Edgar Filing: Conquest Petroleum Inc

As filed with the Securities and Exchange Commission on October 9, 2009.

Registration No. 333-_______

UNITED STATES

Securities and Exchange Commission

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Conquest Petroleum Incorporated

(Exact name of registrant as specified in its charter)


Texas	1382	20-0650828
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

24900 Pitkin Road, Suite 308

Spring, Texas 77386

(281) 466-1530

(Address, including zip code, and telephone number,

including area code, of registrant’s principal executive offices)

Robert D. Johnson

24900 Pitkin Road, Suite 308

Spring, Texas 77386

(281) 466-1530

(Name and address, including zip code, and telephone number,

including area code, of agent for service)

Copies to:

Bryce D. Linsenmayer

Amy Moss

Haynes and Boone, LLP

1221 McKinney Street, Suite 2100

Houston, Texas 77010

(713) 547-2007

(713) 236-5540 (fax)

Approximate date of commencement of proposed sale of securities to the public: As soon as practical after the effective date of this Registration Statement.

If any of the securities being registered on this form are being offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. x

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. 

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. 

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b2 of the Exchange Act.

Large accelerated filer  Accelerated filer 

Non-accelerated filer  Smaller reporting company x

(Do not check if a smaller reporting company)

CALCULATION OF REGISTRATION FEE


Title of Each Class of Securities to be Registered	Amount to be Registered(1)	Proposed Maximum Offering Price Per Unit(2)	Proposed Maximum Aggregate Offering Price	Amount of Registration Fee

Common Stock, par value $0.00001 per share	6,556,100	$0.10	$655,610	$36.58

(1)

Represents shares offered by the selling stockholders. Includes (i) restricted shares owned by the selling stockholders and (ii) an indeterminable number of additional shares of common stock, pursuant to Rule 416 under the Securities Act of 1933, as amended, that may be issued to prevent dilution from stock splits, stock dividends or similar transactions that could affect the shares to be offered by selling stockholders.

(2)

Pursuant to Rule 457(c) under the Securities Act of 1933, as amended, the registration fee has been calculated based on the average of the bid and asked price of the Registrant’s Common Stock as reported by the OTC Bulletin Board on October 5, 2009.

The Registrant hereby amends this Registration Statement on such date as may be necessary to delay its effective date until Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

Subject to completion, dated October 9, 2009

Preliminary Prospectus

6,556,100 Shares

Conquest Petroleum Incorporated

Common Stock

_______________

This prospectus relates to the resale of 6,556,100 shares of our common stock by the selling stockholders named within, including YA Global Master SPV Ltd., (“YA Global”). We may from time to time issue shares of our common stock to the selling stockholder at 93.5% of the market price at the time of such issuance determined in accordance with the terms of our Standby Equity Distribution Agreement, dated as of August 21, 2009, or SEDA, with YA Global. The selling stockholder may sell shares from time to time in regular brokerage transactions, in transactions directly with market makers or in privately negotiated transactions. We have agreed to pay all costs relating to the registration of the securities.

For additional information on the methods of sale that may be used by the selling stockholders, see the section entitled “Plan of Distribution” on page 54. We will not receive any of the proceeds from the sale of these shares. However, we will receive proceeds from YA Global from the initial sale to such stockholder of these shares.

We are currently listed on the OTC Bulletin Board under the trading symbol “CQPT.” On October 5, 2009, the last reported sale price of the common stock on the OTC Bulletin Board was $0.10.

Investing in our common stock involves risks. See “Risk Factors” beginning on page 5.

We may amend or supplement this prospectus from time to time by filing amendments or supplements as required. You should read this prospectus and any prospectus supplement carefully before you decide to invest. You should not assume that the information in this prospectus is accurate as of any date other than the date on the front of this document.

With the exception of YA Global Master SPV Ltd., which has informed us it is an “underwriter” within the meaning of the Securities Act of 1933, as amended or the Securities Act, to the best of our knowledge, no other underwriter or person has been engaged to facilitate the sale of shares of our stock in this offering. The Securities and Exchange Commission may take the view that, under certain circumstances, any broker-dealers or agents that participate with the selling stockholder in the distribution of the shares may be deemed to be “underwriters” within the meaning of the Securities Act. Commissions, discounts or concessions received by any such broker-dealer or agent may be deemed to be underwriting commissions under the Securities Act.

___________

Neither the Securities and Exchange Commission, nor any state securities commission or other regulatory body, has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

___________

The date of this prospectus is October 9, 2009.

TABLE OF CONTENTS

SUMMARY	1
CONQUEST PETROLEUM INCORPORATED	1
RISK FACTORS	5
FORWARD-LOOKING STATEMENTS	16
USE OF PROCEEDS	17
DIVIDEND POLICY	17
SELECTED HISTORICAL FINANCIAL DATA	18
OUR BUSINESS	20
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION	32
AND RESULTS OF OPERATIONS
MANAGEMENT	43
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS	49
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	51
SELLING STOCKHOLDERS	52
PLAN OF DISTRIBUTION	54
DESCRIPTION OF CAPITAL STOCK	56
WHERE YOU CAN FIND MORE INFORMATION	59
LEGAL MATTERS	59
EXPERTS	59

Glossary of Terms A-1

You should rely only on the information contained in this prospectus. The selling stockholders have not, authorized any person to provide you with different information. This prospectus is not an offer to sell, nor is it an offer to buy, these securities in any jurisdiction where the offer or sale is not permitted. The information in this prospectus is complete and accurate only as of the date of this prospectus regardless of the time of delivery of this prospectus or any sale of our common stock. Our business, financial condition, prospects and other information may have changed since this date.

This prospectus includes industry data and forecasts that we obtained from internal company surveys, market research, consultant surveys, publicly available information and industry publications and surveys. Industry surveys, publications, consultant surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable.

The body of accounting principles generally accepted in the United States is commonly referred to as “GAAP.” A non-GAAP financial measure is generally defined by the Securities and Exchange Commission, or SEC, as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measures. Any non-GAAP measures are described within

SUMMARY

This summary highlights selected information described in more detail later in this prospectus, but does not contain all of the information you should consider in making an investment decision. You should also read this entire prospectus, including the risks of investing in our common stock discussed in the section entitled “Risk Factors” and the financial statements and related notes appearing elsewhere in this prospectus before investing in our common stock. References in this prospectus to “Conquest,” the “company,” “us,” “our” or “we” are to Conquest Petroleum Incorporated and its subsidiaries unless the context requires otherwise.

If you are not familiar with some of the industry terms used in this prospectus, please read our Glossary of Terms included as Appendix A to this prospectus.

We held our annual shareholders’ meeting on June 24, 2009. At the shareholders’ meeting, the shareholders approved the change of the company name to Conquest Petroleum Incorporated and a 1 for 10 reverse stock split. Unless otherwise noted, all share numbers have been adjusted for the reverse stock split.

CONQUEST PETROLEUM INCORPORATED

Our Company

Conquest Petroleum Incorporated (formerly known as Maxim TEP, Inc.) is headquartered in Spring, Texas, a suburb of Houston. We are an oil and natural gas exploration, development and production (E&P) company geographically focused on the onshore United States. Our 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 producing wells. Selected fields also have the availability of additional development drilling sites. We seek to have an inventory of existing wells to exploit and a number of new drilling sites to maintain growth, while increasing reserves and cash flow. We have an active workover program to bring non-producing wells back into production while minimizing operational costs.

The following are key elements of the business strategy:

Phase One – Acquisition Phase

Phase One was to acquire low risk, mature fields with proven and probable reserves. We secured initial funding from several accredited investors and through debt financing, and acquired fields with existing wells and infill development drilling opportunities, and now currently own the rights to oil and natural gas leases in Kentucky and Louisiana.

In buying existing oil and natural gas fields, we 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 can be made as to the value of the target property.

Phase Two – Completion of Existing Wells Phase

In Phase Two, our strategy is exploitation of our fields by investing in low risk workover programs on existing wells, monetizing significant upside in workover wells on already proved assets, and developing proved developed non-producing wells into proved developed producing (PDPs) assets with no associated exploration risk. We have over 30 existing wells in the Delhi and Belton fields being brought back on production. This phase is highly dependent on our ability to secure funding from debt and equity sources.

the installing of hub compressors, installing packers to repair holes in casings, and swabbing existing wells. Lastly, we have initiated a 17 well workover program in our Belton Field in Kentucky. Due to limited funding, we have only partially completed the planned activities and foresee the plan to extend into late 2009, if funding is obtained.

Phase Three – Development Drilling on Proved Assets

In Phase Three, our strategy is to execute infill drilling of our oil and gas assets. We will develop proved undeveloped (PUDs) assets into proved developed producing (PDPs) assets with no associated exploration risk. We have identified over 300 infill prospects in the Marion field. We have identified four development oil opportunities in our Delhi field. And we have identified 24 probable gas opportunities in the New Albany Shale and six development oil opportunities in the McCloskey Sand in our Belton field.

All of the planned development drilling and enhancements assume that we are successful in securing our 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, working interest partner issues, the ability to raise additional capital, the success of the drilling programs, weather delays and other factors. Our ability to drill the number of wells budgeted for 2009 and 2010 is dependent on funding.

Phase Four – Expansion Phase

In Phase Four, an effort will be made to expand our oil and natural gas reserves through the acquisition of fields, wells or working interest in oil and gas assets, with similar characteristics as those in Phase One. To minimize risk, properties with blanket type geological deposition will be sought.

Our new management consists of personnel who have successfully followed and executed this exact business plan in the past. By exploiting resources that are less risky than many E&P companies, we are better able to function with less general and administrative costs.

Going Concern

As presented in the unaudited consolidated financial statements herein, we have incurred a net loss of $9,388,486 during the six months ended June 30, 2009, and losses are expected to continue in the near term. Current liabilities exceeded current assets by $15,009,783 and the accumulated deficit is $104,662,100 at June 30, 2009. Amounts outstanding and payable to creditors are in arrears and we are in negotiations with certain creditors to obtain extensions and settlements of outstanding amounts. We are currently in default on certain of our debt obligations and have no future borrowings or funding sources available under our existing financing arrangements. We anticipate that significant additional capital expenditures will be necessary to develop our oil and natural gas properties, which consist primarily of proved reserves that are non-producing or undeveloped, before significant positive operating cash flows will be achieved.

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

For additional information on this and other risk involved with our company see “Risk Factors” beginning on page 5.

August 2009 Standby Equity Distribution Agreement

to YA Global. On August 21, 2009, we issued 260,000 shares of our common stock to YA Global in lieu of payment of a $65,000 commitment fee. As part of the transaction, we also issued YA Global a warrant to buy 1,500,000 shares of our common stock at $7.50 per share. As of September 30, 2009, we had not sold any shares of common stock to YA Global under the SEDA.

For each share of common stock purchased under the SEDA, YA Global will pay ninety-three point five percent (93.5%) of the lowest daily volume weighted average price during the five consecutive trading days after we provide notice to YA Global. Each such advance may be for an amount not to exceed the average daily trading volume of our common stock for the five consecutive trading days prior to the notice date. In addition, in no event shall the number of shares of common stock issuable to YA Global pursuant to an advance cause the aggregate number of shares of common stock beneficially owned by YA Global and its affiliates to exceed 4.99%.

Our right to deliver an advance notice and the obligations of YA Global hereunder with respect to an advance is subject to our satisfaction of a number of conditions, including that our common stock is trading, and we believe will continue for the foreseeable future to trade, on a principal market, that we have not received any notice threatening the continued listing of our common stock on the principal market and that a registration statement is effective.

In addition, without the written consent of YA Global, we may not, directly or indirectly, offer to sell, sell, contract to sell, grant any option to sell or otherwise dispose of any shares of common stock (other than the shares offered pursuant to the provisions of the agreement) or securities convertible into or exchangeable for common stock, warrants or any rights to purchase or acquire, common stock during the period beginning on the 5th trading day immediately prior to an advance notice date and ending on the 5th trading day immediately following the settlement date.

We may terminate the SEDA upon fifteen trading days of prior notice to YA Global, as long as there are no advances outstanding and we have paid to YA Global all amounts then due. A copy of the SEDA is attached hereto as an exhibit.

Corporate Information

Our principal executive offices are located at 24900 Pitkin Road, Suite 308, Spring, Texas 77386, and our telephone number is (281) 466-1530. Our website address is www.conquestpetroleum.com. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

The Offering

We have agreed to register 6,556,100 shares of our common stock owned by the selling stockholders named in this prospectus for resale pursuant to this prospectus. The named selling stockholders may offer shares of our common stock through public or private transactions.

Common stock offered by the selling stockholders	6,556,100 shares.
Use of proceeds	We will not receive any of the proceeds from the sale of shares by the selling stockholders. We will receive proceeds from any sale of shares of common stock to YA Global pursuant to the SEDA and proceeds received under the SEDA will be utilized for working capital and general corporate purposes.
Dividend policy	We have not declared or paid any cash dividends on our common stock, and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. For more information, see “Dividend Policy” on page 17.
Market symbol	CQPT.
Risk factors	For a discussion of certain risks associated with an investment in our common stock, please see the section entitled “Risk Factors” beginning on page 5.

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.

There is a substantial doubt about our ability to continue as a going concern. If we cannot continue to operate our business, you could lose your entire investment in our company.

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 and was $9.39 million and $11.01 million before discontinued operations for the six months ended June 30, 2009 and 2008, 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. We do not have sufficient cash on hand to fund our monthly budget for the next 12 months. As we cannot assure a lender that we will be able to successfully explore and develop our oil and gas properties, we will probably find it difficult to raise debt financing from traditional sources. We have traditionally raised our operating capital from the sale of equity and debt securities but there can be no assurance that we will continue to be able to do so.

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.

These circumstances raise substantial doubt about our ability to continue as a going concern, as described in note 1 to our consolidated financial statements for the six months ended June 30, 2009, which are included with this prospectus. Our consolidated financial statements do not reflect any adjustments that might result if we are unable to continue our business.

We may face challenges in accessing the capital markets for further 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:

·	the level of consumer product demand;

·	the domestic and foreign supply of oil and natural gas;

·	overall economic conditions;

·	weather conditions;

·	domestic and foreign governmental regulations and taxes;

·	the price and availability of alternative fuels;

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

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

·	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:

·	delays imposed by or resulting from compliance with regulatory requirements;

·	pressure or irregularities in geological formations;

·	shortages of or delays in obtaining equipment and qualified personnel;

·	equipment failures or accidents;

·	adverse weather conditions;

·	reductions in oil and natural gas prices; and

·	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 consist of undeveloped reserves.

As of the end of our 2008 fiscal year, approximately 100% of the Delhi Field Properties’ proved reserves, 99% of the Belton Field Properties’ proved reserves and 78% 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:

·	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;

·	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;

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

·	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

·	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:

·	our ability to obtain leases or options on properties for which we have 3-D seismic data;

·	our ability to acquire additional 3-D seismic data;

·	our ability to identify and acquire new exploratory prospects;

·	our ability to develop existing prospects;

·	our ability to continue to retain and attract skilled personnel;

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

·	the results of our drilling program;

·	hydrocarbon prices; and

·	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:

·	timing and amount of capital expenditures;

·	expertise and financial resources;

·	inclusion of other participants in drilling wells; and

·	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:

·	natural disasters;

·	permits for drilling operations;

·	drilling and plugging bonds;

·	reports concerning operations;

·	the spacing and density of wells;

·	unitization and pooling of properties;

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

·	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.

There are substantial risks associated with the Standby Equity Distribution Agreement with YA Global Investments, L.P. which could contribute to the decline of our stock price and have a dilutive impact on our existing stockholders.

The sale of shares of our common stock pursuant to the SEDA will have a dilutive impact on our stockholders. YA Global may re-sell all of the shares we issue to them under the SEDA and such sales could cause the market price of our common stock to decline significantly with advances under the SEDA. To the extent of any such decline, any subsequent advances would require us to issue a greater number of shares of common stock to YA Global in exchange for each dollar of the advance. Under these circumstances, our existing stockholders would experience greater dilution. If we were to fully draw down the commitment amount under the SEDA, we would have to issue 13.27% of our currently outstanding shares. Although YA Global is precluded from short sales, the sale of our common stock under the SEDA could encourage short sales by third parties, which could contribute to the further decline of our stock price.

The market price of our common stock may be volatile.

As we are a publicly 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.

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward looking statements. We have based these forward looking statements on our current expectations and projections about us and our industry. These forward looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this prospectus that address activities, events or developments that we expect or anticipate may occur in the future, including such things as future capital expenditures, business strategy, competitive strengths, goals, growth of our business and operations, plans and references to future successes may be considered forward looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “intend,” “plan,” “project,” “forecast,” “may,” “should,” “expect,” “probably” or similar expressions, we are making forward looking statements. Our forward looking statements speak only as of the date made and we will not update forward looking statements unless the securities laws require us to do so.

Some of the key factors which could cause our future financial results and performance to vary from those expected include:

·	the timing and extent of changes in the price of oil and gas;

·	our future capital requirements and availability of financing on satisfactory terms;

·	competition in the oil and gas industry;

·	the condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions;

·	the effects of weather on our operations;

·	cost and other effects of legal proceedings, settlements, investigations and claims, including liabilities which may not be covered by indemnity or insurance; and

·	governmental regulation.

The information contained in this prospectus, including the information set forth under the heading “Risk Factors,” identifies additional factors that could cause our results or performance to differ materially from those we express or imply in our forward looking statements. Although we believe that the assumptions underlying our forward looking statements are reasonable, any of these assumptions and, therefore, the forward looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward looking statements which are included in this prospectus, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved.

USE OF PROCEEDS

We will not receive any proceeds from the sale of shares by the selling stockholders. All net proceeds from the sale of the common stock covered by this prospectus will go to the selling stockholders. However, we will receive proceeds from any sale of shares of common stock to YA Global pursuant to the SEDA

We anticipate, and have represented to YA Global in the SEDA, that the proceeds received under the SEDA will be utilized only for working capital and general corporate purposes.

DIVIDEND POLICY

We have not declared or paid any cash dividends on our common stock, and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board.

SELECTED HISTORICAL FINANCIAL DATA

The following table shows selected historical financial data for the years ended December 31, 2007 and 2008 and for the six months ended June 30, 2008 and 2009. The financial data for each annual period has been derived from our audited financial statements included elsewhere in this prospectus. Our historical results are not necessarily indicative of results to be expected for any future period. You should read this financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements, including the notes thereto, included elsewhere in this prospectus.

	Unaudited
							Six Months			Six Months
	Year ended			Year ended			Ended			Ended
	December 31,			December 31,			June 30,			June 30,
	2008			2007 (1)			2009			2008

Revenues:
Oil and natural gas revenues	$	1,822,893		$	1,852,365		$	374,889		$	947,060
Drilling services revenues		-			329,018			-			-
License fees, royalties and related services		163,458			257,500			9,000			34,692

Total revenues		1,986,351			2,438,883			383,889			981,752

Cost and expenses:
Production and lease operating expenses		1,295,693			1,664,279			394,639			438,414
Drilling operating expenses		4,628			1,059,168			-			3,741
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			258,825			917,861
Revenue sharing royalties		145,583			144,157			-			40,227
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			67,160			47,028
General and administrative expenses		12,066,399			8,492,384			8,634,257			9,041,349

Total cost and expenses		21,558,272			15,091,416			9,354,881			10,488,620

Loss from operations		(19,571,921	)		(12,652,532	)		(8,970,992	)		(9,506,868	)

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	)		(686,480	)		(1,780,557	)
Gain on transfer of assets		-			-			-			78,282
Gain/Loss on sale of assets		602,879			-			266,346			-
Loss on settlement		(1,368,000	)		-			-			-
Interest Income		45,417			-			-			-
Other miscellaneous income (expense), net		(703,601	)		13,938			3,000			163,528

Total other income (expense), net		(7,280,723	)		(4,240,510	)		(417,494	)		(1,538,747	)

Net loss before discontinued operations		(26,852,644	)		(16,893,042	)		(9,388,486	)		(11,045,615	)

Gain (loss) from discontinued operations		20,823,141			(13,092,498	)		-			22,042,660

Net loss	$	(6,029,503	)	$	(29,985,540	)	$	(9,388,486	)	$	10,997,045

Balance Sheet Data (at period end):
Property, plant and equipment, net		8,762,921			15,462,892			8,588,000			15,947,973
Total assets		9,819,191			34,938,279			9,226,629			22,251,172
Long-term debt	$	-		$	54,375,538		$	-		$	6,774,172

See note to consolidated financial statements.

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

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

OUR BUSINESS

Company Overview

Conquest Petroleum Incorporated, formerly Maxim TEP, Inc. was formed in 2004 as a Texas corporation to acquire, develop, produce and exploit oil and natural gas properties. Our major oil and natural gas properties are located in Louisiana, Kentucky, and Arkansas. Our 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 possible tertiary recovery methods could revitalize them. Targeted fields also have the availability of additional drilling sites. We seek 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. We use 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

Phase One was to acquire low risk, mature fields with proven and probable reserves. We secured initial funding from several accredited investors and debt financing, and acquired fields with existing wells and infill development drilling opportunities, and now currently own the rights to oil and natural gas leases in Louisiana, Kentucky, and Arkansas.

Phase Two – Completion of Existing Wells Phase

Currently, we have active operations on our fields located in Louisiana and Kentucky. We have begun an active fourteen well workover program on our biggest asset, the Delhi Field in Louisiana. Of the fourteen, eight producing wells and six water injection wells, all in the Mengel Sand, will be completed We have 515 low rate productive natural gas wells in our Marion field in Louisiana that we received through the purchase of this field along with over 110 miles of a natural gas gathering pipeline. We have plans to repair leaks in the existing pipeline to more efficiently capture additional natural gas from the existing wells as well as other remedial programs such as the installing of hub compressors, installing packers to repair holes in casings, and swabbing existing wells. Lastly, we have initiated a 17 well workover program in our Belton Field in Kentucky. Due to limited funding, we have only partially completed the planned activities and foresee the plan to extend into late 2009, if funding is obtained.

Phase Three – Development Drilling on Proved Assets

Phase Four – Expansion Phase

Our new Management consists of personnel who have successfully followed and executed this exact Business Plan in the past. By exploiting resources that are less risky than many E&P companies, we are better able to function with less general and administrative costs.

Recent Developments

On August 21, 2009, and amended on September 25, 2009, the Company and YA Global entered into a Standby Equity Distribution Agreement, or SEDA, pursuant to which, for a two-year period, we have the right to sell shares of our common stock to YA Global. On August 21, 2009, we issued 260,000 shares of our common stock to YA Global in lieu of payment of a $65,000 commitment fee. As part of the transaction, we also issued YA Global a warrant to buy 1,500,000 shares of our common stock at $7.50 per share. As of September 30, 2009, we had not sold any shares of common stock to YA Global under the SEDA.

Also in 2009, we entered into an agreement with Potomac Capital, LLC whereby Potomac will render advisory services in assisting in obtaining market makers for our public stock, assistance in securing credible public and investor relations entities, private and public equity investment, debt investment and funding for the oil and gas reserves we own. In addition, Potomac will provide an investor who will provide funding for the monetization of our oil and gas reserves. The investor will provide us with a loan, the interest on which is paid out of production from our properties. We issued Potomac 500,000 shares of our common stock as a fee for its services.

We also have engaged Captima Limited to act as a finder to initiate contacts between us and potential investors. We will pay Captima a finder’s fee of 1% to 5% of the transaction value for each transaction they bring us, depending on the type of transaction.

RESTRUCTURING - Employees

During 2008, we underwent a thorough restructuring in all aspects of our business from employees, consultants, office services, and field services. In January of 2008, we had 35 full-time employees and 8 recurring consultants. As of July 31, 2009, we had a total of 10 full-time employees and three recurring field consultants. There are five full-time employees at our corporate headquarters in Spring, Texas and five in field services.

PROPERTIES

We have 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, we acquired mineral right leases on 1,400 acres in the Delhi Field, in north-east Louisiana. Our 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 and increase reservoir pressure. The water from injection wells physically sweeps the displaced oil to adjacent production wells. Our 2009 development program involves bringing into production 8 existing wells in the Mengel Sand as well as 4 infill drilling possibilities of proved but undeveloped opportunities. In 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. We have a 95.8% Working Interest and 82.7% Net Revenue Interest in this field (encumbered by a 15% ORRI to a funding source).

The Marion Field - Union Parish, Louisiana

In December 2005, we obtained 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 Zones. The wells are currently producing on 40 acre spacing. We, and third party engineers, believe that there is great infill development drilling potential after drilling 4 wells with virgin pressure on 20 acre spacing in 2007. The field can be optimized at 10 acre spacing, creating 800 development opportuities. We forecast 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, we leased deep mineral rights (down to 9,500 feet) on approximately 8,000 acres of the 21,500 acres that will allow us to explore this deeper zone. We believe that a remedial program to fix the infrastructure from pipeline leakages to hub compressors can result in a significant increase in production. We have a 100% Working Interest and 71% Net Revenue Interest in this field.

Belton Field - Muhlenberg County, Kentucky

In April 2004, we 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, we leased the mineral rights to an additional 6,317 acres. Oil was discovered in this basin about 150 years ago. When we 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. Coal was discovered on the property and much of that coal was “mined-out” during strip mining operations. All mining operations ceased decades ago and the mines were reclaimed and are now pastures. Natural gas was discovered in the northwest corner of the field in the 1980’s and continued to produce

natural gas until recently. There are four 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 (4) a deep Silurian oil-bearing zone. We are in the process of bringing into production 17 existing upper McCloskey wells. Our 2009 and 2010 drilling program includes the drilling of 24 New Alabany Shale wells and six Lower McCloskey wells and will endeavor to farm out the deep Silurian zones. We have a 100% working Interest and approximately 76.5% Net Revenue Interest in this field on the 3008 acres.

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

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

·	A 75% Working Interest and 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

·	A 100% Working Interest and a 75% Net Revenue Interest in the Hospah, Lone Pine Field in McKinley County, New Mexico

	Average
	Working	Developed Acreage		Undeveloped Acreage		Total Acreage
	Interest	Gross	Net	Gross	Net	Gross	Net
Marion–LA	100%	10,300	10,300	11,200	11,200	21,500	21,500
Delhi–LA	95.77%	520	498	880	843	1,400	1,341
Belton– KY	100%	110	110	9,215	9,215	9,325	9,325
Total		10,930	10,908	21,295	21,538	32,225	32,166

Oil and Natural Gas Reserves

The reserves as of December 31, 2008 were derived from reserve estimates prepared by an independent reserve engineer, Mark Newendorp for the Delhi Field and the Marion 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 us.

The company did not have an independent reserve engineer evaluate the Belton Field as of December 31, 2008, therefore no reserves are shown for this property or costs capitalized on the balance sheet as of December 31, 2008.

The following table sets forth our estimated net proved oil and natural gas reserves and the PV10 value of such reserves as of December 31, 2008.

	Proved Reserves		All Reserves
	Developed		Total
Oil and condensate (Bbls)		1,073.12		1,073.12
Natural gas (MMcf)		5,340.00		5,340.00
Total proved reserves (BOE)		6,413.12		6,413.12
PV10 Value (MM)(1)	$	23,478.00	$	23,478.00

(1)

The PV10 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 Notes below). Management believes that the presentation of PV10 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 PV10 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 PV10 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 July 31, 2009.

	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

We purchased exclusive North American rights for a non-conventional lateral drilling technology invented by Carl Landers, a Director of ours 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. We sold all rights to these properties to a third party in 2009.

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.

We sold oil and natural gas production representing more than 10% of our 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)	We do not have a formal purchase agreement with this customer, but sell our production on a month-to-month basis at spot prices adjusted for field differentials.

(2)	Orchard Petroleum, Inc. is the operator of our wells in California and sells production on our 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 , or 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.

Legal Proceedings

We are subject to litigation and claims that have arisen in the ordinary course of business, the majority of which have resulted from our 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 us outside the ordinary course of business.

In the suit, Raymond Thomas, et al. vs Ashley Investment Company, et al., on June 26, 2009, the Judge for the 5th District Court, Louisiana approved the Judgment Dismissing Maxim and other Defendants and the Judgment Approving Maxim and other Defendants’ Settlement Agreement of Delhi Field Claims. We will be responsible for the remaining remediation costs to restore the surface leases to standards set by the Louisiana Department of Natural Resources. We will also be responsible for the payment of certain remediation, legal, and expert witness expenses incurred in the past and paid by a 3rd party. We have paid $683,000 and will owe a remaining approximate $200,000 for the remaining past due debt and remediation obligations.

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 they have obtained a partial judgment. We are in the process of negotiating payment 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 we paid them 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 our property for $2,000,000.

·	In the suit with 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 at March 31, 2009 and December 31, 2008.

·	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 our 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 us $100,000. We have come to an agreement whereby Mr. Shein will extend his $100,000 loan and we have facilitated the issuance of 375,000 shares of our common stock by a third party shareholder. . The issuance of shares by the third party shareholder on our behalf relieved $281,250 from stock payable as of June 30, 2009.

·	The former CEO, Marvin Watson is claiming expenses, past salary and severance in regards to his employment. We see no merit in his claim and we will defend ourselves 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.

In the suit with Pannell Kerr Forster of Texas PC (“PKF Texas”), PKF Texas is seeking payment for services rendered. We have retained an expert witness in this field to opine on the what we were charged and the ethics associated with PKF’s performance. At this point the amount and probability of payment is not determinable.

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 prospectus. 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 our 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 years ended December 31, 2008 and 2007 and the unaudited consolidated financial statements included elsewhere herein.

Going Concern

As presented in the unaudited consolidated financial statements herein, we have incurred a net loss of $9,388,486 during the six months ended June 30, 2009, and losses are expected to continue in the near term. Current liabilities exceeded current assets by $15,009,783 and the accumulated deficit is $104,662,100 at June 30, 2009. Amounts outstanding and payable to creditors are in arrears and we are in negotiations with certain creditors to obtain extensions and settlements of outstanding amounts. We are currently in default on certain of our debt obligations and have no future borrowings or funding sources available under our existing financing arrangements. We anticipate that significant additional capital expenditures will be necessary to develop our oil and natural gas properties, which consist primarily of proved reserves that are non-producing or developed, before significant positive operating cash flows will be achieved.

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

Results of Operations

Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Oil and Natural Gas Revenues. Oil and natural gas revenues for the six months ended June 30, 2009 and 2008 were $374,889 and $947,060, respectively, a decrease of 60.42%. This decrease was attributed to oil and gas prices being higher in 2008.

License Fees, Royalties & Related Services. License fees, royalties and related services for the six months ended June 30, 2009 and 2008 were $9,000 and $34,692, respectively, a decrease of $25,692. These fees were associated with the granting of sectional and regional licensing of our proprietary lateral drilling technology. The technology has since been sold to a third party.

Production and Lease Operating Expenses. Production and lease operating expenses for the six months ended June 30, 2009 and 2008 were $394,639 and $438,414, respectively, a decrease of 9.99%. This decrease was attributable to reductions in staff and decrease in well workover activity.

Revenue Sharing Royalties. Revenue sharing royalties for the six months ended June 30, 2009 and 2008 were nil and $40,227 respectively, a decrease of $40,227. This decrease was due to no interest sold in the quarter ended June 30, 2009.

Depletion, Depreciation and Amortization. Depletion, depreciation, and amortization for the six months ended June 30, 2009 and 2008 were $258,825 and $917,861, respectively, a decrease of $659,036. The decrease was due to the decrease in depletion and depreciation of the reserve basis in the Marion and Belton Field.

General and Administrative Expenses. General and administrative expenses for the six months ended June 30, 2009 and 2008 were $8,634,257 and $9,041.349, respectively. This net decrease of $407,092 is due to the continued efforts by management to curtail expenses during the six ended June 30, 2009. Included in the expenses for the six months ended June 30, 2009 are non-cash expenses of $2,775,000 and $4,404,002, respectively for compensation and third party services.

Interest Expense, net. Interest expense, net for the six months ended June, 2009 and 2008 was $686,840 and $1,780,557, respectively. Interest expense related to debt decreased significantly as a result of the conversion of notes payable during the last quarter of 2008.

Net Loss. We incurred a loss from operations for the six months ended June, 2009 and 2008 of $9,388,486 and $11,045,615 respectively, specifically due to reasons discussed above.

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 $29,472 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 we develop 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 we do not expect revenue in the future as we elected to no longer provide drilling services to outside third parties. Drilling revenue for the twelve months ended December 31, 2007 was $329,018. Our Tiger Bend Drilling, LLC subsidiary drilled two wells in the Stephens Field, of which we hold 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 our proprietary lateral drilling technology. We do not anticipate further revenue from this business segment. The technology has since been sold to a third party.

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 our drilling subsidiary Tiger Bend Drilling, LLC began incurring preparation costs which were expensed as it prepared to begin drilling wells for us in Arkansas in second and third quarters of 2007. During the 2008 period our drilling subsidiary incurred minimal operating costs as it wrapped up from completing the drilling of twelve wells for us 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. We plan 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 our 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 our 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. We have 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 us 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	$	(19,059	)		-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	$	-	$	485,971	$	(485,971	)		-100	%
Gen & Admn Support Costs	$	412,876	$	234,044	$	178,832			76	%
Travel & Entertainment	$	-	$	293,206	$	(293,206	)		-100	%
Insurance	$	34,101	$	154,932	$	(120,831	)		-78	%
Total Non Equity Based G&A	$	3,706,385	$	5,953,245	$	(2,246,860	)		-38	%

Gain on Extinguishment of Debt: We 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, we determined that due to the worsened financial markets and oil and gas industry, full impairment of our 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 our E&P activities. This will further postpone our ability to dedicate financial as well as human resources to our technology division in the short term future. As such, we have eliminated the division entirely. We have performed an impairment analysis of our patented lateral drilling technology in the third quarter ending September 2008 and determined $4,034,989 impairment was required. Our basis for such an impairment stemmed from the then recent and unprecedented financial environment affecting us and the world and the ever increasing restrictions on credit, equity and funding opportunities in general. This technology was sold to a third party in 2009.

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 approximately $8.5 million of notes payable and accrued interest into common and preferred stock. We also relieved approximately $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.

Other Miscellaneous Income (Expense), net: The majority of this expense is attributed to a loss on conversion of debt of $543,722. Other expenses include warrants issued for debt extensions, and expenses related to pending lawsuits.

Gain From Discontinued Operations: During April 2008, we sold our 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 2,170,000 shares of our common stock issued to Maxim 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, we 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. We have available Federal income tax net operating loss (“NOL”) carry forwards of approximately $71 million at December 31, 2008. Our NOL generally begins to expire in 2024. We did not recognize the tax benefit of NOL carry forwards as assets to the extent that management believes that the realization of the NOL was not considered likely at this time. The realization of future tax benefits is dependent on our ability

to generate taxable income within the carry forward period. This valuation allowance is provided for all deferred tax assets.

Net Loss: We had a 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.

Despite this, we received $1,500,000 restricted funding from an the Greater European Fund Limited, or GEF, to bring the Delhi field wells back into production and to satisfy certain obligations regarding the settlement of the Delhi lawsuit. The terms of the restricted funding were the issuance of a $1,500,000 note payable at an interest rate of 15% due and payable on June 30, 2010 (principal and interest), and the issuance of 200,000 shares of restricted common stock (the “Closing Shares”) valued at $7.50 per share as an inducement to loan the funds. If the principal and interest are not re-paid at the end of the one year period, GEF will gain legal right and title to 3,000,000 penalty shares of restricted common stock valued at $7.50 per share (the “Penalty Shares”). The Penalty Shares are being held by GEF and will become the property of GEF in the event of default. Also, we executed a term assignment of an overriding royalty interest in the Delhi Field equal to fifteen percent of eight-eights (15% of 8/8ths) of all revenue attributable to Hydrocarbons produced and saved from or attributable or allocable to the Delhi Field net of severance taxes for a period of 30 months ending on December 31, 2011. Further, if a total of $4,500,000 (to include the principal and interest repayment) is not paid at the end of the 30 month period, we will make a cash payment to cover the deficiency.

Effective May 1, 2008, we finalized our negotiations with BlueRock Energy Capital, LTD (“BlueRock”) to restructure our monthly production payment facility on our Marion Field. The new agreement calls for a reduction of the interest rate from its current 18% to 8% and to give back to us, up to $25,000 of our production payment per month so that the field would be cash flow positive. Our 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 we 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. As of June 30, 2009 , we determined this production payment facility was due within the next twelve months and hence classified as current liability. This agreement has since been extended for 6 months until October 30, 2009.

Effective May 1, 2009, we notified BlueRock that we were in default under the Conveyance and the Production Agreement. A third amendment was finalized and the 8% interest rate was increased back to 18%. BlueRock also assumed the payment of all lease operating expenses and revenue distributions under a separate loan facility. In such, we would be charged interest at the rate of 18% per annum on the new facility. Further, we would be required to repay a total of three times the funds advanced to retire the facility

June 30, 2009 Compared to December 31, 2008

At June 30, 2009, we had a working capital deficit of $15,009,783 as compared to a working capital deficit of $11,397,281 at December 31, 2008. Current liabilities increased to $15,224,360 at June 30, 2009 from $11,714,204 at December 31, 2008.

Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Net cash used in operating activities totaled $821,413 for the six months ended June 30, 2009. Net cash used in operating activities totaled $1,099,732 for the six months ended June 30, 2008. Net cash used in operating activities for the 2009 period consists primarily of the net loss of $9,388,486 and the increase in receivables of $122,771 added to the net increase in accounts payable and accrued liabilities of $91,309, and by several non-cash charges including common stock issued for services valued at $6,453,518 and depletion, depreciation and amortization of $258,825. The reduction in cash used in operating activities in the 2009 period was primarily due to the limited availability of funds.

Net cash provided by investing activities totaled $248,073 for the six months ended June 30, 2009. Net cash used in investing activities totaled $213,359 for the six months ended June 30, 2008. Net cash provided by investing activities for the 2009 period consists primarily of proceeds from the sale of properties.

Net cash provided by financing activities totaled $505,838 and $1,725,768 for the six months ended June 30, 2009 and 2008, respectively. Net cash provided by financing activities for the 2009 period consists of proceeds from new borrowings of $130,000 and funds provided by BlueRock for the Marion Field expenses.

While we are actively seeking additional funding sources, no future borrowing or funding sources are available under existing financing arrangements.

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

At December 31, 2008, we had a working capital deficit of $11,397,280 compared to a working capital deficit of $12,701,247 at December 31, 2007. Current liabilities decreased to $11,714,204 at December 31, 2008 from $15,028,178 at December 31, 2007. We significantly reduced our 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 $5,437,747 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 $3,829,558 for the twelve months ended December 31, 2007. Net cash provided by investing activities for the 2008 period consists primarily of $1,282,931 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 $3,543,049 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 our operating activities.

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 did not experience any significant changes due to the adoption of this pronouncement.

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. There were no applicable items on which the fair value option was elected for the periods shown within this registration statement.

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. The company has not entered into any business combinations since the effective date of SFAS 141R. The company will apply this literature toward any future acquisitions considered applicable.

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. We currently have no subsidiary subject to this standard and do not expect a material impact from SFAS No. 160 on our 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. We do not expect a material impact from SFAS No. 161 on our consolidated financial statements.

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. We do not expect a material impact from APB 14-1 on our consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (“GAAP”) in the United States (the GAAP hierarchy). SFAS 162 becomes effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board (“PCAOB”) amendment to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles” and is not expected to have a significant impact on our consolidated financial statements.

In May 2008, the FASB issued SFAS No. 163 Accounting for Financial Guarantee Insurance Contracts—an interpretation of FASB Statement No. 60 . SFAS 163 resolves existing inconsistencies in accounting for financial guarantee insurance contracts by insurance enterprises under FASB Statement No. 60, “Accounting and Reporting by Insurance Enterprises”. SFAS 163 requires that an insurance enterprise recognize a claim liability prior to an event of default (insured event) when there is evidence that credit deterioration has occurred in an insured financial obligation and clarifies how Statement 60 applies to financial guarantee insurance contracts, including the recognition and measurement to be used to account for premium revenue and claim liabilities. SFAS 163 also requires expanded disclosures about financial guarantee insurance contracts. SFAS 163 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and all interim periods within those fiscal years, except for some disclosures about the insurance enterprise’s risk-management activities. SFAS 163 is not expected to have a significant impact on our consolidated financial statements.

In May 2009, the FASB issued SFAS 165 (“SFAS 165”), “Subsequent Events.” This pronouncement establishes standards for accounting for and disclosing subsequent events (events which occur after the balance sheet date but before financial statements are issued or are available to be issued). SFAS 165 requires an entity to disclose the date subsequent events were evaluated and whether that evaluation took place on the date financial statements were issued or were available to be issued. It is effective for interim and annual periods ending after June 15, 2009. The Company adopted SFAS 165 effective June 30, 2009 and the adoption did not have a material impact on its consolidated financial statements. The date through which subsequent events have been evaluated is September 30, 2009, the date on which the financial statements were issued.

On May 1, 2009, the Emerging Issues and Task Force issued EITF No. 07-05, Determining Whether an Instrument (or an Embedded Feature) Is Indexed to an Entity's Own Stock ("EITF 07-05"). EITF 07-05 provides that an entity should use a two-step approach to evaluate whether an equity-linked financial instrument (or embedded feature) is indexed to its own stock, including evaluating the instrument's contingent exercise and settlement provisions. The adoption of EITF 07-05 has affected the accounting for certain freestanding warrants and preferred stock that contain exercise price adjustment features (“down round provisions”). We had no instruments as of the date of this audit that fell within the scope of EITF 07-05.

In June 2009, the FASB issued SFAS 168 (“SFAS 168”), “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” SFAS 168 will become the source of authoritative U.S. generally accepted accounting principles (GAAP) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non grandfathered non-SEC accounting literature not included in the Codification will become non authoritative. This statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company does not expect the adoption of FAS 168 to have an impact on the Company’s results of operations, financial condition or cash flows.

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, we are 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 our 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 our common stock and corresponding volatility, and our 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 ten years.

Long-lived Assets and Intangible Assets

We account 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, we determined that due to the worsened financial markets and oil and gas industry, full impairment of our 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 our E&P activities. This will further postpone our ability to dedicate financial as well as human resources to our technology division in the short term future. As such, we has eliminated the division entirely. We have performed an impairment analysis of our patented lateral drilling technology in the third quarter ending September 2008 and determined $4,034,989 impairment was required. Our basis for such an impairment stemmed from the then recent and unprecedented financial environment affecting us and the world and the ever increasing restrictions on credit, equity and funding opportunities in general.

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.

Accordingly, we 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.

We review our 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 our estimated future undiscounted net cash flows, we 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 we believe approximates fair value, to determine the amount of impairment.

Stock based compensation

Beginning January 1, 2006, we adopted SFAS No. 123(R), “Accounting for Stock Based Compensation,” to account for our 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, we 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 us 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 mandatory 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, we 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 our 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.

MANAGEMENT

Executive Officers and Directors

The following is a list of our directors and executive officers on September 24, 2009.

Name	Age	Position	Year First Elected or Appointed
Robert D. Johnson	65	Chairman of the Board, President and CEO	Became President May 1, 2008 and Chairman and CEO on July 28, 2008
Robert C. Johnson	65	CFO, Secretary and Director	Became Director November 1, 2008 and CFO on May, 1, 2009
Harvey Pensack	85	Director	Became Director June 12, 2004
Ann Thomas	51	Director	Became Director September 9, 2009

Business Experience and Background of Directors and Executive Officers

Robert D. Johnson

Mr. Johnson joined us on May 1, 2008 and became our Chief Executive Officer and Chairman of the Board on July 28, 2008. He is a member of the Executive Committee of the Board of Directors. He brings with him over 40 years of experience in the oil and gas sector. Mr. Johnson graduated with a Bachelor of Science Degree in Petroleum Engineering from Louisiana State University in 1969. He joined Amoco Production Company upon leaving school. 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 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. After securing funding to acquire 68,000 acres of leases in the Texas State Waters and promoting the acreage on 27 prospects to outside 3rd parties. Conquest had five discoveries, then he divested the assets and dissolved the company in 1985 due to insufficient product prices. He formed Bannon Energy Incorporated in 1986 with an initial capitalization of $1,000. During the next 10 years, Bannon acquired 12 sets of producing properties and drilled over 284 development wells. He sold the assets of Bannon in 1996 for $38,000,000 and other considerations. Mr. Johnson dissolved Bannon in February of 2001. From February of 2001 until May of 2008 when he joined the company as President and Chief Operating Officer, he was retired.

Robert C. Johnson

Mr. Johnson was elected to the Board of Directors and Chairman of the Audit Committee on November 20, 2008. He was appointed our Chief Financial Officer on May, 1, 2009. Mr. Johnson graduated with a Professional Degree in Petroleum Engineering from the Colorado School of Mines in 1966. He joined Amoco Production Co. after graduation and advanced through numerous engineering and management positions during his 19+ year tenure. His final position was as Regional Production Manager in Houston, where he was responsible for the production operations in eight states and the management of 2,800 professionals. He left Amoco in 1985 and joined Held By Production, Inc (HBP), where as President and COO, he was responsible for managing the oil and gas assets of a private individual with holdings in Texas, Louisiana, Kansas, and Utah. He formed a $25 million development drilling program while at HBP and served as the managing general partner. In 1989, Mr. Johnson purchased an old-line manufacturing company in Denver, Colorado (Cyclo Manufacturing Company) and merged a large portion of it into a publicly traded company in 2001 and sold his controlling interest in 2007. Mr. Johnson started a mattress manufacturing company in 1999, serving as Chairman and CEO, and sold his controlling interest in 2003. From 2007 until November 20, 2008 when he joined us, he was retired.

Harvey M. Pensack

Mr. Pensack serves on the Nominating and Executive Committee of the Board of Directors. After graduating Cum Laude from Clarkson University in 1944, with a B.S. Degree 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 but then saw the potential in the young computer industry. In 1953, utilizing 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, and in 1970 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, and quick to recognize potential in many diverse fields, Mr. Pensack has been a private investor who specializes in researching and analyzing potential investment choices with a focus on management personnel and growth opportunity.

Ann Thomas

Ms. Thomas, is, and has been President of Killian Capital Group for three and a half years. Ms. Thomas began her career as the first female management trainee recruited by Conoco into the multiple phases of the oil and gas industry. She later joined Azmi Corporation where she managed a US subsidiary of a Saudi Arabian company, based in Houston for the purpose of investing in oil and gas reserves in the USA. Subsequently, Ms. Thomas joined Salomon Smith Barney where as Vice President, she initiated the company’s first institutional energy risk management department. Ms. Thomas served as Investment Officer of Sedona Industries. In addition to managing a diversified portfolio, an internal fund was created and run by Killian Capital Corp., a Commodity Trading Advisor, with Ms. Thomas as President. The fund’s strategy focused on investing in energy specific instruments based on global fundamental analysis, disciplined by a proprietary, quantitative model for entry and exit levels. Killian Capital Corp’s portfolio construction consists of futures and options on crude oil, heating oil, gasoline, and natural gas as well as conventional and alternative energy related equities and ETF’s.

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 Robert D. Johnson 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. Robert C. Johnson. 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

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 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 our principal executive offices. The Board of Directors will consider any such written communication at its next regularly scheduled meeting.

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.

Executive Compensation

The following table sets forth the total compensation awarded to, earned by, or paid to our “principal executive officer,” for the year ended December 31, 2008.

								Warrant
								and
Name and		Contract				Stock		Option		All Other
Principal	Year	Salary		Contract		Awards		Awards		Compensation		Total
Position		-(2)		Bonus		-(3)		-(4)		-(5)

Robert D. Johnson
Chief Executive Officer (1)(6)	2008	$	300,000	$	–	$	861,234	$	—	$	—	$	1,161,234

(1)	Robert D. Johnson has deferred all compensation to assist the Company with cash flows as of May 1, 2008.

(2)	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.

(3)	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 statements.

(4)

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 statements. Mr. Johnson waived any previously issued awards to assist the Company with its reorganization.

(5)	This column represents Company payments towards life insurance for executive officers and auto allowances capped at $1,000 monthly.

(6)	Robert D. Johnson was Chief Operating Officer and President from May 1, 2008 and assumed role as Chief Executive Officer effective July 28, 2008.

On May 1, 2008, we 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. On May 1, 2009 Mr. Robert C. Johnson became our Chief Financial Officer.

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

57,416

–

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 and who is a director going forward, 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 changed to 50,000 warrants cumulative per year on November 19, 2008.

Name	Stock Option		Stock Warrant		Total
	Awards (1)		Awards

Harvey Pensack	$	65,575	$	15,917	$	81,492

Robert C. Johnson	$	—		—		—

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

Equity Benefit Plans

2005 Incentive Compensation Plan

We adopted the 2005 Incentive Compensation Plan on May 13, 2005.

Share Reserve. We reserved 500,000 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 1,500,000 shares. On December 5, 2007, the Board of Directors amended the Plan to increase the number of shares reserved for issuance there under to 3,000,000 shares. On September 9, 2009, the Board of Directors amended the Plan to increase the

number of shares reserved for issuance there under to 10,000,000. On September 29, 2009, the Board of Directors amended the Plan to increase the number of shares reserved for issuance there under to 25,000,000. 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.

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 August 25, 2009 are deemed outstanding and beneficially owned by the person holding such options for purposes of computing the number of shares and percentage beneficially owned by such person, but are not deemed outstanding for purposes of computing the percentage beneficially owned by any other person. Except as indicated in the footnotes to these tables, and subject to applicable community property laws, the persons or entities named have sole voting and investment power with respect to all shares of our common stock shown as beneficially owned by them.

The following table sets forth certain information known to us as of August 25, 2009 with respect to each beneficial owner of more than five percent of our common stock. The percentage ownership is based on 17,106,456 shares of common stock outstanding as of August 25, 2009.

Five Percent or More
Name and Position	Business Address	Equity	Warrants	Options	Preferred	Total	Percent of Class

Greater European Fund	Keinwort Binsonhouse PO Box 76, Wests Center St. Helier, Jersey GE4 8PQ	200,000(1)				3,200,000	1.16%

Maxim TEP, Limited(2)	1 London Wall	2,170,000				2,170,000	12.69%
	London, EC 2Y 5AB


Harvey Pensack	7309 Barclay Court
Director	University Park, FL 34201

	Individually Owned	325,617
	Harvey Pensack Revocable Living Trust	398,378
	Joan Pensack	222,804

		946,799	110,938	4,500	181,818	1,244,055	7.15%

_______

(1)	Under an existing lending agreement, if we do not pay off the loan in full GEF will automatically receive 3,000,000 shares of our common stock.

(2)	This entity is not one of our affiliates.

The following table sets forth beneficial ownership of our common stock as of August 25, 2009 for each of the named executive officers and directors individually and as a group. The percentage ownership is based on 17,106,456 shares of common stock outstanding as of August 25, 2009.

Name and Position	Business Address	Equity	Warrants	Options	Preferred Stock	Total	Percent of Class
Harvey Pensack	7309 Barclay Court
Director	University Park, FL 34201

	Individually Owned	325,617
	Harvey Pensack Revocable Living Trust	398,378
	Joan Pensack	222,804

		946,799	110,938	4,500	181,818	1,244,055	7.15%


Robert D. Johnson	13606 Bermuda Dunes Court
CEO	Houston, TX 77069

	Individually Owned	239,831				239,831	1.40%

Robert C. Johnson
CFO and Director	7085 W. Belmont
	Littleton, CO 80123

	Individually Owned	210,500				210,500	1.23%


All current directors and executive officers as a group (3) persons		1,397,130	110,938	4,500	181,818	1,694,386	9.75%

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Related Party Transactions

In October 2007, we, along with the holders of the wellbore interests in the South Belridge Field, entered into an agreement pursuant to which the holders assigned their ownership interest in the wellbores back to us in consideration for promissory notes in the aggregate principal amount of $3,000,000 and an aggregate of 373,333 shares of our common stock. The notes bear interest at 9% per annum and mature in October 2009. In addition, we issued the holders five year warrants exercisable for up to 1,000,000 shares of our common stock at a per share exercise price of $0.75. One of our directors, Mr. Pensack, and members of his immediate family participated in this transaction. Subsequent to this, during the second and third quarters of 2008, we 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. This information does not give effect to the 1-for-10 reverse stock split of our common stock that occurred on August 5, 2009.

During 2008, we 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 our 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. This information does not give effect to the 1-for-10 reverse stock split of our common stock that occurred on August 5, 2009.During 2008, we 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 our 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. This information does not give effect to the 1-for-10 reverse stock split of out common stock that occurred on August 5, 2009,

During 2008, a Director was paid a $15,000 commission for raising funds and received 100,000 warrants to purchase our common stock with an exercise price of $0.75 per share in connection with the sale of our common stock whose value as assessed using the Black-Scholes model was $41,972. This information does not give effect to the 1-for-10 reverse stock split of out common stock that occurred on August 5, 2009,

In 2008, we granted 900,000 stock options to members of our 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. This information does not give effect to the 1-for-10 reverse stock split of out common stock that occurred on August 5, 2009,

Director Independence

We are listed for trading on the OTC Bulletin Board. While the OTC Bulletin Board does not maintain director independence standards, we are taking the necessary steps to have independent directors under the guidelines of the NYSE Amex.

SELLING STOCKHOLDERS

The selling stockholders named in the table below are offering for resale up to 6,556,100 shares of our common stock. These named selling stockholders may resell the shares of common stock covered by this prospectus as provided under the section entitled “Plan of Distribution” and in any applicable prospectus supplement.

The shares of common stock being offered hereby are being registered to permit public secondary trading, and the named selling stockholders may offer all or part of these securities for resale from time to time. The selling stockholders named in the table below, however, are under no obligation to sell all or any portion of such securities. All information with respect to the share ownership of a named selling stockholders has been furnished by such named selling stockholders.

Beneficial ownership includes the shares of our common stock outstanding as of the date of this prospectus, and the shares of our common stock that a named selling stockholder has the right to acquire within 60 days of the date of this prospectus. Unless otherwise indicated, each of the named selling stockholders has the sole power to direct the voting and investment over the securities owned by them. Because each of the named selling stockholders may sell all, some or none of the securities which they hold, no estimate can be given as to the number of or percentage of total shares of common stock or other securities that will be held by each of the named selling stockholder upon termination of this offering.

Other than the information set forth below regarding private placements of our securities, there were no other transactions between us and the named selling stockholders

Name of Selling Stockholder	Shares Beneficially Owned Before the Offering		Shares of Common Stock Being Offered	Common Stock Beneficially Owned After the Offering
	Number	%(2)	Number	Number(3)	% (3)(4)
Greater European Fund (GEF)	200,000	1.16%	200,000	200,000	1.16%
Maxim TEP, Limited	2,170,000	12.69%	716,100	2,170,000	12.69%
YA Global Master SPV Ltd.(4)	260,000(1)	1.52%	5,140,000	260,000	1.52%
Potomac Capital, LLC	500,000	2.9%	500,000	500,000	2.9%

__________

(1)

This number represents the shares currently held by the selling stockholder and does not include any additional shares which may be sold to the selling stockholder pursuant to the terms of the SEDA. On August 21, 2009, we issued 260,000 shares of common stock to YA Global in lieu of on-half of the payment of a commitment fee.

(2)	Applicable percentage ownership is based on 17,106,456 shares of our common stock outstanding as of August 25, 2009.

(3)	Assumes no sales of shares being offered in this prospectus.

(4)

YA Global Master SPV Ltd. is the investor under the SEDA. All investment decisions of, and control of, YA Global are held by its investment manager, Yorkville Advisors, LLC. Mr. Mark Angelo, the portfolio manager of Yorkville Advisors, makes the investment decisions on behalf of and controls Yorkville Advisors. YA Global acquired, or will acquire, all shares being registered in this offering in financing transactions with us. YA Global has

the right to receive another 260,000 shares of common stock in six months in lieu of the second half of the original commitment fee. The shares are included in the “Shares of Common Stock Being Offered” column.

PLAN OF DISTRIBUTION

The selling stockholders of the common stock, and any of their pledgees, assignees and successors-in-interest, which we collectively refer to herein as the selling stockholder, may, from time to time, sell any or all of their shares of common stock on the OTC Bulletin Board or any other stock exchange, market or trading facility on which the shares are traded or in private transactions. These sales may be at fixed or negotiated prices. A selling stockholder may use any one or more of the following methods when selling shares:

•

ordinary brokerage transactions and transactions in which the broker dealer solicits purchasers;

•

block trades in which the broker dealer will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

•

purchases by a broker-dealer as principal and resale by the broker dealer for its account;

•

an exchange distribution in accordance with the rules of the applicable exchange;

•

privately negotiated transactions;

•

broker-dealers may agree with the selling stockholders to sell a specified number of such shares at a stipulated price per share;

•

through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise;

•

a combination of any such methods of sale; or

•

any other method permitted pursuant to applicable law.

The selling stockholders may also sell shares under Rule 144 under the Securities Act, if available, rather than under this prospectus.

Broker-dealers engaged by the selling stockholders may arrange for other broker-dealers to participate in sales. Broker-dealers may receive commissions or discounts from the selling stockholders (or, if any broker-dealer acts as agent for the purchaser of shares, from the purchaser) in amounts to be negotiated, but, except as set forth in a supplement to this prospectus, in the case of an agency transaction not in excess of a customary brokerage commission in compliance with NASDR Rule 2440; and in the case of a principal transaction a markup or markdown in compliance with NASDR IM-2440.

In connection with the sale of the common stock or interests therein, the selling stockholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in turn engage in short sales of the common stock in the course of hedging the positions they assume. The selling stockholders may also enter into option or other transactions with broker-dealers or other financial institutions or the creation of one or more derivative securities which require the delivery to such broker-dealer or other financial institution of shares offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).

YA Global is, and any other selling stockholder, broker-dealer or agent that are involved in selling the shares may be deemed to be, an “underwriter” within the meaning of the Securities Act in connection with such sales. In such event, any commissions received by such broker-dealers or agents and any profit on the resale of the shares purchased by them may be deemed to be underwriting commissions or discounts under the Securities Act. Each selling stockholder has informed us that it does not have any written or oral agreement or understanding, directly or indirectly, with any person to distribute the common stock. In no event shall any broker-dealer receive fees, commissions and markups which, in the aggregate, would exceed eight percent (8%).

We are required to pay certain fees and expenses incurred by us incident to the registration of the shares. We have agreed to indemnify the selling stockholders against certain losses, claims, damages and liabilities, including liabilities under the Securities Act.

Because YA Global is, and any other selling stockholder may be deemed to be, an “underwriter” within the meaning of the Securities Act, they will be subject to the prospectus delivery requirements of the Securities Act including Rule 172 thereunder. In addition, any securities covered by this prospectus which qualify for sale pursuant to Rule 144 under the Securities Act may be sold under Rule 144 rather than under this prospectus. There is no underwriter or coordinating broker acting in connection with the proposed sale of the resale shares by the selling stockholders.

We agreed to keep this prospectus effective until the earlier of (i) the date on which the shares may be resold by the selling stockholders without registration and without regard to any volume limitations by reason of Rule 144 under the Securities Act or any other rule of similar effect or (ii) all of the shares have been sold pursuant to this prospectus or Rule 144 under the Securities Act or any other rule of similar effect. The resale shares will be sold only through registered or licensed brokers or dealers if required under applicable state securities laws. In addition, in certain states, the resale shares may not be sold unless they have been registered or qualified for sale in the applicable state or an exemption from the registration or qualification requirement is available and is complied with.

Under applicable rules and regulations under the Exchange Act, any person engaged in the distribution of the resale shares may not simultaneously engage in market making activities with respect to the common stock for the applicable restricted period, as defined in Regulation M, prior to the commencement of the distribution. In addition, the selling stockholders will be subject to applicable provisions of the Exchange Act and the rules and regulations thereunder, including Regulation M, which may limit the timing of purchases and sales of shares of the common stock by the selling stockholders or any other person. We will make copies of this prospectus available to the selling stockholders and have informed them of the need to deliver a copy of this prospectus to each purchaser at or prior to the time of the sale (including by compliance with Rule 172 under the Securities Act).

DESCRIPTION OF CAPITAL STOCK

General

The following is a summary of our capital stock and certain provisions of our articles of incorporation and bylaws, as they are currently in effect. This summary does not purport to be complete and is qualified in its entirety by the provisions of our articles incorporation and bylaws, copies of which have been filed as exhibits to the registration statement on Form S-1 of which this prospectus forms a part.

Our authorized capital stock consists of 250,000,000 shares of common stock, $0.00001 par value per share, and 50,000,000 shares of preferred stock, $0.00001 par value per share. As of August 25, 2009, there were 17,106,456 shares of common stock issued and outstanding and 545,454 shares of preferred stock issued and outstanding.

Common Stock

As of August 25, 2009, there were 17,106,456 shares of common stock issued and outstanding held of record by 588 shareholders.

The holders of common stock are entitled to one vote per share on all matters to be voted upon by the shareholders. The holders of common stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by the board of directors out of funds legally available, subject to preferences that may be applicable to preferred stock, if any, then outstanding. In the event of a liquidation, dissolution or winding up of our Company, the holders of common stock are entitled to share ratably in all assets remaining after payment of liabilities, subject to prior distribution rights of preferred stock, if any, then outstanding. The common stock has no preemptive or conversion rights or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock. All outstanding shares of common stock are fully paid and non-assessable.

“Blank Check” Preferred Stock

The Board of Directors has the authority, without further action by the shareholders, to issue up to 50,000,000 shares of preferred stock, $0.00001 par value per share, in one or more series and to fix the rights, preferences, privileges and restrictions thereof, including dividend rights, conversion rights, voting rights, terms of redemption, liquidation preferences, sinking fund terms and the number of shares constituting any series or the designation of such series, without any further vote or action by shareholders.

The Board of Directors has designated 1,000,000 shares as a Series A Preferred Stock, $.00001 par value per share and 545,454 shares of preferred stock have been issued. 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 , that is, 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, we 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.

Warrants & Options

As of August 25, 2009, there were outstanding warrants to purchase up to 3,037,249 shares of common stock at an exercise price of $7.50 per share. As of August 25, 2009, there were outstanding options to purchase up to 439,916 shares of common stock all at an exercise price of $7.50 per share.

Convertible Promissory Notes

As of August 25, 2009, there were outstanding convertible promissory notes in the aggregate principal amount of $700,000 which bear interest ranging from 8% to 18% per annum. Outstanding principal is convertible at any time at the option of the holder into shares of our common stock at conversion rates of $0.75 to $1.50 per share.

Anti-Takeover Effects of Our Charter and Bylaws and Texas Law

Some provisions of Texas law and our articles of incorporation and bylaws could make the following transactions more difficult:

·	acquisition of us by means of a tender offer, a proxy contest or otherwise; and

·	removal of our incumbent officers and directors.

These provisions, summarized below, are expected to discourage and prevent coercive takeover practices and inadequate takeover bids. These provisions are designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. They are also intended to provide our management with the flexibility to enhance the likelihood of continuity and stability if our board of directors determines that a takeover is not in the best interests of our shareholders. These provisions, however, could have the effect of discouraging attempts to acquire us, which could deprive our shareholders of opportunities to sell their shares of common stock at prices higher than prevailing market prices.

Election and Removal of Directors. Our bylaws contain provisions that establish specific procedures for appointing and removing members of the board of directors. Our bylaws provide that vacancies and newly created directorships on the board of directors may be filled only by a majority of the directors then serving on the board (except as otherwise required by law or by resolution of the board).

Special Shareholder Meetings. Under our bylaws, only our President, our board of directors or holders of not less than 1/10th of all the shares issued, outstanding and entitled to vote may call special meetings of shareholders.

Texas Anti-Takeover Law. Following this registration, we will be subject to Article 21 of the Texas Business Organizations Code, which is an anti-takeover law. In general, Article 21 prohibits a publicly held Texas corporation from engaging in a business combination with an interested shareholder for a period of three years following the date that the person became an interested shareholder, unless the business combination or the transaction in which the person became an interested shareholder is approved in a prescribed manner. Generally, a business combination includes a merger, asset or stock sale, or another transaction resulting in a financial benefit to the interested shareholder. Generally, an interested shareholder is a person who, together with affiliates and associates, owns 15% or more of the corporation’s voting stock or holders of at least two-thirds of the shares of common stock entitled to vote held by disinterested directors. The existence of this provision may have an anti-takeover effect with respect to transactions that are not approved in advance by our board of directors, including discouraging attempts that might result in a premium over the market price for the shares of common stock held by shareholders.

No Cumulative Voting. Under Texas law, cumulative voting for the election of directors is not permitted unless a corporation’s articles of incorporation authorize cumulative voting. Our articles of incorporation and bylaws do not provide for cumulative voting in the election of directors. Cumulative voting allows a minority shareholder to vote a portion or all of its shares for one or more candidates for seats on the board of directors. Without cumulative voting, a minority shareholder will not be able to gain as many seats on our board of directors based on the number of shares of our stock the shareholder holds as the shareholder would be able to gain if cumulative voting were permitted. The absence of cumulative voting makes it more difficult for a minority shareholder to gain a seat on our board of directors to influence our board’s decision regarding a takeover.

Undesignated Preferred Stock. The authorization of undesignated preferred stock makes it possible for our board of directors to issue preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of our company.

These and other provisions could have the effect of discouraging others from attempting hostile takeovers and, as a consequence, they may also inhibit temporary fluctuations in the market price of our common stock that often result from actual or rumored hostile takeover attempts. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish transactions that shareholders may otherwise deem to be in their best interests.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is First American Stock Transfer (FAST) located at 706 East Bell Road, Suite 202, Phoenix, AZ 85022. Their telephone number is (602) 485-1346.

WHERE YOU CAN FIND MORE INFORMATION

We filed with the SEC a registration statement on Form S-1 under the Securities Act for the shares of our common stock to be sold in this offering. This prospectus does not contain all of the information in the registration statement and the exhibits that were filed with the registration statement. For further information with respect to us and our common stock, we refer you to the registration statement and the exhibits that were filed with the registration statement. Statements contained in this prospectus about the contents of any contract or any other document that is filed as an exhibit to the registration statement are not necessarily complete, and we refer you to the full text of the contract or other document filed as an exhibit to the registration statement. A copy of the registration statement and the exhibits that were filed with the registration statement may be inspected without charge at the public reference facilities maintained by the SEC in Room 1590, 100 F Street, NE, Washington, D.C. 20549, and copies of all or any part of the registration statement may be obtained from the SEC upon payment of the prescribed fee. Information on the operation of the public reference facilities may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a website that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC. The address of the site is www.sec.gov. You may also request copies of these filings, at no cost, by telephone at (281) 466-1530 or by mail to: Conquest Petroleum Incorporated, 24900 Pitkin Rd., Ste. 308, Spring Texas 77386, Attn: Robert D. Johnson.

We maintain an Internet website at www.conquestpetroleum.com. The information contained on, connected to or that can be accessed via our website is not part of this prospectus.

The other information we file with the SEC and that is available on our website is not part of the registration statement of which this prospectus forms a part.

LEGAL MATTERS

The validity of the shares of common stock offered hereby will be passed upon for us by Haynes and Boone, LLP, Houston, Texas.

EXPERTS

The financial statements included in this prospectus as of December 31, 2007 and 2008, and for the years ended December 31, 2007 and 2008, have been audited by M&K CPAS, PLLC, independent registered public accounting firm, as stated in their report thereon, and is included in reliance upon the report of such firm given upon its authority as experts in accounting and auditing.

GLOSSARY OF TERMS

Terms used to describe quantities of oil and natural gas

Bbl — One stock tank barrel, or 42 US gallons liquid volume, of crude oil or other liquid hydrocarbons.

Bcf — One billion cubic feet of natural gas.

Bcfe — One billion cubic feet of natural gas equivalent.

BOE — One barrel of oil equivalent, converting gas to oil at the ratio of 6 Mcf of gas to 1 Bbl of oil.

MBbl — One thousand Bbls.

Mcf — One thousand cubic feet of natural gas.

Mcfe — One thousand cubic feet of natural gas equivalent.

MMBbl — One million Bbls of oil or other liquid hydrocarbons.

MMcf — One million cubic feet of natural gas.

MBOE — One thousand BOE.

MMBOE — One million BOE.

Terms used to describe our interests in wells and acreage

·	Gross oil and gas wells or acres — Our gross wells or gross acres represent the total number of wells or acres in which we own a working interest.

·	Net oil and gas wells or acres — Determined by multiplying “gross” oil and natural gas wells or acres by the working interest that we own in such wells or acres represented by the underlying properties.

Terms used to classify our reserve quantities

Proved reserves — The estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions.

The SEC definition of proved oil and gas reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows:

Proved oil and gas reserves — Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(a) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

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(b) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(c) Estimates of proved reserves do not include the following: (i) Oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (ii) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (iii) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (iv) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed reserves — Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves — Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Terms which describe the cost to acquire our reserves

Finding costs — Our finding costs compare the amount we spent to acquire, explore and develop our oil and gas properties, explore for oil and gas and to drill and complete wells during a period, with the increases in reserves during the period. This amount is calculated by dividing the net change in our evaluated oil and property costs during a period by the change in proved reserves plus production over the same period. Our finding costs as of December 31st of any year represent the average finding costs over the three-year period ending December 31st of that year.

Terms which describe the productive life of a property or group of properties

·	Reserve to production index — A measure of the productive life of an oil and gas property or a group of oil and gas properties, expressed in years. Reserve to production index is sometimes referred to as reserve life.

Terms used to describe the legal ownership of our oil and gas properties

Royalty interest — A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil and natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land.

Working interest — A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate

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either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property.

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 14.

Indemnification of Directors and Officers

Our articles of incorporation contain a provision that limits the liability of our directors as permitted by the Texas Business Corporation Act. The provision eliminates the personal liability of a director to us and our shareholders for monetary damages for an act or omission in the director’s capacity as a director. The provision does not change the liability of a director for breach of his duty of loyalty to us or to our shareholders, for an act or omission not in good faith that involves intentional misconduct or a knowing violation of law, for an act or omission for which the liability of a director is expressly provided for by an applicable statute, or in respect of any transaction from which a director received an improper personal benefit. Pursuant to our articles of incorporation, the liability of directors will be further limited or eliminated without action by shareholders if Texas law is amended to further limit or eliminate the personal liability of directors.

Our bylaws provide for the indemnification of our officers and directors, and the advancement to them of expenses in connection with proceedings and claims, to the fullest extent permitted by the Texas Business Corporation Act. We have also entered into indemnification agreements with each of our directors and some of our officers that contractually provide for indemnification and expense advancement and include related provisions meant to facilitate the indemnitee’s receipt of such benefits.

Item 15.

Recent Sales of Unregistered Securities

During the past two years, we have issued unregistered securities to a limited number of persons, as described below. None of these transactions involved any underwriters or public offerings and, except as otherwise indicated below, no remuneration or commission was paid or given directly or indirectly. We believe that each of these transactions was exempt from registration requirements pursuant to Section 3(a)(9) or Section 4(2) of the Securities Act, Regulation D promulgated thereunder or Rule 701 of the Securities Act. The recipients of these securities represented their intention to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof, and appropriate legends were affixed to the share certificates and instruments issued in these transactions. All recipients either received adequate information about us or had access, through employment or other relationships with us, to such information. The following information does not give effect to the 1-for-10 reverse stock split of our common stock that occurred on August 5, 2009.

Common stock

During the six months ended June 30, 2009, we issued 4,005,000 shares of common stock with a fair value of $0.75 per share or $3,003,750 to our employees for services.

During the six months ended June 30, 2009, we issued 4,599,692 shares of common stock with a fair value of $0.75 per share or $3,449,768 to third parties for services.

During the six months ended, 2,457,000 shares of common stock with a fair value of $0.75 per share or $1,856,250 were transferred by shareholders for our benefit.

During the six months ended $356,250 was relieved from stock payable by the transfer of shares by shareholders for our benefit.

During 2008, we 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 $37,408,772 772 and accrued interest of $6,068,427 for the year ended December 31, 2008.

During 2008 and 2007, total proceeds of $1,665,590 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

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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, we issued 510,000 and 3,550,753 shares of common stock with a fair value of $382,500 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, we issued 9,677,544 shares of common stock with a fair value of $0.75 per share or, $7,258,158 to employees 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 our 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, we issued 900,000 shares of common stock in connection with the sale of net revenue interests.

During 2008, the Company issued 25,000 shares of common stock for oil and gas properties.

During 2008, the Company issued 900,000 shares of common stock with a short term note attached. The note was paid off prior to year end.

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

During 2007, we 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 the six months ended June 30, 2009, we granted 75,000 warrants to purchase our common stock with an exercise price of $0.75 per share for services provided. These warrants expire in 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 $38,005

During 2008 and 2007, we granted 1,207,543 and 4,356,887, warrants respectively to purchase our common stock with an exercise price of $0.75 per share in connection with the sale of our 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, we entered into various note payable agreements with related and unrelated third party investors to fund its operations. At December 31, 2007, certain note payable agreements provided for warrants to purchase a total of 470,000 of our 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 our 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.

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In contemplation of divesting the South Belridge Field, effective October 1, 2007, we 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, we 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, we 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 our 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.

Stock options

During the six months ended June 30, 2009, we granted options to purchase 175,000 shares of our common stock at an exercise price of $0.75 per share to six employees for services provided. These options expire five years from the date of grant. All options granted to employees in 2009 vested immediately on the grant. The estimated fair value of these stock options was determined on the grant date using the Black-Scholes option pricing model and totaled $66,605.

During 2008 and 2007, we granted options to purchase 3,674,156 and 1,200,000 shares, respectively, of our 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 we recorded $1,256,633 and $471,900, respectively as general and administrative expense to account for vested options.

In addition, during 2007, we granted options to purchase 650,000 shares, of our 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.

Common Stock issued after the 1-for-10 stock split

In July 2009, we issued 260,000 shares to a third party for consulting services

In September 2009, we issued 13,231,534 shares of Common Stock to employees and directors for services under the stock incentive plan and 150,000 shares of Common Stock as incentives and for past services.

In September 2009, we issued 2,496,557 shares of Common Stock to a third party for anti-dilution rights.

Warrants granted after the 1-for-10 stock split

In August 2009, we granted 1,500,000 warrants to purchase our common stock with an exercise price of $7.50 per share in connection with the SEDA agreement.

Item 16.

Exhibits and Financial Statement Schedules

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(a) Exhibits

The following documents are filed as exhibits to this registration statement:

EXHIBIT INDEX
Number		Description
3.1	—	Articles of Incorporation of Conquest Petroleum, Inc., incorporated by reference from Exhibit 3.1 to Form 10 filed on February 12, 2008.
3.2	—	Bylaws of Conquest Petroleum, Inc., incorporated by reference from Exhibit 3.2 to Form 10 filed on February 12, 2008.
4.1	—	Form of Common Stock Certificate, incorporated by reference from Exhibit 4.1 to Form 10 filed on February 12, 2008.
4.2	—	Form of Subscription Agreement with 25% Warrant Coverage, incorporated by reference from Exhibit 4.2 to Form 10 filed on February 12, 2008.
4.3	—	Form of Subscription Agreement, incorporated by reference from Exhibit 4.3 to Form 10 filed on February 12, 2008.
4.4	—	Form of Warrant Certificate, incorporated by reference from Exhibit 4.4 to Form 10 filed on February 12, 2008.
4.5	—	2005 Incentive Compensation Plan, incorporated by reference from Exhibit 4.5 to Form 10 filed on February 12, 2008.
4.6	—	Form of Option Agreement for Directors, incorporated by reference from Exhibit 4.6 to Form 10 filed on February 12, 2008.
5.1*	—	Haynes and Boone Legal Opinion
10.1	—	Production Agreement and Conveyance of Production Payment Closing, by and between Axiom TEP, L.L.C and BlackRock Energy Capital, Inc. dated effective January 1, 2006, incorporated by reference from Exhibit 10.1 to Form 10 filed on February 12, 2008.
10.2	—	Conveyance of Production Payment, by and between Axiom TEP, L.L.C. and BlackRock Energy Capital, Ltd., dated effective January 1, 2006, incorporated by reference from Exhibit 10.2 to Form 10 filed on February 12, 2008.
10.3	—	Convertible Promissory Note, made by Maxim TEP, Inc. to Richard Williamson, for the Days Creek Field, dated effective November 1, 2006, incorporated by reference from Exhibit 10.3 to Form 10 filed on February 12, 2008.
10.4	—	Convertible Promissory Note, made by Maxim TEP, Inc. to Braspro LLC, for Days Creek Field, dated effective November 1, 2006, incorporated by reference from Exhibit 10.4 to Form 10 filed on February 12, 2008.
10.5	—	Convertible Promissory Note, made by Maxim TEP, Inc. to Oilman Rig & Equipment, Inc., for Days Creek Field, dated effective November 1, 2006, incorporated by reference from Exhibit 10.5 to Form 10 filed on February 12, 2008.
10.6	—	Kentucky Assignment, by and between Advanced Methane Recovery, LLC and Maxim Energy, Inc., dated March 30, 2004, incorporated by reference from Exhibit 10.6 to Form 10 filed on February 12, 2008.
10.7	—	Joint Operating Agreement, by and between Orchard Petroleum, Inc. and Maxim TEP, Inc., dated June 30, 2006, incorporated by reference from Exhibit 10.9 to Form 10 filed on February 12, 2008.
10.8	—	Joint Participation Agreement, by and between Orchard Petroleum, Inc. and Maxim TEP, Inc., dated June 30, 2006, incorporated by reference from Exhibit 10.10 to Form 10 filed on February 12, 2008.
10.9	—	License Agreement, by and between Power Hydraulics, LLC and Maxim TEP, Inc., dated July 2, 2007, incorporated by reference from Exhibit 10.12 to Form 10 filed on February 12, 2008.
10.10	—	Term Sheet (License Agreement), by and between Radial Drilling Services, Inc. and Maxim TEP, Inc., dated December 22, 2005, incorporated by reference from Exhibit 10.13 to Form 10 filed on February 12, 2008.
10.11	—	Sales and Limited License Agreement, by and between Triton American Well Service, LLC and Maxim TEP, Inc., dated July 7, 2005, incorporated by reference from Exhibit 10.14 to Form 10 filed on February 12, 2008.

II-4

10.12	—	Assignment of License Agreement, by and between Verdisys, Inc. and Maxim TEP, Inc., dated March 8, 2005, incorporated by reference from Exhibit 10.15 to Form 10 filed on February 12, 2008.
10.13	—	Master Joint Venture Agreement, by and between Energy Capital Group, LLC and Maxim TEP, Inc., dated March 23, 2005, incorporated by reference from Exhibit 10.16 to Form 10 filed on February 12, 2008.
10.14	—	Joint Venture Contract, by and between Carl Landers and Maxim Energy, Inc., dated February 9, 2004, incorporated by reference from Exhibit 10.17 to Form 10 filed on February 12, 2008.
10.15	—	Form of Net Revenue Interest in KY and CA Fields for: Bioform, LLC, Harvey Pensack, and Jon Peddie, incorporated by reference from Exhibit 10.24 to Form 10 filed on February 12, 2008.
10.16	—	Form of Overriding Royalty Interest in all Fields for: Frank Stack, Robert Newton, RF Petroleum, Greathouse Well Services, Harvey Pensack, Dipo Aluko, Jon Peddie, Louis Fusz Family Partnership, Stephan Baden, Wycap Corporation, and Michael Walsh, incorporated by reference from Exhibit 10.25 to Form 10 filed on February 12, 2008.
10.17	—	Form of Orchard Revenue Sharing Agreement –Issued to Riderwood Investors, incorporated by reference from Exhibit 10.26 to Form 10 filed on February 12, 2008.
10.18	—	Form of Oklahoma Revenue Sharing Agreement, incorporated by reference from Exhibit 10.27 to Form 10 filed on February 12, 2008.
10.19	—	Form of Promissory Note for all Outstanding Convertible Promissory Notes, except those with Maxim TEP, Plc (Greater European Funds), incorporated by reference from Exhibit 10.28 to Form 10 filed on February 12, 2008.
10.20	—	Assignment, Conveyance and Bill of Sale, incorporated by reference from Exhibit 10.29 to Form 10 filed on February 12, 2008, submitted as an example of the agreement entered into with the following parties: Baden Enterprise, Harvey Pensack, Judith Pensack Revocable Trust, Janice Peddie Living Trust, Jon Peddie Real Estate, and Jon Peddie.
10.21	—	Purchase and Sale of Working Interest in SB 4-7 Well located in Kern County, California, incorporated by reference from Exhibit 10.30 to Form 10 filed on February 12, 2008, submitted as an example of the agreement entered into with the following parties: Baden Enterprise, Harvey Pensack, Judith Pensack Revocable Trust, Janice Peddie Living Trust, Jon Peddie Real Estate, and Jon Peddie.
10.22	—	Transfer and Re-assignment Letter Agreement, incorporated by reference from Exhibit 10.31 to Form 10 filed on February 12, 2008, submitted as an example of the agreement entered into with the following parties: Baden Enterprise, Harvey Pensack, Judith Pensack Revocable Trust, Janice Peddie Living Trust, Jon Peddie Real Estate, and Jon Peddie.
10.23	—	Assumed Purchase Agreement, by and between Ergon Exploration, Inc. and Interconn Resources, Inc., dated June 1, 1998, incorporated by reference from Exhibit 10.34 to Amendment No. 1 on Form 10 filed on April 8, 2008.
10.24	—	Amendment and Extension of Purchase and Sale Agreement, for Days Creek Field, by and between Oilman Righ and Equipment, Inc., Braspro, LLC, Richard Williamson and Maxim TEP, Inc., incorporated by reference from Exhibit 10.35 to Amendment No. 1 on Form 10 filed on April 8, 2008.
10.25	—	Amendment No. 1 to the Maxim TEP, Inc. Incentive Compensation Plan, adopted on March 21, 2007, incorporated by reference from Exhibit 10.39 to Amendment No. 1on Form 10 filed on April 8, 2008.
10.26	—	Amendment No. 2 to the Maxim TEP, Inc. Incentive Compensation Plan, adopted on December 5, 2007, incorporated by reference from Exhibit 10.40 to Amendment No. 1 on Form 10 filed on April 8, 2008.
10.27	—	Purchase and Sale Agreement, by and between Maxim TEP Limited, Maxim TEP, Inc. and Upstream Capital Partners II Limited, dated April 3, 2008, incorporated by reference from Exhibit 10.41 to Amendment No.2 on Form 10 filed on June 11, 2008.
10.28	—	Transfer Agreement, by and between Maxim TEP, Inc. and Maxim TEP Limited, dated April 3, 2008, incorporated by reference from Exhibit 10.42 to Amendment No. 2 on Form 10 filed on June 11, 2008.
10.29	—	Consulting Agreement, by and between Navitas Land & Mineral Development, LLC and Maxim TEP, Inc., dated October 10, 2007, incorporated by reference from Exhibit 10.44 to Amendment No. 2 on Form 10 filed on June 11, 2008.
10.30	—	Secured Promissory Note and Mutual Release Agreement, by and between Dominick Maggio and Maxim TEP, Inc., dated April 11, 2008, incorporated by reference from Exhibit 10.45 to Amendment No. 4 on Form 10 filed on August 7, 2008.

II-5

10.31	—	Secured Promissory Note, Mutual Release and Pledge and Security Agreement, by and between Robert Sepos and Maxim TEP, Inc., dated April 11, 2008, incorporated by reference from Exhibit 10.46 to Amendment No. 2 on Form 10 filed on June 11, 2008.
10.32	—	Agreement, by and between BlueRock Energy Capital, Ltd. and Axiom TEP, L.L.C., dated effective May 1, 2008, incorporated by reference from Exhibit 10.47 to Amendment No. 2 on Form 10 filed on June 11, 2008.
10.33	—	Registration Rights Agreement, by and between Maxim TEP, Inc. and Maxim TEP Limited, dated April 25, 2008, incorporated by reference from Exhibit 10.48 to Amendment No. 3 on Form 10 filed on July 23, 2008.
10.34	—	Standby Equity Distribution Agreement, by and between Conquest Petroleum Incorporated, dated August 21, 2009, incorporated by reference from Exhibit 1 to Current Report on Form 8-K filed on August 24, 2009.
10.35*	—	Corporate Development Advisory & Funding Agreement (Consulting Agreement), by and between Maxim Oil & Gas, Inc. and Potomac Capital, LLC, dated June 8, 2009.
10.36*	—	Letter Agreement, by and between Maxim Oil & Gas, Inc. and Captima Limited, dated April 13, 2009.
10.37*	—	First Amended and Restated Loan Agreement, by and between Maxim TEP, Inc. and Greater Fund Limited, dated June 30, 2009.
10.38*	—	Amendment No. 1 to Standby Equity Distribution Agreement, by and between Conquest Petroleum Incorporated, dated September 25, 2009.
10.39*	—	Third Amendment to Agreement, by and between BlueRock Energy Capital, Ltd. and Axiom TEP, L.L.C., dated effective as of May 1, 2009.
10.40*	—	Amendment No. 3 to the Maxim TEP, Inc. Incentive Compensation Plan, adopted on September 9, 2009
10.41*	—	Amendment No. 4 to the Maxim TEP, Inc. Incentive Compensation Plan, adopted on September 29, 2009
10.42*	—	Employment Agreement, by and between Robert D. Johnson and Maxim TEP, Inc., dated May 1, 2008
10.43*	—	Employment Agreement, by and between Robert C. Johnson and Maxim TEP, Inc., dated May 1, 2009.
10.44*	—	Technology Purchase Agreement, by and between WES Technologies, LLC and Maxim TEP, Inc., dated April 16, 2009.
23.1	—	Consent of Pannell Kerr Foster of Texas P.C., incorporated by reference from Exhibit 16.1 from Current Report on Form 8-K filed on November 26, 2008.
23.2	—	Consent of Aluko & Associates, Inc., incorporated by reference from Exhibit 23.2 to Amendment No. 2 on Form 10 filed on June 11, 2008.
23.3	—	Consent of Aluko & Associates, Inc. –for Delhi Field as of January 1, 2008, incorporated by reference from Exhibit 23.3 to Amendment No. 2 on Form 10 filed on June 11, 2008.
23.5	—	Consent of Haas Petroleum Engineering Services, Inc. –for Belton Field as of January 1, 2008, incorporated by reference from Exhibit 23.5 to Amendment No. 3 on Form 10 filed on July 23, 2008.
23.7	—	Consent of Netherland, Sewell & Associates, Inc. –for Marion Field as of January 1, 2008, incorporated by reference from Exhibit 23.7 to Amendment No. 3 on Form 10 filed on July 23, 2008.
23.8*	—	Consent of M&K CPAs, PLLC
99.1	—	Summary of Reserve Report of Aluko & Associates, Inc. –for the Delhi Field as of January 1, 2007
99.3	—	Summary of Reserve Report of Aluko & Associates, Inc. –for the Delhi Field as of January 1, 2008, incorporated by reference from Exhibit 99.3 to Amendment No. 2 on Form 10 filed on June 11, 2008.
99.5	—	Summary of Reserve Report of Haas Petroleum Engineering Services, Inc. –for Belton Field as of January 1, 2008, incorporated by reference from Exhibit 99.5 to Amendment No. 3 on Form 10 filed on July 23, 2008.
99.7	—	Summary of Reserve Report of Netherland, Sewell & Associates, Inc. –for Marion Field as of January 1, 2008, incorporated by reference from Exhibit 99.7 to Amendment No. 3 on Form 10 filed on July 23, 2008.

* Filed herewith.

Item 17.

Undertakings

The undersigned Registrant hereby undertakes:

II-6

(a) Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

(b) To provide to the underwriter(s) at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriter(s) to permit prompt delivery to each purchaser.

(c) For purpose of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in the form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

(d) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-7

SIGNATURES

Pursuant to the requirements of the Securities Act, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 9th day of October, 2009.

CONQUEST PETROLEUM INCORPORATED

By: /s/ Robert D. Johnson

Robert D. Johnson

Chairman of the Board, President and

Chief Executive Officer

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Robert D. Johnson, as his true and lawful attorney-in-fact and agent, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to execute any and all amendments (including post-effective amendments) to this Registration Statement, including, without limitation, additional registration statements filed pursuant to Rule 462(b) under the Securities Act, and to file the same, with all exhibits thereto and other documents in connection therewith, with the SEC, granting unto said attorney-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same, as fully and to all intents and purposes as he might or could do if personally present, hereby ratifying and confirming all that said attorneys-in-fact and agents, or either of them, or their substitute or their substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated:

Signature	Title	Date



/s/ Robert D. Johnson	Chairman of the Board, President	October 9, 2009
Robert D. Johnson	and Chief Executive Officer

/s/ Robert C. Johnson	Chief Financial Officer and	October 9, 2009
Robert C. Johnson	Director

/s/ Harvey Pensack	Director	October 9, 2009
Harvey Pensack

/s/ Ann M. Thomas	Director	October 9, 2009
Ann M. Thomas

EXHIBIT INDEX
Number		Description
3.1	—	Articles of Incorporation of Conquest Petroleum, Inc., incorporated by reference from Exhibit 3.1 to Form 10 filed on February 12, 2008.
3.2	—	Bylaws of Conquest Petroleum, Inc., incorporated by reference from Exhibit 3.2 to Form 10 filed on February 12, 2008.
4.1	—	Form of Common Stock Certificate, incorporated by reference from Exhibit 4.1 to Form 10 filed on February 12, 2008.
4.2	—	Form of Subscription Agreement with 25% Warrant Coverage, incorporated by reference from Exhibit 4.2 to Form 10 filed on February 12, 2008.
4.3	—	Form of Subscription Agreement, incorporated by reference from Exhibit 4.3 to Form 10 filed on February 12, 2008.
4.4	—	Form of Warrant Certificate, incorporated by reference from Exhibit 4.4 to Form 10 filed on February 12, 2008.
4.5	—	2005 Incentive Compensation Plan, incorporated by reference from Exhibit 4.5 to Form 10 filed on February 12, 2008.
4.6	—	Form of Option Agreement for Directors, incorporated by reference from Exhibit 4.6 to Form 10 filed on February 12, 2008.
5.1*	—	Haynes and Boone Legal Opinion
10.1	—	Production Agreement and Conveyance of Production Payment Closing, by and between Axiom TEP, L.L.C and BlackRock Energy Capital, Inc. dated effective January 1, 2006, incorporated by reference from Exhibit 10.1 to Form 10 filed on February 12, 2008.
10.2	—	Conveyance of Production Payment, by and between Axiom TEP, L.L.C. and BlackRock Energy Capital, Ltd., dated effective January 1, 2006, incorporated by reference from Exhibit 10.2 to Form 10 filed on February 12, 2008.
10.3	—	Convertible Promissory Note, made by Maxim TEP, Inc. to Richard Williamson, for the Days Creek Field, dated effective November 1, 2006, incorporated by reference from Exhibit 10.3 to Form 10 filed on February 12, 2008.
10.4	—	Convertible Promissory Note, made by Maxim TEP, Inc. to Braspro LLC, for Days Creek Field, dated effective November 1, 2006, incorporated by reference from Exhibit 10.4 to Form 10 filed on February 12, 2008.
10.5	—	Convertible Promissory Note, made by Maxim TEP, Inc. to Oilman Rig & Equipment, Inc., for Days Creek Field, dated effective November 1, 2006, incorporated by reference from Exhibit 10.5 to Form 10 filed on February 12, 2008.
10.6	—	Kentucky Assignment, by and between Advanced Methane Recovery, LLC and Maxim Energy, Inc., dated March 30, 2004, incorporated by reference from Exhibit 10.6 to Form 10 filed on February 12, 2008.
10.7	—	Joint Operating Agreement, by and between Orchard Petroleum, Inc. and Maxim TEP, Inc., dated June 30, 2006, incorporated by reference from Exhibit 10.9 to Form 10 filed on February 12, 2008.
10.8	—	Joint Participation Agreement, by and between Orchard Petroleum, Inc. and Maxim TEP, Inc., dated June 30, 2006, incorporated by reference from Exhibit 10.10 to Form 10 filed on February 12, 2008.
10.9	—	License Agreement, by and between Power Hydraulics, LLC and Maxim TEP, Inc., dated July 2, 2007, incorporated by reference from Exhibit 10.12 to Form 10 filed on February 12, 2008.
10.10	—	Term Sheet (License Agreement), by and between Radial Drilling Services, Inc. and Maxim TEP, Inc., dated December 22, 2005, incorporated by reference from Exhibit 10.13 to Form 10 filed on February 12, 2008.
10.11	—	Sales and Limited License Agreement, by and between Triton American Well Service, LLC and Maxim TEP, Inc., dated July 7, 2005, incorporated by reference from Exhibit 10.14 to Form 10 filed on February 12, 2008.
10.12	—	Assignment of License Agreement, by and between Verdisys, Inc. and Maxim TEP, Inc., dated March 8, 2005, incorporated by reference from Exhibit 10.15 to Form 10 filed on February 12, 2008.
10.13	—	Master Joint Venture Agreement, by and between Energy Capital Group, LLC and Maxim TEP, Inc., dated March 23, 2005, incorporated by reference from Exhibit 10.16 to Form 10 filed on February 12, 2008.

II-9

10.14	—	Joint Venture Contract, by and between Carl Landers and Maxim Energy, Inc., dated February 9, 2004, incorporated by reference from Exhibit 10.17 to Form 10 filed on February 12, 2008.
10.15	—	Form of Net Revenue Interest in KY and CA Fields for: Bioform, LLC, Harvey Pensack, and Jon Peddie, incorporated by reference from Exhibit 10.24 to Form 10 filed on February 12, 2008.
10.16	—	Form of Overriding Royalty Interest in all Fields for: Frank Stack, Robert Newton, RF Petroleum, Greathouse Well Services, Harvey Pensack, Dipo Aluko, Jon Peddie, Louis Fusz Family Partnership, Stephan Baden, Wycap Corporation, and Michael Walsh, incorporated by reference from Exhibit 10.25 to Form 10 filed on February 12, 2008.
10.17	—	Form of Orchard Revenue Sharing Agreement –Issued to Riderwood Investors, incorporated by reference from Exhibit 10.26 to Form 10 filed on February 12, 2008.
10.18	—	Form of Oklahoma Revenue Sharing Agreement, incorporated by reference from Exhibit 10.27 to Form 10 filed on February 12, 2008.
10.19	—	Form of Promissory Note for all Outstanding Convertible Promissory Notes, except those with Maxim TEP, Plc (Greater European Funds), incorporated by reference from Exhibit 10.28 to Form 10 filed on February 12, 2008.
10.20	—	Assignment, Conveyance and Bill of Sale, incorporated by reference from Exhibit 10.29 to Form 10 filed on February 12, 2008, submitted as an example of the agreement entered into with the following parties: Baden Enterprise, Harvey Pensack, Judith Pensack Revocable Trust, Janice Peddie Living Trust, Jon Peddie Real Estate, and Jon Peddie.
10.21	—	Purchase and Sale of Working Interest in SB 4-7 Well located in Kern County, California, incorporated by reference from Exhibit 10.30 to Form 10 filed on February 12, 2008, submitted as an example of the agreement entered into with the following parties: Baden Enterprise, Harvey Pensack, Judith Pensack Revocable Trust, Janice Peddie Living Trust, Jon Peddie Real Estate, and Jon Peddie.
10.22	—	Transfer and Re-assignment Letter Agreement, incorporated by reference from Exhibit 10.31 to Form 10 filed on February 12, 2008, submitted as an example of the agreement entered into with the following parties: Baden Enterprise, Harvey Pensack, Judith Pensack Revocable Trust, Janice Peddie Living Trust, Jon Peddie Real Estate, and Jon Peddie.
10.23	—	Assumed Purchase Agreement, by and between Ergon Exploration, Inc. and Interconn Resources, Inc., dated June 1, 1998, incorporated by reference from Exhibit 10.34 to Amendment No. 1 on Form 10 filed on April 8, 2008.
10.24	—	Amendment and Extension of Purchase and Sale Agreement, for Days Creek Field, by and between Oilman Righ and Equipment, Inc., Braspro, LLC, Richard Williamson and Maxim TEP, Inc., incorporated by reference from Exhibit 10.35 to Amendment No. 1 on Form 10 filed on April 8, 2008.
10.25	—	Amendment No. 1 to the Maxim TEP, Inc. Incentive Compensation Plan, adopted on March 21, 2007, incorporated by reference from Exhibit 10.39 to Amendment No. 1on Form 10 filed on April 8, 2008.
10.26	—	Amendment No. 2 to the Maxim TEP, Inc. Incentive Compensation Plan, adopted on December 5, 2007, incorporated by reference from Exhibit 10.40 to Amendment No. 1 on Form 10 filed on April 8, 2008.
10.27	—	Purchase and Sale Agreement, by and between Maxim TEP Limited, Maxim TEP, Inc. and Upstream Capital Partners II Limited, dated April 3, 2008, incorporated by reference from Exhibit 10.41 to Amendment No.2 on Form 10 filed on June 11, 2008.
10.28	—	Transfer Agreement, by and between Maxim TEP, Inc. and Maxim TEP Limited, dated April 3, 2008, incorporated by reference from Exhibit 10.42 to Amendment No. 2 on Form 10 filed on June 11, 2008.
10.29	—	Consulting Agreement, by and between Navitas Land & Mineral Development, LLC and Maxim TEP, Inc., dated October 10, 2007, incorporated by reference from Exhibit 10.44 to Amendment No. 2 on Form 10 filed on June 11, 2008.
10.30	—	Secured Promissory Note and Mutual Release Agreement, by and between Dominick Maggio and Maxim TEP, Inc., dated April 11, 2008, incorporated by reference from Exhibit 10.45 to Amendment No. 4 on Form 10 filed on August 7, 2008.
10.31	—	Secured Promissory Note, Mutual Release and Pledge and Security Agreement, by and between Robert Sepos and Maxim TEP, Inc., dated April 11, 2008, incorporated by reference from Exhibit 10.46 to Amendment No. 2 on Form 10 filed on June 11, 2008.
10.32	—	Agreement, by and between BlueRock Energy Capital, Ltd. and Axiom TEP, L.L.C., dated effective May 1, 2008, incorporated by reference from Exhibit 10.47 to Amendment No. 2 on Form 10 filed on June 11, 2008.

II-10

10.33	—	Registration Rights Agreement, by and between Maxim TEP, Inc. and Maxim TEP Limited, dated April 25, 2008, incorporated by reference from Exhibit 10.48 to Amendment No. 3 on Form 10 filed on July 23, 2008.
10.34	—	Standby Equity Distribution Agreement, by and between Conquest Petroleum Incorporated, dated August 21, 2009, incorporated by reference from Exhibit 1 to Current Report on Form 8-K filed on August 24, 2009.
10.35*	—	Corporate Development Advisory & Funding Agreement (Consulting Agreement), by and between Maxim Oil & Gas, Inc. and Potomac Capital, LLC, dated June 8, 2009.
10.36*	—	Letter Agreement, by and between Maxim Oil & Gas, Inc. and Captima Limited, dated April 13, 2009.
10.37*	—	First Amended and Restated Loan Agreement, by and between Maxim TEP, Inc. and Greater Fund Limited, dated June 30, 2009.
10.38*	—	Amendment No. 1 to Standby Equity Distribution Agreement, by and between Conquest Petroleum Incorporated, dated September 25, 2009.
10.39*	—	Third Amendment to Agreement, by and between BlueRock Energy Capital, Ltd. and Axiom TEP, L.L.C., dated effective as of May 1, 2009.
10.40*	—	Amendment No. 3 to the Maxim TEP, Inc. Incentive Compensation Plan, adopted on September 9, 2009
10.41*	—	Amendment No. 4 to the Maxim TEP, Inc. Incentive Compensation Plan, adopted on September 29, 2009
10.42*	—	Employment Agreement, by and between Robert D. Johnson and Maxim TEP, Inc., dated May 1, 2008
10.43*	—	Employment Agreement, by and between Robert C. Johnson and Maxim TEP, Inc., dated May 1, 2009.
10.44*	—	Technology Purchase Agreement, by and between WES Technologies, LLC and Maxim TEP, Inc., dated April 16, 2009.
23.1	—	Consent of Pannell Kerr Foster of Texas P.C., incorporated by reference from Exhibit 16.1 from Current Report on Form 8-K filed on November 26, 2008.
23.2	—	Consent of Aluko & Associates, Inc., incorporated by reference from Exhibit 23.2 to Amendment No. 2 on Form 10 filed on June 11, 2008.
23.3	—	Consent of Aluko & Associates, Inc. –for Delhi Field as of January 1, 2008, incorporated by reference from Exhibit 23.3 to Amendment No. 2 on Form 10 filed on June 11, 2008.
23.5	—	Consent of Haas Petroleum Engineering Services, Inc. –for Belton Field as of January 1, 2008, incorporated by reference from Exhibit 23.5 to Amendment No. 3 on Form 10 filed on July 23, 2008.
23.7	—	Consent of Netherland, Sewell & Associates, Inc. –for Marion Field as of January 1, 2008, incorporated by reference from Exhibit 23.7 to Amendment No. 3 on Form 10 filed on July 23, 2008.
23.8*	—	Consent of M&K CPAs, PLLC
99.1	—	Summary of Reserve Report of Aluko & Associates, Inc. –for the Delhi Field as of January 1, 2007
99.3	—	Summary of Reserve Report of Aluko & Associates, Inc. –for the Delhi Field as of January 1, 2008, incorporated by reference from Exhibit 99.3 to Amendment No. 2 on Form 10 filed on June 11, 2008.
99.5	—	Summary of Reserve Report of Haas Petroleum Engineering Services, Inc. –for Belton Field as of January 1, 2008, incorporated by reference from Exhibit 99.5 to Amendment No. 3 on Form 10 filed on July 23, 2008.
99.7	—	Summary of Reserve Report of Netherland, Sewell & Associates, Inc. –for Marion Field as of January 1, 2008, incorporated by reference from Exhibit 99.7 to Amendment No. 3 on Form 10 filed on July 23, 2008.

* Filed herewith.

II-11

INDEX TO FINANCIAL STATEMENTS

	PAGE
Historical Consolidated Financial Statements for the six months ending June 30, 2009
Consolidated Balance Sheets at December 31, 2008 and June 30, 2009	F-1
Consolidated Statements of Operations for the three months ended June 30, 2008 and 2009, and the six months ended June 30, 2008 and 2009	F-4
Consolidated Statements of Cash Flows for the three months ended June 30, 2008 and 2009, and the six months ended June 30, 2008 and 2009	F-7
Notes to Consolidated Financial Statements for the quarterly period ended June 30, 2009	F-9

Historical Consolidated Financial Statements for the years ending December 31, 2007 and 2008
Report of Independent Registered Public Accounting Firm	F-25
Consolidated Balance Sheets at December 31, 2007 and 2008	F-26
Consolidated Statements of Operations for years ended December 31, 2007 and 2008	F-28
Consolidated Statements of Stockholders’ Equity for years ended December 31, 2007 and 2008	F-30
Consolidated Statements of Cash Flows for years ended December 31, 2007 and 2008	F-32
Notes to Consolidated Financial Statements for years ended December 31, 2007 and 2008	F-35

CONQUEST PETROLEUM INCORPORATED

Consolidated Balance Sheets

(unaudited)

	June 30,				December 31,
	2009				2008

Assets
Current assets:
Cash and cash equivalents		$	-			$	67,502
Accounts receivable			58,995				163,745
Other receivable			50,307				64,633
Prepaid expenses and other current assets			105,275				21,044

Total current assets			214,577				316,924

Oil and natural gas properties (successful efforts method of accounting):
Proved			8,214,663				8,170,937
Unproved			1,070,371				1,125,919
			9,285,034				9,296,856

Less accumulated depletion, depreciation and amortization			(2,010,280	)			(1,829,365	)

Oil and natural gas properties, net			7,274,754				7,467,491

Property and equipment:
Land			112,961				112,961
Buildings			215,445				215,445
Leasehold improvements			244,025				244,025
Office equipment and computers			82,340				82,337
Furniture and fixtures			22,939				211,581
Field service vehicles and equipment			738,898				729,743
Drilling equipment			140,101				174,082
Total property and equipment			1,556,709				1,770,174
Less accumulated depreciation			(436,453	)			(474,744	)
Property and equipment, net			1,120,256				1,295,430

Other assets			617,013				489,176
Restricted cash			29				250,170
Total assets		$	9,226,629			$	9,819,191

See accompanying notes to consolidated financial statements

F-2

CONQUEST PETROLEUM INCORPORATED

Consolidated Balance Sheets (Continued)

(unaudited)

	June 30,			December 31,
		2009			2008

Liabilities and Stockholders’ Deficit

Current liabilities:
Accounts payable	$	3,063,360		$	3,276,127
Interest payable		753,293			605,934
Accrued payroll and related taxes and benefits		1,751,626			1,691,710
Accrued liabilities		1,039,995			1,039,995
Production payment payable, current		6,912,370			3,607,570
Current maturity of notes payable, net of discount		850,675			689,518
Current maturities of convertible notes payable, related parties, net of discount		853,041			803,350

Total current liabilities		15,224,360			11,714,204

Production payment payable		-			2,834,520
Deferred revenue		60,000			65,000
Asset retirement obligation		1,907,801			1,840,641

Total liabilities		17,192,161			16,454,365

Stockholders’ deficit:
Preferred stock, $0.00001 par value; 50,000,000 shares
authorized; 5,454,545 and 5,454,545 shares issued and outstanding at June 30, 2009 and December 31, 2008, respectively		55			55
Common stock, $0.00001 par value; 250,000,000 shares
authorized;136,414,561 and 127,859,869 shares issued and 135,984,958 and 127,430,266 shares outstanding at June 30, 2009 and December 31, 2008, respectively		1,364			1,278
Stock payable		1,080,630			1,436,880
Additional paid-in capital		95,936,722			87,522,430
Accumulated deficit		(104,662,100	)		(95,273,614	)
Treasury stock, at cost (429,603 and 429,603 shares at
June 30, 2009 and December 31, 2008, respectively)		(322,203	)		(322,203	)

Total stockholders’ deficit		(7,965,532	)		(6,635,174	)

Total liabilities and stockholders’ deficit	$	9,226,629		$	9,819,191

See accompanying notes to consolidated financial statements

F-3

CONQUEST PETROLEUM INCORPORATED

Consolidated Statements of Operations

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30
	2009			2008			2009			2008

Revenues:
Oil and natural gas revenues	$	187,663		$	546,255		$	374,889		$	947,060
License fees, royalties and related services		9,000			7,192			9,000			34,692

Total revenues		196,663			553,447			383,889			981,752

Cost and expenses:
Production and lease operating expenses		116,939			190,554			394,639			438,414
Drilling operating expenses		-			-			-			3,741
Depletion, depreciation and amortization		118,973			456,869			258,825			917,861
Revenue sharing royalties		-			17,782			-			40,227
Accretion of asset retirement obligation		30,697			22,987			67,160			47,028
General and administrative expenses		6,328,578			4,674,891			8,634,257			9,041,349

Total cost and expenses		6,595,187			5,363,083			9,354,881			10,488,620

Loss from operations		(6,398,524	)		(4,809,636	)		(8,970,992	)		(9,506,868	)

Other income (expense):
Interest expense, net		(406,951	)		(196,049	)		(686,840	)		(1,780,557	)
Gain on transfer of assets					78,282						78,282
Gain/Loss on sale of assets		266,346						266,346

F-4

Other miscellaneous income (expense), net		(33,460	)		-			3,000			163,528

Total other income (expense), net		(174,065	)		(117,767	)		(417,494	)		(1,538,747	)

Net loss before discontinued operations		(6,572,589	)		(4,927,403	)		(9,388,486	)		(11,045,615	)

Gain (loss) from discontinued operations		-			23,487,207			-			22,042,660

Net (loss) income	$	(6,572,589	)	$	18,559,804		$	(9,388,486	)	$	10,997,045

Loss per common share for continuing operations
Basic and diluted	$	(0.05	)	$	(0.05	)	$	(0.07	)	$	(0.11	)

Net income per common share for discontinued operations
Basic and diluted	$	-		$	0.23		$	-		$	0.22

Weighted average common shares outstanding:
Basic and diluted		134,565,075			101,950,115			132,287,901			101,950,115

See accompanying notes to consolidated financial statements

F-5

CONQUEST PETROLEUM INCORPORATED

Consolidated Statements of Stockholders’ Deficit (unaudited)

For the Six Months Ended June 30, 2009

									Additional											Total
	Preferred Stock				Common Stock				Paid-In					Accumulated			Treasury			Stockholders’
	Shares		Amount		Shares		Amount		Capital		Stock Payable			Deficit			Stock			Equity (Deficit)
Balance at December 31, 2008		5,454,545	$	55		127,859,869	$	1,278	$	87,522,430	$	1,436,880		$	(95,273,614	)	$	(322,203	)		(6,635,174	)

Common stock issued for services, nonemployee						4,599,692		46		3,449,722					-			-			3,449,768

Common stock issued to employees for services		-		-		4,005,000		40		3,003,710		-			-			-			3,003,750

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

Expenses and payables paid by shareholder										1,856,250		(356,250	)								1,500,000
Common stock warrants granted for services		-		-		-		-		38,005		-			-			-			38,005

Net loss		-		-		-		-		-		-			(9,388,486	)		-			(9,388,486	)

Balance at June 30, 2009		5,454,545	$	55		136,464,561	$	1,364	$	95,936,722	$	1,080,630		$	(104,662,100	)	$	(322,203	)	$	(7,965,532	)

See accompanying notes to consolidated financial statements

F-6

CONQUEST PETROLEUM INCORPORATED

Consolidated Statements of Cash Flows (unaudited)

	Six Months Ended June 30,
	2009			2008
Cash flows from operating activities:
Net income (loss)	$	(9,388,486	)	$	10,997,045
Net income from discontinued operations		-			22,042,660
Net loss from continuing operations		(9,388,486	)		(11,045,615	)
Adjustments to reconcile net loss from continuing operations to net cash
provided by (used) in operating activities
Depletion, depreciation and amortization		258,825			917,861
Accretion of asset retirement obligation		67,160			47,028
Gain on disposal of assets		(290,000	)		(78,282	)
Loss on sale of fixed assets		23,654			-
Expenses paid for by shareholders		1,500,000			-
Amortization of debt discount		80,848			487,530
Amortization of deferred financing costs		-			69,970
Bad debt expense		10,631			-
Common stock issued for services		6,453,518			7,759,370
Warrants issued for services		38,005			70,535
Options issued for services		66,605			307,885
Changes in operating assets and liabilities, net of effects of
acquisitions and divestitures:
Notes receivable		-			(306,000	)
Accounts receivable		122,771			(265,256	)
Other receivable		(14,326	)		(22,760	)
Prepaid expenses and other current assets		(84,231	)		12,709
Other assets		247,304			33,198
Accounts payable		(210,407	)		307,366
Accrued expenses		301,716			659,729
Amortization of deferred revenue		(5,000	)		(55,000	)
Net cash provided by (used) in operating activities		(821,413	)		(1,099,732	)

Cash flows from investing activities:
Proceeds from sale of intangible assets		125,000			-
Cash paid for purchase of properties		(11,703	)		(260,410	)
Proceeds from sale of fixed assets		134,776			-
Change in oil and gas properties accrual		-			(627,949	)
Proceeds from sale of net revenue interests and sharing agreements		-			675,000
Net cash provided by (used in) investing activities		248,073			(213,359	)

Cash flows from financing activities:
Payment on production payment payable		(66,895	)		-
Proceeds from issuance of notes payable		100,000			100,000
Proceeds from issuance of notes payable - related parties		30,000			300,000
Procceds from borrowings on production payment payable		442,733			(2,331	)
Proceeds from issuance of common stock		-			1,328,099
Net cash provided by financing activities		505,838			1,725,768

Net cash used in discontinued operations		-			(420,428	)
Decrease in cash and cash equivalents		(67,502	)		(7,751	)
Cash and cash equivalents - beginning of year		67,502			166,412
Cash and cash equivalents - end of year	$	-		$	158,661

F-7

Supplementary cash flow information:
Cash paid for interest	$	153,240	$	248,097


Non-cash investing and financing activities:
Notes payable and accrued interest exchanged for common stock, related party	$	-	$	(150,000	)
Other liabilities exchanged for common stock, related party	$	-	$	150,000
Common stock exchanged for net revenue interest	$	-	$	675,000
Common stock issued upon conversion of debt & interest, related party	$	-	$	5,399,841
Common stock issued upon conversion of debt & interest	$	-	$	16,291,667
Notes payable and accrued interest exchanged for preferred stock, related party	$	-	$	1,250,000
Notes payable and accrued interest exchanged for preferred stock	$	-	$	1,750,000
Asset retirement obligation incurred	$	-	$	1,529
Common stock warrants granted in connectionwith NP, related party	$	-	$	15,778
Common stock warrants granted in connection with sale of net revenue interest	$	-	$	60,459
Common stock warrants granted to extend notes payable terms, related party	$	-	$	4,096
Common stock warrants granted to extend notes payable terms	$	-	$	5,734
Common stock warrants granted to extend put agreement terms	$	-	$	10,076
Beneficial conversion feature in connection with convertible debt, related party	$	-	$	15,778
Shares issued by shareholder to relieve stock payable	$	356,250	$	-

See accompanying notes to consolidated financial statements

F-8

CONQUEST PETROLEUM INCORPORATED

Notes to the Consolidated Financial Statements

(unaudited)

June 30, 2009

Note 1 –

Financial Statement Presentation

Organization and nature of operations

CONQUEST PETROLEUM INCORPORATED, formerly Maxim TEP, Inc. was formed in 2004 as a Texas corporation to acquire, develop, produce and exploit oil and natural gas properties. The Company’s major oil and natural gas properties are located in Louisiana, Kentucky, Arkansas, and New Mexico. The Company’s executive offices are located in Spring (Houston), Texas. At the annual shareholder’s meeting in June, 2009, the shareholders approved the change of Maxim TEP, Inc. to Conquest Petroleum. to more closely identify the Company as an independent oil and gas company. On August 5, 2009, after approval from the regulatory agencies, the name change to Conquest Petroleum became effective.

Going concern

As presented in the unaudited consolidated financial statements, the Company has incurred a net loss of $9,388,486 during the six months ended June 30, 2009, and losses are expected to continue in the near term. Current liabilities exceeded current assets by $15,009,783 and the accumulated deficit is $104,662,100 at June 30, 2009. Amounts outstanding and payable to creditors are in arrears and the Company is in negotiations with certain creditors to obtain extensions and settlements of outstanding amounts. The Company is currently in default on certain of its debt obligations and the Company has no future borrowings or funding sources available under existing financing arrangements. Management anticipates that significant additional capital expenditures will be necessary to develop the Company’s oil and natural gas properties, which consist primarily of proved reserves that are non-producing, before significant positive operating cash flows will be achieved.

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

The accompanying unaudited consolidated financial statements are prepared as if the Company will continue as a going concern. The unaudited consolidated financial statements do not contain adjustments, including adjustments to recorded assets and

F-9

liabilities, which might be necessary if the Company were unable to continue as a going concern.

Note 2 –

Summary of Significant Accounting Policies

Principles of consolidation

The accompanying unaudited consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles. The unaudited 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. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading. The financial statements included herein should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2008.

Major customers

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

	Six months ended June 30,
	2009			2008

Interconn Resources, Inc. (1)		90	%		41	%
Lion Oil Trading & Transportation, Inc. (1)		10	%		21	%

Orchard Petroleum, Inc. (2)		-	%		35	%

(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.

F-10

Note 2 –

Summary of Significant Accounting Policies (Continued)

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 the six months ended June, 2009 and the year ended December 31, 2008:

	June 30,		December 31,
	2009		2008

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

Liabilities incurred		-		1,530
Revisions to previous estimates		-		594,209
Dispositions		-		(33,375	)
Accretion expense		67,160		129,010
Asset retirement obligation at end of period	$	1,907,801	$	1,840,641

F-11

Note 2 –

Summary of Significant Accounting Policies (Continued)

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 Emerging Issues Task Force (“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.

The Company recognized stock-based compensation expense from annual stock granted to employees for the six months ended June 30, 2009 of $3,003,750. The Company recognized stock-based compensation expense from stock granted to non-employees for the six months ended June 30, 2009 of $3,449,768. The Company recognized stock-based compensation expense from warrants granted to non-employees for the three months ended June 30, 2009 of $38,005. The Company recognized stock-based compensation expense from options granted to employees for the six months ended June 30, 2009 of $66,605.

Earnings per share

F-12

June 30, 2009 and 2008, 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 six months ended June 30, 2009 and 2008, the Company excluded 230,833 weighted average common shares outstanding for shares issued with put options from its earnings per common share calculation.

Fair Value of Financial Instruments

We adopted the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standard (SFAS) No. 157, Fair Value Measurement at inception. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosure of fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements and accordingly, does not require any new fair value measurements. SFAS No. 157 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, SFAS No. 157 established a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows.

Level 1. Observable inputs such as quoted prices in active markets;

Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

The following table presents assets that are measured and recognized at fair value as of June 30, 2009 and the six months then ended on a non-recurring basis:

								Total
								Gains
Description	Level 1		Level 2		Level 3			(Losses)
Convertible Notes (net)	$	-	$	-		$	853,041		$	-
Asset Retirement Obligation	$	-	$	-		$	1,907,801		$	-
Oil and Gas Properties (net)	$	-	$	-		$	7,274,75434		$	-
Totals	$	-	$	-		$	10,035,596		$	-

F-13

Note 3 –

Debt

Notes payable consist of the following at June 30, 2009 and December 31, 2008:

	June 30,			December 31,
	2009			2008

Notes payable	$	900,000		$	800,000
Notes payable, related party		180,000			-
Convertible notes payable, related party		700,000			850,000

		1,780,000			1,650,000

Less unamortized debt discount		(76,284	)		(157,132	)

		1,703,716			1,492,868
Less current maturities:
Notes payable, net of discount		(850,675	)		(689,518	)
Convertible notes payable, related party, net of discount		(853,041	)		(803,350	)

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

Notes payable

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

During 2008, the Company borrowed an additional $400,000 from four individuals at an interest rate of 15% with a one year maturity on each.

During 2008, the Company borrowed an additional $100,000 from an individual at an interest rate of 15%. This note is a demand note payable at any time.

During the first quarter of 2009, the Company borrowed an additional $100,000 due and payable on March 1, 2010 from an individual at an interest rate of 15%. Simple interest accrues from the note issue date and is due and payable monthly.

During the first quarter of 2009, The Company borrowed an additional $25,000 due and payable on January 20, 2010 from a related party at an interest rate of 8%. Simple interest accrues from the note issue date and is due and payable either at maturity or quarterly or semi-annually until maturity.

F-14

Note 3 –

Debt (Continued)

During the second quarter of 2009, the Company borrowed an additional $5,000 due and payable on April 16, 2010 from a related party at an interest rate of 8%. Simple interest accrues from the note issue date and is due and payable either at maturity or quarterly or semi-annually until maturity.

Convertible notes payable

During 2005, the Company executed a convertible note payable with a related party investor aggregating $700,000. This note payable matured March 29, 2007, bearing interest at a fixed rate of 9%. Simple interest will accrue from the note date and is due and payable quarterly until maturity. Should the 9% convertible note go into default, interest will accrue at a rate of 18%. The note is unsecured. This note payable is convertible into shares of the Company’s common stock at an exchange rate of $0.75 per share, or into 933,333 shares of common stock. At June 30, 2009 and December 31, 2008, the Company had $700,000 outstanding of convertible notes payable to this investor. The maturity date on this note was extended to mature on September 30, 2007 and then extended again to March 30, 2008, whereby the Company issued the note holder warrants to purchase 466,666 shares of the Company’s common stock at an exercise price of $0.75 per share for a period of five years and then issued warrants to purchase another 466,666 shares of the Company’s common stock at an exercise price of $0.75 per share for a period of three years, as fees for the extensions. The fair value of the warrants is being amortized to interest expense using the effective interest method over the extension periods. The extension also revised the notes payable to bear interest at 12% from October 1, 2007 through March 30, 2008 and 18% in the event of default. The Company is currently in default on this note payable and is in negotiations with the note holder.

Production Payment with BlueRock Energy Capital, LTD

Effective May 1, 2008, the Company finalized its negotiations with BlueRock Energy Capital, LTD (“BlueRock”) to restructure its monthly production payment facility on its Marion Field. The new agreement calls for a reduction of the interest rate from its current 18% to 8% and to give back to the Company up to $25,000 of its production payment per month so that the field would be cash flow positive. The Company’s obligations under these new terms would be to seek refinancing of the production payment payable or the outright purchase of the production payable by no later than the anniversary of the execution of the new agreement. Should the Company not meet this obligation, BlueRock has the option of taking back the field in full payment of the production payment payable or reverting back to the previous terms under the existing agreement. As of June 30, 2009 , the Company determined this production payment facility was due within the next twelve months and hence classified as current liability. This agreement has since been extended for 6 months until October 30, 2009.

Effective May 1, 2009, the Company notified BlueRock that the Company was in default under the Conveyance and the Production Agreement. A third amendment was finalized and the 8% interest rate was increased back to 18%.

F-15

Note 3 –

Debt (Continued)

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 effective interest method.

Interest expense, net

Interest expense consists of the following for the six months ended June 30:

	Three Months Ended June 30,					Six Months Ended June 30,
	2009			2008		2009		2008

Interest expense related to debt	$	(4,786	)	$	191,882	$	605,992	$	1,223,057

Amortization of deferred financing costs		-			4,167		-		69,970

Amortization of debt discount		(17,561	)		-		80,848		487,530
	$	(22,347	)	$	196,049	$	279,889	$	1,780,557

Note 4 –

Discontinued Operations

Maxim TEP, PLC, South Belridge and Orchard Petroleum

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

F-16

Orchard Petroleum. The financial results of the Company’s South Belridge operations are reported as discontinued operations for all periods presented.

Days Creek Field

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

Stephens Field

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

F-17

Note 4 –

Discontinued Operations (continued)

	Three Months Ended June				Six Months Ended June
	2009		2008		2009		2008

Operating revenues	$	-	$	286,344	$	-	$	942,201

Operating costs and expenses		-		180,685		-		586,795

Other income (expenses), net		-		545,771		-		(1,148,523	)

Income (loss) from discontinued		-		651,430		-		(793,117	)
operations, net of taxes

Gain on disposal of discontinued		-		22,835,777		-		22,835,777
operations, net of taxes

Net income	$	-	$	23,487,207	$	-	$	22,042,660

Basic and diluted income per share
from discontinued operations		-		0.23				0.22

Total		-		0.23				0.22

Weighted average number of
common shares outstanding

Basic and diluted		134,565,075		101,950,115		132,287,901		101,950,115

Note 5 –

Stockholders’ Equity

Preferred stock

F-18

common stock (i.e. one vote per share) and shall be permitted to vote on all matters on which holders of common stock are entitled to vote. So long as any shares of Series A Preferred Stock remain outstanding, the Company shall not without first obtaining the approval of the holders of seventy-five percent (75%) of the then-outstanding shares of Series A Preferred Stock: (i) alter or change the rights, preferences or privileges of the shares of Series A Preferred Stock so as to adversely affect such shares; (ii) increase or decrease the total number of authorized shares of Series A Preferred Stock; (iii) issue any Senior Securities; or (iv) take any action that alters or amends this Series.

During the second quarter of 2008, the Company issued 5,454,545 shares of Series A Preferred Stock in exchange for $3,000,000 of corporate notes payable. At June 30, 2009, there were 5,454,545 shares of Series A Preferred Stock issued and outstanding.

Common stock

The Company has 250,000,000 authorized shares of $0.00001 par value common stock. From time to time, common stock may be issued for goods and services, the fair value of which has been determined based on recent cash transactions where common stock has been sold to investors or the fair value of the underlying transactions, whichever is more determinable.

During the six months ended June 30, 2009, the Company issued 4,005,000 shares of common stock with a fair value of $0.75 per share or $3,003,750 to employees of the Company for services.

During the three months ended June 30, 2009, the Company issued 4,599,692 shares of common stock with a fair value of $0.75 per share or $3,449,768 to third parties for services.

During the six months ended June 30, 2009, 2,457,000 shares of common stock with a fair value of $0.75 per share or $1,856,250 were transferred by shareholders for the benefit of the Company. These transferred shares of common stock were recorded as $1,125,000 for consulting services, $356,250 as a relief of stock payable and $375,000 reduction of an outstanding accounts payable during the six months ended June 30, 2009.

F-19

Note 5 –

Stockholders’ Equity (continued)

Warrants

During the six months ended June, 2009, warrants to acquire 75,000 shares of the Company’s common stock with an exercise price of $0.75 per share were granted for services. These warrants expire five years from the date of grant. The fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $38,005.

The following is a summary of the warrant activity for the six months ended June 30, and the year ended December 31,

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

Outstanding, beginning of period		15,297,489		$	0.75		14,089,946	$	0.75

Granted		75,000			0.75		1,207,543		0.75
Exercised		–			–		–		0.75
Expired or cancelled		(200,000	)		–		–		0.75

Outstanding, end of period		15,172,489		$	0.75		15,297,489	$	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 quarter ended June 30 and the year ended December 31:

	2009	2008
Risk free rate	1.67%	1.79%-2.23%
Expected life	5 years	5-10 years
Volatility	86%	67%
Dividend yield	0%	0%

F-20

Note 5 –

Stockholders’ Equity (Continued)

Stock options

During the six months ended June 30, 2009, the Company granted options to purchase 175,000 shares of the Company’s common stock at an exercise price of $0.75 per share to employees for services provided. These options expire 5 years from the date of grant. All the options granted to employees in 2009 vested immediately on the grant date. The estimated fair value of these stock options was determined on the grant date using the Black-Scholes option pricing model and totaled $66,605.

The following is a summary of the option activity for the six months ended June 30, and the year ended December 31,

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

Non-vested, beginning of period		-		$	0.75		-		$	0.75

Granted		175,000			0.75		3,674,156			0.75
Vested		(175,000	)		-		(3,674,156	)		0.75

Non-vested, end of period		-		$	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 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 quarter ended June 30 and the year ended December 31,

	2009	2008
Risk free rate	1.14%	2.45%-2.90%
Expected life	2.5 years	5-10 years
Volatility	85%	67%
Dividend yield	0%	0%

F-21

Note 6 –

Commitments and Contingencies

Litigation

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., on June 26, 2009, the Judge for the 5 th District Court, Louisiana approved the Judgment Dismissing Maxim and other Defendants and the Judgment Approving Maxim and other Defendants’ Settlement Agreement of Delhi Field Claims. Maxim will be responsible for the remaining remediation costs to restore the surface leases to standards set by the Louisiana Department of Natural Resources. The Company will also be responsible for the payment of certain remediation, legal, and expert witness expenses incurred in the past and paid by a 3 rd party. The Company has accrued a liability for this remediation of $750,000 as of December 31, 2008. There was no change to the liability for the six months ended June 30, 2009.

·	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.

F-22

Note 6 –

Commitments and Contingencies (continued)

·	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 at June 30, 2009 and December 31, 2008.

·	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 has facilitated the issuance of 375,000 shares of the company’s common stock by a third party shareholder. The issuance of shares by the third party shareholder on the Company’s behalf relieved $356,250 from stock payable as of June 30, 2009.

·	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.

In the suit with Pannell Kerr Forster of Texas PC (AKA PKF Texas) is seeking payment for services rendered. We have retained an expert witness in this field to opine on what the Company was charged and the ethics associated with PKF’s performance. At this point the amount and probability of payment is not determinable.

Note 7 –

Reporting by Business Segments

The Company had three operating segments: oil and natural gas exploration and production, drilling services and lateral drilling services. These segments were 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 provided drilling services for the Company’s subsidiaries and their working interest partners and to third parties. The lateral drilling services unit provided lateral drilling services for third parties, sub-licensed the Company’s LHD Technology, and sold 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

F-23

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 are not reported as separate business segments.

Note 8 –

Subsequent Events

On August 5, 2009, the Company changed its name to Conquest Petroleum Incorporated.

On August 10, 2009, the Company had a one-for-ten reverse stock split.

Common Stock issued after the 1-for-10 stock split

In July 2009, we issued 260,000 shares to a third party for consulting services.

In September 2009, we issued 2,496,557 shares of Common Stock to a third party for anti-dilution rights.

Warrants granted after the 1-for-10 stock split

In August 2009, we granted 1,500,000 warrants to purchase our common stock with an exercise price of $7.50 per share in connection with the SEDA agreement.

The Company received $1,500,000 restricted funding from an external source (“the Lender”) to bring the Delhi field wells back into production and to satisfy certain obligations regarding the settlement of the Delhi lawsuit. The terms of the restricted funding were the issuance of a $1,500,000 note payable at an interest rate of 15% due and payable on June 30, 2010 (principal and interest), and the issuance of 2,000,000 shares of restricted common stock (the “Closing Shares”) valued at $0.75 per share as an inducement to loan the funds. If the principal and interest are not re-paid at the end of the one year period, the Lender will gain legal right and title to 30,000,000 penalty shares of restricted common stock valued at $0.75 per share (“Penalty Shares”). The Penalty Shares are being held by the Lender and will become the property of the Lender in the event of default. Also, the Company executed a term assignment of an overriding royalty interest in the Delhi Field equal to fifteen percent of eight-eights (15% of 8/8ths) of all revenue attributable to Hydrocarbons produced and saved from or attributable or allocable to the Delhi Field net of severance taxes for a period of 30 months ending on December 31, 2011. Further, if a total of $4,500,000 (to include the principal and interest repayment) is not paid at the end of the 30 month period, the Company will make a cash payment to cover the deficiency.

F-24

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Stockholders of Conquest Petroleum, Inc.

We have audited the accompanying consolidated balance sheets of Conquest Petroleum, Inc. (formerly Maxim TEP, Inc.), 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.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Conquest Petroleum, Inc. 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.

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.

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

F-25

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			103,770
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	)		(298,535	)
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

F-26

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		11,714,204			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		16,454,365			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 127,430,266 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 (429,603 and 0 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

F-27

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		12,066,399			8,492,383

Total cost and expenses		21,558,272			15,091,415

Loss from operations		(19,571,921	)		(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 operations
Basic and diluted	$	0.18		$	(0.16)

Net loss per common share from continuing operations:
Basic and diluted	$	(0.23	)	$	(0.21	)

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

See accompanying notes to consolidated financial statements

F-28

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
Common stock options issued to
non-employee directors for services	-	-	-	-	393,448		-	-	393,448
Common stock warrants granted
for Put Extension	-	-	-	-	17,186		-	-	17,186
Beneficiary conversion feature in connection with convertible note payable, related party	-	-	-	-	29,549	-	-	-	29,549
Common stock put options	-	-	-	-	433,330	-	-	-	433,330
Common stock Equity Obiligation						1,436,880			1,436,880
Treasury stock purchased for note receivable								(322,203)	(322,203)
Preferred stock issued associated with
debt conversion, related party	2,272,727	23	-	-	1,322,808	-	-	-	1,322,831
Preferred stock issued associated with
debt conversion, unrelated party	3,181,818	32	-	-	2,386,332	-	-	-	2,386,364
Net income	-	-	-	-	-	-	(6,029,503)	-	(6,029,503)
Balance at December 31, 2008	5,454,545	$ 55	127,859,869	$ 1,278	$ 87,522,430	$ 1,436,880	$ (95,273,614)	$ (322,203)	$ (6,635,174)

See accompanying notes to consolidated financial statements

F-29

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			(13,092,048	)
Net loss for continuing operations	$	(26,852,644	)	$	(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			81,127
Gain on extinguishment of debt		(400,000	)		-
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			3,227,205
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		3,463,966			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	)		(5,437,747	)

Cash flows from investing activities:

Acquisitions of oil and gas property		(582,799	)		(6,967,866	)
Capital expenditures for property and equipment and other assets		-			(295,714	)
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	)		-

Net cash used in investing activities		1,341,505			(3,829,558	)

Cash flows from financing activities:

Proceeds - issuance of notes payable		400,000			-
Principal payments on notes payable and production payable		-			(793,957	)
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 sale of treasury shares		-			244,000
Common stock offering costs		-			(118,010	)
Net cash provided by financing activities		2,198,265			3,543,049

See accompanying notes to consolidated financial statements

F-30

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	)		2,945,705

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	$	67,502		$	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			291,264
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		-			15,000
Sale of oil and gas properties for related party notes		6,128,398			-

F-31

CONQUEST PETROLEUM INCORPORATED, and Subsidiaries

Notes to the Consolidated Financial Statements

Note 1 –

Financial Statement Presentation

Organization and nature of operations

Maxim TEP, Inc. was formed in 2004 as a Texas corporation to acquire, develop, produce and exploit oil and natural gas properties. The Company’s major oil and natural gas properties are located in Louisiana, 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.

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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

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.

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Accounting estimates

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.

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 $29,549 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

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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 $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 (see Note 7).

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

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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.

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, and $87,642, respectively, and impairment of $88,868 for rig equipment.

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.

Asset retirement obligation

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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	$	1,149,267		$	1,159,808
Liabilities incurred		1,529			30,939
Revisions to previous estimates		594,209			(28,361	)
Dispositions		(33,374	)		(94,246	)
Accretion expense		129,010			81,127
Asset retirement obligation at end of period	$	1,840,641		$	1,149,267

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

F-37

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 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 liability within accrued liabilities, from its earnings per common share calculation.

Fair Value of Financial Instruments

Level 1. Observable inputs such as quoted prices in active markets;

Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

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Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.

The following table presents assets that are measured and recognized at fair value as of December 31, 2008 and the year then ended on a non-recurring basis:

								Total
								Gains
Description	Level 1		Level 2		Level 3			(Losses)
Convertible Notes (net)	$	-	$	-		$	803,350		$	-
Asset Retirement Obligation	$	-	$	-		$	1,840,641		$	-
Oil and Gas Properties (net)	$	-	$	-		$	9,296,856		$	-
Totals	$	-	$	-		$	11,940,847		$	-

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.

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 did not experience any significant changes due to the adoption of this pronouncement.

F-39

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. 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. 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 does not expect a material impact from SFAS No. 159 on its consolidated financial statements.

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 does not expect a material impact from SFAS No. 159 on its consolidated financial statements.

F-40

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 note 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 note payable matured on March 30, 2008, bearing interest at fixed rate of 12%. 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 $150,000 from an individual at an interest rate of 5%. 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

F-41

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 were repaid or renegotiated in the first quarter of 2008.

Convertible notes payable

Maxim TEP, PLC, South Belridge and Orchard Petroleum

Days Creek Field

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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 $120,000 and $5,848 of accrued interest into 165,595 shares of the Company’s common stock at a conversion rate of $0.75 per 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 $300,000 from management and directors. The borrowing was subsequently converted into common stock at a price of $0.75 per share, or 400,000 shares. Additionally, $16,667 of convertible notes also converted at a price of $0.75 per share for a total of 22,224 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.

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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	$	1,622,075	$	2,919,682

Amortization of deferred financing costs		94,859		1,312,605

Amortization of debt discount		505,495		85,163

Interest expense related to stock put options

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:

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. The financial results of the Company’s Days Creek Field are reported as discontinued operations for all periods presented.

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.

F-44

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

Operating costs and expenses		446,891			1,593,272

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		114,939,598			80,023,513
Diluted		114,939,598			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.

F-45

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 of $37,408,772 and accrued interest of $6,068,427 for the year ended December 31, 2008.

During 2008 and 2007, total proceeds of $1,655,590 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 510,000 and 3,550,753 shares of common stock with a fair value of $382,500 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 9,677,544 shares of common stock with a fair value of $0.75 per share or, $7,258,158, 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 2008, the Company issued 900,000 shares of common stock with a short-term note payable attached. The note was paid off prior to year end.

During 2008, the Company issued 25,000 shares of common stock to purchase oil and gas properties.

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.

F-46

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 1,231,209 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 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

F-47

$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.

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

	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 $1,256,633 and $471,900, respectively as general and administrative expense to account for vested options.

F-48

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	-		$	0.75	525,000		$	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	2.45%-2.90%	4.23%-4.92%
Expected life	5-10 years	5-10 years
Volatility	67%	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

F-49

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.

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

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 $85 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.

F-50

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:

Net Operating loss	$	28,943,967
Effective Tax Rate		35	%
Deferred Tax Asset	$	10,130,388
Less: Valuation allowance	$	(10,130,388	)
Net Deferred tax asset	$	—

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. Maxim 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

F-51

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.

F-52

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.

F-53

	December
	2008			2007

Total assets:
Oil and natural gas exploration and production	$	2,834,331		$	9,230,185
Drilling services		0			0
Lateral drilling services		4,876,972			4,876,972
Other		2,107,888			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	)		(3,073,931	)
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	)		(8,444,382	)
Interest expense, net		(2,222,429	)		(4,254,448	)
Other miscellaneous income (expense), net		(10,807,142	)		13,938

Net loss	$	(26,852,644	)	$	(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

F-54

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:

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		11,349,519

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

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.

F-55

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 engineer; 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			2,450,341
Purchase of oil and natural gas property in place		-			6,048
Discoveries and extensions		-			587,336
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			143,196
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.

F-56

Standardized measure

Note 11 –

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

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
Gas	2008		2007
Proved developed and undeveloped reserves:
Beginning of year		1,987,875		4,300,316
Purchase 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			256,364,850
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			104,864,260

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

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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 and 100,000 previously issued stock options to purchase the Company’s common stock at an exercise price of $0.75 per share.

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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.

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