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**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM 10-K**

 

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

 

**For the fiscal year ended June 30, 2010**

 

**o****         TRANSITION REPORTPURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934**

 

**For the transition period from             to             **

 

**Commission File Number 001-32942**

 

**EVOLUTIONPETROLEUM CORPORATION**

(Exactname of registrant as specified in its charter)

 

| **Nevada**                                                     | ** ** | **41-1781991**                    |
|----------------------------------------------------------------|------------|-----------------------------------|
| (State or other jurisdiction of incorporation or organization) |       | (IRS Employer Identification No.) |

 

**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)

 

Securitiesregistered pursuant to Section 12(b) of the Act:

 

| **Title of Each Class** | ** ** | **Name of Each Exchange On Which Registered** |
|----------------------------------------|------------|-----------------------------------------------------------------------------|
| Common Stock, $0.001 par value         |       | NYSE Amex                                                                   |

 

Securitiesregistered pursuant to Section 12(g) of the Act:

 

**None**

(Title of Class)

 

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

 

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

 

Indicateby check mark whether the registrant (1) has filed all reports required tobe filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject tosuch filing requirements for the past 90 days. Yes: x  No: o

 

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

 

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the bestof registrant’s knowledge, in definitive proxy or information statementsincorporated by reference in Part III of this Form 10-K or anyamendment to this Form 10-K. x

 

Indicateby check mark whether the registrant is a large accelerated filer, anaccelerated filer, a non-accelerated filer or a smaller reporting company. Seethe definition of “large accelerated filer”, “accelerated filer” and “smallerreporting company” in Rule 12b-2 of the Exchange Act.

 

 

| Large accelerated filer  o |   | Accelerated filer  o         |
|--------------------------------------|--------|----------------------------------------|
|                                 |   |                                   |
| Non-accelerated filer  o   |   | Smaller reporting company  x |

 

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

 

Theaggregate market value of the voting and non-voting common equity held bynon-affiliates on December 31, 2009, the last business day of theregistrant’s most recently completed second fiscal quarter, based on theclosing price on that date of $4.37 on the NYSE Amex was $63,301,941.

 

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

 

**DOCUMENTS INCORPORATED BY REFERENCE**

 

Portionsof the proxy statement related to the registrant’s 2010 Annual Meeting ofStockholders to be filed within 120 days of the end of the fiscal year coveredby 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**

**TABLE OF CONTENTS**

 
| ** **        | ** ** | ** **                                                                                                          | ** ** | **Page** |
|-------------------|------------|---------------------------------------------------------------------------------------------------------------------|------------|----------|
| **PART I**   |       |                                                                                                                |       |     |
|              |       |                                                                                                                |       |     |
| Item 1.           |       | Business                                                                                                            |       | 6        |
|              |       |                                                                                                                |       |     |
| Item 1A.          |       | Risk Factors                                                                                                        |       | 13       |
|              |       |                                                                                                                |       |     |
| Item 1B.          |       | Unresolved  Staff Comments                                                                                          |       | 21       |
|              |       |                                                                                                                |       |     |
| Item 2.           |       | Properties                                                                                                          |       | 21       |
|              |       |                                                                                                                |       |     |
| Item 3.           |       | Legal Proceedings                                                                                                   |       | 28       |
|              |       |                                                                                                                |       |     |
| Item 4.           |       | Submission  of Matters to a Vote of Security Holders                                                                |       | 28       |
|              |       |                                                                                                                |       |     |
| **PART II**  |       |                                                                                                                |       |     |
|              |       |                                                                                                                |       |     |
| Item 5.           |       | Market for  Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases  of Equity Securities |       | 29       |
|              |       |                                                                                                                |       |     |
| Item 6.           |       | Selected  Financial Data                                                                                            |       | 31       |
|              |       |                                                                                                                |       |     |
| Item 7.           |       | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                         |       | 32       |
|              |       |                                                                                                                |       |     |
| Item 7A.          |       | Quantitative  and Qualitative Disclosures About Market Risk                                                         |       | 40       |
|              |       |                                                                                                                |       |     |
| Item 8.           |       | Financial  Statements and Supplementary Data                                                                        |       | 41       |
|              |       |                                                                                                                |       |     |
| Item 9.           |       | Changes In  and Disagreements with Accountants on Accounting and Financial Disclosure                               |       | 63       |
|              |       |                                                                                                                |       |     |
| Item 9A.          |       | Controls and  Procedures                                                                                            |       | 63       |
|              |       |                                                                                                                |       |     |
| Item 9B.          |       | Other Information                                                                                                   |       | 64       |
|              |       |                                                                                                                |       |     |
| **PART III** |       |                                                                                                                |       |     |
|              |       |                                                                                                                |       |     |
| Item 10.          |       | Directors,  Executive Officers and Corporate Governance                                                             |       | 64       |
|              |       |                                                                                                                |       |     |
| Item 11.          |       | Executive  Compensation                                                                                             |       | 64       |
|              |       |                                                                                                                |       |     |
| Item 12.          |       | Security  Ownership of Certain Beneficial Owners and Management and Related Stockholder  Matters                    |       | 64       |
|              |       |                                                                                                                |       |     |
| Item 13.          |       | Certain  Relationships and Related Transactions, and Director Independence                                          |       | 64       |
|              |       |                                                                                                                |       |     |
| Item 14.          |       | Principal  Accounting Fees and Services                                                                             |       | 64       |
|              |       |                                                                                                                |       |     |
| **PART IV**  |       |                                                                                                                |       |     |
|              |       |                                                                                                                |       |     |
| Item 15.          |       | Exhibits  and Financial Statement Schedules                                                                         |       | 65       |

 

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*This Form 10-Kand the information referenced herein contain forward-looking statements withinthe meaning of the Private Securities Litigations Reform Act of 1995, Section 27Aof the Securities Act of 1933 and Section 21E of the Securities ExchangeAct of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,”“anticipate,” “intend,” “budget,” “forecast,” “predict” and other similarexpressions are intended to identify forward-looking statements. Thesestatements appear in a number of places and include statements regarding ourplans, beliefs or current expectations, including the plans, beliefs andexpectations of our officers and directors.* *Whenconsidering any forward-looking statement, you should keep in mind the riskfactors that could cause our actual results to differ materially from thosecontained in any forward-looking statement. Important factors that could causeactual results to differ materially from those in the forward-lookingstatements herein include the timing and extent of changes in commodity pricesfor oil and natural gas, operating risks and other risk factors as described inour Annual Report on Form 10-K as filed with the Securities and ExchangeCommission. Furthermore, the assumptions that support our forward-lookingstatements are based upon information that is currently available and issubject to change. We specifically disclaim all responsibility to publiclyupdate any information contained in a forward-looking statement or any forward-lookingstatement in its entirety and therefore disclaim any resulting liability forpotentially related damages. All forward-looking statements attributable toEvolution Petroleum Corporation are expressly qualified in their entirety bythis cautionary statement.*

 

*We usethe terms, “EPM,” “Company,” “we,” “us” and “our” to refer to EvolutionPetroleum Corporation.*

 

**GLOSSARY OF SELECTED PETROLEUM TERMS**

 

Thefollowing abbreviations and definitions are terms commonly used in the crudeoil and natural gas industry and throughout this form 10-K:

 

“BBL.”A standard measure of volume for crude oil and liquid petroleum products; onebarrel 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 gasto 1 BBL of oil.

 

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

 

“CO2.” Carbon dioxide, a gasthat can be found in naturally occurring reservoirs, typically associated withancient volcanoes, and also is a major byproduct from manufacturing and powerproduction also utilized in enhanced oil recovery through injection into an oilreservoir.

 

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

 

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

 

“Farmout.” Sale or transfer of all or part of theoperating rights from the working interest owner (the assignor or farm-outparty), to an assignee (the farm-in party) who assumes all or some of the burdenof development, in return for an interest in the property. The assignor mayretain an overriding royalty or any other type of interest. For Federal taxpurposes, a farm-out may be structured as a sale or lease, depending on thespecific rights and carved out interests retained by the assignor.

 

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

 

“HorizontalDrilling” Involves drilling horizontally out from a vertical well bore, therebypotentially increasing the area and reach of the well bore that is in contactwith the reservoir.

 

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“HydraulicFracturing” Involves pumping a fluid with or without particulates into aformation at high pressure, thereby creating fractures in the rock and leavingthe particulates in the fractures to ensure that the fractures remain open,thereby potentially increasing the ability of the reservoir to produce oil orgas.

 

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

 

“MBOE.”One thousand barrels of oil equivalent.

 

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

 

“MMBTU.”One million British thermal units.

 

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

 

“MineralRoyalty Interest.” A royalty interest that is retained by the owner of theminerals underlying a lease.  See “RoyaltyInterest”.

 

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

 

“NGL.”Natural gas liquids, being the combination of ethane, propane, butane andnatural gasolines that can be removed from natural gas through processing,typically through refrigeration plants that utilize low temperatures, orthrough J-T plants that utilize compression, temperature reduction andexpansion to a lower pressure.

 

“NYMEX.”New York Mercantile Exchange.

 

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

 

“OverridingRoyalty Interest or ORRI.” A royalty interest that is created out of theoperating or working interest. Unlike a royalty interest, an overriding royaltyinterest terminates with the operating interest from which it was created orcarved 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 arethose additional reserves that are less certain to be recovered than provedreserves but which, together with proved reserves, are as likely as not to berecovered. *

 

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

 

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

 

“ProvedDeveloped Producing Reserves (“PDP”).” Proved Reserves that have been developedand production has been initiated.

 

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“ProvedReserves.” Estimated quantities of crude oil, natural gas, and natural gasliquids which geological and engineering data demonstrate with reasonablecertainty to be recoverable in future years from known reservoirs underexisting economic, operating methods, and government regulations-prior to thetime at which contracts providing the right to operate expire, unless evidenceindicates that renewal is reasonably certain, regardless of whetherdeterministic or probabilistic methods are used for the estimation. The projectto extract the hydrocarbons must have commenced or the operator must bereasonably certain that it will commence the project within a reasonable time.*

 

“ProvedUndeveloped Reserves (“PUD”).” Reserves that are expected to be recovered fromnew wells on undrilled acreage, or from existing wells where a relatively majorexpenditure is required for recompletion.

 

(i) Reserveson undrilled acreage shall be limited to those directly offsetting developmentspacing areas that are reasonably certain of production when drilled, unlessevidence using reliable technology exists that establishes reasonable certaintyof economic producibility at greater distances.

 

(ii) Undrilledlocations can be classified as having undeveloped reserves only if adevelopment plan has been adopted indicating that they are scheduled to bedrilled within five years, unless the specific circumstances, justify a longertime.

 

(iii) Underno circumstances shall estimates for undeveloped reserves be attributable toany acreage for which an application of fluid injection or other improvedrecovery technique is contemplated, unless such techniques have been provedeffective by actual projects in the same reservoir or an analogous reservoir orby other evidence using reliable technology establishing reasonable certainty.

 

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

 

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

 

“ProductiveWell.” 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 notnecessarily the same as market value. PV-10 does not include estimated future income taxes.  Unless otherwise noted, PV-10 is calculatedusing the pricing scheme as required by the Securities and Exchange Commission(“SEC”).  PV-10 of proved reserves iscalculated the same as the Standardized Measure of Discounted Future Net Cash Flows,except that the Standardized Measure of Discounted Future Net Cash Flows includesfuture estimated income taxes discounted at 10% per annum.  See the definition of Standardized Measure ofDiscounted 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 taxesunless the lessor is a government. In certain circumstances, the royalty ownerbears a proportionate share of the costs of making the natural gas saleable,such as processing, compression and gathering. 2) When a royalty interest iscoterminous with and carved out of an operating or working interest, it is an “OverridingRoyalty Interest,” which also may generically be referred to as a Royalty.

 

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

 

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“StandardizedMeasure.” The Standardized Measure ofDiscounted Future Net Cash Flows is an estimate of future net cash flowsassociated with proved reserves, discounted at 10% per annum.  Future net cash flows is calculated byreducing future net revenues by estimated future income tax expenses anddiscounting at 10% per annum.  The StandardizedMeasure and the PV-10 of proved reserves is calculated in the sameexact fashion, except that the Standardized Measure includes futureestimated income taxes discounted at 10% per annum.  The determination of Standardized Measured isin accordance with accounting standards generally accepted in the United Statesof America (“GAAP”).

 

“WorkingInterest.” The interest in the oil and gas in place which is burdened with thecost 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’sproduction.

 

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

 

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**Item 1. Business**

 

**General**

 

Theterms “we,” “us,” “our,” “our Company” and “EPM” refer to Evolution PetroleumCorporation, a Nevada corporation formerly known as Natural Gas Systems, Inc.(Nevada, “NGS”), and, unless the context indicates otherwise, also includes ourwholly-owned subsidiaries.  Natural GasSystems, Inc. (Delaware, “Old NGS”), a private Delaware corporation formedin September 2003 was subsequently merged into NGS.

 

Ourpetroleum operations began in September of 2003. We acquire known crudeoil and natural gas resources and exploit them through the application ofconventional and specialized technology, with the objective of increasingproduction, ultimate recoveries, or both.

 

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

 

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

 

Ourstock is traded on the NYSE Amex under the ticker symbol “EPM”.  Prior to July 17, 2006, our stock wasquoted on the OTC Bulletin Board under the symbol “NGSY.OB”.  Prior to May 26, 2004, our stock wasquoted on the OTC Bulletin Board under the symbol “RLYI.OB”.

 

AtJune 30, 2010, we had ten full-time employees, not including contractpersonnel and outsourced service providers.

 

**Corporate History of Reverse Merger**

 

RealityInteractive, Inc. (“Reality”), a Nevada corporation that previously tradedon the OTC Bulletin Board under the symbol RLYI.OB and the predecessor ofEvolution Petroleum Corporation, was incorporated on May 24, 1994, for thepurpose of developing technology-based knowledge solutions for the industrialmarketplace.  On April 30, 1999,Reality ceased business operations, sold substantially all of its assets andterminated all of its employees. Subsequent to ceasing operations, Reality explored other potentialbusiness opportunities to acquire or merge with another entity while continuingto file reports with the Securities and Exchange Commission (“SEC”).

 

OnMay 26, 2004, Old NGS merged into a wholly owned subsidiary ofReality.  Reality was thereafter renamedNatural Gas Systems, Inc. (“NGS”) and adopted a June 30 fiscal yearend.  As part of the merger, the officersand directors of Reality resigned, the officers and directors of Old NGS becamethe officers and directors of NGS, and the crude oil and natural gas business ofOld NGS became that of NGS.  Concurrentlywith the listing of NGS shares on the NYSE Amex (formerly the American StockExchange) during July 2006, NGS was renamed Evolution PetroleumCorporation to avoid confusion with similar names traded on the NYSE Amex andto better reflect our business model.

 

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

 

**Business Strategy**

 

We are a petroleum companyengaged primarily in the acquisition, exploitation and development ofproperties for the production of crude oil and natural gas, onshore in the UnitedStates. We acquire known, underdeveloped oil and natural gas resources andexploit them through the application of capital, sound engineering and modern technologyto increase production, ultimate recoveries, or both.

 

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

 

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

 

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Theassets we exploit currently fit into three types of project opportunities:

 

·                  Enhanced Oil Recovery (EOR),

 

·                  Bypassed Primary Resources, and

 

·                  Unconventional Shale Gas Development.

 

Ouractive projects in these categories are:

 

***Delhi Field CO******2****** EOR (EnhancedOil Recovery) Project***

 

Ourinterests in the Delhi Holt Bryant Unit in the Delhi Field located in NortheastLouisiana are currently our most significant asset.  The Unit is currently being redeveloped as anEOR project utilizing CO2 technology by a subsidiary of DenburyResources Inc. as Operator.

 

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

 

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

 

DuringFiscal 2010:

 

·      Ourindependent 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 aPV-10 of $224.5 million *

 

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

 

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*PV-10 of proved reserves is a non-GAAPmeasure, 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*ofthis Form 10-K.  Probable reservesare not recognized by GAAP, and therefore the PV-10 of probable reserves cannot be reconciled to a GAAP measure.

 

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

 

·      On November 12,2009 CO2 injection commenced.

 

Webelieve that the Delhi Holt Bryant Unit is a strong candidate for a CO2-EOR project due to itsfavorable rock characteristics, large unproven reserves remaining in place, lowcost of drilling due to a relatively shallow depth and relatively closelocation to naturally occurring CO2 reservesapproximately 100 miles east of the Delhi Field.  We base our belief on (i) our internalanalyses of CO2 pilot tests successfully completed in theDelhi Holt Bryant Unit by a prior field operator, (ii) our analysis offavorable analogous comparisons to successful full scale projects in the sameor similar geological formation, (iii) a competitive offering process,wherein we solicited multiple major participants with CO2-EOR expertise, fundingand operating abilities, leading to confidential competitive offers made to usin writing, (iv) our qualitative assessment that the competitive offerswere based on the CO2-EOR potentialof the Unit and not on the relatively minor associated proved reserves existingat that time, (v) the buyer’s willingness to commit a portion of itsproved CO2 reserves and a $100 million minimum futureinvestment, subject to penalties for non-performance, in a CO2 project in the Unit, (vi) the early oilproduction response following the initiation of CO2 injection,and (vii) D&M’s reserve assignments.

 

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Accordingto published reports and field records, the Delhi Field was discovered in themid-1940’s and was extensively developed by various operators including the SunOil and Murphy Oil companies through the drilling and completion ofapproximately 450 wells, most within the first few years after discovery.  According to D&M, an independentreservoir engineering firm experienced in CO2-EOR projects who is engaged by Denbury and us toreview the project, the Delhi Field has produced approximately 192 millionbarrels of crude oil and substantial amounts of natural gas to date. Much ofthe natural gas production was processed to remove natural gas liquids andre-injected for pressure maintenance. Beginning in the late 1950’s, the fieldwas unitized to conduct a pressure maintenance project through the injection ofwater into the producing reservoir in down dip injection wells (unitization isthe process of combining multiple leases into a single ownership entity inorder to simplify operations and equitably distribute royalties when commonoperations are conducted over multiple leases). Drilling operations resulted inprimarily 40-acre spacing across the unit’s 13,636 acres. A few wells weredrilled below the targeted Tuscaloosa and Paluxy formations. The waterinjection pressure maintenance operations did not utilize a more traditionaland effective five spot flood pattern water flood that generally results in amore complete reservoir sweep and oil recovery.

 

Atthe 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 exceptingthe Mengel Unit), for approximately $2.8 million, including the assumption of aplugging and abandonment reclamation bond. All but 43 wells in Richland, Franklin and Madison Parishes, Louisianahad been plugged and abandoned.  At thattime, production averaged approximately 18 BOPD with no natural gas being solddue to a lack of natural gas processing and transportation facilities.  The best producing well was immediately lostduring a periodic sand wash work-over when water from a lower reservoir brokethrough along the casing exterior and into the producing reservoir.

 

InOctober of 2003, we applied an unproven lateral re-entry technology thatresulted in no increase in production. In December 2003, we initiated a conventional development programbased on re-completion of wells to other reservoirs and restoring non-producingwells to producing status.  During 2004,we refurbished a gas injection line, converting it to a gas gathering and salesline, and placed a gas processing plant in the field to begin natural gasproduction in July of 2004.  During2005, we began a five well development drilling program aimed at reachingmostly proved undeveloped reserves left in primary “attic” positions.  The culmination of these activities causedproduction to increase from 18 BOPD to a monthly average rate of 145 BOEPDduring our peak production month in late 2005, at a capital cost of about $2.5million.

 

Concurrentwith these activities, we completed internal studies indicating that thereservoirs in the Delhi Holt Bryant Unit, the dominant oil producingreservoirs, had substantial remaining recoverable oil in place.  Based on positive CO2 pilots conducted by Sun Oil in 1985, andfavorable rock characteristics shown in multiple cores previously takenthroughout the Delhi Field, we began discussions in late 2004 with potential industrypartners skilled in CO2-EOR recoverymethods,.

 

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

 

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

 

·       Wereceived $50 million in cash (pre-tax) to redeploy to other projects and repayall of our then outstanding debt.

 

·       Weretained significant participating interests through a reversionary workinginterest equal to 23.9% (25% of our original working interest delivered toDenbury), 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 royaltyinterests aggregating 7.4% would substantially exceed the $50 million cashcomponent of the Delhi Farmout, subject to future oil prices, operatingexpenses, anticipated EOR performance and project completion by the Operator.

 

·       TheOperator committed to install a CO2-EOR project in the Holt Bryant Unit and expend aminimum 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 ourinterests in the project are borne by the Operator prior to payout.

 

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·      The Operatoris the dominant CO2-EOR operatoron the Gulf Coast and owns naturally occurring proved CO2 reserves that we believe to be sufficient tomeet the needs of the Delhi project and which have been dedicated to the Delhiproject.

 

·      Ourreversionary working interest in the CO2-EOR project is based on a defined $200 millionthreshold, subject only to expansion of the project through acquisitions, andour reversionary working interest occurs when cumulative project revenues lessdirect operating costs in the field reach the threshold.  Direct operating costs include an establishedcost for each purchased Mcf of CO2  equalto 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 purchasesduring the initial years of a CO2-EOR project, and are gradually displaced by cheaperrecycling costs (currently about $0.15 per Mcf) later in the project.

 

***Bypassed Primary ResourceProjects***

 

Followingthe closing of our Delhi Farmout in June 2006, we began the process ofidentifying new conventional development and/or redevelopment projectstargeting primary petroleum resources previously bypassed by industry inhistorically productive formations, generally due to inadequate technology orcommodity prices.  In selecting ourcandidates:

 

·                  We leveraged our staff’s extensiveexperience, gained over many years while employed at various large independentoil and gas companies in the pioneering of horizontal drilling practicesadapted to further develop and produce the Austin Chalk, Georgetown and Budaformations in the Giddings Field in central Texas;

 

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

 

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

 

·                  We soughtexposure to both crude oil and natural gas opportunities.

 

Giddings Field

 

Webegan leasing activities in the Giddings Field in December 2006 andacquired 20,899 and 19,147 gross and net acres, respectively, of which 5,027net acres are developed and 7,255 net acres remain as net undeveloped andassociated with our proved and probable drilling locations as of June 30,2010.  In late calendar 2007, weinitiated a redevelopment drilling program in the Giddings Field targeting theAustin 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 thatwas drilled and two wells that were restored to production throughworkovers.  Total net proved reservesassigned to our properties in the Giddings Field by our independent reservoirengineer, 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 Giddingsproduction during the year of 119.2 MBOE. Our total investment of $26.7 million to date has generated cash flowsfrom 286.3 MBOE of total net production and our proved PV-10 at June 30,2010 of $41.3 million.  In addition, wehave two probable drilling locations and probable undeveloped reservesassociated with proved drilling locations totaling 978 MBOE with a PV-10 of$11.7 million.  See “Estimated Oil and Natural Gas Reserves andEstimated Future Net Revenues” under *Item 2. Properties*of this Form 10-K for areconciliation of PV-10 to the Standardized Measure.

 

OnJuly 16, 2010, we entered into a joint development agreement (“JDA”) withan industry partner.  The JDA providesthat we operate the drilling of two firm commitment wells on our proved andprobable locations in the Giddings Field, with the potential to add up to threeoption wells as elected by our partner. Under the terms of the JDA, we retain a 10% carried working interest inrecognition of our costs to date, a 10% cost bearing working interest for ourcash participation, and a 22.5% back-in working interest on each well drilledon our partner’s 80% working interest following a simple 2 well basket payout andwell-by-well simple pay-out on subsequent wells (bringing our after-payoutworking 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)

 

Weacquired 1,721 net acres through leasing in our Neptune Oil Project in theLopez Field in South Texas.  We believethat previous drilling and production in this field by another operatorestablished reserves potential on infill spacing.  As of June 30, 2009, our independentreservoir engineer recognized four proved well locations with 47.6 MBO ofproved undeveloped reserves on approximately 40 net acres of our holdings.  We began field testing late in the secondfiscal quarter of 2010 with the drilling of two infill producers and there-entry of two previously abandoned wells for water injection.  Due to delays in obtaining electric powerservice and mechanical problems with the re-entered injection wells, we werenot able to begin effective testing until the fourth quarter of 2010, thus weelected to reclassify the proved reserves as probable as of June 30,2010.  Our independent engineer, W.D. VonGonten & Associates, has concurred with this position and has assigned21 additional probable drilling locations. Should further testing warrant full development, we have identified upto 92 additional prospective infill drilling locations in the balance of ourleasehold.

 

Tullos Field

 

OnMarch 3, 2008, we completed the sale of our properties in the TullosField, located in LaSalle and Winn Parishes in Louisiana, for gross cashproceeds of approximately $4.6 million.

 

Producingabout 100 gross and 79 net barrels of oil production per day from over 150producing wells at the time of our divestiture, the Tullos Field required adisproportionate amount of staff effort and vendor services, thereby adverselyaffecting our ability to develop other projects utilizing our expertise andworking capital, particularly in the Giddings Field. The field producedlarge volumes of water associated with the oil production after being downsizedto only two acre spacing. Furthermore, we believe that the potential upside inthe Tullos Field was substantially less than that offered in our otherprojects, where the cash proceeds from the sale of our properties in the TullosField could be expected to yield a much higher return.  Last, we hadcompleted the testing of our oil-on-water completion technology utilizing theone well we drilled in the Tullos Field and determined that the potential ofthat technology could be best realized in other fields with greater potential.

 

***Unconventional Gas Resources***

 

WoodfordShale Projects in Oklahoma

 

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

 

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

 

·                  Low reserve risk.

 

·                  Repeatable development performance across asubstantial acreage position.

 

·                  Acceptable profitability at $5 NYMEX naturalgas prices.

 

Theseparameters led us to the shallower sections of the Woodford Shale in EasternOklahoma.

 

*Wagoner County*

 

The Woodford Shale formationin 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 todrill commercial wells extensively in the Woodford to date in a much shallowerportion of the formation. During 2010, we continued our deliberate testingprogram with wells in three of our four acreage blocks, tests of the Woodford andCaney formations, and tests of three types of completions including two typesof fracs.  These tests indicated that:

 

·                  The Caney Shaleis an incremental target that may add long term value as a secondary target tothe Woodford.

 

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

 

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

 

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

 

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

 

*Haskell County*

 

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

 

**M****arkets and Customers**

 

Wemarket our production to third parties in a manner consistent with industrypractices.

 

Inthe U.S. market where we operate, crude oil and natural gas liquids are readilytransportable and marketable.  Since March 2005and into 2008, we sold all of our operated crude oil production to PlainsMarketing LP, a crude oil purchaser, at competitive field prices.  In January of 2008, we also beganselling 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 OilLLC are under a normal (thirty day “evergreen”) sales contracts.  During our fiscal 2010 year we amended ourcontracts to sell essentially all of our crude oil from our operated propertiesto Enterprise Crude Oil LLC.  We believethat other crude oil purchasers are readily available.

 

Wesell our natural gas and natural gas liquids from our properties in theGiddings Field, under the terms of normal evergreen sales contracts atcompetitive prices with DCP Midstream, LP, ETC Texas Pipeline, LTD., and Copano Field Services/Upper GulfCoast, L.P.  Gas sold to DCP and ETC isprocessed for removal of natural gas liquids, and we receive the proceeds fromthe sale of the NGL product less a fee and certain operating expenses. Theprice of natural gas sold to Copano is adjusted upward for the high BTUcontent.  We have no other businessrelationships with our crude oil, natural gas or natural gas liquidspurchasers.

 

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

 
| ** **                                   | ** ** | **Year Ended June 30,** | ** ** |
|----------------------------------------------|------------|----------------------------------------|------------|
| **Customer**                                 | ** ** | **2010**                               | ** ** | **2009** | ** ** | **2008** | ** ** |
|                                         |       |                                   |       |   |   |   |   |
| Plains Marketing L.P.                        |       | 12                                     | %          | 40 | % | 67 | % |
| Enterprise Crude Oil LLC                     |       | 31                                     | %          | 5 | % | — |   |
| ETC Texas Pipeline, LTD.                |       | 19                                     | %          | 36 | % | 26 | % |
| DCP Midstream, LP                            |       | 15                                     | %          | 16 | % | — |   |
| Copano Field Services/Upper Gulf Coast, L.P. |       | 23                                     | %          | 2 | % | — |   |

 

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

 

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**MarketConditions**

 

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

 

Overthe 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 perbarrel. Worldwide factors such as geopolitical, macroeconomic, supply anddemand, refining capacity, petrochemical production and derivatives trading,among others, influence prices for crude oil. Local factors also influence prices for crude oil and include qualitydifferences, regulation and transportation issues unique to certain producingregions and reservoirs.

 

Alsoover the past 25 years, domestic natural gas prices have been extremelyvolatile, ranging from $1 to $15 per MMBTU. The spot market for natural gas,changes in supply and demand, derivatives trading, pipeline availability, BTU contentof the natural gas and weather patterns, among others, cause natural gas pricesto be subject to significant fluctuations. Due to the practical difficulties in transporting natural gas, local andregional factors tend to influence product prices more for natural gas than forcrude oil.

 

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

 

**Competition**

 

Theoil and natural gas industry is highly competitive for prospects, acreage andcapital.  Our competitors include major integratedcrude oil and natural gas companies and numerous independent crude oil andnatural gas companies, individuals and drilling and income programs. Many ofour competitors are large, well-established companies with substantially largeroperating staffs and greater capital resources than us. Competitors arenational, regional or local in scope and compete on the basis of financialresources, technical prowess or local knowledge. The principal competitivefactors in our industry are expertise in given geographical and geologicalareas and the abilities to efficiently conduct operations, achievetechnological advantages, identify and acquire economically producible reservesand obtain affordable capital.

 

**Government Regulation**

 

Numerousfederal and state laws and regulations govern the oil and gas industry. Theselaws and regulations are often changed in response to changes in the politicalor economic environment. Compliance with this evolving regulatory burden isoften difficult and costly, and substantial penalties may be incurred fornoncompliance.  We believe that we are insubstantial compliance with all laws and regulations applicable to our operationsand that continued compliance with existing requirements will not have amaterial adverse impact on us. The future annual capital cost of complying withthe regulations applicable to our operations is uncertain and will be governedby several factors, including future changes to regulatory requirements whichare unpredictable. However, we do not currently anticipate that futurecompliance with existing laws and regulations will have a materially adverseeffect on our consolidated financial position or results of operations.

 

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

 

**Insurance**

 

Wemaintain insurance on our properties and operations for risks and in amountscustomary in the industry.  Suchinsurance includes general liability, excess liability, control of well,operators extra expense, casualty, fraud and directors & officer’sliability coverage.  Not all losses areinsured, and we retain certain risks of loss through deductibles, limits andself-retentions.  We do not carry lostprofits coverage.

 

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**Item 1A. Risk Factors**

 

Risks related to the Company

 

**Operating results from oil and natural gas production maydecline.**

 

Inthe near term, our production is totally dependent on ten wellbores at ourGiddings Field and our 7.4% royalty interests in EOR production that began atour Delhi Field in March 2010.  Thetargeted reservoirs in the Giddings Field typically experience flush initialproduction, followed by steep harmonic decline rates that steadily flatten tomuch shallower decline rates.  AlthoughEOR production from proved reserves at Delhi is expected to grow over time,without further development activities in the Giddings Field, Delhi or ourother properties, or without acquisitions of producing properties, our netproduction of oil and natural gas could decline significantly over time, whichcould have a material adverse affect on our financial condition.

 

**The types of resources we focus on have substantialoperational risks.**

 

Ourbusiness plan focuses on the acquisition and development of known resources inpartially depleted reservoirs, naturally fractured or low permeabilityreservoirs, or relatively shallow reservoirs. Shallower reservoirs usually havelower pressure, which translates into fewer natural gas volumes in place; lowpermeability reservoirs require more wells and substantial stimulation fordevelopment of commercial production; naturally fractured reservoirs requirepenetration of sufficient undepleted fractures to establish commercialproduction; and depleted reservoirs require successful application of newertechnology to unlock incremental reserves.

 

OurCO2-EOR project inthe Delhi Field, operated by a subsidiary of Denbury Resources Inc., requiressignificant amounts of CO2 reserves, development capitaland technical expertise, the sources of which have been committed by theOperator.  Although initial CO2 injection began at Delhi in November 2009and an initial oil production response began in March 2010, substantialcapital remains to be invested to fully develop the EOR project and furtherincrease production.  The Operator’sfailure to manage these and other technical, strategic, financial andlogistical risks may render ultimate enhanced recoveries from the planned CO2-EOR project to fall shortof our expectations in volume and or timing. Such occurrences would have amaterial adverse effect on the Company and its results of operations.

 

Theexisting well bores we are re-entering in the Giddings Field were originallydrilled as far back as the 1980’s.  Assuch, they contain older casing that could be more subject to failure, or thewell files, if available, may be incomplete or incorrect.  Such problems can result in the complete lossof a well or a much higher drilling and completion cost.  Our proved undeveloped locations in theGiddings Field are direct offsets to current or previously producing wells, andthere may be unusually long fractures that will connect our well to anotherproducing or depleted well, thus reducing the potential recovery, increasingour drilling costs, or delaying production due to recovery of drilling fluidlost during drilling into the depleted fractures.

 

Ourother projects in Oklahoma and Texas, although believed to have oil and/or gasresources, have yet to exhibit significant proved reserves.  Therefore, their economic outcome isuncertain.

 

Ourprojects generally require that we acquire new leases in and around establishedfields or other known resources, and drill and complete wells, some of whichmay be horizontal, as well as negotiate the purchase of existing well bores andproduction equipment or install our proprietary artificial lift technology thathas yet to be universally proven.  Leasesmay not be available and required oil field services may not be obtainable onthe desired schedule or at the expected costs. While the projected drilling results may be considered to be low tomoderate in risk, there is no assurance as to what productive results may beobtained, if any.

 

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**Our limited operating history and limited production makes itdifficult to predict future results and increases the risk of an investment inour company.**

 

Wecommenced our crude oil and natural gas operations in late 2003 and have alimited operating history, particularly in our currently producing fields.  All of our current production is the resultof recent operational activities, thus our future production retainssubstantial variability.  Therefore, weface all the risks common to companies in their early stage of development,including uncertainty of funding sources, high initial expenditure levels anduncertain revenue streams, an unproven business model, and difficulties inmanaging growth.  Our prospects must beconsidered in light of the risks, expenses, delays and difficulties frequentlyencountered in establishing a new business. Any forward-looking statements inthis report do not reflect any possible effects on us from the outcome of thesetypes of uncertainty.  Prior to the DelhiFarmout, we had incurred significant losses since the inception of our oil andnatural gas operations and we have since resumed incurring losses.  We cannot assure future profitability orsuccess.  While members of our managementteam have previously carried out or been involved with acquisition andproduction activities in the crude oil and natural gas industry while employedby us and other companies, we cannot assure you that our intended acquisitiontargets and development plans will lead to the successful development of crudeoil and natural gas production or additional revenue.

 

**The loss of a large single purchaser of our oil and naturalgas 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 thecompetition for our oil and natural gas production, which in turn couldnegatively impact the prices we receive.

 

**We may be unable to continue licensing from third parties thetechnologies that we use in our business operations.**

 

Asis customary in the crude oil and natural gas industry, we utilize a variety ofwidely available technologies in the crude oil and natural gas development anddrilling process.  We do not have anypatents or copyrights for the technology we currently utilize, but a patentapplication is pending on one of our technologies. We generally license orpurchase services from the holders of such technology, or outsource thetechnology integral to our business from third parties.  Our commercial success will depend in part onthese sources of technology and assumes that such sources will not infringe onthe proprietary rights of others. We cannot be certain whether any third-partypatents will require us to utilize or develop alternative technology or toalter our business plan, obtain additional licenses, or cease activities thatinfringe on third-parties’ intellectual property rights. Our inability toacquire any third-party licenses, or to integrate the related third-partyproducts into our business plan, could result in delays in development unlessand until equivalent products can be identified, licensed, and integrated.Existing or future licenses may not continue to be available to us oncommercially reasonable terms or at all. Litigation, which could result insubstantial cost to us, may be necessary to enforce any patents licensed to usor to determine the scope and validity of third-party obligations.

 

**Ourproprietary technology may not be awarded patent protection and may not resultin a commercial service or product.**

 

Wehave developed and field tested our artificial lift technology that we hope tocommercialize and generate material value. Our success in commercializing thetechnology will depend upon additional positive field tests, acceptance byindustry and our ability to defend the technology from competitors throughconfidentiality and/or patent protection. Although our patent is pending, there is no assurance that a patent willbe awarded or that we will have the ability to exercise patent defense againstcompetitors.

 

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**Regulatory and accounting requirements may requiresubstantial reductions in reporting proven reserves.**

 

Wereview on a periodic basis the carrying value of our crude oil and natural gasproperties under the applicable rules of the various regulatory agencies,including the SEC. Under the full cost method of accounting that we use, theafter-tax carrying value of our oil and natural gas properties may not exceedthe present value of estimated future net after-tax cash flows from provedreserves, discounted at 10%. Application of this “ceiling” test requirespricing future revenues at the previous 12-month average beginning-of-monthprice and requires a write down of the carrying value for accounting purposesif the ceiling is exceeded. We may in the future be required to write down thecarrying value of our crude oil and natural gas properties when crude oil andnatural gas prices are depressed or unusually volatile. Whether we will berequired to take such a charge will depend in part on the prices for crude oiland natural gas during the previous period and the effect of reserve additionsor revisions and capital expenditures during such period. If a write down isrequired, it would result in a current charge to our earnings but would notimpact our current cash flow from operating activities.

 

**Ourprofitability is highly dependent on the prices of crude oil, natural gas, andnatural gas liquids, which have historically been very volatile.**

 

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

 

**We may be unable to acquire and develop the additional oiland natural gas reserves that are required in order to sustain our businessoperations.**

 

Ingeneral, the volumes of production from crude oil and natural gas propertiesdecline as reserves are depleted, with the rate of decline depending onreservoir characteristics. Except to the extent we acquire propertiescontaining proved reserves or conduct successful development activities, orboth, our proved reserves will decline. Our future crude oil and natural gasproduction is, therefore, highly dependent upon our level of success in findingor acquiring additional reserves. Due to decline characteristics of ourGiddings wells, our near-term future growth and financial condition aredependent 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 mayadversely affect our results of operations.**

 

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

 

Wemay not be the operator of some of our wells in the future, and we are not theoperator of our high value assets in the Delhi Field.  As a result, our operating risks for thosewells and our ability to influence the operations for these wells will be lesssubject to our control. Operators of these wells may act in ways that are notin our best interests. If this occurs, the development of, and production ofcrude 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.**

 

Wedepend 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 materialadverse affect on our operations.  Inparticular, our future success is dependent upon Robert S. Herlin, ourPresident and Chief Executive Officer, Sterling H. McDonald, our ChiefFinancial Officer, and Daryl V. Mazzanti, our Vice-President of Operations, forsourcing, evaluating and closing deals, capital raising, and oversight ofdevelopment 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 couldadversely affect our business.**

 

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

 

**We may have difficulty managing future growth and the relateddemands on our resources and may have difficulty in achieving future growth.**

 

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

 

·                    our ability toidentify and acquire new development or acquisition projects;

·                    our ability todevelop existing properties;

·                    our ability tocontinue to retain and attract skilled personnel;

·                    the results ofour development program and acquisition efforts;

·                    the success ofour technologies;

·                    hydrocarbonprices;

·                    drilling,completion and equipment prices;

·                    our ability tosuccessfully integrate new properties;

·                    our access tocapital; and

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

 

Wecan not assure you that we will be able to successfully grow or manage any suchgrowth.

 

**We face strong competition from larger oil and gas companies.**

 

Ourcompetitors include major integrated crude oil and natural gas companies andnumerous independent crude oil and natural gas companies, individuals anddrilling and income programs. Many of our competitors are large,well-established companies with substantially larger operating staffs andgreater capital resources than we have. We may not be able to successfullyconduct our operations, evaluate and select suitable properties and consummatetransactions in this highly competitive environment. Specifically, these largercompetitors may be able to pay more for development projects and productivecrude oil and natural gas properties and may be able to define, evaluate, bidfor and purchase a greater number of properties and prospects than ourfinancial or human resources permit. In addition, such companies may be able toexpend greater resources on hiring contract service providers, obtainingoilfield equipment and acquiring the existing and changing technologies that webelieve are and will be increasingly important to attaining success in ourindustry.

 

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**The crude oil and natural gas reserves included in thisreport are only estimates and may prove to be inaccurate.**

 

Thereare numerous uncertainties inherent in estimating crude oil and natural gasreserves and their estimated values. The reserves discussed in this report areonly estimates that may prove to be inaccurate because of these uncertainties.Reservoir engineering is a subjective and inexact process of estimatingunderground accumulations of crude oil and natural gas that cannot be measuredin an exact manner. Estimates of economically recoverable crude oil and naturalgas reserves depend upon a number of variable factors, such as historical productionfrom the area compared with production from other producing areas andassumptions concerning effects of regulations by governmental agencies, futurecrude oil and natural gas product prices, future operating costs, severance andexcise taxes, development costs and work-over and remedial costs. Some or allof these assumptions may in fact vary considerably from actual results. Forthese reasons, estimates of the economically recoverable quantities of crudeoil and natural gas attributable to any particular group of properties,classifications of such reserves based on risk of recovery, and estimates ofthe future net cash flows expected there from prepared by different engineersor by the same engineers but at different times, may vary substantially. Accordingly,reserve estimates may be subject to downward or upward adjustment. Actualproduction, revenue and expenditures with respect to our reserves will likelyvary from estimates, and such variances may be material. The informationregarding discounted future net cash flows included in this report should notbe considered as the current market value of the estimated crude oil andnatural gas reserves attributable to our properties. The estimated discountedfuture net cash flows from proved reserves are based on the previous 12-monthaverage 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. Actualfuture net cash flows also will be affected by factors such as the amount andtiming of actual production, supply and demand for crude oil and natural gas,increases or decreases in consumption, and changes in governmental regulationsor taxation. In addition, the 10% discount factor, which is required by the SECto be used in calculating discounted future net cash flows for reportingpurposes, is not necessarily the most appropriate discount factor based oninterest rates in effect from time to time and risks associated with us or thecrude 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 weproduce without the assistance of third parties.**

 

Themarketability of the crude oil and natural gas that we produce depends upon theproximity of our reserves to, and the capacity of, facilities and third-partyservices, including crude oil and natural gas gathering systems, pipelines,trucking or terminal facilities, and processing facilities necessary to makethe products marketable for end use. The unavailability or lack of capacity ofsuch services and facilities could result in the shut-in of producing wells orthe delay or discontinuance of development plans for properties. A shut-in ordelay or discontinuance could adversely affect our financial condition. Inaddition, federal and state regulation of crude oil and natural gas productionand transportation could affect our ability to produce and market our crude oiland natural gas on a profitable basis.

 

Risks Relating to the Oil and Gas Industry

 

**Crude oil and natural gas development, re-completion of wellsfrom one reservoir to another reservoir, restoring wells to production anddrilling and completing new wells are speculative activities and involvenumerous risks and substantial and uncertain costs.**

 

Ourgrowth will be materially dependent upon the success of our future developmentprogram.  Drilling for crude oil andnatural gas and re-working existing wells involve numerous risks, including therisk that no commercially productive crude oil or natural gas reservoirs willbe encountered.  The cost of drilling,completing and operating wells is substantial and uncertain, and drillingoperations may be curtailed, delayed or cancelled as a result of a variety offactors beyond our control, including:

 

·                    unexpecteddrilling conditions;

·                    pressurefluctuations or irregularities in formations;

·                    equipmentfailures or accidents;

·                    inability toobtain leases on economic terms, where applicable;

·                    adverse weatherconditions;

·                    compliance withgovernmental requirements; and

·                    shortages ordelays in the availability of drilling rigs or crews and the delivery ofequipment.

 

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Drillingor re-working is a highly speculative activity. Even when fully and correctly utilized, modern well completiontechniques such as hydraulic fracturing , horizontal drilling or CO2 or other injectants do not guarantee that wewill find and produce crude oil and/or natural gas in our wells in economicquantities.  Our future drillingactivities may not be successful and, if unsuccessful, such failure would havean adverse affect on our future results of operations and financialcondition.  We cannot assure you that ouroverall drilling success rate or our drilling success rate for activitieswithin a particular geographic area will not decline.  We may identify and develop prospects througha number of methods, some of which do not include horizontal drilling,hydraulic fracturing or tertiary injectants, and some of which may beunproven.  The drilling and results forthese prospects may be particularly uncertain. Our drilling schedule and costs may vary from our capital budget.  The final determination with respect to thedrilling of any scheduled or budgeted prospects will be dependent on a numberof factors, including, but not limited to:

 

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

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

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

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

·                    our financialresources and results;

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

·                    the success ofour drilling technology.

 

Wecannot assure you that these projects can be successfully developed or that thewells discussed will, if drilled, encounter reservoirs of commercially productivecrude oil or natural gas.  There arenumerous uncertainties in estimating quantities of proved reserves, includingmany factors beyond our control.

 

**Crude oil and natural gas prices are highly volatile ingeneral and low prices will negatively affect our financial results.**

 

Ourrevenues, operating results, profitability, cash flow, future rate of growthand ability to borrow funds or obtain additional capital, as well as thecarrying value of our properties, are substantially dependent upon prevailingprices of crude oil and natural gas. Lower crude oil and natural gas prices also may reduce the amount ofcrude oil and natural gas that we can produce economically.  Historically, the markets for crude oil andnatural gas have been very volatile, and such markets are likely to continue tobe volatile in the future.  Prices forcrude oil and natural gas are subject to wide fluctuation in response torelatively minor changes in the supply of and demand for crude oil and naturalgas, market uncertainty and a variety of additional factors that are beyond ourcontrol, including:

 

·                    worldwide anddomestic supplies of crude oil, natural gas and NGLs;

·                    the level ofconsumer product demand;

·                    weatherconditions;

·                    domestic andforeign governmental regulations;

·                    the price andavailability of alternative fuels;

·                    politicalinstability or armed conflict in oil-producing regions;

·                    the price andlevel of foreign imports; and

·                    overalldomestic and global economic conditions.

 

Itis extremely difficult to predict future crude oil and natural gas pricemovements with any certainty.  Declinesin crude oil and natural gas prices may materially adversely affect ourfinancial condition, liquidity, ability to finance planned capital expendituresand results of operations.  Further,crude oil and natural gas prices do not move in tandem.  Because approximately 83% of our provedreserves at June 30, 2010 are crude oil reserves and 8% are natural gasliquids 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 theavailability of such services may be inadequate to meet our needs.**

 

Ourbusiness plan to develop or redevelop crude oil and natural gas resourcesrequires third party oilfield service vendors and various materials such assteel 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 andmaterials increase, it may render certain or all of our projects uneconomic, ascompared to the earlier prices we may have assumed when deciding to redevelopnewly purchased or existing properties. Further adverse economic outcomes may result from the long lead timesoften necessary to execute and complete our redevelop plans.

 

**Government regulation and liability for environmental mattersmay adversely affect our business and results of operations.**

 

Crudeoil and natural gas operations are subject to extensive federal, state andlocal government regulations, which may be changed from time to time. Matterssubject 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, regulatoryagencies have imposed price controls and limitations on production byrestricting the rate of flow of crude oil and natural gas wells below actualproduction capacity in order to conserve supplies of crude oil and natural gas.There are federal, state and local laws and regulations primarily relating toprotection of human health and the environment applicable to the development,production, handling, storage, transportation and disposal of crude oil andnatural gas, by-products thereof and other substances and materials produced orused in connection with crude oil and natural gas operations. In addition, wemay inherit liability for environmental damages, whether actual or not, causedby previous owners of property we purchase or lease or nearby properties. As aresult, we may incur substantial liabilities to third parties or governmentalentities. We are also subject to changing and extensive tax laws, the effectsof which cannot be predicted. The implementation of new, or the modification ofexisting, laws or regulations could have a material adverse affect on us, suchas diminishing the demand for our products through legislative enactment ofproposed new penalties, fines and/or taxes on carbon that could have the effectof raising prices to the end user.

 

For example, currentlyproposed federal legislation, that, if adopted, could adversely affect ourbusiness, financial condition and results of operations, includes thefollowing:

 

·                  *ClimateChange. *On June 26, 2009, theU.S. House of Representatives passed the “American Clean Energy and SecurityAct of 2009,” or “ACESA,” which would establish an economy-wide cap-and-tradeprogram to reduce U.S. emissions of greenhouse gases, including carbon dioxideand methane. ACESA would require a 17 percent reduction in greenhouse gasemissions from 2005 levels by 2020 and just over an 80 percent reduction ofsuch emissions by 2050. Under this legislation, the EPA would issue a cappedand steadily declining number of tradable emissions allowances to certain majorsources of greenhouse gas emissions so that such sources could continue to emitgreenhouse gases into the atmosphere. These allowances would be expected toescalate significantly in cost over time. The net effect of ACESA would be toimpose 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 reducegreenhouse emissions through an emission allowance system. At the state level,more than one-third of the states, either individually or through multi-stateregional initiatives, already have begun implementing legal measures to reduceemissions of greenhouse gases. The U.S. Environmental Protection Agency (EPA)has also taken recent action related to greenhouse gasses. Based on recentdevelopments, the EPA now purports to have a basis to begin regulatingemissions of greenhouse gasses under existing provisions of the federal CleanAir Act.   It is not possible at thistime to predict whether or when the U.S. Senate may act on climate-changelegislation, however any future federal laws or implementing regulations thatmay be adopted to address greenhouse gas emissions could require us to incurincreased operating costs and could adversely affect demand for the oil andnatural gas that we produce.

 

·                  *Taxes. *President Obama’s FiscalYear 2011 Budget Proposal includes provisions that would, if enacted, repeal ofthe percentage depletion allowance for oil and natural gas properties,eliminate the immediate deduction for intangible drilling and development costsand eliminating the deduction from income for domestic production activitiesrelating to oil and natural-gas exploration and development, and

 

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·                  *HydraulicFracturing. *The U.S.Congress is currently considering legislation that could adversely affect theuse of the hydraulic-fracturing process. Currently, regulation of hydraulic fracturing is primarily conducted atthe state level through permitting and other compliance requirements. Thislegislation, if adopted, could establish an additional level of regulation,permitting and restrictions at the federal level, that could adversely affectthe development of unconventional oil and natural gas resources, particularlyour Oklahoma shale projects.

 

**We could be adversely affected by a weak domestic or globaleconomy.**

 

The current anemic recovery from a recessionaryeconomic environment has limited the recovery in demand for oil and natural gasand, therefore, in commodity prices, particularly natural gas.  If the current economic environmentcontinues, lower realized prices may result, and result in continued orincreased operating losses.  Thesefactors 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 veryvolatile.**

 

Ourcommon stock is thinly traded and the market price has been, and is likely tocontinue 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 pricemakes it extremely difficult to forecast with any certainty the stock price atwhich an investor may be able to buy or sell shares of our common stock.  The market price for our common stock couldbe subject to wide fluctuations as a result of factors that are out of ourcontrol, such as:

 

·                    actual oranticipated variations in our results of operations;

·                    naked shortselling of our common stock and stock price manipulation;

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

·                    generalconditions and trends in the crude oil and natural gas industry; and

·                    generaleconomic, political and market conditions.

 

**Our executive officers, directors and affiliates may be ableto control the election of our directors and all other matters submitted to ourstockholders for approval.**

 

Ourexecutive officers and directors, in the aggregate, beneficially ownapproximately 7.0 million shares or approximately 26% of our outstanding commonstock.  Our former Chairman, and currentdirector of the Board, Mr. Laird Q. Cagan, is a  Managing Director of Cagan McAfee CapitalPartners, LLC (“CMCP”).  Mr. EricMcAfee, also a Managing Director of CMCP, currently owns or controls, directlyor indirectly, approximately 2.9 million shares, or approximately 11% of ouroutstanding common stock, but is neither an officer, employee nor a member ofour board of directors.  Collectively,the two managing directors of CMCP currently own or control, directly orindirectly, approximately 3.2 million shares, or approximately 12% of ouroutstanding common stock.  Institutionalaffiliates, including JVL Advisors LLC and Peninsula Capital Management, LP,collectively own approximately 6.7 million shares or approximately 25% of ouroutstanding common stock.  As a result,these holders, could exercise significant influence over matters submitted toour stockholders for approval (including the election and removal of directorsand any merger, consolidation or sale of all or substantially all of ourassets). 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 ordiscourage a potential acquirer from making a tender offer or otherwiseattempting to obtain control of our company, which in turn could have anadverse effect on the market price of our common stock.

 

**The market for our common stock is limited and may notprovide adequate liquidity.**

 

Ourcommon 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 2,795shares 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 commonstock. Selling our shares is more difficult because smaller quantities ofshares are bought and sold and news media coverage about us is limited. Thesefactors result in a limited trading market for our common stock and thereforeholders of our stock may be unable to sell shares purchased, should they desireto do so.

 

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**If securities or industry analyst do not publish researchreports about our business, or if they downgrade our stock, the price of ourcommon stock could decline.**

 

Small,relatively unknown companies can achieve visibility in the trading marketthrough research and reports that industry or securities analysts publish.  However, to our knowledge, only threeindependent analysts cover our company. The lack of published reports by independent securities analysts couldlimit the interest in our common stock and negatively affect our stockprice.  We do not have any control overthe research and reports these analysts publish or whether they will bepublished at all. If any analyst who does cover us downgrades our stock, ourstock price could decline.  If anyanalyst ceases coverage of our company or fails to regularly publish reports onus, we could lose visibility in the financial markets, which in turn couldcause our stock price to decline.

 

**The issuance of additional common stock and preferred stockcould dilute existing stockholders.**

 

Fromtime to time, we may have an effective shelf registration that allows us topublicly offer various securities, including common or preferred stock, and atany time we may make private offerings of our securities.  We are authorized to issue up to 100,000,000shares of common stock.  To the extent ofsuch authorization, our board of directors has the ability, without seekingstockholder approval, to issue additional shares of common stock in the futurefor such consideration as our board may consider sufficient.  The issuance of additional common stock inthe future would reduce the proportionate ownership and voting power of thecommon stock now outstanding.  We arealso authorized to issue up to 5,000,000 shares of preferred stock, the rightsand preferences of which may be designated in series by our board ofdirectors.  Such designation of newseries of preferred stock may be made without stockholder approval, and couldcreate additional securities which would have dividend and liquidationpreferences over the common stock now outstanding. Preferred stockholders couldadversely affect the rights of holders of common stock by:

 

·                    exercisingvoting, redemption and conversion rights to the detriment of the holders ofcommon stock;

·                    receivingpreferences over the holders of common stock regarding our surplus funds in theevent of our dissolution, liquidation or the payment of dividends to Preferredstockholders;

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

·                    discouragingbids for our common stock.

 

**We do not plan to pay any cash dividends on our common stock.**

 

Wehave not paid any dividends on our common stock to date and do not anticipatethat we will be paying dividends in the foreseeable future.  Any payment of cash dividends on our commonstock in the future will be dependent upon the amount of funds legallyavailable, our earnings, if any, our financial condition, our anticipatedcapital requirements and other factors that our board of directors may thinkare relevant.  However, we currentlyintend for the foreseeable future to follow a policy of retaining all of ourearnings, 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 theforeseeable future.

 

**Item 1B. Unresolved Staff Comments**

 

None.

 

**Item 2. Properties**

 

**CompanyLocation**

 

Ourcorporate headquarters are located at 2500 CityWest Boulevard, Suite 1300,Houston, Texas.  We entered into asublease agreement, effective on March 1, 2007, to rent approximately8,400 square feet of Class “A” office space in the Westchase District areain West Houston.  The current monthlybase 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 leasedheadquarters containing 2,259 square feet in an office building located on thewest side of Houston, Texas.  In April 2007,this lease expired.

 

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**Oil &Gas Properties**

 

Additionaldetailed information describing the types of properties we own can be found in “BusinessStrategy” under *Item 1. Business* of this Form10-K.

 

**Estimated Oil and Natural Gas Reserves and Estimated FutureNet Revenues**

 

InDecember 2008, the SEC adopted new rules related to modernizingreserve estimation and disclosure requirements for oil and natural gascompanies (the “Modernization Requirements”), which became effective for annualreporting periods ending on or after December 31, 2009. The ModernizationRequirements require disclosure of oil and gas proved reserves by significantgeographic area, using the 12-month average beginning-of-month price for theyear, rather than year-end prices, and allows the use of new technologies inthe determination of proved reserves if those technologies have beendemonstrated empirically to lead to reliable conclusions about reservevolumes.  Another significant provisionof the new rules is a general requirement that, subject to limited exceptions,proved undeveloped reserves may only be classified as such if a developmentplan has been adopted indicating that they are scheduled to be drilled withinfive years.

 

Thereare numerous uncertainties inherent in estimating quantities of proved reservesand estimates of reserves quantities and values must be viewed as being subjectto significant change as more data about the properties becomes available.

 

Estimated future netrevenues discounted at 10% or PV-10 is a financial measure that is not recognizedby GAAP.  We believe that thepresentation of the non-GAAP financial measure of PV-10 provides usefulinformation to investors because it is widely used by analysts and investors inevaluating oil and natural gas companies. We believe that PV-10 is relevant and useful for evaluating the relativemonetary significance of oil and natural gas properties. Further, analysts andinvestors may utilize the measure as a basis for comparison of the relativesize and value of our reserves to other companies’ reserves.  We also use this pre-tax measure whenassessing the potential return on investment related to oil and natural gasproperties and in evaluating acquisition opportunities.  Because there are many unique factors thatcan impact an individual company when estimating the amount of future incometaxes to be paid, we believe the use of a pre-tax measure is valuable forevaluating our Company.  PV-10 is not ameasure of financial or operating performance under GAAP, nor is it intended torepresent the current market value of our estimated oil and natural gasreserves. PV-10 should not be considered in isolation or as a substitute forthe Standardized Measure as defined under GAAP, and reconciled below.

 

*ProvedReserves Fiscal Year Ended 2010*

 

Applyingthe new rules, our proved reserves at June 30, 2010, denominated inequivalent barrels using a six Mcf of gas and 42 gallons of natural gas liquidsto one barrel of oil conversion ratio, totaled 12,418 MBOE. Approximately 9% ofour reserves were classified as proved developed and 91% were classified asproved 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 ofJune 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”).  VonGonten and Keeling were engaged for our Texas and Oklahoma properties,respectively, due to their particular expertise in the geographic and geologicareas covered by their reports.  D&Mwas selected for our properties in the Delhi Field due to their expertise in CO2-EOR projects and to ensure consistency with the Operator who hasutilized D&M for their reserves estimates in the Delhi Field.   The scope andresults 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.

 

Thefollowing table sets forth our estimated proved reserves as of June 30,2010.  See Note 16 to the consolidatedfinancial statements, where additional reserve information is provided.  The New York Mercantile Exchange 12-monthaverage 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 wasbased on the historical price received versus the NYMEX basis oil price.  Pricing differentials were applied to allproperties, on an individual property basis. Quality adjustments have been applied based on actual BTU factors foreach well and a shrinkage factor has been applied based on production volumesversus actual sales volumes.

 

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**June 30, 2010**

 
| ** **                                               | ** ** | **Proved**    | ** ** | **Proved**        | ** ** | ** **      | ** ** | ** **            | ** **  |
|----------------------------------------------------------|------------|---------------|------------|-------------------|------------|-----------------|------------|-----------------------|-------------|
| ** **                                               | ** ** | **Developed** | ** ** | **Developed**     | ** ** | **Proved**      | ** ** | **Total Proved** | ** **  |
| ** **                                               | ** ** | **Producing** | ** ** | **Non-producing** | ** ** | **Undeveloped** | ** ** | **Reserves**          | ** **  |
|                                                     |       |          |       |              |       |            |       |                  |        |
| **Crude Oil (MBbls)**                                    |       |          |       |              |       |            |       |                  |        |
| Delhi Field                                              |       | 584           |       | 29                |       | 8,799           |       | 9,412                 |        |
| Giddings Field                                           |       | 81            |       | 12                |       | 750             |       | 843                   |        |
| *Total Crude Oil (MBbls)*                                |       | 665           |       | 41                |       | 9,549           |       | 10,255                |        |
|                                                     |       |          |       |              |       |            |       |                  |        |
| **NGLs (MBbls)**                                         |       |          |       |              |       |            |       |                  |        |
| Giddings Field                                           |       | 143           |       | 15                |       | 879             |       | 1,037                 |        |
| *Total NGLs (MBbls)*                                     |       | 143           |       | 15                |       | 879             |       | 1,037                 |        |
|                                                     |       |          |       |              |       |            |       |                  |        |
| **Natural gas (MMcf)**                                   |       |          |       |              |       |            |       |                  |        |
| Giddings Field                                           |       | 1,348         |       | 51                |       | 5,226           |       | 6,625                 |        |
| Oklahoma                                                 |       | —        |       | 138               |       | —          |       | 138                   |        |
| *Total Natural gas (MMcf)*                               |       | 1,348         |       | 189               |       | 5,226           |       | 6,763                 |        |
|                                                     |       |          |       |              |       |            |       |                  |        |
| **Total (MBOE)**                                         |       | 1,032         |       | 87                |       | 11,299          |       | 12,418                |        |
|                                                     |       |          |       |              |       |            |       |                  |        |
| Estimated future net revenues                            |       | $             | 45,604,219 |              | $          | 3,483,121       |       | $                     | 521,964,756 |   | $ | 571,052,096 |   |
| Estimated future net revenues discounted at 10%  (PV-10) |       | $             | 29,306,414 |              | $          | 2,415,600       |       | $                     | 234,256,329 |   | $ | 265,978,343 |   |

 

*ProvedReserves Fiscal Year Ended 2009*

 

Weengaged Von Gonten to prepare an independent report of our proved reserves asof June 30, 2009. Denominated in equivalent barrels using a six Mcf of gasand 42 gallons of natural gas liquids to one barrel of oil conversion ratio, werecognized proved reserves of 3,060,040 at June 30, 2009.  Of our proved reserves, natural gasrepresented 35%, natural gas liquids represented 34%, and crude oil represented31% as of June 30, 2009.

 

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

 

**June 30, 2009**

 
| ** **                                               | ** ** | **Proved**    | ** ** | **Proved**        | ** ** | ** **      | ** ** | ** **            | ** ** |
|----------------------------------------------------------|------------|---------------|------------|-------------------|------------|-----------------|------------|-----------------------|------------|
| ** **                                               | ** ** | **Developed** | ** ** | **Developed**     | ** ** | **Proved**      | ** ** | **Total Proved** | ** ** |
| ** **                                               | ** ** | **Producing** | ** ** | **Non-producing** | ** ** | **Undeveloped** | ** ** | **Reserves**          | ** ** |
|                                                     |       |          |       |              |       |            |       |                  |       |
| Crude Oil (MBbls)                                        |       | 105           |       | —            |       | 841             |       | 946                   |       |
| NGLs (MBbls)                                             |       | 141           |       | —            |       | 913             |       | 1,054                 |       |
| Natural gas (MMcf)                                       |       | 1,106         |       | —            |       | 5,253           |       | 6,359                 |       |
| Total (MBOE)                                             |       | 430           |       | —            |       | 2,630           |       | 3,060                 |       |
|                                                     |       |          |       |              |       |            |       |                  |       |
| Estimated future net revenues                            |       | $             | 9,714,324  |              | —     |            | $          | 48,480,128            |       | $ | 58,194,452 |   |
| Estimated future net revenues discounted at 10%  (PV-10) |       | $             | 7,640,456  |              | —     |            | $          | 28,185,766            |       | $ | 35,826,222 |   |

 

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*Changes in Proved Reserves*

 

Totalproved 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 provedoil reserves we added to our properties in the Delhi Field, based onapproximately $300 million of development capital spent by the Operator sinceproject inception, the start-up of CO2 injectionoperations during fiscal year 2010, and an oil production response duringfiscal year 2010.  The additions in ourproperties in the Delhi Field along with extensions in Giddings and Oklahoma of127,905 BOE, were offset by production of 125,515 BOE and negative revisions of60,943 BOE primarily related to the transfer of four well locations in theLopez Field in South Texas from the proved classification to probable on June 30,2010.

 
| ** **                                    | ** ** | **Delhi** | ** ** | **Giddings** | ** ** | **Lopez** | ** ** | ** **   | ** ** | ** ** | ** ** |
|-----------------------------------------------|------------|-----------|------------|--------------|------------|-----------|------------|--------------|------------|------------|------------|
| ** **                                    | ** ** | **Field** | ** ** | **Field**    | ** ** | **Field** | ** ** | **Oklahoma** | ** ** | **Total**  | ** ** |
| *Proved  reserves, MBOE*                      |       |      |       |         |       |      |       |         |       |       |       |
| **July 1, 2009**                         |       | —    |       | 3,012        |       | 48        |       | —       |       | 3,060      |       |
| Production                                    |       | (6        | )          | (120         | )          | —    |       | —       |       | (126       | )          |
| Revisions                                     |       | —    |       | (13          | )          | (48       | )          | —       |       | (61        | )          |
| Improved recovery, extensions and discoveries |       | 9,418     |       | 104          |       | —    |       | 23           |       | 9,545      |       |
| **June 30, 2010**                        |       | 9,412     |       | 2,983        |       | —    |       | 23           |       | 12,418     |       |

 

*Reconciliation of PV-10 to theStandardized Measure of Discounted Future Net Cash Flows*

 

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

 
| ** **                                                     | ** ** | **For the Years Ended June 30** | ** **  |
|----------------------------------------------------------------|------------|----------------------------------------------------------|-------------|
| ** **                                                     | ** ** | **2010**                                                 | ** **  | **2009** | ** ** |
|                                                           |       |                                                     |        |   |   |
| Estimated future net revenues                                  |       | $                                                        | 571,052,096 |   | $ | 58,194,452 |   |
| 10% annual discount for estimated timing of future  cash flows |       | (305,073,753                                             | )           | (22,368,230 | ) |
| Estimated future net revenues discounted at 10%  (PV-10)       |       | 265,978,343                                              |        | 35,826,222 |   |
| Estimated future income tax expenses discounted at  10%        |       | (104,351,694                                             | )           | (12,276,431 | ) |
| Standardized Measure                                           |       | $                                                        | 161,626,649 |   | $ | 23,549,791 |   |

 

The following table providesa reconciliation of PV-10 of each of our proved properties to the StandardizedMeasure as shown in Note 16 of the consolidated financial statements.

 
| ** **                                               | ** ** | **For the Years Ended June 30** | ** **  |
|----------------------------------------------------------|------------|----------------------------------------------------------|-------------|
| ** **                                               | ** ** | **2010**                                                 | ** **  | **2009** | ** ** |
|                                                     |       |                                                     |        |   |   |
| Delhi Field                                              |       | $                                                        | 224,462,846 |   | $ | — |   |
| Giddings Field                                           |       | 41,337,594                                               |        | 35,286,887 |   |
| Lopez Field                                              |       | —                                                   |        | 539,335 |   |
| Oklahoma                                                 |       | 177,903                                                  |        | — |   |
| Estimated future net revenues discounted at 10%  (PV-10) |       | $                                                        | 265,978,343 |   | $ | 35,826,222 |   |
| Estimated future income tax expenses discounted at  10%  |       | (104,351,694                                             | )           | (12,276,431 | ) |
| Standardized Measure                                     |       | $                                                        | 161,626,649 |   | $ | 23,549,791 |   |

 

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*2010 Reserves Pricing Sensitivities*

 

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

 
| ** **        | ** ** | **Total Proved Reserves as of June 30, 2010** | ** ** |
|-------------------|------------|----------------------------------------------------------------------------------|------------|
| ** **        | ** ** | **Oil**                                                                          | ** ** | **NGLs** | ** ** | **Natural Gas** | ** ** | **Total Reserves** | ** ** | ** ** | ** ** |
| **Pricing**       | ** ** | **(MBbls)**                                                                      | ** ** | **(MBbls)** | ** ** | **(MMcf)** | ** ** | **(MBOE)** | ** ** | **PV-10** | ** ** |
|              |       |                                                                             |       |   |   |   |   |   |   |   |   |
| SEC               |       | 10,255                                                                           |       | 1,037 |   | 6,763 |   | 12,418 |   | $ | 265,978,343 |   |
| Spot price (1)    |       | 10,106                                                                           |       | 1,036 |   | 6,773 |   | 12,270 |   | $ | 251,930,278 |   |
| Forward curve (2) |       | 10,482                                                                           |       | 1,049 |   | 6,894 |   | 12,679 |   | $ | 308,738,147 |   |

 

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

 

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

 

*ProbableReserves Fiscal Year Ended 2010*

 

TheModernization Requirements also permitted the disclosure of probablereserves.  Probable reserves areadditional reserves that are less certain to be recovered than proved reservesbut which, in sum with proved reserves, are as likely as not to berecovered.  The various reservecategories have different risks associated with them. Proved reserves are morelikely to be produced than probable reserves. Because of these risks, thedifferent reserve categories should not be considered to be directly additive.

 
| ** **                             | ** ** | **Oil**     | ** ** | **NGLs**    | ** ** | **Natural Gas** | ** ** | **Total**  | ** ** | ** ** | ** ** |
|----------------------------------------|------------|-------------|------------|-------------|------------|----------------------|------------|------------|------------|------------|------------|
| ** **                             | ** ** | **(MBbls)** | ** ** | **(MBbls)** | ** ** | **(MMcf)**           | ** ** | **(MBOE)** | ** ** | **PV-10**  | ** ** |
|                                   |       |        |       |        |       |                 |       |       |       |       |       |
| **Probable undeveloped reserves**      |       |        |       |        |       |                 |       |       |       |       |       |
| Delhi Field                            |       | 5,682       |       | —      |       | —               |       | 5,682      |       | $          | 51,185,283 |   |
| Giddings Field                         |       | 206         |       | 226         |       | 3,272                |       | 977        |       | $          | 11,767,618 |   |
| Lopez Field                            |       | 283         |       | —      |       | —               |       | 283        |       | $          | 785,921    |   |
| Oklahoma                               |       | —      |       | —      |       | 1,360                |       | 227        |       | $          | 53,907     |   |
| *Total probable undeveloped  reserves* |       | 6,171       |       | 226         |       | 4,632                |       | 7,169      |       | $          | 63,792,729 |   |

 

Additionaldetailed information describing the types of properties we own can be found inItem 1. Business — Business Strategy.

 

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**Internal Controls Over Reserves Estimation Process and Qualificationsof Technical Persons and**

 

Our policies regardinginternal controls over reserve estimates require reserves to be prepared by anindependent engineering firm under the supervision of our Chief ExecutiveOfficer and Vice President of Operations and to be in compliance with generallyaccepted petroleum engineering and evaluation principles and definitions andguidelines established by the SEC.  Weprovide each engineering firm with property interests, production, currentoperating costs, current production prices and other information.  This information is reviewed by our VicePresident of Operations and our Chief Executive Officer to ensure accuracy andcompleteness of the data prior to submission to our third party engineeringfirm. The scope and results of our third party engineering firms’ proceduresare summarized in a letter included as an exhibit to this Annual Report on Form 10-K.  A letter which identifies the professionalqualifications of each of the independent engineering firms who prepared thereserve reports are also filed as exhibits to this Annual report on Form 10-K.

 

**Proved Undeveloped Reserves**

 

Our proved undevelopedreserves at June 30, 2010 were 11.3 MMBOE. Future development costsassociated with our proved undeveloped reserves at June 30, 2010 totaledapproximately $32.9 million.  Theincrease in proved undeveloped reserves is primarily attributable to 8.8 MMBOEof proved undeveloped oil reserves we added to our properties in the DelhiField, based on approximately $300 million of development capital spent by theOperator since project inception, the start-up of CO2 injection operationsduring fiscal year 2010, and an oil production response during fiscal year2010.  None of our proved undevelopedlocations remain undeveloped for five years from the date of initialrecognition as proved undeveloped reserves.

 

**Sales Volumes, Average Sales Prices and Average ProductionCosts**

 

Thefollowing table shows the Company’s sales volumes and average sales prices receivedfor crude oil, natural gas liquids, and natural gas for the periods indicated:

 
| ** **                 | ** ** | **Year Ended**         | ** ** | **Year Ended**         | ** ** | **Year Ended**         | ** ** |
|----------------------------|------------|-----------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                 | ** ** | **June 30, 2010** | ** ** | **June 30, 2009** | ** ** | **June 30, 2008** | ** ** |
| **Product**                | ** ** | **Volume**                  | ** ** | **Price**                   | ** ** | **Volume**                  | ** ** | **Price** | ** ** | **Volume** | ** ** | **Price** | ** ** |
|                       |       |                        |       |                        |       |                        |       |   |   |   |   |   |   |
| Crude oil (Bbls)           |       | 29,749                      |       | $                           | 73.56      |                        | 36,026     |   | $ | 76.26 |   | 29,466 |   | $ | 99.03 |   |
|                       |       |                        |       |                        |       |                        |       |   |   |   |   |   |   |
| Natural gas liquids (Bbls) |       | 27,820                      |       | $                           | 38.80      |                        | 44,125     |   | $ | 36.83 |   | 10,639 |   | $ | 63.02 |   |
|                       |       |                        |       |                        |       |                        |       |   |   |   |   |   |   |
| Natural gas (Mcf)          |       | 407,674                     |       | $                           | 4.30       |                        | 323,301    |   | $ | 5.33 |   | 69,051 |   | $ | 9.67 |   |

 

Averageproduction costs, including production taxes, per unit of production (using asix to one conversion ratio of Mcf’s to barrels) were approximately $13, $11and $25 per BOE for the years ended June 30, 2010, 2009 and 2008,respectively.

 

Crude oil, NGLs, and naturalgas sales volumes, net to our interest, for the year ended June 30, 2010decreased 6% to 125,515 BOE, compared to 134,035 BOE for the year ended June 30,2009.  Our sales volumes for the yearended June 30, 2010 included 6,333 Bbls of oil from Delhi (of which 5,721bbls of oil were sold during the 4th quarter of2010) and 119,182 BOE from our properties in the Giddings Field in Texas.

 

FirstEOR oil production at Delhi began in the last two weeks of March 2010.  Total sales volumes from Delhi, net to ourinterest, for the year ended June 30, 2010 was 6,333 Bbls of oil comparedto 172 Bbls of oil during the year ended June 30, 2009.  Our interests in the Delhi Field consist ofmore than 76% of our total proved reserves as of June 30, 2010.  The average sales price per barrel of crudeoil at Delhi was $76.59 for the year ended June 30, 2010, with noassociated production costs.

 

Production from ourproperties in the Giddings Field decreased 11% from 133,863 BOE during thefiscal 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 Fieldincreased 26%, while production of crude oil and NGLs decreased 31% compared tothe year ended June 30, 2009.  Ourinterests in the Giddings Field consist of 24% of our total proved reserves asof June 30, 2010.  The average salesprice per BOE at Giddings was $38.07 for the year ended June 30, 2010, andassociated production costs (not including ad valorem and production taxes)were $12.52 per BOE.

 

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Theincrease in volumes from fiscal 2008 to fiscal 2009 were attributable to thedevelopment of our properties in the Giddings Field, which accounted for almost100 percent of our production during the year ended June 30, 2009.  Our production in the Giddings Field beganlate in the third fiscal quarter of the year ended June 30, 2008.  Our properties in the Tullos Field, whichwere sold on March 3, 2008, accounted for 35% of total sales volumes forthe year ended June 30, 2008.

 

**Drilling Activity**

 

Thefollowing table sets forth our drilling activity.

 
| ** **                       | ** ** | **Year Ended June 30,** | ** ** |
|----------------------------------|------------|----------------------------------------|------------|
| ** **                       | ** ** | **2010**                               | ** ** | **2009** | ** ** | **2008** | ** ** |
| ** **                       | ** ** | **Gross**                              | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Productive wells drilled         |       |                                   |       |   |   |   |   |   |   |   |   |   |   |
|                             |       |                                   |       |   |   |   |   |   |   |   |   |   |   |
| Development                      |       | 1.0                                    |       | 1.0 |   | 2.0 |   | 2.0 |   | 6.0 |   | 6.0 |   |
| Exploratory                      |       | —                                 |       | — |   | — |   | — |   | — |   | — |   |
| Total                            |       | 1.0                                    |       | 1.0 |   | 2.0 |   | 2.0 |   | 6.0 |   | 6.0 |   |
| Non productive dry wells drilled |       |                                   |       |   |   |   |   |   |   |   |   |   |   |
|                             |       |                                   |       |   |   |   |   |   |   |   |   |   |   |
| Development                      |       | —                                 |       | — |   | — |   | — |   | — |   | — |   |
| Exploratory                      |       | —                                 |       | — |   | — |   | — |   | — |   | — |   |
| Total                            |       | —                                 |       | — |   | — |   | — |   | — |   | — |   |

 

**Present Activities**

 

We are currently drillingthe Supak-Brinkman-1H in the Giddings Field under of joint developmentagreement with an industry partner.  TheSupak-Brinkman-1H is a $1.7 million gross AFE re-entry operation to add asingle Austin Chalk lateral to an existing wellbore.   We will receive a 10% carried workinginterest, a 10% cost bearing working interest for our cash participation, and a22.5% back-in working interest on our partner’s 80% working interest.

 

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

 

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

 

Forfurther discussion, see**“**Highlightsfor our fiscal year 2010” and “Looking forward into 2011” under *Item 7. Management’s Discussion and Analysis of Financial Condition andResults of Operations* of this Form 10-K.

 

**Delivery Commitments**

 

Asof June 30, 2010, we had no delivery commitments.

 

**Productive Wells and Developed Acreage**

 

Ourdeveloped acreage at June 30, 2010 totaled 5,040 net acres in the GiddingsField, consisting of a 100% working interest in nine producing and one developednon-producing gross and net wells, and 153 net acres in Wagoner County, OK withone nonproducing shut-in well.  We alsoown mineral and overriding royalty interests aggregating 7.4% in our CO2-EOR project in the DelhiField.

 

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Ourdeveloped acreage at June 30, 2009 totaled 5,040 net acres in the GiddingsField, consisting of a 100% working interest in ten gross and net producingwells.

 

Ourdeveloped acreage at June 30, 2008 totaled 3,469 net acres in the GiddingsField, consisting of a 100% working interest in seven gross and net producingwells.

 

**Undeveloped Acreage**

 

Provedundeveloped acreage includes nineteen proved drilling locations and twoprobable drilling locations in the Giddings Field.

 

Thereduction of six proved locations from the 25 proved locations as of the end offiscal 2009 includes the addition of one proved drilling location in Giddingsoffset by the removal of three drilling locations in Giddings and thereclassification of four drilling locations from proved to probable in theLopez Field in South Texas. Probable undeveloped acreage includes two drillinglocations in Giddings, ten drilling locations in Oklahoma and twenty-fivedrilling locations in the Lopez Field. Additional drilling locations are associated with our acreage, butrequire further leasing, step out drilling, and/or an increase in commodityprices before being considered for inclusion.

 

Asof June 30, 2010, we held approximately 55,007 gross and 36,298 netundeveloped acres in the Gulf Coast and Mid-Continent regions of the UnitedStates, as follows:

 
| **Field/Area**                                 | ** ** | **Gross Acreage** | ** ** | **Net Acreage** | ** ** |
|------------------------------------------------|------------|------------------------|------------|----------------------|------------|
| Giddings Field, Texas                          |       | 15,642                 |       | 13,891               |       |
| Woodford, Oklahoma                             |       | 23,925                 |       | 17,421               |       |
| Neptune Oil Project (Lopez Field, South Texas) |       | 1,804                  |       | 1,721                |       |
| Delhi Field, Louisiana *                       |       | 13,636                 |       | 3,265                |       |
| Total                                          |       | 55,007                 |       | 36,298               |       |

 

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*Includes from the surface of the Earth to the top of the Massive Anhydride,less and except the Delhi Holt Bryant CO2 and MengelUnits. With respect to the Delhi Holt Bryant Unit, currently being redevelopedusing CO2-EOR operationswithin this same acreage, we currently own royalty interests aggregatingapproximately 7.4%.  Separately, we own a23.9% reversionary working interest (19% net revenue interest) that will revertto us, as, if and when payout occurs, as defined. We are not the operator ofthe Delhi CO2-EOR project.

 

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

 

Formore complete information regarding current year activities, including crudeoil and natural gas production, refer to *Item 7. Management’sDiscussion and Analysis of Financial Condition and Results of Operations*ofthis Form 10-K.

 

**Item 3. Legal Proceedings**

 

None.

 

**Item 4.****Submission of Matters to a Voteof Security Holders**

 

No matters were submitted toa 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 CommonEquity, Related Stockholder Matters and Issuer Purchases of Equity Securities**

 

**Common Stock**

 

Ourcommon stock is currently traded on the NYSE Amex under the ticker symbol “EPM”.

 

Weinitiated 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 bythe NYSE Euronext (NYX) in 2008 and is now known as NYSE Amex.  The following table shows, for each quarterof fiscal year 2010 and 2009, the high and low sales prices for EPM as reportedby the NYSE Amex.

 

**NYSE Amex**

 
| **2010:**                                   | ** ** | **High** | ** ** | **Low** | ** ** |
|---------------------------------------------|------------|----------|------------|---------|------------|
| Fourth quarter ended June 30, 2010     |       | $        | 6.25       |    | $          | 4.61 |   |
| Third quarter ended March 31, 2010     |       | $        | 5.10       |    | $          | 4.36 |   |
| Second quarter ended December 31, 2009 |       | $        | 4.67       |    | $          | 2.90 |   |
| First quarter ended September 30, 2009 |       | $        | 3.34       |    | $          | 2.21 |   |

 
| **2009:**                                   | ** ** | **High** | ** ** | **Low** | ** ** |
|---------------------------------------------|------------|----------|------------|---------|------------|
| Fourth quarter ended June 30, 2009     |       | $        | 3.13       |    | $          | 1.85 |   |
| Third quarter ended March 31, 2009     |       | $        | 1.99       |    | $          | 1.17 |   |
| Second quarter ended December 31, 2008 |       | $        | 3.06       |    | $          | 1.00 |   |
| First quarter ended September 30, 2008 |       | $        | 6.05       |    | $          | 2.60 |   |

 

**Holders**

 

Asof June 30, 2010, there were 27,061,376 shares of common stock issued andoutstanding, held by approximately 3,050 holders of record.

 

**Dividends**

 

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

 

**Securities Authorized For Issuance Under Equity CompensationPlans**

 
| ** **                                                  | ** ** | **Number of**      | ** ** | ** **                 | ** ** | **Number of securities** | ** ** |
|-------------------------------------------------------------|------------|-------------------------|------------|----------------------------|------------|------------------------------------|------------|
| ** **                                                  | ** ** | **securities to**  | ** ** | **Weighted-average**       | ** ** | **remaining**                      | ** ** |
| ** **                                                  | ** ** | **be issued**      | ** ** | **exercise**               | ** ** | **available for future** | ** ** |
| ** **                                                  | ** ** | **upon exercise**  | ** ** | **price of**          | ** ** | **issuance under**            | ** ** |
| ** **                                                  | ** ** | **of outstanding** | ** ** | **outstanding**            | ** ** | **equity compensation**       | ** ** |
| ** **                                                  | ** ** | **options,**            | ** ** | **options, warrants** | ** ** | **plans (excluding**          | ** ** |
| ** **                                                  | ** ** | **warrants and**   | ** ** | **and**                    | ** ** | **securities reflected**      | ** ** |
| ** **                                                  | ** ** | **rights**              | ** ** | **rights**                 | ** ** | **in column (a))**       | ** ** |
| **Plan category**                                      | ** ** | **(a)**                 | ** ** | **(b)**                    | ** ** | **(c)**                            | ** ** |
| ** **                                                  | ** ** | ** **              | ** ** | ** **                 | ** ** | ** **                         | ** ** |
| Equity compensation plans approved by security  holders     |       | 4,445,320               | (1)        | $                          | 1.90       |                               | 611,407    |   |
|                                                        |       |                    |       |                       |       |                               |       |
| Equity compensation plans not approved by security  holders |       | 1,196,808               | (2)        | $                          | 1.60       |                               | —     |   |
| Total                                                       |       | 5,642,128               |       | $                          | 1.83       |                               | 611,407    |   |

 

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(1) OnMay 26, 2004, we, as Reality Interactive, Inc., executed an Agreementand Plan of Merger with Natural Gas Systems, Inc., a Delaware corporation(the “Merger”).  In connection with theMerger, we assumed the obligations of 600,000 stock options under our acquiredsubsidiary’s 2003 Stock Option Plan.  Asof June 30, 2010, 500,000 shares remain issuable upon exercise of stockoptions under the 2003 Stock Option Plan and no further options shall be issuedthere-under.  As of June 30, 2010,there were 3,945,320 shares of common stock issuable upon exercise ofoutstanding stock options, 3,000 options that were exercised and 940,273 sharesof common stock issued directly under the 2004 Stock Plan, leaving 611,407shares of common stock available for issuance.

 

(2) Inaddition to assuming certain obligations listed in footnote 1 above, inconnection with the Merger, we also assumed outstanding warrants to purchaseshares of common stock issued in connection with arranging the merger and inconnection with capital raising.  Totalwarrants outstanding as of June 30, 2010 related to these activities were159,308 with a weighted average exercise price of $1.87.  Also included were 1,037,500 warrants with aweighted average exercise price of $1.56 issued in connection with employmentand or compensation arrangements, including a warrant to purchase 287,500shares of common stock in connection with Mr. Herlin’s employmentagreement with the Company, a warrant to purchase 200,000 shares in connectionwith Mr. Mazzanti’s employment agreement with the Company, a warrant topurchase 400,000 shares of common stock in connection with Mr. Herlin’sannual performance incentives, including warrants in lieu of cash bonus, and awarrant to purchase 150,000 shares of common stock in connection with Mr. McDonald’sannual performance incentives, including warrants in lieu of cash bonus.

 

**Recent Sales of Unregistered Securities**

 

None.

 

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**Item 6. Selected Financial Data**

 

Theselected consolidated financial data, set forth below should be read inconjunction with Item 7 “Management’s Discussion and Analysis of FinancialCondition and Results of Operations” and with the consolidated financialstatements and notes to those consolidated financial statements includedelsewhere in this report.

 
| ** **                                                        | ** ** | **Quarter Ended**              | ** ** |
|-------------------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                        | ** ** | **June 30,******** 2010** | ** ** | **March 31,******** 2010** | ** ** | **December 31,******** 2009** | ** ** | **September 30,******** 2009** | ** ** | **June 30,******** 2009** | ** ** |
| Revenues                                                          |       |                                |       |   |   |   |   |   |   |   |   |
| Crude oil                                                         |       | $                                   | 759,344    |   | $ | 469,418 |   | $ | 456,375 |   | $ | 503,122 |   | $ | 409,546 |   |
| Natural gas liquids (“NGLs”)                            |       | 231,460                             |       | 282,400 |   | 280,212 |   | 285,311 |   | 283,434 |   |
| Natural gas                                                       |       | 368,387                             |       | 539,563 |   | 464,715 |   | 381,594 |   | 290,971 |   |
| Total operating revenues                                          |       | 1,359,191                           |       | 1,291,381 |   | 1,201,302 |   | 1,170,027 |   | 983,951 |   |
| Operating Expense                                                 |       |                                |       |   |   |   |   |   |   |   |   |
| Lease operating expense (“LOE”)                         |       | 482,160                             |       | 399,833 |   | 369,928 |   | 364,846 |   | 379,969 |   |
| Production taxes                                                  |       | 8,054                               |       | 5,432 |   | 16,459 |   | 18,367 |   | 21,272 |   |
| Depreciation, depletion, and amortization  (“DD&A”) |       | 144,766                             |       | 505,445 |   | 550,142 |   | 617,757 |   | 552,153 |   |
| Accretion expense                                                 |       | 15,954                              |       | 15,562 |   | 15,200 |   | 14,338 |   | 13,149 |   |
| G&A (excluding stock-based compensation) (1)                  |       | 433,064                             |       | 810,171 |   | 828,796 |   | 861,480 |   | 413,132 |   |
| G&A: Stock-based compensation (2)                             |       | 957,595                             |       | 384,701 |   | 424,800 |   | 391,636 |   | 760,365 |   |
| Total operating expense                                           |       | 2,041,593                           |       | 2,121,144 |   | 2,205,325 |   | 2,268,424 |   | 2,137,040 |   |
| Operating loss                                                    |       | (682,402                            | )          | (829,763 | ) | (1,004,023 | ) | (1,098,397 | ) | (1,153,089 | ) |
| Interest income, net                                              |       | 7,269                               |       | 18,776 |   | 13,785 |   | 15,224 |   | 22,820 |   |
| Net loss before income tax benefit                                |       | (675,133                            | )          | (810,987 | ) | (990,238 | ) | (1,083,173 | ) | (1,130,269 | ) |
| Income tax benefit                                                |       | 245,712                             |       | 259,466 |   | 288,298 |   | 378,348 |   | 420,627 |   |
| Net loss                                                          |       | $                                   | (429,421   | ) | $ | (551,521 | ) | $ | (701,940 | ) | $ | (704,825 | ) | $ | (709,642 | ) |
|                                                              |       |                                |       |   |   |   |   |   |   |   |   |
| Loss per share — basic and diluted                           |       | $                                   | (.02       | ) | $ | (.02 | ) | $ | (.03 | ) | (.03 | ) | $ | (.03 | ) |
|                                                              |       |                                |       |   |   |   |   |   |   |   |   |
| Weighted average number of common shares  outstanding             |       | 27,137,611                          |       | 27,144,174 |   | 27,092,954 |   | 26,646,022 |   | 26,297,444 |   |
|                                                              |       |                                |       |   |   |   |   |   |   |   |   |
| Sales volumes per day                                             |       |                                |       |   |   |   |   |   |   |   |   |
| Oil (Bbls)                                                        |       | 109.5                               |       | 66.8 |   | 66.6 |   | 82.3 |   | 78.9 |   |
| NGL (Bbls)                                                        |       | 64.2                                |       | 68.3 |   | 74.9 |   | 96.4 |   | 113.1 |   |
| Natural gas (Mcf)                                                 |       | 972.7                               |       | 1,082.0 |   | 1,188.2 |   | 1,210.7 |   | 934.1 |   |
| Total (BOE)                                                       |       | 335.8                               |       | 315.5 |   | 339.5 |   | 380.5 |   | 347.7 |   |
|                                                              |       |                                |       |   |   |   |   |   |   |   |   |
| Average sales price                                               |       |                                |       |   |   |   |   |   |   |   |   |
| Oil per Bbl                                                       |       | $                                   | 76.18      |   | $ | 77.17 |   | $ | 74.47 |   | $ | 66.46 |   | $ | 57.02 |   |
| NGL per Bbl                                                       |       | 39.63                               |       | 45.42 |   | 40.66 |   | 32.16 |   | 27.55 |   |
| Natural gas per Mcf                                               |       | 4.16                                |       | 5.48 |   | 4.25 |   | 3.43 |   | 3.42 |   |
| Total per BOE                                                     |       | 44.47                               |       | 44.98 |   | 38.46 |   | 33.43 |   | 31.10 |   |
| Per BOE                                                           |       |                                |       |   |   |   |   |   |   |   |   |
| LOE and production taxes                                          |       | 16.04                               |       | 14.12 |   | 12.37 |   | 10.95 |   | 12.59 |   |
| DD&A                                                          |       | 4.74                                |       | 17.61 |   | 17.61 |   | 17.65 |   | 17.45 |   |
| Accretion expense                                                 |       | 0.52                                |       | 0.54 |   | 0.49 |   | 0.41 |   | 0.42 |   |
| G&A (excluding stock-based compensation) (1)                  |       | 14.17                               |       | 28.22 |   | 26.53 |   | 24.61 |   | 13.06 |   |
| G&A: Stock-based compensation (2)                             |       | 31.33                               |       | 13.40 |   | 13.60 |   | 11.19 |   | 24.03 |   |
| Total operating expense                                           |       | 66.80                               |       | 73.88 |   | 70.60 |   | 64.80 |   | 67.55 |   |
| Operating (loss) income                                           |       | $                                   | (22.33     | ) | $ | (28.90 | ) | $ | (32.14 | ) | $ | (31.38 | ) | $ | (36.45 | ) |
| Net income (loss) before income taxes                             |       | $                                   | (22.09     | ) | $ | (28.25 | ) | $ | (31.70 | ) | $ | (30.94 | ) | $ | (35.72 | ) |

 

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(1)   G&A for the quarterended June 30, 2010, includes the reversal of accrued bonuses of $587,033 ($19.21per BOE of production), due to the decision to issue common stock to employeesin lieu of a cash bonus.

 

(2)   G&A: Stock-basedcompensation for the quarter ended June 30, 2010, includes a charge of$587,033 ($19.21 per BOE of production), related to the payment of 2010 bonusesthrough the issuance of common stock.

 

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**Item 7. Management’s Discussion and Analysis of Financial Condition andResults of Operations**

 

**Executive Overview**

 

*General*

 

We are a petroleum companyengaged primarily in the acquisition, exploitation and development ofproperties for the production of crude oil and natural gas, onshore in the UnitedStates. We acquire known, underdeveloped oil and natural gas resources andexploit them through the application of capital, sound engineering and moderntechnology to increase production, ultimate recoveries, or both.

 

Weare focused on increasing underlying asset values on a per share basis.  In doing so, we depend on a conservativecapital structure, allowing us to maintain control of our assets for thebenefit of our shareholders, including approximately 20% beneficially owned byall of our employees.

 

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

 

Theassets we exploit currently fit into three types of project opportunities:

 

·      Enhanced Oil Recovery (EOR),

 

·      Bypassed Primary Resources, and

 

·      Unconventional Shale Gas Development.

 

We expect to fund our fiscal 2011 development planfrom working capital and net cash flows from our properties in the Giddings andDelhi Fields, although we also may utilize appropriate financing to fundadditional development above our 2011 development plan.

 

*Highlights for our fiscal year 2010*

 

***Oil & GasReserves***

 

·      **Proved reservesincreased 306% to 12.4 million BOE. Proved and probable combined reserves increased 10% to 19.6 million BOE.** This compares to 3.1 million BOE of proved and 17.8 million BOE ofproved and probable reserves at June 30, 2009.

 

·      **Provedreserves are 83% oil and 9% liquids, as compared to 31% and 34% at June 30,2009.**

 

·      **PV-10of Proved reserves increased 642%, from $36 million to $266 million .  PV-10 of proved and probable reservesincreased 34%, from $245 million to $330 million. **We believe the presentationof PV-10 provides useful information to investors because it is widely used byanalysts and investors in evaluating oil and natural gas companies and the relativemonetary significance of their oil and natural gas properties.  PV-10 is not intended to represent thecurrent market value of our estimated oil and natural gas reserves, nor shouldit be considered in isolation or as a substitute for the Standardized Measure asdefined under GAAP.  See “Estimated Oil and Natural Gas Reservesand Estimated Future Net Revenues” under *Item 2. Properties*of this Form 10-K for a reconciliation of PV-10 to the Standardized Measure.

 

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·**                 ****Weadded 9.4 million net barrels of proved oil reserves at Delhi.  Net proved and probable reserves at Delhiincreased 11% to 15.1 million barrels of oil due to greater expected recoverybased on the earlier and stronger than anticipated EOR response, and theinclusion of additional pay zones. **Fiscal 2010 wasa pivotal year for the Delhi Field. Following four years of field development and $300 million of relatedcapital expended by the Operator, we obtained first EOR production in March 2010,three months earlier than the anticipated mid-summer response date.  This early response further supported ourindependent reservoir engineer’s assignment of 15.1 million net barrels ofproved and probable oil reserves, 9.4 million of which are classified as provedreserves.  Of the 15.1 million netbarrels of proved and probable oil reserves approximately five million areassociated with our royalty interests. This compares to 13.6 million barrels of probable reserves, and noproved reserves, assigned to Delhi by D&M at the end of fiscal 2009.  The current reserve report includes changesto the Delhi EOR development plan that resulted in both positive and negativeimpacts on our Delhi reserves.  Theexpected future purchase volumes of CO2 weresubstantially increased, particularly during the pre-payout period, therebyextending the pre-payout period.  Inaddition, title work by DNR has determined that a small amount of the workinginterest is owned by third parties, resulting in a minor reduction to our afterpayout working interest from 25% to 23.9%.  These adverse effects are more than offset by three positiverevisions.  First, the early strongproduction response, combined with further analysis, have led to a higherexpected peak production rate and an increase in the recovery rate from 15% to17% of original oil in place.  Second,D&M has concurred with the expansion of the EOR project to severaladditional , analogous reservoirs within the field.  The combination of these two revisions bringstotal expected proved and probable gross recoveries to 68 MMBO.  Third, reserves now include the benefit ofthe EOR severance tax holiday granted by the State of Louisiana.  For Evolution shareholders, the combinationof these effects equates to 1.5 MMBO of added proved and probable reserves anda $79 million increase in PV-10 associated with our proved and probablereserves, offset by an approximate 20 month delay in reversionary payoutcompared to the 2009 report.  At June 30,2010, proved PV-10 at Delhi is $224.5 million and probable PV-10 is $51.2million. See “Estimated Oil and NaturalGas Reserves and Estimated Future Net Revenues” under *Item 2.Properties* of this Form 10-K for a reconciliation of PV-10 to theStandardized Measure.

 

·      **Ourfourth quarter depletion rate of $4.39 per BOE is a proxy for our averagehistorical full-cycle F&D costs.**Since we have never had aceiling test write-down of our oil and gas properties, our current depletionrate is equal to our average historical, full-cycle finding and developmentcosts for proved reserves.

 

·      **Ourproved reserves are 9% developed, but we bear no expected future capitalexpenditures related to our 8.8 MMBo of proved undeveloped reserves atDelhi. **While less than 10% of Delhi’splanned producing wells were online at June 30, 2010, approximately 65% ofbudgeted project costs had been expended by the Operator through June 30,2010.

 

·      **Due todelayed testing at our Neptune Oil Project in South Texas, we have elected torevise our 48 MBO of proved undeveloped reserves as probable reserves as of June 30,2010.**  Delay in obtaining power andthen unforeseen mechanical difficulties in obtaining adequate saltwaterinjection capacity delayed the start of our production testing to the fourthfiscal quarter.  We will continue to testthe project through a workover of the existing producer and re-entry of potentiallytwo additional producer wells during fiscal 2011.

 

·      **We madeprogress with our first producing test well in our shallow Woodford shaleproject in Wagoner County, OK, establishing 1.6 BCF of proved and probablereserves in and around the Henry 19-2 vertical test well. **In late February webegan steady-state production by flaring production from the Henry.  Production steadily increased from an initiallow rate as the localized area of the reservoir dewatered.  At the end of April, water rates weredecreasing while gas production rates were increasing past our targeted peakrate of 80 Mcfd, reaching a rate of 93 Mcfd of gas before the well was shut indue to power failure due to lightning. Although we are unable to predict the final peak gas rate capability ofthis well, we believe this result is very encouraging and suggests that thedewatering process relieves the hydrostatic formation pressure to allowincreasing gas rates, typically followed by a long slow decline curve.  An additional test well was put on productionin the southern block of our Wagoner leasehold with a different fracapplication and was disappointing.  Weexpect to again test this block in a different location using the frac utilizedin the Henry well.  As previouslyreported, in a separate well we also performed a brief production test of theCaney Shale and determined its modest economic potential to be limited to anadd-on to the Woodford Shale.

 

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·                  **Wereplaced 76% of our 120 MBOE net production at the Giddings Field in CentralTexas and ended the fiscal year with proved reserves of 3.0 MMBOE and probablereserves of 1.0 MBOE. **Due toupgrading of our portfolio of drilling locations, proved PV-10 at Giddingsincreased 17% from the prior year to $41.3 million.  See  *Looking Forward to 2011*for a discussion of the jointdevelopment agreement entered into subsequent to our year ended June 30,2010.  See “Estimated Oil and Natural Gas Reserves and Estimated Future NetRevenues” under *Item 2. Properties* of this Form10-K for a reconciliation of PV-10 to the Standardized Measure.

 

***Operations***

 

·                  **Firsttertiary oil production began at Delhi in March 2010. **Our share of production fromDelhi, net to our royalty interests for the year ended June 30, 2010, was6,333 Bbls of oil compared to 172 Bbls of oil during the year ended June 30,2009.  In June, gross field productionwas slightly over 800 BOPD.  Denbury iscontinuing its multi-year roll out of the project by installing Phase II andPhase III in the field through the addition of producer and injector wells andassociated facilities in the field, which is expected to provide a continuedsteady increase in oil production.  OnceDenbury has generated sufficient net revenues to offset direct operatingexpenses of the project by the deemed $200 million payout, we will receive a23.9% working interest (25% of Denbury’s interest), and an incrementalestimated 19.2% revenue interest (increasing our revenue interest to 26.56%).We expect to continue bearing no capital expenditures or operating costs untilsuch payout occurs, after which we begin paying our working interest share offuture costs.

 

·                  **Salesvolumes decreased 6% in fiscal 2010 versus fiscal 2009. **Our decrease in salesvolumes for the year was solely attributable to our normal production declinein the Giddings Field.  Production fromour properties in the Giddings Field decreased 11% from 133,863 BOE during thefiscal 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 Fieldincreased 26%, while production of crude oil and NGLs decreased 31% compared tothe year ended June 30, 2009.  FirstEOR oil production at Delhi began in the last two weeks of March 2010.  Our net production from Delhi for the yearended June 30, 2010 was 6,333 Bbls of oil compared to 172 Bbls of oilduring the year ended June 30, 2009.

 

·                  **Welowered our depletion rate 75% to less than $5 per BOE during the fourthquarter of fiscal 2010.**  Ourdepletion rate for the fourth quarter of fiscal year 2010 was $4.39 per BOE,compared to $17.61 for the third quarter of 2010.  The decrease in our depletion rate was due tothe addition of 9.4 million barrels of proved oil reserves at Delhi, whileassociated legacy capital costs of only $1.2 million ($0.13 of costs perincremental barrel) were transferred to our full cost pool.

 

·                  **Theproduct prices we received declined 12% in fiscal 2010 versus fiscal 2009. **During the year ended June 30,2010, the average price we received was $40.01 per BOE, as compared to $45.47per BOE during the year ended June 30, 2009.

 

***Finances***

 

·                  **Weended the year with $4.9 million of working capital, compared to $7.6 millionat June 30, 2009. **At June 30,2010, working capital included $4.5 million of cash, cash equivalents andshort-term certificates of deposit, and $0.7 million of recoverable incometaxes arising from current year tax losses carried back to a prior tax year.****** The $2.7 million reduction in our workingcapital since June 30, 2009 was due primarily to investments of $3.8million in oil and natural gas properties, offset by positive cash flow generatedfrom our oil and gas properties

 

·                  **Cashflows from operations covered our general and administrative expenses andfunded a portion of our capital expenditures. **Cash flows from operations were $2.3 million during the year ended June 30,2010, which includes $2.1 million received in January 2010 from theInternal Revenue Service as a result of a carry-back of our tax loss for theyear ended June 30, 2009.

 

·                  **Non-cash stock-based compensation expense of $2.1 million comprised over42% of G&A for fiscal year 2010. **Non-cash stock-based compensation expense remains an important part ofour total compensation program to help motivate and retain high performingemployees and consultants, in addition to conserving our cash resources.

 

·                  **Wenearly completed negotiations with an industry partner to help finance theresumption of development drilling at Giddings. **For details, see the Looking Forward section below.

 

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·**                 ****Wefiled a universal shelf registration with the SEC. **With considerable marketprice volatility becoming more common, we view a shelf registration as animportant part of prudent capital management.

 

·                  **Weremained debt free.** All of our expenditures were funded solely byworking capital and we ended our fiscal year with no funded debt.

 

*Looking forward into 2011*

 

OurBase Case capital budget of $4 million will focus on selective low cost testingand development of our current portfolio properties within the following majoroperations:

 

·                  **Continuethe roll out of the CO****2**** EOR project at Delhi that is operated andfunded by Denbury.** The Operatoris continuing development activities through its installation of Phases II andIII that began earlier in calendar 2010, and the rate of CO2 injection has continued to increase. Furtherroll out is expected to continue during our fiscal 2011.  Gross oil production, and our resulting netproduction from our royalty interests, is expected to substantially increaseduring the year accordingly.

 

·                  **Resumedevelopment drilling at Giddings on up to 5 of our 19 proved and 2 probabledrilling locations. **Immediatelyfollowing the close of our recently completed fiscal year, we entered into ajoint development agreement (“JDA”) with an industry partner.  The JDA provides that we operate the drillingof two firm commitment wells on our proved locations in the Giddings Field,with the potential to add up to three option wells as elected by ourpartner.  Under the terms of the JDA, wewill receive a 10% carried working interest in recognition of our costs todate, a 10% cost bearing working interest for our cash participation, and a22.5% 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-wellsimple pay-out on the subsequent wells (bringing our after-payout workinginterest to 38%).  The leases carryapproximately 80% net revenue interest to the 100% working interest.

 

The first location, the Supak-Brinkman-1H located inBurleson County, is a $1.7 million gross AFE re-entry operation to add a singleAustin Chalk lateral to an existing wellbore. We began operations on this location in late August, 2010.  We expect to follow with drilling operationson a $2.9 million gross AFE grass roots location (new well), the Dodd, innorthern Grimes County to complete two 4,000’ opposing laterals into theGeorgetown formation. Our outside engineers have assigned to the 100% workinginterest approximately 164,000 net BOE of proved reserves to the Supak and244,000 net BOE of reserves to the Dodd. The Dodd reserves are split evenly between proved and probable reservecategories.  Our share of expected netcapital expenditures for the JV program is $1.18 million, assuming all five wellsare drilled.  We are also exploringopportunities to enter into a second joint venture to develop additionaldrilling locations, which would require an increase in our capital subject tothe terms of such joint venture.

 

·                  **Increaseour Woodford Shale test activity.**  We plan to complete up to two more test wellsat our shallow 1,500’ depth Woodford acreage block in Wagoner County, OK duringfiscal 2011 to add to our knowledge base. Separately, in our mid-depth Haskell County, OK, Woodford Shaleleasehold, we expect to begin re-entry operations on the first of a twovertical well program to begin testing vertical completions in the Woodfordbetween 4,000’ and 6,000’ depth. We intend to use the information gained toattract candidates for joint venture development.

 

·                  **Pursuecommercial joint ventures utilizing our proprietary artificial lift technology.**  Based on tests results at Giddings, webelieve our technology could re-establish production in many wells throughoutGiddings and other fields developed with horizontal wells where liquids areassociated with their production.  We arecurrently negotiating with a major producer at Giddings, and have entered intodiscussions with a second producer, to provide our lift technology with theintent of gaining an interest in the newly re-established production.  We also plan on approaching other producersduring fiscal 2011 for potential applications both within and outside ofGiddings.

 

·                  **Continuetesting of our Neptune Oil Project in South Texas**.  Now that adequate water injection capacityexists in the field, we plan to conduct a workover on the Garcia #1 producer tore-complete in a different portion of the Mirando Sand and re-enter up to twoadditional producer wells to complete our testing program.

 

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·                  **Exerciselease options and renew other leases.**We plan to exercise leaseoptions and renew other leases to maintain high value drilling locations atGiddings and our leasehold in Oklahoma, as well as provide funds for forcedpooling associated with producing Woodford wells in Oklahoma.

 

***Continued conservativefinancial management.***

 

·                  **Emphasizelong-term share value over near-term earnings during the current period of lownatural gas prices.**

 

·                  **Retainfinancial strength and flexibility to assure we obtain proper value of our coreassets.**

 

·                  **Primarilyuse internally generated funds and our working capital to achieve our goals forfiscal 2011.**We may accelerate our development operations wherewarranted by utilizing joint ventures, project financing, selective divestmentsof noncore assets or minor equity offerings at attractive stock valuations whencapital market conditions improve.

 

·                  **Improvefinancial results through reductions in depletion expense and expectedincreases in Delhi production. **The fourfoldincrease in proved reserves, without a substantial increase in future capitalcosts, is expected to dramatically reduce our depletion expense in futureperiods.  When combined with our expectedrevenue growth from our Delhi royalty interests bearing no future operatingexpense or incremental expenditures for capital, our financial results are expectedto improve.

 

**Liquidityand Capital Resources**

 

AtJune 30, 2010, our working capital was $4.9 million and we continued to bedebt free.  This compares to workingcapital of $7.6 million at June 30, 2009. The $2.7 million decrease in working capital since June 30, 2009,was due primarily to investments of $3.7 million in oil and natural gasproperties (not including $0.1 million incurred related to recognition of assetretirement obligations).  Of the $3.7million of incurred capital expenditures during the year ended June 30,2010, $0.5 million was for leasehold acquisitions and $3.2 million was fordevelopment activities.  Developmentactivities were in the Giddings Field in Texas, our Neptune Oil Project in theLopez Field in South Texas, and our gas shale project in Eastern Oklahoma.

 

***Cash Flows from Operating Activities***

 

Cashflows provided by operating activities for the year ended June 30, 2010were $2.4 million.  Cash flows providedby operations include cash receipts of $5.0 million from oil and natural gassales, primarily from our properties in the Giddings Field, cash receipts of$2.1 million from the Internal Revenue Service due to our 2009 tax year netoperating loss carry-back, and interest received of $0.1 million.  Total cash received of $7.2 million waspartially offset by $4.5 million of cash payments for operating expenses,including lease operating expenses, production taxes, salaries and wages, andpayment of $0.3 million in state income taxes.

 

Cashflows provided by operating activities for the year ended June 30, 2009were $6.0 million.  Cash flows providedby operations for fiscal year ended June 30, 2009 included cash proceedsof $7.3 million from oil and natural gas production, primarily from ourproperties in the Giddings Field, cash proceeds of $0.1 million from interestincome and cash proceeds of $4.1 million from income tax refunds, primarilyfrom our 2008 tax year net operating loss carry-back.  Sources of cash were offset by $5.5 millionof cash payments for operating activities, including lease operating expenses,production taxes, salaries and wages and general administrative expense.

 

***Cash Flows from Investing Activities***

 

Cashpaid for oil and gas capital expenditures during the year ended June 30,2010 and 2009, was $3.8 million and $10.7 million, respectively, which includesnet payments on accounts payable of $0.1 million and $2.1 million,respectively, relating to prior period expenditures for oil and natural gasproperties.

 

Wepurchased $1.4 million and $1.8 million in short-term certificates of depositduring the year ended June 30, 2010 and 2009, respectively.  During the year ended June 30, 2010,$2.1 million of certificates of deposit matured.

 

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***Cash Flows from Financing Activities***

 

There were no significantcash flows from financing activities during the year ended June 30,2010.  During the previous fiscal year,on October 30, 2008, we repurchased 788,200 shares of common stock at anaverage price of $1.10 per share plus $0.02 in transaction costs from anunaffiliated accredited investor.

 

***Capital Budget***

 

Forour fiscal 2011 Plan, we expect to incur capital expenditures of approximately$4.0 million (for expenditure details, see the “Looking Forward” sectionabove).

 

Weexpect to fund our fiscal 2011 Plan with internally generated funds, ourworking capital and the JDA we signed in July 2010.  Increases in our activity level over theplanned operations will be funded from joint ventures, project financing,selective divestments of noncore assets or potentially from minor equityofferings at attractive stock valuations when capital market conditionsimprove.

 

**Resultsof Operations**

 

*Year ended June 30, 2010 comparedwith the year ended June 30, 2009*

 

The following table setsforth certain financial information with respect to our oil and natural gasoperations:

 
| ** **                                               | ** ** | **Year Ended** | ** ** | ** ** | ** ** | ** **   | ** ** |
|----------------------------------------------------------|------------|---------------------|------------|------------|------------|--------------|------------|
| ** **                                               | ** ** | **June 30**    | ** ** | ** ** | ** ** | **%**        | ** ** |
| ** **                                               | ** ** | **2010**            | ** ** | **2009**   | ** ** | **Variance** | ** ** | **change** | ** ** |
| ** **                                               | ** ** | ** **          | ** ** | ** ** | ** ** | ** **   | ** ** |   | ** ** |
| **Sales Volumes, net to the  Company:**                  | ** ** | ** **          | ** ** | ** ** | ** ** | ** **   | ** ** |   | ** ** |
|                                                     |       |                |       |       |       |         |       |   |   |
| Crude oil (Bbl)                                          |       | 29,749              |       | 36,026     |       | (6,277       | )          | (17 | )% |
|                                                     |       |                |       |       |       |         |       |   |   |
| NGLs (Bbl)                                               |       | 27,820              |       | 44,125     |       | (16,305      | )          | (36 | )% |
|                                                     |       |                |       |       |       |         |       |   |   |
| Natural gas (Mcf)                                        |       | 407,674             |       | 323,301    |       | 84,373       |       | 26 | % |
| Crude oil, NGLs and natural gas (BOE)                    |       | 125,515             |       | 134,035    |       | (8,520       | )          | (6 | )% |
|                                                     |       |                |       |       |       |         |       |   |   |
| **Revenue data:**                                        |       |                |       |       |       |         |       |   |   |
|                                                     |       |                |       |       |       |         |       |   |   |
| Crude oil                                                |       | $                   | 2,188,259  |       | $          | 2,747,494    |       | $ | (559,235 | ) | (20 | )% |
|                                                     |       |                |       |       |       |         |       |   |   |
| NGLs                                                     |       | 1,079,383           |       | 1,625,063  |       | (545,680     | )          | (34 | )% |
|                                                     |       |                |       |       |       |         |       |   |   |
| Natural gas                                              |       | 1,754,259           |       | 1,722,626  |       | 31,633       |       | 2 | % |
| Total revenues                                           |       | 5,021,901           |       | $          | 6,095,183  |         | $          | (1,073,282 | ) | (18 | )% |
|                                                     |       |                |       |       |       |         |       |   |   |
| **Average price:**                                       | ** ** | ** **          | ** ** | ** ** | ** ** | ** **   | ** ** |   | ** ** |
| Crude oil (per Bbl)                                      |       | $                   | 73.56      |       | $          | 76.26        |       | $ | (2.70 | ) | (4 | )% |
| NGLs (per Bbl)                                           |       | 38.80               |       | 36.83      |       | 1.97         |       | 5 | % |
| Natural gas (per Mcf)                                    |       | 4.30                |       | 5.33       |       | (1.03        | )          | (19 | )% |
| Crude oil, NGLs and natural gas (per BOE)                |       | $                   | 40.01      |       | $          | 45.47        |       | $ | (5.46 | ) | (12 | )% |
|                                                     |       |                |       |       |       |         |       |   |   |
| **Expenses (per BOE)**                                   | ** ** | ** **          | ** ** | ** ** | ** ** | ** **   | ** ** |   | ** ** |
| Lease operating expenses and production taxes            |       | $                   | 13.27      |       | $          | 10.69        |       | $ | 2.58 |   | 24 | % |
| Depletion expense on oil and natural gas  properties (a) |       | $                   | 14.10      |       | $          | 18.07        |       | $ | (3.97 | ) | (22 | )% |

 

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(a)   Excludes depreciation ofoffice equipment, furniture and fixtures, and other of $48,699 and $38,965, forthe year ended June 30, 2010 and 2009, respectively.

 

Netloss.  For the year ended June 30,2010, we reported a net loss of $2,387,707, or $0.09 loss per share (whichincludes $2,148,400 of non-cash stock-based compensation expense) on total oiland natural gas revenues of $5,021,901. This compares to a net loss of $2,601,593, or $0.10 loss per share(which includes $2,405,900 of non-cash stock-based compensation expense) ontotal oil and natural gas revenues of $6,095,183 for the year ended June 30,2009.  A decrease in our revenues of$1,073,282 was offset by decreases in operating costs of $1,199,426 (primarilyrelated to a decrease in G&A and depreciation, depletion, andamortization), and an increase in our income tax benefit of $154,960.  Additional details of the components of netloss are explained in greater detail below.

 

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Sales Volumes.  Crude oil, NGLs, and natural gas salesvolumes, net to our interest, for the year ended June 30, 2010 decreased6% to 125,515 BOE, compared to 134,035 BOE for the year ended June 30,2009.  Our sales volumes for the yearended June 30, 2010 included 6,333 Bbls of oil from Delhi (of which 5,721bbls of oil were sold during the 4th quarter of2010) and 119,182 BOE from our properties in the Giddings Field in Texas.

 

FirstEOR oil production at Delhi began in the last two weeks of March 2010.  Total production from Delhi, net to ourinterest, for the year ended June 30, 2010 was 6,333 Bbls of oil comparedto 172 Bbls of oil during the year ended June 30, 2009.

 

Productionfrom our properties in the Giddings Field decreased 11% from 133,863 BOE duringthe fiscal year ended June 2009 to 119,182 BOE during the fiscal yearended June 30, 2010. Production of natural gas from our properties in theGiddings Field increased 26%, while production of crude oil and NGLs decreased31% compared to the year ended June 30, 2009.

 

PetroleumRevenues.  Crude oil,NGLs and natural gas revenues for the year ended June 30, 2010 decreased18% from the year ended June 30, 2009. This was due to a 6% decline in sales volumes and a 12% decline in theaverage price received per BOE, from $45 per BOE for the year ended June 30,2009 to $40 per BOE for the year ended June 30, 2010.

 

LeaseOperating Expenses (including production severance taxes).  Lease operating expenses and production taxesfor the year ended June 30, 2010 increased 16% compared to the year endedJune 30, 2009, primarily due to the additions of three producing wells andan increase in workover expense from $232 thousand during fiscal 2009 to $452thousand during fiscal 2010.  Leaseoperating expense and production taxes per barrel of oil equivalent increased24% from $10.69 per BOE during fiscal 2009, to $13.27 per BOE during fiscal2010.

 

General and AdministrativeExpenses (“G&A”). G&A expenses decreased 14% to $5.1 million for the year endedJune 30, 2010, compared to $5.9 million for the year ended June 30,2009.  The reduction was due to adecrease in non-cash stock-based compensation expense, which was $2,148,400(42% of total G&A) and $2,405,900 (41% of total G&A) for the year endedJune 30, 2010 and 2009, respectively, and a reduction of legal fees ofapproximately $380 thousand due to the settlement of the Delhi litigation in July 2009.  Non-cash stock-based compensation is anintegral part of total staff compensation utilized to recruit quality stafffrom other, more established companies and, as a result, will likely continueto be a significant component of our G&A costs.

 

Depreciation,Depletion & Amortization Expense (“DD&A”).  DD&A decreased by 26% to $1,818,110 foryear ended June 30, 2010, compared to $2,461,162 for the year endedJune 30, 2009.  The decrease isprimarily due to a 6% decrease in net sales volumes, and a lower annualdepletion rate ($14.10 vs. $18.07) per BOE.

 

Our depletion rate for thefourth quarter of fiscal year 2010 was $4.39 per BOE compared to $17.23 for the3rd quarter of 2010, due to the addition of 9.4million proved oil reserves at Delhi with associated legacy costs of only $1.2million transferred to our full cost pool. The lower fourth quarter rate is the primary cause of the lower annualdepletion rate.

 

Interest Income.  Interest income for the year endedJune 30, 2010 decreased $67,218 to $55,054, compared to $122,272 for theyear ended June 30, 2009.  Thedecrease in interest income is due to lower average daily balances of cash andshort term certificates of deposit and a reduction in market interest ratesreceived on invested cash.

 

Inflation.  Although the general inflationrate in the United States, as measured by the Consumer Price Index and theProducer Price Index, has been relatively low in recent years, the oil and gasindustry has experienced unusually volatile price movements in commodityprices, vendor goods and oilfield services. Prices for drilling and oilfield services, oilfield equipment, tubulars,labor, expertise and other services greatly impact our lease operating expensesand our capital expenditures.  Duringfiscal 2009 and into fiscal 2010, we saw a substantial decline in bothpetroleum product prices and drilling and oilfield services costs from prioryears, followed more recently by moderate increases in products andservices.  Product prices, operatingcosts and development costs may not always move in tandem.

 

KnownTrends and Uncertainties. While general worldwide economic conditions improved during fiscal 2010,they continue to be uncertain and volatile.  Concerns over uncertainfuture economic growth are affecting numerous industries, companies, as well asconsumers, which impact demand for crude oil and natural gas.  Ifdemand decreases in the future, it may put downward pressure on crude oil andnatural gas prices, thereby lowering our revenues and working capital goingforward.

 

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Seasonality.  Our business is generally not directlyseasonal, except for instances when weather conditions may adversely affectaccess to our properties or delivery of our petroleum products.  Although we do not generally modify ourproduction for changes in market demand, we do experience seasonality in theproduct prices we receive, driven by summer cooling and driving, winterheating, and extremes in seasonal weather including hurricanes that maysubstantially affect oil and natural gas production and imports.

 

**Critical Accounting Policies andEstimates**

 

The preparation of financialstatements in accordance with accounting principles generally accepted in theUnited States of America requires that we select certain accounting policiesand make estimates and assumptions that affect the reported amounts of theassets and liabilities and disclosures of contingent assets and liabilities asof the date of the balance sheet as well as the reported amounts of revenuesand expenses during the reporting period. These policies, together with our estimates have a significant affect onour consolidated financial statements. Our significant accounting policies are included in Note 2 to theconsolidated financial statements. Following is a discussion of our most critical accounting estimates,judgments and uncertainties that are inherent in the preparation of ourconsolidated financial statements.

 

*Oil andNatural Gas Properties*.  Companies engaged in theproduction of oil and natural gas are required to follow accounting rules thatare unique to the oil and gas industry. We apply the full cost accounting method for our oil and natural gasproperties as prescribed by SEC Regulation S-X Rule 4-10.  Under this method of accounting, the costs ofunsuccessful, as well as successful, exploration and development activities arecapitalized as properties and equipment. This includes any internal costs thatare directly related to property acquisition, exploration and developmentactivities but does not include any costs related to production, generalcorporate overhead or similar activities. Gain or loss on the sale or otherdisposition of oil and gas properties is not recognized, unless the gain orloss would significantly alter the relationship between capitalized costs andproved reserves.  Oil and natural gasproperties include costs that are excluded from costs being depleted oramortized. Oil and natural gas property costs excluded represent investments inunevaluated properties and include non-producing leasehold, geological andgeophysical costs associated with leasehold or drilling interests andexploration drilling costs. We exclude these costs until the property has beenevaluated. Costs are transferred to the full cost pool as the properties areevaluated.  As of June 30, 2010, ourtotal unevaluated costs were $7.9 million. If these costs were evaluated and included in our full cost pool, withno increases in our proved reserves as of June 30, 2010, our depreciation,depletion and amortization expense would have increased by approximately $20thousand.

 

*Estimatesof Proved Reserves.*  The estimated quantities ofproved oil and natural gas reserves have a significant impact on the underlyingfinancial statements.  The estimatedquantities of proved reserves are used to calculate depletion expense, and theestimated future net cash flows associated with those proved reserves is thebasis in determining impairment under the quarterly ceiling testcalculation.  The process of estimatingoil and natural gas reserves is very complex, requiring significant decisionsin the evaluation of all available geological, geophysical, engineering andeconomic data. Estimated reserves are often subject to future revisions, whichcould be substantial, based on the availability of additional information,including reservoir performance, additional development activity, newgeological and geophysical data, additional drilling, technologicaladvancements, price changes and other economic factors.  As a result, material revisions to existingreserve estimates may occur from time to time. Although every reasonable effortis made to ensure that the reported reserve estimates represent the mostaccurate assessments possible, including the hiring of independent engineers toprepare our reserve estimates, the subjective decisions and variances inavailable data for the properties make these estimates generally less precisethan other estimates included in our financial statements.  Material revisions to reserve estimates and /or significant changes in commodity prices could substantially affect ourestimated future net cash flows of our proved reserves, affecting our quarterlyceiling test calculation and could significantly affect our depletionrate.  A 10% decrease in commodity pricesused to determine our proved reserves and Standardized Measure as of June 30,2010, would not have resulted in an impairment of our oil and natural gasproperties.  Holding all other factorsconstant, a reduction in the Company’s proved reserve estimate at June 30,2010 of 5%, 10% and 15% would affect depreciation, depletion and amortizationexpense by approximately $7 thousand, $16 thousand, and $25 thousand,respectively.

 

On December 31, 2008,the SEC issued its final rule on the modernization of reporting oil and gasreserves.  The new rule allowsconsideration of new technologies in evaluating reserves, allow companies todisclose their probable and possible reserves to investors, require reportingof oil and gas reserves using an average price based on the prior 12-monthperiod rather than year-end prices, revises the disclosure requirements for oiland gas operations, and revises accounting for the limitation on capitalizedcosts for full-cost companies.  The newrule became effective for our Annual Report on Form 10-K for the mostrecent fiscal ended June 30, 2010 and did not have a material affect onour financial statements.

 

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*Valuationof Deferred Tax Assets*.  We make certain estimatesand judgments in determining our income tax expense for financial reportingpurposes.  These estimates and judgmentsoccur in the calculation of certain tax assets and liabilities that arise fromdifferences in the timing and recognition of revenue and expense for tax andfinancial reporting purposes.  Ourfederal and state income tax returns are generally not prepared or filed beforethe consolidated financial statements are prepared or filed; therefore, weestimate the tax basis of our assets and liabilities at the end of each periodas well as the effects of tax rate changes, tax credits, and net operating losscarry backs and carry forwards. Adjustments related to these estimates are recorded in our tax provisionin the period in which we file our income tax returns. Further, we must assessthe likelihood that we will be able to recover or utilize our deferred taxassets (primarily our net operating loss). If recovery is not likely, we must record a valuation allowance againstsuch deferred tax assets for the amount we would not expect to recover, whichwould result in an increase to our income tax expense.  As of June 30, 2010, we have recorded avaluation allowance for the portion of our net operating loss that is limitedby IRS Section 382.

 

Management considers thescheduled reversal of deferred tax liabilities, projected future taxableincome, and tax planning strategies in making the assessment of the ultimaterealization of deferred tax assets.  Basedupon the level of historical taxable income and projections for future taxableincome over the periods for which the deferred tax assets are deductible, as ofend of the current fiscal year, we believe that it is more likely than not thatthe Company will realize the benefits of its net deferred tax assets. If ourestimates and judgments change regarding our ability to utilize our deferredtax assets, our tax provision would increase in the period it is determinedthat recovery is not probable.

 

*Stock-basedCompensation.*  We estimate the fair valueof stock option awards on the date of grant using the Black-Scholes optionpricing model.  This valuation methodrequires the input of certain assumptions, including expected stock pricevolatility, expected term of the award, the expected risk-free interest rate,and the expected dividend yield of the Company’s stock .  The risk-free interest rate used is the U.S.Treasury yield for bonds matching the expected term of the option on the dateof grant.  Our dividend yield is zero, aswe do not pay a dividend.  Because of ourlimited trading experience of our common stock and limited exercise history ofour stock option awards, estimating the volatility and expected term is verysubjective.  We base our estimate of ourexpected future volatility, on peer companies whose common stock has beentrading longer than ours, along with our own limited trading history whileoperating as an oil and natural gas producer. Future estimates of our stock volatility could be substantiallydifferent from our current estimate, which could significantly affect theamount of expense we recognize for our stock-based compensation awards.

 

**OffBalance Sheet Arrangements**

 

TheCompany has no off-balance sheet arrangements as of June 30, 2010.

 

**ITEM 7A.**** QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUTMARKET RISKS**

 

*Interest Rate Risk*

 

Weare exposed to changes in interest rates. Changes in interest rates affect theinterest earned on our cash and cash equivalents.  Under our current policies, we do not useinterest rate derivative instruments to manage exposure to interest ratechanges.

 

*Commodity Price Risk*

 

Our most significant marketrisk is the pricing for crude oil, natural gas and NGLs. We expect energyprices to remain volatile and unpredictable. If energy prices declinesignificantly, revenues and cash flow would significantly decline. In addition,a non-cash write-down of our oil and gas properties could be required underfull cost accounting rules if future oil and gas commodity pricessustained a significant decline. Prices also affect the amount of cash flowavailable for capital expenditures and our ability to borrow and raiseadditional capital, as, if and when needed. Although our current production base may not be sufficient enough toeffectively allow hedging, we may use derivative instruments to hedge ourcommodity price risk.

 

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**Item 8. Financial Statements**

 

**Index to Consolidated Financial Statements**

 
| Report of Independent Registered Public Accounting  Firm                                              | 42     |
|-------------------------------------------------------------------------------------------------------|--------|
|                                                                                                  |   |
| Consolidated Balance Sheets as of June 30, 2010  and 2009.                                       | 43     |
|                                                                                                  |   |
| Consolidated Statements of Operations for the Years ended  June 30, 2010 and 2009.               | 44     |
|                                                                                                  |   |
| Consolidated Statements of Cash Flows for the Years  ended June 30, 2010 and 2009.               | 45     |
|                                                                                                  |   |
| Consolidated Statements of Stockholders’ Equity for  the Years ended June 30, 2010 and 2009 | 46     |
|                                                                                                  |   |
| Notes to Consolidated Financial Statements                                                            | 47     |

 

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**REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

Board of Directors and Stockholders

Evolution Petroleum Corporation

Houston, Texas

 

We have audited the accompanying consolidated balancesheets of Evolution Petroleum Corporation as of June 30, 2010 and 2009 andthe related consolidated statements of operations, stockholders’ equity, andcash flows for each of the two years in the period ended June 30, 2010.  These consolidated financial statements arethe responsibility of the Company’s management. Our responsibility is toexpress an opinion on these consolidated financial statements based on ouraudits.

 

We conducted our audits in accordance with the standardsof the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audits to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements. An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation.We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statementsreferred to above present fairly, in all material respects, the consolidatedfinancial position of Evolution Petroleum Corporation as of June 30, 2010and 2009, and the consolidated results of its operations and its cash flows foreach of the two years in the period ended June 30, 2010 in conformity withaccounting principles generally accepted in the United States of America.

 

We were not engaged to examine management’s assertionabout the effectiveness of Evolution Petroleum Corporation’s internal controlsover financial reporting as of June 30, 2010 included in the accompanyingManagement’s Report on Internal Control over Financial Reporting and,accordingly, we do not express an opinion thereon.

 

 

HEIN & ASSOCIATES LLP

 

Houston, Texas

September 27, 2010

 

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**PART I — FINANCIALINFORMATION**

 

**ITEM 1. CONSOLIDATED FINANCIALSTATEMENTS**

 

**Evolution Petroleum Corporation and Subsidiaries**

**Consolidated Balance Sheets**

** **
| ** **                                                                                                                                                                                      | ** ** | **June 30,** | ** ** | **June 30,** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|-------------------|------------|
| ** **                                                                                                                                                                                      | ** ** | **2010**          | ** ** | **2009**          | ** ** |
| **Assets**                                                                                                                                                                                      | ** ** | ** **        | ** ** | ** **        | ** ** |
| Current assets                                                                                                                                                                                  |       |              |       |              |       |
| Cash and cash equivalents                                                                                                                                                                       |       | $                 | 3,138,259  |              | $          | 3,891,764 |   |
| Certificates of deposit                                                                                                                                                                         |       | 1,350,000         |       | 2,059,147         |       |
| Receivables                                                                                                                                                                                     |       |              |       |              |       |
| Oil and natural gas sales                                                                                                                                                                       |       | 536,366           |       | 532,318           |       |
| Income taxes                                                                                                                                                                                    |       | 25,200            |       | —            |       |
| Other                                                                                                                                                                                           |       | 147,059           |       | 172,314           |       |
| Income taxes recoverable                                                                                                                                                                        |       | 716,973           |       | 2,055,802         |       |
| Prepaid expenses and other current assets                                                                                                                                                       |       | 315,494           |       | 162,441           |       |
| Total current assets                                                                                                                                                                            |       | 6,229,351         |       | 8,873,786         |       |
|                                                                                                                                                                                            |       |              |       |              |       |
| Property and equipment, net of depreciation,  depletion, and amortization                                                                                                                       |       |              |       |              |       |
| Oil and natural gas properties — full-cost method  of accounting, of which $7,851,068 and $9,819,465 at June 30, 2010 and  2009, respectively, were excluded from amortization.       |       | 30,803,061        |       | 28,751,178        |       |
| Other property and equipment                                                                                                                                                                    |       | 101,998           |       | 150,697           |       |
| Total property and equipment                                                                                                                                                                    |       | 30,905,059        |       | 28,901,875        |       |
|                                                                                                                                                                                            |       |              |       |              |       |
| Other assets                                                                                                                                                                                    |       | 60,665            |       | 53,162            |       |
|                                                                                                                                                                                            |       |              |       |              |       |
| Total assets                                                                                                                                                                                    |       | $                 | 37,195,075 |              | $          | 37,828,823 |   |
|                                                                                                                                                                                            |       |              |       |              |       |
| **Liabilities  and Stockholders’ Equity**                                                                                                                                                  |       |              |       |              |       |
| Current liabilities                                                                                                                                                                             |       |              |       |              |       |
| Accounts payable                                                                                                                                                                                |       | $                 | 678,609    |              | $          | 690,639 |   |
| Accrued payroll                                                                                                                                                                                 |       | 75,692            |       | 71,427            |       |
| Royalties payable                                                                                                                                                                               |       | 221,062           |       | 218,477           |       |
| State taxes payable                                                                                                                                                                             |       | 202,334           |       | 157,736           |       |
| Other current liabilities                                                                                                                                                                       |       | 110,002           |       | 99,625            |       |
| Total current liabilities                                                                                                                                                                       |       | 1,287,699         |       | 1,237,904         |       |
|                                                                                                                                                                                            |       |              |       |              |       |
| Long term liabilities                                                                                                                                                                           |       |              |       |              |       |
| Deferred income taxes                                                                                                                                                                           |       | 2,949,880         |       | 3,721,317         |       |
| Asset retirement obligations                                                                                                                                                                    |       | 811,635           |       | 664,710           |       |
| Stock-based compensation (Note 6 and 15)                                                                                                                                                        |       | 587,033           |       | 370,440           |       |
| Deferred rent                                                                                                                                                                                   |       | 81,635            |       | 77,858            |       |
|                                                                                                                                                                                            |       |              |       |              |       |
| Total liabilities                                                                                                                                                                               |       | 5,717,882         |       | 6,072,229         |       |
|                                                                                                                                                                                            |       |              |       |              |       |
| Commitments  and contingencies (Note 12)                                                                                                                                                        |       |              |       |              |       |
|                                                                                                                                                                                            |       |              |       |              |       |
| Stockholders’ equity                                                                                                                                                                       |       |              |       |              |       |
| Preferred stock, par value $0.001; 5,000,000  shares authorized; no shares issued or outstanding                                                                                                |       | —            |       | —            |       |
| Common stock; par value $0.001; 100,000,000 shares  authorized; issued 27,849,576 shares; outstanding 27,061,376 shares and  26,530,317 shares as of June 30, 2010 and 2009, respectively. |       | 27,849            |       | 27,318            |       |
| Additional paid-in capital                                                                                                                                                                      |       | 18,532,643        |       | 16,424,868        |       |
| Retained earnings                                                                                                                                                                               |       | 13,798,723        |       | 16,186,430        |       |
|                                                                                                                                                                                            |       | 32,359,215        |       | 32,638,616        |       |
| Treasury stock, at cost, 788,200 shares as of June 30,  2010 and June 30, 2009.                                                                                                       |       | (882,022          | )          | (882,022          | )          |
|                                                                                                                                                                                            |       |              |       |              |       |
| Total stockholders’ equity                                                                                                                                                                 |       | 31,477,193        |       | 31,756,594        |       |
|                                                                                                                                                                                            |       |              |       |              |       |
| Total liabilities and stockholders’ equity                                                                                                                                                 |       | $                 | 37,195,075 |              | $          | 37,828,823 |   |

 

See accompanying notes to consolidated financial statements.

 

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**Evolution Petroleum Corporation and Subsidiaries**

**ConsolidatedStatements of Operations**

** **
| ** **                                            | ** ** | **Year Ended** | ** ** |
|-------------------------------------------------------|------------|---------------------|------------|
| ** **                                            | ** ** | **June 30,**   | ** ** |
| ** **                                            | ** ** | **2010**            | ** ** | **2009** | ** ** |
| Revenues                                              |       |                |       |   |   |
| Crude oil                                             |       | $                   | 2,188,259  |   | $ | 2,747,494 |   |
| Natural gas liquids                                   |       | 1,079,383           |       | 1,625,063 |   |
| Natural gas                                           |       | 1,754,259           |       | 1,722,626 |   |
| Total revenues                                        |       | 5,021,901           |       | 6,095,183 |   |
|                                                  |       |                |       |   |   |
| Operating Costs                                       |       |                |       |   |   |
| Lease operating expenses                              |       | 1,616,767           |       | 1,281,989 |   |
| Production taxes                                      |       | 48,312              |       | 158,794 |   |
| Depreciation, depletion and amortization              |       | 1,818,110           |       | 2,461,162 |   |
| Accretion of asset retirement obligations             |       | 61,054              |       | 37,601 |   |
| General and administrative expenses *                 |       | 5,092,243           |       | 5,896,366 |   |
| Total operating costs                                 |       | 8,636,486           |       | 9,835,912 |   |
|                                                  |       |                |       |   |   |
| Loss from operations                                  |       | (3,614,585          | )          | (3,740,729 | ) |
|                                                  |       |                |       |   |   |
| Other income                                          |       |                |       |   |   |
| Interest income                                       |       | 55,054              |       | 122,272 |   |
|                                                  |       |                |       |   |   |
| Net loss before income  tax benefit                   |       | (3,559,531          | )          | (3,618,457 | ) |
|                                                  |       |                |       |   |   |
| Income tax benefit                                    |       | 1,171,824           |       | 1,016,864 |   |
|                                                  |       |                |       |   |   |
| Net loss                                              |       | $                   | (2,387,707 | ) | $ | (2,601,593 | ) |
|                                                  |       |                |       |   |   |
| Loss per common share                                 |       |                |       |   |   |
| Basic and Diluted                                     |       | $                   | (0.09      | ) | $ | (0.10 | ) |
|                                                  |       |                |       |   |   |
| Weighted average number  of common shares outstanding |       |                |       |   |   |
| Basic and Diluted                                     |       | 27,004,066          |       | 26,461,057 |   |

 

----

*Generaland administrative expenses for the year ended June 30, 2010 and 2009included non-cash stock-based compensation expense of $2,148,400 and$2,405,900, respectively.

 

See accompanying notes to consolidated financial statements.

 

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**Evolution Petroleum Corporation and Subsidiaries**

**ConsolidatedStatements of Cash Flow**

 
| ** **                                                                       | ** ** | **Year Ended********June 30,** | ** ** |
|----------------------------------------------------------------------------------|------------|------------------------------------------|------------|
| ** **                                                                       | ** ** | **2010**                                 | ** ** | **2009** | ** ** |
| Cash flows from  operating activities                                            |       |                                     | ** ** | ** ** | ** ** |
| Net loss                                                                         |       | $                                        | (2,387,707 | ) | $ | (2,601,593 | ) |
| Adjustments to reconcile net loss to net cash  provided by operating activities: |       |                                     |       |   |   |
| Depreciation, depletion and amortization                                         |       | 1,818,110                                |       | 2,461,162 |   |
| Stock-based compensation                                                         |       | 2,148,400                                |       | 2,405,900 |   |
| Issuance of common stock for charitable donation                                 |       | —                                   |       | 28,600 |   |
| Accretion of asset retirement obligations                                        |       | 61,054                                   |       | 37,601 |   |
| Settlement of asset retirement obligations                                       |       | —                                   |       | (90,761 | ) |
| Deferred income taxes                                                            |       | (771,437                                 | )          | 819,388 |   |
| Deferred rent                                                                    |       | 3,777                                    |       | 3,777 |   |
| Other assets                                                                     |       | 5,717                                    |       | 6,236 |   |
| Changes in operating assets and liabilities:                                     |       |                                     |       |   |   |
| Receivables from oil and natural gas sales                                       |       | (4,048                                   | )          | 1,533,982 |   |
| Receivables from income taxes and other                                          |       | 1,512,041                                |       | 1,963,436 |   |
| Prepaid expenses and other current assets                                        |       | (153,053                                 | )          | 108,497 |   |
| Accounts payable and accrued expenses                                            |       | 65,144                                   |       | (624,333 | ) |
| Royalties payable                                                                |       | 2,585                                    |       | (254,850 | ) |
| Income taxes payable                                                             |       | 44,598                                   |       | 157,736 |   |
| Net cash provided by operating activities                                        |       | 2,345,181                                |       | 5,954,778 |   |
|                                                                             |       |                                     |       |   |   |
| Cash flows from  investing activities                                            |       |                                     |       |   |   |
| Development of oil and natural gas properties                                    |       | (3,280,425                               | )          | (8,063,465 | ) |
| Acquisitions of oil and natural gas properties                                   |       | (517,530                                 | )          | (2,603,098 | ) |
| Capital expenditures for other equipment                                         |       | —                                   |       | (28,635 | ) |
| Maturities of certificates of deposit                                            |       | 2,059,147                                |       | — |   |
| Purchases of certificates of deposit                                             |       | (1,350,000                               | )          | (1,757,312 | ) |
| Other assets                                                                     |       | (13,220                                  | )          | (4,715 | ) |
| Net cash used in investing activities                                            |       | (3,102,028                               | )          | (12,457,225 | ) |
|                                                                             |       |                                     |       |   |   |
| Cash flows from  financing activities                                            |       |                                     |       |   |   |
| Proceeds from issuance of restricted stock                                       |       | 42                                       |       | 130 |   |
| Proceeds from the exercise of stock options                                      |       | 3,300                                    |       | — |   |
| Purchase of treasury stock                                                       |       | —                                   |       | (882,022 | ) |
| Other                                                                            |       | —                                   |       | 3,823 |   |
| Net cash provided by (used in) financing  activities                             |       | 3,342                                    |       | (878,069 | ) |
|                                                                             |       |                                     |       |   |   |
| Net decrease in cash and cash equivalents                                        |       | (753,505                                 | )          | (7,380,516 | ) |
|                                                                             |       |                                     |       |   |   |
| Cash and cash equivalents, beginning of period                                   |       | 3,891,764                                |       | 11,272,280 |   |
|                                                                             |       |                                     |       |   |   |
| Cash and cash equivalents, end of period                                         |       | $                                        | 3,138,259  |   | $ | 3,891,764 |   |

 

See accompanying notes to consolidated financial statements.

 

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**Evolution Petroleum Corporation and Subsidiaries**

**ConsolidatedStatements of Changes in Stockholders’ Equity**

**For the Years ended June 30, 2010 and 2009**

 
| ** **                                                                                   | ** ** | ** **            | ** ** | ** **         | ** ** | **Additional** | ** ** | ** **   | ** ** | ** **             | ** ** | **Total**  | ** ** |
|----------------------------------------------------------------------------------------------|------------|-----------------------|------------|--------------------|------------|----------------|------------|--------------|------------|------------------------|------------|------------|------------|
| ** **                                                                                   | ** ** | **Common Stock** | ** ** | **Paid-in**        | ** ** | **Retained**   | ** ** | **Treasury** | ** ** | **Stockholders’** | ** ** |
| ** **                                                                                   | ** ** | **Shares**            | ** ** | **Par Value** | ** ** | **Capital**    | ** ** | **Earnings** | ** ** | **Stock**              | ** ** | **Equity** | ** ** |
| Balance, July 1, 2008                                                                   |       | 26,870,439            |       | $                  | 26,870     |           | $          | 14,188,841   |       | $                      | 18,788,023 |       | $          | — |   | $ | 33,003,734 |   |
| Issuance of common stock to certain employees in  lieu of partial payment of 2008 cash bonus |       | 46,795                |       | 47                 |       | 168,415        |       | —       |       | —                 |       | 168,462    |       |
| Issuance of restricted common stock                                                          |       | 390,283               |       | 390                |       | (260           | )          | —       |       | —                 |       | 130        |       |
| Issuance of common stock for charitable donation                                             |       | 11,000                |       | 11                 |       | 28,589         |       | —       |       | —                 |       | 28,600     |       |
| Purchase of 788,200 treasury shares                                                          |       | (788,200              | )          | —             |       | —         |       | —       |       | (882,022               | )          | (882,022   | )          |
| Other                                                                                        |       | —                |       | —             |       | 3,823          |       | —       |       | —                 |       | 3,823      |       |
| Stock-based compensation                                                                     |       | —                |       | —             |       | 2,035,460      |       | —       |       | —                 |       | 2,035,460  |       |
| Net loss                                                                                     |       | —                |       | —             |       | —         |       | (2,601,593   | )          | —                 |       | (2,601,593 | )          |
| Balance, June 30, 2009                                                                  |       | 26,530,317            |       | $                  | 27,318     |           | $          | 16,424,868   |       | $                      | 16,186,430 |       | (882,022   | ) | $ | 31,756,594 |   |
| Issuance of common stock to certain employees in  lieu of cash payment of 2009 bonus         |       | 138,224               |       | 138                |       | 370,302        |       | —       |       | —                 |       | 370,440    |       |
| Issuance of restricted common stock                                                          |       | 386,914               |       | 387                |       | (345           | )          | —       |       | —                 |       | 42         |       |
| Exercise of stock warrants                                                                   |       | 133,005               |       | 133                |       | (133           | )          | —       |       | —                 |       | —     |       |
| Exercise of stock options                                                                    |       | 3,000                 |       | 3                  |       | 3,297          |       | —       |       | —                 |       | 3,300      |       |
| Forfeiture of restricted common stock                                                        |       | (130,084              | )          | (130               | )          | 130            |       | —       |       | —                 |       | —     |       |
| Windfall tax benefit                                                                         |       | —                |       | —             |       | 173,157        |       | —       |       | —                 |       | 173,157    |       |
| Stock-based compensation                                                                     |       | —                |       | —             |       | 1,561,367      |       | —       |       | —                 |       | 1,561,367  |       |
| Net loss                                                                                     |       | —                |       | —             |       | —         |       | (2,387,707   | )          | —                 |       | (2,387,707 | )          |
| Balance, June 30, 2010                                                                  |       | 27,061,376            |       | $                  | 27,849     |           | $          | 18,532,643   |       | $                      | 13,798,723 |       | $          | (882,022 | ) | $ | 31,477,193 |   |

 

See accompanying notes to consolidated financial statements.

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIALSTATEMENTS**

 

**Note 1****—****Organization and Basis of Preparation**

 

***Nature of Operations.***  EvolutionPetroleum Corporation (“EPM”) and its subsidiaries (the “Company”, “we”, “our”or “us”), is an independent petroleum company headquartered in Houston, Texasand incorporated under the laws of the State of Nevada.  We are engaged primarily in the acquisition,exploitation and development of properties for the production of crude oil andnatural gas.  We acquire properties withknown oil and natural gas resources and exploit them through the application ofconventional and specialized technology to increase production, ultimaterecoveries, or both.

 

***Principles of Consolidation and Reporting.***  Our consolidated financial statements includethe accounts of EPM and its wholly-owned subsidiaries: NGS Sub Corp and itswholly owned subsidiary, Tertiaire Resources Company, NGS Technologies, Inc.,and Evolution Operating Corp.  Allsignificant intercompany transactions have been eliminated in consolidation.The consolidated financial statements for the previous year include certainreclassifications that were made to conform to the current presentation.  Such reclassifications have no impact onpreviously reported income or stockholders’ equity.

 

***Use of Estimates. ***The preparationof financial statements in conformity with accounting principles generally acceptedin the United States of America (“GAAP”) requires us to make estimates andassumptions that affect the reported amounts of assets and liabilities at thedates of the financial statements and the reported amounts of revenues andexpenses during the reporting periods. Significant estimates include reserve quantities and estimated futurecash flows associated with proved reserves, which significantly impactdepletion expense and potential impairments of oil and natural gas properties,income taxes and the valuation of deferred tax assets, stock-based compensationand commitments and contingencies.  Weanalyze our estimates based on historical experience and various otherassumptions that we believe to be reasonable. While we believe that ourestimates and assumptions used in preparation of the consolidated financialstatements are appropriate, actual results could differ from those estimates.

 

**Note 2****—****Summary of Significant Accounting Policies**

 

***Cash and CashEquivalents.***  We considerall highly liquid investments, with original maturities of 90 days or less whenpurchased, to be cash and cash equivalents.

 

***Allowance forDoubtful Accounts.***  Weestablish provisions for losses on accounts receivables if it is determinedthat collection of all or a part of an outstanding balance is notprobable.  Collectability is reviewedregularly and an allowance is established or adjusted, as necessary, using thespecific identification method.  As of June 30,2010 and 2009, no allowance for doubtful accounts was considered necessary.

 

***Oil and NaturalGas Properties*****.**  We use the full cost method of accounting forour investments in oil and natural gas properties.  Under this method of accounting, all costsincurred in the acquisition, exploration and development of oil and natural gasproperties, including unproductive wells, are capitalized.  This includes any internal costs that aredirectly related to property acquisition, exploration and developmentactivities but does not include any costs related to production, generalcorporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gasproperties is not recognized, unless the gain or loss would significantly alterthe relationship between capitalized costs and proved reserves.

 

Oil and natural gasproperties include costs that are excluded from costs being depleted oramortized. Excluded costs represent investments in unproved and unevaluatedproperties and include non-producing leasehold, geological and geophysicalcosts associated with leasehold or drilling interests and exploration drillingcosts. We exclude these costs until the project is evaluated and provedreserves are established or impairment is determined. Excluded costs arereviewed at least quarterly to determine if impairment has occurred. The amountof any evaluated or impaired oil and natural gas properties is transferred tocapitalized costs being amortized (the “Full-cost Pool”).

 

***Limitation on Capitalized Costs.***Under the full-cost methodof accounting, we are required, at the end of each fiscal quarter, to perform atest to determine the limit on the book value of our oil and natural gasproperties (the “Ceiling Test”). If the capitalized cost of our oil and naturalgas properties, net of accumulated amortization and related deferred incometaxes (the “Net Capitalized Costs”), exceed the “Ceiling”, this excess orimpairment is charged to expense and reflected as additional accumulateddepreciation, depletion and amortization or as a credit to oil and natural gasproperties.  The expense may not bereversed in future periods, even though higher oil and natural gas prices maysubsequently increase the Ceiling.  TheCeiling is defined as the sum of: (a) the present value, discounted at 10percent, and assuming continuation of existing economic

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 2****—****Summary of Significant Accounting Policies** (Continued)

 

conditions, of 1) estimatedfuture gross revenues from proved reserves, which is computed using oil andnatural gas prices determined as the unweighted arithmetic average of thefirst-day-of-the-month price for each month within the 12-month period prior tothe end of the reporting period (with consideration of price changes only tothe extent provided by contractual arrangements including hedging arrangementspursuant to SAB 103), less 2) estimated future expenditures (based on currentcosts) to be incurred in developing and producing the proved reserves; plus (b) thecost of properties not being amortized (pursuant to Reg. S-X Rule 4-10(c)(3)(ii)); plus (c) the lower of cost or estimated fair value ofunproven properties included in the costs being amortized; net of (d) therelated tax effects related to the difference between the book and tax basis ofour oil and natural gas properties.   OurCeiling Test did not result in an impairment of our oil and natural gasproperties during the years ended June 30, 2010 and 2009.

 

***Other Propertyand Equipment.***  Otherproperty and equipment includes buildings, data processing andtelecommunications equipment, office furniture and equipment, and other fixedassets. These items are recorded at cost and are depreciated using thestraight-line method based on expected lives of the individual assets or groupof assets, which ranges from three to five years. Repairs and maintenance costsare expensed in the period incurred.

 

***Asset Retirement Obligations*****.**  An asset retirement obligation associatedwith the retirement of a tangible long-lived asset is recognized as a liabilityin the period incurred, with an associated increase in the carrying amount ofthe related long-lived asset, our oil and natural gas properties. The cost ofthe tangible asset, including the asset retirement cost, is depleted over theuseful life of the asset. The asset retirement obligation is recorded at itsestimated fair value, measured by reference to the expected future cashoutflows required to satisfy the retirement obligation discounted at ourcredit-adjusted risk-free interest rate. Accretion expense is recognized overtime as the discounted liability is accreted to its expected settlement value.If the estimated future cost of the asset retirement obligation changes, anadjustment is recorded to both the asset retirement obligation and thelong-lived asset. Revisions to estimated asset retirement obligations can resultfrom changes in retirement cost estimates, revisions to estimated inflationrates and changes in the estimated timing of abandonment.

 

***Fair Value of FinancialInstruments.***  Ourfinancial instruments consist of cash and cash equivalents, certificates ofdeposit, accounts receivable, and accounts payable. The carrying amounts ofthese approximate fair value, due to the highly liquid nature of theseshort-term instruments.

 

***Stock-basedCompensation.**** *We record all share-basedpayment expense in our financial statements based on the fair value of theaward on the grant date.  We use theBlack-Scholes option-pricing model as the most appropriate fair-value methodfor our stock option awards.  Restrictedstock awards are valued using the market price of our common stock on the grantdate.  We record compensation cost, netof estimated forfeitures, for stock-based compensation awards over therequisite service period on a straight-line basis as the awards vest.  As each award vests, an adjustment is made tocompensation cost for any difference between the estimated forfeitures and theactual forfeitures related to the vested awards.

 

***RevenueRecognition.***  We recognizeoil and natural gas revenue from our interests in producing wells at the timethat title passes to the purchaser.  As aresult, we accrue revenues related to production sold for which we have notreceived payment.

 

***Depreciation,Depletion and Amortization.***  The depreciable base for oil and natural gasproperties includes the sum of all capitalized costs net of DD&A, estimatedfuture development costs and asset retirement costs not included in oil andnatural gas properties, less costs excluded from amortization. The depreciablebase of oil and natural gas properties is amortized using the unit-of-productionmethod. Other property including, leasehold improvements, office and computerequipment and vehicles which are stated at original cost and depreciated usingthe straight-line method over the useful life of the assets, which ranges fromthree to five years.

 

***Income Taxes*****.**  We recognize deferred tax assets andliabilities based on the differences between the tax basis of assets andliabilities and their reported amounts in the financial statements that mayresult in taxable or deductible amounts in future years. The measurement ofdeferred tax assets may be reduced by a valuation allowance based uponmanagement’s assessment of available evidence if it is deemed more likely thannot some or all of the deferred tax assets will not be realizable.  We recognize a tax benefit from an uncertainposition when it is more likely than not that the position will be sustainedupon examination, based on the technical merits of the position and will recordthe largest amount of tax benefit that is greater than 50% likely of beingrealized upon settlement with a taxing authority.

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 2****—****Summary of Significant Accounting Policies** (Continued)

 

***Earnings (loss) per share.***  Basic Earnings (loss) per share (“EPS”) iscomputed by dividing earnings or loss by the weighted-average number of commonshares outstanding less any non-vested restricted common stockoutstanding.  The computation of dilutedEPS is similar to the computation of basic EPS, except that the denominator isincreased to include the number of additional common shares that would havebeen outstanding if potential dilutive common shares had been issued.  Our potential dilutive common shares are ouroutstanding stock options, warrants, and non-vested restricted common stock.  The dilutive effect of our potential dilutivecommon shares is reflected in diluted EPS by application of the treasury stock method.  Under the treasury stock method, exercise ofstock options and warrants shall be assumed at the beginning of the period (orat time of issuance, if later) and common shares shall be assumed to be issued;the proceeds from exercise shall be assumed to be used to purchase common stockat the average market price during the period; and the incremental shares (thedifference between the number of shares assumed issued and the number of sharesassumed purchased) shall be included in the denominator of the diluted EPScomputation.  Potential dilutive commonshares are excluded from the computation if their effect is anti-dilutive.   Including potential dilutive common sharesin the denominator of a diluted EPS computation for continuing operationsalways will result in an anti-dilutive per-share amount when an entity has aloss from continuing operations and no potential dilutive common shares shallbe included in the computation of  dilutedEPS when a loss from continuing operations exists.

 

**Note 3 — Recent Accounting Pronouncements**

 

***New Accounting Standards.***  We disclose theexistence and potential effect of accounting standards issued but not yetadopted by us or recently adopted by us with respect to accounting standardsthat may have an impact on us in the future.

 

OnDecember 31, 2008, the SEC released new requirements for reporting oil andgas reserves (the “Modernization Requirements”).  The ModernizationRequirements, when effective, provide for consideration of current technologyin evaluating reserves, allow companies to disclose their probable and possiblereserves to investors, require reporting of oil and gas reserves using anaverage price based on the prior 12-month period rather than period-end prices,revise the disclosure requirements for oil and gas operations, and reviseaccounting for the limitation on capitalized costs for full costcompanies.  The Modernization Requirements are effective for fiscal yearsending on or after December 31, 2009. A company may not apply the Modernization Requirements to disclosures inquarterly reports prior to the first annual report in which the reviseddisclosures are required.  TheModernization Requirements did not have material affect on our financialstatements.

 

The SEC staff issued StaffAccounting Bulletin (“SAB”) 113 (“SAB 113”), which revises portions of theguidance included in SAB Topic 12, *Oil andGas Producing Activities.* Specifically, SAB 113 revises the relevant interpretive guidance in SABTopic 12 to conform it to the Modernization Requirements.

 

On January 6, 2010, theFinancial Accounting Standards Board (“FASB”) issued Accounting StandardsUpdate 2010-03 *Extractive Activities - Oiland Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures*,an update of ASC Topic 932 *ExtractiveActivities - Oil and Gas*(“Topic932”), which substantially aligns the reserve estimation, disclosurerequirements, and definitions of Topic 932 with the disclosure requirements ofthe Modernization Requirements issued by the SEC.

 

***EPS***

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 4 —****Property and Equipment**

 

Asof June 30, 2010 and June 30, 2009 our oil and natural gas propertiesand other property and equipment consisted of the following:

 
| ** **                                                   | ** ** | **June 30,********2010** | ** ** | **June 30,   2009** | ** ** |
|--------------------------------------------------------------|------------|-------------------------------|------------|-------------------------------|------------|
| **Oil and natural gas properties**                           |       |                          |       |                          |       |
| Property costs subject to amortization                       |       | $                             | 27,775,641 |                          | $          | 21,985,950 |   |
| Less: Accumulated depreciation, depletion, and  amortization |       | (4,823,648                    | )          | (3,054,237                    | )          |
| Unproved properties not subject to amortization              |       | 7,851,068                     |       | 9,819,465                     |       |
| Oil and natural gas properties, net                          |       | $                             | 30,803,061 |                          | $          | 28,751,178 |   |
|                                                         |       |                          |       |                          |       |
| **Other property and equipment**                             |       |                          |       |                          |       |
| Furniture, fixtures and office equipment, at cost            |       | 260,476                       |       | 260,476                       |       |
| Less: Accumulated depreciation                               |       | (158,478                      | )          | (109,779                      | )          |
| Other property and equipment, net                            |       | $                             | 101,998    |                          | $          | 150,697 |   |

 

Unprovedproperties not subject to amortization includes unevaluated acreage of $6.0 and$7.5 million as of June 30, 2010 and June 30, 2009, respectively,consisting of properties in the Giddings Field in Central Texas, the WoodfordShale trend in Oklahoma, and the Lopez Field in South Texas (our “Neptune OilProject”).    Unproved properties include$0.7 million and $2.0 million as of June 30, 2010 and June 30, 2009,respectively, of participating interests through royalty and overriding royaltyinterests aggregating 7.4% in the Delhi Holt Bryant Unit of the Delhi Field inLouisiana and a 23.9% after payout reversionary working interest in the DelhiHolt Bryant Unit along with a 23.9% working interest in certain other depths inthe Delhi Field.  Unproved propertiesalso include $1.2 million and $0.3 million as of June 30, 2010 and 2009,respectively, related to the drilling of three test wells and re-entry of fourtest wells on our acreage in Wagoner County in Oklahoma.  Production testing of our wells in Oklahomais ongoing.  Development of our unprovedproperties is expected to be completed within one to five years.  Our evaluation of impairment of unprovedproperties occurs, at a minimum, on a quarterly basis.

 

The following table providesa summary of costs that are not being amortized as of June 30, 2010, bythe fiscal year in which the costs were incurred:

 
| ** **                                          | ** ** | ** ** | ** ** | **During the Year Ended June 30,** | ** ** |
|-----------------------------------------------------|------------|------------|------------|-------------------------------------------------------------|------------|
| **Costs excluded from amortization** | ** ** | **Total**  | ** ** | **2010**                                                    | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|                                                |       |       |       |                                                        |       |   |   |   |   |   |   |
| Leasehold acquisition costs and other               |       | $          | 5,957,924  |                                                        | $          | 158,586 |   | $ | 1,135,971 |   | $ | 3,847,312 |   | $ | 816,056 |   |
| Royalty and overriding royalty interests            |       | 735,627    |       | —                                                      |       | 3,636 |   | — |   | 731,991 |   |
| Test drilling (exploration)                         |       | 1,157,517  |       | 865,211                                                     |       | 292,306 |   | — |   | — |   |
|                                                |       | $          | 7,851,068  |                                                        | $          | 1,023,797 |   | $ | 1,431,913 |   | $ | 3,847,312 |   | $ | 1,548,047 |   |

 

**Note 5****—****Asset Retirement Obligations**

 

Ourasset retirement obligations represent the estimated present value of theamount we will incur to plug, abandon and remediate our producing properties atthe end of their productive lives in accordance with applicable laws. Thefollowing is a reconciliation of the beginning and ending asset retirementobligation for the years ended June 30, 2010 and 2009:

 
| ** **                                                   | ** ** | **Year Ended** | ** ** |
|--------------------------------------------------------------|------------|---------------------|------------|
| ** **                                                   | ** ** | **2010**            | ** ** | **2009** | ** ** |
| **Asset retirement obligations —  beginning of period** |       | $                   | 664,710    |   | $ | 215,056 |   |
| Liabilities incurred                                         |       | 85,871              |       | 238,702 |   |
| Liabilities settled                                          |       | —              |       | (90,761 | ) |
| Accretion                                                    |       | 61,054              |       | 37,601 |   |
| Revisions to previous estimates                              |       | —              |       | 264,112 |   |
| **Asset retirement obligations —  end of period**       |       | $                   | 811,635    |   | $ | 664,710 |   |

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 6 — Stockholders’ Equity**

 

OnAugust 19, 2008, the Board of Directors authorized the issuance of 46,795shares of common stock to certain employees who elected to receive these sharesin lieu of a portion of their fiscal 2008 cash bonus.  The value of the shares issued was $168,462,based on the fair market value on the date of issuance, or $3.60 per share.

 

On October 30, 2008, werepurchased 788,200 shares of our common stock at an average price of $1.10 pershare, plus approximately $15,000 of transaction costs, from an unaffiliatedaccredited investor.  There is currentlyno plan to repurchase additional common shares.

 

On December 9, 2008,three outside directors each received 30,000 shares of restricted common stock,with a per share price of $1.20, as part of their board compensation forcalendar 2009.   The value of the sharesissued was $108,000, based on the fair market value on the date of issuance, or$1.20 per share.  All issuances of commonstock were subject to vesting terms per individual stock agreements, which isgenerally one year for directors.

 

On January 16 and February 10,2009, we issued 24,324 and 15,789 shares of restricted common stock,respectively, to a director as compensation for his services for calendar year2009.   The 15,789 share award waselected by the director in lieu of cash retainers for his board service duringcalendar 2009.   The value of the sharesissued was $60,000, based on the fair market value on the date ofissuance.  These issuances of commonstock are subject to vesting terms per the individual stock agreements, whichis generally one year for directors.

 

On May 29, 2009, weissued 11,000 shares of unregistered common stock to various non-profitentities as a charitable donation.  Werecognized an expense of $28,600 based on the per share price of $2.60 on thedate of issue.  These shares of commonstock are subject to restrictions on transfer and cannot be sold untilregistered or the earlier of April 17, 2014, or written release by a dulyappointed officer of the Company.

 

On June 19, 2009,pursuant to an offer by the Company as discussed in Note 7, we issued 260,170shares of restricted common stock to certain employees in exchange for stockoptions to purchase 449,390 shares of common stock with a weighted averageexercise price of $4.67.  See Note 7.

 

OnSeptember 8, 2009, the Board of Directors authorized and the Companyissued 138,224 unrestricted and fully vested shares of common stock from the2004 Stock Plan to certain employees for the payment of fiscal 2009bonuses.  The value of the shares issuedwas $370,440, based on the fair market value on the date of issuance, or $2.68per share.  The amount of bonus wasaccrued as of June 30, 2009 and recognized as a long-term liability. On September 8,2009, when the shares were issued, the liability was reclassified tostockholders’ equity.  See Note 7.

 

OnSeptember 8, 2009, the Board of Directors authorized and the Companyissued 324,597 shares of restricted common stock from the 2004 Stock Plan toemployees as a long-term incentive award. Total unrecognized stock-based compensation expense of $869,917 relatedto the long-term incentive award will be recognized ratably over a four year vestingperiod.  See Note 7.

 

OnOctober 27, 2009, 119,795 shares of common stock were issued through a netcashless exercise of a placement warrant. The placement warrant, which was issued to Cagan McAfee CapitalPartners, LLC (“CMCP”), a related party (See Note 10), on May 26, 2004 inconnection with a financing transaction, gave CMCP the right to purchase165,000 shares, with an exercise price of $1.00 per share.

 

OnNovember 10, 2009, 5,833 shares of common stock were issued through a netcashless exercise of a placement warrant. The placement warrant, issued on November 30, 2004 in connectionwith a financing transaction, gave the holder the right to purchase 10,000shares, with an exercise price of $1.50 per share.

 

On December 9, 2009, atotal of 42,317 shares of restricted common stock were issued to four outsidedirectors as part of their board compensation for calendar year 2010.  The value of the shares issued was $168,000,based on the fair market value on the date of issuance.  All issuances of common stock were subject tovesting terms per individual stock agreements, which is generally one year fordirectors.  See Note 7.

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 6 — Stockholders’ Equity**  (Continued)

 

On February 6, 2010, atotal of 38,182 shares of restricted common stock were forfeited by anemployee.  Total unrecognized  stock-based compensation expense related tothe shares was $187,965.  The shares werecancelled and are available for a future grant in the 2004 Stock Plan.  See Note 7.

 

On March 5, 2010, atotal of 20,000 shares of restricted stock were issued to a new employee as long-termincentive compensation.  The value of theshares issued was $90,000, based on the fair market value on the date ofissuance.  The shares are subject to afour year vesting term.  See Note 7.

 

OnApril 14, 2010 and April 16, 2010, a total of 7,377 shares of commonstock were issued through a net cashless exercise of a placement warrant.  The placement warrants, issued on June 22,2006 in connection with a financing transaction, gave the holder the right topurchase 12,000 shares, with an exercise price of $2.25 per share.

 

On June 14, 2010, anemployee of the Company exercised 3,000 stock options granted in 2005 at anexercise price of $1.10. See Note 7.

 

On June 19, 2010, atotal of 91,902 shares of restricted common stock were forfeited by an employee.  Total unrecognized  stock-based compensation expense related tothe shares was $436,522.  The shares werecancelled and are available for a future grant in the 2004 Stock Plan.  See Note 7.

 

**Note 7****—****Stock-Based Incentive Plan**

 

Wemay grant option awards to purchase common stock (the “Stock Options”),restricted common stock awards (“Restricted Stock”), and unrestricted and fullyvested common stock, to employees, directors, and consultants of the Companyand its subsidiaries under the Natural Gas Systems Inc. 2003 Stock Plan (the “2003Stock Plan”) and the Evolution Petroleum Corporation Amended and Restated 2004Stock Plan (the “2004 Stock Plan” or together, the “EPM Stock Plans”).  Option awards for the purchase of 600,000shares of common stock were issued under the 2003 Stock Plan.  The 2004 Stock Plan authorized the issuanceof 5,500,000 shares of common stock.  Noshares are available for grant under the 2003 Stock Plan and, as ofJune 30, 2010, 611,407 shares remain available for grant under the 2004Stock Plan.

 

Wehave also granted common stock warrants, as authorized by the Board ofDirectors, to employees in lieu of cash bonuses or as incentive awards toreward previous service or provide incentives to individuals to acquire aproprietary interest in the Company’s success and to remain in the service ofthe Company (the “Incentive Warrants”). These Incentive Warrants have similar characteristics of the StockOptions.  A total of 1,037,500 IncentiveWarrants have been issued, with Board of Directors approval, outside of the EPMStock Plans.  We have not issuedIncentive Warrants since the listing of our shares on the NYSE Amex (formerly,the American Stock Exchange) in July 2006.

 

***Short-term Incentive Compensation***

 

OnSeptember 8, 2009, the Board of Directors authorized the issuance of138,224 shares of common stock from the 2004 Stock Plan to certain employeesfor the payment of fiscal 2009 bonuses in lieu of cash.  The value of the shares issued was $370,440,based on the fair market value on the date of issuance, or $2.68 pershare.  The amount of bonus was accruedas of June 30, 2009, and recognized as a long term liability.  On September 8,2009, the liability was reclassified as additional paid-in capital.

 

OnSeptember 10, 2010, the Board of Directors authorized the issuance of106,927 shares of common stock from the 2004 Stock Plan to certain employeesfor the payment of fiscal 2010 bonuses in lieu of cash.  The value of the shares issued was $587,033,based on the fair market value on the date of issuance, or $5.49 pershare.  The amount of bonus was accruedas of June 30, 2010, and recognized as a long term liability.  On September 10,2010, the liability was reclassified as additional paid-in capital.

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 7****—****Stock-Based Incentive Plan**(Continued)

 

***Offer to Exchange***

 

Theextreme financial market volatility encountered during fiscal 2009 caused us toreassess the continued effectiveness of our outstanding stock options grantedto employees for the purposes of retention and equity participation.  Based on management’s analysis andconsiderable review, our Board of Directors approved an “exchange offer” toemployees with “out-of-the-money” options, excluding Executive Officers andDirectors.  Under the terms of the offer,each eligible option to purchase 1.727 shares could be exchanged for one shareof restricted common stock.  In return,the company and shareholders benefited by (i) re-establishing theretention incentive for nonexecutive employees, (ii) adding one additionalyear of vesting to all awards exchanged, as further described below, (iii) reduceddilution as the number of restricted shares issued was substantially less thanthe options exchanged and the exchanged options were returned to the 2004 Plan,and (iv) spread the expense of the incentives over a longer period oftime.

 

Accordingly,we filed a Tender Offer Statement on Schedule TO with the SEC on May 15,2009, and amendments on May 21, 2009, June 9, 2009, and a finalfiling on July 2, 2009 announcing termination of the offer, relating to anoffer by us to certain employees (excluding Named Executive Officers) toexchange certain outstanding Stock Options granted under the 2004 Stock Plan,with shares of Restricted Stock (the “Offer to Exchange”).  The Offer to Exchange expired onJune 19, 2009 (the “Expiration Date”).  Pursuant to the Offer toExchange, 449,390 eligible Stock Options were tendered and subsequentlycancelled, representing 54% of the total Stock Options that were eligible forexchange in the Offer to Exchange.  Theshares of common stock that were subject to the cancelled Stock Options will beavailable for future awards under our 2004 Stock Plan.  On June 19, 2009 the Company granted anaggregate of 260,170 shares of Restricted Stock in exchange for the StockOptions surrendered in the Offer to Exchange.

 

Wewill recognize the unrecognized compensation cost associated with the 449,390Stock Options cancelled pursuant to the Offer to Exchange of approximately$1,068,430 along with the incremental compensation cost of $78,891 ratably overthe vesting period of the Restricted Stock. The incremental compensation, determined on June 19, 2009, wasmeasured as the excess of the fair value of the Restricted Stock granted in theOffer to Exchange, over the fair value of the Stock Options surrendered priorto cancellation.  The price of our common stock as of June 19, 2009was $2.85, however, due to the stock-based compensation requirements, we willrecognize expense ratably over the vesting period of the Restricted Stockgranted in the Offer to Exchange of approximately $4.41 per share.

 

Theshares of Restricted Stock granted in the Offer to Exchange were unvested atthe time of grant and will become vested on the basis of continued service withthe Company in accordance with and subject to the terms of the Offer toExchange as follows:  If and to the extent the Stock Options surrenderedwere vested on the Expiration Date, the Restricted Stock exchanged for thosevested Stock Options will become vested on the first anniversary of the ExpirationDate, being June 19, 2010.  If and to the extent any Stock Optionssurrendered were not vested on the Expiration Date the Restricted Stockexchanged for those unvested Stock Options will become vested on the firstanniversary of the original vesting dates on which such unvested StockOptions would have otherwise become vested. The Restricted Stock granted pursuant to the Offer to Exchange will vestover a weighted average period of approximately four years.

 

***Stock Options and Incentive Warrants***

 

Non-cashstock-based compensation expense related to Stock Options and IncentiveWarrants for the year ended June 30, 2010 and 2009 was $985,060 and$1,786,055, respectively.

 

Therewere no Stock Options granted during the year ended June 30, 2010.  We granted Stock Options to purchase 591,090shares of common stock under the 2004 Stock Plan with a weighted averageexercise price of $4.27.  The exerciseprice was determined based on the market price of the Company’s common stock onthe date of grant.  The Stock Optionsgranted during the years ended June 30, 2009 generally vest quarterly, ona straight line basis, over a period of four years.  The Stock Options granted during the yearended June 30, 2009 have a contractual life of seven.  The weighted average assumptions used tocalculate the fair value of these Stock Options and the weighted average fairvalue of each option granted are as follows:

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 7****—****Stock-Based Incentive Plan**(Continued)

 
| ** **               | ** ** | **Year Ended** | ** ** |
|--------------------------|------------|---------------------|------------|
| ** **               | ** ** | **June 30,**   | ** ** |
| ** **               | ** ** | **2010**            | ** ** | **2009** | ** ** |
| Expected volatility      |       | —              |       | 87.1 | % |
| Expected dividends       |       | —              |       | — |   |
| Expected term (in years) |       | —              |       | 4.6 |   |
| Risk-free rate           |       | —              |       | 3.10 | % |
| Fair value               |       | —              |       | $ | 2.62 |   |
|                          |            |                     |            |  |  |  |

 

Weestimated the fair value of Stock Options and Incentive Warrants issued toemployees and directors at the date of grant using a Black-Scholes-Mertonvaluation model.  The risk-free rate isbased on the U.S. Treasury yield curve in effect at the time of grant.  The expected term (estimated period of timeoutstanding) of Stock Options and Incentive Warrants is based on the “simplified”method of the estimated expected term for “plain vanilla” options allowed bythe SEC Staff Accounting Bulletin (“SAB”) No. 107 and SAB No. 110,and varied based on the vesting period and contractual term of the StockOptions or Incentive Warrants.   Expected volatility is based on thehistorical volatility of the Company’s closing common stock price and that ofan evaluation of a peer group of similar companies trading activity.  Wehave not declared any cash dividends on the Company’s common stock.

 

Thefollowing summary presents information regarding outstanding Stock Options andIncentive Warrants as of June 30, 2010, and the changes during the fiscalyear: 

 
| ** **                                                              | ** ** | **Number of Stock  Options  and Incentive Warrants** | ** ** | **Weighted Average  Exercise Price** | ** ** | **Aggregate  Intrinsic Value  (1)** | ** ** | **Weighted  Average  Remaining  Contractual  Term (in  years)** | ** ** |
|-------------------------------------------------------------------------|------------|--------------------------------------------------------------------------|------------|------------------------------------------------|------------|------------------------------------------|------------|----------------------------------------------------------------------|------------|
|                                                                    |       |                                                                     |       |                                           |       |                                     |       |                                                                 |       |
| Stock Options and Incentive Warrants outstanding  at July 1, 2009  |       | 5,485,820                                                                |       | $                                              | 1.83       |                                     |       |                                                                 |       |   |
|                                                                    |       |                                                                     |       |                                           |       |                                     |       |                                                                 |       |
| Granted                                                                 |       | —                                                                   |       | —                                         |       |                                     |       |                                                                 |       |
| Exercised                                                               |       | (3,000                                                                   | )          | $                                              | 1.10       |                                     |       |                                                                 |       |   |
| Cancelled or forfeited                                                  |       | —                                                                   |       | —                                         |       |                                     |       |                                                                 |       |
| Expired                                                                 |       | —                                                                   |       | —                                         |       |                                     |       |                                                                 |       |
|                                                                    |       |                                                                     |       |                                           |       |                                     |       |                                                                 |       |
| Stock Options and Incentive Warrants outstanding  at June 30, 2010 |       | 5,482,820                                                                |       | $                                              | 1.83       |                                     | $          | 17,421,302                                                           |       | 5.4 |   |
|                                                                    |       |                                                                     |       |                                           |       |                                     |       |                                                                 |       |
| Vested or expected to vest at June 30, 2010                        |       | 5,482,820                                                                |       | $                                              | 1.83       |                                     | $          | 17,235,235                                                           |       | 5.4 |   |
|                                                                    |       |                                                                     |       |                                           |       |                                     |       |                                                                 |       |
| Exercisable at June 30, 2010                                       |       | 4,930,238                                                                |       | $                                              | 1.72       |                                     | $          | 16,235,235                                                           |       | 5.3 |   |

 

----

(1) Basedupon the difference between the market price of our common stock on the lasttrading date of the period ($5.01 as of June 30, 2010) and the StockOption or Incentive Warrant exercise price of in-the-money Stock Options andIncentive Warrants.

 

There were 3,000 StockOptions exercised during the year ended June 30, 2010 with an aggregateintrinsic value of $13,620.  There wereno Stock Options or Incentive Warrants that were exercised during the yearended June 30, 2009.

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 7****—****Stock-Based Incentive Plan**(Continued)

 

Asummary of the status of our unvested Stock Options and Incentive Warrants asof June 30, 2010 and the changes during the year ended June 30, 2010,is presented below:

 
| ** **                     | ** ** | **Number of  Stock Options********and Incentive  Warrants** | ** ** | **Weighted  Average Grant-  Date Fair Value** | ** ** |
|--------------------------------|------------|----------------------------------------------------------------------------|------------|--------------------------------------------------------------|------------|
|                           |       |                                                                       |       |                                                         |       |
| Unvested at July 1, 2009  |       | 1,091,912                                                                  |       | $                                                            | 1.97       |   |
|                           |       |                                                                       |       |                                                         |       |
| Granted                        |       | —                                                                     |       | —                                                       |       |
|                           |       |                                                                       |       |                                                         |       |
| Vested                         |       | (539,330                                                                   | )          | $                                                            | 1.90       |   |
|                           |       |                                                                       |       |                                                         |       |
| Forfeited                      |       | —                                                                     |       | —                                                       |       |
|                           |       |                                                                       |       |                                                         |       |
| Unvested at June 30, 2010 |       | 552,582                                                                    |       | $                                                            | 2.04       |   |

 

Duringthe years ended June 30, 2010 and 2009, there were 539,330 and 1,063,029Stock Options and Incentive Warrants that vested with a total grant date fairvalue of $1,024,727 and $1,870,931, respectively.

 

Thetotal unrecognized compensation cost at June 30, 2010, relating tonon-vested Stock Options and Incentive Warrants was $1,069,075.  Such unrecognized expense is expected to berecognized over a weighted average period of 1.5 years.

 

***Restricted Stock***

 

Stock-basedcompensation expense related to Restricted Stock grants for the years ended June 30,2010 and 2009 was $576,307 and $249,405, respectively.  See Note 6 for a detail of Restricted Stocktransactions during the years ended June 30, 2010 and 2009.

 

Thefollowing table sets forth the Restricted Stock transactions for the year endedJune 30, 2010:

 
| ** **                     | ** ** | **Number of  Restricted  Shares** | ** ** | **Weighted  Average  Grant-Date  Fair Value** | ** ** |
|--------------------------------|------------|----------------------------------------|------------|----------------------------------------------------|------------|
|                           |       |                                   |       |                                               |       |
| Unvested at July 1, 2009  |       | 390,283                                |       | $                                                  | 3.37       |   |
|                           |       |                                   |       |                                               |       |
| Granted                        |       | 386,914                                |       | $                                                  | 2.91       |   |
|                           |       |                                   |       |                                               |       |
| Vested                         |       | (243,954                               | )          | $                                                  | 2.26       |   |
|                           |       |                                   |       |                                               |       |
| Forfeited                      |       | (130,084                               | )          | $                                                  | 4.80       |   |
|                           |       |                                   |       |                                               |       |
| Unvested at June 30, 2010 |       | 403,159                                |       | $                                                  | 3.15       |   |

 

AtJune 30, 2010, unrecognized stock compensation expense related toRestricted Stock grants totaled $1,135,229. Such unrecognized expense will be recognized over a weighted averageperiod of 3.0 years.

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 8 —Supplemental Disclosure of Cash Flow Information**

 

Oursupplemental disclosures of cash flow information for the year ended June 30,2010 and 2009 are as follows:

 
| ** **                                                                                                                         | ** ** | **Year Ended** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|
| ** **                                                                                                                         | ** ** | **June 30,**   | ** ** |
| ** **                                                                                                                         | ** ** | **2010**            | ** ** | **2009** | ** ** |
| Income taxes paid:                                                                                                                 |       | $                   | 329,800    |   | $ | 15,000 |   |
|                                                                                                                               |       |                |       |   |   |
| Income tax refunds and net operating loss  carry-back received:                                                                    |       | $                   | 2,095,126  |   | 4,057,772 |   |
|                                                                                                                               |       |                |       |   |   |
| Non-cash transactions:                                                                                                             |       |                |       |   |   |
| Decrease in accounts payable used to acquire oil  and natural gas leasehold interests and develop oil and natural gas  properties: |       | $                   | (62,532    | ) | $ | (2,043,235 | ) |
| Oil and natural gas properties incurred through  recognition of asset retirement obligations:                                      |       | $                   | 85,871     |   | $ | 502,814 |   |
| Windfall tax benefit recognized in income taxes  recoverable:                                                                      |       | $                   | 173,157    |   | — |   |

 

**Note 9****—****Income Taxes**

 

Wefile a consolidated federal income tax return in the United States and variouscombined and separate filings in several state and local jurisdictions.

 

Therewere no unrecognized tax benefits nor any accrued interest or penaltiesassociated with unrecognized tax benefits during the year ended June 30,2010 and 2009.  We believe that we haveappropriate support for the income tax positions taken and to be taken on theCompany’s tax returns and that the accruals for tax liabilities are adequatefor all open years based on our assessment of many factors including pastexperience and interpretations of tax law applied to the facts of each matter.The Company’s federal and state income tax returns are open to audit under thestatute of limitations for the years ending June 30, 2007 through June 30,2009.

 

Thecomponents of our income tax benefit are as follows:

 
| ** **                                       | ** ** | **June 30,********2010** | ** ** | **June 30,  2009** | ** ** |
|--------------------------------------------------|------------|-------------------------------|------------|-------------------------|------------|
| **Current:**                                     |       |                          |       |                    |       |
| Federal                                          |       | $                             | (608,339   | )                       | $          | (1,993,988 | ) |
| State                                            |       | 207,952                       |       | 157,736                 |       |
| *Total current income tax  benefit*              |       | (400,387                      | )          | (1,836,252              | )          |
| **Deferred:**                                    |       |                          |       |                    |       |
| Federal                                          |       | (553,326                      | )          | 528,787                 |       |
| State                                            |       | (218,111                      | )          | 290,601                 |       |
| *Total deferred income tax  (benefit) provision* |       | (771,437                      | )          | 819,388                 |       |
| **Total income tax benefit**                     |       | $                             | (1,171,824 | )                       | $          | (1,016,864 | ) |

 

Thefollowing is a reconciliation of statutory income tax expense to our income taxprovision:

 
| ** **                                                      | ** ** | **June 30,********2010** | ** ** | **June 30,  2009** | ** ** |
|-----------------------------------------------------------------|------------|-------------------------------|------------|-------------------------|------------|
| **Income tax benefit computed at  the statutory federal rate:** |       | $                             | (1,210,241 | )                       | $          | (1,230,275 | ) |
| Reconciling items:                                              |       |                          |       |                    |       |
| State income taxes, net of federal tax benefit                  |       | (10,413                       | )          | 148,134                 |       |
| Stock-based compensation (primarily incentive  stock options)   |       | 105,402                       |       | 264,060                 |       |
| Deferred tax asset valuation adjustment                         |       | —                        |       | (152,588                | )          |
| Rate adjustment                                                 |       | (42,651                       | )          | 21,931                  |       |
| Other                                                           |       | (13,921                       | )          | (68,126                 | )          |
| **Income tax benefit**                                          |       | $                             | (1,171,824 | )                       | $          | (1,016,864 | ) |

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 9****—****Income Taxes**(Continued)

 

Deferredincome taxes primarily represent the net tax effect of temporary differencesbetween the carrying amounts of assets and liabilities for financial reportingpurposes and the amounts used for income tax purposes. The components of ourdeferred taxes are detailed in the table below:

 
| ** **                             | ** ** | **June 30,********2010** | ** ** | **June 30,  2009** | ** ** |
|----------------------------------------|------------|-------------------------------|------------|-------------------------|------------|
| **Deferred tax assets:**               |       |                          |       |                    |       |
| Non qualified stock-based compensation |       | $                             | 866,035    |                    | $          | 657,369 |   |
| Net operating loss carryforwards       |       | 5,389,065                     |       | 5,389,065               |       |
| AMT credit carryforward*               |       | 645,938                       |       | —                  |       |
| Other                                  |       | 21,306                        |       | 22,841                  |       |
| *Gross deferred tax assets*            |       | 6,922,344                     |       | 6,069,275               |       |
| Valuation allowance                    |       | (5,187,983                    | )          | (5,187,983              | )          |
| *Total deferred tax assets*            |       | 1,734,361                     |       | 881,292                 |       |
| **Deferred tax liability:**            |       |                          |       |                    |       |
| Oil and natural gas properties         |       | (4,684,241                    | )          | (4,602,609              | )          |
| *Total deferred tax liability*         |       | (4,684,241                    | )          | (4,602,609              | )          |
| **Net deferred tax liability**         |       | $                             | (2,949,880 | )                       | $          | (3,721,317 | ) |

 

----

*                      The total AMTcredit carryforward is $775,807.  Our netdeferred tax liability does not include $129,869 of AMT credit carryforwardassociated with the windfall tax benefit.

 

Weexpect to recover approximately $0.7 million in federal income taxes paidduring the tax year ended June 30, 2007, as a result of the carry-back ofour 2010 income tax loss.  Significantintangible drilling costs were incurred during the 2010 fiscal year, of which,we elected to deduct (expense) approximately $1.3 million for federal and stateincome tax purposes.    During the yearended June 30, 2009, we received approximately $2.1 million in federalincome taxes paid during the tax years ended June 30, 2007 and 2006, as aresult of the carry-back of our 2009 income tax loss.  Significant intangible drilling costs wereincurred during the 2009 fiscal year, of which, we elected to deduct (expense)approximately $4.8 million for federal and state income tax purposes.  Under GAAP, and specifically the full-cost accountingmethod, intangible drilling costs are capitalized as part of oil and naturalgas properties, and depleted using the unit-of-production method.  The deduction of intangible drilling costsresulted in a significant difference in the income tax and book basis of ouroil and natural gas properties.

 

AtJune 30, 2010, we have a federal tax loss carryforward of approximately$15.9 million that we acquired through the reverse merger in May 2004, ofwhich, approximately $0.6  million isavailable to us to use in equal amounts through 2023.  We have applied a valuation allowance againstthe portion of the federal tax loss carryforward that has been disallowedthrough IRC Section 382.

 

**Note 10****—****Related Party Transactions**

 

Laird Q. Cagan, a member ofour Board of Directors, is a Managing Director and co-owner of Cagan McAfeeCapital Partners, LLC (“CMCP”).  CMCP hasperformed financial advisory services to us pursuant to a written agreementamended in December 2008.  Alsopursuant to the Agreement, Mr. Cagan, as a registered representative ofColorado Financial Services Corporation and as a partner of CMCP, could serveas our placement agent in private equity financings, wherein CMCP could earncash fees equal to 8% of gross equity proceeds, declining to 4% subject to theamount of equity raised through CMCP, and a fixed 4% warrant fee.  We have not paid placement fees to CMCP underthis agreement since May 2006.

 

Eric A. McAfee, a majorshareholder of the Company, is also a Managing Director of CMCP.

 

OnOctober 27, 2009, we issued CMCP 119,795 shares of common stock through anet cashless exercise of a placement warrant. The placement warrant, which was issued to CMCP on May 26, 2004 inconnection with a financing transaction, gave CMCP the right to purchase165,000 shares of common stock, with an exercise price of $1.00 per share.

 

See also Note 6 for equitytransactions with related parties.

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 11 —****Net loss Per Share**

 

The following table setsforth the computation of basic and diluted loss per share:

 
| ** **                                                         | ** ** | **Year Ended********June 30,** | ** ** |
|--------------------------------------------------------------------|------------|------------------------------------------|------------|
| ** **                                                         | ** ** | **2010**                                 | ** ** | **2009** | ** ** |
| *Numerator*                                                        |       |                                     |       |   |   |
| Net loss                                                           |       | $                                        | (2,387,707 | ) | $ | (2,601,593 | ) |
|                                                               |       |                                     |       |   |   |
| *Denominator*                                                      |       |                                     |       |   |   |
| Weighted average number of common shares – basic  and diluted |       | 27,004,066                               |       | 26,461,057 |   |
|                                                               |       |                                     |       |   |   |
| Net Loss per common share – basic and diluted                 |       | $                                        | (0.09      | ) | $ | (0.10 | ) |

 

Outstandingpotentially dilutive securities as of June 30, 2010 are as follows:

 
| **Outstanding Potential Dilutive Securities**                       | ** ** | **Weighted  Average  Exercise Price** | ** ** | **Outstanding at  June 30, 2009** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|--------------------------------------------------|------------|
|                                                                               |       |                                       |       |                                             |       |
| Common stock warrants issued in connection with  equity and financing transactions |       | $                                          | 1.87       |                                             | 159,308    |   |
| Stock Options and Incentive Warrants                                               |       | $                                          | 1.83       |                                             | 5,482,820  |   |
| Total                                                                              |       | $                                          | 1.83       |                                             | 5,642,128  |   |

 

Outstandingpotentially dilutive securities as of June 30, 2009 are as follows:

 
| **Outstanding Potential Dilutive Securities**                       | ** ** | **Weighted  Average  Exercise Price** | ** ** | **Outstanding at  June 30, 2008** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|--------------------------------------------------|------------|
|                                                                               |       |                                       |       |                                             |       |
| Common stock warrants issued in connection with  equity and financing transactions |       | $                                          | 1.46       |                                             | 348,058    |   |
| Stock Options and Incentive Warrants                                               |       | $                                          | 1.83       |                                             | 5,485,820  |   |
| Total                                                                              |       | $                                          | 1.81       |                                             | 5,833,878  |   |

 

**Note 12 — Commitments and Contingencies**

 

Weare subject to various claims and contingencies in the normal course ofbusiness.  In addition, from time totime, we receive communications from government or regulatory agenciesconcerning investigations or allegations of noncompliance with laws orregulations in jurisdiction in which we operate.  We disclose such matters if we believe it isreasonably possible that a future event or events will confirm a loss throughimpairment of an asset or the incurrence of a liability. We establish reservesif we believe it is probable that a future event or events will confirm a lossand we can reasonably estimate such loss. Furthermore, we will disclose any matter that is unasserted if weconsider it probable that a claim will be asserted and there is a reasonablepossibility that the outcome will be unfavorable.

 

***Lease Commitments.***  We have a non-cancelable operating lease foroffice space that expires on August 1, 2016. Future minimum leasecommitments as of June 30, 2010 under this operating lease are as follows:

 
| **For the year ended June 30,** | ** ** | ** ** | ** ** |
|----------------------------------------------------------|------------|------------|------------|
| 2011                                                     |       | $          | 138,089    |   |
| 2012                                                     |       | 157,268    |       |
| 2013                                                     |       | 159,011    |       |
| 2014                                                     |       | 159,011    |       |
| 2015                                                     |       | 159,011    |       |
| Thereafter                                               |       | 172,262    |       |
| Total                                                    |       | $          | 944,652    |   |

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 12 — Commitments and Contingencies**(Continued)

 

Rentexpense for the year ended June 30, 2010 and 2009 was $138,823 and$149,397, respectively.

 

***Employment Contracts.***  We have entered into employment agreementswith the Company’s three senior executives. The employment contracts provide for a severance package for terminationby the Company for any reason other than cause or permanent disability, or inthe event of a constructive termination, that includes payment of base pay andcertain medical and disability benefits from six months to a year aftertermination.   The total contingentobligation under the employment contracts as of June 30, 2010 isapproximately $499,000.

 

**Note 13 — Concentrations of Credit Risk**

 

***Major Customers.***  We market all of our oil andnatural gas production from the properties we operate.  The majority of our operated gas, oil andcondensate production is sold to a variety of purchasers under short-term (lessthan 12 months) contracts at market-based prices. The following tableidentifies customers from whom we derived 10 percent or more our net oil andnatural gas revenues during the years ended June 30, 2010 and 2009.  Based on the current demand for oil andnatural gas and availability of other customers, we do not believe the loss ofany of these customers would have a significant affect on our operations or financialcondition.

 
| ** **                                   | ** ** | **Percent of Total Revenue**        | ** ** |
|----------------------------------------------|------------|----------------------------------------------------|------------|
| **Customer**                                 | ** ** | **Year Ended********June 30, 2010** | ** ** | **Year Ended********June 30, 2009** | ** ** |
|                                         |       |                                               |       |   |   |
| Enterprise Crude Oil LLC                     |       | 31                                                 | %          | — |   |
| Copano Field Services/Upper Gulf Coast, L.P. |       | 23                                                 | %          | 2 | % |
| Plains Marketing L.P.                        |       | 12                                                 | %          | 40 | % |
| ETC Texas Pipeline, LTD.                |       | 19                                                 | %          | 36 | % |
| DCP Midstream, LP                            |       | 15                                                 | %          | 16 | % |

 

***Accounts Receivable.***  Substantially all of our accounts receivableresult from oil and natural gas sales to third parties in the oil and naturalgas industry. This concentration of customers may impact our overall creditrisk in that these entities may be similarly affected by changes in economicand other conditions.

 

***Cash and Cash Equivalents and Certificates of Deposit.***  We are subject to concentrations of creditrisk with respect to our cash and cash equivalents, which we attempt tominimize by maintaining our cash and cash equivalents in high quality moneymarket funds. At times cash balances may exceed limits federally insured by theFederal Deposit Insurance Corporation (“FDIC”). Our certificates of deposit are below or at the maximum federallyinsured limit set by the FDIC.

 

**Note 14****—****Retirement Plan**

 

EffectiveFebruary 1, 2007, we implemented a 401(k) Savings Plan which coversall full-time employees.  At ourdiscretion, we may match a certain percentage of the employees’ contributionsto the plan. The matching percentage is currently 100% of the first 4% of eachparticipant’s compensation, vesting fully upon our contributions.  Our matching contribution to the plan was$87,846 and $58,884 for the years ended June 30, 2010 and 2009,respectively.

 

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** **

**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 15****—****Subsequent Events**

 

On August 9, 2010, atotal of 30,233 shares of restricted stock were issued to a new employee aslong-term incentive compensation.  Thevalue of the shares issued was $156,000, based on the fair market value on thedate of issuance.  The shares are subjectto a four year vesting term.

 

OnSeptember 10, 2010, the Board of Directors authorized and the Companyissued 106,927 shares of common stock from the 2004 Stock Plan to certainemployees for the payment of fiscal 2010 bonuses.  The value of the shares issued were $587,033,based on the fair market value on the date of issuance, or $5.49 pershare.  The amount of bonus was accruedas of June 30, 2010, and recognized as a long term liability.  On September 10, 2010, the liability wasreclassified to additional paid-in capital.

 

OnSeptember 10, 2010, the Board of Directors authorized and the Companyissued 240,478 shares of restricted common stock from the 2004 Stock Plan tocertain employees as a long-term incentive award.  Total unrecognized stock-based compensationexpense of $1,320,224 related to the long-term incentive award will berecognized ratably over a four year period as the restricted common stockvests.

 

**Note 16****—****Supplemental Disclosures about Oil and Natural Gas ProducingProperties (unaudited)**

 

***Costs incurred for oil andnatural gas property acquisition, exploration and development activities***

 

Thefollowing table summarizes costs incurred and capitalized in oil and naturalgas property acquisition, exploration and development activities.  Property acquisition costs are those costs incurredto lease property, including both undeveloped leasehold and the purchase ofreserves in place.  Exploration costsinclude costs of identifying areas that may warrant examination and examiningspecific areas that are considered to have prospects containing oil and naturalgas reserves, including costs of drilling exploratory wells, geological andgeophysical costs and carrying costs on undeveloped properties. Developmentcosts are incurred to obtain access to proved reserves, including the cost ofdrilling.  Development costs also includeamounts incurred due to the recognition of asset retirement obligations, of$85,871 and $502,814, during the years ended June 30, 2010 and 2009,respectively.

 
| ** **                                               | ** ** | **For the Years Ended June 30** | ** ** |
|----------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                               | ** ** | **2010**                                                 | ** ** | **2009** | ** ** |
|                                                     |       |                                                     |       |   |   |
| Oil and Natural Gas Activities                           |       |                                                     |       |   |   |
| Property acquisition costs:                              |       |                                                     |       |   |   |
| Proved property                                          |       | $                                                        | 391,785    |   | $ | 876,640 |   |
| Unproved property                                        |       | 185,154                                                  |       | 1,413,941 |   |
| Exploration costs                                        |       | 2,354,239                                                |       | 349,403 |   |
| Development costs                                        |       | 890,116                                                  |       | 6,486,158 |   |
| Total costs incurred for oil and natural gas  activities |       | $                                                        | 3,821,294  |   | $ | 9,126,142 |   |

 

***Estimated Net Quantities of Proved Oil and Natural Gas Reserves(Unaudited)***

 

Weadopted revised oil and gas reserve estimation and disclosure requirements asof June 30, 2010. The primary impact of the new disclosures is to conformthe definition of proved reserves with the Modernization Requirements, whichwere issued by the SEC at the end of calendar year 2008. The accountingstandards update revised the definition of proved oil and gas reserves to requirethat the average, first-day-of-the-month price during the 12-month periodbefore the end of the year rather than the year-end price, must be used whenestimating whether reserve quantities are economical to produce. This same12-month average price is also used in calculating the aggregate amount of (andchanges in) future cash inflows related to the standardized measure ofdiscounted future net cash flows. The rules also allow for the use ofreliable technology to estimate proved oil and gas reserves if thosetechnologies have been demonstrated to result in reliable conclusions aboutreserve volumes. The unaudited supplemental information on oil and gasexploration and production activities for 2010 has been presented in accordancewith the new reserve estimation and disclosure rules, which may not be appliedretrospectively. The 2008 and 2009 data are presented in accordance with oiland gas disclosure requirements effective during those periods. The effect ofapplying the new definition of reliable technology and other non-price relatedaspects of the updated

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 16****—****Supplemental Disclosures about Oil and Natural Gas ProducingProperties (unaudited)** (Continued)

 

rules didnot impact 2010 net proved reserve volumes. The effect of applying the 12-monthaverage price, versus the June 30, 2010 year-end price, increased provedreserves by less than 2% of total proved reserves. The standardized measure ofdiscounted future net cash flows as of June 30, 2010 increased byapproximately $8.5 million as a result of using the 12-month average pricerather than the year-end 2010 price.

 

Proved oil and natural gasreserves are estimated quantities of crude oil, natural gas and natural gasliquids that geological and engineering data demonstrate with reasonablecertainty to be recoverable in future years from known reservoirs underexisting economic and operating conditions. Proved developed oil and naturalgas reserves are reserves that can be expected to be recovered through existingwells with existing equipment and operating methods. There are uncertaintiesinherent in estimating quantities of proved oil and natural gas reserves,projecting future production rates, and timing of development expenditures.Accordingly, reserve estimates often differ from the quantities of oil andnatural gas that are ultimately recovered. All of our proved reserves are located in the United States. Thefollowing information about our proved oil and natural gas reserves wasprepared by independent reserve engineers:

 
| ** **                                    | ** ** | **Crude Oil********(Bbls)** | ** ** | **Natural Gas  Liquids********(Bbls)** | ** ** | **Natural Gas********(Mcf)** | ** ** | **BOE**    | ** ** |
|-----------------------------------------------|------------|----------------------------------|------------|---------------------------------------------|------------|-----------------------------------|------------|------------|------------|
|                                          |       |                             |       |                                        |       |                              |       |       |       |
| June 30, 2008                            |       | 952,041                          |       | 1,310,460                                   |       | 10,534,391                        |       | 4,018,233  |       |
| Revisions of previous estimates               |       | (92,729                          | )          | (272,689                                    | )          | (4,498,026                        | )          | (1,115,089 | )          |
| Purchases of minerals in place                |       | 122,662                          |       | 60,648                                      |       | 645,724                           |       | 290,931    |       |
| Production (sales volumes)                    |       | (36,026                          | )          | (44,125                                     | )          | (323,301                          | )          | (134,035   | )          |
| June 30, 2009                            |       | 945,948                          |       | 1,054,294                                   |       | 6,358,788                         |       | 3,060,040  |       |
| Revisions of previous estimates               |       | (113,487                         | )          | (19,147                                     | )          | 430,145                           |       | (60,943    | )          |
| Improved recovery, extensions and discoveries |       | 9,451,758                        |       | 29,300                                      |       | 381,695                           |       | 9,544,674  |       |
| Production (sales volumes)                    |       | (29,749                          | )          | (27,820                                     | )          | (407,674                          | )          | (125,515   | )          |
| June 30, 2010                            |       | 10,254,470                       |       | 1,036,627                                   |       | 6,762,954                         |       | 12,418,256 |       |
|                                          |       |                             |       |                                        |       |                              |       |       |       |
| **Proved developed reserves:**                |       |                             |       |                                        |       |                              |       |       |       |
| June 30, 2008                            |       | 96,167                           |       | 109,716                                     |       | 561,001                           |       | 299,383    |       |
| June 30, 2009                            |       | 104,731                          |       | 141,372                                     |       | 1,106,028                         |       | 430,441    |       |
| June 30, 2010                            |       | 706,053                          |       | 157,302                                     |       | 1,536,858                         |       | 1,119,498  |       |

 

Totalproved 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 improved recovery of 9,411,841barrels of proved oil reserves added to our properties in the Delhi Field,based on approximately $300 million of development capital spent by the Operatorsince project inception, the start-up of CO2 injection operations during fiscalyear 2010, and oil production response during fiscal year 2010.  The additions to our properties in the DelhiField along with extensions in Giddings and Oklahoma of 127,905 BOE, wereoffset by production of 125,515 BOE and negative revisions of 60,943 BOEprimarily related to the transfer of four well locations in the Lopez Field inSouth Texas from the proved classification to probable during 2010.

 

The revisions of previous estimates during ourfiscal year ended June 30, 2009, were due primarily to the decline in theprice of natural gas.  During the yearended June 30, 2008, the revisions ofprevious estimates were primarily due to the identification and separation of naturalgas liquids in 2008 and the effects of the new SEC guideline on PUD locationswith fractured reservoirs.  Natural gasliquids were not separately identified in the June 30, 2007 independentreport prepared by Von Gonten.

 

Purchasesof minerals in place during 2009 resulted from leasehold acquisitions of provedundeveloped reserves in the Giddings Field and in our Neptune Oil Project inSouth Texas.

 

Purchasesof minerals in place during 2008 resulted from leasehold acquisitions of provedundeveloped reserves that directly offset currently or historically productivewells in the same fracture trend in the Giddings Field.

 

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**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**Note 16****—****Supplemental Disclosures about Oil and Natural Gas ProducingProperties (unaudited)**(Continued)

 

***StandardizedMeasure of Discounted Future Net Cash Flows***

 

Future oil and natural gassales and production and development costs have been estimated using prices andcosts in effect at the end of the years indicated, as required by ASC 932, *Disclosures about Oil and Gas Producing Activities* (“ASC 932”).  ASC 932 requires that net cash flowamounts be discounted at 10%. Future production and development costs arecomputed by estimating the expenditures to be incurred in developing andproducing our proved oil and natural gas reserves assuming continuation ofexisting economic conditions. Future income tax expenses are computed byapplying the appropriate period-end statutory tax rates to the future pretaxnet cash flow relating to our proved oil and natural gas reserves, less the taxbasis of the related properties. The future income tax expenses do not giveeffect to tax credits, allowances, or the impact of general and administrativecosts of ongoing operations relating to the Company’s proved oil and naturalgas reserves.  Changes in the demand foroil and natural gas, inflation, and other factors make such estimatesinherently imprecise and subject to substantial revision. The table belowshould not be construed to be an estimate of the current market value of theour proved reserves.

 

The standardized measure ofdiscounted future net cash flows related to proved oil and natural gas reservesas of June 30, 2010 and 2009 are as follows:

 
| ** **                                                | ** ** | **For the Years Ended June 30** | ** **  |
|-----------------------------------------------------------|------------|----------------------------------------------------------|-------------|
| ** **                                                | ** ** | **2010**                                                 | ** **  | **2009** | ** ** |
|                                                      |       |                                                     |        |   |   |
| Future cash inflows                                       |       | $                                                        | 827,902,260 |   | $ | 127,639,699 |   |
| Future production costs and severance taxes               |       | (222,826,052                                             | )           | (36,128,247 | ) |
| Future development costs                                  |       | (34,024,112                                              | )           | (33,317,000 | ) |
| Future income tax expenses                                |       | (213,063,769                                             | )           | (15,697,532 | ) |
| Future net cash flows                                     |       | 357,988,327                                              |        | 42,496,920 |   |
| 10% annual discount for estimated timing of cash  flows   |       | (196,361,678                                             | )           | (18,947,129 | ) |
| Standardized measure of discounted future net cash  flows |       | $                                                        | 161,626,649 |   | $ | 23,549,791 |   |

 

Futurecash inflows represent expected revenues from production of period-endquantities of proved reserves based on the unweighted average offirst-day-of-the-month commodity prices for the year ended June 30, 2010and period-end commodity prices for the years ended June 30, 2009. Theunweighted average of first-day-of-the-month commodity prices over the period July 1,2009 through June 30, 2010 adjusted by lease for quality, transportationfees, energy content and regional price differentials related to provedreserves of crude oil and natural gas liquids approximated $73.88 and $39.91,respectively, and natural gas approximated $4.10 per MMbtu.  At June 30, 2009, the end-of-periodprices adjusted by lease for quality, transportation fees, energy content andregional price differentials related to proved reserves of crude oil andnatural gas liquids approximated $69.89 and $36.96 per barrel, respectively,and natural gas approximated $3.885 per MMbtu.

 

A summary of the changes inthe standardized measure of discounted future net cash flows applicable toproved crude oil, natural gas liquids, and natural gas reserves is as follows:

 
| ** **                                                                     | ** ** | **For the Years Ended June 30** | ** **  |
|--------------------------------------------------------------------------------|------------|----------------------------------------------------------|-------------|
| ** **                                                                     | ** ** | **2010**                                                 | ** **  | **2009** | ** ** |
|                                                                           |       |                                                     |        |   |   |
| Balance, beginning of year                                                     |       | $                                                        | 23,549,791  |   | $ | 97,072,641 |   |
| Net changes in sales prices and production costs  related to future production |       | 3,935,863                                                |        | (144,680,473 | ) |
| Changes in estimated future development costs                                  |       | (3,502,403                                               | )           | 24,399,826 |   |
| Sales of oil and gas produced during the period,  net of production costs      |       | (3,356,822                                               | )           | (4,654,400 | ) |
| Net change due to purchases of minerals in place                               |       | —                                                   |        | 2,683,261 |   |
| Net change due to extensions, discoveries, and  improved recovery              |       | 236,828,138                                              |        | — |   |
| Net change due to revisions in quantity estimates                              |       | (934,602                                                 | )           | (20,564,731 | ) |
| Development costs incurred during the period                                   |       | —                                                   |        | 5,960,423 |   |
| Accretion of discount                                                          |       | 3,582,622                                                |        | 13,315,725 |   |
| Net change in discounted income taxes                                          |       | (91,991,767                                              | )           | 50,903,834 |   |
| Other                                                                          |       | (6,484,171                                               | )           | (886,315 | ) |
| Balance, end of year                                                           |       | $                                                        | 161,626,649 |   | $ | 23,549,791 |   |

 

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**Item 9.  Changes In and Disagreements with Accountantson Accounting and Financial Disclosure**

 

None.

 

**Item 9A. Controls and Procedures**

 

**DisclosureControls and Procedures**

 

We maintain disclosurecontrols and procedures that are designed to ensure that information requiredto be disclosed in our Exchange Act reports is recorded, processed, summarizedand reported within the time periods specified in the Securities and ExchangeCommission’s rules and forms and that such information is accumulated andcommunicated to this Company’s management, including our Chief ExecutiveOfficer and Chief Financial Officer, as appropriate to allow for timelydecisions regarding required disclosure.

 

As required by Securitiesand Exchange Commission Rule 13a-15(b), we carried out an evaluation,under the supervision and with the participation of the Company’s management,including our Chief Executive Officer and the Company’s Chief FinancialOfficer, of the effectiveness of the design and operation of our disclosurecontrols and procedures as of the end of the period covered by this report.Based on this evaluation, our Chief Executive Officer and Chief FinancialOfficer concluded that our disclosure controls and procedures are effective in ensuringthat the information required to be disclosed in our reports filed or submittedunder the Exchange Act is recorded, processed, summarized and reported withinthe time periods specified in the Securities and Exchange Commission rules andforms.

 

**Management’sReport on Internal Control Over Financial Reporting**

 

The Company’s management isresponsible for establishing and maintaining adequate internal control overfinancial reporting, (as defined in Rules 13a-15(f) and 15d-15(f) ofthe Exchange Act), as a process designed by, or under the supervision of, thecompany’s principal executive and principal financial officers and effected bythe Company’s board of directors, management and other personnel, to providereasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance withaccounting principles generally accepted in the United States of America andincludes those policies and procedures that:

 

·                  Pertain to themaintenance of records that in reasonable detail accurately and fairly reflectthe transactions and dispositions of the assets of the company;

 

·                  Providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with accounting principlesgenerally accepted in the United States of America and that receipts andexpenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and

 

·                  Providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use or disposition of the company’s assets that could have amaterial affect on the financial statements.

 

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements. Therefore, even those systems determined to be effectivecan provide only reasonable assurance with respect to financial statementpreparation and presentation.  Also,projections of any evaluation of effectiveness to future periods are subject torisk that controls may become inadequate because of changes in conditions, orthat the degree of compliance with the policies or procedures maydeteriorate.  Under the supervision andwith the participation of management, including the Chief Executive Officer andthe Chief Financial Officer, an evaluation was conducted on the effectivenessof the Company’s internal control over financial reporting based on criteriaestablished in the Internal Control—Integrated Framework issued by theCommittee of Sponsoring Organizations of the Treadway Commission.  Management concluded that the Companymaintained effective internal control over financial reporting as of June 30,2010.

 

This annual report does notinclude an attestation report of the Company’s registered public accountingfirm regarding internal control over financial reporting.  Management’s report was not subject toattestation by the Company’s registered public accounting firm pursuant to rules ofthe Securities and Exchange Commission.

 

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**Changes inInternal Control Over Financial Reporting**

 

There has been no change inthe Company’s internal control over financial reporting during the fourthquarter ended June 30, 2010 that has materially affected, or is reasonablylikely to materially affect, the Company’s internal control over financialreporting.

 

**Item 9B. Other Information**

 

None.

 

**PART III**

 

**Item 10. Directors, Executive Officers And Corporate Governance**

 

Incorporatedby reference to the Company’s Proxy Statement to be filed with the Commissionpursuant to Regulation 14A within 120 days of the end of the Company’s 2010fiscal year.

 

**Item 11. Executive Compensation**

 

Incorporatedby reference to the Company’s Proxy Statement to be filed with the Commissionpursuant to Regulation 14A within 120 days of the end of the Company’s 2010fiscal year.

 

**Item 12.****Security Ownership****of Certain Beneficial Owners and Management and Related StockholderMatters**

 

Incorporatedby reference to the Company’s Proxy Statement to be filed with the Commissionpursuant to Regulation 14A within 120 days of the end of the Company’s 2010fiscal year.

 

**Item 13. Certain Relationships and RelatedTransactions, Director Independence**

 

Incorporatedby reference to the Company’s Proxy Statement to be filed with the Commissionpursuant to Regulation 14A within 120 days of the end of the Company’s 2010fiscal year.

 

**Item 14. Principal Accountant Fees and Services**

 

Incorporatedby reference to the Company’s Proxy Statement to be filed with the Commissionpursuant to Regulation 14A within 120 days of the end of the Company’s 2010fiscal year.

 

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**PART IV.**

 

**Item 15.  Exhibits and FinancialStatement Schedules**

 

The following documents are filed as part of this report:

 
| **1.** | **Financial Statements.**                                                                                                                                                                                                                                                                                                                                                                                          |   |
|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
|   |                                                                                                                                                                                                                                                                                                                                                                                                               |   |
|   | **Our consolidated financial statements are included in  Part II, Item 8 of this report:**                                                                                                                                                                                                                                                                                                               |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                               |   |
|   | Report  of Independent Registered Public Accounting Firm                                                                                                                                                                                                                                                                                                                                                           |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                               |   |
|   | Consolidated  Balance Sheets                                                                                                                                                                                                                                                                                                                                                                                       |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                               |   |
|   | Consolidated  Statements of Operations                                                                                                                                                                                                                                                                                                                                                                             |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                               |   |
|   | Consolidated  Statements of Cash Flows                                                                                                                                                                                                                                                                                                                                                                             |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                               |   |
|   | Consolidated  Statements of Stockholders’ Equity                                                                                                                                                                                                                                                                                                                                                              |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                               |   |
|   | Notes  to the Consolidated Financial Statements                                                                                                                                                                                                                                                                                                                                                                    |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                               |   |
| **2.** | **Financial Statements Schedules and supplementary  information required to be submitted:**                                                                                                                                                                                                                                                                                                                        |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                               |   |
|   | None.                                                                                                                                                                                                                                                                                                                                                                                                              |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                               |   |
| **3.** | **Exhibits**                                                                                                                                                                                                                                                                                                                                                                                                       |   |
|   |                                                                                                                                                                                                                                                                                                                                                                                                               |   |
|   | A  list of the exhibits filed or furnished with this report on Form 10-K  (or incorporated by reference to exhibits previously filed or furnished by  us) is provided in the Exhibit Index of this report.  Those  exhibits incorporated by reference herein are indicated as such by the  information supplied in the parenthetical thereafter.  Otherwise, the  exhibits are filed herewith. |   |

 

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**SIGNATURES**

 

Inaccordance with Section 13 or 15(d) of the Securities Exchange Act of1934, the registrant caused this report to be signed on its behalf by theundersigned, thereunto duly authorized in the City of Houston, Texas, on thedate indicated.

 

**Evolution Petroleum Corporation**

 
|                            | *By:*    | */s/*    | *ROBERT S. HERLIN*                                |
|---------------------------------|----------|----------|---------------------------------------------------|
|                            | * * | * * | *Robert S. Herlin*                                |
|                            | * * | * * | *Chairman, President and Chief Executive Officer* |
|                            | * * | * * | *(Principal Executive Officer)*                   |
|                            | * * | * * | * *                                          |
| *Date: September 27, 2010* | * * | * * | * *                                          |

 

 

Inaccordance with the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the registrant and in thecapacities and on the dates indicated.

 
| **Date**                  | ** ** | **Signature** | ** **              | **Title** |
|---------------------------|------------|---------------|-------------------------|-----------|
|                      |       |          |                    |      |   |
| *September 27, 2010* |       | */s/*         | *ROBERT S. HERLIN*      |      | *Chairman of the Board, President and Chief* |
| * *                  |       |          | *Robert S. Herlin*      |      | *Executive Officer (Principal Executive Officer)* |
|                      |       |          |                    |      |   |
| *September 27, 2010* |       | */s/*         | *STERLING  H. MCDONALD* |      | *Vice President and Chief Financial Officer* |
|                      |       |          | *Sterling  H. McDonald* |      | *(Principal Financial Officer)* |
|                      |       |          |                    |      |   |
| *September 27, 2010* |       | */s/*         | *GREG  S. GOODALE*      |      | *Chief  Accounting Officer* |
|                      |       |          | *Greg  S. Goodale*      |      | *(Principal  Accounting Officer)* |
|                      |       |          |                    |      |   |
| *September 27, 2010* |       | */s/*         | *EDWARD J. DIPAOLO*     | * *  | *Director* |
|                      |       |          | *Edward J. DiPaolo*     |      |   |
|                      |       |          |                    |      |   |
| *September 27, 2010* |       | */s/*         | *GENE STOEVER*          | * *  | *Director* |
|                      |       |          | *Gene Stoever*          |      |   |
|                      |       |          |                    |      |   |
| *September 27, 2010* |       | */s/*         | *WILLIAM DOZIER*        | * *  | *Director* |
|                      |       |          | *William Dozier*        |      |   |
|                      |       |          |                    |      |   |
| *September 27, 2010* |       | */s/*         | *KELLY W. LOYD*         | * *  | *Director* |
|                      |       |          | *Kelly W. Loyd*         |      |   |
|                      |       |          |                    |      |   |
| *September 27, 2010* |       | */s/*         | *LAIRD Q. CAGAN*        | * *  | *Director* |
| * *                  |       |          | *Laird Q. Cagan*        |      | * * |

 

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**INDEX OF EXHIBITS**

 

**MASTER EXHIBIT INDEX**

 
| **EXHIBIT   NUMBER** | ** ** | **DESCRIPTION**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
|---------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2.1                       |       | Asset  Purchase Agreement for Tullos Field, dated September 3, 2004 (Previously  filed as an exhibit to Form 8-K on September 9, 2004)                                                                                                                                                                                                                                                                                                                                                   |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 2.2                       |       | Definitive  Asset Purchase Agreement, dated as of February 2, 2005, by and between  Chadco, Inc., Alan Chadwick McCartney, Sonya McCartney and NGS Sub.  Corp. (Previously filed as an exhibit in Form 8-K on February 8,  2005)                                                                                                                                                                                                                                                    |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 2.3                       |       | Purchase  and Sale Agreement, by and between NGS Sub Corp. and Denbury Onshore, LLC,  dated May 8, 2006 (Previously filed as an exhibit to Form 8-K on  May 11, 2006)                                                                                                                                                                                                                                                                                                                    |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 2.4                       |       | Purchase  and Sale Agreement I, by and between NGS Sub Corp. and Denbury Onshore, LLC,  dated May 8, 2006 (Previously filed as an exhibit to Form 8-K on  June 16, 2006)                                                                                                                                                                                                                                                                                                                 |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 2.5                       |       | Purchase  and Sale Agreement II, by and between NGS Sub Corp. and Denbury Onshore, LLC,  dated May 8, 2006 (Previously filed as an exhibit to Form 8-K on  June 16, 2006)                                                                                                                                                                                                                                                                                                                |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 2.6                       |       | Conveyance,  Assignment and Bill of Sale Agreement, by and between NGS Sub Corp. and  Denbury Onshore, LLC, dated May 8, 2006 (Previously filed as an exhibit  to Form 8-K on June 16, 2006)                                                                                                                                                                                                                                                                                             |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 2.7                       |       | Agreement  and Plan of Reorganization dated as of April 12, 2004 among Reality  Interactive, Inc., Reality Acquisition Corp., Global Marketing  Associates, Inc., Dean H. Becker and Natural Gas Systems, Inc.  (incorporated by reference to the Current Report on Form 8-K/A filed by  Natural Gas Systems, Inc. with the Securities and Exchange Commission on  April 27, 2004) (Previously filed as an exhibit to Form Schedule  13D on July 11, 2008) |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 3.1                       |       | Articles  of Incorporation (Previously filed as an exhibit to the Company’s Current  Report on Form 8-K on February 7, 2002)                                                                                                                                                                                                                                                                                                                                                             |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 3.2                       |       | Certificate  of Amendment to Articles of Incorporation (Previously filed as an exhibit to  the Company’s Current Report on Form 8-K on February 7, 2002)                                                                                                                                                                                                                                                                                                                                 |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 3.3                       |       | Certificate  of Amendment to Articles of Incorporation (Previously filed as an exhibit to  Form SB 2/A on October 19, 2005)                                                                                                                                                                                                                                                                                                                                                                   |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 3.4                       |       | Bylaws  (Previously filed as an exhibit to the Company’s Current Report on  Form 8-K on February 7, 2002)                                                                                                                                                                                                                                                                                                                                                                                |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 3.5                       |       | Amended  Bylaws (Previously filed as an exhibit to Form 10KSB on March 31,  2004)                                                                                                                                                                                                                                                                                                                                                                                                             |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 4.1                       |       | Form of  Stock Option Agreement for the Natural Gas Systems 2004 Stock Plan  (Previously filed as an exhibit to the Current Report on Form 8—K on  April 8, 2005)                                                                                                                                                                                                                                                                                                                   |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 4.2                       |       | Articles  of Merger (Previously filed as an exhibit to Form SB — 2/A on  October 19, 2005)                                                                                                                                                                                                                                                                                                                                                                                               |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 4.3                       |       | Form of  Warrant Agreement between Natural Gas Systems, Inc. and Tatum CFO  Partners, LLP (Previously filed as an exhibit to the Company’s Current Report  on Form 8-K on April 8, 2005)                                                                                                                                                                                                                                                                                       |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 4.4                       |       | Revocable  Warrant Agreement between Natural Gas Systems, Inc. and Daryl V.  Mazzanti (Previously filed as an exhibit to the Company’s Current Report on  Form 8-K on June 29, 2005)                                                                                                                                                                                                                                                                                                |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 4.5                       |       | Specimen  form of the Company’s Common Stock Certificate (Previously filed herewith as  an exhibit to Form SB — 2/A on October 19, 2005)                                                                                                                                                                                                                                                                                                                                            |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 4.6                       |       | Securities  Purchase Agreement dated as of May 6, 2005, by and between Natural Gas  Systems, Inc. and Rubicon Master Fund (Previously filed as an exhibit to  the Company’s Current Report on Form 8-K on May 11, 2005)                                                                                                                                                                                                                                                        |
|                      |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 4.7                       |       | Registration  Rights Agreement dated as of May 6, 2005, by and between Natural Gas  Systems, Inc. and Rubicon Master Fund (Previously filed as an exhibit to  the Company’s Current Report on Form 8-K on May 11, 2005)                                                                                                                                                                                                                                                        |

 

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| 4.8    |   | Stock  Grant Agreement, dated as of May 4, 2005, by and between Natural Gas  Systems, Inc. and Liviakis Financial Communications, Inc.  (Previously filed as an exhibit to the Company’s Current Report on  Form 8-K on May 11, 2005)                        |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.9    |   | Herlin  Stock Option Agreement, dated April 4, 2005 (Previously filed as an  exhibit to the Company’s Current Report on Form 8-K on April 8,  2005)                                                                                                                    |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.10   |   | Revocable  Warrant Agreement between Natural Gas Systems, Inc. and Robert S.  Herlin, dated April 4, 2005 (Previously filed as an exhibit to the  Company’s Current Report on Form 8-K on April 8, 2005)                                                          |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.11   |   | Amended  and Restated Tatum Resources Agreement, dated January 1, 2005  (Previously filed as an exhibit to the Company’s Current Report on  Form 8-K on April 8, 2005)                                                                                                 |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.12   |   | Warrant  Agreement between Natural Gas Systems, Inc. and Tatum CFO Partners, LLP,  dated January 1, 2005 (Previously filed as an exhibit to the Company’s  Current Report on Form 8-K on April 8, 2005)                                                           |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.13   |   | McDonald  Stock Option Agreement, dated April 4, 2005 (Previously filed as an  exhibit to the Company’s Current Report on Form 8-K on April 8,  2005)                                                                                                                  |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.14   |   | Warrant  Agreement, dated as of February 2, 2005, between Natural Gas  Systems, Inc. and Prospect Energy Corporation (Previously filed as an  exhibit to the Company’s Current Report on Form 8-K on February 8,  2005)                                           |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.15   |   | Natural  Gas Systems, Inc. Common Stock Purchase Warrant in favor of Prospect  Energy Corporation, dated as of February 2, 2005 (Previously filed as an  exhibit to the Company’s Current Report on Form 8-K on February 8,  2005)                                |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.16   |   | Revocable  Warrant Agreement, dated as of February 2, 2005, between Natural Gas  Systems, Inc. and Prospect Energy Corporation (Previously filed as an  exhibit to the Company’s Current Report on Form 8-K on February 8,  2005)                                 |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.17   |   | Natural  Gas Systems, Inc. Revocable Common Stock Purchase Warrant in favor of  Prospect Energy Corporation, dated as of February 2, 2005 (Previously  filed as an exhibit to the Company’s Current Report on Form 8-K on  February 8, 2005)                      |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.18   |   | Registration  Rights Agreement, dated as of February 2, 2005, between Natural Gas Systems, Inc.  and Holders of Common Stock of Natural Gas Systems, Inc. (Previously  filed as an exhibit to the Company’s Current Report on Form 8-K on  February 8, 2005) |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.19   |   | Form of  Registration Rights Agreement (Previously filed as an exhibit to the Company’s  Current Report on Form 8-K on October 26, 2004)                                                                                                                               |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.20   |   | 2004  Stock Plan (Previously filed as an exhibit to the Company’s Definitive  Information Statement on Schedule 14C on August 9, 2004)                                                                                                                                      |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.21   |   | 2003  Stock Option Plan, adopted September 25, 2003 (Previously filed as an  exhibit to the Company’s Form 8-K on January 24, 2007)                                                                                                                                    |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.22   |   | Second  Revocable Warrant Agreement , dated as of September 27, 2005, between  Natural Gas Systems, Inc. and Prospect Energy Corporation (Previously  filed as an exhibit to the Company’s Report on Form 10-KSB on  September 28, 2005)                          |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.23   |   | Stock  Option Agreement, dated June 23, 2005 between Natural Gas  Systems, Inc. and Daryl V. Mazzanti (Previously filed as an exhibit to  the Company’s Current Report on Form 8-K on June 29, 2005)                                                              |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.24   |   | Stock  Option Grant Agreement, dated June 23, 2005 between Natural Gas  Systems, Inc. and Daryl V. Mazzanti (Previously filed as an exhibit to  the Company’s Current Report on Form 8-K on June 29, 2005)                                                        |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.25   |   | Securities  Purchase Agreement dated as of January 13, 2006, by and between Natural  Gas Systems, Inc. and Rubicon Master Fund (Previously filed as an  exhibit to the Company’s Current Report on Form 8-K on January 20,  2006)                                 |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.26   |   | Amended  and Restated Registration Rights Agreement dated as of January 13, 2006,  by and between Natural Gas Systems, Inc. and Rubicon Master Fund  (Previously filed as an exhibit to the Company’s Current Report on  Form 8-K on January 20, 2006)            |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.27   |   | Third  Revocable Warrant Agreement, by and between Prospect Energy Corporation and  Natural Gas Systems, Inc., dated January 31, 2006 (Previously filed  as an exhibit to Form SB — 2/A on March 3, 2006)                                                         |

 

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| 4.28   |   | Amendment  No. 1 to the Registration Rights Agreement, by and between Prospect  Energy Corporation and Natural Gas Systems, Inc., dated January 31,  2006 (Previously filed as an exhibit to Form SB — 2/A on March 3,  2006) |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                        |
| 4.29   |   | Subordinated  Promissory Note, dated March 3, 2006, between Natural Gas  Systems, Inc. and Laird Q. Cagan (Previously filed as an exhibit to  Form 8-K on March 8, 2006)                                                                |
|   |   |                                                                                                                                                                                                                                                        |
| 4.30   |   | Form of  Restricted Stock Agreement (Previously filed as an exhibit to the Company’s  Schedule TO on May 15, 2009)                                                                                                                           |
|   |   |                                                                                                                                                                                                                                                        |
| 4.31   |   | Form of  Senior Indenture (Previously filed as an exhibit to Form S-3 on  July 14, 2010)                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                        |
| 4.32   |   | Form of  Subordinated Indenture (Previously filed as an exhibit to Form S-3 on  July 14, 2010)                                                                                                                                               |
|   |   |                                                                                                                                                                                                                                                        |
| 10.1   |   | Third  Amendment to Consulting Agreement between Liviakis Financial  Communications, Inc. and Evolution Petroleum dated November 14,  2006 (Previously filed as an exhibit to Form 10-QSB on February 14,  2007)                        |
|   |   |                                                                                                                                                                                                                                                        |
| 10.2   |   | Executive  Employment Agreement of Robert S. Herlin, dated April 4, 2005  (Previously filed as an exhibit to Form 8-K on April 8, 2005)                                                                                                      |
|   |   |                                                                                                                                                                                                                                                        |
| 10.3   |   | Executive  Employment Agreement of Sterling H. McDonald, dated April 4, 2005  (Previously filed as an exhibit to Form 8-K on April 8, 2005)                                                                                                  |
|   |   |                                                                                                                                                                                                                                                        |
| 10.4   |   | Executive  Employment Agreement of Daryl V. Mazzanti, dated June 23, 2005  (Previously filed as an exhibit to Form 8-K on June 29, 2005)                                                                                                     |
|   |   |                                                                                                                                                                                                                                                        |
| 10.5   |   | Master  Services Agreement, dated September 29, 2005, by and between the NGS  Technologies, Inc. and MTEM, Ltd. (Previously filed as an exhibit  on Form 8-K on October 7, 2005)                                                   |
|   |   |                                                                                                                                                                                                                                                        |
| 10.6   |   | Agreement  with Chadbourn Securities, Inc., dated February 13, 2006  (Previously filed as an exhibit to Form 10QSB on February 14, 2006)                                                                                                |
|   |   |                                                                                                                                                                                                                                                        |
| 10.7   |   | Agreement  with Cagan McAfee Capital Partners, LLC, dated February 13, 2006  (Previously filed as an exhibit to Form 10QSB on February 14, 2006)                                                                                             |
|   |   |                                                                                                                                                                                                                                                        |
| 10.8   |   | Unit  Operating Agreement, by and between NGS Sub Corp. and Denbury Onshore, LLC,  dated May 8, 2006 (Previously filed as an exhibit to Form 8-K on  June 16, 2006)                                                                          |
|   |   |                                                                                                                                                                                                                                                        |
| 10.9   |   | Form of  Indemnification Agreement for Officers and Directors, as adopted on  September 20, 2006 (Previously filed as an exhibit to Form 8-K on  September 22, 2006)                                                                    |
|   |   |                                                                                                                                                                                                                                                        |
| 10.10  |   | Asset  Purchase and Sale Agreement by and between NGS SUB. CORP. (Seller) and MWM  Energy, LLC (Buyer), dated February 15, 2008 (Previously filed as an  exhibit to Form 10-Q on May 14, 2008)                                               |
|   |   |                                                                                                                                                                                                                                                        |
| 10.11  |   | Evolution  Petroleum Corporation Amended and Restated 2004 Stock Plan (Previously filed  as Annex A to Form Schedule 14A on October 29, 2007)                                                                                                     |
|   |   |                                                                                                                                                                                                                                                        |
| 10.12  |   | Gas  Purchase and Gas Processing Contract by and between EVOLUTION OPERATION  CO., INC. (Seller) and ETC TEXAS PIPELINE LTD. (Buyer) dated  October 8, 2007 (Previously filed as an exhibit to Form 10-K/A on  April 7, 2009)           |
|   |   |                                                                                                                                                                                                                                                        |
| 10.13  |   | Gas  Purchase Contract by and between EVOLUTION OPERATION CO., INC. (Seller)  and DCP MIDSTREAM, LP (Buyer) dated December 1, 2007 (Previously filed  as an exhibit to Form 10-K/A on April 7, 2009)                                    |
|   |   |                                                                                                                                                                                                                                                        |
| 10.14  |   | Gas  Purchase and Sale Agreement by and between EVOLUTION OPERATION CO., INC.  (Seller) and COPANO FIELD SERVICES/UPPER GULF COAST, L.P. (Buyer) dated  February 1, 2009 (Previously filed as an exhibit to Form 10-Q on  May 15, 2009) |
|   |   |                                                                                                                                                                                                                                                        |
| 14.1   |   | Code  of Business Conduct and Ethics for Natural Gas Systems, Inc. (Previously  filed as an exhibit to Form 8-K on May 4, 2006)                                                                                                              |
|   |   |                                                                                                                                                                                                                                                        |
| 21.1   |   | List  of Subsidiaries of Evolution Petroleum Corporation (Filed herein)                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                        |
| 23.1   |   | Consent  of Hein & Associates, LLP, independent auditors (Filed herein)                                                                                                                                                                            |

 

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| 23.2   |   | Consent  of W. D. Von Gonten & Co. (Filed herein)                                                                                                                                                                                |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                      |
| 23.3   |   | Consent  of DeGolyer and MacNaughton (filed herein)                                                                                                                                                                                       |
|   |   |                                                                                                                                                                                                                                      |
| 23.4   |   | Consent  of Lee Keeling & Associates, (filed herein)                                                                                                                                                                             |
|   |   |                                                                                                                                                                                                                                      |
| 31.1   |   | Certification  of Chief Executive Officer Robert S. Herlin Pursuant to Rule 15D-14 of  the Securities Exchange Act of 1934, as Amended as Adopted Pursuant to  Section 302 of the Sarbanes-Oxley Act of 2002 (Filed herein)     |
|   |   |                                                                                                                                                                                                                                      |
| 31.2   |   | Certification  of Chief Financial Officer Sterling H. McDonald Pursuant to Rule 15D-14  of the Securities Exchange Act of 1934, as Amended as Adopted Pursuant to  Section 302 of the Sarbanes-Oxley Act of 2002 (Filed herein) |
|   |   |                                                                                                                                                                                                                                      |
| 32.1   |   | Certification  of Chief Executive Officer Robert S. Herlin Pursuant to 18 U.S.C.  Section 1350, as Adopted Pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002 (Filed herein)                                            |
|   |   |                                                                                                                                                                                                                                      |
| 32.2   |   | Certification  of Chief Financial Officer Sterling H. McDonald Pursuant to 18 U.S.C.  Section 1350, as Adopted Pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002 (Filed herein)                                        |
|   |   |                                                                                                                                                                                                                                      |
| 99.1   |   | Audit  Committee Charter of the Board of Directors of Natural Gas Systems, Inc.  (Previously filed as an exhibit to Form 8-K on May 4, 2006)                                                                               |
|   |   |                                                                                                                                                                                                                                      |
| 99.2   |   | Compensation  Committee Charter of the Board of Directors of Natural Gas Systems, Inc.  (Previously filed as an exhibit to Form 8-K on May 4, 2006)                                                                        |
|   |   |                                                                                                                                                                                                                                      |
| 99.3   |   | Nominating  Committee Charter of the Board of Directors of Natural Gas Systems, Inc.  (Previously filed as an exhibit to Form 8-K on May 4, 2006)                                                                          |
|   |   |                                                                                                                                                                                                                                      |
| 99.4   |   | The  summary of W.D. Von Gonten & Co. Report as of June 30, 2010, on  oil and gas reserves (SEC Case) dated August 17, 2010 and certificate of  experience (Filed herein)                                              |
|   |   |                                                                                                                                                                                                                                      |
| 99.5   |   | The  summary of DeGolyer and MacNaughton’s Report as of June 30, 2010, on oil  and gas reserves (SEC Case) dated August 10, 2010 and certificate of  experience (Filed herein)                                             |
|   |   |                                                                                                                                                                                                                                      |
| 99.6   |   | The  summary of Lee Keeling & Associates Report as of June 30, 2010,  on oil and gas reserves (SEC Case) dated August 23, 2010 and certificate  of experience (Filed herein)                                           |

 

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