Edgar Filing: Conquest Petroleum Inc

Unassociated Document

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 end period ended: December 31, 2008

¨	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

The Woodlands, 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 April 15, 2009: 130,084,869 shares.

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

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

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

The Company was not publicly trading at the end of the quarter ended June 30, 2008 and therefore no aggregate market value of the voting and non-voting common equity held by non-affiliates could be determined.

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 The Woodlands, 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 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. Conquest 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. Conquest 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, Louisiana, Arkansas and New Mexico.

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 is exploitation of its fields by investing in low risk workover programs on existing wells, monetize significant upside in workover wells on already proved assets, and develop proved developed non-producing wells into proved developed producing (PDPs) assets with no associated exploration risk. Conquest has over 32 existing wells in the Delhi and Belton fields with expected full production of 538 Bbl/d and 300 Mcf/d. This phase is highly dependent on the Company’s ability to secure funding from debt and equity sources.

Currently, the Company has active operations on its fields located in Louisiana and Kentucky. The Company began an active fourteen well workover program on its largest field, the Delhi Field in Louisiana. Of the fourteen, seven will be completed in the Mengel Sand and three will completed in the Z Sand. 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 17 well workover program in its Belton Field in Kentucky. Due to limited funding, as of December 2008, the Company has only partially begun these planned 2008 activities and foresees the plan to extend into 2009, if funding is obtained.

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 (PUDs) assets into proved developed and producing (PDPs) assets with no associated exploration risk. The Company has identified over 300 infill prospects in the Marion, Delhi, and Belton fields with expected full production of 480 Bbl/d and 11,800 Mcf/d. It has identified three development oil opportunities in the Z Sand and two development oil opportunities in the Mengel Sand in its Delhi field. It has identified 200 development gas opportunities in its Marion field. And it has identified 24 development gas opportunities in the New Albany Shale and 24 development oil opportunities in the McCloskey Sand in its Belton field.

All of the planned development drilling and enhancements assume that the Company is successful in securing its 2009 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 2009 and 2010 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.

RESTRUCTURING - Employees

During 2008, the Company underwent a thorough restructuring in all aspects of its business from employees, consultants, office services, and field services. In January of 2008, the company had 35 full-time employees and 8 recurring consultants. As of December 31, 2008, Conquest and its subsidiaries had a total of 12 full-time employees and one recurring field consultant. There are five full-time employees at the Company’s corporate headquarters in The Woodlands, Texas and 8 in its subsidiaries.

ITEM 1A. RISK FACTORS

You should carefully consider each of the risks described below, together with all of the other information contained in this report, before deciding to invest in our securities. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected and you may lose all or part of your investment.

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 operating losses for the fiscal years ended December 31, 2008 and 2007 were $6.03 million and $29.99 million, respectively. In addition, we expect to incur substantial operating expenses in connection with our natural gas and oil exploration and development activities. As a result, we may continue to experience negative cash flow for at least the foreseeable future and cannot predict when, or even if, we might become profitable.

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 contain 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. 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 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.

A substantial percentage of our proved reserves consists of undeveloped reserves.

As of the end of our 2008 fiscal year, approximately 35% of the Delhi Field Properties’ proved reserves, 65% of the Belton Field Properties’ proved reserves and 74% of the Marion Field Properties’ proved reserves were classified as proved undeveloped reserves. These reserves may not ultimately be developed or produced, or quantities developed and produced may be smaller than expected, which in turn may have a material adverse effect on our results of operations.

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 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 to the point of production;

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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 for which we have 3-D seismic data;

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our ability to acquire additional 3-D seismic data;

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our ability to identify and acquire new exploratory 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 exploratory projects and 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.

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 experience and 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. The loss of Mr. Johnson could have a material adverse effect on our operations. Although we have an employment agreement with Mr. Johnson which provides for notice before he may resign and contains non-competition and non-solicitation provisions, we do not, and likely will not, maintain key-man life insurance with respect to him or any of our employees.

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 currently is 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 do not operate certain of the properties in which we have an interest. As a result, we have 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 do 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 writedown 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 is 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 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 do not operate all of the properties 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 impact 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 has 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 process of becoming 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.

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 physically sweeps the displaced oil to adjacent production wells. The Company’s 2009 development program involves bringing into production 10 existing wells, 7 in the Mengel Sand and 43 in the Z-Equivelent Sand as well as 5 infill drilling possibilities of proved but undeveloped opportunities, 3 in the Z- Equivelent Sand and 2 in the Mengel Sand. In 2008, 4 existing wellbores were converted to water injection wells which will enhance the efficiency of the waterflood 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 Interest in this field.

The Marion Field - Union Parish, Louisiana

In December 2005, the Company leased 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 700-750 MCF a day from approximately 500 wells from the Arkadelfia Gas Zonesand, and with proved developed reserves of 1,788 MMcf. 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. The field can be optimized at 10 acre spacing, creating 800 development opportuities. The Company forecasts a 300 well program for the next 2 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 should be noted that in 2005, state records indicated that the Monroe Gas Field produced over 7.0 Tcf. 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, in December 2005, the Company 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 this deeper zone. The Company believes that a remedial program to fix the infrastructure from pipeline leakages to hub compressors can result in up to 50% increased 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 McClosky 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 five known 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 McClosky zone) and (2) a deep Silurian oil-bearing zone. The Company is in the process of bringing into production 17 existing upper McCloskey wells. The Company’s 2009 and 2010 drilling program includes the drilling of 24 New Alabany Shale wells and 24 Lower McCloskey wells and 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.

Hospah, Lone Pine & Clovis Fields - McKinley County, New Mexico

In 2006 and 2007, the Company acquired mineral rights leases on approximately 1,280 acres in the Hospah Field and Lone Pine Field in McKinley County, New Mexico. The Hospah Field was discovered in 1924 and has produced oil for many years. The Upper Hospah Sandstone of Cretaceous Age produced 5 million barrels by 1974. The Lone Pine Field was found just south of Hospah in 1970 and oil was discovered from the productive Dakota Sandstone at a depth of between 2,500 and 3,800 feet. Most of the oil development in these fields was done by Tenneco. Oil and gas production from the Hospah Sandstones reservoirs from 1927 to 2005 has yielded nearly 22 million barrels of oil and nearly 53 Mcf of gas. The company is currently evaluating the prospects of this field. The Company is currently negotiating to acquire a 100% Working Interest and an 80% Net Revenue Interest on an approximately 1,200 acres in the Clovis field.

The Company divested the following fields in 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 85% Working Interest and 57.25% 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 Smackove, Ouachita County, Arkansas

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2008. “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
Hospah–NM	100%	0	0	1,280	1,280	1,280	1,280
Belton– KY	100%	110	110	9,215	9,215	9,325	9,325
Total		10,930	10,908	22,575	22,538	33,505	33,446

Oil and Natural Gas Reserves

The reserves as of December 31, 2008 were derived from reserve estimates prepared by independent reserve engineers; Mark Newendorp for the Delhi Field and the Marion Field and The Daniel Company, LLC for the Belton Field. The PV-10 value was derived using constant prices as of the calculation date, 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, 2008.

	Proved Reserves
	Developed	Undeveloped	Total
Oil and condensate (Bbls)	1,151.73	835.58	1,987.31
Natural gas (MMcf)	2,983.88	7,618.00	10,601.88
Total proved reserves (BOE)	1,649.05	2,105.33	3,754.38
PV-10 Value (MM)	$ 26,635.58	$ 20,270.12	$ 46,905.70

		Probable Reserves
		Total
Oil and condensate (Bbls)		245.20
Natural gas (MMcf)		5,617.18
Total proved reserves (BOE)		1,181.40
PV-10 Value (1)		$ 16,292.00

(1)	The PV-10 value as of December 31, 2008 is pre-tax and was determined by using the December 31, 2008 sales prices, which weighted averaged $42.68 per Bbl of oil, $6.71 per Mcf of natural gas. 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 measure to the most directly comparable GAAP financial measure (standardized measure of discounted future 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.

	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.

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, 2008.

	Total
	Gross	Net
Oil	38	34.1
Natural gas	515	515
Total	553	549.1

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.

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:

	Year Ended December 31,
	2008	2007
Interconn Resources, Inc. (1)	62%	39%
Lion Oil Trading & Transportation, Inc. (1)	24%	18%
Plains Marketing, LP (1)	-	11%
Orchard Petroleum, Inc. (2)	14%	32%

(1)	The Company does not have a formal purchase agreement with this customer, but sells production on a month-to-month basis at spot prices adjusted for field differentials.
(2)	Orchard Petroleum, Inc. is the operator of the Company’s wells in California and sells production on the Company’s behalf to Kern Oil & Refining, Co. and Aera Energy, LLC.

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 are 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. Principal defendants in the suit, in addition to the Company, include the Company’s indemnities including McGowan Working Partners, MWP North La, LLC., Murphy Exploration & Production Company, Ashley Investment Company, Eland Energy, Inc. and Delhi Package I, Ltd. The Company believes that it has meritorious defenses with regard to the plaintiffs’ claims and, thus, with regard to the extent of its monetary exposure under its indemnity obligation. The Company has and continues to defend the suit vigorously. Conquest has paid over $500,000 to pay legal fees and remediation costs. The central issue is contamination of the groundwater at the Delhi Field. Plaintiffs are landowners that claim the groundwater is polluted and needs to be extracted from the ground through a pumping process and disposed of remotely. Plaintiff has made a settlement offer to the Company of $6 million, which was rejected. The plaintiffs made a second settlement offer of $3 million. The Company counter offered to pay for the remediation but no cash in addition to the remediation costs under 29-B standards. No settlement has been reached. A trial date has been set for July 1, 2009. The company, with the legal fees and remediation already done and in process, believes its future exposure will be only legal bills and minor remediation. The Company granted McGowan Working Partners a first mortgage position on the field as they have been representing the Company in the litigation and overseeing the remediation and they are a party the Company agreed to indemnify when it purchased the field from them. The Company believes its total exposure based upon information currently available is $750,000 which is currently accrued.


·	Vanguard Energy Services sued for $340,000 for use of their drilling rigs in 2006 and 2007. This $340,000 is an account payable and the Company is in the process of negotiating in conjunction with a suit filed against a sister company, Recompletion Financial Corporation.

Recompletion Financial Corporation is a sister company of Vanguard with the same legal representation. Recompletion was hired as a marketing and financial company to raise funds and the Company paid over a million dollars in 2005 with no work done. In addition, there is a breach of contract as they used and employed our proprietary technology barring them from certain geographical locations including China. They have been sued for breach of contract and misappropriating the Company’s property for $2,000,000.

·	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 2008 and 2007.

·	Anthony Austin, a former employee, was let go in January 2008 after working 3 months and has filed a claim for $1,000,000. Mr. Austin’s attorney has since withdrawn from the case and on April 14, 2009, the court granted a motion for directed verdict in Conquest’s favor.

Don Shein, a former employee, is claiming back salary, severance expenses and commissions that do not coincide with our accounting and his employment contract. He also lent the Company $100,000. We have come to an agreement whereby Mr. Shein will extend his $100,000 loan and the Company will facilitate the issuance of 375,000 shares of the company’s common stock by a third party shareholder. The Company has accrued a liability and corresponding expense for $281,250, in addition to his $100,000 note.

·	The former CEO, Marvin Watson, is claiming expenses, past salary and severance in regards to his employment. The Company sees no merit in his claim and will defend itself vigorously.

·	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.

ITEM 4 SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS

No matters were submitted to the vote or consent of the holders of the outstanding shares of our common stock during the quarter ended December 31, 2008.

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, 2008 and 2007 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, Kentucky and New Mexico.

Going Concern

The Company’s auditors have concluded there is substantial doubt about our ability to continue as a going concern specifically if the Company is unable to secure adequate funding in 2009.

The Company has done much to alleviate financial pressures from debt service by converting or repaying substantial portions of our outstanding debt and interest and by lowering our overall cash cost of operations through the significant reduction of personnel and other general cost cutting measures. In the twelve months ended December 31, 2008, the Company has paid off and/or converted over $51.0 million in principal and interest owed related to indebtedness. Concurrently, in the same time period, the Company has undergone a major cost restructuring in an effort to streamline operations and transform the Company into an efficient operation. It has eliminated over 35 contracted and non contracted personnel at both the corporate and field levels with annualized savings of over $3.5 million. The cost reductions extended to consulting services and day to day operating costs which amounted to approximately $2.1 million in annual savings of the total estimate that will be saved. Management believes that the reduction in debt and its enhanced balance sheet in conjunction with the cost restructurings should allow the Company to raise additional financings. In addition, management continues to negotiate to settle certain trade payables with stock, deferral of certain scheduled payments, and from 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.

Nonetheless, the Company has no future borrowings or funding sources available under existing financing arrangements as 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, as well as significant. In addition, given dropping commodity prices, lack of funding alternatives and a worsening financial environment, the Company is under significant liquidity constraints that hinder its ability to continue as a going concern.

Results of Operations

Twelve Months Ended December 31, 2008 Compared to the Twelve Months Ended December 31, 2007

Oil and Natural Gas Revenues: Oil and natural gas revenues for the twelve months ended December 31, 2008 and 2007 were $1,822,893 and $1,852,365, respectively. A decrease of $360,860 was attributed to the disposition of the Holt Bryant formation in the Delhi Field in May 2007 and the shutting in of the remaining wells in the Delhi Field during the 2008 period while the Company develops a new water flood program for the field. The Delhi Field had revenues for the 2008 and 2007 periods of nil and $360,860, respectively. We brought production back on line for three wells in the Delhi Field during the first quarter of 2009. The decrease was offset by an increase in revenue of $370,315 in the Marion Field to $1,739,874 for the twelve months ended December 31, 2008 compared to the same time period in 2007 of $1,373,094 due to natural gas price increases and marginal increased production. Revenue during 2008 was further increased by $177,849 from wells drilled and put in production in the Stephens Field during 2008 as well as $56,361 from wells put into production in the Belton Field in 2008.

Drilling Revenue: Drilling revenue during the twelve months ended December 31, 2008 was nil and the Company does not expect revenue in the future as it elected to no longer provide drilling services to outside third parties. Drilling revenue for the twelve months ended December 31, 2007 was $329,018. The Company’s Tiger Bend Drilling, LLC subsidiary drilled two wells in the Stephens Field, of which the Company holds a 24% working interest. The $329,018 in drilling revenue corresponds to the billings to the other working interest partners for drilling services. The drilling company sold its drilling rigs 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 no longer provide any drilling services to third parties.

License Fees, Royalties & Related Service Revenue: License fees, royalties and related services for the twelve months ended December 31, 2008 and 2007 were $163,458 and $257,500, respectively. This decrease was due to the sale of lateral drilling technology equipment for $228,000 in the 2007 period and no corresponding sales in the 2008 period. The remaining fees were associated with the granting of sectional and regional licensing of the Company’s proprietary lateral drilling technology. The Company does not anticipate further revenue from this business segment.

Production and Lease Operating Expenses: Production and lease operating expenses for the twelve months ended December 31, 2008 and 2007 were $1,295,693 and $1,664,279, respectively. This decrease was attributed to the first quarter 2008 including several initial well workovers of $713,330 and the repair and maintenance of the existing infrastructure of $273,125 on acquisitions of the Days Creek, Delhi and Marion Fields. Operations labor costs also decreased in the Marion, Days Creek and Delhi Fields due to staff reductions in those fields.

Drilling Operating Expenses: Drilling operating expenses for the twelve months ended December 31, 2008 and 2007 were $4,628 and $1,059,168, respectively. During the 2007 period the Company’s drilling subsidiary Tiger Bend Drilling, LLC began incurring preparation costs which were expensed as it prepared to begin drilling wells for the Company in Arkansas in second and third quarters of 2007. During the 2008 period the Company’s drilling subsidiary incurred minimal operating costs as it wrapped up from completing the drilling of twelve wells for the Company in Arkansas during 2007. 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.

Exploration Costs: Exploration costs for the twelve months ended December 31, 2008 and 2007 were nil and $458,650, respectively. This decrease was due to management’s election to curtail exploration activities efforts and focus its efforts on recompletion and workover wells. The Company plans to “farm out” all exploratory efforts to third party prospective partners.

Depletion, Depreciation and Amortization: Depletion, depreciation, and amortization for the twelve months ended December 31, 2008 and 2007 was $1,993,100 and $1,555,939, respectively.

Impairment of Oil and Natural Gas Properties. Impairment of oil and natural gas properties for 2008 and 2007 was $5,291,298 and $250,000, respectively. Management performed its impairment evaluation of its long lived assets and determined that the Belton Field, Marion Field and Days Creek Field required an impairment charge of $1,114,737, $4,000,051 and $87,642, respectively, and impairment of $88,868 for rig equipment, due to the future cash flows from the Company’s interest in this field not being able to cover the cost basis of this property.

Environmental Remediation Costs: This is associated to the Thomas, Raymond et al Ashley Investment class action lawsuit in the Delhi Field. The Company has proactively remediated the contamination it did not cause in an effort to reach a favorable settlement in the aforementioned lawsuit.

General and Administrative Expense: Non equity based general and administrative or “overhead” decreased by over 38% to $3,600,472 for the twelve months ended December 31, 2008 from $5,953,244 in the same period in 2007, a decrease of $2,352,772, as a result of a proactive cost reduction and restructuring program started in the first quarter of 2008 that continues to present day. In these periods, total salaries decreased by 54% to $1,522,913 for the twelve months ended December 31, 2008 from $3,316,988 in the same comparable period in 2007, saving the Company approximately $1,800,000. There were also significant cost reductions in finance costs, professional fees, general and administrative support costs and travel and entertainment. This decrease was offset by an increase in legal fees, primarily $525,325 in legal fees related to the defense of the Thomas, Raymond et al Ashley Investment class action lawsuit in the Delhi Field and over $360,000 in legal fees related to the Form 10 registration and the Greater European Fund debt negotiations and South Belridge asset sale. Total cash and non cash based general and administrative expenses for the twelve months ended December 31, 2008 and 2007 were $12,066,402 and $8,492,384, respectively. The majority of the net increase was the result of non cash stock based compensation totaling $8,939,263 for the 12 months ended December 31, 2008 compared to $2,539,140 in the same period in 2007. Of this, 4,448,312 shares of common stock valued at $0.75 per share, or $3,336,234, were issued to the current CEO and former CEO, $3,375,000 from the issuance of 4,500,000 shares to consultants for professional services rendered, 2,774,156 cashless stock options with a strike price of $0.75 per share valued at $1,012,241 to the current CEO and two other employees, 900,000 cashless stock options with a strike price of $0.75 per share valued at $367,455 to Directors and 500,000 shares of common stock valued at $0.75 per share, or $375,000, were issued to a law firm and investment bank for services rendered. This was compared to 2,500,000 shares of common stock valued at $0.75 per share, or $1,875,000, to the former CEO in 2007, 650,000 cashless stock options with a strike price of $0.75 per share valued at $192,240 to employees, and 1,200,000 cashless stock options with a strike price of $0.75 per share valued at $471,900 to Directors in the same period in 2007.

	Twelve Months Ended			Twelve Months Ended
	December 31, 2008			December 31, 2007		Difference			% Change
Compensation	$	1,522,913		$	3,316,988	$	(1,794,075	)		-54	%
Building & Equipment Costs	$	173,878		$	192,937	$	(19,058	)		-10	%
Commissions	$	272,958		$	337,500	$	(64,542	)		-19	%
Legal	$	962,706		$	459,469	$	503,237			110	%
Accounting	$	326,953		$	478,198	$	(151,245	)		-32	%
Consulting Services	$	(17,088	)	$	485,971	$	(503,059	)		-104	%
Gen & Admn Support Costs	$	412,876		$	234,044	$	178,832			76	%
Travel & Entertainment	$	(88,825	)	$	293,206	$	(382,031	)		-130	%
Insurance	$	34,101		$	154,932	$	(120,831	)		-78	%
Total Non Equity Based G&A	$	3,600,472		$	5,953,244	$	(2,352,772	)		-40	%

Gain on Extinguishment of Debt: The Company had a gain of $400,000 during the twelve months ended December 31, 2008. The gain was attributable to the retirement of $6.3 million dollars in debt and accrued interest secured by a 75% working interest in the Days Creek Field that was exchanged for relief of the debt.

Impairment of LHD Patented Technology: 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 had performed an impairment analysis of its patented lateral drilling technology in the third quarter ending September 2008 and determined $4,034,989 impairment was required. The Company’s basis for such an impairment stemmed from the then recent and unprecedented financial environment affecting the world and the Company and the ever increasing restrictions on credit, equity and funding opportunities in general.

Interest Expense, net: Interest expense, net for the twelve months ended December 31, 2008 and 2007 was $2,222,429 and $4,254,448, respectively. Interest expense related to debt decreased significantly as a result of the conversion of $4.0 million of notes payable and accrued interest into common and preferred stock. The Company also relieved $6.3 million in convertible debt and accrued interest by delivering a 75% working interest in the Days Creek Field during May of 2008 to the note holders. In addition, the Company renegotiated its production payment payable with BlueRock in May of 2008 to reduce the interest rate from 18% to 8%, saving the Company approximately $100,000 in interest per quarter.

Other Miscellaneous Income (Expense), net: The majority of this expense is attributed to settlement with a former employee of and accrual for future losses of $607,932, $548,264 settlement with a former director and warrants issued for debt extensions and a loss on conversion of debt of $543,722. This was offset by $602,879 from the gain on the sale of wellbores in the Delhi and Belton Fields.

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 21,700,000 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 $22,835,777.

Income Taxes: There is no provision for income tax recorded for either the 2008 or 2007 periods due to operating losses in both periods. The Company has available Federal income tax net operating loss (“NOL”) carry forwards of approximately $71 million at December 31, 2008. 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, 2008 of $6,029,503 and a net loss of $29,985,540 for the same period in 2007 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, 2008, the Company had a working capital deficit of $11,397,281 compared to a working capital deficit of $12,701,247 at December 31, 2007. Current liabilities decreased to $11,714,205 at December 31, 2008 from $15,028,178 at December 31, 2007. The Company significantly reduced its liabilities including debt by over $51 million through debt repayment, asset sales, restructuring and debt conversions.

Net cash used in operating activities totaled $964,344 and $6,096,496 the twelve months ended December 31, 2008 and 2007, respectively. Net cash used in operating activities for the 2008 period consists primarily of the net loss from continuing operations of $26,852,644. This was primarily offset by non-cash expenses due to stock based compensation valued at $11,068,330, an impairment of the LHD patent technology of $4,034,989, impairment of oil and gas properties of $5,291,298, amortization of debt discount of $523,352 and depletion, depreciation and amortization of $1,993,100. The reduction in cash used in operating activities in the 2008 period as compared to the 2007 period was primarily due to the cost reductions and restructurings, the reduction in salaries and wages, and from the reduction in administrative costs and travel and entertainment, and finance costs and the increase in common stock used to pay for services instead of cash.

Net cash provided by investing activities totaled $1,341,505 for the twelve months ended December 31, 2008, compared to cash used of $2,451,898 for the twelve months ended December 31, 2007. Net cash provided by investing activities for the 2008 period consists primarily of $1,215,000 from proceeds from the sale of wellbores in the Delhi Field and interest in specific wells in the Belton Field, and $675,000 from the sale of net revenue interests in certain fields. These 2008 cash inflows were offset by capital expenditures for oil and natural gas properties of $582,799.

Net cash provided by financing activities totaled $2,198,265 for the twelve months ended December 31, 2008, compared to $3,709,299 for the twelve months ended December 31, 2007. Net cash provided by financing activities for the 2008 period consists of proceeds from the sale of common stock of $1,350,598, and proceeds from new borrowings of $850,000, offset by payments on notes payable of $2,333.

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

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements ”. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, where fair value has been determined to be the relevant measurement attribute. This statement is effective for financial statements of fiscal years beginning after November 15, 2007. The Company does not expect a material impact from SFAS No. 157 on its consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, “ The Fair Value Option for Financial Assets and Financial Liabilities including an amendment of FASB Statement No. 115 .” The new standard permits an entity to make an irrevocable election to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. Changes in fair value would be recorded in income. SFAS No. 159 establishes presentation and disclosure requirements intended to help financial statement users understand the effect of the entity’s election on earnings. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007. The Company does not expect a material impact from SFAS No. 159 on its consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “ Business Combinations ”. SFAS No. 141(R) establishes principles and requirements to recognize the assets acquired and liabilities assumed in an acquisition transaction and determines what information to disclose to investors regarding the business combination. SFAS No. 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual period beginning after December 15, 2008.

In December 2007, the FASB issued SFAS No. 160, “ Non-controlling Interests in Consolidated Financial Statement—amendments of ARB No. 51.” SFAS No. 160 states that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity. The statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Company currently has no subsidiary subject to this standard and does not expect a material impact from SFAS No. 160 on its consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “ Disclosures about Derivative Instruments and Hedging Activities ”. SFAS No. 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. The provisions of SFAS No. 161 are effective for the fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the impact of adopting SFAS No. 161 on its consolidated financial statement disclosures.

In May 2008, the FASB issued FASB Staff Position APB 14-1, “ Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) ”. APB 14-1 requires the issuer to separately account for the liability and equity components of convertible debt instruments in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The guidance will result in companies recognizing higher interest expense in the statement of operations due to amortization of the discount that results from separating the liability and equity components. APB 14-1 will be effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting APB 14-1 on it consolidated financial statements.

Recently Adopted Accounting Pronouncements

In September 2006, the FASB issued Interpretation No. 48, “ Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109 ,” which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. Under FIN 48, the Company is required to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If the tax position meets the “more likely than not” recognition threshold, it is then measured and recorded at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The adoption of FIN 48 did not have a material effect on the Company’s consolidated financial position or results of operations.

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 SFAS No. 142, "Accounting for Goodwill and Other Intangible Assets.” 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 had performed an impairment analysis of its patented lateral drilling technology in the third quarter ending September 2008 and determined $2,041,894 impairment was required. The Company’s basis for such an impairment stemmed from the then recent and unprecedented financial environment affecting the world and the Company and the ever increasing restrictions on credit, equity and funding opportunities in general (see Note 6).

The net capitalized costs of proved oil and natural gas properties are limited to an “impairment test” based on the estimated future reserves, discounted at 10% per annum, from proved oil and natural gas reserves based on current economic and operating conditions. If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization.

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

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 in accordance with SFAS No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets”. 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.

Stock based compensation

Beginning January 1, 2006, the Company adopted SFAS No. 123(R), “Accounting for Stock Based Compensation,” to account for its Incentive Compensation Plan (the “2005 Incentive Plan”). SFAS No. 123(R) 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 required by EITF Issue 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services.” In accordance with EITF 96-18, 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, 2008 and 2007 as all potentially dilutive common stock equivalents are anti-dilutive. Under SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” entities that have issued mandatorily redeemable shares of common stock or entered into forward contracts that require physical settlement by repurchase of a fixed number of the issuer’s equity shares of common stock in exchange for cash shall exclude the common shares that are to be redeemed or repurchased in calculating basic and diluted earnings per share. For the twelve months ended December 31, 2008, the Company excluded 230,833 weighted average common share equivalents outstanding for shares issued with put options that were recorded as a liability within accrued liabilities, from its earnings per common share calculation.

Income Taxes

Under SFAS No. 109, “Accounting for Income Taxes,” 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


	PAGE
Conquest Petroleum Incorporated –
Report of Independent Registered Public Accounting Firm		28
Balance Sheets at December 31, 2008 and 2007		29-30
Statements of Operations for the Years Ended December 31, 2008 and 2007		31
Statements of Cash Flows for the Years Ended December 31, 2008 and 2007		32-33
Statements of Changes in Stockholders’ (Deficit) for Years Ended December 31, 2008 and 2007		34
Notes to Consolidated Financial Statements

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, 2008 and 2007 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, 2008 and 2007, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ M&K CPAS, PLLC
www.mkacpas.com
Houston, Texas
April 15, 2009

PART I—FINANCIAL INFORMATION

Item 1.Financial Statements

Conquest Petroleum Incorporated

Consolidated Balance Sheets

As of December 31, 2008 and 2007

	December 31,			December 31,
	2008			2007

Assets
Current assets:
Cash and cash equivalents	$	67,502		$	187,342
Accounts receivable		163,745			122,644
Other receivable		64,633			304,198
Inventories		-			88,868
Prepaid expenses and other current assets		21,044			103,771
Deferred financing costs, net		-			51,800
Current assets of discontinued operations		-			1,468,309
Total current assets		316,924			2,326,931

Oil and natural gas properties (successful efforts method of accounting):
Proved		8,170,937			11,236,731
Unproved		1,125,919			3,706,590
		9,296,856			14,943,321

Less accumulated depletion, depreciation and amortization		(1,829,365	)		(916,172	)

Oil and natural gas properties, net		7,467,491			14,027,149

Property and equipment:
Land		112,961			112,961
Buildings		215,445			217,550
Leasehold improvements		244,025			244,025
Office equipment and computers		82,337			79,769
Furniture and fixtures		211,581			211,581
Field service vehicles and equipment		729,743			694,310
Drilling equipment		174,082			174,082
Total property and equipment		1,770,174			1,734,278
Less accumulated depreciation		(474,744	)		(298,536	)
Property and equipment, net		1,295,430			1,435,743

Intangible assets, net		-			4,881,302
Other assets		489,176			496,046
Restricted cash		250,170			-
Long term assets of discontinued operations		-			11,771,108
Total assets	$	9,819,191		$	34,938,279

See accompanying notes to consolidated financial statements

Conquest Petroleum Incorporated

Consolidated Balance Sheets (Continued) (Audited)

	December 31,			December 31,
	2008			2007

Liabilities and Stockholders’ Deficit

Current liabilities:
Accounts payable	$	3,276,127		$	2,911,025
Interest payable		605,934			609,356
Accrued payroll and related taxes and benefits		1,691,710			1,056,272
Accrued liabilities		1,039,995			1,038,851
Production payment payable, current		3,607,570			3,851,649
Current maturity of notes payable, net of discount		689,518			400,000
Current maturities of notes payable, related parties, net of discount		803,350			5,161,025

Total current liabilities		11,714,205			15,028,178

Notes payable, net of current maturities and discount		-			1,750,000
Notes payable, related parties, net of current maturities and discount		-			1,250,000
Production payment payable, long term		2,834,520			3,026,296
Deferred revenue		65,000			125,000
Asset retirement obligation		1,840,641			1,149,267
Long term liabilities of discontinued operations		-			51,375,538

Total liabilities		16,454,366			73,704,279

Commitments and contingencies		-

Stockholders’deficit:
Preferred stock, $0.00001 par value; 50,000,000 shares
authorized; 5,454,545 and zero shares issued and outstanding at December 31, 2008 and December 31, 2007, respectively		55			-
Common stock, $0.00001 par value; 250,000,000 shares
authorized; 127,859,869 and 85,604,516 shares issued and 127,784,869 and 85,604,516 shares outstanding at December 31, 2008 and December 31, 2007, respectively		1,278			856
Stock payable		1,436,880
Additional paid-in capital		87,522,430			50,477,255
Accumulated deficit		(95,273,614	)		(89,244,111	)
Treasury stock, at cost (50,000 and 25,000 shares at
December 31, 2008 and December 31, 2007, respectively)		(322,203	)		-

Total stockholders’ deficit		(6,635,174	)		(38,766,000	)

Total liabilities and stockholders’ deficit	$	9,819,191		$	34,938,279

See accompanying notes to consolidated financial statements

Conquest Petroleum Incorporated

Consolidated Statements of Operations

For The Years Ended December 31, 2008 and 2007

	Year Ended December 31,
	2008			2007

Revenues:
Oil and natural gas revenues	$	1,822,893		$	1,852,365
Drilling services revenues		-			329,018
License fees, royalties and related services		163,458			257,500

Total revenues		1,986,351			2,438,883

Cost and expenses:
Production and lease operating expenses		1,295,693			1,664,279
Drilling operating expenses		4,628			1,059,168
Costs attributable to license fees and related services		132,202			20,000
Exploration costs		-			458,650
Depletion, depreciation and amortization		1,993,100			1,555,939
Revenue sharing royalties		145,583			144,157
Impairment of investments		42,808			1,365,712
Impairment of oil and natural gas properties		5,291,298			250,000
Environmental remediation costs		457,551			-
Accretion of asset retirement obligation		129,010			81,127
General and administrative expenses		12,066,402			8,492,384

Total cost and expenses		21,558,273			15,091,416

Loss from operations		(19,571,922	)		(12,652,532	)

Other income (expense):
Gain on settlement of debt		400,000			-
Impairment of LHD patent technology		(4,034,989	)		-
Interest expense, net		(2,222,429	)		(4,254,448	)
Gain on sale of assets		602,879
Loss on settlement		(1,368,000	)
Interest Income		45,417
Other miscellaneous income (expense), net		(703,601	)		13,938

Total other income (expense), net		(7,280,723	)		(4,240,510	)

Net loss before discontinued operations		(26,852,644	)		(16,893,042	)

Gain (loss) from discontinued operations		20,823,141			(13,092,498	)

Net loss	$	(6,029,503	)	$	(29,985,540	)

Net Income/(Loss) per common share from discontinued
Basic and diluted	$	0.18		$	(0.16	)

Net loss per common share from continuing operations:
Basic and diluted	$	(0.23	)	$	(0.37	)

Weighted average common shares outstanding:
Basic and diluted		114,939,598			80,023,513

See accompanying notes to consolidated financial statements

Conquest Petroleum Incorporated

Consolidated Statements of Stockholders’ Deficit

For the Years Ended December 31, 2008 and 2007

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

Balance at December 31, 2006	-		77,146,581	$ 771	$ 42,521,892	$ -	$ (59,258,571)	$ (250,000)	$ (16,985,908)
Common stock issued for cash	-		3,921,799	39	2,941,307	-	-	-	2,941,347
Common stock with put options issued for cash	-		266,666	3	-	-	-	-	3
Common stock issued for services	-		3,550,753	35	2,663,030	-	-	-	2,663,065
Common stock issued upon the conversion of
debt and accrued interest	-		75,883	1	56,911	-	-	-	56,912
Common stock issued upon the conversion of
debt and accrued interest, related party	-		269,501	3	202,123	-	-	-	202,126
Common stock issued for oil and natural gas
property	-		163,334	2	122,499	-	-	-	122,501
Common stock issued for oil and natural gas
property, related party	-		209,999	2	157,497	-	-	-	157,499
Treasury stock issued for cash	-		-	-	-	-	-	244,000	244,000
Treasury stock issued for services	-			-	-	-	-	6,000	6,000
Common stock offering costs	-		-	-	(1,441,569)	-	-	-	(1,441,569)
Common stock warrants issued as offering costs	-		-	-	1,308,559	-	-	-	1,308,559
Common stock warrants issued in connection
with notes payable, related parties	-		-	-	91,264	-	-	-	91,264
Common stock warrants issued in connection
with notes payable conversion	-		-	-	11,006	-	-	-	11,006
Common stock warrants issued in connection
with notes payable conversion, related parties	-		-	-	14,600	-	-	-	14,600
Common stock warrants issued to extend
notes payable terms	-		-	-	145,521	-	-	-	145,521
Common stock warrants issued to extend
notes payable terms, related party	-		-	-	259,210	-	-	-	259,210
Common stock warrants issued in connection
with purchase of well bores	-		-	-	313,558	-	-	-	313,558
Common stock warrants issued in connection
with purchase of well bores, related party	-		-	-	121,290	-	-	-	121,290
Common stock warrants issued in connection
with sale of net revenue interests	-		-	-	26,520	-	-	-	26,520
Common stock warrants issued in connection
with sale of net revenue interests, related party			-	-	6,630	-	-	-	6,630
Common stock options issued to employees
for services			-	-	192,240	-	-	-	192,240
Common stock options issued to
non-employee directors for services			-	-	471,900	-	-	-	471,900
Beneficiary conversion feature in connection with
convertible note payable, related party			-	-	291,264	-	-	-	291,264
Net loss			-	-	-	-	(29,985,540)	-	(29,985,540)

Balance at December 31, 2007	-	$ -	85,604,516	$ 856	$ 50,477,255	$ -	$ (89,244,111)	$ -	$ (38,766,000)

Common stock issued for cash	-	-	1,320,798	13	990,576	-	-	-	990,589
Common stock issued for services, employees	-	-	9,677,544	97	7,258,061	-	-	-	7,258,158
Common stock issued for services,
non employees	-	-	510,000	5	382,495	-	-	-	382,500
Common stock issued upon the conversion of
debt and accrued interest, related party	-	-	7,199,788	72	5,085,592	-	-	-	5,085,664
Common stock issued upon the conversion of
debt and accrued interest	-	-	21,722,223	217	16,291,451	-	-	-	16,291,668
Common stock issued in connection
with sale of net revenue interests	-	-	900,000	9	674,992	-	-	-	675,001
Common stock issued for oil and gas
properties, related party			25,000	-	18,750	-	-	-	18,750

Common stock issued with note payable attached			900,000	9	510,000	-	-	-	510,009

Common stock issued for accrued liabilities									-
Common stock offering costs	-	-	-	-		-	-	-	-
Common stock warrants issued as offering costs	-	-	-	-		-	-	-	-
Common stock warrants issued in connection
with notes payable, related parties	-	-	-	-	83,317	-	-	-	83,317
Common stock warrants issued in connection
with notes payable, unrelated parties					143,891	-			143,891
Common stock warrants issued to extend
notes payable terms	-	-	-	-	8,735	-	-	-	8,735
Common stock warrants issued to extend
notes payable terms, related party	-	-	-	-	6,239	-	-	-	6,239
Common stock warrants issued in connection
with sale of net revenue interests	-	-	-	-	103,267	-	-	-	103,267
Common stock warrants granted to
employees for services					41,972	-			41,972
Common stock options issued to
officers and employees for services	-	-	-	-	863,185	-	-	-	863,185

Conquest Petroleum Incorporated

Consolidated Statements of Cash Flows

For the Years Ended December 31, 2008 and 2007

	Year Ended December 31,
	2008			2007
Cash flows from continuing operating activities:
Net income (loss)	$	(6,029,503	)	$	(29,985,540	)
Net income from discontinued operations		20,823,141			(12,671,174	)
Net loss for continuing operations	$	(26,852,650	)	$	(16,893,042	)
Adjustments to reconcile net loss from continuing operations to net cash
used in operating activities:
Depletion, depreciation and amortization		1,993,100			1,555,939
Accretion of asset retirement obligation		129,010			110,443
Gain on extinguishment of debt		(400,485	)		-
Loss on disposal of assets		-			1,365,712
Impairment of oil and gas property		5,291,298			250,000
Impairment of LHD patent technology		4,034,989			-
Amortization of debt discount		523,352			126,552
Amortization of deferred financing costs		61,638			1,332,482
Stock based compensation		11,068,330			2,539,140
Bad debt expense		42,808			-
Loss on note settled with preferred stock		543,722			-
Gain on sale of overriding royalty interest		(421,733	)		-
Changes in operating assets and liabilities, net of effects of
acquisitions and divestitures:
Accounts receivable		(211,323	)		209,582
Other receivable					(522,735	)
Inventories					207,124
Prepaid expenses and other current assets		(170,372	)		(25,673	)
Accounts payable and accrued expenses		3,463,973			1,005,216
Other current liabilities		(60,000	)		-
Accrued payroll and related taxes and benefits		-			645,492
Interest payable and accrued liabilities		-			1,957,272
Deferred revenue		-			40,000

Net cash used in operating activities		(964,344	)		(6,096,496	)

Cash flows from investing activities:

Acquisitions of oil and gas property		(582,799	)		(50,000	)
Capital expenditures for oil and gas properties		-			(6,917,866	)
Capital expenditures for property and equipment and other assets		-			(70,714	)
Change in oil and gas properties accrual		-			1,377,660
Proceeds from sale of oil and natural gas equipment		-			50,000
Proceeds from disposition of oil & gas properties		1,282,931			2,250,000
Proceeds from sale of net revenue interests and sharing agreements		675,000			620,000
Proceeds from sale of other assets		16,732			500,000
Proceeds from dividend on investments		-			14,022
Purchase of fixed assets		(50,359	)		-
Investment in other assets					(225,000)

Net cash used in investing activities		1,341,505			(2,451,898	)
Cash flows from financing activities:

Payment on production payment payable		-			(14,482)
Proceeds - issuance of notes payable		400,000			-
Principal payments on notes payable and production payable		-			(779,475	)
Proceeds - issuance of notes payable - related parties		450,000			1,582,333
Principal payments on notes payable - related parties		(2,333	)		(312,666	)
Proceeds - issuance of common stock		1,350,598			2,941,349
Proceeds from issuance of common stock with put options		606+9-			200,000
Proceeds - issuance of treasury shares		-			(18,750	)
Purchase of treasury shares					244,000
Common stock offering costs		-			(133,010	)

Net cash provided by financing activities		2,198,265			3,709,299

Conquest Petroleum Incorporated

Consolidated Statements of Cash Flows (Continued) (Audited)

	For the Year Ended December 31
	2008			2007

Net cash (used in) and provided by discontinued operations		(2,695,266	)		2,060,544

Decrease in cash and cash equivalents		(119,840	)		(2,778,551	)

Cash and cash equivalents - beginning of year		187,342			2,965,893

Cash and cash equivalents - end of year	$	67,503		$	187,342

Supplementary cash flow information:
Cash paid for interest	$	248,097		$	1,889,215

Non-cash investing and financing activities:
Notes payable and accrued interest exchanged for common stock, related party	$	-		$	202,126
Notes payable and accrued interest exchanged for common stock		-			56,912
Notes payable and accrued interest exchanged for oil and gas properties		8,267,685			-
Reserve report revisions to asset retirement obligations		(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			-
Common stock issued for working interest in oil and natural gas well		-			122,501
Common stock issued for working interest in oil and natural gas well, related party		-			157,499
Common stock issued to settle accrued payroll		-			788,065
Treasury stock issued to settled accrued payroll		-			6,000
Notes payable and accrued interest exchanged for preferred stock		-			1,750,000
Notes payable and accrued interest exchanged for preferred stock, related party		-			1,250,000
Asset retirement obligation incurred		-			330,299
Common stock warrants granted in connection with note payable conversion		-			11,006
Common stock warrants granted in connection with note payable conversion, related party		-			14,600
Common stock warrants granted in connection with sale of net revenue interest		-			26,520
Common stock warrants granted in connection with sale of net revenue interest, related party		-			6,630
Common stock warrants granted to extend notes payable terms		-			145,521
Common stock warrants issued in connection with notes payable ,
related party		-			91,264
Common stock warrants granted to extend notes payable terms, related party		-			259,210
Common stock warrants granted as offering costs		-			1,131,636

See accompanying 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 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, Kentucky, Arkansas, and New Mexico. The Company’s executive offices are located in The Woodlands (Houston), Texas.

Going concern

The Company’s auditors have concluded there is substantial doubt about our ability to continue as a going concern, specifically if the Company is unable to secure adequate funding in 2009.

The Company has done much to alleviate financial pressures from debt service by converting or repaying a substantial portion of our outstanding debt and interest and by lowering our overall cash cost of operations through the significant reduction of personnel and other general cost cutting measures. In the twelve months ended December 31, 2008, the Company has paid off and/or converted over $51.0 million in principal and interest owed related to indebtedness. Concurrently, in the same time period, the Company has undergone a major cost restructuring in an effort to streamline operations and transform the Company into an efficient operation. It has eliminated over 35 contracted and non contracted personnel at both the corporate and field levels with annualized saving of over $3.5 million. The cost reductions extended to consulting services and day to day operating costs which amounted to approximately $2.1 million in annual savings of the total estimate that will be saved. Management believes that the reduction in debt and its enhanced balance sheet in conjunction with the cost restructurings should allow the Company to raise additional financing. In addition, management continues to negotiate to settle certain trade payables with stock, deferral of certain scheduled payments, and from 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.

Nonetheless, the Company has no future borrowings or funding sources available under existing financing arrangements as 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. In addition, given dropping commodity prices, lack of funding alternatives and a worsening financial environment, the Company is under significant liquidity constraints that hinder its ability to continue as a 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 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 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.

Major Customers

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, 2008
	2008	2007

Interconn Resources, Inc. (1)	62%		39%
Lion Oil Trading & Transportation, Inc. (1)	24%		18%
Plains Marketing, LP (1)	-%		11%
Orchard Petroleum, Inc. (2)	14%		32%

(1) The Company does not have a formal purchase agreement with this customer, but sells production on a month-to-month basis at spot prices adjusted for field differentials.
(2) Orchard Petroleum, Inc. is the operator of the Company’s wells in California and sells production on the Company’s behalf to Kern Oil & Refining, Co. and Aera Energy, LLC.

Accounting estimates

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. In accordance with EITF 00-27 “Application of Issue No. 98-5 to Certain Convertible Instruments,” 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 interest method. During the year ended December 31, 2008, beneficial conversion features related to convertible notes payable totaling $261,730 were recorded, all of which was attributable to related parties.

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 provisions of SFAS No. 142, "Accounting for Goodwill and Other Intangible Assets.” 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 had performed an impairment analysis of its patented lateral drilling technology in the third quarter ending September 30, 2008, and determined $2,041,894 impairment was required. The Company’s basis for such an impairment stemmed from the then recent and unprecedented financial environment affecting the world and the Company and the ever increasing restrictions on credit, equity and funding opportunities in general (see Note 6).

Accordingly, the Company recorded $7,195,367 as impairment of proved oil and natural gas properties and related equipment on the South Belridge Field during the three months ended March 31, 2007, which is reflected within discontinued operations for the twelve months ended December 31, 2007. The Company recorded $5,291,298 for December 31, 2008 in determining that the Belton Field, Marion Field and Days Creek Field required an impairment charge of $1,114,737, $4,000,051,$87,642 and impairment of $88,868 for rig equipment respectively

Asset retirement obligation

SFAS No. 143, “ Accounting for Asset Retirement Obligations,” 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 2008 and 2007:

	Twelve Months Ended December,
	2008			2007

Asset retirement obligation at beginning of period	$	1,506,305		$	1,159,808

Liabilities incurred		1,529			30,939
Revisions to previous estimates		594,209			(28,362	)
Dispositions		(390,412	)		(94,246	)
Accretion expense		129,010			81,127

Asset retirement obligation at end of period	$	1,840,641		$	1,149,266

Income taxes

The Company accounts for income taxes in accordance with the provisions of SFAS No. 109, “Accounting for Income Taxes.” 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 FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109”. FIN 48 prescribes a measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, FIN 48 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. At December 31, 2008, the Company had no material uncertain tax positions and the tax years 2004 through 2007 remained open to review by federal and various state tax jurisdictions.

Stock based compensation

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, 2008 and 2007, basic and diluted loss per share are the same as all potentially dilutive common stock equivalents are anti-dilutive. Under SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” entities that have issued mandatorily redeemable shares of common stock or entered into forward contracts that require physical settlement by repurchase of a fixed number of the issuer’s equity shares of common stock in exchange for cash shall exclude the common shares that are to be redeemed or repurchased in calculating basic and diluted earnings per share. For the twelve months ended December 31, 2008, the Company excluded 230,833 weighted average common shares equivalent outstanding for shares issued with put options that were recorded as a derivative liability within accrued liabilities, from its earnings per common share calculation.

Recently adopted accounting pronouncements

During September 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, “ Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109 ,” (“FIN 48”) which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. Under FIN 48, the Company is required to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If the tax position meets the “more likely than not” recognition threshold, it is then measured and recorded at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The adoption of FIN 48 did not have a material effect on the Company’s consolidated financial position or results of operations.

Recent unadopted accounting pronouncements

In May, 2008, the FASB issued FASB Staff Position APB 14-1, “ Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) ”. APB 14-1 requires the issuer to separately account for the liability and equity components of convertible debt instruments in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The guidance will result in companies recognizing higher interest expense in the statement of operations due to amortization of the discount that results from separating the liability and equity components. APB 14-1 will be effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting APB 14-1 on it consolidated financial statements.

Note 3 –

Debt

Notes payable consists of the following at December 31, 2008 and December 31, 2007:

	December 31, 2008			December 31, 2007

Notes payable	$	800,000		$	400,000
Notes payable, related party		-			3,597,001
Convertible notes payable		-			1,750,000
Convertible notes payable, related party		850,000			3,270,000

		1,650,000			9,017,001

Less unamortized debt discount		(157,132	)		(455,976	)

		1,492,868			8,561,025
Less current maturities:
Notes payable, net of discount		(689,518	)		(400,000	)
Notes payable, related party, net of discount		(803,350	)		(5,161,025	)

Notes payable, net of current maturities and discount	$	-		$	3,000,000

Notes payable

The Company had a note payable with an individual investor aggregating $400,000 at December 31, 2008. This notes payable matured on December 31, 2007, bearing interest at a 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 this note payable at December 31, 2008, 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.

The Company had a note payable with an individual investor aggregating $700,000 at December 31, 2008. This notes payable matured on March 30, 2008, bearing interest at fixed rate of 12%. Simple 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 this note payable at December 31, 2008, and is in the process of renegotiating its terms. This note payable in default is accruing interest at 18%. This note payable is unsecured.

During 2008, the Company borrowed an additional $100,000 from an individual. This note is a demand note payable at any time.

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.

The Company held notes payable with various individual investors aggregating $400,000 at December 31, 2007. These notes payable with individuals mature from May 1, 2007 to September 30, 2007, bearing interest at fixed rates of 9%. 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, 2007 and is in the process of renegotiating its terms. These notes payable in default are accruing interest at a higher rate and additional late fees may apply. These notes payable are unsecured.

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 (see Note 4). 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 or renegotiated in the first quarter of 2008.

Convertible notes payable

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.

During the twelve months ended December 31, 2008, related party note holders converted notes payable of $420,000 and $8,841 of accrued interest into 571,788 shares of the Company’s common stock at a conversion rate of $0.75 share.

During the twelve months ended December 31, 2008, a related party holding a note payable totaling $1,200,000 with a 20% imputed interest rate, maturing in one year from the note date, converted the note payable into common stock of the Company at a conversion rate of $0.75 per dollar of principal. The entire outstanding balance of $1,200,000 was converted into 1,600,000 shares of the Company’s common stock.

During the twelve months ended December 31, 2008, the Company borrowed an additional $400,000 from management and directors. The borrowing was subsequently converted into common stock at a price of $0.75 per share, or 533,333 shares. Additionally, $5,048,000 of convertible notes also converted, plus accrued interest of $51,841 at a price of $0.75 per share for a total of 6,799,788 shares.

During the twelve months ended December 31, 2008, the Company sold 2% of ORRIs in the Days Creek Field and 7% of ORRIs in its Marion Field to investors generating total proceeds of $675,000. These ORRIs were subsequently converted into stock at $0.75 per share or 900,000 shares.

During the twelve months ended December 31, 2008, the Company converted $3,000,000 of corporate notes to 5,454,545 shares of Series A Preferred Stock which were originally associated with the purchase in October 2007 of various working interests in certain wells located in the South Belridge Field from several individuals, totaling $3,000,000.

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. For the years ended December 31, 2008 and 2007, the Company determined 56% of this production payment facility was due within the next twelve months and hence classified as current portion of long term debt. This agreement has since been extended for 6 months until October 30, 2009.

Interest expense, net

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

	Twelve Months Ended December 31,
	2008		2007

Interest expense related to debt	$	1,635,964	$	2,586,350

Amortization of deferred financing costs		324,735		1,312,605

Amortization of debt discount		261,730		85,163

Interest expense related to stock put options		-		333,333

Capitalized interest		-		(42,125	)

Interest income		-		(20,877	)
	$	2,222,429	$	4,254,448

Note 4 –

Discontinued Operations

During the second quarter of 2008, the Company sold its interest in the South Belridge field and the debt associated with it was extinguished (see Note 3). Accordingly, the consolidated financial statement amounts for the three and twelve months ended December 31, 2008 and 2007 have been adjusted to give effect to the disposition as a discontinued operation. The operating results of the South Belridge field included within discontinued operations are presented as follows:

	Twelve Months Ended December 31,
	2008			2007
Operating revenues	$	751,059		$	1,683,865

Operating costs and expenses		446,891			1,593,273

Other expenses, net		2,337,811			13,183,091

Loss from discontinued		(2,033,643	)		(13,092,498	)
operations, net of taxes

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

Net income (loss)	$	20,823,141		$	(13,092,498	)

Basic and diluted income per
share from discontinued operations	$	(0.02	)	$	(0.16	)

Basic and diluted income per share
from gain on disposal of
discontinued operations		0.20			-

Total	$	0.18		$	(0.16	)

Weighted average number of
common shares outstanding

Basic		115,024,598			80,023,513
Diluted		115,024,598			80,023,513

Note 5 –

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 50,000,000 shares of a new class of preferred stock, of which 10,000,000 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 Corporation 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.

As referred to in Note 3, during the second quarter of 2008, the Company issued 5,454,545 shares of Series A Preferred Stock in exchange for $3,000,000 of corporate notes payable. At December 31, 2008, there were 5,454,545 shares of Series A Preferred Stock issued and outstanding.

Common stock

During 2008, the Company issued to a third party 21,722,223 shares of common stock with a fair value of $0.75 per share or $16,291,668 as a debt conversion resulting in a loss on disposal of debt of $37,408,772 for the year ended December 31, 2008.

During 2008 and 2007, total proceeds of $1,655,599 and $3,141,349 were generated through private offerings of common stock from the issuance of 2,220,798 and 4,188,465 shares at $0.75 per share. Of the total number of common shares sold during the year ended December 31, 2007 100,000 shares were sold to related parties generating proceeds of $75,000. Of the total number of common shares sold in 2007, 266,666 shares included embedded put options at $2.00 per share, which originally expired on December 15, 2007, but were extended to August 31, 2008. These shares with embedded put options were recorded at their par value and the excess obligation over the par value was recorded as a liability, which is recorded within accrued liabilities.

During 2008 and 2007, the Company issued 5,035,000 and 3,550,753 shares of common stock with a fair value of $3,776,250 and $2,663,065, respectively, at $0.75 to third parties for services. In 2007, all shares issued were to employees for compensation or salary conversion.

During 2008, the Company issued 5,177,544 shares of common stock with a fair value of $0.75 per share or, $3,883,158, to employees of the Company for services.

During 2008 , related party note holders comprising $5,399,841 of principal and accrued interest and other liabilities elected to convert into 7,199,788 shares of the Company’s common stock, at an exchange rate of one share for each $0.75 of principal. 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 900,000 shares of common stock in connection with the sale of net revenue interests.

During 2007, note holders comprising $259,038 of principal and accrued interest elected to convert into 345,384 shares of the Company’s common stock at an exchange rate of one share for each $0.75 of principal.

During 2007, the Company issued 373,333 shares of common stock at a fair value of $0.75 per share, in conjunction with the purchase of certain ownership interests in four well bores in its South Belridge Field.

Warrants

During 2008 and 2007, the Company granted 1,207,543 and 4,356,887, warrants respectively to purchase the Company’s common stock with an exercise price of $0.75 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 $365,018. Of these warrants issued in 2007, 2,018,750 were granted to related parties. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $1,308,559 and was recorded as common stock offering costs included in additional paid-in capital during 2007.

During 2007, the Company entered into various note payable agreements with related and unrelated third party investors to fund its operations (see Note 5 under the caption “Detachable common stock warrants”). At December 31, 2007, certain note payable agreements provided for warrants to purchase a total of 470,000 of the Company’s common stock, respectively, at an exercise price of $0.75 per share of which 470,000 shares were granted to related parties. These warrants expire three or five years from the date of grant. The fair value of these warrants was determined using the Black-Scholes option pricing model and was recorded as a debt discount totaling $91,264 during the year ended December 31, 2007. The debt discount is being amortized to interest expense over the life of the notes using the effective interest method.

During 2007, warrants to purchase 1,411,331 shares of the Company’s common stock with an exercise price of $0.75 per share were granted to certain note holders for extending the terms of their notes payable. These warrants expire five years from the date of grant. Of these warrants issued, 933,332 were issued to related parties. The estimated fair value of these warrants was determined using the Black-Scholes option pricing model and totaled $404,731.

In contemplation of divesting the South Belridge Field, effective October 1, 2007, the Company repurchased various working interests in four well bores in its South Belridge Field that it had sold to four individuals in 2005. The purchase price consideration included the granting of 1,000,000 warrants with an exercise price of $0.75 per share. Of the total warrants issued, 562,500 warrants were issued to related parties. The estimated fair value of these warrants was determined using the Black-Scholes option pricing model and totaled $215,627.

Also, in contemplation of divesting the South Belridge Field, effective October 1, 2007, the Company reacquired certain Revenue Sharing Agreements comprising 4.36% in the aggregate on a certain seven wells located in the South Belridge Field by granting 1,016,672 warrants with an exercise price of $0.75 per share. The estimated fair value of these warrants was determined using the Black-Scholes option pricing model and totaled $219,221 and was recorded in oil and natural gas properties.

During 2007, the Company sold a 5% net revenue interest in the oil and natural gas properties in the Days Creek Field for $500,000. The ORRI sales agreements also provided for warrants to purchase a total of 150,000 shares of the Company’s common stock with an exercise price of $0.75 per share expiring three years from the date of the agreements. Of these warrants issued, 30,000 were issued to related parties. The estimated fair value of these warrants was determined using the Black-Scholes option pricing model and totaled $33,150 and was recorded as additional paid-in capital.

00.

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

	2008			2007
	Number of	Weighted			Weighted
	Shares	Average		Number of	Average
		Exercise Price		Shares	Exercise Price

Outstanding, beginning of year	14,089,946	$	0.75	5,597,494	$	0.75

Granted	1,207,543		0.75	8,492,452		0.75
Exercised	–		–			0.75
Expired or cancelled	–		–	–		0.75

Outstanding, end of year	15,297,489	$	0.75	14,089,946	$	0.75

Exercisable, end of year	15,297,489	$	0.75	14,089,946	$	0.75

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:

	Twelve Months Ended
	December 31,
	2008	2007
Risk free rate	1.79%-2.32%	4.23%-4.92%
Expected life	5-10 years	5-10 years
Volatility	67%	38%
Dividend yield	0%	0%

Stock options

During 2008 and 2007, the Company granted options to purchase 3,674,156 and 1,200,000 shares, respectively, of the Company’s common stock at an exercise price of $0.75 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 and 2007 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 $1,379,696 and $471,900, respectively as general and administrative expense to account for vested options.

In addition, during 2007, the Company granted options to purchase 650,000 shares, of the Company’s common stock at an exercise price of $0.75 per share to employees for services provided. These options expire five or seven years from the date of grant. Of these options granted, 400,000 were 100% vested on the date of grant during 2007, and 250,000 granted in 2007 vest within 90 days from the grant date. The estimated fair value of these stock options was determined on the grant date using the Black-Scholes option pricing model to be $192,240, of which $192,240 was amortized to general and administrative expense during 2007.

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

	2008				2007
	Number of		Weighted				Weighted
	Shares		Average		Number of		Average
			Exercise Price		Shares		Exercise Price

Non-vested beginning of year		14,089,946	$	0.75		5,597,494	$	0.75

Granted		3,674,156		0.75		1,850,000		0.75

Vested		(3,674,156)		–		(2,375,000)		0.75

Non vested, end of year		-	$	0.75		–	$	0.75

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, 2008 and 2007:

	Twelve Months Ended
	December 31,
	2008	2007
Risk free rate	2.46%-3.41%	4.23%-4.92%
Expected life	5-10 years	5-10 years
Volatility	45%	38%
Dividend yield	0%	0%

Note 6 –

Asset Sale

In July 2008, the Company sold three non strategic wellbores from its Delhi Field to Denbury Offshore for $1,025,000. These well bores, wells 182-1, 182-2 and 196-2 went into the Holt Bryant shale which the Company has no strategic interest in as its primary play is the Mengel Sand. The Company recorded a $594,337 gain on the sales of these assets.

On December 1, 2008, the Company sold its 24% working interest in the Stephens Field located in Columbia County Arkansas and 75% working interest in the Jones Well located in Lafayette County Arkansas to its working partners for $346,251.

In the fourth quarter of 2008, the Company sold 50% Working Interest in three wellbores in the Belton Field and recorded a gain on asset of $8,541.

On May 1, 2007, the Company sold all of its interest in the Holt Bryant Sand formation of the Delhi property for $2,500,000, of which $250,000 was held in escrow for an environmental assessment. Because the sale occurred shortly after and was contemplated in the original acquisition, SFAS 141 requires the proceeds received be recorded as an adjustment to the cost of the property and no gain or loss was recorded.

Note 7 –

Intangible Assets

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 had performed an impairment analysis of its patented lateral drilling technology in the third quarter ending September 30, 2008, and determined $2,041,894 impairment was required. The Company’s basis for such an impairment stemmed from the then recent and unprecedented financial environment affecting the world and the Company and the ever increasing restrictions on credit, equity and funding opportunities in general.

Note 8 –

Federal Income Tax

No provision for federal income taxes has been recognized for the twelve months ended December 31, 2008 and 2007 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 assets include a net operating loss carryforward and stock based compensation. The primary deferred tax liability is the basis difference in oil and gas property and property and equipment.

At December 31, 2008, the Company has net operating loss carryforwards of approximately $71 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.

A reconciliation of the income tax provision computed at statutory tax rates to the income tax provision for the twelve months ended December 31 is as follows:

	Twelve Months Ended December 31,

	2008	2007
Federal income tax expense (benefit) at statutory rate	34%	-34%
Change in valuation allowance	-34%	34%
Total income tax provision	0%	0%

Note 9 –

Commitments and Contingencies

Litigation

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 are 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. Principal defendants in the suit, in addition to the Company, include the Company’s indemnities including McGowan Working Partners, MWP North La, LLC., Murphy Exploration & Production Company, Ashley Investment Company, Eland Energy, Inc. and Delhi Package I, Ltd. The Company believes that it has meritorious defenses with regard to the plaintiffs’ claims and, thus, with regard to the extent of its monetary exposure under its indemnity obligation. The Company has and continues to defend the suit vigorously. Conquest has paid over $500,000 to pay legal fees and remediation costs. The central issue is contamination of the groundwater at the Delhi Field. Plaintiffs are landowners that claim the groundwater is polluted and needs to be extracted from the ground through a pumping process and disposed of remotely. Plaintiff has made a settlement offers to the company of $6 million, which was rejected. The plaintiffs made a second settlement offer of $3 million. The company counter offered to pay for the remediation but no cash in addition to the remediation costs under 29-B standards. No settlement has been reached. A trial date has been set for July 1, 2009. The company, with the legal fees and remediation already done and in process, believes its future exposure will be only legal bills and minor remediation. The company granted McGowan Working Partners a first mortgage position on the field as they have been representing the company in the litigation and overseeing the remediation and they are a party the company agreed to indemnify when it purchased the field from them. The company believes its total exposure is based upon the information currently available is $750,000 which is current year accrual.

·	In the Suit with Vanguard Energy Services for $340,000 for use of their drilling rigs in the 2006 and 2007. This $340,000 is an Accounts Payable and the Company is in the process of negotiating in conjunction with a suit filed against a sister company, Recompletion Financial Corporation.

Recompletion Financial Corporation – This is a sister company of Vanguard with the same legal representation. Recompletion was hired as a marketing and financial company to raise funds and the company paid over a million dollars in 2005 with no work done. In addition, there is a breach of contract as they used and employed our proprietary technology barring them from certain geographical locations including China. They have been sued for breach of contract and misappropriating the company’s property for $2,000,000.

·	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 payables in 2008 and 2007.

·	In the suit with Anthony Austin, Mr. Austin was let go in January 2008 after working 3 months and has filed a claim for $1,000,000. Mr. Austin’s attorney has since withdrawn from the case and on April 14, 2009 the court granted a motion for directed verdict in Maxim’s favor.

In the suit with Don Shein, Mr. Shein is claiming back salary, severance expenses and commissions that do not coincide with our accounting and his employment contract. He also lent the company $100,000. We have come to an agreement whereby Mr. Shein will extend his $100,000 loan and the company will facilitate the issuance of 375,000 shares of the company’s common stock by a third part shareholder. The company has accrued a liability and corresponding expense for $281,250 in addition to his $100,000 note.

·	The former CEO, Marvin Watson is claiming expenses, past salary and severance in regards to his employment. The company sees no merit in his claim and will defend itself vigorously.

·	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.

Contingencies

During September 2007, the Company executed an agreement with a consulting services firm to provide investor relations services for a period of up to 24 months upon the Company going public on a publicly traded exchange. As consideration for their services, 4,599,692 shares of common stock are to be issued contingent on the Company becoming traded on a public listed exchange. The company has since been approved to trade on the Over The Counter Bulletin Board in February of 2009 but has not begun actual trading of the shares.

Note 10 –

Reporting by Business Segments

The Company has three operating segments: oil and natural gas exploration and production, drilling services and lateral drilling services. These segments are managed separately because of their distinctly different products, operating environments and capital expenditure requirements. The oil and natural gas production unit explores for, develops, produces and markets crude oil and natural gas, with all areas of operation in the United States. The drilling services unit provides drilling services for the Company’s subsidiaries and their working interest partners and to third parties. The lateral drilling services unit provides lateral drilling services for third parties, sub-licenses the Company’s LHD Technology, and sells related LHD Technology equipment. Segment performance is evaluated based on operating income (loss), which represents results of operations before considering general corporate expenses, interest and debt expenses, other income (expense) and income taxes. The drilling company sold its drilling rigs 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 no longer provide any drilling services to third parties. As of 2009, the drilling services and lateral drilling services will not be reported as separate business segments.

	December
	2008			2007

Total assets:
Oil and natural gas exploration and production	$	2,834,327		$	9,230,185
Drilling services		0			0
Lateral drilling services		4,876,972			4,876,972
Other		2,107,892			7,591,705
Total	$	9,819,191		$	21,698,862

	Twelve Months Ended
		2008			2007
Revenues:
Oil and natural gas revenues	$	1,822,893		$	1,852,365
Drilling services revenue		-			329,018
License fees, royalties and related services		163,458			257,500
Total	$	1,986,351		$	2,438,883


Operating income (loss):
Oil and natural gas exploration and production		(2,473,032	)		(3,073,932	)
Drilling services		(5,865	)		(736,984	)
Lateral drilling services		(29,015	)		(397,235	)
Total		(2,507,912	)		(4,208,150	)

Corporate expenses (1)		(11,315,162	)		(8,444,383	)
Interest expense, net		(2,222,429	)		(4,254,448	)
Other miscellaneous income (expense), net		(10,807,142	)		13,938

Net loss	$	(26,852,645	)	$	(16,893,043	)

Depletion, depreciation and amortization:
Oil and natural gas exploration and production	$	1,932,829		$	877,954
Drilling services		-			5,465
Lateral drilling services		60,271			634,735
Other		-			37,785
Total	$	1,993,100		$	1,555,939

Capital expenditures
Oil and natural gas exploration and production	$	(1,251	)	$	5,400,089
Drilling services		-			-
Lateral drilling services		-			-
Other		1,251			17,578
Total	$	-		$	5,417,667

(1) Includes non-cash charges for the fair value of stock options granted to employee and non-employee directors for services of $1,256,633

Note 11 –

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

The following disclosures provide unaudited information required by SFAS No. 69, “Disclosures About 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:

	2008		2007
Revenues	1,986,351		2,438,883
Production (lifting) costs:
Production and lease operating expenses	1,295,692		1,664,279
Revenue sharing royalties	145,583		144,157
Exploration costs			458,650
Impairment of oil and natural gas properties	5,291,298		7,445,367
Accretion of asset retirement obligation	129,010		81,127
Depreciation, depletion and amortization	1,993,100		1,555,939

Total costs	8,854,683		13,788,402

Pretax income (loss) from producing activities	(6,868,332	)	(8,910,636	)
Income tax expense	–		–
Results of oil and natural gas producing activities (excluding overhead and interest costs)	(6,868,332	)	(8,910,636	)

Costs incurred

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

	2008		2007
Property acquisition costs:
Unproved				778,312
Proved		559,024		4,726,215
Exploration costs		226,138		3,227,137
Development costs		30,258		3,704,171
Asset retirement obligations		129,010		81,127
Total costs incurred		944,430		12,516,962

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, 2008 and 2007, and the related discounted future net cash flows are based on estimates prepared by independent petroleum engineers. The reserves as of December 31, 2008 were derived from reserve estimates prepared by the independent reserve engineers; Mark Newendorp for the Delhi Field and the Marion Field. The reserves as of December 31, 2007 were derived from reserve estimates prepared by the independent reserve engineers; Aluko & Associates, Inc. for the Delhi Field and the South Belridge Field, Haas Petroleum Engineering Services, Inc. for the Stephens Field, Netherland, Sewell & Associates, Inc. for the Marion Field, and Lee Keeling and Associates, Inc. for the Days Creek Field. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.

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:

Note 11 –

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

	Barrels of Oil and Condensate
	2008			2007
Oil
Proved developed and undeveloped reserves:
Beginning of year		2,609,815			2,464,821
Purchase of oil and natural gas property in place		-			6,048
Discoveries and extensions		-			587,337
Revisions		(1,323,492	)		(20,343	)
Sale of oil and natural gas properties in place		-			(389,687	)
Production		11,277			(23,880	)
End of year		1,297,600			2,609,815
Proved developed reserves at beginning of year		146,596			146,196
Proved developed reserves at end of year		1,297,600			146,596

Revisions in 2008 consist of a reduction of 708,464 barrels of oil in the total estimated reserves in the Delhi field, a reduction of 544,736 in the exchange of the Company’s working interest in the Days Creek Field in lieu of debt owed and a reduction of 60,576 in the sale of the Company’s working interest in the Stephens Field. The revision also includes and additional 8,032,101 MMCF of natural gas largely due to additional proved undeveloped reserves on the Marion field as determined by the third party engineer. Production came from all fields in 2008.

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:

	Cubic Feet of Natural Gas
	2008		2007
Gas
Proved developed and undeveloped reserves:
Beginning of year		1,987,875		4,300,316
Pruchase of oil and natural gas property in place		-		58,180
Discoveries and extensions		-		-
Revisions		3,094,136		(2,516,359	)
Sale of oil and natural gas properties in place		-		-
Production		257,989		145,738
End of year		5,340,000		1,987,875
Proved developed reserves at beginning of year		1,987,875		1,987,875
Proved developed reserves at end of year		5,340,000		1,987,875

	2008			2007
Future cash inflows		56,975,022			256,364,851
Future oil and natural gas operation expenses		(16,552,930	)		(57,090,933	)
Future development costs		(895,990	)		(7,547,995	)
Future income tax expenses		-			-
Future net cash flows		39,526,102			191,725,922
10% annual discount for estimating timing of cash flow		(16,047,672	)		(86,861,662	)
Standardized measure of discounted future net cash flow		23,478,430			104,864,261

Even though total proved reserves increase from 2007 to 2008, the PV10 value was reduced significantly mainly as a result of two things 1) no PUDS (proved developed not producing reserves) were included and 2) a sharp drop in prices of oil. Future cash flows are computed by applying year-end prices of oil and natural gas to year-end quantities of proved oil and natural gas reserves. Average prices used in computing year-end 2008 and 2007 future cash flows were $42.68 and $92.79 for oil, respectively, and $6.71and $6.46 for natural gas, respectively. Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

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 standardized measure (continued)

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:

	2008			2007
Changes due to current-year operations:
Sale of oil and natural gas, net of oil and natural gas operating expenses		(199,729	)		(378,001	)
Extensions and discoveries		-			28,994,114
Development costs incurred		-			3,704,171
Purchase of oil and gas properties		-			829,006
Changes due to revisions in standardized variables:		-			-
Prices and operating expenses		(3,695,044	)		34,207,795
Income taxes		-			0
Estimated future development costs		(13,345,990	)		(5,967,100	)
Revision of quantities		(68,580,699	)		(11,025,755	)
Sales of reserves in place		-			(5,549,976	)
Accretion of discount		10,553,014			6,116,675
Production rates, timing and other		(6,117,382	)		(7,233,419	)
Net of change		(81,385,830	)		43,697,510
Beginning of year		104,864,261			61,166,751
End of year		23,478,431			104,864,261

Note 12 –

Subsequent Events

In January of 2009, the CEO loaned the company $25,000 with an 8% interest rate which is payable upon demand.

In January of 2009, 5 employees were granted a sum total of 150,000 shares of common stock options to purchase the Company’s common stock at an exercise price of $0.75 per share.

In January of 2009, a consultant was granted 150,000 shares of common stock 100,000 stock options to purchase the Company’s common stock at an exercise price of $0.75 per share.

In February of 2009, the CEO was granted 2,000,000 shares of common stock and gave back 2,000,000 previously issued stock options to purchase the Company’s common stock at an exercise price of $0.75 per share.

The Company extended its amended agreement with BlueRock Energy Capital Ltd. by an additional 6 months.

The Company entered into a two year lease with a $2,837 monthly payment.

The Company has recorded expenses attributed to settlement with a former employee of and accrual for future losses of $607,932, $548,264 settlement with a former director and warrants issued for debt extensions and a loss on conversion of debt of $543,722. This was offset by $602,879 from the gain on the sale of wellbores in the Delhi and Belton Field.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

Dismissal of Certifying Accountant

As of November 19, 2008, the Registrant dismissed Pannell Kerr Forster of Texas, P.C. (“PKF”) as its independent registered public accounting firm as approved by the Audit Committee of the Board of Directors.

PKF had been our principal independent accountants and had reported on the financial statements for the fiscal years ended December 31, 2007 and 2006 and the interim periods through September 30, 2008. The audit report of PKF on the consolidated financial statements of Conquest Petroleum Incorporated as of and for the fiscal years ended December 31, 2007 and 2006 did not contain an adverse opinion or a disclaimer of opinion, and was not qualified or modified as to audit scope or accounting principles.

In connection with the audits of the Company’s consolidated financial statements for the fiscal years ended December 31, 2007 and 2006 and through the date of this dismissal, there were: (1) no disagreements between Conquest and PKF on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which disagreements, if not resolved to the satisfaction of PKF, would have caused PKF to make reference to the subject matter of the disagreement in their report on Conquest’s consolidated financial statements for such year, and (2) no reportable events within the meaning set forth in Item 304 of Regulation S-K.

Retention of New Certifying Accountant

As of December 3, 2008, the Company entered into a formal engagement agreement with M&K CPAS, PLLC of Houston, Texas (“M&K”) to assume the role of its new principal independent accountants. The decision to engage M&K was approved by the Audit Committee of the Board of Directors on December 2, 2008.

During the periods ended December 31, 2006 through 2007 and the subsequent interim period ended September 30, 2008, and through the date of the firm’s engagement the Registrant did not consult with M&K with regard to:

(1)	The application of accounting principles to a specified transaction, either completed or proposed; or the type of audit opinion that might be rendered on Registrant’s financial statements; or

(2)	Any matter that was the subject of a disagreement or a reportable event (as described in Item 304(a) (1) (iv) of Regulation S-B.

ITEM 9A. 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, 2008. 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

Our management is responsible for establishing and maintaining effective internal control over financial reporting. Under the supervision of our Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2008 using the criteria established in Internal Control—Inte grated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

During our review of controls for the audited period ended December 31, 2008, and in the process of preparing our Annual Report, our management discovered that there are material weaknesses in our internal controls over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The material weaknesses identified during the preparation of the Annual Report were (i) insufficient evidence of a robust corporate governance function; (ii) lack of sufficient resources with SEC, generally accepted accounting principles (GAAP); (iii) inadequate security over information technology and (iv) lack of evidence to document compliance with the operation of internal accounting controls in accordance with our policies and procedures. These control deficiencies could result in a material misstatement of significant accounts or disclosures that would result in a material misstatement to our interim or annual financial statements that would not be prevented or detected. Accordingly, management has determined that these control deficiencies constitute material weaknesses.

Management’s Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act, as amended. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. We have identified the following material weaknesses:

1. As of December 31, 2008, 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 independent members and no director 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.

2. As of December 31, 2008, 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.

3. This lack of internal controls over financial reporting resulted in numerous adjusting journal entries proposed by our independent auditor during their audit of the year ended December 31, 2008.

Because of these material weaknesses, management has concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2008, based on the criteria established in "Internal Control-Integrated Framework" issued by the COSO.

Changes in Internal Control Over Financial Reporting

There were no changes in internal controls over financial reporting that occurred during the year ended December 31, 2008, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management is currently evaluating remediation plans for the above control deficiencies. In our evaluation, 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 as the proposed remediation plan (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, and (v) developing 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.

In light of the existence of these control deficiencies, the Company concluded that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis by the company’s internal controls.

As a result, management has concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2008 based on criteria established in Internal Control—Integrated Framework issued by COSO.

M&K CPAS, PLLC, an independent registered public accounting firm, was not required to and has not issued an attestation report concerning the effectiveness of our internal control over financial reporting as of December 31, 2008 pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

ITEM 9B. OTHER INFORMATION

None

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	62	Chairman of the Board, President and CEO	Became President May 1, 200 and Chairman and CEO on July 28, 2008
Robert C. Johnson	64	Director	Became Director November 1, 2008
Harvey Pensack	85	Director	Became Director June 12, 2004
Arturo Henriquez	38	CFO	Became CFO August 1, 2008

Business Experience and Background of Directors and Executive Officers

Robert D. Johnson

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 Maxim, Mr. Johnson was officially in full retirement.

Arturo F. Henriquez

Prior to joining Maxim, Mr. Henriquez was the CEO of Mexico for Helm Bank of Florida. In 2002, Mr. Henriquez assumed the title of Managing Director of Investment Banking Division of KPMG Financial Advisory Services in Mexico City where he was in charge of the M&A, Financing and Financial Advisory Department for Mexico. In 1999, Mr. Henriquez was the co-founder and CFO of Netenvios.com, Inc., the first Latin American logistics aggregator with physical operations in Argentina, Mexico, Brazil, Chile, Colombia and the United States (Miami). Mr. Henriquez was responsible for negotiating, structuring, and successfully raising millions of dollars in venture capital from Citibank (CVC), Merrill Lynch, and Explorador Fund. Previous to this he worked in the equity divisions of Goldman Sachs and Lehman Brothers. In 1995, Mr. Henriquez started with Bank of America as a Vice President. He devised, marketed, and structured lease and asset-based financings in dual currencies to the top 50 corporate and governmental firms in Mexico, such as Pemex, Cemex, Telmex Grupo Alfa, Ahmsa, Kimberly Clark, and Volvo Mexico. Mr. Henriquez earned an MBA degree from the Kellogg Graduate School of Management at Northwestern and two Masters Degrees from Boston University in International Relations and Communications.

Harvey M. Pensack

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

Mr. Johnson graduated with a Professional Degree in Petroleum Engineering from the Colorado School of Mines in 1966. He joined Amoco Production Company after graduation and advanced through numerous engineering and management positions during his 19 plus 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. Mr. Johnson is currently retired from active company management but continues to stay involved in the oil and gas industry as well as his other personal investments.

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 Mr. Robert C. Johnson and Mr. Harvey Pensack. Mr. 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 Mr. Steve Warner and Mr. Harvey Pensack. Mr. Pensack 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 Mr. Robert D. Johnson and Mr. Steve Warner. Mr. 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 2008 and 2007 and 2006.

								Warrant and
Name and		Contract				Stock		Option		All Other
Principal		Salary		Contract		Awards		Awards		Compensation			Total
Position	Year		-3	Bonus			-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
Chief Executive Officer (1)(9)	2008	$	300,000	$	–	$	861,234	$	942,641	$	–		$	2,103,875

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

Arturo Henriquez
Chief Financial Officer (2)	2008	$	300,000	$	–	$	–	$	–	$	–		$	300,000

-1	Robert D. Johnson has deferred all compensation to assist the Company with cash flows as of May 1, 2008.
-2	Arturo Henriquez has deferred all compensation to assist the Company with cash flows as of August 1, 2008.
-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

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 Financial Officer. On August 3, 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.

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.

Outstanding Equity Awards at Fiscal Year End

The following table sets forth information regarding each unexercised option held by each of our fiscal year 2007 named executive officers as of December 31, 2008.

Name	No. of Securities Underlying Unexercised Options Exercisable(1)		No. of Securities Underlying Unexercised Options Unexercisable	Option Exercise Price		Option Expiration Date
Robert D. Johnson		2,574,156	–	$	0.75	05/01/2018

(1)	These options were fully vested on the date of grant.

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 2008, 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 2008 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 Option		Stock Warrant		Total
Name	Awards(1)		Awards
Carl Landers	$	61,242	$	-	$	61,242
Harvey Pensack	$	61,242	$	16,407	$	77,649	(2	)(3)(4)
John P. Ritota	$	61,242	$	-	$	61,242
Robert C. Johnson	$	-	$	94,818	$	94,818	(5	)(6)
John J. Dorgan	$	61,242	$	5,259	$	66,501
Glenn Biggs	$	61,242	$	5,259	$	66,501	(8	)
Steve Warner	$	-	$	-	$	-
Marvin Watson	$	61,242	$		$	61,242
Robert D. Johnson	$	942,641	$		$	942,641

1)	Amounts represent the dollar amount recognized for financial statement reporting purposes with respect to the fiscal year in accordance with SFAS No. 123(R) excluding forfeiture estimates. See Note 2 of the notes to consolidated financial statements included else where in this Annual Report for a discussion of our assumptions in determining the SFAS No.123(R) fair values of our option awards.
2)	Mr. Pensack received 25,000 warrants with an exercise price of $0.75 per share for a note payable.
3)	Mr. Pensack received 15,000 warrants with an exercise price of $0.75 per share for the extension of a note payable
4)	Mr. Pensack received 28,125 warrants with an exercise price of $0.75 per share with a stock purchase.
5)	Mr.Robert C. Johnson received 100,000 warrants with an exercise price of $0.75 per share for fund raising services.
6)	Mr. Robert C.Johnson received 100,000 warrants with an exercise price of $0.75 per share for a note payable.
7)	Mr. Jack Dorgan received 25,000 warrants with an exercise price of $0.75 per share for a note payable.
8)	Mr. Glenn Biggs received 25,000 warrants with an exercise price of $0.75 per share for a note payable.

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, 2008 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, 2008 with respect to each beneficial owner of more than five percent of the Company’s common stock. The percentage ownership is based on 127,859,869 shares of common stock outstanding as of December 31, 2008.

Five Percent or More
Name and Position	Business Address	Total	Percent of
			Class
Maxim TEP, Limited	1 London Wall	21,700,000	16.97%
	London, EC 2Y 5AB


Harvey Pensack	7309 Barclay Court	12,845,546	9.79%
Director	University Park, FL 34201
	Individually Owned
	Harvey Pensack Revocable Living Trust
	Joan Pensack



Carl Landers	141 S. Union Street	7,122,500	5.54
Director	Madisonville, KY 42431
	Individually Owned

Robert McCann	160 Yacht Club Way	6,618,334	5.17%
	Hypoluxo, FL 33462

The following table sets forth beneficial ownership of the Company’s common stock as of December 31, 2008 for each of the named executive officers and directors individually and as a group. The percentage ownership is based on 127,859,869 shares of common stock outstanding as of December 31, 2008.

Name and Position	Business Address	Total	Percent of
			Class
Harvey Pensack (1)	7309 Barclay Court
Director	University Park, FL 34201	12,845,546	9.79%

	Individually Owned
	Harvey Pensack Revocable Living Trust
	Joan Pensack



Carl Landers (2)	141 S. Union Street
Director	Madisonville, KY 42431	7,122,500	5.54%
01/01 -07/28/08

W. Marvin Watson (3)	Individually Owned
Chairman of the Board	11 Steepbank Drive
Chief Executive Officer	The Woodlands, TX 77381	5,566,549	4.33%
01/01 -07/28/08
	Individually Owned


Dr. John P. Ritota, Jr.(4)	Individually Owned
01/01 -07/28/08	919 Seagate Drive	4,141,667	3.18%
	Delray Beach, FL 33483


Robert Sepos	Individually Owned
Vice President &	87 Robindale Circle
Chief Operating Officer	The Woodlands, TX 77382	2,213,135	1.73%
01/01 - 01/25/08


Dominick F. Maggio	110 Bethany Bend Circle
Vice President	The Woodlands, TX 77382
Chief Information Officer	Individually Controlled &
and Corporate Secretary	Owned by AMDG Incorporated	1,390,922	1.09%


John J. Dorgan (5)	555 Byron Street
Director	Palo Alto, CA 94301	1,965,675	1.52%
01/01 -07/28/08	Individually Owned


Robert D. Johnson (6)	13606 Bermuda Dunes Court
CEO	Houston, TX 77069
	Individually Owned	3,722,468	2.85%

Steve Warner (7)	400 N Flagler Drive, #1601
Director	West Palm Beach, FL 33401
	Individually Owned	1,025,000	0.80%

Glenn Biggs (8)	1208 South Main Street
Director	Boerne, TX 78006
01/01 - 01/25/08	Individually Owned	550,397	0.43

Arturo F. Henriquez	2 Wenoah Place
CFO	The Woodlands, TX 77389
	Individually Owned	502,347	0.39%

Robert C. Johnson (9)
Director	7085 W. Belmont
	Littleton, CO 80123
	Individually Owned	200,000	0.16%

All current directors and executive officers as a group (12) persons		41,246,206	29.58%

(1) Includes (i) 1,216,250 shares issuable pursuant to outstanding warrants, (ii) 450,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008, and (iii) 1,818,182 shares of voting preferred stock. Also includes 3,983,779 shares held by the Harvey Pensack Revocable Living Trust of which Mr. Pensack is a trustee, and 2,228,042 shares held by Joan Pensack, Mr. Pensack’s wife.

(2) Includes 600,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.

(3) Includes (i) 2,500 shares issuable upon exercise of warrants, and (ii) 600,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.

(4) Includes (i) 1,650,000 shares issuable upon exercise of outstanding warrants, and (ii) 600,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.

(5) (i) 600,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.

(6) Includes 547,456 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.

(7) Includes 300,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.

(8) Includes 300,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.

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

Related Party Transactions

In October 2007, the Company and the holders of the wellbore interests in the South Belridge Field (the “Holders”), entered into an agreement pursuant to which the Holders assigned their ownership interest in the wellbores back to the Company in consideration for promissory notes in the aggregate principal amount of $3,000,000 and an aggregate of 373,333 shares of the Company’s common stock. The notes bear interest at 9% per annum and mature in October 2009. In addition, the Company issued the Holders five year warrants exercisable for up to 1,000,000 shares of the Company’s common stock at a per share exercise price of $0.75. One of the Company’s directors, Mr. Pensack, and members of his immediate family participated in this transaction. Subsequent to this, during the second and third quarters of 2008, the Company issued 5,454,545 shares of series A Preferred Stock in exchange for the $3,000,000 of corporate notes payable and accrued interest. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

During 2008, the Company entered into notes payable totaling $75,000 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 dividing the principal amount of the note and interest by $0.75 per share. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

During 2008, the Company entered into notes payable totaling $100,000 with one Director. These notes bear interest at a fixed rate of 15% 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 dividing the principal amount of the note and interest by $0.75 per share. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

During 2008, a Director was paid a $15,000 commission for raising funds and received 100,000 warrants to purchase the Company’s common stock with an exercise price of $0.75 per share in connection with the sale of the Company’s common stock whose value as assessed using the Black-Scholes model was $41,972.

In 2008, the Company granted 900,000 stock options to members of its board of directors whose value, as assessed using the Black-Scholes model, was $393,448, for their service as directors. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

Director Independence

We anticipate being listed for trading 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 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

As disclosed earlier, the board of directors approved the engagement of M&K CPAS, PLLC of Houston, Texas (“M&A”) for all audit and permissible non-audit services, and dismissed Pannell Kerr Forster of Texas, P.C. (“PKF”), the Company's prior certifying accountant, in each case effective as of December 31, 2008.

The table below sets forth the aggregate fees billed for the years ended December 31, 2008 and December 31, 2007 for professional services rendered by our principal accounting firms for audit services and audit related services (as indicated) for our financial statements; and the other fees billed for the years ended December 31, 2008 and December 31, 2007 for professional services rendered by such firms related to the performance of audit services; and aggregate fees billed for such year for all other services billed by such firms.

	M&K				PKF Texas						Total
After careful consideration, the Audit Committee of the Board of Directors has determined that payment of the audit fees is in conformance with the independent status of the Company's principal independent accountants.	2008		2007		2008			2007			2008			2007

Current Year Audit fees - audit of annual financial statements and review of financial statements included in our 10-QSB, services normally provided by the accountant in connection with statutory and regulatory filings.	$	58,000	$	-	$	274,633		$	66,783		$	332,633		$	66,783

Audit-related fees - related to the performance of audit or review of financial statements not reported under "audit fees" above	$	-	$	-	$	-		$	260,337		$	-		$	260,337

Audit Related fees related to the Form 10 Registration Statement	$	-	$	-	$	-		$	-		$	-		$	-

Tax fees - tax compliance, tax advice and tax planning	$	-	$	2,850	$	-		$	47,763		$	-		$	50,613

All other fees - services provided by our principal accountants other than those identified above	$	-	$	-	$	143,959		$	112,696		$	143,959		$	112,696

Less Discounts	$	-	$	-	$	(50,650	)	$	(25,286	)	$	(50,650	)	$	(25,286	)

Total fees paid or accrued to our principal accountants	$	58,000	$	2,850	$	367,943		$	462,293		$	425,943		$	465,143

The PKF bills are still in dispute nonetheless they are reflected in full in our accounts payable.

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: November 16, 2009	CONQUEST PETROLEUM INCORPORATED

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