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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, 2010

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

For the transition period from              to             

Commission File Number 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)

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

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

None

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes: ¨  No: x

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes: o  No: o

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

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

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, 2009, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $4.37 on the NYSE Amex was $63,301,941.

The number of shares outstanding of the registrant’s common stock, par value $0.001, as of September 24, 2010, was 27,441,674.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant’s 2010 Annual Meeting of Stockholders to be filed within 120 days of the end of the fiscal year covered by this report are incorporated by reference into Part III of this report.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

2010 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 Annual Report on Form 10-K 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.

We use the terms, “EPM,” “Company,” “we,” “us” and “our” to refer to Evolution Petroleum Corporation.

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 form 10-K:

“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 one 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 farm-out party), to an assignee (the farm-in 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 farm-out 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 a 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.

“Mineral Royalty Interest.” A royalty interest that is retained by the owner of the minerals underlying a lease.  See “Royalty Interest”.

“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 gasolines 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 Interest or ORRI.” 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 a fluid 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.

“Probable reserves.” Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. *

“Proved Developed Reserves.” Proved Reserves  that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“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.

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“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, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. *

“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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for 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 projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

“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 the present value, discounted at 10% per annum, of future net revenues (estimated future gross revenues less estimated future costs of production, development, and asset retirement costs) associated with reserves and is not necessarily the same as market value.  PV-10 does not include estimated future income taxes.  Unless otherwise noted, PV-10 is calculated using the pricing scheme as required by the Securities and Exchange Commission (“SEC”).  PV-10 of proved reserves is calculated the same as the Standardized Measure of Discounted Future Net Cash Flows, except that the Standardized Measure of Discounted Future Net Cash Flows includes future estimated income taxes discounted at 10% per annum.  See the definition of Standardized Measure of Discounted Future Net Cash Flows below.

“Royalty” or “Royalty Interest.” 1) 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. 2) When a royalty interest is coterminous with and carved out of an operating or working interest, it is an “Overriding Royalty Interest,” which also may generically be referred to as a Royalty.

“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.

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“Standardized Measure.” The Standardized Measure of Discounted Future Net Cash Flows is an estimate of future net cash flows associated with proved reserves, discounted at 10% per annum.  Future net cash flows is calculated by reducing future net revenues by estimated future income tax expenses and discounting at 10% per annum.  The Standardized Measure and the PV-10 of proved reserves is calculated in the same exact fashion, except that the Standardized Measure includes future estimated income taxes discounted at 10% per annum.  The determination of Standardized Measured is in accordance with accounting standards generally accepted in the United States of America (“GAAP”).

“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.

* This definition is an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of Regulation S-X.

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Item 1.  Business

General

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.

Our petroleum operations began in September of 2003. We acquire known 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.

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 NYSE Amex 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, 2010, we had ten full-time employees, not including contract personnel and outsourced service providers.

Corporate History of Reverse Merger

Reality Interactive, Inc. (“Reality”), a Nevada corporation that previously traded on the OTC Bulletin Board under the symbol RLYI.OB and the predecessor of 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 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 NGS, and the crude oil and natural gas business of Old NGS became that of NGS.  Concurrently with the listing of NGS shares on the NYSE Amex (formerly the American Stock Exchange) during July 2006, NGS was renamed Evolution Petroleum Corporation to avoid confusion with similar names traded on the NYSE 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 EPM after the merger.

Business Strategy

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

We are focused on increasing underlying asset values on a per share basis.  In doing so, we depend on a conservative capital structure, allowing us to maintain control of our assets for the benefit of our shareholders, including approximately 20% beneficially owned by all of our employees.

Our strategy is intended to generate scalable, low unit cost, development and re-development opportunities that minimize or eliminate exploration risks.  These opportunities involve the application of modern technology, our own proprietary technology and our specific expertise in overlooked areas of the United States.

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The assets we exploit currently fit into three types of project opportunities:

·                  Enhanced Oil Recovery (EOR),

·                  Bypassed Primary Resources, and

·                  Unconventional Shale Gas Development.

Our active projects in these categories are:

Delhi Field CO2 EOR (Enhanced Oil Recovery) Project

Our interests in the Delhi Holt Bryant Unit in the Delhi Field located in Northeast Louisiana are currently our most significant asset.  The Unit is currently being redeveloped as an EOR project utilizing CO2 technology by a subsidiary of Denbury Resources Inc. as Operator.

We own royalty interests in the Unit aggregating 7.4%.  The royalties bear no operating or capital cost burdens to us and are in effect throughout the life of the project.

We also own a 23.9% reversionary working interest with an associated 19.2% net revenue interest.  The working interest reverts to us when the Operator has generated $200 million of field revenue from the 100% working interest and associated revenue interest, less  direct operating expenses including the cost of purchased CO2.  Upon reversion of the deemed $200 million payout, regardless of the Operator’s actual capital expenditures, we begin bearing 23.9% of all future operating and capital expense.  Also at payout reversion, our net revenue interest increases from 7.4% to 26.6%.

During Fiscal 2010:

·      Our independent reservoir engineers, DeGolyer & MacNaughton (“D&M”) assigned the following net reserves to our interests at Delhi as of June 30, 2010:

·                  9.4 MMBBLs of proved oil reserves, with a PV-10 of $224.5 million *

·                  5.7 MMBBLS of probable oil reserves, with a PV-10 of $51.2 million *

* PV-10 of proved reserves is a non-GAAP measure, reconciled to the Standardized Measure of Future Net Cash Flows at “Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues” under Item 2. Properties of this Form 10-K.  Probable reserves are not recognized by GAAP, and therefore the PV-10 of probable reserves can not be reconciled to a GAAP measure.

·      On April 5, 2010, we announced that oil production in the Delhi enhanced oil recovery project (EOR) began in March 2010, approximately three to four months earlier than we expected.

·      On November 12, 2009 CO2 injection commenced.

We believe that the Delhi Holt Bryant Unit is a strong candidate for a CO2-EOR project due to its favorable rock characteristics, large unproven reserves remaining in place, 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.  We base our belief on (i) our internal analyses of CO2 pilot tests successfully completed in the Delhi Holt Bryant Unit by a prior field operator, (ii) our analysis of favorable analogous comparisons to successful full scale projects in the same or similar geological formation, (iii) a competitive offering process, wherein we solicited multiple major participants with CO2-EOR expertise, funding and operating abilities, leading to confidential competitive offers made to us in writing, (iv) our qualitative assessment that the competitive offers were based on the CO2-EOR potential of the Unit and not on the relatively minor associated proved reserves existing at that time, (v) the buyer’s willingness to commit a portion of its proved CO2 reserves and a $100 million minimum future investment, subject to penalties for non-performance, in a CO2 project in the Unit, (vi) the early oil production response following the initiation of CO2 injection, and (vii) D&M’s reserve assignments.

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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 D&M, an independent reservoir engineering firm experienced in CO2-EOR projects who is engaged by Denbury and us to review the project, the Delhi Field has produced approximately 192 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 approximately 95.8% of the working 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.  At that time, 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 conventional 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, at a capital cost of about $2.5 million.

Concurrent with these activities, we completed internal studies indicating that the reservoirs in the Delhi Holt Bryant Unit, the dominant oil producing reservoirs, had substantial remaining recoverable oil in place.  Based on positive CO2 pilots conducted by Sun Oil in 1985, and favorable rock characteristics shown in multiple cores previously taken throughout the Delhi Field, we began discussions in late 2004 with potential industry partners skilled in CO2-EOR recovery methods,.

During this time we also began to acquire royalty and overriding royalty interests that ultimately aggregated 7.4%, at a capital cost of approximately $1.5 million.

With positive industry reception, and following extended negotiations with three candidates as prospective partners, we accelerated our redevelopment plan in June 2006 by selling all of our working interest in the Holt Bryant Unit, in the form of a Farmout, to Denbury Onshore LLC, a subsidiary of the Operator, and 75% of our working interests in certain other depths of the Delhi Field (the “Delhi Farmout”).  Important aspects of this transaction include:

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

·       We retained significant participating interests through a reversionary working interest equal to 23.9% (25% of our original working interest delivered to Denbury), with an associated 19.2% net revenue interest.  We expected that the value of these interests (along with the separately acquired mineral royalty and overriding royalty interests aggregating 7.4% would substantially exceed the $50 million cash component of the Delhi Farmout, subject to future oil prices, operating expenses, anticipated EOR performance and project completion by the Operator.

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

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·      The Operator is the dominant CO2-EOR operator on the Gulf Coast and owns naturally occurring proved 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.

·      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 revenues less direct operating costs in the field reach the threshold.  Direct operating costs include an established cost for each purchased Mcf of CO2  equal to 1% of the price of a barrel of crude oil sold from the Holt Bryant Unit plus $0.20 for transportation.  CO2 injection volumes are primarily from purchases during the initial years of a CO2-EOR project, and are gradually displaced by cheaper recycling costs (currently about $0.15 per Mcf) later in the project.

Bypassed Primary Resource Projects

Following the closing of our Delhi Farmout in June 2006, we began the process of identifying new conventional development and/or redevelopment projects targeting primary petroleum resources previously bypassed by industry in historically productive formations, generally due to inadequate technology or commodity prices.  In selecting our candidates:

·                  We leveraged our staff’s extensive experience, gained over many years while employed at various large independent oil and gas companies in the pioneering of horizontal drilling practices adapted to further develop and produce the Austin Chalk, Georgetown and Buda formations in the Giddings Field in central Texas;

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

·                  We sought projects that could generate multiple, scalable drilling opportunities with long term production growth; and

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

Giddings Field

We began leasing activities in the Giddings Field in December 2006 and acquired 20,899 and 19,147 gross and net acres, respectively, of which 5,027 net acres are developed and 7,255 net acres remain as net undeveloped and associated with our proved and probable drilling locations as of June 30, 2010.  In late calendar 2007, we initiated a redevelopment drilling program in the Giddings Field targeting the Austin Chalk and Georgetown formations.  As of June 30, 2010, we have placed ten wells into production, including seven wells that were re-entered and re-drilled, one new well that was drilled and two wells that were restored to production through workovers.  Total net proved reserves assigned to our properties in the Giddings Field by our independent reservoir engineer, W.D. Von Gonten & Associates, are 2,983 MBOE as of June 30, 2010, a slight decrease of 30 MBOE from June 30, 2009 despite Giddings production during the year of 119.2 MBOE.  Our total investment of $26.7 million to date has generated cash flows from 286.3 MBOE of total net production and our proved PV-10 at June 30, 2010 of $41.3 million.  In addition, we have two probable drilling locations and probable undeveloped reserves associated with proved drilling locations totaling 978 MBOE with a PV-10 of $11.7 million.  See “Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues” under Item 2. Properties of this Form 10-K for a reconciliation of PV-10 to the Standardized Measure.

On July 16, 2010, we entered into a joint development agreement (“JDA”) with an industry partner.  The JDA provides that we operate the drilling of two firm commitment wells on our proved and probable locations in the Giddings Field, with the potential to add up to three option wells as elected by our partner.  Under the terms of the JDA, we retain a 10% carried working interest in recognition of our costs to date, a 10% cost bearing working interest for our cash participation, and a 22.5% back-in working interest on each well drilled on our partner’s 80% working interest following a simple 2 well basket payout and well-by-well simple pay-out on subsequent wells (bringing our after-payout working interest in each well to 38%).  The leases carry an approximate 80% net revenue interest to the 100% working interests.

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Lopez Field (Neptune Oil Project)

We acquired 1,721 net acres through leasing in our Neptune Oil Project in the Lopez Field in South Texas.  We believe that previous drilling and production in this field by another operator established reserves potential on infill spacing.  As of June 30, 2009, our independent reservoir engineer recognized four proved well locations with 47.6 MBO of proved undeveloped reserves on approximately 40 net acres of our holdings.  We began field testing late in the second fiscal quarter of 2010 with the drilling of two infill producers and the re-entry of two previously abandoned wells for water injection.  Due to delays in obtaining electric power service and mechanical problems with the re-entered injection wells, we were not able to begin effective testing until the fourth quarter of 2010, thus we elected to reclassify the proved reserves as probable as of June 30, 2010.  Our independent engineer, W.D. Von Gonten & Associates, has concurred with this position and has assigned 21 additional probable drilling locations.  Should further testing warrant full development, we have identified up to 92 additional prospective infill drilling locations in the balance of our leasehold.

Tullos Field

On March 3, 2008, we completed the sale of our properties in the Tullos Field, located in LaSalle and Winn Parishes in 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 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. The field produced large volumes of water associated with the oil production after being downsized to only two acre spacing. Furthermore, we believe that the potential upside in the Tullos Field was substantially less than that offered in our other projects, where the cash proceeds from the sale of our properties in the Tullos Field could be expected to yield a much higher return.  Last, we had completed the testing of our oil-on-water completion technology utilizing the one well we drilled in the Tullos Field and determined that the potential of that technology could be best realized in other fields with greater potential.

Unconventional Gas Resources

Woodford Shale Projects in Oklahoma

Also following the closing of our Delhi Farmout in June 2006, we began the process of identifying unconventional natural gas resource projects, to balance the oily nature of our anticipated Delhi reserves.  Following are the parameters we sought.

·                  Low drilling risks, with well AFE costs in the $200,000 to $2 million range.

·                  Low reserve risk.

·                  Repeatable development performance across a substantial acreage position.

·                  Acceptable profitability at $5 NYMEX natural gas prices.

These parameters led us to the shallower sections of the Woodford Shale in Eastern Oklahoma.

Wagoner County

The Woodford Shale formation in our leasehold in Wagoner County generally lies at a depth of 1200’ to 1600’. Our 9,176 net acre leasehold is offset by two operators that have combined to drill commercial wells extensively in the Woodford to date in a much shallower portion of the formation. During 2010, we continued our deliberate testing program with wells in three of our four acreage blocks, tests of the Woodford and Caney formations, and tests of three types of completions including two types of fracs.  These tests indicated that:

·                  The Caney Shale is an incremental target that may add long term value as a secondary target to the Woodford.

·                  The frac tests, when combined with information obtained from other operators, have better defined optimum completion practices.

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·                  Henry #19-2 in our western most block was more successful than expected, reaching a peak production rate of 90-100 mcfd before power failures from storms ended the test.  Our independent reservoir engineer has assigned proved developed nonproducing reserves of 138 MMCF to the Henry well and further assigned ten offset probable drilling locations (1.4 BCF net) surrounding the well.

·                  The Knoche well in our southern leasehold block utilized a different completion method and was substantially less productive than expected.  A second test well in the leasehold will be required prior to a full development decision regarding this block..

·                  The Limon well in our eastern leasehold block was tested in the Caney Shale and is currently being prepared for testing in the Woodford Shale.

Haskell County

The Woodford Shale formation in our 8,441 net acre leasehold in Haskell County generally lies at a depth of 4000’ to 6000’. Our leasehold is just north of a short horizontal Woodford well with extensive production history that indicates substantial ultimate recovery and good commerciality.  As of July 1, 2010, development and production testing had not yet begun on our leasehold, although we plan to begin initial test operations during fiscal 2011.

Markets and Customers

We market our production to third parties in a manner consistent with industry practices.

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 Enterprise Crude Oil LLC, a crude oil gathering, transportation, storage and marketing company.  Our agreements with both Plains Marketing LP and Enterprise Crude Oil LLC are under a normal (thirty day “evergreen”) sales contracts.  During our fiscal 2010 year we amended our contracts to sell essentially all of our crude oil from our operated properties to Enterprise Crude Oil LLC.  We believe that other crude oil purchasers are readily available.

We sell our natural gas and natural gas liquids from our properties in the Giddings Field, under the terms of normal evergreen sales contracts at competitive prices with DCP Midstream, LP,  ETC Texas Pipeline, LTD., and Copano Field Services/Upper Gulf Coast, L.P.  Gas sold to DCP and ETC is processed for removal of natural gas liquids, and we receive the proceeds from the sale of the NGL product less a fee and certain operating expenses. The price of natural gas sold to Copano is adjusted upward for the high BTU content.  We have no other business relationships with our crude oil, natural gas or natural gas liquids purchasers.

The following table sets forth purchasers of our oil and natural gas that accounted for more than 10% of total revenues for 2010, 2009, and 2008.

The loss of any single purchaser would not be expected to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive.

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Market Conditions

Marketing of crude oil, natural gas, and natural gas liquids 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 25 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 25 years, domestic natural gas prices have been extremely 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 and regional factors tend to influence product prices more for natural gas than for crude oil.

Similarly, domestic natural gas liquids prices have been volatile, influenced by crude oil price, NGL supply and demand, consolidation among NGL fractionators and natural gas price.

Competition

The oil and natural gas industry is highly competitive for prospects, acreage and capital.  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

Numerous federal and state laws and regulations govern the oil and gas industry. These laws and regulations are often changed in response to changes in the political or economic environment. Compliance with this evolving regulatory burden is often difficult and costly, and substantial penalties may be incurred for noncompliance.  We believe that we are in substantial compliance with all laws and regulations applicable to our operations and that continued compliance with existing requirements will not have a material adverse impact on us. The future annual capital cost of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including future changes to regulatory requirements which are unpredictable. However, we do not currently anticipate that future compliance with existing laws and regulations will have a materially adverse effect on our consolidated financial position or results of operations.

See “Government regulation and liability for environmental matters may adversely affect our business and results of operations” under Item 1A Risk Factors of this Form 10-K, for additional information regarding government regulation.

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, casualty, fraud and directors & officer’s liability 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.

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Item 1A. Risk Factors

Risks related to the Company

Operating results from oil and natural gas production may decline.

In the near term, our production is totally dependent on ten wellbores at our Giddings Field and our 7.4% royalty interests in EOR production that began at our Delhi Field in March 2010.  The targeted reservoirs in the Giddings Field typically experience flush initial production, followed by steep harmonic decline rates that steadily flatten to much shallower decline rates.  Although EOR production from proved reserves at Delhi is expected to grow over time, without further development activities in the Giddings Field, Delhi or our other properties, or without acquisitions of producing properties, our net production of oil and natural gas could 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.

Our CO2-EOR project in the Delhi Field, operated by a subsidiary of Denbury Resources Inc., requires significant amounts of CO2 reserves, development capital and technical expertise, the sources of which have been committed by the Operator.  Although initial CO2 injection began at Delhi in November 2009 and an initial oil production response began in March 2010, substantial capital remains to be invested to fully develop the EOR project and further increase production.  The Operator’s failure to manage these and other technical, strategic, financial and logistical risks may render ultimate enhanced recoveries from the planned CO2-EOR project to fall short of our expectations in volume and or timing. Such occurrences would have a material adverse effect on the Company and its results of operations.

The existing well bores we are re-entering in the Giddings Field were 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 other projects in Oklahoma and Texas, although believed to have oil and/or gas resources, have yet to exhibit significant proved reserves.  Therefore, their economic outcome is uncertain.

Our projects generally require that we acquire new leases in and around established fields or other known resources, 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 universally proven.  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.

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Our limited operating history and limited 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, particularly in our currently producing fields.  All of our current production is the result of recent operational 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.  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.

The loss of a large single purchaser of our oil and natural gas could reduce the competition of our production.

For the year ended June 30, 2010, five purchasers each accounted for all of  our oil and natural gas revenues.  The loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive.

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, but a patent application is pending on one of our technologies. We generally 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.

Our proprietary technology may not be awarded patent protection and may not result in a commercial service or product.

We have developed and field tested our artificial lift technology that we hope to commercialize and generate material value. Our success in commercializing the technology will depend upon additional positive field tests, acceptance by industry and our ability to defend the technology from competitors through confidentiality and/or patent protection.  Although our patent is pending, there is no assurance that a patent will be awarded or that we will have the ability to exercise patent defense against competitors.

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Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.

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 after-tax carrying value of our 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 requires pricing future revenues at the previous 12-month average beginning-of-month price and requires a write down of the carrying value for accounting purposes if the ceiling is exceeded. 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 during the previous 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 current charge to our earnings but would not impact our current 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 natural 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 decline characteristics of our Giddings wells, our near-term future growth and financial condition are dependent upon our ability to realize production increases expected at Delhi, and /or the development of 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, and we are not the operator of our high value assets in the Delhi Field.  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 timely or at all, 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;

·                    our access to capital; and

·                    the Delhi Field operator’s ability to: deliver sufficient quantities of CO2 from its reserves in the Jackson Dome, secure all of the development capital necessary to fund its and Evolution’s cost interests and to successfully manage technical, strategic and logistical development and operating risks.

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

We face strong competition from larger oil and 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.

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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 product 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 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. The estimated discounted future net cash flows from proved reserves are based on the previous 12-month average beginning-of-month price 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.  PV-10 does not necessarily correspond to market value.

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 necessary to make the products marketable for end use. 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.

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Drilling or re-working is a highly speculative activity.  Even when fully and correctly utilized, modern well completion techniques such as hydraulic fracturing , horizontal drilling or CO2 or other injectants do not guarantee that we will find and produce crude oil and/or natural gas in our wells in economic quantities.  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, hydraulic fracturing or tertiary injectants, 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:

·                    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, natural gas and NGLs;

·                    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 83% of our proved reserves at June 30, 2010 are crude oil reserves and 8% are natural gas liquids reserves, we are heavily impacted by movements in crude oil prices, which also influence natural gas liquids prices.

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Oil field service and materials’ prices may increase, and the availability of such services may be inadequate to meet our needs.

Our business plan to develop or redevelop 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, if costs for such services and materials increase, it 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.

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, such as diminishing the demand for our products through legislative enactment of proposed new penalties, fines and/or taxes on carbon that could have the effect of raising prices to the end user.

For example, currently proposed federal legislation, that, if adopted, could adversely affect our business, financial condition and results of operations, includes the following:

·                  Climate Change.  On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.  President Obama has indicated his support of legislation to reduce greenhouse emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. The U.S. Environmental Protection Agency (EPA) has also taken recent action related to greenhouse gasses. Based on recent developments, the EPA now purports to have a basis to begin regulating emissions of greenhouse gasses under existing provisions of the federal Clean Air Act.   It is not possible at this time to predict whether or when the U.S. Senate may act on climate-change legislation, however any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas that we produce.

·                  Taxes.  President Obama’s Fiscal Year 2011 Budget Proposal includes provisions that would, if enacted, repeal of the percentage depletion allowance for oil and natural gas properties, eliminate the immediate deduction for intangible drilling and development costs and eliminating the deduction from income for domestic production activities relating to oil and natural-gas exploration and development, and

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·                  Hydraulic Fracturing.  The U.S. Congress is currently considering legislation that could adversely affect the use of the hydraulic-fracturing process.  Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. This legislation, if adopted, could establish an additional level of regulation, permitting and restrictions at the federal level, that could adversely affect the development of unconventional oil and natural gas resources, particularly our Oklahoma shale projects.

We could be adversely affected by a weak domestic or global economy.

The current anemic recovery from a recessionary economic environment has limited the recovery in demand for oil and natural gas and, therefore, in commodity prices, particularly natural gas.  If the current economic environment continues, lower realized prices may result, and result in continued or increased operating losses.  These factors could negatively impact our operations and may limit our growth.

Risks Associated with Our Stock

Our stock prices 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, 2010, our stock price as traded on the NYSE Amex ranged from $2.21 to $6.25.  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.

Our executive officers and directors, in the aggregate, beneficially own approximately 7.0 million shares or approximately 26% of our outstanding common stock.  Our former Chairman, and current director of the Board, Mr. Laird Q. Cagan, is a  Managing Director of Cagan McAfee Capital Partners, LLC (“CMCP”).  Mr. Eric McAfee, also a Managing Director of CMCP, currently owns or controls, directly or indirectly, approximately 2.9 million shares, or approximately 11% of our outstanding 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 3.2 million shares, or approximately 12% of our outstanding common stock.  Institutional affiliates, including JVL Advisors LLC and Peninsula Capital Management, LP, collectively own approximately 6.7 million shares or approximately 25% of our outstanding common stock.  As a result, these holders, could exercise significant influence over 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.

The market for our common stock is limited and may not provide adequate liquidity.

Our common stock is currently thinly traded on the NYSE Amex. In the year prior to June 30, 2010, the actual daily trading volume in our common stock ranged from 2,795 shares of common stock to a high of 1,097,969 shares of common stock traded, with only 89 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.

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If securities or industry analyst 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 three independent 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 stock and preferred stock could dilute existing stockholders.

From time to time, we may have an effective shelf registration that allows us to publicly offer various securities, including common or preferred stock, and at any time we may make private offerings of our securities.  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.

Item 2.  Properties

Company Location

Our corporate headquarters are located at 2500 CityWest Boulevard, Suite 1300, Houston, Texas.  We entered into a sublease agreement, effective on March 1, 2007, to rent approximately 8,400 square feet of Class “A” office space in the Westchase District area in West Houston.  The current monthly base rent is $11,507 with the base rent escalating to a monthly base rate of $13,251 in August 2011. 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.

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Oil & Gas Properties

Additional detailed information describing the types of properties we own can be found in “Business Strategy” under Item 1. Business of this Form 10-K.

Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues

In December 2008, the SEC adopted new rules related to modernizing reserve estimation and disclosure requirements for oil and natural gas companies (the “Modernization Requirements”), which became effective for annual reporting periods ending on or after December 31, 2009. The Modernization Requirements require disclosure of oil and gas proved reserves by significant geographic area, using the 12-month average beginning-of-month price for the year, rather than year-end prices, and allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes.  Another significant provision of the new rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.

There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.

Estimated future net revenues discounted at 10% or PV-10 is a financial measure that is not recognized by GAAP.  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 as defined under GAAP, and reconciled below.

Proved Reserves Fiscal Year Ended 2010

Applying the new rules, our proved reserves at June 30, 2010, denominated in equivalent barrels using a six Mcf of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio, totaled 12,418 MBOE. Approximately 9% of our reserves were classified as proved developed and 91% were classified as proved undeveloped. Classified by product, 83% of our reserves were crude oil, 8% were natural gas liquids, and 9% were natural gas. Our proved reserves as of June 30, 2010 were estimated by our independent petroleum consultants, W.D. Von Gonten & Co. (“Von Gonten”), DeGolyer and MacNaughton (“D&M”), and Lee Keeling and Associates, Inc. (“Keeling”).  Von Gonten and Keeling were engaged for our Texas and Oklahoma properties, respectively, due to their particular expertise in the geographic and geologic areas covered by their reports.  D&M was selected for our properties in the Delhi Field due to their expertise in CO2-EOR projects and to ensure consistency with the Operator who has utilized D&M for their reserves estimates in the Delhi Field.   The scope and results of their procedures are summarized in letters from each of those firms, which are included as exhibits to this Annual Report on Form 10-K.

The following table sets forth our estimated proved reserves as of June 30, 2010.  See Note 16 to the consolidated financial statements, where additional reserve information is provided.  The New York Mercantile Exchange 12-month average beginning-of-month price used to calculate estimated revenues was $76.45 per barrel of crude oil and $4.09 per MMbtu of natural gas.  The price of natural gas liquids utilized was based on the historical price received versus the NYMEX basis oil price.  Pricing differentials were applied to all properties, on an individual property basis.  Quality adjustments have been applied based on actual BTU factors for each well and a shrinkage factor has been applied based on production volumes versus actual sales volumes.

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June 30, 2010

Proved Reserves Fiscal Year Ended 2009

We engaged Von Gonten to prepare an independent report of our proved reserves as of June 30, 2009. Denominated in equivalent barrels using a six Mcf of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio, we recognized proved reserves of 3,060,040 at June 30, 2009.  Of our proved reserves, natural gas represented 35%, natural gas liquids represented 34%, and crude oil represented 31% as of June 30, 2009.

The following table sets forth our estimated proved reserves as of June 30, 2009.  See Note 16 to the consolidated financial statements, where additional reserve information is provided.  The NYMEX spot prices used to calculate estimated revenues were $69.89 per barrel of crude oil and $3.885 per MMbtu of natural gas as of June 30, 2009.  The price of natural gas liquids utilized was based on the historical price received versus the NYMEX basis oil price.  Pricing differentials were applied to all properties, on an individual property basis, in order to reflect prices actually received at the wellhead.  Quality adjustments have been applied based on actual BTU factors for each well and a shrinkage factor has been applied based on production volumes versus actual sales volumes.

June 30, 2009

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Changes in Proved Reserves

Total proved reserves increased 9.4 million BOE from 3,060,040 BOE at June 30, 2009 to 12,418,256 BOE at June 30, 2010.  The increase is primarily attributable to 9,411,841 barrels of proved oil reserves we added to our properties in the Delhi Field, based on approximately $300 million of development capital spent by the Operator since project inception, the start-up of CO2 injection operations during fiscal year 2010, and an oil production response during fiscal year 2010.  The additions in our properties in the Delhi Field along with extensions in Giddings and Oklahoma of 127,905 BOE, were offset by production of 125,515 BOE and negative revisions of 60,943 BOE primarily related to the transfer of four well locations in the Lopez Field in South Texas from the proved classification to probable on June 30, 2010.

Reconciliation of PV-10 to the Standardized Measure of Discounted Future Net Cash Flows

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

The following table provides a reconciliation of PV-10 of each of our proved properties to the Standardized Measure as shown in Note 16 of the consolidated financial statements.

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2010 Reserves Pricing Sensitivities

In addition to the proved reserves determined using SEC pricing, our independent engineers prepared estimates of our year-end proved reserves using two alternative commodity price assumptions. The following table summarizes our total proved reserves as of June 30, 2010 under each of the three assumptions:

(1)  The Spot price case is based on the NYMEX spot crude oil, natural gas liquid, and natural gas price as of June 30, 2010. For oil and natural gas liquids, the NYMEX posted price of $75.63 per barrel was adjusted by lease for quality, transportation fees and regional price differentials. For natural gas, the NYMEX spot price of $4.53 per MMBtu was adjusted by lease for energy content, transportation fees and regional price differentials. Such prices were held constant throughout the estimated lives of the reserves. Future production and development costs are based on year-end costs with no escalations.

(2) The Forward curve case is based on the five year applicable monthly forward closing prices on the NYMEX for oil and natural gas as of June 30, 2010. For oil and natural gas liquids, the price was based on a crude oil price which increased from $75.63 per Bbl to $84.43 per Bbl during the first five years and then held constant during the remaining life of the reserves, adjusted by lease for quality, transportation fees and regional price differentials. For natural gas, the price was based on a natural gas price which increased from $4.53 per MMBtu to $6.07 per MMBtu  during the first five years and then held constant over the remaining life of the properties, adjusted by lease for energy content, transportation fees and regional price differentials. Future production and development costs are based on year-end costs with no escalations.

Probable Reserves Fiscal Year Ended 2010

The Modernization Requirements also permitted the disclosure of probable reserves.  Probable reserves are additional reserves that are less certain to be recovered than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered.  The various reserve categories have different risks associated with them. Proved reserves are more likely to be produced than probable reserves. Because of these risks, the different reserve categories should not be considered to be directly additive.

Additional detailed information describing the types of properties we own can be found in Item 1. Business — Business Strategy.

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Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons and

Our policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our Chief Executive Officer and Vice President of Operations and to be in compliance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.  We provide each engineering firm with property interests, production, current operating costs, current production prices and other information.  This information is reviewed by our Vice President of Operations and our Chief Executive Officer to ensure accuracy and completeness of the data prior to submission to our third party engineering firm. The scope and results of our third party engineering firms’ procedures are summarized in a letter included as an exhibit to this Annual Report on Form 10-K.  A letter which identifies the professional qualifications of each of the independent engineering firms who prepared the reserve reports are also filed as exhibits to this Annual report on Form 10-K.

Proved Undeveloped Reserves

Our proved undeveloped reserves at June 30, 2010 were 11.3 MMBOE. Future development costs associated with our proved undeveloped reserves at June 30, 2010 totaled approximately $32.9 million.  The increase in proved undeveloped reserves is primarily attributable to 8.8 MMBOE of proved undeveloped oil reserves we added to our properties in the Delhi Field, based on approximately $300 million of development capital spent by the Operator since project inception, the start-up of CO2 injection operations during fiscal year 2010, and an oil production response during fiscal year 2010.  None of our proved undeveloped locations remain undeveloped for five years from the date of initial recognition as proved undeveloped reserves.

Sales Volumes, Average Sales Prices and Average Production Costs

The following table shows the Company’s sales volumes and average sales prices received for crude oil, natural gas liquids, and natural gas 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 $13, $11 and $25 per BOE for the years ended June 30, 2010, 2009 and 2008, respectively.

Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the year ended June 30, 2010 decreased 6% to 125,515 BOE, compared to 134,035 BOE for the year ended June 30, 2009.  Our sales volumes for the year ended June 30, 2010 included 6,333 Bbls of oil from Delhi (of which 5,721 bbls of oil were sold during the 4th quarter of 2010) and 119,182 BOE from our properties in the Giddings Field in Texas.

First EOR oil production at Delhi began in the last two weeks of March 2010.  Total sales volumes from Delhi, net to our interest, for the year ended June 30, 2010 was 6,333 Bbls of oil compared to 172 Bbls of oil during the year ended June 30, 2009.  Our interests in the Delhi Field consist of more than 76% of our total proved reserves as of June 30, 2010.  The average sales price per barrel of crude oil at Delhi was $76.59 for the year ended June 30, 2010, with no associated production costs.

Production from our properties in the Giddings Field decreased 11% from 133,863 BOE during the fiscal year ended June 2009 to 119,182 BOE during the fiscal year ended June 30, 2010. Production of natural gas from our properties in the Giddings Field increased 26%, while production of crude oil and NGLs decreased 31% compared to the year ended June 30, 2009.  Our interests in the Giddings Field consist of 24% of our total proved reserves as of June 30, 2010.  The average sales price per BOE at Giddings was $38.07 for the year ended June 30, 2010, and associated production costs (not including ad valorem and production taxes) were $12.52 per BOE.

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The increase in volumes from fiscal 2008 to fiscal 2009 were attributable to the development of our properties in the Giddings Field, which accounted for almost 100 percent of our production during the year ended June 30, 2009.  Our production in the Giddings Field began late in the third fiscal quarter of the year ended June 30, 2008.  Our properties in the Tullos Field, which were sold on March 3, 2008, accounted for 35% of total sales volumes for the year ended June 30, 2008.

Drilling Activity

The following table sets forth our drilling activity.

Present Activities

We are currently drilling the Supak-Brinkman-1H in the Giddings Field under of joint development agreement with an industry partner.  The Supak-Brinkman-1H is a $1.7 million gross AFE re-entry operation to add a single Austin Chalk lateral to an existing wellbore.   We will receive a 10% carried working interest, a 10% cost bearing working interest for our cash participation, and a 22.5% back-in working interest on our partner’s 80% working interest.

We are continuing to test the Garcia #1 of our Neptune South Texas Project through a workover.

In Oklahoma, we have temporarily suspended the Henry 19-2 waiting on pipeline connection and we are moving our test of the Limon from the Caney to the Woodford Shale in the same well bore.  Further testing of the Knoche 1 and Knoche 2 are pending.

For further discussion, see “Highlights for our fiscal year 2010” and “Looking forward into 2011” under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

Delivery Commitments

As of June 30, 2010, we had no delivery commitments.

Productive Wells and Developed Acreage

Our developed acreage at June 30, 2010 totaled 5,040 net acres in the Giddings Field, consisting of a 100% working interest in nine producing and one developed non-producing gross and net wells, and 153 net acres in Wagoner County, OK with one nonproducing shut-in well.  We also own mineral and overriding royalty interests aggregating 7.4% in our CO2-EOR project in the Delhi Field.

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Our developed acreage at June 30, 2009 totaled 5,040 net acres in the Giddings Field, consisting of a 100% working interest in ten gross and net producing wells.

Our developed acreage at June 30, 2008 totaled 3,469 net acres in the Giddings Field, consisting of a 100% working interest in seven gross and net producing wells.

Undeveloped Acreage

Proved undeveloped acreage includes nineteen proved drilling locations and two probable drilling locations in the Giddings Field.

The reduction of six proved locations from the 25 proved locations as of the end of fiscal 2009 includes the addition of one proved drilling location in Giddings offset by the removal of three drilling locations in Giddings and the reclassification of four drilling locations from proved to probable in the Lopez Field in South Texas. Probable undeveloped acreage includes two drilling locations in Giddings, ten drilling locations in Oklahoma and twenty-five drilling locations in the Lopez Field.  Additional drilling locations are associated with our acreage, but require further leasing, step out drilling, and/or an increase in commodity prices before being considered for inclusion.

As of June 30, 2010, we held approximately 55,007 gross and 36,298 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 being redeveloped using CO2-EOR operations within this same acreage, we currently own royalty interests aggregating approximately 7.4%.  Separately, we own a 23.9% reversionary working interest (19% 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.

Our net undeveloped acreage that is subject to expiration over the next three years, if not renewed or extended by option,  (consisting of our acreage in the Giddings Field, Woodford, and South Texas) is approximately 18,122 acres in fiscal 2011, 4,112 acres in fiscal 2012 and 8,505 acres in fiscal 2013.

For more complete information regarding current year activities, including crude oil and natural gas production, refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

Item 3. Legal Proceedings

None.

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, 2010.

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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 NYSE Amex 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 American Stock Exchange was acquired by the NYSE Euronext (NYX) in 2008 and is now known as NYSE Amex.  The following table shows, for each quarter of fiscal year 2010 and 2009, the high and low sales prices for EPM as reported by the NYSE Amex.

NYSE Amex

Holders

As of June 30, 2010, there were 27,061,376 shares of common stock issued and outstanding, held by approximately 3,050 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.

Securities Authorized For Issuance Under Equity Compensation Plans

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(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, 2010, 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, 2010, there were 3,945,320 shares of common stock issuable upon exercise of outstanding stock options, 3,000 options that were exercised and 940,273 shares of common stock issued directly under the 2004 Stock Plan, leaving 611,407 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.  Total warrants outstanding as of June 30, 2010 related to these activities were 159,308 with a weighted average exercise price of $1.87.  Also included were 1,037,500 warrants with a weighted average exercise price of $1.56 issued in connection with employment and or compensation arrangements, including 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 cash bonus, and a warrant to purchase 150,000 shares of common stock in connection with Mr. McDonald’s annual performance incentives, including warrants in lieu of cash bonus.

Recent Sales of Unregistered Securities

None.

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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.