interest entity and require ongoing reassessment of whether an enterprise is the primary beneficiary of the variable interest entity. The provisions of the new standards are effective for annual reporting periods beginning after November 15, 2009 and interim periods within those fiscal years. The adoption of the new standards will not have an impact on the Company’s consolidated financial position, results of operations and cash flows.

In May 2009, the FASB issued guidance establishing general standards for accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued and shall be applied to subsequent events not addressed in other applicable generally accepted accounting principles. This guidance, among other things, sets forth the period after the balance sheet date during which management should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and the disclosures an entity should make about events or transactions that occurred after the balance sheet date. The adoption of this guidance had no impact on the Company’s consolidated financial position, results of operations and cash flows

Summary of Critical Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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 periods reported. Actual results could differ from these estimates.

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of proved and unproved properties, future income taxes and related assets and liabilities, the fair value of various common stock, warrants and option transactions, and contingencies. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the calculation of impairment, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data, the engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

These significant estimates are based on current assumptions that may be materially effected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the fair value of the Company’s common stock and corresponding volatility, and the Company’s ability to generate future taxable income. Future changes to these assumptions may affect these significant estimates materially in the near term.

Oil and Natural Gas Properties

We account for investments in natural gas and oil properties using the successful efforts method of accounting. Under this method of accounting, only successful exploration costs that directly result in the discovery of proved reserves are capitalized. Unsuccessful exploration costs that do not result in an asset with future economic benefit are expensed. All development costs are capitalized because the purpose of development activities is considered to be building a producing system of wells, and related equipment facilities, rather than searching for oil and gas. Items charged to expense generally include geological and geophysical costs. Capitalized costs of proved properties are depleted on a field-by-field (Common Reservoir) basis using the units-of-production method based upon proved, producing oil and natural gas reserves.

The net capitalized costs of proved oil and natural gas properties are subject to an impairment test based on the undiscounted future net reserves from proved oil and natural gas reserves based on current economic and operating conditions. Impairment of an individual producing oil and natural gas field is first determined by comparing the undiscounted future net cash flows associated with the proved property to the carring value of the underlying property. If the cost of the underlying property is in excess of the undiscounted future net cash flows the carrying cost of the impaired property is compared to the estimated fair value and the difference is recorded as an impairment loss. Management’s estimate of fair value takes into account many factors such as the present value discount rate, pricing, and when appropriate, possible and probable reserves when justified by economic conditions and actual or planned drilling or other development activities.

Under the successful efforts method of accounting, the depletion rate is the current period production as a percentage of the total proved producing reserves. The depletion rate is applied to the net book value of property costs to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income.

We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.

Long-lived Assets and Intangible Assets

The Company accounts for intangible assets in accordance with the provisions of the applicable FASB standard. Intangible assets that have defined lives are subject to amortization over the useful life of the assets. Intangible assets held having no contractual factors or other factors limiting the useful life of the asset are not subject to amortization but are reviewed at least annually for impairment or when indicators suggest that impairment may be needed. Intangible assets are subject to impairment review at least annually or when there is an indication that an asset has been impaired. As of December 31, 2008, the Company determined that due to the worsened financial markets and oil and gas industry, full impairment of its patented lateral drilling technology was necessary. While there are prospects for possible capital funding (either debt or equity), much is left to the market and outside instability. As such, at this time, management cannot anticipate with a comfortable degree of certainty if the appropriate amount of funding will be achieved and any funding will be diverted fully to its E&P activities. This will further postpone the Company’s ability to dedicate financial as well as human resources to its technology division in the short term future. As such, the Company has eliminated the division entirely.

For unproved property costs, management reviews these investments for impairment on a property-by-property basis if a triggering event should occur that may suggest that an impairment may be required.

The Company reviews its long-lived assets and proved oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable in accordance with the applicable FASB standard. Proved oil and gas assets are evaluated for impairment at least annually. If the carrying amount of the asset, including any intangible assets associated with that asset, exceeds its estimated future undiscounted net cash flows, the Company will recognize an impairment loss equal to the difference between its carrying amount and its estimated fair value. The fair value used to calculate the impairment for a producing oil and natural gas field that produces from a common reservoir is first determined by comparing the undiscounted future net cash flows associated with total proved properties to the carrying value of the underlying evaluated property. If the cost of the underlying evaluated property is in excess of the undiscounted future net cash flows, the future net cash flows discounted at 10%, which the Company believes approximates fair value, to determine the amount of impairment.

Stock based compensation

Beginning January 1, 2006, the Company adopted the FASB standard related to stock compensation to account for its Incentive Compensation Plan (the “2005 Incentive Plan”). The standard requires all share-based payments to employees (which includes non-employee Board of Directors), including employee stock options, warrants and restricted stock, be measured at the fair value of the award and expensed over the requisite service period (generally the vesting period). The fair value of common stock options or warrants granted to employees is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of comparable public companies. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock option or warrant, the dividend yield and the risk-free interest rate.

Under the 2005 Incentive Plan, the Company from time to time may issue stock options, warrants and restricted stock to acquire goods or services from third parties. Restricted stock, options or warrants issued to other than employees or directors are recorded on the basis of their fair value, which is measured as of the date issued. In accordance with the standard, the options or warrants are valued using the Black-Scholes option pricing model on the basis of the market price of the underlying equity instrument on the “valuation date,” which for options and warrants related to contracts that have substantial disincentives to non-performance, is the date of the contract, and for all other contracts is the vesting date. Expense related to the options and warrants is recognized on a straight-line basis over the shorter of the period over which services are to be received or the vesting period.

Earnings per share

Basic earnings per share is computed using the weighted average number of common shares outstanding. Diluted earnings per share reflects the potential dilutive effects of common stock equivalents such as options, warrants and convertible securities. Due to the Company incurring a net loss from continuing operations, basic and diluted loss per share are the same for the years ended December 31, 2009 and 2008 as all potentially dilutive common stock equivalents are anti-dilutive.

Income Taxes

Under the applicable FASB standard, deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. We routinely assess the reliability of our deferred tax assets. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.

Contingencies

Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.

Volatility of Oil and Natural Gas Prices

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.

ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Table of Contents

		Page
PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements	2

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Controls and Procedures	27

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings	27

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28

Item 3.	Default Upon Senior Securities	29

Item 4.	Submission of Matters to a Vote of Security Holders	29

Item 5.	Other Information	29

Item 6.	Exhibits	29

SIGNATURES		30

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Stockholders of Conquest Petroleum Incorporated

We have audited the accompanying consolidated balance sheets of Conquest Petroleum Incorporated (formerly Maxim TEP, Inc.) (the “Company”) as of December 31, 2009 and 2008 and the related consolidated statements of operations, cash flows and stockholders’ deficit for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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 audits 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 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.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has insufficient working capital and reoccurring losses from operations, all of which raises substantial doubt about its ability to continue as a going concern. Management's plans regarding those matters also are described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Conquest Petroleum Incorporated as of December 31, 2009 and 2008, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

As discussed in Note 11 to the financial statements, the 2009 financial statements have been restated to correct a misstatement in the footnotes to the financial statements related to the unaudited Note 9, Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities.

/s/ M&K CPAS, PLLC
www.mkacpas.com
Houston, Texas
May 17, 2010, except for Note 11, as to which the date is July 30, 2010

PART I—FINANCIAL INFORMATION

Item 1.Financial Statements

Conquest Petroleum Incorporated

Consolidated Balance Sheets

As of December 31, 2009 and 2008

	December 31,			December 31,
	2009			2008

Assets
Current assets:
Cash and cash equivalents	$	89,813		$	67,502
Accounts receivable		27,351			163,745
Other receivable		32,464			64,633
Prepaid expenses and other current assets		90,620			21,044

Total current assets		240,248			316,924

Oil and natural gas properties (successful efforts method of accounting):
Proved		4,194,381			8,170,937
Unproved		172,796			1,125,919
		4,367,177			9,296,856

Less accumulated depletion, depreciation and amortization		(3,035,497	)		(1,829,365	)

Oil and natural gas properties, net		1,331,680			7,467,491

Property and equipment:
Land		112,961			112,961
Buildings		215,445			215,445
Property improvements		244,025			244,025
Office equipment and computers		31,489			82,337
Furniture and fixtures		22,937			211,581
Field service vehicles and equipment		484,782			729,743
Drilling equipment		137,600			174,082
Total property and equipment		1,249,239			1,770,174
Less accumulated depreciation		(409,798	)		(474,744	)
Property and equipment, net		839,441			1,295,430

Other assets		540,802			489,176
Restricted cash		-			250,170
Total assets	$	2,952,171		$	9,819,191

Conquest Petroleum Incorporated

Consolidated Balance Sheets (Continued)

	December 31,			December 31,
	2009			2008

Liabilities and Stockholders’ Deficit

Current liabilities:
Accounts payable	$	2,530,614		$	3,276,127
Interest payable		921,301			605,934
Accrued payroll and related taxes and benefits		944,375			1,691,710
Accrued liabilities		695,902			1,039,995
Derivative liability		107,425			-
Production payment payable, current		7,853,620			3,607,570
Current maturity of notes payable, net of discount		4,413,309			689,518
Current maturities of convertible notes payable, related parties, net of discount		725,000			803,350

Total current liabilities		18,191,546			11,714,204

Production payment payable, long-term		-			2,834,520
Deferred revenue		60,000			65,000
Asset retirement obligation		1,923,883			1,840,641

Total liabilities		20,175,429			16,454,365


Stockholders’deficit:
Preferred stock, $0.00001 par value; 50,000,000 shares
authorized; 545,454 and 545,454 shares issued and outstanding at December 31, 2009 and December 31, 2008, respectively		5			5
Common stock, $0.00001 par value; 250,000,000 shares
authorized;39,545,867and 12,785,987 shares issued and 39,545,028 and 12,743,027 shares outstanding at December 31, 2009 and December 31, 2008, respectively		395			128
Stock payable		2,264,093			1,436,880
Stock held in escrow		(5,100,800	)		-
Additional paid-in capital		104,149,392			87,523,630
Accumulated deficit		(118,536,343	)		(95,273,614	)
Treasury stock, at cost (839 and 42,960 shares held at
December 31, 2009 and December 31, 2008, respectively)		-			(322,203	)

Total stockholders’ deficit		(17,223,258	)		(6,635,174	)

Total liabilities and stockholders’ deficit	$	2,952,171		$	9,819,191

See accompanying notes to consolidated financial statements

Conquest Petroleum Incorporated

Consolidated Statements of Operations

For The Years Ended December 31, 2009 and 2008

	Years Ended December 31,
	2009			2008
Revenues:
Oil and natural gas revenues	$	905,781		$	1,822,893

License fees, royalties and related services		9,000			163,458

Total revenues		914,781			1,986,351

Cost and expenses:
Production and lease operating expenses		1,365,878			1,295,693
Drilling operating expenses		-			4,628
Costs attributable to license fees and related services		-			132,202
Depletion, depreciation and amortization		1,368,758			1,993,100
Revenue sharing royalties		1,647			145,583
Impairment of investments		-			42,808
Impairment of oil and natural gas properties		4,913,349			5,291,298
Environmental remediation costs		-			457,548
Accretion of asset retirement obligation		60,469			129,010
General and administrative expenses		12,992,340			12,066,402

Total cost and expenses		20,702,441			21,558,272

Loss from operations		(19,787,660	)		(19,571,921	)

Other income (expense):
Gain on settlement of debt		-			400,000
Impairment of LHD patent technology		-			(4,034,989	)
Interest expense, net		(3,376,308	)		(2,222,429	)
Gain on sale of assets		21,240			602,879
Gain/(loss) on settlement		100,000			(1,368,000	)
Change in value of derivative		(107,425	)		-
Interest Income		8,466			45,417
Other miscellaneous income (expense), net		(121,042	)		(703,601	)

Total other income (expense), net		(3,475,069	)		(7,280,723	)

Net loss before discontinued operations		(23,262,729	)		(26,852,644	)

Gain (loss) from discontinued operations		-			20,823,141

Net loss	$	(23,262,729	)	$	(6,029,503	)

Net Income per share from discontined operations
Basic and diluted	$	-		$	1.82

Net loss per common share from continuing operations
Basic and diluted	$	(1.13	)	$	(2.34	)

Total Net loss per common share
Basic and diluted	$	(1.13	)	$	(0.52	)

Weighted average common shares outstanding:
Basic and diluted		20,535,343			11,493,956

See accompanying notes to consolidated financial statements

Conquest Petroleum Incorporated

Consolidated Statements of Stockholders’ Deficit

For the Years Ended December 31, 2009 and 2008

									Additional							Stock					Total
	Preferred Stock				Common Stock				Paid-In				Accumulated			Held In		Treasury			Stockholders’
	Shares		Amount		Shares		Amount		Capital		Stock Payable		Deficit			Escrow		Stock			Deficit
Balance at December 31, 2007		0	$	-		8,560,452	$	86	$	50,478,025		-	$	(89,244,111	)		-	$	-			(38,766,000	)

Common stock issued for cash		-	$	-		132,080	$	1		990,588		-		-			-		-			990,589

Common stock issued with note payable attached		-	$	-		90,000	$	1		510,008		-		-			-		-			510,009

Common stock issued for services, nonemployee		-	$	-		51,000	$	-		382,500		-		-			-		-			382,500

Common stock issued for services, employee		-	$	-		967,754	$	10		7,258,148		-		-			-		-			7,258,158

Common stock issued in connection with sale of net revenue interests		-		-		90,000	$	1		675,000		-		-			-		-			675,001

Common stock issued upon the conversion of debt and accrued interest, related party		-	$	-		719,979	$	7		5,085,657		-		-			-		-			5,085,664

Common stock issued upon the conversion of debt and accrued interest		-	$	-		2,172,222	$	22		16,291,646		-		-			-		-			16,291,668

Common stock issued for oil and natural gas property, related party		-		-		2,500		-		18,750		-		-			-		-			18,750

Common stock warrants issued to extend notes payable terms		-		-		-		-		8,735		-		-			-		-			8,735

Common stock warrants issued in connection with notes payable, related party		-		-		-		-		83,317		-		-			-		-			83,317
Common stock warrants issued in connection with notes payable				-		-		-		143,891		-		-			-		-			143,891

Common stock warrants issued to extend notes payable terms, related party		-		-		-		-		6,238		-		-			-		-			6,238

Common stock warrants issued in connection with sale of net revenue interests		-		-		-		-		103,267		-		-			-		-			103,267

Common stock options issued to non-employee directors for services		-		-		-		-		393,448		-		-			-		-			393,448

Common stock options issued to employees for services		-		-		-		-		863,185		-		-			-		-			863,185

Common stock warrans granted to employees for services		-		-		-		-		41,972		-		-			-		-			41,972

Common stock warrants granted for put extension		-		-		-		-		17,186		-		-			-		-			17,186

Beneficiary conversion feature in connection with convertible note payable, related party		-		-		-		-		29,549		-		-			-		-			29,549

Preferred Stock issued associated with debt conversion, related party		227,272		2		-		-		1,322,829		-		-			-		-			1,322,831

Preferred Stock issued associated with debt conversion		318,182		3		-		-		2,386,361		-		-			-		-			2,386,364

Expiration of common stock put options		-		-		-		-		433,330		-		-			-		-			433,330

Common stock Equity Obligation		-		-		-		-		-		1,436,880		-			-		-			1,436,880
																						0
Treasury stock purchased for note receivable		-		-		-		-		-		-		-			-		(322,203	)		(322,203	)
																						0
Net loss		-		-		-		-		-		-		(6,029,503	)		-		-			(6,029,503	)

Balance at December 31, 2008		545,454	$	5		12,785,987	$	128	$	87,523,630	$	1,436,880	$	(95,273,614	)	$	-	$	(322,203	)	$	(6,635,174	)

Conquest Petroleum Incorporated

Consolidated Statements of Stockholders’ Deficit

For the Years Ended December 31, 2009 and 2008

									Additional								Stock					Total
	Preferred Stock				Common Stock				Paid-In					Accumulated			Held In			Treasury		Stockholders’
	Shares		Amount		Shares		Amount		Capital		Stock Payable			Deficit			Escrow			Stock		Deficit

Rounding to difference due to stock split		-		-		133		-		-		-			-			-			-		-

Common stock issued for services, employees		-		-		6,150,846		61		3,923,720		-			-			-			-		3,923,781

Common stock issued for services, non-employees		-		-		1,996,634		20		3,703,085		-			-			-			-		3,703,105

Common stock issued for note conversion, related party		-		-		1,242,128		12		169,965		-			-			-			-		169,977

Common stock issued for note conversion		-		-		2,025,000		20		303,730		-			-			-			-		303,750
																							-
Common stock issued to escrow related to N/P		-		-		5,000,000		50		4,619,950		-			-			(4,620,000	)		-		-
																							-
N/P issued with stock attached		-		-		1,200,000		12		359,988		-			-			-			-		360,000

Common stock issued to convert accounts payable		-		-		100,000		1		14,609		-			-			-			-		14,610

Common stock issued for accrued payroll		-		-		5,999,407		60		814,355		-			-			-			-		814,415

Shares issued for anti-dilution clause		-		-		3,045,732		31		546,573		-			-			-			-		546,604

Common stock options granted to employees for services		-		-		-		-		66,605		-			-			-			-		66,605

Common stock warrants granted for services		-		-		-		-		38,005		-			-			-			-		38,005

Treasury stock issued for services and stock payable		-		-		-		-		2,065,177		(686,880	)		-			-			322,203		1,700,500

Shares owed due to anity-dilution clause on note payable agreement		-		-		-		-		-		784,093			-			(480,800	)		-		303,293

Shares owed for lawsuit settlement		-		-		-		-		-		30,000			-			-			-		30,000

Shares owed for consulting agreement		-		-		-		-		-		700,000			-			-			-		700,000

Net loss		-		-		-		-		-		-			(23,262,729	)		-			-		(23,262,729	)

Balance at December 31, 2009		545,454	$	5		39,545,867	$	395	$	104,149,392	$	2,264,093		$	(118,536,343	)	$	(5,100,800	)	$	-	$	(17,223,258	)

See notes to consolidated financial statements.

Conquest Petroleum Incorporated

Consolidated Statements of Cash Flows

For the Years Ended December 31, 2009 and 2008

	Years Ended December 31,
	2009			2008
Cash flows from continuing operating activities:
Net income (loss)	$	(23,262,729	)	$	(6,029,503	)
Net income from discontinued operations		-			(20,823,141	)
Net loss for continuing operations	$	(23,262,729	)	$	(26,852,644	)
Adjustments to reconcile net loss from continuing operations to net cash
used in operating activities:
Depletion, depreciation and amortization		1,356,884			1,993,100
Accretion of asset retirement obligation		60,469			129,010
Gain on extinguishment of debt		-			(400,000	)
Gain on lawsuit settlement		(100,000	)
Loss on sale of assets		136,869			-
Impairment of oil and gas property		4,913,349			5,291,298
Impairment of LHD patent technology		-			4,034,989
Amortization of debt discount, related party		30,308			1,475
Amortization of debt discount		1,389,386			521,877
Amortization of deferred financing costs		11,874			61,638
Write off drilling on unproved property		283,100			-
Change in fair value of derivative liabilities		107,425			-
Common stock owed for services		700,000			-
Common stock owed due to anti-dilution clausein N/P agreement		303,293			-
Common stock issued related to anti-dilution clause		546,604			-
Common stock issued for services, non employees		3,703,105			-
Common stock warrants issued for services		38,005			-
Treasury stock issued for services		1,700,500			-
Options issued for services		66,605			-
Common stock issued for services, employees		3,923,781			11,068,330
Bad debt expense		16,000			42,808
Loss on note settled with preferred stock		-			543,722
Gain on sale of overriding royalty interest		-			(421,733	)
Gain on sale of fixed assets		(21,240	)		-
Changes in operating assets and liabilities, net of effects of
acquisitions and divestitures:
Accounts receivable		152,563			(211,808	)
Prepaid expenses and other current assets		117,094			(170,372	)
Accounts payable and accrued expenses		800,963			3,463,966
Other current liabilities		-			(60,000	)
Deferred revenue		(5,000	)		-

Net cash used in operating activities		(3,030,792	)		(964,344	)

Cash flows from investing activities:

Acquisitions of oil and gas property		-			(582,799	)
Cash paid for purchase of oil and gas assets		(8,752	)		-
Cash paid for purchase of fixed assets		(262,639	)		(50,359	)
Proceeds from sale of fixed assets		115,974			-
Proceeds from disposition of oil & gas properties		25,000			1,282,931
Proceeds from sale of net revenue interests and sharing agreements		-			675,000
Proceeds from sale of other assets		-			16,732

Net cash provided by investing activities		(130,417	)		1,341,505
Cash flows from financing activities:

Proceeds from borrowings on production payable		548,828
Proceeds - issuance of notes payable		2,625,000			400,000
Principal payments on notes payable		(45,308	)		-
Proceeds - issuance of notes payable - related parties		55,000			450,000
Principal payments on notes payable - related parties		-			(2,333	)
Proceeds - issuance of common stock		-			1,350,598

Common stock offering costs
Net cash provided by financing activities		3,183,520			2,198,265

See notes to consolidated financial statements.

	For the Years Ended December 31
	2009		2008

Net cash used in discontinued operations		-		(2,695,266	)

(Decrease)/Increase cash equivalents		22,311		(119,840	)

Cash and cash equivalents - beginning of year		67,502		187,342

Cash and cash equivalents - end of year	$	89,813	$	67,502

Supplementary cash flow information:
Cash paid for interest	$	-	$	248,097

Non-cash investing and financing activities:
Notes payable and accrued interest exchanged for oil and gas properties		-		8,267,685
Reserve report revisions to asset retirement obligations		22,773		(579,879	)
Discount recorded on debt with attached warrants		-		242,180
Common stock issued for the purchase of oil and gas properties		-		18,750
Beneficial conversion feature on related party notes payable		-		50,537
Common stock issued upon expiration of put options		-		433,330
Sale of oil and gas properties for related parties		-		6,128,398
Common stock issued to convert accounts payable		14,610		-
Common stock issued to convert notes payable		303,750		-
Common stocvk issued to convert notes payable, related party		169,977		-
Common stock issued to convert accrued payroll		814,415		-
Common stock issued to escrow due to notes payable agreement		4,620,000		-
Treasury stock issued for stock payable		686,880		-
Accounts payable converted to notes payable		414,713		-

See notes to consolidated financial statements.

Conquest Petroleum Incorporated and Subsidiaries

Notes to the Consolidated Financial Statements

Note 1 –

Financial Statement Presentation

Organization and nature of operations

CONQUEST PETROLEUM INCORPORATED, formerly Maxim TEP, Inc. was formed in 2004 as a Texas corporation to acquire, develop, produce and exploit oil and natural gas properties. The Company’s major oil and natural gas properties are located in Louisiana, and Kentucky. The Company’s executive offices are located in Spring (Houston), Texas. At the annual shareholder’s meeting in June, 2009, the shareholders approved the change of Maxim TEP, Inc. to Conquest Petroleum Incorporated to more closely identify the Company as an independent oil and gas company and approved a 10-for-1 reverse stock split. On August 5, 2009, after approval from the regulatory agencies, the name change to Conquest Petroleum Incorporated and the 10-for-1 reverse stock split became effective. In connection with the 10-for-1 reverse stock split and name change, the new trading symbol has been changed from (OTCBB: MTIM) to (OTCBB: CQPT).

Going concern

Note 2 –

Summary of Significant Accounting Policies

Principles of consolidation

The accompanying consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles. The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances. The consolidated financial statements reflect necessary adjustments, all of which were of a recurring nature and are in the opinion of management necessary for a fair presentation.

Property and equipment

Property and equipment are recorded at cost. Cost of repairs and maintenance are expensed as they are incurred. Major repairs that extend the useful life of equipment are capitalized and depreciated over the remaining estimated useful life. When property and equipment are sold or otherwise disposed, the related costs and accumulated depreciation are removed from the respective accounts and the gains or losses realized on the disposition are reflected in operations. The Company uses the straight-line method in computing depreciation for financial reporting purposes.

Derivative Instruments

We have evaluated Topic Number 815 in determining whether the Company has a derivative related to warrants issued in the quarter ended December 31, 2009. The literature applies to the Company for certain freestanding warrants that contain exercise price adjustment features known as down round provisions. Based on the guidance we have concluded these instruments are required to be accounted for as derivatives effective upon issuance of the warrants in 2009.

We have recorded the fair value of the warrants and preferred stock that are classified as derivative liabilities in our balance sheet at fair value with changes in the value of these derivatives reflected in the consolidated statements of operations as gain or loss on derivative liabilities. These derivative instruments are not designated as hedging instruments.

The derivatives have been valued upon issuance and on the balance sheet date using the Black-Scholes model. This valuation is outlined in more detail in the following note “Fair Value of Financial Instruments”.

Revenue Recognition

The Company recognizes oil, gas and natural gas condensate revenue in the period of delivery. Settlement on sales occur anywhere from two weeks to two months after the delivery date. The Company recognizes revenue when an arrangement exists, the product has been delivered, the sales price is fixed or determinable, and collectability is reasonably assured.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, other assets, fixed assets, derivative liability, deferred revenue, accounts payable, accrued liabilities and short-term debt. The estimated fair value of cash, accounts receivable, other assets, accounts payable, deferred revenue and accrued liabilities approximated their carrying amounts due to the short-term nature of these instruments. The carrying value of short-term debt also approximates fair value since their terms are similar to those in the lending market for comparable loans with comparable risks. None of these instruments are held for trading purposes.

The Company utilizes various types of financing to fund its business needs, including debt with warrants attached and other instruments indexed to its stock. The Company reviews its warrants and conversion features of securities issued as to whether they are freestanding or contain an embedded derivative and if so, whether they are classified as a liability at each reporting period until the amount is settled and reclassified into equity with changes in fair value recognized in current earnings. At December 31, 2009, the Company has 1,500,000 warrants to purchase common stock, the fair values of which are classified as a liability.

Inputs used in the valuation to derive fair value are classified based on a fair value hierarchy which distinguishes between assumptions based on market data (observable inputs) and an entity’s own assumptions (unobservable inputs). The hierarchy consists of three levels:

•		Level one – Quoted market prices in active markets for identical assets or liabilities;
•		Level two - Inputs other than level one inputs that are either directly or indirectly observable; and

•

Level three – Unobservable inputs developed using estimates and assumptions, which are developed by the reporting entity and reflect those assumptions that a market participant would use.

Determining which category an asset or liability falls within the hierarchy requires significant judgment. The company evaluates its hierarchy disclosures each quarter. The Company’s only asset or liability measured at fair value on a recurring basis is its derivative liability associated with the warrants to purchase common stock (discussed above). The Company classifies the fair value of the derivative liability under level three. The fair value of the derivative liability was calculated using the Black-Scholes model. Under the Black-Scholes model using an expected life of three years, volatility of 98.79% and a risk-free interest rate of 1.65%, the Company determined the fair value of the derivative liability to be $24,438 as of the date the warrants were issued. Under the Black-Scholes model using an expected life of 2.6 years, volatility of 198.14% and a risk-free interest rate of 1.70%, the Company determined the fair value of the derivative liability to be $107,425 at December 31, 2009

The following shows the changes in the derivative liability measured on a recurring basis for the year ended December 31, 2009


Loss on derivative on initial valuation date	$	(24,438	)

Loss on derivative on balance sheet, valuation date		(82,987	)

Net loss on derivative
for the year ended December 31, 2009	$	(107,425)

There were no instruments valued at fair value on a recurring basis as of December 31, 2008.

The following table presents all assets that were measured and recognized at fair value as of December 31, 2009 and 2008, and for the twelve months then ended on a non-recurring basis. The assets shown below were presented at fair value due to the impairment analysis indicating an estimated fair value below the carrying value for the proved oil and gas properties.

Fair value of assets measured and recognized at fair value on a non-recurring basis as of December 31, 2009 and 2008 were as follows:

As of December 31 2009, and for the year then ended:

								Total
								Realized (Loss		Total
Description	Level 1		Level 2		Level 3			due to valuation)		Unrealized (Loss)
Proved Properties (net)	$	-	$	-		$	1,158,884	$	(4,913,349)	$	-
Totals	$	-	$	-		$	1,158,884	$	(4,913,349)	$	-

As of December 31 2008, and for the year then ended:

								Total
								Realized (Loss		Total
Description	Level 1		Level 2		Level 3			due to valuation)		Unrealized (Loss)
Proved Properties (net)	$	-	$	-		$	6,341,572	$	(5,291,298)	$	-
Totals	$	-	$	-		$	6,341,572	$	(5,291,298)	$	-

The Company valued the Proved Properties at their fair value in accordance with the applicable FASB standard due to the impairment indicators prevalent as of December 31, 2009 and 2008. The inputs that were used in determining the fair value of these assets were Level 3 inputs. These inputs consist of but are not limited to the following: estimates of reserve quantities, estimates of future production costs and taxes, estimates of consistent pricing of commodities, 10% discount rate, etc. Impairment expense was recorded at both year ends at the amount the carrying value of the assets exceeded their estimated fair values as of December 31, 2009 and 2008.

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

On January 1, 2009, the Company adopted a new accounting standard issued by the FASB related to the disclosure of derivative instruments and hedging activities. This standard expanded the disclosure requirements about an entity’s derivative financial instruments and hedging activities including qualitative disclosures about objectives and strategies for suing derivatives, quantitative disclosures about fair value amounts of an gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative instruments. At December 31, 2009, the Company has a derivative liability of $107,425 related to the warrants to purchase common stock. The derivative instruments were not entered into as hedging activities, and the change in value of the liability is included in the accompanying Consolidated Statement of Operations.

Effective January 1, 2009, the Company adopted a new accounting standard related to determining whether an instrument (or an embedded feature) is indexed to an entity’s own stock, which would qualify as a scope exception from hedge accounting. Upon adoption, the Company’s warrants issued in the third quarter were classified in liabilities as these warrants contain exercise price reset features and were deemed to not be indexed to the Company’s own stock. See Note 3 for further discussion.

Recently Issued Accounting Standards

In August 2009, the FASB issued an amendment to the accounting standards related to the measurement of liabilities that are recognized or disclosed at fair value on a recurring basis. This standard clarifies how a company should measure the fair value of liabilities and that restrictions preventing the transfer of a liability should not be considered as a factor in the measurement of liabilities within the scope of this standard. This standard was effective for the Company on October 1, 2009.

In October 2009, the FASB issued an amendment to the accounting standards related to the accounting for revenue in arrangements with multiple deliverables including how the arrangement consideration is allocated among delivered and undelivered items of the arrangement. Among the amendments, this standard eliminates the use of the residual method for allocating arrangement consideration and requires an entity to allocate the overall consideration to each deliverable based on an estimated selling price of each individual deliverable in the arrangement in the absence of having vendor-specific objective evidence or other third party evidence of fair value of the undelivered items. This standard also provides further

guidance on how to determine a separate unit of accounting in a multiple-deliverable revenue arrangement and expands the disclosure requirements about the judgments made in applying the estimated selling price method and how those judgments affect the timing or amount of revenue recognition. This standard, for which the Company is currently assessing the impact, will become effective for the Company on January 1, 2011.

In October 2009, the FASB issued an amendment to the accounting standards related to certain revenue arrangements that include software elements. This standard clarifies the existing accounting guidance such that tangible products that contain both software and non-software components that function together to deliver the product’s essential functionality, shall be excluded from the scope of the software revenue recognition accounting standards. Accordingly, sales of these products may fall within the scope of other revenue recognition accounting standards or may now be within the scope of this standard and may require an allocation of the arrangement consideration for each element of the arrangement. This standard, for which the Company is currently assessing the impact, will become effective for the Company on January 1, 2011.

Beneficial conversion features

From time to time, the Company may issue convertible notes that have detached warrants and may contain an imbedded beneficial conversion feature. A beneficial conversion feature exists on the date a convertible note is issued when the fair value of the underlying common stock to which the note is convertible into is in excess of the remaining unallocated proceeds of the note after first considering the allocation of a portion of the note proceeds to the fair value of the warrants, if related warrants have been granted. The intrinsic value of the beneficial conversion feature is recorded as a debt discount with a corresponding amount to additional paid in capital. The debt discount is amortized to interest expense over the life of the note using the effective interest method.

Major Customers

The Company sold oil and natural gas production that composed material concentrations of its oil and natural gas revenues as follows:

	Twelve Months Ended December 31,

	2009			2008

Interconn Resources, Inc. (l)		76	%		62	%

Plains (1)		22	%		24	%

Orchard Petroleum		-			14	%

(1) The Company does not have a formal purchase agreement with these customers, but sells production
on a month-to-month basis at spot prices adjusted for field differentials

Accounting estimates

corresponding volatility, and the Company’s ability to generate future taxable income. Future changes to these assumptions may affect these significant estimates materially in the near term.

Oil and natural gas properties

The Company accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, all costs associated with property acquisitions, successful exploratory wells, all development wells, including dry hole development wells, and asset retirement obligation assets are capitalized. Additionally, interest is capitalized while wells are being drilled and the underlying property is in development. Costs of exploratory wells are capitalized pending determination of whether each well has resulted in the discovery of proved reserves. Oil and natural gas mineral leasehold costs are capitalized as incurred. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells, and oil and natural gas production costs. Capitalized costs of proved properties including associated salvage are depleted on a well-by-well or field-by-field (common reservoir) basis using the units-of-production method based upon proved producing oil and natural gas reserves. The depletion rate is the current period production as a percentage of the total proved producing reserves. The depletion rate is applied to the net book value of property costs to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income. Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs with gain or loss recognized upon sale. A gain (loss) is recognized to the extent the sales price exceeds or is less than original cost or the carrying value, net of impairment. Oil and natural gas properties are also subject to impairment at the end of each reporting period. Unproved property costs are excluded from depletable costs until the related properties are developed. See impairment discussed in “Long-lived assets and intangible assets” below.

We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.

Long-lived assets and intangible assets

The Company accounts for intangible assets in accordance with the applicable FASB standard. Intangible assets that have defined lives are subject to amortization over the useful life of the assets. Intangible assets held having no contractual factors or other factors limiting the useful life of the asset are not subject to amortization but are reviewed at least annually for impairment or when indicators suggest that impairment may be needed. Intangible assets are subject to impairment review at least annually or when there is an indication that an asset has been impaired. As of December 31, 2008, the Company determined that due to the worsened financial markets and oil and gas industry, full impairment of its patented lateral drilling technology was necessary. While there are prospects for possible capital funding (either debt or equity), much is left to the market and outside instability. As such, at this time, management cannot anticipate with a comfortable degree of certainty if the appropriate amount of funding will be achieved and any funding will be diverted fully to its E&P activities. This will further postpone the Company’s ability to dedicate financial as well as human resources to its technology division in the short term future. As such, the Company has eliminated the division entirely.

“The Company recorded $4,913,349 and $5,291,298, respectively for 2009 and 2008 in determining that the Delhi Field, Belton Field and Marion Field required an impairment.”

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the carrying amount of the asset, including any intangible assets associated with that asset, exceeds its estimated future undiscounted net cash flows, the Company will recognize an impairment loss equal to the difference between its carrying amount and its estimated fair value. The fair value used to calculate the impairment for a producing oil and natural gas field that produces from a common reservoir is first determined by comparing the undiscounted future net cash flows associated with total proved properties to the carrying value of the underlying evaluated property. If the cost of the underlying evaluated property is in excess of the undiscounted future net cash flows, the future net cash flows are discounted at 10%, which the Company believes approximates fair value, to determine the amount of impairment.

Asset retirement obligation

The FASB standard on accounting for asset retirement obligation requires that the fair value of the liability for asset retirement costs be recognized in an entity’s balance sheet, as both a liability and an increase in the carrying values of such assets, in the periods in which such liabilities can be reasonably estimated. The present value of the estimated future asset retirement obligation (“ARO”), as of the date of acquisition or the date at which a successful well is drilled, is capitalized as part of the costs of proved oil and natural gas properties and recorded as a liability. The asset retirement costs are depleted over the production life of the oil and natural gas property on a unit-of-production basis.

The ARO is recorded at fair value and accretion expense is recognized as the discounted liability is accreted to its expected settlement value. The fair value of the ARO liability is measured by using expected future cash outflows discounted at the Company’s credit adjusted risk free interest rate.

Amounts incurred to settle plugging and abandonment obligations that are either less than or greater than amounts accrued are recorded as a gain or loss in current operations. Revisions to previous estimates, such as the estimated cost to plug a well or the estimated future economic life of a well, may require adjustments to the ARO and are capitalized as part of the costs of proved oil and natural gas property.

The following table is a reconciliation of the ARO liability for continuing operations for the twelve months ended December 31 2009 and 2008:

	December
	2009		2008

Asset retirement obligation at beginning of period	$	1,840,641	$	1,149,267

Liabilities incurred		-		1,529
Revisions to previous estimates		22,773		594,209
Dispositions		-		(33,374	)
Accretion expense		60,469		129,010

Asset retirement obligation at end of period	$	1,923,883	$	1,840,641

Income taxes

The Company accounts for income taxes in accordance with the provisions of the applicable FASB standard. Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws and regulations. Deferred tax assets include tax loss and credit carryforwards and are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

On January 1, 2007, the Company adopted the FASB Interpretation on accounting for uncertainty in income taxes. The interpretation prescribes a measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, the interpretation provides guidance regarding uncertain tax positions relating to derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company will classify any interest and penalties associated with income taxes as interest expense.

Stock based compensation

Beginning January 1, 2006, the Company adopted the FASB standard for accounting for stock based compensation to account for its Incentive Compensation Plan (the “2005 Incentive Plan”). The standard requires all share-based payments to employees (which includes non-employee Board of Directors), including employee stock options, warrants and restricted stock, be measured at the fair value of the award and expensed over the requisite service period (generally the vesting period). The fair value of common stock options or warrants granted to employees is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of comparable public companies. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock option or warrant, the dividend yield and the risk-free interest rate.

Under the 2005 Incentive Plan, the Company from time to time may issue stock options, warrants and restricted stock to acquire goods or services from third parties. Restricted stock, options or warrants issued to other than employees or directors are recorded on the basis of their fair value, which is measured as of the date issued. The options or warrants are valued using the Black-Scholes option pricing model on the basis of the market price of the underlying equity instrument on the “valuation date,” which for options and warrants related to contracts that have substantial disincentives to non-performance, is the date of the contract, and for all other contracts is the vesting date. Expense related to the options and warrants is recognized on a straight-line basis over the shorter of the period over which services are to be received or the vesting period.

The Company recognized stock-based compensation expense from annual stock granted to employees for the twelve months ended December , 2009 of $3,923,781. The Company recognized stock-based compensation expense from stock granted to non-employees for the twelve months ended December 31, 2009 of $3,703,105. The Company recognized stock-based compensation expense from options granted to employees for the twelve months ended December 31, 2009 of $66,605. The Company recognized stock-based compensation expense from warrants granted to non-employees for the twelve months ended December 31, 2009 of $38,005.

Earnings per share

Basic earnings per share is computed using the weighted average number of common shares outstanding. Diluted earnings per share reflects the potential dilutive effects of common stock equivalents such as options, warrants and convertible securities. Due to the Company incurring a net loss from continuing operations during the twelve months ended December 31, 2009 and 2008, basic and diluted loss per share are the same as all potentially dilutive common stock equivalents are anti-dilutive.

Note 3 –

Derivative Liability

Derivative

On August 21, 2009, and amended on September 25, 2009, the Company and YA Global entered into a Standby Equity Distribution Agreement, or SEDA, pursuant to which, for a two-year period, we have the right to sell shares of our common stock to YA Global. On August 21, 2009, we issued 260,000 shares of our common stock to YA Global in lieu of payment of a $65,000 commitment fee. As part of the transaction, we also issued YA Global a warrant to buy 1,500,000 shares of our common stock at $7.50 per share. On March 8, 2010 the Agreement was mutually terminated with no further liability to the Company

On January 1, 2009, the Company adopted Topic No. 815, and as a result the 1,500,000 warrants issued by the Company containing exercise price reset provisions, were classified as a derivative liability as of August 21, 2009 as these warrants were not deemed to be indexed to the Company’s own stock. These warrants had an exercise price of $7.50 at issuance and expire in August 2012. The exercise price was ratcheted down to $6.92 at December 31, 2009 based on the ratchet provisions in the warrant agreement. As of August 21, 2009, the fair value of these warrants of $24,438 was recognized and resulted in a loss on derivative. The change in fair value during the year ended December 31, 2009 of ($82,987) was netted with the loss and recorded as a net derivative loss of $107,425 in the accompanying Consolidated Statements of Operations.

Note 4 –

Debt

Notes payable consists of the following at December 31, 2009 and December 31, 2008:

	December 31,				December 31,
		2009				2008

Notes payable		$	8,494,405			$	800,000

Convertible notes payable, related party			725,000				850,000

			9,219,405				1,650,000

Less unamortized debt discount			(4,081,096	)			(157,132	)

			5,138,309				1,492,868
Less current maturities:
Notes payable, net of discount			(4,413,309	)			(689,518	)
Convertible notes payable, related party, net of discount			(725,000	)			(803,350	)

			-				-

The Company has a note payable with an individual investor aggregating $400,000 at December 31, 2009. This note payable matured on September 30, 2007 bearing interest at fixed rate of 18%. Interest will accrue from the note issue date and is due and payable either at maturity or quarterly or semi-annually until maturity. The Company is in default on notes payable of $400,000 at December 31, 2009, and is in the process of renegotiating its terms. This note payable in default is accruing interest at an additional 10% (28% total) and additional late fees may apply. This note payable is unsecured. Texas usury laws prevent interest rates above 18% and as such, the Company has not accrued interest above the 18% limit.

During 2008, the Company borrowed an additional $400,000 from four individuals at an interest rate of 15% with a one year maturity on each. During the third quarter ended September 30, 2009, two of these individuals converted these notes plus accrued interest to common stock at a fair market value of $.15 per share or $202,500 and 1,350,000 shares of common stock were issued and no gain was recognized because the fair value of the shares was equal to the debt and accrued interest. The remaining debt of $200,000 was considered in default based on the notes not being paid at their maturity dates.

During 2008, the Company borrowed an additional $50,000 from a related party at an interest rate of 8%. Simple interest accrues from the note issue date and is due and payable either at maturity or quarterly or semi-annually until maturity. During the third quarter ended September 30, 2009, this note plus interest was converted to common stock at a fair market value of $.15 per share or $53,896 and 359,307 shares of common stock were issued and no gain was recognized due to it being a related party. Any difference between the value of the shares issued and the debt relieved was recorded as additional paid in capital due to the party being a related party.

Effective September 12, 2006, the Company and a related party entered into a formal purchase and sale agreement to purchase their right, title and interest in the LHD Technology for a total purchase price of $4,750,000, comprised of $4,000,000 of cash and 1,000,000 shares of the Company’s common stock valued at $750,000. During 2006, as part of the payment consideration, the Company issued two notes payable to the seller totaling $1,650,000 and $2,000,000, respectively. These notes payable matured on June 1, 2007 and December 31, 2007, respectively, and interest accrued at a fixed interest rate of 8% starting from January 1, 2007 and January 1, 2008, respectively, until the amounts are paid. The Company had a total of $3,578,000 outstanding at December 31, 2007. Subsequent to December 31, 2007, the lender converted the entire $3,578,000 of the outstanding notes payable into shares of the Company’s common stock at $0.75 per share. During 2007, the Company borrowed $262,333 from officers of the Company. These notes matured on December 31, 2007 and did not bear interest. As of December 31, 2007, $240,666 was repaid and $2,666 was offset against a receivable, leaving a remaining $19,001 outstanding. These notes were in default at December 31, 2007, but have been repaid in the first quarter of 2008.

During 2008, the Company borrowed an additional $100,000 due and payable on March 1, 2010 from an individual at an interest rate of 15%. Simple interest accrues from the note issue date and is due and payable monthly. During the third quarter ended September 30, 2009, this note plus interest was converted to common stock at a fair market value of $.15 per share or $100,863 and 672,420 shares of common stock were issued and no gain was recognized due to it being a related party. Any difference between the value of the shares issued and the debt relieved was recorded as additional paid in capital due to the party being a related party.

During 2009, the Company borrowed an additional $100,000 due and payable on March 1, 2010 from an individual at an interest rate of 15%. Simple interest accrues from the note issue date and is due and payable monthly. During the third quarter ended September 30, 2009, this note plus interest was converted to common stock at a fair market value of $.15 per share or $101,250 and 675,000 shares of common stock were issued and no gain was recognized because the fair value of the shares was equal to the debt and accrued interest.

During 2009, The Company borrowed an additional $25,000 due and payable on January 20, 2010 from a related party at an interest rate of 8%. Simple interest accrues from the note issue date and is due and payable either at maturity or quarterly or semi-annually until maturity. During the third quarter ended September 30, 2009, this note plus interest was converted to common stock at a fair market value of $.15 per share or $26,387 and 175,913 shares of common stock were issued and no gain was recognized due to it being a related party. Any difference between the value of the shares issued and the debt relieved was recorded as additional paid in capital due to the party being a related party.

During 2009, the Company borrowed an additional $5,000 due and payable on April 16, 2010 from a related party at an interest rate of 8%. Simple interest accrues from the note issue date and is due and payable either at maturity or quarterly or semi-annually until maturity. During the third quarter ended September 30, 2009, this note plus interest was converted to common stock at a fair market value of $.15 per share or $5,173 and 34,486 shares of common stock were issued and no gain was recognized due to it being a related party. Any difference between the value of the shares issued and the debt relieved was recorded as additional paid in capital due to the party being a related party.

During 2009, the Company borrowed an additional $25,000 due and payable on December 31, 2009 at an interest rate of 8%. Simple interest accrues from the note issue date and is due and payable either at maturity or quarterly or semi-annually until maturity. This note was in default as of December 31, 2009 due to non-payment.

During 2009, the Company borrowed an additional $25,000 due and payable on December 31, 2009 from a related party at an interest rate of 8%. Simple interest accrues from the note issue date and is due and payable either at maturity or quarterly or semi-annually until maturity. This note is convertible into common stock at the greater of the closing price on the date of conversion, or one cent. This note was in default as of December 31, 2009 due to non-payment.

During 2009, the Company borrowed $1,500,000 due and payable on June 30, 2010 from a third party at an interest rate of 15%. Simple interest accrues from the note issue date and is due and payable at maturity. This funding was restricted funds to bring the Delhi field wells back into production. The Company issued 200,000 shares of common stock as an inducement to the lender. The 200,000 shares were valued at the closing price on the date of issuance equaling a total of $300,000. This value was taken as a discount on debt. The discount is being amortized over the life of the note according to the effective interest method. The Company received $1,477,271 of the total $1,500,000 funds related to the

note. The difference of $22,729 was paid for offering costs associated with the loan. These costs have been capitalized and are being amortized according to the effective interest method over the life of the loan. Amortization for the twelve months ended December 31, 2009 was $11,874.

During 2009, the Company borrowed an additional $1,000,000 from this third party that was due and payable on October 31, 2010 at an interest rate of 15%. Simple interest accrues from the note issue date and is due and payable at maturity. This funding was restricted funds to bring the Delhi field wells back into production. The Company issued 1,000,000 shares of common stock as an inducement to the lender, valued at the closing price on the date of issuance equaling a total of $300,000. This value was taken as a discount on debt. The discount is being amortized over the life of the note according to the effective interest method.

In conjunction with the previous two loans, the Company issued to Lender a term assignment of an overriding royalty interest in the Delhi Field equal to fifteen percent of eight-eighths (15% of 8/8") and ten percent of eight-eighths (10% of 8/8”) of all Hydrocarbons produced and saved from or attributable or allocable to the Delhi Field net of severance taxes owing with respect thereto through December 31, 2011. Further, if a total of $7,500,000 (including the principal and interest repayments on the two notes above) is not paid by December 31, 2011, the Company will make a cash payment to cover the deficiency. The balance owed related to the overriding interest only of $5,000,000 was fully discounted upon issuance due to its attachment to the notes payable of $1,500,000, and $1,000,000. The discounts are being amortized over the term of the notes payable. Amortization on the discount related to the overriding royalty interest and the aforementioned discounts due to shares issued with the debt was $1,278,904 for the year ended December 31, 2009. The remaining balance of the discounts as of December 31, 2009 was a total of $4,081,096. During the year ended December 31, 2009 overriding royalty payments were made against the $5,000,000 balance of $45,308. The net balance has been presented within current notes payable on the balance sheet.

During 2009 The Company issued 5,000,000 default shares of common stock valued at $4,620,000 that are held in escrow as insurance to the lenders and will be remitted back to the Company if the note is paid in full with 15% interest. The company valued these shares according to the closing price of the shares on the date of issuance.

The Company has an anti-dilution clause with the lender that any shares of capital stock (excluding the Default Shares) held by the Lender or any affiliate thereof shall represent an agreed upon percentage of all of the issued and outstanding shares of capital stock of Borrower computed on a fully diluted basis as of the date hereof, which Percentage Interest is 15.00% and increased to 17.37% with funding of the second loan. Lender shall at all times from and after the Loan Date hold a minimum equity interest in Borrower equal to the Percentage Interest, and Borrower shall not, and shall not permit any of its Subsidiaries to, take any action that in any way dilutes or impairs the Percentage Interest at any time. In the event Borrower shall (a) issue or sell (i) Equity Interests of Borrower or any of its Subsidiaries, or (ii) any options, warrants, rights, debt securities, promissory notes, or other securities exercisable or exchangeable for or convertible into shares of capital stock of Borrower or any Subsidiary thereof, (b) declare or pay any dividend or other distribution to holders of Equity Interests of Borrower or any of its Subsidiaries, or (c) repurchase or redeem any Equity Interests of Borrower or any of its Subsidiaries, and if as a result such event or occurrence dilutes or impairs in any manner and to any extent (a "Diluting Event") the Percentage Interest, Lender shall be entitled to receive, and Borrower shall issue to Lender immediately upon such event or occurrence, such additional number of shares of capital stock of Borrower such that after giving effect to any such event or occurrence Lender's equity interest in Borrower is not less than the Percentage Interest, such additional shares of capital stock to be issued to and acquired by Lender without any additional consideration of any nature. In the event prior to the Default Shares being deemed issued to Lender (and thereby covered by the language above), a Diluting Event occurs which will lessen the Default Percentage Interest , the Default Shares, without any additional consideration of any nature, shall be increased by such additional number. of shares of capital stock of Borrower such that after giving effect to any such event or occurrence the number of Default Shares is not less that the Default Percentage. Additional shares owed related to this anti-dilution provision were the following: 3,450,633 default shares valued at $480,900 and 1,990,430 common shares valued at $303,293.

Convertible notes payable

During 2005, the Company executed a convertible note payable with a related party investor aggregating $700,000. This note payable matured March 29, 2007, bearing interest at a fixed rate of 9%. Simple interest will accrue from the note date and is due and payable quarterly until maturity. Should the 9% convertible note go into default, interest will accrue at a rate of 18%. The note is unsecured. This note payable is convertible into shares of the Company’s common stock at an exchange rate of $7.50 per share, or into 93,333 shares of common stock. At December 31, 2009 and December 31, 2008, the Company had $700,000 outstanding of convertible notes payable to this investor. The maturity date on this note was extended to mature on September 30, 2007 and then extended again to March 30, 2008, whereby the Company issued the note holder warrants to purchase 466,666 shares of the Company’s common stock at an exercise price of $0.75 per share for a period of five years and then issued warrants to purchase another 466,666 shares of the Company’s common stock at an exercise price of $0.75 per share for a period of three years, as fees for the extensions. The fair value of the warrants was amortized to interest expense using the effective interest method over the extension periods. The extension also revised the notes payable to bear interest at 12% from October 1, 2007 through March 30, 2008 and 18% in the event of default. The Company is currently in default on this note payable and is in negotiations with the note holder.

Production Payment with BlueRock Energy Capital, LTD

Effective May 1, 2008, the Company finalized its negotiations with BlueRock Energy Capital, LTD (“BlueRock”) to restructure its monthly production payment facility on its Marion Field. The new agreement calls for a reduction of the interest rate from its current 18% to 8% and to

give back to the Company up to $25,000 of its production payment per month so that the field would be cash flow positive. The Company’s obligations under these new terms would be to seek refinancing of the production payment payable or the outright purchase of the production payable by no later than the anniversary of the execution of the new agreement. Should the Company not meet this obligation, BlueRock has the option of taking back the field in full payment of the production payment payable or reverting back to the previous terms under the existing agreement. This agreement was later extended for 6 months until October 30, 2009.

Effective May 1, 2009, the Company notified BlueRock that the Company was in default under the Conveyance and the Production Agreement. A third amendment was finalized and the 8% interest rate was increased back to 18%. A fourth amendment was finalized and the agreement was extended to November 30, 2009. At December 31, 2009, the Company is in default.

Interest expense, net

Interest expense consists of the following for the twelve months ended December 31:


	Twelve Months Ended December 31,
	2009		2008

Interest expense related to debt	$	1,944,740	$	1,635,964

Amortization of deferred financing costs		11,874		324,735

Amortization of debt discount		1,419,694		261,730

	$	3,376,308	$	2,222,429

Note 5 –

Discontinued Operations

Maxim TEP, PLC, South Belridge and Orchard Petroleum

During April 2008, the Company sold its South Belridge Field in a three party transaction that involved Mercuria Partners, a majority shareholder in Orchard Petroleum, and Maxim TEP, PLC as an all inclusive deal to eliminate all debt, joint interest rights and obligations amongst all three parties, for a cash consideration of $35,781,654 and the issuance of 21,700,000 shares of common stock of the Company issued to Maxim TEP, PLC. With this cash and stock consideration, the Company retired $37,408,772 in current notes payable and approximately $6,068,427 in interest payable. South Belridge Field had a carrying cost of $4,366,422 at the date of closing. At the closing of this transaction, the Company had no further interest, rights or obligations in the South Belridge Field and satisfied in full all debt, interests and other obligations owed to Maxim TEP, PLC and its parent, the Greater European Fund, as well as any interest, rights or obligations under the Joint Venture agreement with Orchard Petroleum. The financial results of the Company’s South Belridge operations are reported as discontinued operations for all periods presented.

Days Creek Field

During November 2006, the Company entered into three convertible notes payable totaling $2,000,000 each ($6,000,000 in total) bearing interest at a rate of 10%, which matured on October 31, 2007, secured by the leases in the Days Creek Field. These notes payable were originally convertible into shares of the Company’s common stock at an exchange rate of $1.50 per share, or into approximately 4,000,000 shares of common stock. These notes are collateralized by the Company’s oil and natural gas properties in Days Creek. During 2007, the maturity dates on these notes were extended to mature on February 1, 2008, whereby the Company agreed to pay an additional $300,000 to the note holders as a fee for the extension. In February 2008, these notes were extended again to mature on April 30, 2008, for an additional extension fee of $300,000 and the exchange rate of $1.50 per share was amended to $0.75 per share, resulting in the $6,000,000 in convertible notes being convertible into 8,000,000 shares of common stock. In May of 2008, the Company exchanged a 75% working interest in its Days Creek Field in consideration for the $6,000,000 convertible note that it owed to the three note holders effective May 1, 2008, keeping a net 10% working interest in the field. The financial results of the Company’s Days Creek Field are reported as discontinued operations for all periods presented.

Stephens Field

During the last quarter of 2008, the Company sold its interest in the Stephens Field. The financial results of the Company’s Stephens Field are reported as discontinued operations for all periods presented.

The results for all discontinued operations are summarized below:

	Twelve Months Ended December 31,
	2009		2008
Operating revenues	$	-	$	751,059

Operating costs and expenses		-		446,891

Other expenses, net		-		2,337,811

Loss from discontinued		-		(2,033,643	)
operations, net of taxes

Gain on disposal of discontinued		-		22,856,784
operations, net of taxes

Net income	$	-	$	20,823,141

Basic and diluted loss per
share from discontinued operations	$	-	$	(0.18	)

Basic and diluted income per share
from gain on disposal of
discontinued operations		-		2.00

Total	$	-	$	1.82

Weighted average number of
common shares outstanding

Basic				11,493,956
Diluted		-		11,493,956

Note 6 –

Stockholders’ Equity

Preferred stock

On June 30, 2008, the Board of Directors resolved to cancel the Company’s previous class of preferred stock and issue up to 5,000,000 shares of a new class of preferred stock, of which 1,000,000 has been designated as a Series A Preferred Stock, $.00001 par value per share. This series has liquidation preference above common stock. The holders of Series A Preferred Stock shall be entitled to receive dividends if and when declared by the Board of Directors. Each share of Series A Preferred Stock shall have voting rights identical to a share of common stock (i.e. one vote per share) and shall be permitted to vote on all matters on which holders of common stock are entitled to vote. So long as any shares of Series A Preferred Stock remain outstanding, the Company shall not without first obtaining the approval of the holders of seventy-five percent (75%) of the then-outstanding shares of Series A Preferred Stock: (i) alter or change the rights, preferences or privileges of the shares of Series A Preferred Stock so as to adversely affect such shares; (ii) increase or decrease the total number of authorized shares of Series A Preferred Stock; (iii) issue any Senior Securities; or (iv) take any action that alters or amends this Series.

During the second quarter of 2008, the Company issued 545,455 shares of Series A Preferred Stock in exchange for $3,000,000 of corporate notes payable. At December 31, 2009, there were 545,455 shares of Series A Preferred Stock issued and outstanding.

Common stock

During 2008, the Company issued to a third party 2,172,222 shares of common stock with a fair value of $16,291,668 as a debt conversion of $37,408,772 and accrued interest of $6,068,427 for the year ended December 31, 2008.

During 2008, total proceeds of $990,589 were generated through private offerings of common stock from the issuance of 132,080 shares.

During 2008, the Company issued 51,000 shares of common stock with a fair value of $382,500, respectively, to third parties for services.

During 2008, the Company issued 967,754 shares of common stock with a fair value of $7,258,158, to employees of the Company for services.

During 2008, related party note holders comprising $5,085,664 of principal and accrued interest and other liabilities elected to convert into 719,979 shares of the Company’s common stock. On August 31, 2008, the put option feature on the remaining 216,666 shares of common stock with embedded put options at $2.00 per share expired and as a result the related liabilities of $433,300 were reclassed to permanent equity.

During 2008, the Company issued 90,000 shares of common stock in connection with the sale of net revenue interests. Proceeds of $675,001 were received from the sale.

During 2008, the Company issued 90,000 shares of common stock with a short-term note payable attached. The note was paid off prior to year end and therefore was expensed for the fair value of $510,009.

During 2008, the Company issued 2,500 shares of common stock to purchase oil and gas properties. The fair value of the shares issued as a result of this purchase was equal to $18,750.

During 2009, the Company issued 6,150,846 shares of common stock with a fair value of $3,923,781 to employees of the Company for services. The fair value was recorded as an expense, and was calculated according to the closing price of the shares on the date of issuance.

During 2009, the Company issued 5,999,407 shares of common stock with a fair value of $791,944 to employees to relieve accrued salary of $814,415. The difference between the value of the shares issued and the accrued salary converted was recorded as additional paid in capital due to the employees being considered related parties.

During 2009, the Company issued 1,996,634 shares of common stock with a fair value of $3,703,105 to third parties for services. The fair value was recorded as an expense, and was calculated according to the closing price of the shares on the date of issuance.

During 2009, the Company issued 1,242,128 shares of common stock with a fair value of $169,977 for note conversion to related parties. The fair value was calculated according to the closing price of the shares on the date of issuance. Any differences between the fair value of the shares and the debt relieved was recorded through additional paid in capital.

During 2009, the Company issued 2,025,000 shares of common stock with a fair value of $303,750 for note conversion to unrelated parties. The fair value of the shares was calculated according to the closing price of the shares on the date of issuance. The fair value of the shares issued was equal to the debt and accrued interest relieved therefore there was no gain or loss on the conversion.

During 2009, the Company issued 5,000,000 shares of common stock with a fair value of $4,620,000 related to a note payable. These shares are considered “Default Shares” and are being held in escrow as insurance to the lenders and will be remitted back to the Company if the note is paid in full. The agreement has an anti-dilution clause related to these Default Shares. In the event prior to the Default Shares being deemed issued to Lender (and thereby covered by the language above), a Diluting Event occurs which will lessen the Default Percentage Interest , the Default Shares, without any additional consideration of any nature, shall be increased by such additional number of shares of capital stock of Borrower such that after giving effect to any such event or occurrence the number of Default Shares is not less that the Default Percentage

During 2009, the Company issued 1,200,000 shares of common stock with a fair value of $360,000 with a note payable of $2,500,000 to a third party. The fair value of the shares was taken as a discount on debt and is being amortized over the life of the note according to the effective interest rate method.

During, 2009, the Company issued 3,045,732 shares of common stock with a fair value of $546,604 for an anti-dilution clause related to the $2,500,000 notes payable. The shares were valued according to the closing price of the shares on the date of issuance. The Company has an anti-dilution clause with the lender that any shares of capital stock (excluding the Default Shares) held by the Lender or any affiliate thereof shall represent an agreed upon percentage of all of the issued and outstanding shares of capital stock of Borrower computed on a fully diluted basis as of the date hereof, which Percentage Interest is 17.37%. Lender shall at all times from and after the Loan Date hold a minimum equity interest in Borrower equal to the Percentage Interest, and Borrower shall not, and shall not permit any of its Subsidiaries to, take any action that in any way dilutes or impairs the Percentage Interest at any time. In the event Borrower shall (a) issue or sell (i) Equity Interests of Borrower or any of its Subsidiaries, or (ii) any options, warrants, rights, debt securities, promissory notes, or other securities exercisable or exchangeable for or convertible into shares of capital stock of Borrower or any Subsidiary thereof, (b) declare or pay any dividend or other distribution to holders of Equity Interests of Borrower or any of its Subsidiaries, or (c) repurchase or redeem any Equity Interests of Borrower or any of its Subsidiaries, and if as a result such event or occurrence dilutes or impairs in any manner and to any extent (a "Diluting Event") the Percentage Interest, Lender shall be entitled to receive, and Borrower shall issue to Lender immediately upon such event or occurrence, such additional number of shares of capital stock of Borrower such that after giving effect to any such event or occurrence Lender's equity interest in Borrower is not less than the Percentage Interest, such additional shares of capital stock to be issued to and acquired by Lender without any additional consideration of any nature.

During 2009, 100,000 shares of common stock with a fair value of $14,610 were issued to convert accounts payable. The fair value of the shares was equal to the accounts payable converted.

During 2009, we received a total of 439,463 shares from former employees for no consideration given up by the company. All of these shares and the shares held at December 31, 2008 were re-issued for services and to relieve stock payables during 2009 with the exception of 839 shares that remained at December 31, 2009. The value of the stock payable relieved from the issuances of treasury shares was $686,880, and the value of the treasury shares issued for services was $1,378,297. The value of the shares issued for services was calculated based on the market price of the shares on the date the shares were issued.

During the nine months ended September 30, 2009, the Company recorded a stock payable of 500,000 shares of common stock with a fair value of $700,000 for a consulting agreement. These shares were valued as of the date of the agreement according to the closing price of the shares on that date. The shares have not been issued as of December 31, 2009 and therefore were disclosed within stock payable.

During 2009, the Company recorded a stock payable of $784,093 owed related to the anti-dilution provision of the $2,500,000 aforementioned notes payable. A portion of the shares shown as stock payable were owed to the debt holder and a portion were owed as default shares in case the company defaults on the note agreement. The value of the shares owed to the lender were valued at $303,293, and the value of the default shares owed to escrow were valued at $480,800. The shares were valued according to the closing market price as of December 31, 2009.

During 2009, a stock payable for 500,000 shares was recorded at a value of $30,000 related to a 2010 settlement of litigation that related to prior periods. The shares were valued according to the share price on the settlement date. The settlement included a cash portion of $160,000 which was recorded within liabilities at December 31, 2009. The original accrual for the estimated settlement was $290,000 as recorded at December 31, 2008. The Company recorded a gain of $100,000 related to the settlement in 2009 based on the revision to the prior estimate.

Warrants

During 2008, the Company granted 120,754 warrants, respectively, to purchase the Company’s common stock with an exercise price of $7.50 per share in connection with the sale of the Company’s common stock. These warrants expire in three and five years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $414,605.

During the first quarter of 2009 months, warrants to acquire 7,500 shares of the Company’s common stock with an exercise price of $7.50 per share were granted for services. These warrants expire five years from the date of grant. The fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $38,005.

During the third quarter ended September, 2009, warrants to acquire 1,500,000 shares of the Company’s common stock were issued containing exercise price reset provisions, were classified as a derivative liability as of August 21, 2009 as these warrants were not deemed to be indexed to the Company’s own stock. These warrants had an exercise price of $7.50 upon issuance and expire in August 2012. As of August 21, 2009, the fair value of these warrants of $24,438 was recognized and resulted in a loss on derivative. The change in fair value during the year ended December 31, 2009 of ($82,687) was netted with the loss and recorded as a net derivative loss of $107,425 in the accompanying Consolidated Statements of Operations.

The following is a summary of the warrant activity for the years ended December 31:

	2009			2008
	Number of	Weighted			Weighted
	Shares	Average		Number of	Average
		Exercise Price		Shares	Exercise Price

Outstanding, beginning of period	1,529,749	$	7.5	1,408,995	$	7.5

Granted	1,507,500		7.5	120,754		7.5
Exercised	–		–	–		–
Expired or cancelled	(20,000)		–	0		7.5

Outstanding, end of period	3,017,249	$	7.5	1,529,749	$	7.5

The fair value of common stock warrants granted is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of comparable public companies. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock warrant, the dividend yield and the risk-free interest rate. Following are the assumptions used during the years ending December 31:

	2009	2008
Risk free rate	1.14%	4.23-4.92
Expected life	5	5-10 years
Volatility	86-98%	38%
Dividend yield	0%	0%

Stock options

During 2008, the Company granted options to purchase 367,416 shares, of the Company’s common stock at an exercise price of $7.50 per share to employees and to non-employee Directors for services provided. These options expire between five and ten years from the date of grant. All options granted to employees in 2008 vested immediately upon grant. The estimated fair value of these stock options was determined on the grant date using the Black-Scholes option pricing model and the Company recorded $1,256,634 as general and administrative expense to account for vested options.

During, 2009, the Company granted options to purchase 17,500 shares of the Company’s common stock at an exercise price of $7.50 per share to employees for services provided. These options expire 5 years from the date of grant. All the options granted to employees in 2009 vested immediately on the grant date. The estimated fair value of these stock options was determined on the grant date using the Black-Scholes option pricing model and totaled $66,605.

The following is a summary of the stock option activity for the years ended December 31:

		2009							2008
	Number of				Weighted				Number of			Weighted
		Shares			Average			Shares				Average
					Exercise Price							Exercise Price

Non-vested, beginning of period			-			$	-			-			$	-

Granted			17,500				7.5			367,416				7.5
Vested			(17,500	)			-			(367,416	)			7.5

Non-vested, end of period			-			$	7.5			-			$	7.5

The fair value of common stock options granted is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of a comparable public company. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock option, the dividend yield and the risk-free interest rate. In addition, the Company estimates a forfeiture rate at the inception of the option grant based on historical data and adjusts this prospectively as new information regarding forfeitures becomes available. Following are the average assumptions used during the years ended December 31, 2009 and 2008:

	2009	2008
Risk free rate	1.14%	2.45% - 2.90%
Expected life	2.5 years	5-10 years
Volatility	86%	67%
Dividend yield	0%	0%

Note 7 –

Federal Income Tax

No provision for federal income taxes has been recognized for the twelve months ended December 31, 2009 and 2008 as the Company has a net operating loss carry forward for income tax purposes available in each period. Additionally, it is uncertain if the Company will have taxable income in the future so a valuation allowance has been established for the full value of net tax assets. The primary deferred tax asset includes a net operating loss carryforward The primary deferred tax liability is the basis difference in oil and gas property and property and equipment.

At December 31, 2009, the Company has net operating loss carryforwards of approximately $35 million for federal income tax purposes. These net operating loss carryforwards may be carried forward in varying amounts until 2024 and may be limited in their use due to significant changes in the Company's ownership.

Deferred Tax Assets	$14,000,000
Less: Valuation Allowance	(14,000,000)
Net Tax Assets	-

We have valued our net deferred tax asset at zero with a valuation allowance due to the substantial doubt that we will generate taxable income in the future and utilize our deferred tax assets.

The Company believes it has no uncertain income tax positions as of December 31, 2009 and 2008.

Note 8 –

Commitments and Contingencies

Office Lease

The Company leased office space for a two year period beginning March, 2009 through December 31, 2010. The remaining payments for the lease in 2010 are $34,050 and none for the remaining four years.

Litigation

The following describes legal action being pursued against the Company outside the ordinary course of business:

•

Vanguard Energy Services sued for $340,000 for use of their drilling rigs in 2006 and 2007. The Company has settled the claims to include two sister Companies, Recompletion Finance Corporation and Edge Capital. Each party was mutually released. The lawsuit was settled with the cash of $160,000 and 500,000 shares of common stock.

•

In the suit, LFU Fort Pierce, Inc. d/b/a Labor Finders, our subsidiary Tiger Bend Drilling was sued for $284,988. This has been expensed in 2007 and is reflected in our accounts payable in 2009 and 2008. In connection with this suit, an additional a 25% attorney fees and interest are owed and have been accrued at December 31, 2009.

•

In a suit with Pannell Kerr Forster of Texas PC (AKA PKF Texas) and PKF (UK) LLP were seeking payment for services rendered. We have retained an expert witness in this field to opine on what the Company was charged and the ethics associated with PKF’s

performance. This lawsuit was settled for a sum of $281,818, payable in 24 monthly installments. If the Company defaults on monthly installment, the entire outstanding balance of $563,636 becomes due.

•

Note 9 –

Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)

The following disclosures provide unaudited information required by the FASB standard on oil and gas producing activities.

Results of operations from oil and natural gas producing activities

The Company’s oil and natural gas properties are located within the United States. The Company currently has no operations in foreign jurisdictions. Results of operations from oil and natural gas producing activities are summarized below for the years ended December 31:

	2009			2008
Revenues	$	905,781		$	1.822.893
Production and lease operating expenses		(1,365,878	)		(1,295,692	)
Impairment of oil and natural gas properties		(4,913,349	)		(5,291,298	)
Depreciation, depletion and amortization		(1,368,758	)		(1,993,100	)

Results of oil and natural gas producing activities
(excluding overhead and interest costs)	$	(6,742,204	)	$	(6,757,197	)

Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below for the years ended December 31:

	2009	2008

Property acquisition costs:

Acquisition of properties	-			-
Exploration Costs	-			-
Development costs	102,079		127,072

Total costs incurred	102,079		127,072

Capitalized costs net of accumulated depletion and other valuation allowances as of December 31:

	2009			2008
Unproved oil and gas properties		722,492			1,125,919
Proved oil and gas properties		13,340,293			13,373,317
		14,062,785			14,499,236
Accumulated depreciation, depletion, and
amortization, and valuation allowances		(12,731,105	)		(7,031,745	)
Net capitalized costs		1,331,680			7,467,491

Oil and natural gas reserves

Proved reserves are estimated quantities of oil and natural gas which geological 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 proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.

Proved oil and natural gas reserve quantities at December 31, 2009 and 2008, and the related discounted future net cash flows are based on estimates prepared by independent petroleum engineers. The reserves as of December 31, 2009 were derived from reserve estimates prepared by the independent reserve engineers; Huddleston & Co., Inc. for the Delhi Field and the Marion Field. The reserves as of December 31, 2008 were derived from reserve estimates prepared by the independent reserve engineers; Mark Newendorp. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission. In 2009 the SEC issued guidance requiring oil and gas companies to calculate the value of proved reserves using prices that were calculated as the average price of the first day of the twelve months in the year. This guidance differed from the previous standard of valuing prices according to the end of year prices. The guidance does not require that prior year information be revised for the new method. As a result, this change in methods of pricing should be taken into account while reviewing the comparable information for 2009 and 2008 within this disclosure.

The Company’s net ownership interests in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized below as of December 31:

	2009			2008
Oil
Proved developed and undeveloped reserves (BBL):
Beginning of year		1,073,120			2,609,815
Revisions		(1,024,071	)		(1,525,418	)
Production		(4,049	)		(11,277	)

End of year		45,000			1,073,120

Proved developed reserves at beginning of year		1,073,120			146,596
Proved developed reserves at end of year		45,000			1,073,120

	2009			2008

Gas
Proved developed and undeveloped reserves (MCF):
Beginning of year		1,973,000			1,987,875
Revisions		(1,149,431	)		252,884
Production		(247,469	)		(267,759	)

End of year		576,100			1,973,000

Proved developed reserves at beginning of year		1,973,000			1,987,875
Proved developed reserves at end of year		576,100			1,973,000

Standardized measure

The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved oil and natural gas reserves for the years ended December 31 are shown below:

	2009			2008

Future cash inflows	$	5,218,733		$	56,975,022
Future oil and natural gas operation expenses		(3,841,106	)		(16,552,930	)
Future development costs		-			(895,990	)
Future net cash flows		1,377,627			39,526,102
10% annual discount for estimating timing of cash flow		(221,313	)		(16,047,672	)
Standardized measure of discounted future net cash flow	$	1,156,314		$	23,478,430

The reason for the large drop in discounted future net cash flow from 2008 to 2009 was two-fold. First, it was primarily due to weather delays and equipment failure which postponed our progress in restoring the Delhi Field to production. Second, there was a large drop in gas prices in the Marion Field which greatly decreased its value. The rules promulgated by the SEC regarding the price used to calculate future net values changed whereby in 2008, the December 31, 2008 price was used and in 2009, the average price for the year was used. Product prices for oil and gas respectively for 2009 and 2008 were $61.80/Bbl and $41.55Bbl, and $4.21/MMBTU and $6.73/MMBTU.

In neither year was the Company allowed to value assets attributable to Proved Undeveloped or Probable Reserves because of the SEC guidelines requiring available capital to monetize the projects.

Future income taxes are based on year-end statutory rates, adjusted for tax basis of oil and natural gas properties and availability of applicable tax assets, such as net operating losses. A discount factor of 10% was used to reflect the timing of future net cash flows.

The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair value may also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and may require a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

Changes in standardized measure

Included within standardized measure are reserves purchased in place. The purchase of reserves in place includes undeveloped reserves which were acquired at minimal value that have been estimated by independent reserve engineers to be recoverable through existing wells utilizing equipment and operating methods available to the Company and that are expected to be developed in the near term based on an approved plan of development contingent on available capital.

Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for the years ended December 31 is summarized below:

	2009			2008
Changes due to current-year operations:
Sales and transfers, net of production costs	$	460,097		$	(527,201	)
Net change in sales and transfer prices, net of production costs		(13,272,213	)		(48,685,276	)
Revision of quantity estimates		(11,875,918	)		(23,172,803	)
Sales of reserves in place		-			(21,362,595	)
Accretion of discount		2,347,843			10,486,426
Other-unspecified		18,075			1,875,618
Net of change		(22,322,116	)		(81,385,831	)
Beginning of year		23,478,430			104,864,261
End of year	$	1,156,314		$	23,478,430

Note 10 –

Subsequent Events

•

During 2008, the Company failed to pay payroll taxes to the Internal Revenue Service and various state revenue agencies totaling $329,337 and $30,525, respectively. The Company made a payment of $125,000 to the Internal Revenue Service. Since this is quite a serious matter which could result in substantial penalties and interest which would be very detrimental to the Company’s financial position, the Company has hired a consulting firm to deal with the Internal Revenue Service and the State Agencies. The Company has accrued all payroll liabilities and the estimated interest and penalties related to this as of December 31,2009.

In 2010 the SEDA Agreement with Yorkville Advisors was mutually terminated with no further liability to the Company

•

The lawsuit with PKF Pannell Kerr Forster of Texas PC (AKA PKF Texas) and PKF (UK) LLP was settled for a sum of $281,818, payable in 24 monthly installments. If the Company defaults on monthly installment, the entire outstanding balance of $563,636 becomes due.

The Company has settled the claims with Vanguard and two sister Companies, Recompletion Finance Corporation and Edge Capital. Each party was mutually released. As a part of the settlement, the Company issued 500,000 shares of common stock.

The Company obtained restricted funding from a third party in 2010. In connection with the funding, the Company issued 1,500,000 shares of common stock and 3,000,000 transactional shares of common stock.

The Company issued 1,500 shares of common stock to a Director as compensation.

The Company owed $160,000 and issued 129,626 anti-dilution shares of common stock to third party lender

Note 11 –

Correction of Errors in Previously Issued Financial Statements

The Company intends to restate its previously issued December 31, 2009 financial statements due to deficiencies in disclosures with regards to the unaudited footnote number 9 “Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities”. This disclosure has been revised to fulfill the requirements pursuant to FASB ASC 932-235-50.

ITEM 9 CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rule 13a-1 5(e) promulgated under the Securities Exchange Act of 1934 (the "Exchange Act"), that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2009. Based on the evaluation of these disclosure controls and procedures, and in light of the material weaknesses found in our internal controls over financial reporting, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective.

Management’s Report on Internal Control over Financial Reporting

Material Weaknesses in Internal Control Over Financial Reporting

Management’s assessment of the effectiveness of the registrant’s internal control over financial reporting is as of the year December 31, 2009. Based on that evaluation, our management concluded that our control over financial reporting and related disclosure controls and procedures were not effective because our accounting processes lack appropriate segregation of responsibilities and accounting technical expertise necessary for an effective system of internal control. We believe that our lack of technical expertise constitutes a material weakness in our internal control. In addition to this material weakness, Management’s assessment showed that the following material weaknesses from the audited year ended December 31, 2009.

As of December 31, 2009, we did not maintain effective controls over the control environment. Specifically we have not developed and effectively communicated to our employees its accounting policies and procedures. This has resulted in inconsistent practices. Further, the

Board of Directors does not currently have any directors who qualifies as an audit committee financial expert as defined in Item 407(d)(5)(ii) of Regulation S-B. Since these entity level programs have a pervasive effect across the organization, management has determined that these circumstances constitute a material weakness.

As of December 31 2009, we did not maintain effective controls over financial statement disclosure. Specifically, controls were not designed and in place to ensure that all disclosures required were originally addressed in our financial statements. Accordingly, management has determined that this control deficiency constitutes a material weakness.

This lack of internal controls over financial reporting resulted in numerous adjusting journal entries proposed by our independent auditor during their audit of the period ended December 31, 2009.

During the Company’s annual audit Management evaluated remediation plans related to the above internal control deficiencies. Management analyzed the costs and benefits of several different options to improve our internal controls over financial reporting. The following options for improving the controls were analyzed (i) hiring a qualified CFO with both GAAP and SEC reporting experience (ii) forming an internal audit department (iii) subscribing to GAAP and SEC reporting databases (iv) additional staffing to provide segregation of duties and a review infrastructure for financial reporting (v) An information technology department to provide security over our information and to help facilitate electronic filing. In the evaluation, Management estimated implementation of the proposed remediation plan within 1 to 2 years. It was concluded from our evaluation that the costs to implement the plan were greater than the benefits to be received, and Management therefore passed on implementation until operations of the Company have improved. Due to the current operating condition of the company, and the current and future outlook of the economic climate, we do not foresee the ability to adequately implement the remediation plan within the foreseeable future.

ITEM 9B. OTHER INFORMATION

The Company received $2,500,000 restricted funding from an external source (“the Lender”) to bring the Delhi field wells back into production and to satisfy certain obligations regarding the settlement of the Delhi lawsuit. The terms of the restricted funding were the issuance of two notes aggregating to $2,500,000 at an interest rate of 15% due and payable on June 30, 2010 (principal and interest), and the issuance of 200,000 shares of restricted common stock (the “Closing Shares”) valued at $7.50 per share as an inducement to loan the funds. If the principal and interest are not re-paid at the end of the one year period, the Lender will gain legal right and title to 5,000,000 penalty shares of restricted common stock valued at $7.50 per share (“Penalty Shares”). The Penalty Shares are being held by the Lender and will become the property of the Lender in the event of default. Also, the Company executed a term assignment of an overriding royalty interest in the Delhi Field equal to fifteen percent of eight-eights (25% of 8/8ths) of all revenue attributable to Hydrocarbons produced and saved from or attributable or allocable to the Delhi Field net of severance taxes for a period of 30 months ending on December 31, 2011. Further, if a total of $5,000,000 (to include the principal and interest repayment) is not paid at the end of the 30 month period, the Company will make a cash payment to cover the deficiency.

August 2009 Standby Equity Distribution Agreement

ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS

The following is a list of the directors and executive officers of the Company on December 31, 2008.

Name	Age	Position	Year First Elected or Appointed
Robert D. Johnson	63	Chairman of the Board, President and CEO	Became President May 1, 2008 and Chairman and CEO on July 28, 2008
Robert C. Johnson	65	CFO	Director November 1, 2008/CFO May 15, 2009
Harvey Pensack	85	Director	June 12, 2004
Ann Thomas	50	Director	September 15, 2009

Business Experience and Background of Directors and Executive Officers

Robert D. Johnson, CEO

Mr. Johnson joined the Company on May 1, 2008 and is a member of the Executive Committee of the Board of Directors. He has over 40 years of experience in the oil and gas sector. Mr. Johnson graduated with a BS in Petroleum Engineering from Louisiana State University in 1969, and upon graduation, he joined Amoco Production Company. In 1970, he entered the United States Army and served for nearly two years. He rejoined Amoco in 1971 and rose rapidly through the ranks. His final position was Regional Engineering Manager, managing over 250 engineers. He left Amoco in 1980 and joined Superior Oil Company as Division Drilling Engineering Manager for the western half of the United States. In 1981, he left Superior and formed Conquest Petroleum Incorporated as the Founder and Chief Executive Officer. Conquest secured funding to acquire 68,000 acres of leases in the state waters of Texas, promoted the acreage on 27 prospects to outside third parties, and had five discoveries. Later, Mr. Johnson divested the assets and dissolved the company in 1985 due to insufficient commodity prices. He formed Bannon Energy Incorporated in 1986 with an initial capitalization of $1,000. During the next ten years, Bannon acquired 12 sets of producing properties and drilled over 284 development wells. Mr. Johnson sold the assets of Bannon in 1996 for $38 million and other considerations. Mr. Johnson dissolved Bannon in February of 2001. From February of 2001 until May of 2008, when he joined the Company, Mr. Johnson was officially in full retirement.

Harvey M. Pensack, Director

After graduating Cum Laude from Clarkson University in 1944 with a BS in Mechanical Engineering, Mr. Pensack served in the military, finishing as a First Lieutenant in 1946. He spent seven years in the insurance industry, earning promotions and supervisory positions. However, he saw the potential in the young computer industry. In 1953, using his engineering training and entrepreneurial spirit, he founded Mitronics Inc., an innovative firm and manufacturer of hermetic ceramic to metal seals for the then-fledgling semiconductor industry. Mr. Pensack served as Chairman and CEO of Mitronics, which prospered. In 1970, Mitronics was merged into a public corporation to become Varadyne, Inc. Throughout the 1970s, 1980s, and 1990s, Mr. Pensack had an active career as a financial consultant specializing in insurance, business succession planning, and estate management. Throughout his career, Mr. Pensack has been a private investor who specializes in researching and analyzing potential investment choices with a focus on management personnel and growth opportunities.

Robert C. Johnson, Director/CFO

Mr. Johnson graduated with a Professional Degree in Petroleum Engineering from the Colorado School of Mines in 1966. He joined Amoco Production Co. after graduation and advanced through numerous engineering and management positions during his 19+ year tenure. His final position was as Regional Production Manager in Houston, where he was responsible for the production operations in eight states and the management of 2,800 professionals. He left Amoco in 1985 and joined Held By Production, Inc (HBP), where as President and COO, he was responsible for managing the oil and gas assets of a private individual with holdings in Texas, Louisiana, Kansas, and Utah. He formed a $25 million development drilling program while at HBP and served as the managing general partner. In 1989, Mr. Johnson purchased an old-line manufacturing company in Denver, Colorado (Cyclo Manufacturing Company) and merged a large portion of it into a publicly traded company in 2001. Mr. Johnson started a mattress manufacturing company in 1999, serving as Chairman and CEO, and sold his controlling interest in 2003. From 1992 to 1996, Mr. Johnson served on the Board of Bannon Energy Incorporated. He joined the Board of Directors of Conquest Petroleum Incorporated in November 2008 and assumed the role of CFO in May 2009.

Ann Thomas, Director

Currently, Ms. Thomas is President of Killian Capital Group with offices in Texas and New York City. Ms. Thomas began her career as a management trainee with Conoco in Houston, TX focused in the oil & gas industry. She later joined Azmi Corporation where she managed the US subsidiary of a Saudi Arabian company, based in Houston for the purpose of investing in oil & gas reserves in the US. Subsequently, Ms. Thomas joined Salomon Smith Barney where as Vice President; she initiated the company’s first institutional energy risk management department, headquartered in New York City. Ms. Thomas later served as an Investment Officer with Sedona Industries. In addition to managing a diversified portfolio, an internal fund was created and managed by Killian Capital Corp., a CTA (Commodity Trading Advisor), with Ms. Thomas as President, registered with the CFTC since November 1994. Ms. Thomas joined the Board in September 2009..

Involvement in Certain Legal Proceedings

The foregoing directors or executive officers have not been involved during the last five years in any of the following events:

•

Bankruptcy petitions filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;

Conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);

Being subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring or suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or

Being found by a court of competition jurisdiction (in a civil action), the Securities and Exchange Commission or the Commodities Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended or vacated.

Board Composition and Committees

Our business and affairs are organized under the direction of our board of directors, which currently consists of three members. The primary responsibilities of our board of directors are to provide oversight, strategic guidance, counseling and direction to our management. Our board of directors meets on a regular basis and additionally as required. Written board materials are distributed in advance as a general rule, and our board of directors schedules meetings with and presentations from members of our senior management on a regular basis and as required.

Our board of directors has established an audit committee, a compensation committee and a nominating/corporate governance committee. Our board of directors and its committees set schedules to meet throughout the year and also can hold special meetings and act by written consent under certain circumstances. Our board of directors has delegated various responsibilities and authority to its committees as generally described below. The committees will regularly report on their activities and actions to the full board of directors.

Audit Committee

The current members of our audit committee are Robert C. Johnson and Harvey Pensack. Robert C. Johnson is the chairman of the audit committee.

The audit committee of our board of directors oversees our accounting practices, system of internal controls, audit processes and financial reporting processes. Among other things, our audit committee is responsible for reviewing our disclosure controls and processes and the adequacy and effectiveness of our internal controls. It also discusses the scope and results of the audit with our independent auditors, reviews with our management and our independent auditors our interim and year-end operating results and, as appropriate, initiates inquiries into aspects of our financial affairs. Our audit committee has oversight for our code of business conduct and is responsible for establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or auditing matters, or matters related to our code of business conduct, and for the confidential, anonymous submission by our employees of concerns regarding such matters. In addition, our audit committee has sole and direct responsibility for the appointment, retention, compensation and oversight of the work of our independent auditors, including approving services and fee arrangements. Our audit committee also is responsible for reviewing and approving all related party transactions in accordance with our policies and procedures with respect to related person transactions.

Compensation Committee

The current members of our compensation committee are Ann Thomas, Robert C. Johnson. Ann Thomas is the chairman the compensation committee.

The purpose of our compensation committee is to have primary responsibility for discharging the responsibilities of our board of directors relating to executive compensation policies and programs. Among other things, specific responsibilities of our compensation committee include evaluating the performance of our chief executive officer and determining our chief executive officer’s compensation. In consultation with our chief executive officer, it will also determine the compensation of our other executive officers. In addition, our compensation committee will administer our equity compensation plans and has the authority to grant equity awards and approve modifications of such awards under our equity compensation plans, subject to the terms and conditions of the equity award policy adopted by our board of directors. Our compensation committee also reviews and approves various other compensation policies and matters.

Nominating/Corporate Governance Committee

The current members of our nominating/corporate governance committee are Robert D. Johnson and Ann Thomas. Robert D. Johnson is the chairman of the nominating/corporate governance committee.

The nominating/corporate governance committee of our board of directors oversees the nomination of directors, including, among other things, identifying, evaluating and making recommendations of nominees to our board of directors and evaluates the performance of our board of directors and individual directors. Our nominating/corporate governance committee is also responsible for reviewing developments in corporate governance practices, evaluating the adequacy of our corporate governance practices and making recommendations to our board of directors concerning corporate governance matters.

Limitation of Liability and Indemnification

We intend to enter into indemnification agreements with each of our directors and executive officers and certain other key employees. The form of agreement provides that we will indemnify each of our directors, executive officers and such other key employees against any and all expenses incurred by that director, executive officer or key employee because of his or her status as one of our directors, executive officers or key employees, to the fullest extent permitted by Texas law, our articles of incorporation and our bylaws (except in a proceeding initiated by such person without board approval). In addition, the form agreement provides that, to the fullest extent permitted by Texas law, we will advance all expenses incurred by our directors, executive officers and such key employees in connection with a legal proceeding.

Our articles of incorporation and bylaws contain provisions relating to the limitation of liability and indemnification of directors and officers. The articles of incorporation provide that our directors will not be personally liable to us or our stockholders for monetary damages for any breach of fiduciary duty as a director.

Our bylaws provide that we will indemnify our directors and officers to the fullest extent permitted by Texas law, as it now exists or may in the future be amended, against all expenses and liabilities reasonably incurred in connection with their service for or on our behalf. Our bylaws provide that we shall advance the expenses incurred by a director or officer in advance of the final disposition of an action or proceeding. Our bylaws also authorize us to indemnify any of our employees or agents and permit us to secure insurance on behalf of any officer, director, employee or agent for any liability arising out of their action in that capacity, whether or not Texas law would otherwise permit indemnification.

Shareholder Communications

Any shareholder of the Company wishing to communicate to the Board of Directors may do so by sending written communication to the board of directors to the attention of Mr. Robert D. Johnson, Chief Executive Officer, at the principal executive offices of the Company. The Board of Directors will consider any such written communication at its next regularly scheduled meeting.

Compliance with Section 16(a) of the Exchange Act:

Under the securities laws of the United States, the Company's directors, its executive officers and any persons holding more than 10% of the Company's common stock are required to report their ownership of the Company's common stock and any changes in that ownership to the Securities and Exchange Commission. Specific due dates for these reports have been established by rules adopted by the SEC and the Company is required to report in this Annual Statement any failure to file by those deadlines.

Based solely upon public reports of ownership filed by such persons and the written representations received by the Company from those persons, all of our officers, directors and 10% owners have satisfied these requirements during its most recent fiscal year.

Code of Ethics

We have not adopted a code of ethics to apply to our principal executive officer, principal financial officer, principal accounting officer and controller, or persons performing similar functions. We expect to prepare a Code of Ethics in the near future

ITEM 11.EXECUTIVE COMPENSATION

The following table sets forth the total compensation awarded to, earned by, or paid to our “principal executive officer,” and our other named executive officers for all services rendered in all capacities to us in 2009 and 2008, 2007 and 2006.

											Warrant
											and
Name and					Contract		Contract		Stock		Option		All Other
Principal			Year		Salary		Bonus		Awards		Awards		Compensation			Total
Position								-3		-4		-5		-6

W. Marvin Watson			2006		$	240,000		–		813,500	$	70,800	$	11,679		$	1,135,979
Chairman/President
Director of Development & Corporate Structure			2007		$	385,000		–		–	$	44,469	$	11,980		$	441,449
	(7	)(8)		2008	$	385,000		–		2,475,000	$	61,242	$	5,838		$	2,927,080

Robert D. Johnson				2008	$	300,000		–		861,234	$	942,641	$	–		$	2,103,875
Chief Executive Officer (1)(9)(16)
				2009	$	300,000		–		615,000	$	-	$	–		$	915,000

Robert Sepos				2006	$	300,000	$	200,000		–	$	–	$	14,921		$	514,921
VP/Chief Operating Officer				2007	$	300,000		–		–	$	–	$	19,677		$	319,677
	(10	)(11)(12)		2008	$	300,000		–		–	$	–			$	$	300,000

Dominick F. Maggio				2006	$	300,000	$	200,000		–	$	–	$	17,176		$	517,176
VP/Chief Information Officer				2007	$	300,000		–		–	$	–	$	23,584		$	323,584
	(10	)(11)(12)		2008	$	300,000		–		–	$	–	$	–		$	300,000

Robert C. Johnson
Chief Financial Officer
	(2	) (13)		2009	$	300,000		–		487,500	$	-	$	–		$	787,500

Arturo Henriquez
Chief Financial Officer
	(14	) (15)		2008	$	300,000		–		–	$	–	$	–		$	300,000

-1	Robert D. Johnson has deferred all compensation May 1, 2008 to September 30, 2008 and one half of his compensation from September 30, 2009 to December 31, 2009 to assist the Company with cash flows.
-2	Robert C. Johnson has deferred all his compensation from May 1, 2009 to September 30, 2009 and one half his compensation from September 30, 2009 to assist the Company with cash flows.
-3	Bonuses were components of Employee Agreements, the majority of which payments were deferred by all the Executives to assist the Company with cash flow requirements.
-4	Amounts represent the dollars recognized for financial statement reporting purposes with respect to the fiscal yearin accordance with SFAS No. 123(R). See Note 2 of the notes to consolidated financial statementsincluded elsewhere in this Registratio
-5	Amounts represent the dollars recognized for financial statement reporting purposes with respect to the fiscal yearin accordance with SFAS No. 123(R) excluding forfeiture estimates. See Note 2 of the notes to consolidated financial statementsinclude
-6	This column represents Company payments towards life insurance for executive officers and auto allowances capped at $1,000 monthly.
-7	W. Marvin Watson was the Director of Development & Corporate Structure from June 1, 2005 until he assumed the role of Chief Executive Officer effective October 3, 2007.
-8	W. Marvin Watson resigned as Chief Executive Officer effective July 28, 2008.
-9	Robert D. Johnson was Chief Operating Officer and President from May 1, 2008 and assumed role as Chief Executive Officer effective July 28, 2008.
-10	Robert Sepos served as the Company's Chief Financial Officer until October 29, 2007 when he assumed the role of Chief Operating Officer.
-11	Officers Maggio and Sepos deferred 2/3 of their salary from November 2006 to December 2007 to assist the Company with cash flows.
-12	As a part of the Company's 2008 restructuring Messrs. Maggio and Sepos were terminated
-13	Robert C. Johnson assumed the role of Chief Financial Officer in May, 2009
-14	Arturo Henriquez was the Chief Financial Officer from July, 2008 until April, 2009 when he resigned
-15	Arturo Henriquez deferred all his compensation from September 1, 2008 to April 17, 2009 when he resigned to assist the Company with cash flows.
-16	Robert D. Johnson returned options issued in 2008 to the Company

On October 3, 2007, the Company entered into an addendum to Mr. Watson’s employment agreement, elevating his position to Chief Executive Officer from Director of development and corporate structure. The agreement increased the initial term of employment by two years to October 2, 2011, continued automobile reimbursement and raised Mr. Watson’s base salary to $385,000. The base salary would increase to $435,000 after the first anniversary of the effective date of October 3, 2007 and to $485,000 after the second anniversary of the effective date. Mr. Watson was granted 3,300,000 shares of the Company’s common stock in 2008. Mr. Watson will be entitled to receive bonuses based on annual performance of the Company and at the discretion of the Board. On July 28, 2008, Mr. Watson was removed as Chairman and Chief Executive officer at an extraordinary meeting of the Shareholders. Mr. Watson had tendered his resignation the day before.

On May 1, 2008, the Company entered into an employment agreement with Robert D. Johnson to become President and Chief Operations Officer. On July 28, 2008, Mr. Johnson became the Chairman of the Board, President and Chief Executive Officer. Also on August 3, 2008, Mr. Arturo Henriquez entered into an employment agreement to become Chief Financial Officer. Mr. Arturo Henriquez resigned on April 17, 2009.

On May 1, 2009, the Company entered into an employment agreement with Robert C. Johnson to become Chief Financial Officer.

Messrs. Maggio and Sepos were terminated as part of a reorganization and restructuring of the Company. The Company has reached a settlement agreement with both Messrs Maggio and Sepos whereas Mr. Maggio signed a note to pay back the Company $300,000 with an 8% interest rate collateralized by stock in the Company and Mr. Sepos signed a note to pay back the Company $6,000 with an 8% interest rate collateralized by his stock in the Company. On December 2, 2008, the company received stock from Mr. Sepos in full payment of the principal and interest outstanding for both aforementioned notes.

Director Compensation

The following table sets forth the total compensation awarded to, earned by, or paid to each person who served as a director during fiscal year 2009 other than a director who also served as a named executive officer. Our directors who are not executive officers did not receive any cash compensation during 2009 for serving on our board of directors. We have a policy of reimbursing our directors for their reasonable out-of-pocket expenses incurred in attending Board and committee meetings. Pursuant to the terms of our 2005 Incentive Compensation Plan, each director upon appointment or election to the board is entitled to receive an option to acquire 150,000 shares of Common Stock on the date elected with an exercise price of $0.75 per share. In addition, for as long as the 2005 Incentive Compensation Plan remains in effect and shares of Common Stock remain available for issuance there under, each director serving on the Board shall automatically be granted an option to acquire 150,000 shares of Common Stock, with an exercise price of $0.75 per share, each year. This plan was subsequently changed to 50,000 warrants cumulative per year on November 19, 2008.

	Stock
Name	Awards (1)		Total
Ann Thomas	$	7,895	$	7,895
Harvey Pensack	$	150,000	$	150,000

Equity Benefit Plans

2005 Incentive Compensation Plan

The Company adopted the 2005 Incentive Compensation Plan on May 13, 2005.

Share Reserve . We reserved 5,000,000 shares of our common stock for issuance under the 2005 Incentive Compensation Plan on May 13, 2005. On March 21, 2007, the Board of Directors amended the Plan to increase the number of shares reserved for issuance thereunder to 15,000,000 shares. On December 5, 2007, the Board of Directors amended the Plan to increase the number of shares reserved for issuance there under to 30,000,000 shares. In general, to the extent that awards under the 2005 Incentive Compensation Plan are forfeited or lapse without the issuance of shares, those shares will again become available for awards. All share numbers described in this summary of the 2005 Incentive Compensation Plan (including exercise prices for options) are automatically adjusted in the event of a stock split, a stock dividend, or a reverse stock split.

Administration . The board of directors administers the 2005 Incentive Compensation Plan. The board of directors may delegate its authority to administer the 2005 Incentive Compensation Plan to a committee of the Board. The administrator of the 2005 Incentive Compensation Plan has the complete discretion to make all decisions relating to the plan and outstanding awards.

Eligibility. Employees, members of our board of directors and consultants are eligible to participate in our 2005 Incentive Compensation Plan.

Types of Award . Our 2005 Incentive Compensation Plan provides for the following types of awards:

	•	incentive and non-qualified stock options to purchase shares of our common stock; and
	•	restricted shares of our common stock.

Options. The exercise price for options granted under the 2005 Incentive Compensation Plan may not be less than 100% of the fair market value of our common stock on the option grant date. Optionee may pay the exercise price by using:

	•	cash;
	•	shares of our common stock that the Optionee already owns;
	•	an immediate sale of the option shares through a broker approved by us; or
	•	any other form of payment as the compensation committee determines.

Restricted Shares. In general, these awards will be subject to vesting. Vesting may be based on length of service, the attainment of performance-based milestones, or a combination of both, as determined by the plan administrator.

Amendments or Termination. Our board of directors may amend or terminate the 2005 Incentive Compensation Plan at any time. If our board of directors amends the plan, it does not need to ask for stockholder approval of the amendment unless required by applicable law.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Beneficial ownership is determined in accordance with the rules of the SEC, and generally includes voting power and/or investment power with respect to the securities held. Shares of common stock subject to options currently exercisable or exercisable within 60 days of December 31, 2009 are deemed outstanding and beneficially owned by the person holding such options for purposes of computing the number of shares and percentage beneficially owned by such person, but are not deemed outstanding for purposes of computing the percentage beneficially owned by any other person. Except as indicated in the footnotes to these tables, and subject to applicable community property laws, the persons or entities named have sole voting and investment power with respect to all shares of our common stock shown as beneficially owned by them.

The following table sets forth certain information known to us as of December 31, 2009 with respect to each beneficial owner of more than five percent of the Company’s common stock. The percentage ownership is based on 34,980,718 shares of common stock outstanding as of December 31, 2009.

Name and Position	Business Address	Equity		Warrants		Options		Preferrred		Total		Percent of			Total Outstanding
								Stock				Class			Shares
																34,980,718
Harvey Pensack	7309 Barclay Court
Director	University Park, FL 34201
	Individually Owned		2,074,322		110,938		45,000		181,818		2,412,078		6.90	%

Robert D. Johnson	13606 Bermuda Dunes Court
CEO	Houston, TX 77069
	Individually Owned		6,518,789				57,416				6,576,205		18.80	%

Robert C. Johnson
CFO	7085 W. Belmont
05/01/09 - current	Littleton, CO 80123
	Individually Owned		4,049,587								4,049,587		11.58	%

Ann Thomas
Director	546 Fifth Avenue, 14th Floor
09/09 - current	New York, New York 10036
	Individually Owned		62,346								62,346		0.18	%

Arturo F. Henriquez
CFO	2 Wenoah Place
09/01/08 - 04/17/09	The Woodlands, TX 77389
	Individually Owned		2,392,741								2,392,741		6.84	%

All directors and executive officers as a group (4) persons			15,035,439		110,938		102,416		181,818		15,492,957		44.29	%

The following table sets forth beneficial ownership of the Company’s common stock as of December 31, 2009 for each of the named executive officers and directors individually and as a group. The percentage ownership is based on 34,545,867 shares of common stock outstanding as of December 31, 2009.

Five Percent or More
Name and Position	Business Address	Equity		Warrants		Options		Preferred		Total		Percent of
												Class
Maxim TEP, Limited	1 London Wall		2,170,000								2,170,000		6.20	%
	London, EC 2Y 5AB

Greater Europe Fund Limited	Kleinwort Benson House		4,245,732								4,245,732		12.14	%
	PO Box 76 Wests Center
	St Helier, Jersey JEF 8PQ

Harvey Pensack (1)	7309 Barclay Court
Director	University Park, FL 34201
	Individually Owned		2,074,322		110,938		45,000		181,818		2,412,078		6.90	%

Robert D. Johnson (6)	13606 Bermuda Dunes Court
CEO	Houston, TX 77069
	Individually Owned		6,518,789				57,416				6,576,205		18.80	%

Robert C. Johnson (9)
Director	7085 W. Belmont
	Littleton, CO 80123
	Individually Owned		4,049,587								4,049,587		11.58	%

Arturo F. Henriquez
CFO	2 Wenoah Place
	The Woodlands, TX 77389
	Individually Owned		2,392,741								2,392,741		6.84	%

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

Related Party Transactions

During 2009, the Company entered into notes payable totaling $55,000 with one officer. These notes bear interest at a fixed rate of 9% and are unsecured. Upon maturity and in lieu of receipt of payment of all or a portion of the outstanding principal and interest, the note holder may convert their note, in whole or in part, into shares of the Company’s common stock determined by the closing price of the shares at that date. The terms of the transaction were on terms that would have been made between unaffiliated third parties..

Director Independence

The Company is listed on the OTC Bulletin Board. While the OTC Bulletin Board does not maintain director independence standards, the Company is taking the necessary steps to qualify as having independent directors under the guidelines of the AMEX.

ITEM 15. EXHIBITS

Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

Indemnification of Directors and Officers

Our Articles of Incorporation provide that we shall indemnify, to the fullest extent permitted by Texas law, any of our directors, officers, employees or agents who are made, or threatened to be made, a party to a proceeding by reason of the former or present official position of the person, which indemnity extends to any judgments, penalties, fines, settlements and reasonable expenses incurred by the person in connection with the proceeding if certain standards are met. At present, there is no pending litigation or proceeding involving any of our directors, officers, employees or agents where indemnification will be required or permitted. Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to our directors, officers and controlling persons pursuant to the foregoing provisions, or otherwise, we have been advised that, in the opinion of the Securities and Exchange Commission (the SEC or Commission), such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.

Our Articles of Incorporation limit the liability of our directors to the fullest extent permitted by the Texas Business Corporation Act. Specifically, our directors will not be personally liable for monetary damages for breach of fiduciary duty as directors, except for (i) any breach of the duty of loyalty to us or our stockholders, (ii) acts or omissions not in good faith or that involved intentional misconduct or a knowing violation of law, (iii) dividends or other distributions of corporate assets that are in contravention of certain statutory or contractual restrictions, (iv) violations of certain laws, or (v) any transaction from which the director derives an improper personal benefit. The Articles do not limit liability under federal securities law.

Safe Harbor - Forward Looking Statements

When used in this Annual Report on Form 10-K, in documents incorporated herein and elsewhere by us from time to time, the words "believes," "anticipates," "expects" and similar expressions are intended to identify forward-looking statements concerning our business operations, economic performance and financial condition, including in particular, our business strategy and means to implement the strategy, our objectives, the amount of future capital expenditures required, the likelihood of our success in developing and introducing new products and expanding the business, and the timing of the introduction of new and modified products or services. These forward looking statements are based on a number of assumptions and estimates which are inherently subject to significant risks and uncertainties, many of which are beyond our control and reflect future business decisions which are subject to change.

A variety of factors could cause actual results to differ materially from those expected in our forward-looking statements, including those set forth from time to time in our press releases and reports and other filings made with the Securities and Exchange Commission. We caution that such factors are not exclusive. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements and readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this Annual Report on Form 10-K. We undertake no obligation to publicly release the results of any revisions of such forward-looking statements that may be made to reflect events or circumstances after the date hereof, or thereof, as the case may be, or to reflect the occurrence of unanticipated events.

SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: August 2, 2010	CONQUEST PETROLEUM INCORPORATED

	By:	/s/ Robert D. Johnson
		Robert D. Johnson
		Chief Executive Officer