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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended June 30, 2008

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE EXCHANGE ACT

For the transition period from              to              

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

2500 CityWest Blvd., Suite 1300, Houston, Texas 77042

(Address of principal executive offices and zip code)

(713) 935-0122

(Registrant’s telephone number, including area code)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes:  o  No: x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes:  o  No: x

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

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

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates on December 31, 2007, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $5.05 on the American Stock Exchange was $66,387,795

The number of shares outstanding of the registrant’s common stock, par value $0.001, as of September 24, was 26,917,234.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

2008 ANNUAL REPORT ON FORM 10-K

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This Form 10-K and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in our 2007 Annual Report on Form 10-KSB for the year ended June 30, 2007 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.

GLOSSARY OF SELECTED PETROLEUM TERMS

The following abbreviations and definitions are terms commonly used in the crude oil and natural gas industry and throughout this prospectus:

“BBL.” A standard measure of volume for crude oil and liquid petroleum products; one barrel equals 42 U.S. gallons.

“BCF.” Billion Cubic Feet of natural gas at standard temperature and pressure.

“BOE.” Barrels of oil equivalent. BOE is calculated by converting 6 MCF of natural gas to 1 BBL of oil.

“BTU” or “British Thermal Unit.” The standard unit of measure of energy equal to the amount of heat required to raise the temperature of one pound of water 1 degree Fahrenheit. One Bbl of crude is typically 5.8 MMBTU, and one standard MCF is typically 1 MMBTU.

“CO₂.” Carbon dioxide, a gas that can be found in naturally occurring reservoirs, typically associated with ancient volcanoes, and also is a major byproduct from manufacturing and power production, also utilized in enhanced oil recovery through injection into an oil reservoir.

“EOR.” Enhanced Oil Recovery projects involve injection of heat, miscible or immiscible gas, or chemicals into oil reservoirs, typically following full primary and secondary waterflood recovery efforts, in order to gain incremental recovery of oil from the reservoir.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geologic structural feature and/or stratigraphic feature.

 “Farmout.” Sale or transfer of all or part of the operating rights from the working interest owner (the assignor or farmout party), to an assignee (the farmin party) who assumes all or some of the burden of development, in return for an interest in the property. The assignor may retain an overriding royalty or any other type of interest. For Federal tax purposes, a farmout may be structured as a sale or lease, depending on the specific rights and carved out interests retained by the assignor.

“Gross Acres or Gross Wells.” The total acres or number of wells participated in, regardless of the amount of working interest owned.

“Horizontal Drilling” Involves drilling horizontally out from an existing vertical well bore, thereby potentially increasing the area and reach of the well bore that is in contact with the reservoir.

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“Hydraulic Fracturing” Involves pumping a fluid with or without particulates into a formation at high pressure, thereby creating fractures in the rock and leaving the particulates in the fractures to ensure that the fractures remain open, thereby potentially increasing the ability of the reservoir to produce oil or gas.

“LOE.” Means lease operating expense(s), a current period expense incurred to operate a well.

“MBOE.” One thousand barrels of oil equivalent.

“MCF.” One thousand cubic feet of natural gas at standard conditions, being approximately sea level pressure and 60 degrees Fahrenheit temperature. Standard pressure in the state of Louisiana is deemed to be 15.025 psi by regulation, but varies in other states.

“MMBTU.” One million British thermal units.

“MMCF.” One million cubic feet of natural gas at standard temperature and pressure.

“Net Acres or Net Wells.” The sum of the fractional working interests owned in gross acres or gross wells.

“NGL.” Natural gas liquids, being the combination of ethane, propane, butane and natural gasoline’s that can be removed from natural gas through processing, typically through refrigeration plants that utilize low temperatures, or through J-T plants that utilize compression, temperature reduction and expansion to a lower pressure.

“NYMEX.” New York Mercantile Exchange.

“Operator.”  An oil and gas joint venture participant that manages the joint venture, pays venture costs and bills the venture’s non-operators for their share of venture costs. The operator is also responsible to market all oil and gas production, except for those non-operators who take their production in-kind.

“Overriding Royalty.” A royalty interest that is created out of the operating or working interest. Unlike a royalty interest, an overriding royalty interest terminates with the operating interest from which it was created or carved out of. See “royalty interest”.

“Permeability.” The measure of ease with which petroleum can move through a reservoir.

“Porosity.” (of sand or sandstone). The relative volume of the pore space (or open area) compared to the total bulk volume of the reservoir.

“Proved Developed Reserves.” Proved 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 pilot project or after the operation of an installed program has confirmed through production responses that increased recovery will be achieved.

“Proved Developed Nonproducing Reserves (“PDNP”).” Proved Reserves that have been developed and no material amount of capital expenditures are required to bring on production, but production has not yet been initiated due to timing, markets, or lack of third party completed connection to a gas sales pipeline.

“Proved Developed Producing Reserves (“PDP”).” Proved Reserves that have been developed and production has been initiated.

“Proved Reserves.” 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.

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“Proved Undeveloped Reserves (“PUD”).” 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 are 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. Proved undeveloped reserves may not include estimates 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.

“PSI,” or pounds per square inch, a measure of pressure. Pressure is typically measured as “psig”, or the pressure in excess of standard atmospheric pressure.

“Present Value.” When used with respect to oil and gas reserves, present value means the estimated future net revenues computed by applying current prices of oil and gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs to be incurred in developing and producing the proved reserves) computed using a discount factor and assuming continuation of existing economic conditions.

“Productive Well.” A well that is producing oil or gas or that is capable of production.

“PV-10.” Means a present value, discounted at 10% per annum, and is not necessarily the same as market value.

“Royalty” or “Royalty Interest.” The mineral owner’s share of oil or gas production (typically between 1/8 and 1/4), free of costs, but subject to severance taxes unless the lessor is a government. In certain circumstances, the royalty owner bears a proportionate share of the costs of making the natural gas saleable, such as processing, compression and gathering. A royalty interest that is coterminous with an operating or working interest is an “overriding royalty” interest.

“Shut-in Well.” A well that is not on production, but has not yet been plugged and abandoned. Wells may be shut-in in anticipation of future utility as a producing well, plugging and abandonment or other use.

“Standardized Measure.” The standardized measure is an estimate of future net reserves from a property, and is calculated in the same exact fashion as a PV-10 value, except that the projected revenue stream is adjusted to account for the estimated amount of federal income tax that must be paid.

“Working Interest.” The interest in the oil and gas in place which is burdened with the cost of development and operation of the property.  Also called the operating interest.

“Workover.” A remedial operation on a completed well to restore, maintain or improve the well’s production.

ITEM 1.  BUSINESS

The terms “we,” “us,” “our,” “our Company” and “EPM” refer to Evolution Petroleum Corporation, a Nevada corporation formerly known as Natural Gas Systems, Inc. (Nevada, “NGS”), and, unless the context indicates otherwise, also includes our wholly-owned subsidiaries.  Natural Gas Systems, Inc. (Delaware, “Old NGS”), a private Delaware corporation formed in September 2003 was subsequently merged into NGS.

Overview

Our petroleum operations began in September of 2003. We acquire established crude oil and natural gas resources and exploit them through the application of conventional and specialized technology, with the objective of increasing production, ultimate recoveries, or both.

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Our team is broadly experienced in oil and gas operations, development, acquisitions and financing. We follow a strategy of outsourcing most of our property accounting, human resources, administrative and non-core functions.

Our principal executive offices are located at 2500 City West Blvd, Suite 1300, Houston, Texas 77042, and our telephone number is (713) 935-0122. We maintain a website at www.EvolutionPetroleum.com, but information contained on our website does not constitute part of this document.

Our stock is traded on the American Stock Exchange under the ticker symbol “EPM”.  Prior to July 17, 2006, our stock was quoted on the OTC Bulletin Board under the symbol “NGSY.OB”.  Prior to May 26, 2004, our stock was quoted on the OTC Bulletin Board under the symbol “RLYI.OB”.

At June 30, 2008, we had twelve full-time employees, not including contract personnel and outsourced service providers.

Corporate History of Reverse Merger

Reality Interactive, Inc. (“Reality”), a Nevada corporation that traded on the OTC Bulletin Board under the symbol RLYI.OB and the predecessor of NGS, now Evolution Petroleum Corporation, was incorporated on May 24, 1994, for the purpose of developing technology-based knowledge solutions for the industrial marketplace.  On April 30, 1999, Reality ceased business operations, sold substantially all of its assets and terminated all of its employees.  Subsequent to ceasing operations, Reality explored other potential business opportunities to acquire or merge with another entity, while continuing to file reports with the Securities and Exchange Commission (“SEC”).

On May 26, 2004, Old NGS was merged into a wholly owned subsidiary of Reality.  Reality was thereafter renamed Natural Gas Systems, Inc. (“NGS”) and adopted a June 30 fiscal year end.  As part of the merger, the officers and directors of Reality resigned, the officers and directors of Old NGS became the officers and directors of our Company, and the crude oil and natural gas business of Old NGS became that of our Company.  Concurrently with the listing of our shares on the AMEX during July, 2006, NGS was renamed Evolution Petroleum Corporation to avoid confusion with similar names traded on the AMEX and to better reflect our business model.

All regulatory filings and other historical information prior to May 26, 2004 that applied to Reality continue to apply to us after the merger.

Business Strategy

We are an independent oil and natural gas company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas. We acquire known oil and natural gas resources and exploit them through the application of conventional and specialized technology to increase production, ultimate recoveries, or both.

We are focused on an overall strategy of acquiring controlling working interests in oil and natural gas resources within established fields and redeveloping those fields through the application of capital and technology to convert a portion of the oil and natural gas resources into profitable producing reserves.

Within this overall strategy, we pursue three specific initiatives:

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Our strategy is intended to generate scalable development opportunities at normally pressured depths, exhibiting relatively low completion risk, generally more predictable production lives, less expenditures on infrastructure and lower operational risks. We believe that the benefits of this approach include:

·                  Reduced exposure to the risk of whether resources are present;

·                  Reduced capital expenditures per net BOE for infrastructure, such as roads, water handling facilities and pipelines;

·                  Large inventory of development opportunities, which provides a more predictable future stream of drilling activity and production, as well as potentially reducing risks from short-term oil and natural gas price volatility;

·                  Reduced operational risks and costs associated with lower pressures and lower temperatures; and

·                  Control of operations, development timing and technology selection.

Markets and Customers

Historically our crude oil has been produced and sold from properties in the Delhi Field in Louisiana, the Tullos Field Area in Louisiana and the Giddings Field in Texas.  All of our natural gas has been produced and sold from our properties in the Delhi Field and the Giddings Field.  Since June 2006, we are no longer the operator of the Delhi Field, due to the farmout we completed on June 12, 2006 with Denbury Onshore LLC, a subsidiary of Denbury Resources Inc. (“Denbury”) (the “Delhi Farmout”), and, consequently, we have had no natural gas or natural gas liquids production available to us for sales and marketing purposes in the Delhi Field since June 2006.  In March 2008 we sold our properties in the Tullos Field Area and as a result have no production or properties from that area.  With respect to our properties in the Giddings Field, we have been producing natural gas and natural gas liquids since our first well began production in late February 2008, with two more wells beginning production in mid March, and four wells that began production in May and June of 2008.

Marketing of crude oil and natural gas production is influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand, market prices, government regulation and actions of major foreign producers.

Over the past 20 years, crude oil price fluctuations have been extremely volatile, with crude oil prices varying from less than $10 to in excess of $140 per barrel. Worldwide factors such as geopolitical, macroeconomic, supply and demand, refining capacity, petrochemical production and derivatives trading, among others, influence prices for crude oil.  Local factors also influence prices for crude oil and include quality differences, regulation and transportation issues unique to certain producing regions and reservoirs.

Also over the past 20 years, domestic natural gas prices have been volatile, ranging from $1 to $15 per MMBTU. The spot market for natural gas, changes in supply and demand, derivatives trading, pipeline availability, BTU content of the natural gas and weather patterns, among others, cause natural gas prices to be subject to significant fluctuations.  Due to the practical difficulties in transporting natural gas, local factors tend to influence product prices more for natural gas than for crude oil.

In the U.S. market where we operate, crude oil and natural gas liquids are readily transportable and marketable.  Since March 2005 and into 2008, we sold all of our operated crude oil production to Plains Marketing LP, a crude oil purchaser, at competitive field prices.  In January of 2008, we also began selling crude oil to Teppco Crude Oil, LLC, a crude oil gathering, transportation, storage and marketing company.  Our agreements with both Plains Marketing LP and Teppco Crude Oil, LLC are under a normal (thirty day “evergreen”) sales contracts.  We believe that other crude oil purchasers are readily available.

Prior to fiscal year 2007, we produced natural gas liquids from our Delhi Field, all of which we sold to Dufour Petroleum, L.P., a subsidiary of Enbridge Energy Partners, LP, at a market competitive price based on an index price of liquid components, less a charge of $0.175 per gallon for transportation and fractionation.  Beginning in the second quarter of our 2008 fiscal year we began selling our natural gas and natural gas liquids to DCP Midstream, LP,  and ETC Texas Pipeline, LTD., under the terms of normal evergreen sales contracts at competitive prices.  We have no other business relationships with our crude oil, natural gas or natural gas liquids purchasers.

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Competition

Our competitors include major integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than us. Competitors are national, regional or local in scope and compete on the basis of financial resources, technical prowess or local knowledge. The principal competitive factors in our industry are expertise in given geographical and geological areas and the abilities to efficiently conduct operations, achieve technological advantages, identify and acquire economically producible reserves and obtain affordable capital.

Government Regulation

Crude oil and natural gas drilling and production operations are regulated by various federal, state and local agencies. These agencies issue binding rules and regulations that carry penalties, often substantial, for failure to comply.  These regulations and rules require monthly, semiannual and annual reports on production amounts and water disposal amounts, and govern most aspects of operations, drilling and abandonment, as well as crude oil spills.  We anticipate the aggregate burden of federal, state and local regulation will continue and potentially increase.  We also believe that our present operations materially comply with applicable regulations.  To date, such regulations have not had a material effect on our operations, or the costs thereof, other than as described further in “Item 3. Legal Proceedings”.  We do not believe that capital expenditures related to environmental control facilities or other regulatory matters will be material in the near term.  We cannot predict what subsequent legislation or regulations may be enacted or what effect it will have on our operations or business.

Insurance

We maintain insurance on our properties and operations for risks and in amounts customary in the industry.  Such insurance includes general liability, excess liability, control of well, operators extra expense and casualty coverage.  Not all losses are insured, and we retain certain risks of loss through deductibles, limits and self-retentions.  We do not carry lost profits coverage, and our aviation liability insurance coverage is limited to $1million.

ITEM 1A. RISK FACTORS

Risks related to the Company

OPERATING RESULTS FROM OIL AND GAS PRODUCTION MAY DECLINE.

Due to the Delhi Farmout, our future development initiatives in the Delhi Field have been replaced with a CO2 enhanced oil recovery (“CO2-EOR”) project, in which Denbury has undertaken an obligation to fund, install and operate.  We have retained a 25% reversionary interest after a defined payout and separately acquired overriding royalty interests totaling 7.4% in the Delhi CO2-EOR project.  As anticipated, the Delhi Farmout resulted in the reduction of net proved reserves, net production and net revenues accruing to us from the Delhi Field until such time, if at all, as the CO2-EOR project is completed and brought online.

Concurrent with the sale of our properties in the Tullos Field Area, we began establishing production from newly drilled and completed wells in the Giddings Field.  The targeted reservoirs in the Giddings Field typically experience flush production followed by steep harmonic decline rates that steadily flatten to much shallower decline rates.  While the newly drilled producing wells in the Giddings Field substantially increased our net production above historic levels, without further development activities in the Giddings Field or our other properties or acquisitions of producing properties, our net production of oil and natural gas will decline significantly over time, which could have a material adverse affect on our financial condition.

THE TYPES OF RESOURCES WE FOCUS ON HAVE SUBSTANTIAL OPERATIONAL RISKS.

Our business plan focuses on the acquisition and development of known resources in partially depleted reservoirs, naturally fractured or low permeability reservoirs, or relatively shallow reservoirs. Shallower reservoirs usually have lower pressure, which translates into fewer natural gas volumes in place; low permeability reservoirs require more wells and substantial stimulation for development of commercial production; naturally fractured reservoirs require penetration of sufficient undepleted fractures to establish commercial production; and depleted reservoirs require successful application of newer technology to unlock incremental reserves.

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Our CO2-EOR project in the Delhi Field, operated by Denbury, requires significant amounts of CO2 reserves, the source of which may become unavailable or be curtailed.  Denbury controls the operations and CO2 for the project, and as a result, we have a limited ability to control or influence the development and ultimate success of the project.  In order to deliver sufficient quantities of CO2 from Denbury’s reserves from its Jackson Dome Field in Mississippi, a pipeline is being constructed to connect to the Delhi Field requiring large amounts of capital resources and the acquisition of permits, right-of-ways, engineering designs, construction personnel and materials. Denbury’s failure to manage these and other technical, strategic and logistical risks may render ultimate enhanced recoveries from the planned CO2-EOR project, if any, to fall short of our expectations in volume and or timing.

The existing well bores we are re-entering in the Giddings Field may have been originally drilled as far back as the 1980’s.  As such, they contain older casing that could be more subject to failure, or the well files, if available, may be incomplete or incorrect.  Such problems can result in the complete loss of a well or a much higher drilling and completion cost.  Our proved undeveloped locations in the Giddings Field are direct offsets to current or previously producing wells, and there may be unusually long fractures that will connect our well to another producing or depleted well, thus reducing the potential recovery, increasing our drilling costs, or delaying production due to recovery of drilling fluid lost during drilling into the depleted fractures.

Our projects generally require that we acquire new leases in and around established fields and drill and complete wells, some of which may be horizontal, as well as negotiate the purchase of existing well bores and production equipment or install our proprietary artificial lift technology that has yet to be proven in the field.  Leases may not be available and required oil field services may not be obtainable on the desired schedule or at the expected costs.  While the projected drilling results may be considered to be low to moderate in risk, there is no assurance as to what productive results may be obtained, if any.

OUR LIMITED OPERATING HISTORY AND NEWNESS OF OUR PRODUCTION MAKES IT DIFFICULT TO PREDICT FUTURE RESULTS AND INCREASES THE RISK OF AN INVESTMENT IN OUR COMPANY.

We commenced our crude oil and natural gas operations in late 2003 and have a limited operating history.  All of our current production is the result of recent drilling activities, thus our future production retains substantial variability.  Therefore, we face all the risks common to companies in their early stage of development, including uncertainty of funding sources, high initial expenditure levels and uncertain revenue streams, an unproven business model, and difficulties in managing growth.  Our prospects must be considered in light of the risks, expenses, delays and difficulties frequently encountered in establishing a new business. Any forward-looking statements in this report do not reflect any possible effects on us from the outcome of these types of uncertainty.  Prior to the Delhi Farmout, we had incurred significant losses since the inception of our oil and natural gas operations and we have since resumed incurring losses, except for the quarter ended June 30, 2008, in which we recognized positive operating income.  We cannot assure future profitability or success.  While members of our management team have previously carried out or been involved with acquisition and production activities in the crude oil and natural gas industry while employed by us and other companies, we cannot assure you that our intended acquisition targets and development plans will lead to the successful development of crude oil and natural gas production or additional revenue.

WE MAY BE UNABLE TO CONTINUE LICENSING FROM THIRD PARTIES THE TECHNOLOGIES THAT WE USE IN OUR BUSINESS OPERATIONS.

As is customary in the crude oil and natural gas industry, we utilize a variety of widely available technologies in the crude oil and natural gas development and drilling process.  We do not have any patents or copyrights for the technology we currently utilize. Instead, we license or purchase services from the holders of such technology, or outsource the technology integral to our business from third parties. Our commercial success will depend in part on these sources of technology and assumes that such sources will not infringe on the proprietary rights of others. We cannot be certain whether any third-party patents will require us to utilize or develop alternative technology or to alter our business plan, obtain additional licenses, or cease activities that infringe on third-parties’ intellectual property rights. Our inability to acquire any third-party licenses, or to integrate the related third-party products into our business plan, could result in delays in development unless and until equivalent products can be identified, licensed, and integrated. Existing or future licenses may not continue to be available to us on commercially reasonable terms or at all. Litigation, which could result in substantial cost to us, may be necessary to enforce any patents licensed to us or to determine the scope and validity of third-party obligations.

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REGULATORY AND ACCOUNTING REQUIREMENTS MAY REQUIRE SUBSTANTIAL REDUCTIONS IN REPORTED PROVEN RESERVES (SEE GLOSSARY OF SELECTED PETROLEUM TERMS).

We review on a periodic basis the carrying value of our crude oil and natural gas properties under the applicable rules of the various regulatory agencies, including the SEC. Under the full-cost method of accounting that we use, the carrying value of proved reserves of crude oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted at 10%. Application of this “ceiling” test generally requires pricing future revenues at the un-escalated prices in effect as of the end of our fiscal quarter and requires a write down of the carrying value for accounting purposes if the ceiling is exceeded, even if prices declined for only a short period of time. We may in the future be required to write down the carrying value of our crude oil and natural gas properties when crude oil and natural gas prices are depressed or unusually volatile. Whether we will be required to take such a charge will depend in part on the prices for crude oil and natural gas at the end of any fiscal period and the effect of reserve additions or revisions and capital expenditures during such period. If a write down is required, it would result in a charge to our earnings but would not impact our cash flow from operating activities.

OUR PROFITABILITY IS HIGHLY DEPENDENT ON THE PRICES OF CRUDE OIL, NATURAL GAS, AND NATURAL GAS LIQUIDS, WHICH HAVE HISTORICALLY BEEN VERY VOLATILE.

Our estimated proved reserves, revenues, profitability, operating cash flow and future rate of growth are highly dependent on the prices of crude oil, natural gas and NGLs, which are affected by numerous factors beyond our control.  Historically, these prices have been very volatile and are likely to remain volatile in the future.  A significant and extended downward trend in commodity prices would have a material adverse effect on our revenues, profitability and cash flow, and could result in a reduction in the carrying value of our oil and natural gas properties and the amounts of our estimated proved oil and natural gas reserves.  To the extent that we have not hedged our production with derivative contracts or fixed-price contracts, any significant and extended decline in oil and natural gas prices may adversely affect our financial position.

WE MAY BE UNABLE TO ACQUIRE AND DEVELOP THE ADDITIONAL OIL AND GAS RESERVES THAT ARE REQUIRED IN ORDER TO SUSTAIN OUR BUSINESS OPERATIONS.

In general, the volumes of production from crude oil and natural gas properties decline as reserves are depleted with the rate of decline depending on reservoir characteristics. Except to the extent we acquire properties containing proved reserves or conduct successful development activities, or both, our proved reserves will decline. Our future crude oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring additional reserves. Due to the Delhi Farmout and the sale of our properties in the Tullos Field Area, our near-term future growth and financial condition is highly dependent on our ability to develop additional oil and natural gas reserves.

WE ARE SUBJECT TO SUBSTANTIAL OPERATING RISKS THAT MAY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS.

The crude oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, hurricanes, flooding, pollution, releases of toxic gas and other environmental hazards and risks. We could suffer substantial losses as a result of any of these events. While we carry general liability, control of well, and operator’s extra expense coverage typical in our industry, we are not fully insured against all risks incident to our business.

We may not be the operator of some of our wells in the future. As a result, our operating risks for those wells and our ability to influence the operations for these wells will be less subject to our control. Operators of these wells may act in ways that are not in our best interests. If this occurs, the development of, and production of crude oil and natural gas from, some wells may not occur which would have an adverse affect on our results of operations.

THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT US.

We depend to a large extent on the services of certain key management personnel, including our executive officers, the loss of any of whom could have a material adverse affect on our operations.  In particular, our future success is dependent upon Robert S. Herlin, our President and Chief Executive Officer, Sterling H. McDonald, our Chief Financial Officer, and Daryl V. Mazzanti, our Vice-President of Operations, for sourcing, evaluating and closing deals, capital raising, and oversight of development and operations.  Presently, the Company is not a beneficiary of any key man insurance.

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THE LOSS OF ANY OF OUR SKILLED TECHNICAL PERSONNEL COULD ADVERSELY AFFECT OUR BUSINESS.

We depend to a large extent on the services of skilled technical personnel to lease, drill, complete, operate and maintain our crude oil and natural gas fields. We do not have the resources to perform all of these services and therefore we outsource many of our requirements. Additionally, as our production increases, so does our need for such services. Generally, we do not have long-term agreements with our drilling and maintenance service providers. Accordingly, there is a risk that any of our service providers could discontinue servicing our crude oil and natural gas fields for any reason. Although we believe that we could establish alternative sources for most of our operational and maintenance needs, any delay in locating, establishing relationships, and training our sources could result in production shortages and maintenance problems, with a resulting loss of revenue to us. We also rely on third-party carriers for the transportation and distribution of our production, the loss of any of which could have a material adverse affect on our operations.

WE MAY HAVE DIFFICULTY MANAGING FUTURE GROWTH AND THE RELATED DEMANDS ON OUR RESOURCES AND MAY HAVE DIFFICULTY IN ACHIEVING FUTURE GROWTH.

Although we hope to experience growth through acquisitions and development activity, any such growth may place a significant strain on our financial, technical, operational and administrative resources. Our ability to grow will depend upon a number of factors, including:

·                  our ability to identify and acquire new development or acquisition projects;

·                  our ability to develop existing properties;

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

·                  the results of our development program and acquisition efforts;

·                  the success of our technologies;

·                  hydrocarbon prices;

·                  drilling, completion and equipment prices;

·                  our ability to successfully integrate new properties; and

·                  our access to capital.

We can not assure you that we will be able to successfully grow or manage any such growth.

WE FACE STRONG COMPETITION FROM LARGER CRUDE OIL AND NATURAL GAS COMPANIES.

Our competitors include major integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than we have. We may not be able to successfully conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and productive crude oil and natural gas 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, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment and acquiring the existing and changing technologies that we believe are and will be increasingly important to attaining success in our industry.

THE CRUDE OIL AND NATURAL GAS RESERVES INCLUDED IN THIS REPORT ARE ONLY ESTIMATES AND MAY PROVE TO BE INACCURATE.

There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. The reserves discussed in this report are only estimates that may prove to be inaccurate because of these uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors, such as historical production from the area compared with production from other producing areas and assumptions concerning effects of regulations by governmental agencies, future crude oil and natural gas prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs. Some or all of these assumptions may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from prepared by different

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engineers or by the same engineers but at different times, may vary substantially. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the crude oil and natural gas industry in general.

WE CANNOT MARKET THE CRUDE OIL AND NATURAL GAS THAT WE PRODUCE WITHOUT THE ASSISTANCE OF THIRD PARTIES.

The marketability of the crude oil and natural gas that we produce depends upon the proximity of our reserves to, and the capacity of, facilities and third-party services, including crude oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in or delay or discontinuance could adversely affect our financial condition. In addition, federal and state regulation of crude oil and natural gas production and transportation could affect our ability to produce and market our crude oil and natural gas on a profitable basis.

Risks Relating to the Oil and Gas Industry

CRUDE OIL AND NATURAL GAS DEVELOPMENT, RE-COMPLETION OF WELLS FROM ONE RESERVOIR TO ANOTHER RESERVOIR, RESTORING WELLS TO PRODUCTION AND DRILLING AND COMPLETING NEW WELLS ARE SPECULATIVE ACTIVITIES AND INVOLVE NUMEROUS RISKS AND SUBSTANTIAL AND UNCERTAIN COSTS.

Our growth will be materially dependent upon the success of our future development program.  Drilling for crude oil and natural gas and re-working existing wells involve numerous risks, including the risk that no commercially productive crude oil or natural gas reservoirs will be encountered.  The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:

·                  unexpected drilling conditions;

·                  pressure fluctuations or irregularities in formations;

·                  equipment failures or accidents;

·                  inability to obtain leases on economic terms, where applicable;

·                  adverse weather conditions;

·                  compliance with governmental requirements; and

·                  shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.

Drilling or re-working is a highly speculative activity.  Even when fully and correctly utilized, modern well completion techniques such as Hydraulic Fracturing and Horizontal Drilling do not guarantee that we will find crude oil and/or natural gas in our wells.  Our future drilling activities may not be successful and, if unsuccessful, such failure would have an adverse affect on our future results of operations and financial condition.  We cannot assure you that our overall drilling success rate or our drilling success rate for activities within a particular geographic area will not decline.  We may identify and develop prospects through a number of methods, some of which do not include Horizontal Drilling or Hydraulic Fracturing, and some of which may be unproven.  The drilling and results for these prospects may be particularly uncertain.  Our drilling schedule and costs may vary from our capital budget.  The final determination with respect to the drilling of any scheduled or budgeted prospects will be dependent on a number of factors, including, but not limited to:

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·                  the results of previous development efforts and the acquisition, review and analysis of data;

·                  the availability of sufficient capital resources to us and the other participants, if any, for the drilling of the prospects;

·                  the approval of the prospects by other participants, if any, after additional data has been compiled;

·                  economic and industry conditions at the time of drilling, including prevailing and anticipated prices for crude oil and natural gas and the availability of drilling rigs and crews;

·                  our financial resources and results;

·                  the availability of leases and permits on reasonable terms for the prospects; and

·                  the success of our drilling technology.

We cannot assure you that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of commercially productive crude oil or natural gas.  There are numerous uncertainties in estimating quantities of proved reserves, including many factors beyond our control.

CRUDE OIL AND NATURAL GAS PRICES ARE HIGHLY VOLATILE IN GENERAL AND LOW PRICES WILL NEGATIVELY AFFECT OUR FINANCIAL RESULTS.

Our revenues, operating results, profitability, cash flow, future rate of growth 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 crude oil and natural gas.  Lower crude oil and natural gas prices also may reduce the amount of crude oil and natural gas that we can produce economically.  Historically, the markets for crude oil and natural gas have been very volatile, and such markets are likely to continue to be volatile in the future.  Prices for crude oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, including:

·                  worldwide and domestic supplies of crude oil and natural gas;

·                  the level of consumer product demand;

·                  weather conditions;

·                  domestic and foreign governmental regulations;

·                  the price and availability of alternative fuels;

·                  political instability or armed conflict in oil-producing regions;

·                  the price and level of foreign imports; and

·                  overall domestic and global economic conditions.

It is extremely difficult to predict future crude oil and natural gas price movements with any certainty.  Declines in crude oil and natural gas prices may materially adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations.  Further, crude oil and natural gas prices do not move in tandem.  Because approximately 24% of our reserves at July 1, 2008 are crude oil reserves and 33% are natural gas liquids reserves, we are heavily impacted by movements in crude oil prices, which also influence natural gas liquids prices.  While our new projects are evaluated based on the assumption of oil and natural gas prices considerably less than in the current market or projected in the futures market, we do assume commodity prices will be higher than historic levels prior to 2004.

OILFIELD SERVICE AND MATERIALS’ PRICES HAVE BEEN ESCALATING, AND THE AVAILABILITY OF SUCH SERVICES MAY BE INADEQUATE TO MEET OUR NEEDS.

Our business plan to redevelop mature crude oil and natural gas resources requires third party oilfield service vendors and various materials such as steel tubulars, which we do not control.  Long lead times and spot shortages may prevent us from, or delay us in, maintaining or increasing the production volumes we expect.  In addition, the recent escalating costs for such services and materials may render certain or all of our projects uneconomic, as compared to the earlier prices we may have assumed when deciding to redevelop newly purchased or existing properties.  Further adverse economic outcomes may result from the long lead times often necessary to execute and complete our redevelop plans.

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GOVERNMENT REGULATION AND LIABILITY FOR ENVIRONMENTAL MATTERS MAY ADVERSELY AFFECT OUR BUSINESS AND RESULTS OF OPERATIONS.

Crude oil and natural gas operations are subject to extensive federal, state and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas wells below actual production capacity in order to conserve supplies of crude oil and natural gas. There are federal, state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation and disposal of crude oil and natural gas, by-products thereof and other substances and materials produced or used in connection with crude oil and natural gas operations. In addition, we may inherit liability for environmental damages, whether actual or not, caused by previous owners of property we purchase or lease or nearby properties. As a result, we may incur substantial liabilities to third parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations could have a material adverse affect on us.

Risks Associated with Our Stock

OUR STOCK PRICE HAS BEEN AND MAY CONTINUE TO BE VERY VOLATILE.

Our common stock is thinly traded and the market price has been, and is likely to continue to be, highly volatile. For example, during the year prior to June 30, 2008, our stock price as traded on the American Stock Exchange ranged from $2.15 to $7.17.  The variance in our stock price makes it extremely difficult to forecast with any certainty the stock price at which an investor may be able to buy or sell shares of our common stock.  The market price for our common stock could be subject to wide fluctuations as a result of factors that are out of our control, such as:

·                  actual or anticipated variations in our results of operations;

·                  naked short selling of our common stock and stock price manipulation;

·                  changes or fluctuations in the commodity prices of crude oil and natural gas;

·                  general conditions and trends in the crude oil and natural gas industry; and

·                  general economic, political and market conditions.

OUR EXECUTIVE OFFICERS, DIRECTORS AND AFFILIATES MAY BE ABLE TO CONTROL THE ELECTION OF OUR DIRECTORS AND ALL OTHER MATTERS SUBMITTED TO OUR STOCKHOLDERS FOR APPROVAL.

The following share calculations treat shares issuable upon the exercise of options or warrants as outstanding (both in the numerator and denominator for percentages) and assume actual vesting.

Our executive officers and directors, in the aggregate, beneficially own approximately 12.4 million shares or approximately 38% of our fully diluted common stock, inclusive of which our Chairman of the Board, Mr. Laird Q. Cagan, Managing Director of Cagan McAfee Capital Partners, LLC (“CMCP”) currently owns or controls, directly or indirectly, approximately 7.2 million shares, or approximately 22% of our fully diluted common stock.  Mr. Eric McAfee, a Managing Director of CMCP, currently owns or controls, directly or indirectly, approximately 5.0 million shares, or approximately 15% of our fully diluted common stock, but is neither an officer, employee nor a member of our board of directors.  Collectively, the two managing directors of CMCP currently own or control, directly or indirectly, approximately 12.2 million shares, or approximately 37% of our fully diluted common stock. As a result, these holders, if they were to act together, could exercise effective control over all matters submitted to our stockholders for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of delaying, deferring or preventing a change in control of our company, impede a merger, consolidation, takeover or other business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.

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THE MARKET FOR OUR COMMON STOCK IS LIMITED AND MAY NOT PROVIDE ADEQUATE LIQUIDITY.

Our common stock is currently thinly traded on the American Stock Exchange. In the year prior to June 30, 2008, the actual trading volume in our common stock ranged from a low of 100 shares of common stock traded to a high of 353,300 shares of common stock traded, with only 66 days exceeding a trading volume of 50,000 shares. On most days, this trading volume means there is limited liquidity in our shares of common stock. Selling our shares is more difficult because smaller quantities of shares are bought and sold and news media coverage about us is limited. These factors result in a limited trading market for our common stock and therefore holders of our stock may be unable to sell shares purchased, should they desire to do so.

IF SECURITIES OR INDUSTRY ANALYSTS DO NOT PUBLISH RESEARCH REPORTS ABOUT OUR BUSINESS OR IF THEY DOWNGRADE OUR STOCK, THE PRICE OF OUR COMMON STOCK COULD DECLINE.

Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish.  However, to our knowledge, only four non-company paid analysts cover our company.  The lack of published reports by independent securities analysts could limit the interest in our common stock and negatively affect our stock price.  We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline.  If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline.

THE ISSUANCE OF ADDITIONAL COMMON AND PREFERRED STOCK WOULD DILUTE EXISTING STOCKHOLDERS.

We are authorized to issue up to 100,000,000 shares of common stock.  To the extent of such authorization, our board of directors has the ability, without seeking stockholder approval, to issue additional shares of common stock in the future for such consideration as our board may consider sufficient.  The issuance of additional common stock in the future would reduce the proportionate ownership and voting power of the common stock now outstanding.  We are also authorized to issue up to 5,000,000 shares of preferred stock, the rights and preferences of which may be designated in series by our board of directors.  Such designation of new series of preferred stock may be made without stockholder approval, and could create additional securities which would have dividend and liquidation preferences over the common stock now outstanding. Preferred stockholders could adversely affect the rights of holders of common stock by:

·                  exercising voting, redemption and conversion rights to the detriment of the holders of common stock;

·                  receiving preferences over the holders of common stock regarding our surplus funds in the event of our dissolution, liquidation or the payment of dividends to Preferred stockholders;

·                  delaying, deferring or preventing a change in control of our company; and

·                  discouraging bids for our common stock.

WE DO NOT PLAN TO PAY ANY CASH DIVIDENDS ON OUR COMMON STOCK.

We have not paid any dividends on our common stock to date and do not anticipate that we will be paying dividends in the foreseeable future.  Any payment of cash dividends on our common stock in the future will be dependent upon the amount of funds legally available, our earnings, if any, our financial condition, our anticipated capital requirements and other factors that our board of directors may think are relevant.  However, we currently intend for the foreseeable future to follow a policy of retaining all of our earnings, if any, to finance the development and expansion of our business and, therefore, do not expect to pay any dividends on our common stock in the foreseeable future.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

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ITEM 2.  PROPERTIES

Enhanced Oil Recovery (“EOR”) Property

Our EOR Initiative targets the use of miscible and immiscible gas flooding to achieve economic redevelopment and production of tertiary crude oil resources. Field candidates are likely to have already completed primary and secondary recovery operations, generally through water flooding.

Delhi Field

The Delhi Holt Bryant Unit in the Delhi Field in Louisiana, currently our most significant asset, is being redeveloped by Denbury, as operator, through an EOR project utilizing CO2 technology:

We, and the companies that submitted offers to participate with us, believe that the Delhi Holt Bryant Unit is an excellent candidate for a CO2-EOR project due to its favorable rock characteristics, large unproven reserves remaining in place, miscibility potential, low cost of drilling due to a relatively shallow depth and relatively close location to naturally occurring CO2 reserves approximately 100 miles east of the Delhi Field.  In June 2006, we conveyed a farmout to Denbury for all of our working interests in the Delhi Holt Bryant Unit and its proved reserves and 75% of our working interests in certain other depths of the Delhi Field, as described in more detail below.

According to published reports and field records, the Delhi Field was discovered in the mid-1940’s and was extensively developed by various operators including the Sun Oil and Murphy Oil companies through the drilling and completion of approximately 450 wells, most within the first few years after discovery. According to W. D. Von Gonten & Co., the third party reservoir engineering firm that prepares our independent estimate of proved reserves, the Delhi Field has produced approximately 200 million barrels of crude oil and substantial amounts of natural gas to date. Much of the natural gas production was processed to remove natural gas liquids and re-injected for pressure maintenance. Beginning in the late 1950’s, the field was unitized to conduct a pressure maintenance project through the injection of water into the producing reservoir in down dip injection wells (unitization is the process of combining multiple leases into a single ownership entity in order to simplify operations and equitably distribute royalties when common operations are conducted over multiple leases). Drilling operations resulted in primarily 40-acre spacing across the unit’s 13,636 acres. A few wells were drilled below the targeted Tuscaloosa and Paluxy formations. The water injection pressure maintenance operations did not utilize a more traditional and effective five spot flood pattern water flood that generally results in a more complete reservoir sweep and oil recovery.

At the time we began our oil and natural gas operations in late September 2003, we purchased essentially all of the working interests and an 80% net revenue interest in the Delhi Field (from the surface to the top of the Massive Anhydride formation, but excepting the Mengel Unit), for approximately $2.8 million, including the assumption of a plugging and abandonment reclamation bond.  All but 43 wells in Richland, Franklin and Madison Parishes, Louisiana had been plugged and abandoned and production averaged approximately 18 BOPD with no natural gas being sold due to a lack of natural gas processing and transportation facilities.  The best producing well was immediately lost during a periodic sand wash work-over when water from a lower reservoir broke through along the casing exterior and into the producing reservoir.

In October of 2003, we applied an unproven lateral re-entry technology that resulted in no increase in production.  In December 2003, we initiated a development program based on re-completion of wells to other reservoirs and restoring non-producing wells to producing status.  During 2004, we refurbished a gas injection line, converting it to a gas gathering and sales line, and placed a gas processing plant in the field to begin natural gas production in July of 2004.  During 2005, we began a five well development drilling program aimed at reaching mostly proved undeveloped reserves left in primary “attic” positions.  The culmination of these activities caused production to increase from 18 BOPD to a monthly average rate of 145 BOEPD during our peak production month in late 2005.

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Concurrent with these activities, we completed internal studies indicating that the reservoirs in the Delhi Holt Bryant Unit, the dominant oil producing reservoirs, were believed to be less than 50% depleted.  Based on positive CO2 pilots conducted by Sun Oil in 1985, and favorable rock characteristics shown in multiple cores taken throughout the Delhi Field, we began discussions in late 2004 with industry partners skilled in tertiary/EOR recovery methods, especially with respect to CO2 injection.

With positive industry reception, and following extended negotiations with three candidates as prospective partners, we accelerated our redevelopment plan in June 2006 by selling a major portion of our Delhi Field interests, in the form of a farmout, to a subsidiary of Denbury (the “Delhi Farmout”). Important aspects of this transaction include:

·                    We received approximately $50 million in cash (pre-tax) to redeploy to other projects and repay all of our then outstanding debt.

·                    Denbury committed to install a CO2-EOR project in the Holt Bryant Unit and expend a minimum additional $100 million on the project over the next 6-1/2 years, subject to penalty payments to us for shortfalls in such expenditures. All capital expenditures related to the project are borne by Denbury prior to payout.

·                    Denbury is the dominant CO2-EOR operator on the Gulf Coast and currently operates a large number of CO2-EOR projects and owns naturally occurring CO2 reserves that we believe to be sufficient to meet the needs of the Delhi project and which have been dedicated to the Delhi project.

·                    We retained significant participating interests through separately acquired royalty and overriding royalty interests aggregating 7.4%, and a reversionary working interest equal to 25% of Denbury’s working interest (20% revenue interest net to us). We expect the value of these interests will substantially exceed the $50 million cash component of the Delhi Farmout.

·                    Our reversionary working interest in the CO2-EOR project is based on a defined $200 million threshold, subject only to expansion of the project through acquisitions, and our reversionary working interest occurs when cumulative project net revenues less direct operating costs in the field reach the threshold.

·                    We further retained a 25% working interest (20% net revenue interest) in certain other depths outside of the Holt Bryant Unit within the Delhi Field, and believe that additional development potential may exist in the shallower depths.

·                    We expect to be able to claim proved reserves following the first EOR production response, projected to occur in late calendar 2009 or shortly thereafter.

Conventional Redevelopment Property

Our Conventional Redevelopment Initiative targets the economic development or redevelopment of primary petroleum resources previously bypassed by industry in mature, historically productive formations generally due to inadequate technology or commodity prices.

Giddings Field

Following the closing of our Delhi Farmout in June 2006, we began the process of identifying new Conventional Redevelopment projects.  In selecting our candidates:

·                     We leveraged our staff’s extensive experience, gained over many years while employed at UPRC and Anadarko Petroleum Corporation, in the pioneering of horizontal drilling practices adapted to further develop and produce the Austin Chalk and Georgetown formations in the Giddings Field in central Texas;

·                     We sought projects that could provide substantial early revenues, production and net cash flows prior to peak production from the Delhi Field; and

·                     We sought exposure to both crude oil and natural gas opportunities.

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We began leasing activities in the Giddings Field in December 2006 and acquired 17,903 net acres as of June 30, 2008.  In late 2007, we initiated a redevelopment drilling program in the Giddings Field targeting the Austin Chalk and Georgetown formations.  As of June 30, 2008, we have completed that initial drilling program and placed seven wells into production, including five wells that were re-entered, one well that was drilled and one well that was restored to production through a workover.

Essentially all of our proved reserves are located in the Giddings Field and our operations there have increased our total proved reserves by 133% over June 30, 2007, from total proved reserves of 1,723,867 BOE as of July 1, 2007 to 4,018,233 BOE as of July 1, 2008.

Tullos Field Area

On March 3, 2008, we completed the sale of our properties in the Tullos Field Area in LaSalle and Winn Parishes, Louisiana, for gross cash proceeds of approximately $4.6 million.

Producing about 100 gross and 79 net barrels of oil production per day from over 150 producing wells at the time of our divestiture, the Tullos Field Area required a disproportionate amount of staff effort and vendor services, thereby adversely affecting our ability to develop other projects utilizing our expertise and working capital, particularly in the Giddings Field.  Furthermore, we believe that the potential upside in the Tullos Field Area was substantially less than that offered in our other projects, particularly the Giddings Field drilling program, where the cash proceeds from the sale of our properties in the Tullos Field Area could be expected to yield a much higher return.  Last, we had completed the testing of our completion technology utilizing the one well we drilled in the Tullos Field Area and determined that the potential of that technology would be best realized in other fields having less depletion.

Unconventional Natural Gas Resource Property

Our Unconventional Natural Gas Resource Initiative targets the use of modern stimulation and completion technologies for the economic development and production of tight gas formations.

Two Woodford Shale Projects in Oklahoma

Following the closing of our Delhi Farmout in June 2006, we began the process of identifying Unconventional Natural Gas Resource Initiative projects.  We chose two projects in the Woodford Shale trend in Oklahoma.  In choosing these two projects:

·                     We are leveraging our staff’s expertise in horizontal drilling and tight gas development, a prerequisite to successfully exploiting and developing these resources;

·                     We are focusing on locations of source rock formations that are well known, especially gas shales;

·                     We have considered that these projects require large amounts of capital over long periods of time, thereby providing reinvestment opportunities to absorb the substantial cash flows we expect from our future Delhi EOR and Bypassed Resource production; and

·                     We are adding additional natural gas exposure to balance our existing crude oil exposure.

We began actively acquiring leases in these two projects in May 2007.  At June 30, 2008, we had acquired approximately 27,999 and 16,565 gross and net acres, respectively, across the two projects.

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Estimated Proved Oil and Natural Gas Reserves and Future Net Revenues

We engaged W. D. Von Gonten & Co. (“Von Gonten”) to prepare an independent report of our proved reserves as of July 1, 2008 (the “Reserve Report”). Von Gonten also previously prepared independent reports for all of our proved reserves at July 1, 2007, July 1, 2006, July 1, 2005, July 1, 2004 and January 1, 2004.

Estimates of reserve quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.

Denominated in equivalent barrels using a six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio, at July 1, 2008, natural gas represented 43%, natural gas liquids represented 33%, and crude oil represented 24% of total proved reserves, as compared to natural gas of 37% and crude oil of 63% of total proved reserves at July 1, 2007. The increase in proved reserves was due to the leasing, redevelopment and drilling activities in our properties in the Giddings Field, thereby more than offsetting our production and the divestment of proved reserves through our sale of properties in the Tullos Field Area in March 2008.  The change in mix of proved reserves is due, in part, to the identification and separation of natural gas liquids in the 2008 report, whereas natural gas liquids were included in the natural gas volumes in the 2007 report.

The following table sets forth, as of July 1, 2008, information regarding our proved reserves based on our Reserve Report. See Note 16 to the consolidated financial statements, where additional reserve information is provided. The average NYMEX prices used to calculate estimated future net revenues were $138.73 per barrel of crude oil, $84.39 per barrel of natural gas liquid, and $14.00 per MMBTU of natural gas as of June 30, 2008.  The NYMEX prices used were adjusted for transportation, market differentials and BTU content of gas produced.

The following table sets forth, as of July 1, 2007, information regarding our proved reserves based on an independent report prepared by Von Gonten. See Note 16 to the consolidated financial statements, where additional reserve information is provided. The average NYMEX prices used to calculate estimated future net revenues were $70.68 per barrel of oil $6.80 per MMBTU of natural gas as of June 30, 2007.  The average NYMEX prices used were adjusted for transportation, market differentials and BTU content of gas produced.

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Estimated future net revenues discounted at 10% (“PV-10”) is a non-GAAP financial measure.  We believe that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by analysts and investors in evaluating oil and natural gas companies.  We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. Further, analysts and investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies’ reserves.  We also use this pre-tax measure when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities.  Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our Company.  PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

The following table provides a reconciliation of PV-10 to the Standardized Measure of Discounted Future Net Cash Flows as shown in Note 16 of the consolidated financial statements.

During fiscal 2008, we sold production and leaseholds with reserves in place of 51,614 BOE and 433,600 barrels of crude oil, respectively.  During fiscal 2007, we sold 28,800 barrels of crude oil.

Sales Volumes, Average Sales Prices and Average Production Costs

The following table set forth certain information regarding sales volumes, average sales prices received for crude oil, natural gas liquids, and natural gas, and expenses for the periods indicated:

Average production costs, including production taxes, per unit of production (using a six to one conversion ratio of Mcf’s to barrels) were approximately $25 and $49 per BOE for the years ended June 30, 2008 and 2007, respectively.

Increased volumes for the year ended June 30, 2008, as compared to the year ended June 30, 2007, were attributable to the development of our properties in the Giddings Field.

Productive Wells and Developed Acreage

Our developed acreage at June 30, 2008 totaled 3,469 net and gross acres, all of which is in the Giddings Field, consisting of a 100% working interest in seven producing wells.  Proved undeveloped acreage includes twenty-seven proved drilling locations.  Additional drilling locations are associated with our acreage, but require further leasing before being considered for inclusion in our proved reserves.

At June 30, 2007, we owned working interests in 260 net and gross wells consisting of 158 crude oil wells, 23 salt water disposal wells and 93 shut-in wells with uncertain future utility, all located in the Tullos Field Area.  Our properties in the Tullos Field Area were sold on March 3, 2008.

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Undeveloped Acreage

As of June 30, 2008, we held approximately 57,756 gross and 34,408 net undeveloped acres in the Gulf Coast and Mid-Continent regions of the United States, as follows:

* Includes from the surface of the Earth to the top of the Massive Anhydride, less and except the Delhi Holt Bryant CO2 and Mengel Units. With respect to the Delhi Holt Bryant Unit, currently scheduled for CO2-EOR operations within this same acreage, we currently own royalty and overriding royalty interests aggregating approximately 7.4%.  Separately, we own a 25% working interest (20% net revenue interest) that will revert to us, as, if and when payout occurs, as defined. We are not the operator of the Delhi CO2-EOR project.

For more complete information regarding current year activities, including crude oil and natural gas production, refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Corporate Office

Effective on March 1, 2007, we entered into a sublease agreement with Aspen Technology, Inc to rent approximately 8,400 square feet of Class “A” office space in the Westchase District area in West Houston. The sublease expires by its term on July 1, 2016.  Prior to March 1, 2007, we occupied a leased headquarters containing 2,259 square feet in an office building located on the west side of Houston, Texas.  In April 2007, this lease expired.

ITEM 3. LEGAL PROCEEDINGS.

On August 3, 2007, we were advised of an oil spill in the Tullos Field Area near one of our leases. At the request of field agents of the Louisiana Department of Environmental Quality and the Environmental Protection Agency (“EPA”), we agreed to commence a clean-up operation that was completed by the end of August 2007. A detailed analysis of the oil in the spill compared to the Company’s produced oil was conducted by an EPA approved laboratory.  We believe that the oil in the spill did not originate from our operations, supported by the formal findings of the laboratory.  We received insurance reimbursements of $484,197 in October 2007 and $217,668 in March 2008.  These reimbursements covered all of our actual cleanup costs except a $5,000 insurance deductible and excluding our legal fees, in-house administrative costs, and any possible EPA expense reimbursements and fines that might be billed.  On May 5, 2008, we received a letter from the EPA proposing a $5,500 fine related to the oil spill.  We have also received a bill from the United States Coast Guard of approximately $70,000 for expense reimbursement.  We believe these claims are not supported by independent investigation.  As of the date of this filing, we have requested further verification from the United States Coast Guard to support their claims, and have entered into a settlement with the EPA where we have agreed to pay the $5,500 fine with no admission of liability.

In July 2008, a multi-plaintiff lawsuit was filed in the twenty-eighth Judicial District Court, Lasalle Parish, Louisiana, against 15 defendants, including Four Star Development Corporation, a former indirect wholly owned subsidiary of the Company, which was sold on March 3, 2008, as part of our sale of the Tullos Field Area.  Plaintiffs claim that the defendants’ oil and natural gas exploration, development and production activities on their properties have caused soil and ground water contamination as a result of the release of hydrocarbons and drilling fluids. Plaintiffs seek damages for testing, clean-up and remediation of the properties as well as diminution in their value and mental anguish and emotional distress to the individual plaintiffs, unjust enrichment and punitive damages for alleged concealment of ongoing activities.  At this time, we are not a party to the litigation and are unable at this time to determine the exposure, if any, to the Company.

In November 2005, a multi-plaintiff lawsuit was filed in the Fifth Judicial District Court, Richland Parish, Louisiana, against 18 defendants including NGS Sub Corp. and Arkla Petroleum LLC, the Company’s direct and indirect wholly owned subsidiaries (the “Subsidiaries”), as working interest owners/operators of various oil and natural gas leases in the Delhi Field.  Plaintiffs claim that the defendants’ oil and natural gas exploration, development and production activities on their properties have caused soil and ground water contamination as a result of the release of hydrocarbons and drilling fluids. Plaintiffs seek

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damages for testing, clean-up and remediation of the properties as well as diminution in their value and mental anguish to the individual plaintiffs, unjust enrichment and punitive damages for alleged concealment of ongoing activities.  Defendants have answered plaintiffs’ suit denying plaintiffs’ claims. Trial is set before a jury in Richland Parish for July13, 2009, and we intend to continue contesting plaintiffs’ claims vigorously.  Discovery is in process, with Plaintiffs’ expert’s report due to be filed with the Court by September 26, 2008. Defendants have performed field testing which indicates that any contamination is far less pervasive than we believe plaintiffs are claiming, although Plaintiff’s complaints are vague and a full analysis of plaintiffs’ claims cannot be completed until their expert report is available for analysis. While the Delhi Field has been in production for approximately sixty years, NGS Sub Corp. and ARKLA were owner and operator since 2003 and 2002, respectively, until June of 2006. We believe that no contamination of significance has occurred during our ownership of the Delhi Field, and that potential liability for exposure of NGS Sub Corp. results largely through any contractual indemnity of prior working interest owners which NGS Sub Corp. may have assumed for historical operations in the field in its acquisition of the subject oil and gas working interests.  At this time, the likelihood or amount of any judgment which might be rendered cannot be determined with any certainty.

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

No matters were submitted to a vote of our security holders, through solicitation of proxies or otherwise, during the fourth quarter ended June 30, 2008.

PART II

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

Common Stock

Our common stock is currently traded on the American Stock Exchange under the ticker symbol “EPM”.

We initiated trading of our common stock on the OTC Bulletin Board in May 2004, under the symbol “NGSY”.  On July 17, 2006 we qualified for trading on the American Stock Exchange. The following table shows, for each quarter of fiscal year 2008 and 2007, the high and low closing sales prices as reported by the American Stock Exchange.

American Stock Exchange

Holders

As of June 30, 2008, there were 26,870,439 shares of common stock issued and outstanding, held by 155 holders of record.

Dividends

We have never declared or paid any cash dividends with respect to our common stock. We anticipate that we will retain future earnings for use in the operation and expansion of our business and do not anticipate paying cash dividends on the common stock in the foreseeable future. Any future determination with regard to the payment of dividends will be at the discretion of the board of directors and will be dependent upon our future earnings, financial condition, applicable dividend restrictions and capital requirements and other factors deemed relevant by the board of directors.

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Securities Authorized For Issuance Under Equity Compensation Plans

(1) On May 26, 2004, we, as Reality Interactive, Inc., executed an Agreement and Plan of Merger with Natural Gas Systems, Inc., a Delaware corporation (the “Merger”). In connection with the Merger, we assumed the obligations of 600,000 stock options under our acquired subsidiary’s 2003 Stock Option Plan. As of June 30, 2008, 500,000 shares remain issuable upon exercise of stock options under the 2003 Stock Option Plan and no further options shall be issued there under. As of June 30, 2008, there were 3,946,000 shares of common stock issuable upon exercise of outstanding options and 228,141shares of restricted common stock issued directly under the 2004 Stock Plan, leaving 1,325,859 shares of common stock available for issuance.

(2) In addition to assuming certain obligations listed in footnote 1 above, in connection with the Merger, we also assumed outstanding warrants to purchase shares of common stock issued in connection with arranging the merger and in connection with capital raising services.  Total warrants outstanding as of June 30, 2008 related to these services was 401,058 with a weighted average exercise price of $1.40.  This also includes a warrant to purchase 287,500 shares of common stock in connection with Mr. Herlin’s employment agreement with the Company, a warrant to purchase 200,000 shares in connection with Mr. Mazzanti’s employment agreement with the Company, a warrant to purchase 400,000 shares of common stock in connection with Mr. Herlin’s annual performance incentives, including warrants in lieu of a cash bonus, and a warrant to purchase 150,000 shares of common stock in connection with Sterling McDonald’s annual performance incentives, including warrants in lieu of a cash bonus.

Recent Sales of Unregistered Securities

In February 2008, we made a direct stock grant for 50,000 shares to Liviakis Financial Communications, Inc. for investor relations services.

In January 2008, we issued 3,099 shares of our common stock upon exercise of warrants totaling 5,000.

In December 2007, we issued 5,207 shares of our common stock upon exercise of warrants totaling 9,463.

The shares issued during the period were exempted from registration in reliance upon Section 4(2) of the Securities Act of 1933, as amended, and Regulation D promulgated thereunder.

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ITEM 6. SELECTED FINANCIAL DATA

The selected consolidated financial data, set forth below should be read in conjunction with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the consolidated financial statements and notes to those consolidated financial statements included elsewhere in this report.

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

Executive Overview

General

We are a petroleum company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas. We acquire known, underdeveloped oil and natural gas resources and exploit them through the application of capital and technology to increase production, ultimate recoveries, or both.

Our strategy is intended to generate scalable development opportunities at normally pressured depths, exhibiting relatively low completion risk, generally longer and more predictable production lives, less expenditures on infrastructure and lower operational risks.

Within this overall strategy, we pursue three specific initiatives: