**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

**FORM10-KSB**

 

**x****ANNUAL REPORT UNDER SECTION 13OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934**

 

**For the fiscal year ended June 30, 2007**

 

**o****TRANSITION REPORT UNDER SECTION13 OR 15 (d) OF THE EXCHANGE ACT**

 

**For the transition period                     to                      **

 

**Commission file number: 001-32942**

 

**EVOLUTION PETROLEUM CORPORATION**

(Name of small business issuer in its charter)

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

 

**2500 City West Blvd., Suite 1300, Houston,Texas 77042**

(Address of principal executive offices and zip code)

 

**(713) 935-0122**

(Issuer’s telephone number, including area code)

 

Securities registered pursuant to Section12(b) of the Exchange Act:

 
| **Title  of each class**                    | ** ** | **Name  of exchange on which registered** |
|---------------------------------------------|------------|-------------------------------------------|
| **Common Stock, par value $.001 per share** | ** ** | **American Stock Exchange**               |

 

Securities registered pursuant to Section12(g) of the Exchange Act:  **None**

 

Checkwhether the issuer is not required to file reports pursuant to Section 13or 15(d) of the Exchange Act.o

 

Checkwhether the issuer: (1) filed all reports required to be filed bySection 13 or 15(d) of the Exchange Act during the past 12 months (orfor such shorter period that the registrant was required to file such reports),and (2) has been subject to such filing requirements for the past90 days. Yes  x   No o

 

Checkif there is no disclosure of delinquent filers in response to Item 405 ofRegulation S-B contained in this form, and no disclosure will becontained, to the best of registrant’s knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form10-KSB or any amendment to this Form 10-KSB. o

 

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

 

Stateissuer’s revenues for its most recent fiscal year: $1,866,878

 

Theaggregate market value of the voting and non-voting common equity held bynon-affiliates of the registrant was approximately $39 million as of September20, 2007 based upon the closing price of the common stock on the American StockExchange on September 20, 2007 of $2.98 per share.

 

**APPLICABLE ONLY TO CORPORATE REGISTRANTS**

 

Statethe number of shares outstanding of each of the issuer’s classes of commonequity, as of the latest practicable date.

 

26,776,234Shares of Common Stock outstanding at September 20, 2007

 

**DOCUMENTS INCORPORATED BY REFERENCE**

 

Portionsof the Company’s Proxy Statement for the 2007 Annual Meeting of Shareholdersare incorporated by reference in Part III.

 

Transitional Small BusinessDisclosure Format (Check one):  Yes: o No:  x

 

 

----

 

**EVOLUTION PETROLEUMCORPORATION AND SUBSIDIARIES**

 

**2007 ANNUAL REPORT ON 10-KSB**

 

**TABLE OF CONTENTS**

 
| **PART I**    |
|---------------|
|          |   |   |   |
| ITEM 1.       | Business |   |   |
|          |   |   |   |
| ITEM 1A.      | Risk Factors |   |   |
|          |   |   |   |
| ITEM 2.       | Properties |   |   |
|          |   |   |   |
| ITEM 3.       | Legal Proceedings |   |   |
|          |   |   |   |
| ITEM 4.       | Submission of Matters to a  Vote of Security Holders |   |   |
|          |   |   |   |
| **PART  II**  |
|          |   |   |   |
| ITEM 5.       | Market for Registrant’s  Common Equity, Related Stockholder Matters and Issue Purchases of Equity  Securities |   |   |
|          |   |   |   |
| ITEM 6.       | Management’s Discussion and  Analysis of Financial Condition and Results of Operations |   |   |
|          |   |   |   |
| ITEM 7.       | Financial Statements and  Supplementary Data |   |   |
|          |   |   |   |
| ITEM 8.       | Changes in  and Disagreements with Accountants on Accounting and Financial Disclosure |   |   |
|          |   |   |   |
| ITEM 8A.      | Controls and  Procedures |   |   |
|          |   |   |   |
| ITEM 8B.      | Other information |   |   |
|          |   |   |   |
| **PART  III** |
|          |   |   |   |
| ITEM 9.       | Directors  and Executive Officers, Control Persons and Corporate Governance |   |   |
|          |   |   |   |
| ITEM 10.      | Executive  Compensation |   |   |
|          |   |   |   |
| ITEM 11.      | Security  Ownership of Certain Beneficial Owners and Management and Related Stockholder  Matters |   |   |
|          |   |   |   |
| ITEM 12.      | Certain  Relationships and Related Transactions, Director Independence |   |   |
|          |   |   |   |
| ITEM 13.      | Exhibits |   |   |
|          |   |   |   |
| ITEM 14.      | Principal  Accountant Fees and Services |   |   |
|          |   |   |   |
| SIGNATURES    |   |   |

 

2

----

 

**Forward-Looking Statements**

 

Asused in this Annual Report on Form 10-KSB, the terms “Evolution”, “EPM”, “Company”,“we”, “us”, “our” and similar terms refer to Evolution Petroleum Corporation, aNevada Corporation formerly known as Natural Gas Systems, Inc. (Nevada, “NGS”),and its subsidiaries, unless the context indicates otherwise.

 

This Annual Report on Form10-KSB contains “forward-looking statements” within the meaning of the PrivateSecurities Litigation Reform Act of 1995, Section 27A of the Securities Act andSection 21E of the Exchange Act. Forward-looking statements give our currentexpectations or forecasts of future events. They include statements regardingour future operating and financial performance. Although we believe theexpectations and forecasts reflected in these and other forward-lookingstatements are reasonable, we can give no assurance they will prove to havebeen correct. They can be affected by inaccurate assumptions or by known orunknown risks and uncertainties. You should understand that the followingimportant factors, could affect our future results and could cause thoseresults or other outcomes to differ materially from those expressed or impliedin the forward-looking statements relating to: (1) amount, nature and timing ofcapital expenditures; (2) drilling of wells and other planned exploitationactivities; (3) timing and amount of future production of oil and natural gas;(4) increases in production growth and proved reserves; (5) operating costssuch as lease operating expenses, administrative costs and other expenses; (6)our future operating or financial results; (7) cash flow and anticipatedliquidity; (8) our business strategy, including the availability of leasingopportunities; (9) hedging strategy; (10) exploration and exploitationactivities and property acquisitions; (11) marketing of oil and natural gas;(12) governmental and environmental regulation of the oil and gas industry;(13) environmental liabilities relating to any pollution arising from ouroperations, net of any insurance proceeds; (14) our level of indebtedness; (15)timing and amount of future dividends; (16) industry competition, conditions,performance and consolidation; (17) natural events such as severe weather,hurricanes, floods, fire and earthquakes; (18) availability of drilling rigsand other oil field equipment and services; (19) our inability to control thedevelopment, production and operations of our non-operated properties; and (20)the timing, amount and terms of capital available to us .

 

We caution you not to place undue reliance on theseforward-looking statements, which speak only as of the date of this report, andwe undertake no obligation to update such information.

 

3

----

 

**GLOSSARY OF SELECTED PETROLEUM TERMS**

 

The following abbreviationsand definitions are terms commonly used in the oil and natural gas industry andthroughout this Form 10-KSB:

 

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

 

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

 

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

 

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

 

“EOR.” Enhanced Oil Recoveryprojects involve injection of heat, miscible or immiscible gas, or chemicalsinto oil reservoirs, typically following full primary and secondary waterfloodrecovery efforts, in order to gain incremental recovery of oil from thereservoir.

 

“field.” An area consistingof a single reservoir or multiple reservoirs all grouped on or related to thesame individual geologic structural feature and/or stratigraphic feature.

 

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

 

“gross acres or gross wells.”The total acres or number of wells participated in, regardless of the amount ofworking interest owned.

 

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

 

“MBOE.” One thousand barrelsof oil equivalent.

 

“MCF.” One thousand cubicfeet of natural gas at standard conditions, being approximately sea levelpressure and 60 degrees Fahrenheit temperature. Standard pressure in the stateof Louisiana is deemed to be 15.025 psi by regulation, but varies in otherstates.

 

“MMBTU.” One million Britishthermal units.

 

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

 

“net acres or net wells.”The sum of the fractional working interests owned in gross acres or grosswells.

 

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

 

“NYMEX.” New York MercantileExchange.

 

“operator.”  An E&P joint venture participant thatmanages the joint venture, pays venture costs and bills the venture’snon-operators for their share of venture costs. The operator is alsoresponsible to market all oil and gas production, except for thosenon-operators who take their production in-kind.

 

“overriding royalty.” Aroyalty interest that is created out of the operating or working interest. Unlikea royalty interest, an overriding royalty interest terminates with theoperating interest from which it was created or carved out of. See “royaltyinterest”.

 

“permeability.” The measureof ease with which petroleum can move through a reservoir.

 

“porosity” (of sand orsandstone). The relative volume of the pore space (or open area) compared tothe total bulk volume of the reservoir.

 

“proved developed reserves.”Reserves that can be expected to be recovered through existing wells withexisting equipment and operating methods. Additional oil and gas expected to beobtained through the application of fluid injection or other improved recoverytechniques for supplementing the natural forces and mechanisms of primaryrecovery should be included as “proved developed reserves” only after testingby pilot project or after the operation of an installed program has confirmed throughproduction responses that increased recovery will be 

 

4

----

 

achieved.

 

“proved reserves.” Estimatedquantities of crude oil, natural gas, and natural gas liquids which geologicaland engineering data demonstrate with reasonable certainty to be recoverable infuture years from known reservoirs under existing economic and operatingconditions, i.e., prices and costs as of the date the estimate is made. Pricesinclude consideration of changes in existing prices provided only bycontractual arrangements, but not on escalations based upon future conditions.

 

“proved undevelopedreserves.” Reserves that are expected to be recovered from new wells onundrilled acreage or from existing wells where a relatively major expenditureis required for recompletion. Reserves on undrilled acreage are limited tothose drilling units offsetting productive units that are reasonably certain ofproduction when drilled. Proved reserves for other undrilled units can beclaimed only where it can be demonstrated with certainty that there iscontinuity of production from the existing productive formation. Provedundeveloped reserves may not include estimates attributable to any acreage forwhich an application of fluid injection or other improved recovery technique iscontemplated, unless such techniques have been proved effective by actual testsin the area and in the same reservoir.

 

“psi,” or pounds per squareinch, a measure of pressure. Pressure is typically measured as “psig”, or thepressure in excess of standard atmospheric pressure.

 

“present value.” When usedwith respect to oil and gas reserves, present value means the estimated futurenet revenues computed by applying current prices of oil and gas reserves (withconsideration of price changes only to the extent provided by contractualarrangements) to estimated future production of proved oil and gas reserves asof the date of the latest balance sheet presented, less estimated futureexpenditures (based on current costs to be incurred in developing and producingthe proved reserves) computed using a discount factor and assuming continuationof existing economic conditions.

 

“productive well.” A wellthat is producing oil or gas or that is capable of production.

 

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

 

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

 

“shut-in well.” A well thatis not on production, but has not yet been plugged and abandoned. Wells may beshut-in in anticipation of future utility as a producing well, plugging andabandonment or other use.

 

“standardized measure.” Thestandardized measure is an estimate of future net reserves from a property, andis calculated in the same exact  fashionas a PV-10 value, except that the projected revenue stream is adjusted toaccount for the estimated amount of federal income tax that must be paid.

 

“working interest.” Theinterest in the oil and gas in place which is burdened with the cost ofdevelopment and operation of the property. Also called the operating interest.

 

“workover.” A remedialoperation on a completed well to restore, maintain or improve the well’sproduction.

 

**PART I**

 

**ITEM 1. DESCRIPTIONOF BUSINESS**

 

The terms “we,” “us,” “our,”“our Company” and “EPM” refer to Evolution Petroleum Corporation, a Nevadacorporation formerly known as Natural Gas Systems, Inc. (Nevada, “NGS”), and,unless the context indicates otherwise, also includes our wholly-ownedsubsidiaries. “Old NGS” refers to Natural Gas Systems, Inc. (Delaware), aprivate Delaware corporation formed in 2003, which subsequently merged intoNGS.

** **

**General**

 

Our petroleum operations began in September of 2003. We acquireestablished crude oil and natural gas resources and exploit them through theapplication of conventional and specialized technology, with the objective of increasingproduction, ultimate recoveries, or both. We currently own oil and gasproperties in four crude oil and natural gas producing fields in the State ofLouisiana, all of which are referred to as our Delhi Field or our Tullos Field(Area), and non producing leases in the Gulf Coast and Mid-continent regions ofthe United States.

 

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

 

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

 

5

----

 

document.

 

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

 

At June 30, 2007, we had sixfull-time employees, not including contract personnel and outsourced serviceproviders.

 

**CorporateHistory of Reverse Merger**

 

Reality Interactive, Inc. (“Reality”),a Nevada corporation that traded on the OTC Bulletin Board under the symbolRLYI.OB and the predecessor of Natural Gas Systems, Inc., now EvolutionPetroleum Corporation, was incorporated on May 24, 1994, for the purpose ofdeveloping technology-based knowledge solutions for the industrial marketplace.On April 30, 1999, Reality ceased business operations, sold substantially allof its assets and terminated all of its employees. Subsequent to ceasingoperations, Reality explored other potential business opportunities to acquireor merge with another entity, while continuing to file reports with the SEC.

 

On May 26, 2004, Natural GasSystems, Inc., a privately owned Delaware corporation formed in September 2003(“Old NGS”), was merged into a wholly owned subsidiary of Reality. Reality wasthereafter renamed Natural Gas Systems, Inc. (“NGS”) and adopted a June 30fiscal year end. As part of the merger, the officers and directors of Realityresigned, the officers and directors of Old NGS became the officers anddirectors of our Company, and the crude oil and natural gas business of Old NGSbecame that of our Company. Concurrently with the listing of our shares on theAMEX during July, 2006, Natural Gas Systems was renamed Evolution PetroleumCorporation to avoid confusion with similar names traded on the AMEX and tobetter reflect our business model.

 

All regulatory filings andother historical information prior to May 26, 2004 that applied to Realitycontinue to apply to us after the merger.

 

**BusinessActivities**

 

We are focused on an overallstrategy of acquiring controlling working interests in oil and gas resourceswithin established fields and redeveloping those fields through the applicationof capital and technology to convert the oil and gas resources into profitableproducing reserves. Within this overall strategy, we have established threespecific business initiatives:

 

I                                           Enhanced oil recovery (EOR) Initiative, usingmiscible and immiscible gas flooding to extract tertiary resources;

 

II                                       Bypassed Resource Initiative, usingtechnology-based redevelopment of primary resources in mature oil and gasfields; and

 

III                                         Unconventional Gas Resource Initiative,  using modern stimulation and completiontechnologies to economically produce tight gas formations.

 

Our strategy is intended togenerate scalable development opportunities at normally pressured depths,exhibiting relatively low completion risk, generally longer and morepredictable production lives, less expenditures on infrastructure and loweroperational risks. We believe that the benefits of this approach include:

 

•                   Reduced exposure to the risk of whetherresources are present;

 

•                   Reduced capital expenditures per net BOE forinfrastructure, such as roads, water handling facilities and pipelines;

 

•                   Large inventory of development opportunities,which provides a more predictable future stream of drilling activity andproduction, as well as potentially reducing risks from short-term oil and gasprice volatility;

 

•                   Reduced operational risks and costsassociated with lower pressures and lower temperatures; and

 

•                   Control of operations, development timing andtechnology selection.

 

We purchased our first oiland gas property in September 2003 through the acquisition of all of the activeworking interests and the corresponding 80% net revenue interest in propertyand wells in the Delhi Field, located in northeastern Louisiana. Thisacquisition included the purchase of six producing wells, one salt waterdisposal well and 37 shut-in wells with minimal crude oil production per dayand no natural gas sales. The Delhi Field encompasses approximately 13,636acres, and the primary Paluxy and Tuscaloosa producing reservoirs in the fieldwere unitized in the 1950’s as the Delhi Holt Bryant Unit. Our acquisitionincluded the Delhi Holt Bryant Unit and certain other depths, excluding aseparate reservoir contained in the Mengel Unit in the Delhi Field. Weconducted various development activities in the Delhi Field since theacquisition. Between January and July 2006, we also acquired royalty andoverriding royalty interests in the Delhi Holt Bryant Unit aggregatingapproximately 7.4%.

 

In June 2006, we conveyed afarmout to a wholly owned subsidiary of Denbury Resources (**“Denbury”**)that included all of our working interests in the Delhi Holt Bryant Unit and75% of our working interests in other depths of the Delhi Field, for which wereceived 

 

6

----

 

approximately $50 million incash, a 25% reversionary back-in working interest in the Delhi Holt Bryant Unitafter payout, as defined in the agreement, and a commitment by Denbury toinstall a CO2 enhanced oil recovery project (**“CO2-EOR”**)in the Delhi Holt Bryant Unit (the **“Delhi Farmout”**).We also retained our separately acquired royalty and overriding royaltyinterests aggregating approximately 7.4% on the Delhi Holt Bryant Unit,including the CO2-EOR project.

 

In September 2004, wecompleted the acquisition of a 100% working interest and an approximate 78%average net revenue interest in producing crude oil wells, equipment andimprovements located in the Tullos Urania, Colgrade and Crossroads Fields inLaSalle and Winn Parishes, Louisiana, which we refer to collectively as the “**Tullos Field Area**”. The purchased assets includedapproximately 124 oil wells, 9 water disposal wells, and all associatedinfrastructure, including water disposal facilities, crude oil and water tanks,flow lines and pumping units. The purchase also included 15 wells withoutleases. We subsequently acquired new leases for ten of these wells.

 

In early February 2005, wecompleted the acquisition of a 100% working interest and an approximate 79%average net revenue interest in similar properties in our Tullos Field Area.The purchased assets included approximately 121 oil wells, 8 salt waterdisposal wells and associated infrastructure and equipment.

 

Since the acquisitions ofthe Tullos Field assets, we have conducted various development activities,primarily to improve operations, bring operations up to industry standards, andincrease produced water disposal capacity.

 

During fiscal 2007, weinitiated four projects within our Bypassed Resource Initiative and twoprojects within our Unconventional  GasResource Initiative. To date, activity in these projects primarily has been theleasing of mineral rights in the state of Texas for our Bypassed ResourceInitiative and in the Mid-Continent region for our Unconventional Gas Initiative.

 

For a more detaileddiscussion, please see “**Item 2. - Properties**.”

 

**Markets andCustomers**

 

To date all of our crude oilhas been produced and sold from our Delhi Field and Tullos Field Areas inLouisiana. All of our natural gas has been produced and sold from our DelhiField in Louisiana. Since June 2006, we are no longer the operator of the DelhiField, due to our closing of the Delhi Farmout. Consequently, we had no naturalgas or natural gas liquids production available to us for sales and marketingpurposes during fiscal year 2007.

 

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

 

Over the past 20 years,crude oil price fluctuations have been extremely volatile, with crude oilprices varying from less than $10.00 to in excess of $75 per barrel. Worldwidefactors such as geopolitical, macroeconomic, supply and demand, refiningcapacity, petrochemical production and derivatives trading, among others,influence prices for crude oil. Local factors also influence prices for crudeoil and include quality differences, regulation and transportation issuesunique to certain producing regions and reservoirs.

 

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

 

In the U.S. market where weoperate, crude oil and gas liquids are readily transportable and marketable.Since March 2005, we have sold all of our operated crude oil production toPlains Marketing LP, a crude oil purchaser, at competitive field prices. Aportion of our crude oil production has been subject to fixed price contracts(excluding basis risk) with Plains Marketing as described in the “CommodityContracts” section below. We believe that other crude oil purchasers arereadily available.

 

Prior to fiscal year 2007,we  produced  natural gas liquids from our Delhi Field, allof which we sold to Dufour Petroleum, L.P., a subsidiary of Enbridge EnergyPartners, at a market competitive price based on an index price of liquidcomponents, less a charge of $0.175 per gallon for transportation andfractionation.

 

With respect to natural gassales, there is only one natural gas pipeline sales point readily available tothe gas treating facility that had been serving our Delhi natural gasproduction. Although this could reduce our operator’s leverage in negotiatingfavorable transportation charges and sales prices, we believe that any futurenatural gas sales would be inconsistent with the nature of the CO2-EOR projectplanned for the Delhi Holt Bryant Unit.

 

From March 2005 to theclosing of the Delhi Farmout in June 2006, we sold all of our operated naturalgas volumes through Texla Energy Management, Inc., a natural gas marketer/aggregator,although we believe that other natural gas marketers are readily available. Aportion of our natural gas volumes had been sold under commodity contracts, asdiscussed in the section below. The remaining natural gas volumes were pricedon either a monthly average index or a daily cash price as established at theHenry Hub market, less a $0.215 per MMBTU deduction for the market differentialbetween Henry Hub and our sales point. All gas sold from the Delhi Field wascharged $0.0854 per MMBTU by Gulf 

 

7

----

 

South, the pipeline intowhich we deliver our gas, for transportation. These costs, along with the costsfor natural gas processing and transportation prior to delivery to the salespoint, were deducted from the natural gas sales receipts before calculation anddistribution of royalties. Title to the natural gas passed to the purchaser atthe metered interconnection to the transportation pipeline, where the Indexprice was reduced by the Gulf South transportation charge.

 

**COMMODITYCONTRACTS**

 

In compliance with the loanagreement we entered into with Prospect Energy in February 2005, we executedthree commodity contracts for approximately 50% of the production volumes thatour outside petroleum engineers estimated for our proved developed producingreserves on a rolling two year basis. Although we paid off the Prospect loan inMay 2006, three of these contracts continued to be effective in fiscal 2006 and2007, as described below.

 

The first commoditycontract, with Plains Marketing L.P., covered the sale of 70 barrels of crudeoil per day for a 12 month period from March 2005 through February 2006. Thefixed sale price was based upon the NYMEX WTI (West Texas Intermediate) crudeoil price and monthly settlements, wherein Plains Marketing delivered a fixedprice of $48.35 per barrel to us before adjustment for the basis differentialbetween the NYMEX price and the contract price. This contract was extended forthe months of March 2006 through May 2006 at a fixed price of $52.55 per barrelof oil for 70 barrels of oil per day, extended for the three months of June2006 through August 2006 at a fixed price of $63.45 per barrel of oil for 90barrels of oil per day, and extended for the six months of September 2006through February 2007 at a fixed price of $69.30 per barrel of oil for 90barrels of oil per day. Plains Marketing L.P. is our crude oil purchaser andpicks up our production in the field using their trucks.

 

The second commoditycontract is between us and Wells Fargo Bank, N.A. We purchased a series ofprice floors, set at a NYMEX WTI price of $38.00 per barrel of crude oil, basedupon the arithmetic average of the daily settlement price for the first nearbymonth of NYMEX WTI futures, for 2,000 barrels of crude oil per month for March2006 through February 2007. The cost of the hedge was $3.00 per barrel of oil.

 

Our third commodity contractwas with Texla Energy Management, Inc., whereby we sold 100 MMBTU per day at afixed price of $6.21 per MMBTU over a fifteen month period beginning March 1,2005 and ending May 31, 2006.The fixed price was before deduction of a $0.0854per MMBTU fixed gathering charge by Gulf South, the owner of the natural gaspipeline into which we deliver our natural gas from the Delhi Field. This fixedprice included the basis differential from NYMEX to our sales point on the GulfSouth pipeline.

 

Since March 1, 2007, all ofour oil production has been sold to Plains Marketing L.P. under a normal(thirty day “evergreen”) sales contract.

 

**COMPETITION**

 

Our competitors includemajor integrated crude oil and natural gas companies and numerous independentcrude oil and natural gas companies, individuals and drilling and incomeprograms. Many of our competitors are large, well-established companies withsubstantially larger operating staffs and greater capital resources than us.Competitors are national, regional or local in scope and compete on the basisof financial resources, technical prowess or local knowledge. The principal competitivefactors in our industry are the ability to efficiently conduct operations,achieve technological advantages, identify and acquire suitable properties andobtain affordable capital.

 

**GOVERNMENTREGULATION**

 

Crude oil and natural gasdrilling and production operations are regulated by various federal, state andlocal agencies. These agencies issue binding rules and regulations that carrypenalties, often substantial, for failure to comply. These regulations andrules require monthly, semiannual and annual reports on production amounts andwater disposal amounts, and govern most aspects of operations, drilling andabandonment, as well as crude oil spills. We anticipate the aggregate burden offederal, state and local regulation will continue to increase, including in thearea of rapidly changing environmental laws and regulations. We also believethat our present operations substantially comply with applicable regulations.To date, such regulations have not had a material effect on our operations, or thecosts thereof. We do not believe that capital expenditures related toenvironmental control facilities or other regulatory matters will be materialin the near term  We cannot predict whatsubsequent legislation or regulations may be enacted or what effect it willhave on our operations or business.

 

Please see Item 2.Properties, Item 2. Subsequent Events and Item 3. Legal Proceedings).

 

**ITEM 1A. RISKFACTORS**

 

**Risks related to the Company**

 

**OPERATING RESULTS FROM OIL AND GAS PRODUCTION MAYDECLINE.**

 

Due to the Delhi Farmout we completed on June 12, 2006 with DenburyOnshore LLC (the “Delhi Farmout”), our future development initiatives in theDelhi Field are expected to be replaced with a CO2 enhanced oil recovery (“CO2-EOR”)project offering much greater potential, which Denbury has undertaken anobligation to fund and operate. As anticipated, the Delhi Farmout resulted inthe reduction of net production and net revenues accruing to us from Delhi,until such time, if at all, as the CO2-EOR project is completed and broughtonline. 

 

8

----

 

Without further acquisitions of new properties, production increases atour Tullos Field Area or any results from future drilling, our production andrevenues from oil and gas operations may decline in the foreseeable future, ascompared to our fiscal 2006 results.

 

**THE TYPESOF RESOURCES WE FOCUS ON HAVE SUBSTANTIAL OPERATIONAL RISKS.**

 

Our business plan focuses onthe acquisition and development of relatively shallow, more complex and/orlower permeability reservoirs. Shallower reservoirs usually have lowerpressure, which translates into fewer natural gas volumes in place; complexreservoirs are more difficult to analyze and exploit; and low permeabilityreservoirs require more wells and stimulation for development and such wellsmay have low profit margins and higher capital costs per produced BBL of oil orMCF of gas.

 

The Delhi Farmout EORproject requires significant amounts of CO2 resources, the source of which maybe become unavailable or be curtailed. In order to produce and deliversufficient quantities of CO2 from Denbury’s reserves from its Jackson Dome,Mississippi field, the construction of an approximately 100 mile pipelinenecessary to connect to the Delhi Field will require large amounts of capitalresources and the acquisition of new permits, right-of-ways, engineeringdesigns, construction personnel and materials. Denbury’s failure to managethese and other technical, strategic and logistical risks may render ultimateenhanced recoveries from the planned CO2-EOR project, if any, to fall short ofour expectations.

 

In addition, the maturefields we currently own and operate have well bores that were drilled as earlyas the 1920s. As such, they contain older down-hole equipment and casing thatis more subject to failure than new equipment. The failure of such equipment orother subsurface failure can result in the complete loss of a well.

 

Our new projects requirethat we acquire new leases in and around established fields and drill andcomplete wells, some which may be horizontal, as well as negotiate the purchaseof existing well bores and production equipment and install our proprietaryartificial lift technology that has yet to be proven in the field. Leases maynot be available, required oil field services may not be obtainable on thedesired schedule or at the expected costs. While the projected drilling resultsare considered to be low to moderate in risk, there is no assurance as to whatproductive results may be obtained, if any.

 

**OUR LIMITEDOPERATING HISTORY MAKES IT DIFFICULT TO PREDICT FUTURE RESULTS AND INCREASESTHE RISK OF AN INVESTMENT IN OUR COMPANY.**

 

We commenced our crude oiland natural gas operations in late 2003 and have a limited operating history. Therefore,we face all the risks common to companies in their early stages 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 be considered in light of the risks,expenses, delays and difficulties frequently encountered in establishing a newbusiness. Any forward-looking statements in this report do not reflect anypossible effect on us from the outcome of these types of uncertainty. Prior toour recent Delhi Farmout with Denbury, we have incurred significant lossessince the inception of our oil and gas operations and we have since resumedincurring losses. We cannot assure you that we will be successful. Whilemembers of our management have previously carried out or been involved withacquisition and production activities in the crude oil and natural gas industrywhile employed by us and other companies, we cannot assure you that ourintended acquisition targets and development plans will lead to the successfuldevelopment of crude oil and natural gas production or additional revenue.

 

**WE MAY BEUNABLE TO CONTINUE LICENSING FROM THIRD PARTIES THE TECHNOLOGIES THAT WE USE INOUR BUSINESS OPERATIONS.**

 

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

 

**REGULATORYAND ACCOUNTING REQUIREMENTS MAY REQUIRE SUBSTANTIAL REDUCTIONS IN REPORTEDPROVEN RESERVES (SEE GLOSSARY) AND LIMITATIONS OF HEDGING.**

 

We review on a periodicbasis the carrying value of our crude oil and natural gas properties under theapplicable rules of the various regulatory agencies, including the SEC. Underthese rules, the carrying value of proved reserves of crude oil and natural gasproperties may not exceed the present value of estimated future net after-taxcash flows from proved reserves, discounted at 10%. Application of this “ceiling”test generally requires pricing future revenues at the un-escalated prices ineffect as of the end of our fiscal year and requires a write down foraccounting purposes if the ceiling is exceeded, even if prices declined foronly a short period of time. We may in the future be required to write down thecarrying value of our crude oil and natural gas properties when crude oil and naturalgas prices are depressed or unusually volatile. Whether we will be required totake such a charge will depend in part on the prices for crude oil and naturalgas at the end of any fiscal period and the effect 

 

9

----

 

of reserve additions orrevisions and capital expenditures during such period. If a write down isrequired, it would result in a charge to our earnings but would not impact ourcash flow from operating activities.

 

In order to reduce our exposureto short-term fluctuations in the price of crude oil and natural gas and complywith the terms of our loan agreement with Prospect Energy, we entered intothree commodity contracts. Although we terminated our loan agreement in May2006, these contracts continued to be effective in our fiscal 2006 and 2007years, all of which had expired by February 2007. Commodity contracts mayexpose us to risk of financial loss in certain circumstances, includinginstances where production is less than expected, our customers fail topurchase contracted quantities of crude oil or natural gas or a sudden,unexpected event materially impacts crude oil prices. In addition, any futurecommodity contracts may limit the benefit to us of increases in the price ofcrude oil.

 

**WE MAY BEUNABLE TO ACQUIRE AND DEVELOP THE ADDITIONAL OIL AND GAS RESERVES THAT AREREQUIRED IN ORDER TO SUSTAIN OUR BUSINESS OPERATIONS.**

 

In general, the volumes ofproduction from crude oil and natural gas properties decline as reserves aredepleted, with the rate of decline depending on reservoir characteristics.Except to the extent we acquire properties containing proved reserves orconduct successful development activities, or both, our proved reserves willdecline. Our future crude oil and natural gas production is, therefore, highlydependent upon our level of success in finding or acquiring additional reserves.Due to the Delhi Farmout, our immediate future growth is highly dependent onour ability to develop additional oil and gas reserves.

 

**WE ARESUBJECT TO SUBSTANTIAL OPERATING RISKS THAT MAY ADVERSELY AFFECT OUR RESULTS OFOPERATIONS.**

 

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

 

We may not always be theoperator of some of our wells. As a result, our operating risks for those wellsand 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 which would have anadverse effect on our results of operations.

 

**THE LOSS OFKEY PERSONNEL COULD ADVERSELY AFFECT US.**

 

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

 

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

 

We depend to a large extenton the services of skilled technical personnel to operate and maintain ourcrude oil and natural gas fields. We do not have the resources to perform allof these services and therefore we outsource many of our requirements.Additionally, as our production increases, so does our need for such services.Generally, we do not have long-term agreements with our drilling andmaintenance service providers. Accordingly, there is a risk that any of ourservice providers could discontinue servicing our crude oil and natural gasfields for any reason. Although we believe that we could establish alternativesources for most of our operational and maintenance needs, any delay inlocating, establishing relationships, and training our sources could result inproduction shortages and maintenance problems, with a resulting loss of revenueto us. We also rely on third-party carriers for the transportation and distributionof our production, the loss of any of which could have a material adverseeffect on our operations.

 

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

 

Although we hope toexperience growth through acquisitions and development activity, any suchgrowth may place a significant strain on our financial, technical, operationaland administrative resources. Our ability to grow will depend upon a number offactors, including:

 

•                   our ability to identify and acquire newdevelopment or acquisition projects;

•                   our ability to develop existing properties;

•                   our ability to continue to retain and attractskilled personnel;

•                   the results of our development program andacquisition efforts;

•                   the success of our technologies;

•                   hydrocarbon prices;

 

10

----

 

•                   our ability to successfully integrate newproperties; and

•                   our access to capital.

 

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

 

**WE FACESTRONG COMPETITION FROM LARGER CRUDE OIL AND NATURAL GAS COMPANIES.**

 

Our competitors includemajor integrated crude oil and natural gas companies and numerous independentcrude oil and natural gas companies, individuals and drilling and incomeprograms. Many of our competitors are large, well-established companies withsubstantially larger operating staffs and greater capital resources than wehave. We may not be able to successfully conduct our operations, evaluate andselect suitable properties and consummate transactions in this highlycompetitive environment. Specifically, these larger competitors may be able topay more for development projects and productive crude oil and natural gasproperties and may be able to define, evaluate, bid for and purchase a greaternumber of properties and prospects than our financial or human resourcespermit. In addition, such companies may be able to expend greater resources onthe existing and changing technologies that we believe are and will beincreasingly important to attaining success in our industry.

 

**THE CRUDEOIL AND NATURAL GAS RESERVES INCLUDED IN THIS REPORT ARE ONLY ESTIMATES AND MAYPROVE TO BE INACCURATE.**

 

There are numerousuncertainties inherent in estimating crude oil and natural gas reserves andtheir estimated values. The reserves discussed in this report are onlyestimates 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 historicalproduction from the area compared with production from other producing areasand assumptions concerning effects of regulations by governmental agencies,future crude oil and natural gas 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 therefrom prepared by different engineers orby the same engineers but at different times may vary substantially.Accordingly, reserve estimates may be subject to downward or upward adjustment.Actual production, revenue and expenditures with respect to our reserves willlikely vary 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. As required by the SEC,the estimated discounted future net cash flows from proved reserves are basedon prices and costs as of the date of the estimate, while actual future pricesand costs may be materially higher or lower. Actual future net cash flows alsowill be affected by factors such as the amount and timing of actual production,supply and demand for crude oil and natural gas, increases or decreases inconsumption, and changes in governmental regulations or taxation. In addition,the 10% discount factor, which is required by the SEC to be used in calculatingdiscounted future net cash flows for reporting purposes, is not necessarily themost appropriate discount factor based on interest rates in effect from time totime and risks associated with us or the crude oil and natural gas industry ingeneral.

 

**WE CANNOTMARKET THE CRUDE OIL AND NATURAL GAS THAT WE PRODUCE WITHOUT THE ASSISTANCE OFTHIRD PARTIES.**

 

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

 

**RisksRelating to the Oil and Gas Industry**

 

**CRUDE OIL AND NATURAL GASDEVELOPMENT, RE-COMPLETION OF WELLS FROM ONE RESERVOIR TO ANOTHER RESERVOIR,RESTORING WELLS TO PRODUCTION AND DRILLING AND COMPLETING NEW WELLS ARESPECULATIVE ACTIVITIES AND INVOLVE NUMEROUS RISKS AND SUBSTANTIAL AND UNCERTAINCOSTS.**

 

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

 

•                  unexpected drilling conditions;

•                  pressure or irregularities in formations;

•                  equipment failures or accidents;

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

 

11

----

 

•                  adverse weather conditions;

•                  compliance with governmental requirements;and

•                  shortages or delays in the availability ofdrilling rigs or crews and the delivery of equipment.

 

Drilling or re-working is ahighly speculative activity. Even when fully and correctly utilized, modernwell completion techniques such as hydraulic fracturing and horizontal drillingdo not guarantee that we will find crude oil and/or natural gas in our wells.Hydraulic fracturing involves pumping a fluid with or without particulates intoa formation at high pressure, thereby creating fractures in the rock andleaving the particulates in the fractures to ensure that the fractures remainopen, thereby potentially increasing the ability of the reservoir to produceoil or gas. Horizontal drilling involves drilling horizontally out from anexisting vertical well bore, thereby potentially increasing the area and reachof the well bore that is in contact with the reservoir. Our future drillingactivities may not be successful and, if unsuccessful, such failure would havean adverse effect on our future results of operations and financial condition.We cannot assure you that our overall drilling success rate or our drillingsuccess rate for activities within a particular geographic area will notdecline. We may identify and develop prospects through a number of methods,some of which do not include lateral drilling or hydraulic fracturing, and someof which may be unproven. The drilling and results for these prospects may beparticularly uncertain. Our drilling schedule may vary from our capital budget.The final determination with respect to the drilling of any scheduled orbudgeted prospects will be dependent on a number of factors, including, but notlimited to:

 

•                  the results of previous development effortsand the acquisition, review and analysis of data;

•                  the availability of sufficient capitalresources to us and the other participants, if any, for the drilling of theprospects;

•                  the approval of the prospects by otherparticipants, if any, after additional data has been compiled;

•                 economic and industry conditions at the timeof drilling, including prevailing and anticipated prices for crude oil andnatural gas and the availability of drilling rigs and crews;

•                 our financial resources and results;

•                 the availability of leases and permits onreasonable terms for the prospects; and

•                 the success of our drilling technology.

 

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

 

**CRUDE OILAND NATURAL GAS PRICES ARE HIGHLY VOLATILE IN GENERAL AND LOW PRICES WILLNEGATIVELY AFFECT OUR FINANCIAL RESULTS.**

 

Our revenues, operatingresults, profitability, cash flow, future rate of growth and ability to borrowfunds or obtain additional capital, as well as the carrying value of ourproperties, are substantially dependent upon prevailing prices of crude oil andnatural gas. Lower crude oil and natural gas prices also may reduce the amountof crude oil and natural gas that we can produce economically. Historically,the markets for crude oil and natural gas have been very volatile, and suchmarkets are likely to continue to be volatile in the future. Prices for crudeoil and natural gas are subject to wide fluctuation in response to relativelyminor changes in the supply of and demand for crude oil and natural gas, marketuncertainty and a variety of additional factors that are beyond our control,including:

 

•                worldwide and domestic supplies of crude oiland natural gas;

•                the level of consumer product demand;

•                weather conditions;

•                domestic and foreign governmentalregulations;

•                the price and availability of alternativefuels;

•                political instability or armed conflict inoil-producing regions;

•                the price and level of foreign imports; and

•                overall domestic and global economicconditions.

 

It is extremely difficult topredict future crude oil and natural gas price movements with any certainty.Declines in crude oil and natural gas prices may materially adversely affectour financial condition, liquidity, ability to finance planned capitalexpenditures and results of operations. Further, oil and gas prices do not movein tandem. Because approximately 63% of our reserves at July 1, 2007 are crudeoil reserves, we are more affected by movements in crude oil prices. While ournew projects are evaluated based on the assumption of oil and gas pricesconsiderably less than in the current market or projected in the futuresmarket, we do assume commodity prices will be higher than historic levels priorto 2004.

 

**OILFIELD SERVICE PRICES HAVE BEENESCALATING, AND THE AVAILABILITY OF SUCH SERVICES MAY BE INADEQUATE TO MEET OURNEEDS.**

 

Our business plan toredevelop mature oil and gas resources requires third party oilfield servicevendors, which we do not control. Long lead times and spot shortages of any ofa myriad of services we may require to redevelop our properties may prevent usfrom, or delay us in, maintaining or increasing the production volumes weexpect. In addition, the recent escalating costs for such services may rendercertain or all of our projects uneconomic, as compared to the earlier prices wemay have assumed when deciding to redevelop newly purchased or existingproperties. Further adverse economic outcomes may result from the long leadtimes often necessary to execute and complete our redevelop plans.

 

12

----

 

**GOVERNMENTREGULATION AND LIABILITY FOR ENVIRONMENTAL MATTERS MAY ADVERSELY AFFECT OURBUSINESS AND RESULTS OF OPERATIONS.**

 

Crude oil and natural gasoperations are subject to extensive federal, state and local governmentregulations, which may be changed from time to time. Matters subject toregulation include discharge permits for drilling operations, drilling bonds,reports concerning operations, the spacing of wells, unitization and pooling ofproperties and taxation. From time to time, regulatory agencies have imposedprice controls and limitations on production by restricting the rate of flow ofcrude oil and natural gas wells below actual production capacity in order toconserve supplies of crude oil and natural gas. There are federal, state andlocal laws and regulations primarily relating to protection of human health andthe environment applicable to the development, production, handling, storage,transportation and disposal of crude oil and natural gas, by-products thereofand other substances and materials produced or used in connection with crudeoil and natural gas operations. In addition, we may inherit liability forenvironmental damages caused by previous owners of property we purchase orlease or nearby properties. As a result, we may incur substantial liabilitiesto third parties or governmental entities. We are also subject to changing andextensive tax laws, the effects of which cannot be predicted. Theimplementation of new, or the modification of existing, laws or regulationscould have a material adverse effect on us.

 

**RisksAssociated with Our Stock**

 

**OUR STOCKPRICE HAS BEEN AND MAY CONTINUE TO BE VERY VOLATILE.**

 

Our common stock is thinlytraded and the market price has been, and is likely to continue to be, highlyvolatile. For example, during the year prior to June 30, 2007, our stock priceas traded on the American Stock Exchange ranged from $2.38 to $3.66. Thevariance in our stock price makes it extremely difficult to forecast with anycertainty the stock price at which an investor may be able to buy or sellshares of our common stock. The market price for our common stock could be subjectto wide fluctuations as a result of factors that are out of our control, suchas:

 

•                actual or anticipated variations in ourresults of operations;

•                naked short selling of our common stock andstock price manipulation;

•                changes or fluctuations in the commodityprices of crude oil and natural gas;

•                general conditions and trends in the crudeoil and natural gas industry; and

•                general economic, political and marketconditions.

 

**OUREXECUTIVE OFFICERS, DIRECTORS AND AFFILIATES MAY BE ABLE TO CONTROL THEELECTION OF OUR DIRECTORS AND ALL OTHER MATTERS SUBMITTED TO OUR STOCKHOLDERSFOR APPROVAL.**

 

The following sharecalculations treat shares issuable upon the exercise of options or warrants asoutstanding (both in the numerator and denominator for percentages) and assumeactual vesting.

 

Our executive officers anddirectors, in the aggregate, beneficially own approximately 11 million sharesor approximately 38% of our outstanding common stock, inclusive of which ourChairman of the Board, Mr. Laird Q. Cagan, Managing Director of Cagan McAfeeCapital Partners, LLC (“CMCP”) currently owns or controls, directly orindirectly, approximately 7.7 million shares, or approximately 29% of ouroutstanding common stock. Mr. Eric McAfee, a Managing Director of CMCP, currentlyowns or controls, directly or indirectly, approximately 5.1 million shares, orapproximately 19% of our outstanding common stock, but is neither an officernor a member of our board of directors. Collectively, the two managingdirectors of CMCP currently own or control, directly or indirectly,approximately 12.9 million shares, or approximately 47% of our outstandingcommon stock. As a result, these holders, if they were to act together, couldexercise effective control over all matters submitted to our stockholders forapproval (including the election and removal of directors and any merger,consolidation or sale of all or substantially all of our assets). Thisconcentration of ownership may have the effect of delaying, deferring orpreventing a change in control of our company, impede a merger, consolidation,takeover or other business combination involving our company or discourage apotential acquirer from making a tender offer or otherwise attempting to obtaincontrol of our company, which in turn could have an adverse effect on themarket price of our common stock.

 

**THE MARKETFOR OUR COMMON STOCK IS LIMITED AND MAY NOT PROVIDE ADEQUATE LIQUIDITY.**

 

Our common stock iscurrently thinly traded on the American Stock Exchange. In the year prior to June30, 2007, the actual trading volume in our common stock ranged from a low of1,200 shares of common stock traded to a high of 532,900 shares of common stocktraded, with only 61 days exceeding a trading volume of 50,000 shares. On mostdays, this trading volume means there is limited liquidity in our shares ofcommon stock. Selling our shares is more difficult because smaller quantitiesof shares are bought and sold and news media coverage about us is limited.These factors result in a limited trading market for our common stock andtherefore holders of our stock may be unable to sell shares purchased shouldthey desire to do so.

 

**IF SECURITIES OR INDUSTRYANALYSTS DO NOT PUBLISH RESEARCH REPORTS ABOUT OUR BUSINESS OR IF THEYDOWNGRADE OUR STOCK, THE PRICE OF OUR COMMON STOCK COULD DECLINE.**

 

Small, relatively unknowncompanies can achieve visibility in the trading market through research andreports that industry or securities analysts publish. However, to ourknowledge, only one non-company paid analyst and one company paid analyst coverour company. The lack 

 

13

----

 

of published reports byindependent securities analysts could limit the interest in our common stockand negatively affect our stock price. We do not have any control over theresearch and reports these analysts publish or whether they will be publishedat all. If any analyst who does cover us downgrades our stock, our stock pricewould likely decline. If any analyst ceases coverage of our company or fails toregularly publish reports on us, we could lose visibility in the financialmarkets, which in turn could cause our stock price to decline.

 

**THEISSUANCE OF ADDITIONAL COMMON AND PREFERRED STOCK WOULD DILUTE EXISTINGSTOCKHOLDERS.**

 

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

 

•                exercising voting, redemption and conversionrights to the detriment of the holders of common stock;

•                receiving preferences over the holders ofcommon stock regarding our surplus funds in the event of our dissolution orliquidation;

•                delaying, deferring or preventing a change incontrol of our company; and

•                discouraging bids for our common stock.

 

**WE DO NOTPLAN TO PAY ANY CASH DIVIDENDS ON OUR COMMON STOCK.**

 

We have not paid anydividends on our common stock to date and do not anticipate that we will bepaying dividends in the foreseeable future. Any payment of cash dividends onour common stock in the future will be dependent upon the amount of fundslegally available, our earnings, if any, our financial condition, ouranticipated capital requirements and other factors that our board of directorsmay think are relevant. However, we currently intend for the foreseeable futureto follow a policy of retaining all of our earnings, if any, to finance thedevelopment and expansion of our business and, therefore, do not expect to payany dividends on our common stock in the foreseeable future.

 

**ITEM 2.DESCRIPTION OF PROPERTIES.**

 

***Enhanced Oil Recovery(EOR) Property***

 

Our EOR Initiative targetsthe use of miscible and immiscible gas flooding to achieve economicredevelopment and production of tertiary crude oil resources. Field candidatesare likely to have already completed primary and secondary recovery operations,generally through water flooding.

 

**Delhi Field**

 

The Delhi Holt Bryant Unitin the Delhi Field, currently our most strategic asset, is in the early stagesof being redeveloped by Denbury, as operator, through an enhanced oil recovery(EOR) project utilizing CO2 technology:

 

•                  As of June 30, 2007, Denbury reported to usthat approximately $27.75 million of capital has been charged to the project.

 

•                  On August 2, 2007, Denbury announced that thefirst leg of the Delhi CO2 pipeline, from Jackson Dome to Tinsley Field, was56% complete.

 

•                  Via public presentations, Denbury continuesto state that first CO2 injection at Delhi should occur in 2008 and thatsignificant oil production from Delhi is projected for 2009.

 

We, and various othercompanies that submitted offers to participate with us, believe that the DelhiHolt Bryant Unit is an excellent candidate for a CO2-EOR project due to itsfavorable rock characteristics, large unproven reserves remaining in place,miscibility potential, low cost of drilling to a relatively shallow depth andrelatively close location to naturally occurring CO2 reserves approximately 100miles east of the Delhi Field. In June 2006, we conveyed a farmout to Denburyfor all of our working interests in the Delhi Holt Bryant Unit and 75% of ourworking interests in certain other depths of the Delhi Field. For this, wereceived approximately $50 million in cash, a 25% back-in working interest inthe Delhi Holt Bryant Unit and a commitment by Denbury Resources to install aCO2-EOR project in the Delhi Holt Bryant Unit (the **“DelhiFarmout”**), while also retaining separately acquired royalty andoverriding royalty interests aggregating 7.4% in the Holt Bryant Unit, asdescribed in more detail below.

 

The Delhi Field was discovered in the mid-1940’s and was extensivelydeveloped by various operators including the Sun Oil and Murphy Oil companiesthrough the drilling and completion of approximately 450 wells, most within thefirst few years after discovery. According to W. D. Von Gonten & Co., thethird party reservoir engineering firm that prepares our independent estimateof proved reserves, the Delhi Field has produced more than 200 million barrelsof crude oil and substantial amounts of natural gas to date. Much of thenatural 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 common 

 

14

----

 

operations are conductedover multiple leases). Drilling operations resulted in primarily 40-acrespacing across the unit’s 13,636 acres. A few wells were drilled below thetargeted Tuscaloosa and Paluxy formations. The water injection pressuremaintenance waterflood did not utilize a more traditional and effective fivespot flood pattern that generally results in a more complete reservoir sweepand oil recovery.

 

At the time we began our oiland gas operations in late September 2003, we purchased 100% of the workinginterests and an 80% net revenue interest in the Delhi Field (from the surfaceto the top of the Massive Anhydride, but excepting the Mengel Unit), forapproximately $2.8 million, including the assumption of a plugging andabandonment reclamation bond. All but 43 wells in Richland, Franklin andMadison Parishes, Louisiana had been plugged and abandoned and productionaveraged approximately 18 BOPD with no natural gas being sold due to a lack ofnatural gas processing and transportation facilities. The best producing wellwas immediately lost during a periodic sand wash work-over when water from alower reservoir broke through along the casing exterior and into the producingreservoir.

 

In October of 2003, weapplied an unproven lateral re-entry technology that resulted in no increase inproduction. In December 2003, we initiated a development program based onre-completion of wells to other reservoirs and restoring non-producing wells toproducing status. During 2004, we refurbished a gas injection line necessary toserve as our gas gathering line and placed a gas processing plant in the field,thus re-starting shut-in natural gas production in July of 2004. During 2005,we began a five well development drilling program aimed at reaching mostlyproved undeveloped reserves left in primary “attic” positions. The culminationof these activities caused production to increase from 18 BOPD to a monthlyaverage rate of 145 BOEPD during our peak production month in late 2005.

 

Concurrent with theseactivities, we completed internal studies indicating that the reservoirs in theDelhi Holt Bryant Unit, the dominant oil producing reservoirs, were believed tobe less than 50% depleted. Based on positive CO2 pilots conducted by Sun Oil in1985, and favorable rock characteristics shown in multiple cores takenthroughout the Delhi Field, we began discussions in late 2004 with industrypartners skilled in tertiary/EOR recovery methods, especially with respect toCO2 injection.

 

With positive industryreception, and following extended negotiations with three candidate partners,we accelerated our redevelopment plan in June 2006 by selling a major portionof our Delhi Field interests in the form of a farmout (the “Delhi Farmout”) toa subsidiary of Denbury. Important aspects of this transaction include:

 

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

 

•                  Denbury committed to install a CO2-EORproject in the Holt Bryant Unit and is obligated to expend a minimum of $100million on the project over the next 6-1/2 years, subject to penalty paymentsto us for shortfalls in such expenditures. All capital expenditures necessaryto install the project are required to be borne by DNR.

 

•                  Denbury, the dominant CO2-EOR operator on theGulf Coast, currently operates several CO2-EOR projects, and owns naturallyoccurring CO2 reserves we believe to be sufficient to meet the needs of theDelhi project and which have been dedicated to the Delhi Project.

 

•                  We retained significant participatinginterests through separately acquired royalty and overriding royalty interestsaggregating 7.4%, and a 25% back-in working interest (20% revenue interest). Weexpect the value of these interests will substantially exceed the $50 millioncash component of the Delhi Farmout.

 

•                  Our 25% back-in working interest in theCO2-EOR project is based on a defined $200 million threshold, and our back-inoccurs when cumulative project net revenues less direct operating costs in thefield reach the threshold.

 

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

 

•                  We expect to be able to claim proven reservesfollowing the first injection of CO2 and demonstration of production response,projected to occur in 2009.

 

***Bypassed Resource Property***

 

Our Bypassed ResourceInitiative targets the economic development or redevelopment of primarypetroleum resources previously bypassed by industry in mature, historicallyproductive formations generally due to inadequate technology or commodityprices.

 

**Texas**

 

Following the closing of ourDelhi Farmout in June 2006, we began the process of identifying new BypassedResource Initiative projects. In selecting our four candidates:

 

•                We leveraged our staff’s extensiveexperience, gained over many years while employed at UPRC & AnadarkoPetroleum, in the pioneering of horizontal drilling practices adapted tofurther develop and produce the Austin Chalk and Georgetown formations.

 

•                We sought “flush production” projects thatcould provide substantial early revenues prior to peak production from theDelhi field.

 

•                We sought exposure to both crude oil andnatural gas opportunities.

 

15

----

 

Following projectidentification and economic analysis, we began leasing activities in December,2006. Although leasing is far from complete, we had acquired 3,449 net acres asof June 30, 2007. Based on an independent reserve report from W.D. Von Gonten& Co. dated July 1, 2007, this leasing resulted in approximately:

 

•                  1,272,000 proved undeveloped BOE

 

•                  50% oil and 50% gas, and

 

•                  $25,715,000 of PV10.

 

**TullosField Area**

 

On September 3, 2004,through a wholly-owned subsidiary, we completed the acquisition of a 100%working interest and approximately 78% average net revenue interest inproducing and shut-in crude oil wells, water disposal wells, equipment andimprovements located in the Tullos Urania, Colgrade and Crossroads Fields inLaSalle and Winn Parish, Louisiana, collectively referred to as the TullosField Area. The purchased assets included 124 completed wells, 9 water disposalwells, and all associated infrastructure, including water disposal facilities,crude oil and water tanks, flow lines and pumping units. Fifteen of these crudeoil wells required new leases. Of the purchased wells, 81 were producing and 43were shut-in due to repair and maintenance requirements. The purchase price forthe acquisition was $725,000 before adjustment for post-effective dateproduction and expenses.

 

In early February 2005, weclosed the purchase of a 100% working interest and approximately 79% averagenet revenue interest in additional properties in the same Tullos Urania andColgrade Fields. The purchased assets included 65 producing crude oil wells, 56shut-in crude oil wells, 8 salt water disposal wells and associatedinfrastructure and equipment. The purchase price for the acquisition was$798,907, after post-closing adjustments.

 

The original developmentplan for the properties included restoring wells to production and increases inproduced water disposal capacity. Oil production from wells is generally in theform of fluid that is 99.5% brine water on average, and oil production rate isconstrained by the capacity to properly dispose of the produced water. The highlevel of industry activity, however, has reduced the availability of oil fieldservices, particularly workover rigs, and our wells require substantial ongoingmaintenance and repairs that had been neglected in the year prior to the sale. Thus,the initial focus of operations was on restoring the stated production level ofthe then producing wells. We first applied to state regulatory agencies forrequired permits to convert wells to disposal use in 2005, and received thefirst permit in the spring of 2006. Following conversion, the state agenciesmust then authorize use of the converted well. The conversion process isongoing and four disposal wells were completed in fiscal 2007.

 

We are reviewing the resultsof our development program and the ongoing high level of required maintenanceand repairs to determine other options to maximize our value in the TullosField Area. In this regard, we have researched, analyzed and chosen are-completion technique to increase the oil cut rate. In March, 2007, weattempted to test an existing well bore, but were not able to make there-completion due to the poor condition of the down-hole equipment. Lackingother candidates possessing the necessary well bore size needed to test thecompletion technology, we chose to drill a new well. This well has been drilledand completion operations are under way. If economically successful, we believethis technique could be applied to many other fields along the Gulf Coast withsimilar high water cut production characteristics.

 

***Unconventional Natural GasResource Property***

 

Our Unconventional NaturalGas Resource Initiative targets the use of modern stimulation and completiontechnologies for the economic development and production of tight gasformations.

 

Following the closing of ourDelhi Farmout in June 2006, we began the process of identifying UnconventionalNatural Gas Resource Initiative projects. In choosing our two currentcandidates:

 

•                  We are leveraging our staff’s expertise inhorizontal drilling and tight gas development, a prerequisite to successfullyexploiting and developing these resources;

 

•                  We focused on locations of source rockformations that are well known, especially shales and coals;

 

•                  We considered that these projects requirelarge amounts of capital over long periods of time, thereby providingreinvestment opportunities to absorb the substantial cash flows we expect fromour future Delhi EOR and Bypassed Resource production; and

 

•                  We are adding additional natural gas exposureto our existing oil exposure.

 

We began actively acquiringleases for these two projects in May 2007. At June 30, 2007, we had acquiredapproximately 2,290 gross and 1,145 net acres across two projects, with activeleasing still continuing.

 

**OtherOperations**

 

We maintain insurance on ourproperties and operations for risks and in amounts customary in the industry.Such insurance includes general 

 

16

----

 

liability, excess liability,control of well, operators extra expense and casualty coverage. Not all lossesare insured, and we retain certain risks of loss through deductibles, limitsand self-retentions. We do not carry lost profits coverage, and our aviationliability insurance coverage is limited to $1million.

 

Effective on March 1, 2007,we entered into a sublease agreement with Aspen Technology, Inc to rent approximately8,400 square feet of Class “A” office space in the Westchase District area inWest Houston. The terms of the lease are approximately nine years. Prior tothat, we occupied a leased headquarters containing 2,259 square feet in amodern high-rise office building located in the West Memorial area of Houston,Texas. In April 2007, this lease expired. For more complete informationregarding current year activities, including crude oil and natural gasproduction, refer to “Management’s Discussion and Analysis of FinancialCondition and Results of Operations.”

 

**Significant Properties, EstimatedProved Oil and Gas Reserves, and Future Net Revenues**

 

We engaged W. D. Von Gonten& Co. (“Von Gonten”) to prepare an independent report of our provedreserves located in the Delhi Field, Texas properties and Tullos Field Area asof July 1, 2007. Von Gonten also previously prepared independent reports of ourproved reserves at July 1, 2006, July 1, 2005, July 1, 2004 and January 1,2004.

 

Estimates of reservequantities and values must be viewed as being subject to significant change asmore data about the properties becomes available. Many, if not most, of ourexisting wells are generally mature wells, originally drilled as early as the1920’s. As such, they contain older down-hole equipment and casing that is moresubject to failure than new equipment. The failure of such equipment or othersubsurface failure can result in the complete loss of a well.

 

At July 1, 2007, natural gasrepresented 37% and crude oil represented 63% of total proved reserves,denominated in equivalent barrels using a six MCF of gas to one barrel of oilconversion ratio, as compared to 1% and 99%, respectively, at July 1, 2006. Theincrease in proved reserves was mostly due to the proved undeveloped reserveswe acquired through mineral leasing activities during the last half of fiscal2007 and development opportunities identified in the Tullos Field Area.

 

The following table setsforth, as of July 1, 2007 and July 1, 2006, information regarding our provedreserves based on the assumptions set forth in Note 10 to the ConsolidatedFinancial Statements, where additional reserve information is provided. Theaverage NYMEX prices used to calculate estimated future net revenues were$70.68 and $73.93 per barrel of oil and $6.80 and $6.10 per MMBTU of gas as ofJune 30, 2007 and June 30, 2006, respectively. The average NYMEX prices usedwere adjusted for transportation, market differentials and BTU content of gasproduced. Amounts do not include estimates of future Federal and State incometaxes.

 

| ** **   | ** ** | ** ** | ** ** | ** ** | ** ** | ** **                | ** ** | **Estimated Future**       | ** ** |
|--------------|------------|------------|------------|------------|------------|---------------------------|------------|---------------------------------|------------|
| ** **   | ** ** | **Oil**    | ** ** | **Gas**    | ** ** | **Estimated Future** | ** ** | **Net Revenues**           | ** ** |
| ** **   | ** ** | **(bbls)** | ** ** | **(mcf)**  | ** ** | **Net Revenues**     | ** ** | **Discounted at 10%** | ** ** |
|         |       |       |       |       |       |                      |       |                            |       |
| July 1, 2007 |       | 1,084,000  |       | 3,838,000  |       | $                         | 50,009,883 |                            | $          | 33,327,359 |   |
| July 1, 2006 |       | 460,525    |       | 25,800     |       | $                         | 14,141,560 |                            | $          | 8,038,791 |   |

 

At July 1, 2007, ProvedDeveloped reserves (including Proved Developed non-producing) totaled 23% ofTotal Proved reserves, the balance consisting of Proved Undeveloped reserves.

 

At July 1, 2006, ProvedDeveloped reserves totaled 82% of Total Proved reserves, the balance consistingof Proved Undeveloped reserves.

 

**Production,Average Sales Prices and Average Production Costs**

 

The following table setforth certain information regarding production volumes, oil and gas sales,average sales prices received and expenses for the periods indicated:  

 
| ** **  | ** ** | **Year**                               | ** ** | **Year**                               | ** ** |
|-------------|------------|----------------------------------------|------------|----------------------------------------|------------|
| ** **  | ** ** | **ended June 30, 2007** | ** ** | **ended June 30, 2006** | ** ** |
| **Product** | ** ** | **Volume**                             | ** ** | **Price**                              | ** ** | **Volume** | ** ** | **Price** | ** ** |
|        |       |                                   |       |                                   |       |   |   |   |   |
| Gas (Mcf)   |       | —                                 |       | —                                 |       | 44,745 |   | $ | 9.48 |   |
|        |       |                                   |       |                                   |       |   |   |   |   |
| Oil (Bbls)  |       | 29,148                                 |       | $                                      | 64.05      |   | 42,869 |   | $ | 56.85 |   |
|             |            |                                        |            |                                        |            |  |  |  |  |  |  |

 

Average production costs,including production taxes, per unit of production (using a six to oneconversion ratio of Mcf’s to barrels) were approximately $49 and $35 per barrelof oil equivalent for the years ended June 30, 2007 and 2006, respectively.

 

Reduced volumes for the yearended June 30, 2007, as compared to the year ended June 30, 2006, were mostlyattributable to the near term loss of our working interest in the Delhi HoltBryant Unit, which is undergoing installation of a CO2-EOR operation. Under theJune 2006 Delhi Farmout agreement, we retained separately acquired royalty andoverriding royalty interests aggregating approximately 7.4% on all present andfuture 

 

17

----

 

production in the Delhi HoltBryant Unit, plus a 25% reversionary working interest after payout, as defined.

 

**ProductiveWells and Developed Acreage**

 

Developed acreage at June30, 2006 totaled 599 net and gross acres, all of which is in the Tullos FieldArea in La Salle and Winn Parish Louisiana. This is a reduction from thebeginning of the prior year by 13,636 acres, due to the Delhi Farmout, whichbecame effective as of June 1, 2006.

 

At June 30, 2007, we ownedworking interests in 260 net and gross wells consisting of 158 crude oil wells,23 salt water disposal wells and 93 shut-in wells with uncertain futureutility, all located in the Tullos Field Area. Approximately 75% of the shut-incrude oil wells in the Tullos Field Area are believed, in most part, to becapable of production following varying degrees of repair and maintenance orincremental water disposal capacity.

 

**UndevelopedAcreage**

 

As of June 30, 2007, we heldapproximately 19,572 gross and 8,003 net undeveloped acres in the Gulf Coastand Mid-Continent regions of the United States, as follows:

 

| **Region/Field**          | ** ** | **Gross Acreage** | ** ** | **Net Acreage*** | ** ** |
|---------------------------|------------|------------------------|------------|-----------------------|------------|
| Mid-Continent             |       | 2,290                  |       | 1,145                 |       |
| Gulf Coast                |       | 3,646                  |       | 3,449                 |       |
| Gulf Coast, Delhi Field** |       | 13,636                 |       | 3,409                 |       |
| Total                     |       | 19,572                 |       | 8,003                 |       |

 

----

*Of these acres, 31% or2,494 net acres were proved.

 

** Includes from the surfaceof the Earth to the top of the Massive Anhydride, less and except the DelhiHolt Bryant CO2 and Mengel Units. With respect to the Delhi Holt Bryant Unit,currently scheduled for CO2-EOR operations within this same acreage, wecurrently hold royalty and overriding royalty interests aggregatingapproximately 7.4%, and a 25% working interest that will revert to us, as, ifand when payout occurs, as defined. We are not the operator of the CO2-EORproject.

 

**Drilling**

 

During the year ended June30, 2007, no new wells were drilled. During the year ended June 30, 2006, wedrilled and completed 5 new development wells in the Delhi Field.

 

**SubsequentEvents**

 

On August 3, 2007, we wereadvised of an oil spill in the Tullos Field near one of our leases. At therequest of field agents of the Louisiana Department of Environmental Qualityand the EPA, we agreed to commence a clean-up operation that was completed bythe end of August 2007. A detailed analysis of the oil in the spill compared toour produced oil was conducted by an EPA approved laboratory. We believe thatthe various independent analyses show, supported by the formal findings of thelaboratory, that the oil in the spill did not originate from our operations. Wealso believe that most of the estimated $600,000 of costs incurred in thecleanup, before adjustment following audit and negotiation of the billings,will be covered by insurance or reimbursement from the relevant government oilspill funds, but we can give no assurance that such reimbursement will occur. Allclean up costs, net of any reimbursements, will be expensed as incurred.

 

In August 2007, the board ofdirectors approved a resolution to issue a total of 125,000 shares of commonstock options to three new employees as part of their total compensation foremployment. The options are excisable at the closing price of the common stockon the date of issuance and vests in equal amounts quarterly over four years,subject to other standard terms and conditions as provided by the Company.

 

In September 2007, the boardof directors approved a resolution to issue a total of 1,010,000 shares ofcommon stock options to existing employees as part of their long term incentivecompensation. The options are excisable at the closing price of the commonstock on the date of issuance and vest in equal amounts quarterly over fouryears, subject to other standard terms and conditions as provided by theCompany.

 

**ITEM 3.LEGAL PROCEEDINGS.**

 

On November 17, 2005, amulti-plaintiff lawsuit was filed in the Fifth Judicial District Court,Richland Parish, Louisiana, against 18 defendants including NGS Sub Corp. andArkla Petroleum LLC, our wholly owned subsidiaries, as working interest owners/operatorsof various oil and gas leases in the Delhi Field. Plaintiffs claim that thedefendants’ oil and gas exploration, development and production activities ontheir properties has caused soil and ground water contamination as a result ofthe release of hydrocarbons and drilling fluids. Plaintiffs seek damages fortesting, clean-up and remediation of the properties as well as diminution intheir value and mental anguish to the individual plaintiffs, unjust enrichmentand punitive damages for alleged concealment of ongoing activities.

 

All defendants have filedexceptions to plaintiffs’ suit alleging that it is premature, its allegationsare vague and that administrative review 

 

18

----

 

through the Louisiana Officeof Conservation rather than legal action in the court is plaintiffs’ properremedy. These exceptions have not yet been heard by the court. Discovery hasjust begun and the allegations of plaintiffs’ suit are so vague that thespecifics of their claims cannot be determined yet with certainty.

 

Managementintends to contest plaintiffs’ claims vigorously. To this point, plaintiffshave not produced any evidence of specific damage to their lands by defendants’oil and gas operations. While the Delhi Field has been in production for overfifty years, NGS Sub Corp. and Arkla Petroleum LLC have only been the owner andoperator for the period of time beginning 2003 and ending in 2006, and webelieve that no contamination of significance occurred during our period ofownership. We believe that our liability exposure results largely through anypotential contractual indemnity of prior working interest owners. Until suchtime as the specifics of plaintiffs’ claims are identified through thediscovery process, and particularly any evidence of actual contamination ofsoil or groundwater, the amount of any judgment that might be rendered cannotbe determined with accuracy.

 

During the quarter ended June 2006, the Governor of the State ofLouisiana signed into law new legislation addressing complaints similar to andincluding those filed against us. Although the intention of the legislation wasdesigned to limit plaintiff complaints and remedies by possibly deferring firstto administrative experts within the Louisiana State Departments ofEnvironmental Quality and Natural Resources, it is unclear at this time theimpact of such legislation.

 

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

 

There were no matterssubmitted during the fourth quarter of the fiscal year covered by this reportto a vote of security holders through the solicitation of proxies or otherwise.

 

**PART II**

 

**ITEM 5.MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND SMALL BUSINESS ISSUERPURCHASES OF EQUITY SECURITIES.**

 

**Common Stock**

 

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

 

We initiated trading of ourcommon stock on the OTC Bulletin Board in May 2004, under the symbol “NGSY”. OnJuly 17, 2006 we qualified for trading on the American Stock Exchange. Thefollowing table shows, for each quarter of fiscal 2007 and 2006, the high andlow closing sales prices as reported by the American Stock Exchange and the OTCBulletin Board. The quotations from the OTC Bulletin Board representinter-dealer prices, without retail mark-up, markdown or commissions, and maynot represent actual transactions.

 

**American Stock Exchange / OTC Bulletin Board**

 

| **2007:**                              | ** ** | **High** | ** ** | **Low** | ** ** |
|----------------------------------------|------------|----------|------------|---------|------------|
| Fourth quarter ended June 30, 2007     |       | $        | 3.66       |    | $          | 2.42 |   |
| Third quarter ended March 31, 2007     |       | $        | 3.18       |    | $          | 2.49 |   |
| Second quarter ended December 31, 2006 |       | $        | 3.04       |    | $          | 2.38 |   |
| First quarter ended September 30, 2006 |       | $        | 3.30       |    | $          | 2.64 |   |

 

| **2006:**                              | ** ** | **High** | ** ** | **Low** | ** ** |
|----------------------------------------|------------|----------|------------|---------|------------|
| Fourth quarter ended June 30, 2006     |       | $        | 3.70       |    | $          | 2.01 |   |
| Third quarter ended March 31, 2006     |       | $        | 2.65       |    | $          | 1.31 |   |
| Second quarter ended December 31, 2005 |       | $        | 2.05       |    | $          | 1.15 |   |
| First quarter ended September 30, 2005 |       | $        | 2.05       |    | $          | 1.00 |   |

 

**Holders**

 

Asof June 30, 2007, there were 26,776,234 shares of common stock issued andoutstanding, held by approximately 182 holders of record.

 

**Dividends**

 

We have never declared or paid any cash dividends with respect to ourcommon stock. 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.

 

19

----

 

**Securities authorized forissuance under equity compensation plans**

 
| ** **                                                  | ** ** | **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     |       | 3,223,242               | (1)        | $                          | 1.50       |                               | 1,286,758  |   |
| Equity compensation plans not approved by  security holders |       | 1,453,021               | (2)        | $                          | 1.51       |                               | —     |   |
| Total                                                       |       | 4,676,263               |       | $                          | 1.50       |                               | 1,286,758  |   |

 

----

(1) On May 26, 2004, we, asReality Interactive, Inc., executed an Agreement and Plan of Merger withNatural Gas Systems, Inc., a Delaware corporation (the “Merger”). In connectionwith the Merger, we assumed the obligations of 600,000 stock options under ournewly acquired subsidiary’s 2003 Stock Option Plan. As of June 30, 2007,510,000 shares remain issuable upon exercise under the 2003 Stock Option Planand no further options shall be issued thereunder. As of June 30, 2007, therewere 2,511,000 shares of common stock issued or issuable upon exercise ofoutstanding options and 202,242 shares issued directly under the 2004 StockPlan, leaving 1,286,758 shares of common stock available for issuance.

 

(2) In addition to assumingcertain obligations listed in footnote 1 above, in connection with the Merger,we also assumed outstanding warrants to purchase 319,931 shares of common stockat an exercise price of $1.00, with a seven year term (warrants), of which287,931 remain outstanding and un-exercised. Of these aforementioned warrants,240,000 of these were issued to CMCP and their assigns in connection witharranging the merger, of which 215,000 remain outstanding and un-exercisedand  79,931 were issued to Laird Q.Cagan, Chadbourn Securities and their assigns in connection with capitalraising services, of which 72,931 remain outstanding and un-exercised.Subsequently, we issued warrants to purchase 122,590 shares of common stock toLaird Q. Cagan, Chadbourn Securities and their assigns in connection withcapital raising services, a warrant to purchase 50,000 shares for capitalraising services in connection with arranging our loan with Prospect EnergyCorporation, of which 5,000 shares remain outstanding and un-exercised, awarrant to purchase 287,500 shares of common stock in connection with Mr.Herlin’s employment agreement with the Company, a warrant to purchase 200,000shares in connection with Mr. Mazzanti’s employment agreement with the Company,a warrant to purchase 400,000 shares of common stock in connection with Mr.Herlin’s annual performance incentives and a warrant to purchase 150,000 sharesof common stock in connection with Sterling McDonald’s annual performanceincentives.

 

**RecentSales of Unregistered Securities**

 

In November 2006, we made adirect stock grant for 50,000 shares to Liviakis Communications for investorrelations services. In May 2007, we issued 16,987 shares of our common stockunder a cashless exercise, thereby fully retiring a warrant to purchase 25,000of our common shares at $1 per share. The shares issued during the period wereexempted from registration in reliance upon Section 4(2) of the Securities Actof 1933, as amended, and Regulation D promulgated thereunder.

 

20

----

 

**ITEM 6.MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION.**

 

**Oil & Gas Activities andReserves**

 

As previously reported,fiscal 2007 was expected to be a transitional year following the June 2006closing of the farmout of our Delhi Holt Bryant Unit in the Delhi Field toinstall a CO2 enhanced oil recovery project (the “**DelhiFarmout**”). We understood that the Delhi Farmout would eliminate ourrevenues and net income from the Delhi Field producing wells until such time asthe operator commenced EOR field production, most likely after mid-calendar2008. We also projected that the interest income on the net cash proceeds fromthe Delhi Farmout would more than make up for this lost income, while alsoproviding a funding source to accelerate the development of new project in ourBypassed Resource and Unconventional Gas Resource Initiatives. Theseexpectations and projections were borne out during the fiscal year 2007.

 

Our ongoing strategic planis to maximize shareholder value by utilizing our staff expertise and strongbalance sheet to develop near term revenues through our Bypassed Resourceprojects and to seed our Unconventional Gas Resource projects through acreageacquisitions. Net cash flows from the Bypassed Resource projects and the DelhiFarmout then will be utilized to begin full development of our UnconventionalGas Resource projects, our new EOR projects and future growth.

 

**EPMBusiness Plan**

* Current cashresources feed Bypassed Resource Projects for near term revenues 

** Cash generated from Bypassed Resource Projects and Delhi then feedpending projects in Unconventional Gas and EOR

 

 

***Bypassed ResourceInitiative:***

 

As previously reported, webegan leasing in December 2006 on four Bypassed Resource projects located inTexas. This initiative targets the leasing of specific well sites in order toaccess previously bypassed primary resources, in known productive fields, thatwe believe exhibit fairly predictable reserves and production. With thispursuit, we leverage our operating personnel’s successful track record andknowledge of specific reservoirs, fields and horizontal drilling techniques. Bythe end of our fiscal year ended June 30, 2007, we had leased 3,646 gross and3,449 net acres in these projects. Based on an independent reserve report fromW.D. Von Gonten & Co. dated July 1, 2007, these leasing activities resultedin:

 

•                  The addition of approximately 1,272,000 BOEof Proved Undeveloped reserves.; and

 

•                  The addition of approximately $25,714,000 inPV-10, or $0.96 per outstanding common share.

 

•                  The addition of both natural gas and oil toour previous oil exposure.

 

Our fifth Bypassed Resourceproject is in our Louisiana Tullos Field Area, which also supplies all of ourcurrent production. Our plans for Tullos have been carried out in part throughthe conversion of five wells to salt water disposal and restarting productionin numerous shut-in producer wells during fiscal 2007 and part of fiscal 2006. InMarch 2007, we attempted to test a new completion technique in an existing,inactive well bore, but were unsuccessful in making the re-completion due tothe poor downhole condition of the well. Lacking other well bore candidateswith the necessary size to test 

 

21

----

 

the technology, we electedto drill a new well. This well was drilled in September 2007 and we anticipatethat testing of the technology will extend to the end of calendar year 2007. Ifsuccessful, we believe this technique could be applied to increase productionin a large number of fields along the Gulf Coast that exhibit similar highwater cut production and other reservoir characteristics.

 

***Enhanced Oil Recovery(EOR) Initiative:***

 

Our EOR projects target theuse of miscible and immiscible gas flooding techniques, potentially combinedwith the completion technology developed in Tullos, to develop tertiaryreserves from otherwise “depleted” oil fields. Our most substantial EOR assetis the Delhi Holt Bryant Unit CO2-EOR project, that continues to progress onschedule:

 

•                  As of June 30, 2007, Denbury reported to usthat approximately $27.75 million of capital has been charged to the project.

 

•                  On August 2, 2007, Denbury announced that thefirst leg of the Delhi CO2 pipeline, from Jackson Dome to Tinsley Field, was56% complete.

 

•                  Via public presentations, Denbury continuesto state that first CO2 injection at Delhi should occur in 2008 and thatsignificant oil production from Delhi is projected for 2009.

 

We view these as positivesigns that our significant ownership interests in this project, including 7.4%in royalty and overriding royalty interests and a 25% back-in after payout, aremoving closer to fruition.

 

Currently, we have begunearly development work on our next EOR project.

 

***Unconventional GasResource Initiative:***

 

Subsequent to March 31,2007, we began leasing on two Unconventional Natural Gas Resource projects. Theseprojects are targeted at known reservoirs of “unconventional natural gas”,meaning natural gas stored in “tight” formations. Our focus is on source rocksthat have low permeability, repeatable similar drilling results and extend overlarge areas, such as shales and coals. Our operating staff’s extensiveexperience in horizontal drilling and unconventional gas reservoirs is key,since horizontal drilling practices are generally required for positiveeconomic results from these reservoirs.

 

These projects are expectedto require substantial investments over a multiyear period beginning in late2008. Consequently, these projects are a natural fit with our Bypassed Resourceprojects and the Delhi Farmout, in that we believe the Bypassed Resourceprojects should begin generating substantial free cash flows during the sametime period as the Unconventional Gas investments are required. Increasingproduction from the Unconventional Gas projects should then be available tooffset normal production declines from the Bypassed Resource projects currentlyunder way.

 

By June 30, 2007, we hadleased 3,646 gross and 3,449 net acres with additional leasing activity ongoing.Development of proved reserves will require additional investments in drillingof test wells and establishment of economic production in offsetting leases.

 

Referto Item 2, “Properties”, for further disclosures regarding reserve values and amore in-depth discussion of our properties.

 

**Liquidityand Capital Resources**

 

Our balance sheet remainsstrong with a large bank of working capital and no funded debt.

 

At June 30, 2007, we hadapproximately $27.3 million of positive working capital, as compared to $6.8million of positive working capital at June 30, 2006. Our June 30, 2006 workingcapital excluded approximately $34.7 million of short-term investments in theQI account discussed below, and also excluded $12.4 million of deferred taxliabilities, both arising from the Delhi Farmout.

 

At June 30, 2007 our workingcapital (i) was free of all income tax liabilities arising from our DelhiFarmout, as these amounts were disbursed to taxing authorities during 2006 and2007, (ii) exceeded our original expectations by approximately $1.1 million, inthat our state of Louisiana income tax estimate was initially overstated forthe gain from our Delhi Farmout, and (iii) contained more than adequate fundsto seed and carry out, in part, the balance of the five Initiative II BypassedResource projects and two Initiative III Unconventional Gas Resource projectsnow in process.

 

Virtually all of the $27.7million of cash balances held in our working capital at June 30, 2007 was, andcontinues to be, invested in a U.S. Government Money Market Fund holdinginvestments exclusively in short-term U.S. Government Agency securities orshort-term repurchase agreements secured by U.S. Government Agency securities. Noneof our funds have had exposure to securities associated with collateralizedmortgage, debt or loan obligations (CMO, CDO or CLOs), extendible commercialpaper, secured liquidity notes or similar securities.

 

Of the $35 million we placedin a qualified intermediary (**“QI”**) accountfor possible Internal Revenue Code 1031 “like-kind exchanges”(from the $50million of proceeds we received from the Delhi Farmout in June 2006), wecompleted $0.58 million of like kind exchanges during 

 

22

----

 

fiscal 2006 and 2007. Inaccordance with IRC 1031 regulations, we withdrew the balance of approximately$35.3 million, including approximately $0.85 million in interest earned, onDecember 9, 2007. An unintended benefit we received from the establishment ofthe QI account was a resulting installment sale for tax purposes, which delayedthe payment of our estimated deposits, thus earning us additional investmentincome.

 

Cash flow used by ouroperating activities for the year ended June 30, 2007 was $14.5 million, ofwhich $15.1 million was used to pay our income taxes payable, including$421,325 of overpaid tax deposits. This compares to cash flow used by operatingactivities of $0.7 million for the year ended June 30, 2006.

 

Cash flow provided byinvesting activities was approximately $32.4 million for the year ended June30, 2007, mostly due to $34.7 million that was provided from the QI account.This was offset by approximately $2.3 million of capital expenditures weinvested in oil and gas properties. Of this amount, approximately $1.9 millionwas used to research title and to pay lease bonuses to acquire acreage for  four Bypassed Resource and two UnconventionalGas Resource programs currently in process. The remaining $0.4 million was usedto further develop our oil and gas properties in the Tullos Field. For thecomparable year ended June 30, 2006, $11.8 million was provided by investingactivities, mostly due to the $50 million provided from the Delhi Farmout sale,offset by $34.7 million used to set up the QI account.

 

We expect our capitalexpenditures will increase substantially during fiscal year 2008, due tocontinued leasing and the execution of a development drilling program withinour Bypassed Resource Initiative, and continued leasing in our UnconventionalGas Initiative. Based on our current plans, we expect capital expenditures toexceed $15 million during fiscal 2008, with half or more dedicated todevelopment drilling.

 

During the year ended June30, 2007, we neither used nor provided funds through financing transactions,except for the $15,532 we used for transaction costs related to prior periodfinancing transactions. During the year ended June 30, 2006, $1.04 million wasprovided to us through borrowings, and $1.0 million in proceeds (net oftransaction costs) was provided to us from the sale of 351,335 shares of ourcommon stock and the issuance of warrants to Prospect for their additional loan.Funds used in financing activities included the repayment of all of our debt inthe amount of $5.6 million during the year ended June 30, 2006, resulting in anet use of funds for financing transactions of $3.7 million.

 

**Results ofOperations**

 

***Summary***

 

As previously disclosed, at this stage of ourdevelopment our objectives are to:

 

•      Continue increasing our intrinsic netasset value per share,

 

•      Build the infrastructure necessary tocarry our many development projects, while reducing our cash burn rate,

 

•      Begin to convert our non-producing assetsto producing assets through the drill bit, and

 

•      Continue managing our cash burn rate, andbegin generating earnings per share.

 

We believe considerable progress has been madein these metrics.  Since our inception inlate 2003, we have funded our operations with $8.4 million of total cash equityinvested (excluding $1.3 million of accounting value assigned to warrantsissued to a lender) against 26.8 million shares currently outstanding.  By June 30, 2007, we had converted thisequity into: (i) $28 million of cash held on a debt free balance sheet, (ii)1,724,000 BOE of proved reserves, and (iii) a 7.4% overriding royalty and 25%reversionary back-in interest in a major CO2 EOR project in the Delhi Fieldthat, if successful, would generate far greater value per share.

 

On the second and third metrics, we have addedhighly experienced technical and administrative staff that will allow us tobegin active drilling operations within our development projects.  In October 2006, we hired a General Managerof Horizontal Drilling and Unconventional Development as part of our keymanagement team.  He brings valuedexperience in drilling over 800 wells, over 200 of which being horizontalwells.  In January 2007, we hired ourfirst Landman who has over 25 year’s of related experience.  Subsequent to the close of our current fiscalyear, we further hired a Manager of Land Administration to organize andmaintain our land records and interface them with our accounting records in ouroutsourced Excalibur ERP system. Additional infrastructure has been added subsequent to fiscal year end,and we are actively recruiting additional support personnel to aid in ourprojected drilling activity.

 

On the last metric, of the $1.81 millionearnings loss incurred during the current fiscal year, $1.61 million was due tonon-cash stock compensation expense, which significantly increased by ourrequired adoption of SFAS 123 (R).  Whencombined with other non-cash charges presented in our Statement of Cash Flows,this left us slightly positive in cash flow generated from our operations,before changes in assets and liabilities. With respect to future earnings per share, we expect to make positiveprogress as we begin converting our relatively low earning cash assets intoproduction from our proved undeveloped reserves, beginning with the drilling ofour first proved undeveloped location in late calendar 2007.

 

 

23

----

 

***Year Ended June 30, 2007vs. June 30, 2006***

 

Forthe year ended June 30, 2007 we reported a net loss available to commonshareholders of $1.8 million, or $0.07 per share basic and diluted, and for theyear ended June 30, 2006 we reported net income available to commonshareholders of $25.7 million or $1.03 per share basic, and $1.01 per share diluted.

 

Amajor contributor to our fiscal year 2007 loss was a $1.6 million charge tonon-cash stock compensation expense. This expense was driven much higher,mostly by our required adoption of FAS 123(R) in the current year, as comparedto the $.55 million we charged to non-cash stock compensation expense under APB25 during fiscal year 2006. In our fiscal year 2007, we also lost our Delhiproduction due to the Delhi Farmout we completed in June 2006. The lostproduction was much more than offset by the $1.9 million of interest income werecorded in fiscal year 2007. This compared to $0.2 million of interest incomerecorded during fiscal 2006.

 

Oil and Gas Revenues. Total revenues were $1.9 million in fiscalyear 2007, compared to total revenues of $2.9 million in fiscal year 2006. This35% decrease in total revenues was primarily due to the loss of oil and gassales from the Delhi Field as a result of the Delhi Farmout last year. Offsettingthis was higher average realized oil prices in 2007 versus 2006, orapproximately $64 versus $55 per BOE, respectively.

 

Lease Operating Expenses. Lease operating expenses include costs incurred to operate and maintainwells and related equipment. Lease operating expenses for the years ended June30, 2007 and 2006 was $1.4 million and $1.7 million, respectively. The 21% decrease in our lease operatingexpenses is primarily due to the Delhi Farmout from last year. However, theTullos Field area incurred higher than anticipated expenses in fiscal 2007 dueto overall cost increases for goods and services, unexpected casing leaks innumerous saltwater disposal wells, and other non-recurring operating events.

 

Production taxes.    The 28% decrease in production (severance)taxes is directly related to the reduction of volumes produced and sold as aresult of the Delhi Farmout in prior year.

 

Franchise taxes. Approximately $108,000 of State ofLouisiana franchise taxes was expensed and paid in fiscal year 2007.

 

General and Administrativeexpenses (G&A). General and administrative expenses areoverhead-related expenses, including among others, wages and benefits,stock-based compensation, legal and accounting fees, insurance, and investorrelations expenses. General and administrative expenses for the years endedJune 30, 2007 and 2006 were $4.4 million and $2.8 million, respectively. This55% increase in G&A expenses is primarily related to incremental highernon-cash stock-based compensation expense of $1 million in fiscal 2007 comparedto fiscal 2006, and $0.5 million in other compensation related costs, includingthe addition of one employee, annual bonus payouts, new 401-K plan and relatedtaxes. Our G&A expensescontinue to increase due to costs of being a public company compounded by highrecruitment costs, salaries and benefits necessary to attract and retainpersonnel in a tight labor market for skilled energy staff professionals.

 

Depletion, Depreciation andAmortization (DD&A).DD&A expenses for the years ended June 30, 2007 and 2006 was $0.3 millionand $0.4 million, respectively. This 29% decrease in DD&A expense is due tofewer volumes recorded as a result of the Delhi Farmout from last year. Theaverage DDA rate per BOE increased 34% to $9.99 per barrel of oil equivalent,compared to prior year of $7.48 per barrel of oil equivalent. This increase ismostly attributable to the addition of proved reserves in our Texas BypassedResource properties at approximately $13.80/BOE and, to a lesser extent, tohigher capital spending than estimated for our Tullos Field Area during fiscalyear 2007. Depreciation of office equipment and computer equipment is computedon a straight line basis.

 

Interest Income. Our interest income increased significantlyin fiscal 2007 from fiscal 2006, or to $1.9 million from $0.2 million. This isprimarily due to higher cash available to the Company due to the proceedsreceived from the Delhi Farmout and slightly higher interest rate yields infiscal 2007 on our money market investments.

 

Interest Expense. Interest expense decreased to $0 in fiscal2007, compared to $2.6 million in fiscal 2006. We were debt free in fiscal 2007and continue to be in fiscal 2008.

 

24

----

 

 

**CriticalAccounting Policies and Estimates**

 

Accounting for Oil and GasProperty Costs. As more fully discussed in Note 2 to the consolidated financialstatements (i) we follow the full cost method of accounting for the costs ofour oil and gas properties in accordance with SEC Rule 4-10 of Regulation SX,(ii) we amortize such costs using the units of production method, and (iii) weapply a quarterly full cost ceiling test. Adverse changes in operatingconditions (primarily oil or gas price declines) could result in permanentwrite-downs in the carrying value of oil and gas properties as well as non-cashcharges to operations, but would not affect cash flows. At June 30, 2007, themeasure to calculate our ceiling test was approximately $23.7 million, therebyexceeding the carrying value of our oil and gas properties by approximately$18.3 million, or 343%. At that date, a 10% decrease in product priceassumptions would reduce our ceiling test cushion by approximately $3.1million.

 

ProvedOil and Gas Reserves are also subject to estimates. An independent petroleumengineer annually estimates 100% of our proved reserves. Reserve engineering isa subjective process that is dependent upon the quality of available data andthe interpretation thereof. In addition, subsequent physical and economicfactors such as the results of drilling, testing, production and product pricesmay justify revision of such estimates. Therefore, actual quantities,production timing, and the value of reserves may differ substantially fromestimates. A reduction in proved reserves would result in an increase indepreciation, depletion and amortization (“DD&A”) expense and could resultin permanent write-downs in the carrying value of our oil and gas propertiesresulting in non-cash charges to operations, but would not affect our cashflows. Since July 1, 2005, we have experienced cumulative upward reserveestimate revisions totaling 95,662 BOE, or 11% on beginning reserves of 893,904BOE, or 6% on ending reserves of 1,723,667 BOE.

 

Stock Based Compensation. Effective July 1, 2006, we adopted Statementof Financial Accounting Standards (“SFAS”) No. 123(R), “Accounting forShare-Based Payment,” as amended, using the modified prospective transitionmethod which requires, among other things, current recognition of compensationexpense for share-based compensation granted after July 1, 2006, and forthat portion of prior period share-based compensation for which the requisiteservice has not been rendered that was outstanding as of July 1, 2006. Forperiods prior to July 1, 2006, we applied to our stock-based compensationawards the intrinsic method of accounting as set forth in Accounting PrinciplesBoard (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,”and related interpretations.

 

NewAccounting Pronouncements. During February 2007, the Financial AccountingStandards Board (“FASB”) issued FASB Statement of Accounting Standards (“SFAS”)No 159, “The Fair Value Option for Financial Assets and Financial Liabilities”(“SFAS No. 159”) which 

 

25

----

 

permitsall entities to choose, at specified election dates, to measure eligible itemsat fair value. SFAS No. 159 permits entities to choose to measure manyfinancial instruments and certain other items at fair value that are notcurrently required to be measured at fair value, and thereby mitigatevolatility in reported earnings caused by measuring related assets andliabilities differently without having to apply complex hedge accountingprovisions. This Statement also establishes presentation and disclosurerequirements designed to facilitate comparisons between entities that choosedifferent measurement attributes for similar types of assets and liabilities.SFAS No. 159 is effective as of the beginning of an entity’s first fiscalyear that begins after November 15, 2007. We are evaluating the impactthat this Statement will have on our financial statements.

 

InSeptember 2006, the Financial Accounting Standards Board (“FASB”) issued FASBStatement of Accounting Standards (“SFAS”) No. 157. This Statement definesfair value, establishes a framework for measuring fair value in generallyaccepted accounting principles, and expands disclosures about fair valuemeasurements. This Statement applies under other accounting pronouncements thatrequire or permit fair value measurements, where fair value has been determinedto be the relevant measurement attribute. This statement is effective forfiscal years beginning after November 15, 2007. We are evaluating theimpact that this Statement will have on our financial statements.

 

InJune 2006, the FASB issued Interpretation No. 48, “Accounting forUncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,”(“FIN 48”) which provides guidance for the recognition and measurement of a taxposition taken or expected to be taken in a tax return. FIN 48 requires theevaluation of a tax position as a two-step process. First, we will be requiredto determine whether it is more likely than not that a tax position will besustained upon examination, including resolution of any related appeals orlitigation processes, based on the technical merits of the position. If the taxposition meets the “more likely than not” recognition threshold, it is thenmeasured and recorded at the largest amount of benefit that is greater than 50percent likely of being realized upon ultimate settlement. We will be requiredto adopt FIN 48 in the first quarter of fiscal year 2008. We are evaluating ourtax positions and the impact that this guidance will have on our financialstatements.

 

**ITEM 7. FINANCIALSTATEMENTS**

 

**Index toConsolidated Financial Statements**

 
| **Report of Independent Registered Public Accounting  Firm**                                      |   |   |
|---------------------------------------------------------------------------------------------------|--------|--------|
|                                                                                              |   |   |
| Consolidated Balance Sheets as of June 30, 2007 and  2006.                                        |   |   |
|                                                                                              |   |   |
| Consolidated Statements of Operations for the Years  ended June 30, 2007 and 2006.                |   |   |
|                                                                                              |   |   |
| Consolidated Statements of Cash Flows for the Years  ended June 30, 2007 and 2006.                |   |   |
|                                                                                              |   |   |
| Consolidated Statements of Stockholders’ Equity for  the Years ended June 30, 2007 and 2006. |   |   |

 

26

----

** **

**Evolution Petroleum Corporation andSubsidiaries**

**ConsolidatedBalance Sheets**

 
| ** **                                                                                                                                                                                                                                                                       | ** ** | **June 30,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|
| ** **                                                                                                                                                                                                                                                                       | ** ** | **2007**          | ** ** | **2006** | ** ** |
| ** **                                                                                                                                                                                                                                                                       | ** ** | ** **        | ** ** | **(as restated -  see note 3)** | ** ** |
| **Assets**                                                                                                                                                                                                                                                                       |       |              |       |   |   |
| Current Assets:                                                                                                                                                                                                                                                                  |       |              |       |   |   |
| Cash and cash equivalents                                                                                                                                                                                                                                                        |       | $                 | 27,746,942 |   | $ | 9,893,547 |   |
| Accounts receivable, trade                                                                                                                                                                                                                                                       |       | 212,585           |       | 132,371 |   |
| Income tax receivable                                                                                                                                                                                                                                                            |       | 421,325           |       | — |   |
| Inventories                                                                                                                                                                                                                                                                      |       | 274,813           |       | 76,917 |   |
| Prepaid expenses                                                                                                                                                                                                                                                                 |       | 159,228           |       | 157,629 |   |
| Retainers and deposits                                                                                                                                                                                                                                                           |       | 106,625           |       | 60,895 |   |
| Total current assets                                                                                                                                                                                                                                                             |       | 28,921,518        |       | 10,321,359 |   |
|                                                                                                                                                                                                                                                                             |       |              |       |   |   |
| Cash in qualified intermediary account for  “like-kind” exchanges                                                                                                                                                                                                      |       | —            |       | 34,662,368 |   |
|                                                                                                                                                                                                                                                                             |       |              |       |   |   |
| Oil & Gas properties - full cost                                                                                                                                                                                                                                             |       | 4,187,440         |       | 3,878,551 |   |
| Oil & Gas properties - not being  amortized                                                                                                                                                                                                                                  |       | 1,924,552         |       | 52,098 |   |
| Less: accumulated depletion                                                                                                                                                                                                                                                      |       | (652,439          | )          | (371,624 | ) |
| Net oil & gas properties                                                                                                                                                                                                                                                     |       | 5,459,553         |       | 3,559,025 |   |
|                                                                                                                                                                                                                                                                             |       |              |       |   |   |
| Furniture, fixtures and equipment, at cost                                                                                                                                                                                                                                       |       | 173,205           |       | 16,561 |   |
| Less: accumulated depreciation                                                                                                                                                                                                                                                   |       | (18,333           | )          | (7,998 | ) |
| Net furniture, fixtures, and equipment                                                                                                                                                                                                                                           |       | 154,872           |       | 8,563 |   |
|                                                                                                                                                                                                                                                                             |       |              |       |   |   |
| Restricted deposits                                                                                                                                                                                                                                                              |       | —            |       | 326,835 |   |
| Other assets                                                                                                                                                                                                                                                                     |       | 370,049           |       | 79,808 |   |
| Total assets                                                                                                                                                                                                                                                                     |       | $                 | 34,905,992 |   | $ | 48,957,958 |   |
|                                                                                                                                                                                                                                                                             |       |              |       |   |   |
| **Liabilities  and Stockholders’ Equity**                                                                                                                                                                                                                                   |       |              |       |   |   |
| Current liabilities:                                                                                                                                                                                                                                                             |       |              |       |   |   |
| Accounts payable                                                                                                                                                                                                                                                                 |       | $                 | 993,894    |   | $ | 310,272 |   |
| Accrued liabilities                                                                                                                                                                                                                                                              |       | 595,833           |       | 473,782 |   |
| Income taxes payable                                                                                                                                                                                                                                                             |       | —            |       | 2,645,619 |   |
| Royalties payable                                                                                                                                                                                                                                                                |       | 6,831             |       | 47,054 |   |
| Total current liabilities                                                                                                                                                                                                                                                        |       | 1,596,558         |       | 3,476,727 |   |
|                                                                                                                                                                                                                                                                             |       |              |       |   |   |
| Long term liabilities:                                                                                                                                                                                                                                                           |       |              |       |   |   |
| Deferred tax liability                                                                                                                                                                                                                                                           |       | 338,001           |       | 12,362,156 |   |
| Deferred rent payable                                                                                                                                                                                                                                                            |       | 47,289            |       | — |   |
| Asset retirement obligations                                                                                                                                                                                                                                                     |       | 140,998           |       | 123,679 |   |
| Total liabilities                                                                                                                                                                                                                                                                |       | 2,122,846         |       | 15,962,562 |   |
|                                                                                                                                                                                                                                                                             |       |              |       |   |   |
| Common Stock, totaling 351,335 shares  subject to demand registration rights                                                                                                                                                                                                     |       | —            |       | 790,500 |   |
|                                                                                                                                                                                                                                                                             |       |              |       |   |   |
| Stockholders’ equity:                                                                                                                                                                                                                                                       |       |              |       |   |   |
| Common Stock, par value $0.001 per share;  100,000,000 shares authorized, 26,776,234 and 26,300,670 issued and  outstanding as of June 30, 2007 and June 30, 2006, respectively, net of  351,335 shares of common stock subject to demand registration rights at June  30, 2006. |       | 26,776            |       | 26,300 |   |
| Additional paid-in capital                                                                                                                                                                                                                                                       |       | 12,443,199        |       | 10,274,555 |   |
| Deferred stock compensation                                                                                                                                                                                                                                                      |       | (45,826           | )          | (265,167 | ) |
| Retained earnings                                                                                                                                                                                                                                                                |       | 20,358,997        |       | 22,169,208 |   |
| Total stockholders’ equity                                                                                                                                                                                                                                                  |       | 32,783,146        |       | 32,204,896 |   |
|                                                                                                                                                                                                                                                                             |       |              |       |   |   |
| Total liabilities and stockholders’ equity                                                                                                                                                                                                                                  |       | $                 | 34,905,992 |   | $ | 48,957,958 |   |

 

See accompanying notes toconsolidated financial statements.

 

27

----

 

**Evolution Petroleum Corporation andSubsidiaries**

**ConsolidatedStatements of Operations**

 
| ** **                                                                                                                           | ** ** | **Year Ended June 30,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                                                                                                           | ** ** | **2007**                               | ** ** | **2006** | ** ** |
| ** **                                                                                                                           | ** ** | ** **                             | ** ** | **(as restated -  see note 3)** | ** ** |
| **Revenues:**                                                                                                                        |       |                                   |       |   |   |
| Oil sales                                                                                                                            |       | $                                      | 1,866,892  |   | $ | 2,450,676 |   |
| Gas sales                                                                                                                            |       | —                                 |       | 424,190 |   |
| Price risk management activities                                                                                                     |       | (14                                    | )          | (13,452 | ) |
| Total revenues                                                                                                                       |       | 1,866,878                              |       | 2,861,414 |   |
|                                                                                                                                 |       |                                   |       |   |   |
| **Operating expenses:**                                                                                                              |       |                                   |       |   |   |
| Production expenses                                                                                                                  |       | 1,370,226                              |       | 1,725,760 |   |
| Production taxes                                                                                                                     |       | 62,426                                 |       | 86,562 |   |
| Franchise taxes                                                                                                                      |       | 107,754                                |       | — |   |
| Depreciation, depletion and amortization                                                                                             |       | 291,150                                |       | 407,467 |   |
| General and administrative (includes stock-based  compensation of $1,613,493 and $546,597, respectively for June 30, 2007 and  2006) |       | 4,383,846                              |       | 2,826,085 |   |
| Total operating expenses                                                                                                             |       | 6,215,402                              |       | 5,045,874 |   |
| **Loss from operations**                                                                                                             |       | (4,348,524                             | )          | (2,184,460 | ) |
| ** **                                                                                                                           |       |                                   |       |   |   |
| **Other income (expense):**                                                                                                          |       |                                   |       |   |   |
| Interest income                                                                                                                      |       | 1,920,913                              |       | 165,313 |   |
| Interest expense                                                                                                                     |       | —                                 |       | (2,600,180 | ) |
| Gain (loss) on sale of assets                                                                                                        |       | (21,453                                | )          | 45,325,468 |   |
| Total other income (expense)                                                                                                         |       | 1,899,460                              |       | 42,890,601 |   |
| **Income (loss) before income taxes**                                                                                                |       | (2,449,064                             | )          | 40,706,141 |   |
|                                                                                                                                 |       |                                   |       |   |   |
| **Income tax expense:**                                                                                                              |       |                                   |       |   |   |
| ** **                                                                                                                           |       |                                   |       |   |   |
| Current                                                                                                                              |       | 11,407,202                             |       | 2,645,619 |   |
| Deferred                                                                                                                             |       | (12,046,055                            | )          | 12,362,156 |   |
|                                                                                                                                 |       |                                   |       |   |   |
| Total income tax expense                                                                                                             |       | (638,853                               | )          | 15,007,775 |   |
| **Net income (loss)**                                                                                                                |       | $                                      | (1,810,211 | ) | $ | 25,698,366 |   |
|                                                                                                                                 |       |                                   |       |   |   |
| **Earnings (loss) per common share**                                                                                                 |       |                                   |       |   |   |
| Basic                                                                                                                                |       | $                                      | (0.07      | ) | $ | 1.03 |   |
| Diluted                                                                                                                              |       | $                                      | (0.07      | ) | $ | 1.01 |   |
|                                                                                                                                 |       |                                   |       |   |   |
| **Weighted average number of common share**                                                                                          |       |                                   |       |   |   |
| Basic                                                                                                                                |       | 26,706,713                             |       | 25,031,125 |   |
| Diluted                                                                                                                              |       | 26,706,713                             |       | 25,555,992 |   |

 

See accompanying notes toconsolidated financial statements.

 

28

----

 

**Evolution Petroleum Corporation andSubsidiaries**

**ConsolidatedStatements of Cash Flow**

 
| ** **                                                                            | ** ** | **Year Ended June 30,** | ** ** |
|---------------------------------------------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                                                            | ** ** | **2007**                               | ** ** | **2006** | ** ** |
| ** **                                                                            | ** ** | ** **                             | ** ** | **(as restated -  see note 3)** | ** ** |
| **Cash flows from operating activities**                                              | ** ** | ** **                             | ** ** | ** ** | ** ** |
| Net Income (loss)                                                                     |       | $                                      | (1,810,211 | ) | $ | 25,698,366 |   |
| Adjustments to reconcile net income (loss)  to net cash used in operating activities: |       |                                   |       |   |   |
| Gain on asset sale                                                                    |       | —                                 |       | (45,208,532 | ) |
| Depletion                                                                             |       | 280,815                                |       | 402,870 |   |
| Depreciation                                                                          |       | 10,335                                 |       | 4,597 |   |
| Stock-based compensation                                                              |       | 1,613,493                              |       | 546,567 |   |
| Accretion of asset retirement obligations                                             |       | 17,319                                 |       | 27,716 |   |
| Income tax liability                                                                  |       | (12,024,155                            | )          | 12,362,156 |   |
| Deferred rent                                                                         |       | 47,289                                 |       | — |   |
| Amortization of deferred financing costs                                              |       | —                                 |       | 293,797 |   |
| Accretion of debt discount and non-cash  loan costs                                   |       | —                                 |       | 1,739,046 |   |
| Non-cash penalty expense                                                              |       | —                                 |       | 240,000 |   |
| Changes in operating assets and  liabilities:                                         |       |                                   |       |   |   |
| Accounts receivable                                                                   |       | (80,214                                | )          | 168,390 |   |
| Income tax receivable                                                                 |       | (421,325                               | )          | — |   |
| Retainer and deposits                                                                 |       | (45,730                                | )          | (4,560 | ) |
| Inventories                                                                           |       | (197,896                               | )          | 145,553 |   |
| Prepaid expenses                                                                      |       | (1,599                                 | )          | (73,325 | ) |
| Accounts payable                                                                      |       | 683,622                                |       | 69,883 |   |
| Royalties payable                                                                     |       | (40,223                                | )          | (42,659 | ) |
| Accrued liabilities                                                                   |       | 122,051                                |       | 247,312 |   |
| Income taxes                                                                          |       | (2,645,619                             | )          | 2,645,619 |   |
| Net cash used in operating activities                                                 |       | (14,492,048                            | )          | (737,204 | ) |
| **Cash flows from investing activities**                                              |       |                                   |       |   |   |
| Development of oil and gas properties                                                 |       | (417,964                               | )          | (2,611,369 | ) |
| Acquisitions of oil and gas properties                                                |       | (1,918,757                             | )          | (1,448,239 | ) |
| Proceeds from asset sale                                                              |       | 155,378                                |       | 49,993,134 |   |
| Capital expenditures for furniture,  fixtures and equipment                           |       | (156,644                               | )          | (4,448 | ) |
| Cash in qualified intermediary account for  “like-kind” exchanges           |       | 34,662,368                             |       | (34,662,368 | ) |
| Restricted deposits                                                                   |       | 326,835                                |       | 536,254 |   |
| Other assets                                                                          |       | (290,241                               | )          | 19,661 |   |
| Net cash provided by investing activities                                             |       | 32,360,975                             |       | 11,822,625 |   |
| **Cash flows from financing activities**                                              |       |                                   |       |   |   |
| Payments on notes payable                                                             |       | —                                 |       | (5,634,654 | ) |
| Proceeds from notes payable                                                           |       | —                                 |       | 1,040,764 |   |
| Deferred financing costs                                                              |       | —                                 |       | (37,201 | ) |
| Proceeds from issuance of common stock and  fair value of warrants issued with debt   |       | 125                                    |       | 999,385 |   |
| Transaction and registration costs                                                    |       | (15,657                                | )          | (108,856 | ) |
| Net cash used in financing activities                                                 |       | (15,532                                | )          | (3,740,562 | ) |
| Net increase in cash and cash equivalents                                             |       | 17,853,395                             |       | 7,344,859 |   |
| Cash and cash equivalents, beginning of  period                                       |       | 9,893,547                              |       | 2,548,688 |   |
| Cash and cash equivalents, end of period                                              |       | $                                      | 27,746,942 |   | $ | 9,893,547 |   |
|                                                                                  |       |                                   |       |   |   |
| Supplemental disclosure of cash flow  information:                                    |       |                                   |       |   |   |
| Interest paid                                                                         |       | $                                      | —     |   | $ | 567,273 |   |
| Income taxes paid                                                                     |       | $                                      | 14,560,000 |   | $ | — |   |
| Non-cash transactions:                                                                |       |                                   |       |   |   |
| Non-cash equity adjustment                                                            |       | $                                      | 790,500    |   | $ | 50,000 |   |
| Assumption of asset retirement obligations                                            |       | $                                      | —     |   | $ | — |   |

 

See accompanying notes to the consolidated financial statements.

 

29

----

 

**Evolution Petroleum Corporation and Subsidiaries**

**ConsolidatedStatements of Changes in Stockholders’ Equity**

**For the Years ended June 30, 2007 and 2006**

 
| ** **                                                                           | ** ** | ** ** | ** ** | ** **  | ** ** | **Additional** | ** ** | ** **              | ** ** | ** **                  | ** ** | **Total**              | ** ** |
|--------------------------------------------------------------------------------------|------------|------------|------------|-------------|------------|----------------|------------|-------------------------|------------|-----------------------------|------------|------------------------|------------|
| ** **                                                                           | ** ** | ** ** | ** ** | ** **  | ** ** | **Paid-in**    | ** ** | **Deferred Stock** | ** ** | **Retained**                | ** ** | **Stockholders’** | ** ** |
| ** **                                                                           | ** ** | **Shares** | ** ** | **Dollars** | ** ** | **Capital**    | ** ** | **Compensation**        | ** ** | **Earnings (deficit)** | ** ** | **Equity**             | ** ** |
| Balance, June 30,  2005                                                              |       | 24,774,606 |       | $           | 24,774     |           | $          | 9,611,767               |       | $                           | (595,283   | )                      | $          | (3,529,158 | ) | $ | 5,512,100 |   |
| Sales and  issuances of common stock                                                 |       | 599,335    |       | 599         |       | 1,005,073      |       | —                  |       | —                      |       | 1,005,672              |       |
| Reduction of  capital related to common stock, subject to demand registration rights |       | (351,335   | )          | (351        | )          | (790,149       | )          | —                  |       | —                      |       | (790,500               | )          |
| Exercise of  warrants                                                                |       | 1,278,064  |       | 1,278       |       | —         |       | —                  |       | —                      |       | 1,278                  |       |
| Fair value of  warrants issued with debt                                             |       | —     |       | —      |       | 209,236        |       | —                  |       | —                      |       | 209,236                |       |
| Transaction and  Registration Costs                                                  |       | —     |       | —      |       | 238,628        |       | —                  |       | —                      |       | 238,628                |       |
| Stock-based  compensation                                                            |       | —     |       | —      |       | —         |       | 330,116                 |       | —                      |       | 330,116                |       |
| Net income                                                                           |       | —     |       | —      |       | —         |       | —                  |       | 25,698,366                  |       | 25,698,366             |       |
| Balance, June 30,  2006                                                              |       | 26,300,670 |       | $           | 26,300     |           | $          | 10,274,555              |       | $                           | (265,167   | )                      | $          | 22,169,208 |   | $ | 32,204,896 |   |
| Issuance of  common stock                                                            |       | 124,229    |       | 125         |       | —         |       | —                  |       | —                      |       | 125                    |       |
| Reclassify  temporary equity from prior year                                         |       | 351,335    |       | 351         |       | 790,149        |       | —                  |       | —                      |       | 790,500                |       |
| Transaction and  Registration Costs                                                  |       | —     |       | —      |       | (15,657        | )          | —                  |       | —                      |       | (15,657                | )          |
| Stock-based  compensation                                                            |       | —     |       | —      |       | 1,394,152      |       | 219,341                 |       | —                      |       | 1,613,493              |       |
| Net loss                                                                             |       | —     |       | —      |       | —         |       | —                  |       | (1,810,211                  | )          | (1,810,211             | )          |
| Balance, June 30,  2007                                                              |       | 26,776,234 |       | $           | 26,776     |           | $          | 12,443,199              |       | $                           | (45,826    | )                      | $          | 20,358,997 |   | $ | 32,783,146 |   |

 

See accompanying notes toconsolidated financial statements.

 

30

----

 

**EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES**

 

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**1. Organization and Basis ofPreparation**

 

Headquartered in Houston,Texas, Evolution Petroleum Corporation, formerly Natural Gas Systems, Inc. (the“Company”, “EPM”, “we” or “us”), is a petroleum company incorporated under thelaws of the State of Nevada, engaged primarily in the acquisition, exploitationand development of properties for the production of crude oil and natural gas.We acquire established oil and gas properties and exploit them through theapplication of conventional and specialized technology to increase production,ultimate recoveries, or both.

 

Our stock is traded on theAmerican Stock Exchange (AMEX) under the ticker symbol EPM. Prior to July 17,2006, our stock was quoted on the OTC Bulletin Board under the symbol NGSY.OB. Priorto May 26, 2004, our stock was quoted on the OTC Bulletin Board under thesymbol RLYI.OB. Concurrently with the listing of our shares on the AMEX duringJuly, 2006, we changed our name from Natural Gas Systems, Inc. to EvolutionPetroleum Corporation to avoid confusion with similar names traded on the AMEXand to better reflect our business model.

 

At June 30, 2007, weconducted operations through our 100% working interests in our Tullos FieldArea and our non-operated interests in our Delhi Field, all located onshore inLouisiana. Our Tullos Field Area consists of approximately 156 producing wellsout of 260 well bores across 599 acres of high water cut primary reserveproduction, which we believe may be a candidate for redevelopment using moderntechnology. Our non-operated interests in the 13,636 acre Delhi Field consistof a 7.4% overriding and mineral royalty interest in the Delhi Holt BryantUnit, a 25% reversionary working interest in the Delhi Holt Bryant Unit, and a25% working interest in certain other depths in the Delhi Field. Our Delhi HoltBryant Unit is scheduled for redevelopment using CO2 enhanced oil recoverytechnology.

 

Theconsolidated financial statements herein have been prepared in accordance withgenerally accepted accounting principles (GAAP) and include the accountsof Evolution Petroleum Corporation and its subsidiaries, all of which arewholly owned. All inter-company transactions are eliminated upon consolidation.Certain prior year amounts have been reclassified to conform to the currentyear presentation.

 

**2. Summary of SignificantAccounting Policies**

 

Use of Estimates — The preparation of financial statements inaccordance with generally accepted accounting principles and pursuant to therules and regulations of the Securities and Exchange Commission (“SEC”)requires management to make estimates and assumptions that affect the reportedamounts of assets, liabilities, revenues and expenses, and disclosure ofcontingent assets and liabilities in the financial statements, including thesignificant use of estimates for oil and gas reserve information and thevaluation allowance for deferred income taxes. Actual results could differ fromthose estimates.

 

Cash and Cash Equivalents — Cash and cash equivalents primarily consistof cash on deposit and investments in money market funds with originalmaturities of three months or less, stated at market value.

 

Oil and Gas Properties  — We follow the full cost method of accountingfor our investments in oil and natural gas properties. All costs incurred inthe acquisition, exploration and development of oil and natural gas properties,including unproductive wells, are capitalized. Proceeds from the sale of oiland natural gas properties are credited to the full cost pool, unless the saleinvolves a significant quantity of reserves, in which case a gain or loss isrecognized. Under the rules of the Securities and Exchange Commission (“SEC”)for the full cost method of accounting, the net carrying value of oil andnatural gas properties is limited to the sum of the present value (10% discountrate) of the estimated future net cash flows from proved reserves (net ofestimated future expenditures to be incurred in developing and producing theproved reserves) based on current prices as of the balance sheet date, andexcluding future cash outflows associated with settling asset retirementobligations, plus the lower of cost or estimated fair market value of unprovedproperties adjusted for related income tax effects. For the years ended June30, 2007 and 2006, there was no impairment.

 

Capitalized costs of provedoil and natural gas properties are depleted on a unit of production methodusing proved oil and natural gas reserves. Costs depleted include netcapitalized costs subject to depletion and estimated future dismantlement,restoration and abandonment costs.

 

The costs of certainunevaluated leasehold acreage and wells being drilled are not being amortized.Costs not being amortized are periodically assessed for possible impairments orreductions in value. If a reduction of value has occurred, the amount of theimpairment is transferred to costs being amortized.

 

Furniture and Fixtures — Furniture and fixtures consist of officefurniture, computer hardware and software and leasehold improvements.Depreciation of furniture and fixtures is computed using the straight-linemethod over their estimated useful lives, which vary from three to seven years.

 

Concentrations of CreditRisk — Financial instruments which potentially expose us to concentrations ofcredit risk consist primarily of trade accounts receivable. Our customer baseis highly concentrated, even though our oil and gas products are highlymarketable. Although we are directly affected by the well-being of the oil andgas industry, management does not believe a significant credit risk exists atJune 30, 2007.

 

31

----

 

Revenue Recognition — Werecognize oil and natural gas revenues from our interests in producing wells atthe time that title passes to the purchaser. As a result, we accrue revenuesrelated to production sold for which we have not received payment. Through June30, 2007, there were no product imbalances, as we owned and operated 100% ofour natural gas properties.

 

Accounts Receivable, trade —Accounts receivable, trade consists of uncollateralized accrued oil and gasrevenues due under normal trade terms, generally requiring payment within 30days of production. Management reviews receivables periodically and reduces thecarrying amount by a valuation allowance that reflects management’s bestestimate of the amount that may not be collectible. As of June 30, 2007 and2006, the valuation allowance was $0.

 

Inventory — Inventoryincludes tubular goods and other lease and well equipment which we plan toutilize in our ongoing development activities and is generally carried at thelower of cost or market using the specific identification method.

 

Stock-based Compensation — Effective July 1, 2006, we adopted Statementof Financial Accounting Standards (“SFAS”) No. 123(R), “Accounting forShare-Based Payment,” as amended, using the modified prospective transitionmethod which requires, among other things, current recognition of compensationexpense for share-based compensation granted after July 1, 2006, and for thatportion of prior period share-based compensation for which the requisiteservice has not been rendered as of July 1, 2006. During the fiscal years endedJune 30, 2007 and 2006, we recognized aggregate compensation expense of $1.5million and $0.5 million, respectively, related to outstanding common stockoptions. During the fiscal years ended June 30, 2007 and 2006, we recognizedaggregate compensation expense of approximately $95,000 and $40,000,respectively, related to outstanding restricted stock grants.

 

Fair Value of FinancialInstruments — Our financial instruments consist of cash and cash equivalents,accounts receivable, accounts payable, derivatives, notes payable and sellernotes. The carrying amounts of cash and cash equivalents, derivative, accountsreceivable and accounts payable approximate fair value due to the highly liquidnature of these short-term instruments.

 

Accounting for Price RiskManagement activities — We enter into certain financial derivative contractsutilized for non-trading purposes to minimize the impact of market pricefluctuations on contractual commitments and forecasted transactions related toour oil and gas production. We follow the provisions of the Statement ofFinancial Accounting Standards (“SFAS”) No. 133, Accounting for DerivativeInstruments and Hedging Activities, for the accounting of our hedgetransactions. SFAS No. 133 establishes accounting and reporting standardsrequiring that all derivatives instruments be recorded in the consolidatedbalance sheet as either an asset or a liability measured at fair value andrequires that the changes in the fair value be recognized currently in earningsunless specific hedge accounting criteria is met. In accordance with thisspecific criteria, we did not elect to document and designate certainover-the-counter contracts we entered into to hedge the cash flow of part ofour forecasted sale of oil and gas production.. Thus, the changes in the fairvalue of these over-the-counter contracts are reflected in earnings in theperiod in which they occur.

 

Income taxes — Income taxesare provided for the tax effects of transactions reported in the financialstatements and consist of taxes currently due, if any, plus net deferred taxesrelated primarily to differences between the basis of assets and liabilitiesfor financial and income tax reporting. Deferred tax assets and liabilitiesrepresent the future tax return consequences of those differences, which willeither be taxable or deductible when the assets and liabilities are recoveredor settled. Deferred tax assets include recognition of operating losses thatare available to offset future taxable income and tax credits that areavailable to offset future income taxes. Valuation allowances are recognized tolimit recognition of deferred tax assets where appropriate. Such allowances maybe reversed when circumstances provide evidence that the deferred tax assetswill more likely than not be realized.

 

Earnings (loss) per share — Basicand diluted earning per share calculations are presented in accordance withFASB 128, and are calculated on the basis of the weighted average number ofcommon shares outstanding during the year. They include the dilutive effect ofcommon stock equivalents in years with net income

 

NewAccounting Pronouncements — During February 2007, the Financial AccountingStandards Board (“FASB”) issued FASB Statement of Accounting Standards (“SFAS”)No 159, “The Fair Value Option for Financial Assets and Financial Liabilities”(“SFAS No. 159”) which permits all entities to choose, at specifiedelection dates, to measure eligible items at fair value. SFAS No. 159permits entities to choose to measure many financial instruments and certainother items at fair value that are not currently required to be measured atfair value, and thereby mitigate volatility in reported earnings caused bymeasuring related assets and liabilities differently without having to applycomplex hedge accounting provisions. This Statement also establishes presentationand disclosure requirements designed to facilitate comparisons between entitiesthat choose different measurement attributes for similar types of assets andliabilities. SFAS No. 159 is effective as of the beginning of an entity’sfirst fiscal year that begins after November 15, 2007. We are evaluatingthe impact that this Statement will have on our financial statements.

 

DuringSeptember 2006, the Financial Accounting Standards Board (“FASB”) issued FASBStatement of Accounting Standards (“SFAS”) No. 157. This Statement definesfair value, establishes a framework for measuring fair value in generallyaccepted accounting principles, and expands disclosures about fair valuemeasurements. This Statement applies under other accounting pronouncements thatrequire or permit fair value measurements, where fair value has been determinedto be the relevant measurement attribute. This statement is effective forfiscal years beginning after November 15, 2007. We are evaluating theimpact that this Statement will have on our financial statements.

 

32

----

 

InJune 2006, the FASB issued Interpretation No. 48, “Accounting forUncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,”(“FIN 48”) which provides guidance for the recognition and measurement of a taxposition taken or expected to be taken in a tax return. FIN 48 requires theevaluation of a tax position as a two-step process. First, we will be requiredto determine whether it is more likely than not that a tax position will besustained upon examination, including resolution of any related appeals orlitigation processes, based on the technical merits of the position. If the taxposition meets the “more likely than not” recognition threshold, it is thenmeasured and recorded at the largest amount of benefit that is greater than 50percent likely of being realized upon ultimate settlement. We will be requiredto adopt FIN 48 in the first quarter of fiscal year 2008. We are evaluating ourtax positions and the impact that this guidance will have on our financialstatements.

 

**3. Restatement of prior yearfinancial statements**

 

The financial statements forthe year ended June 30, 2006 have been restated due to an error in the taxprovision calculations. Income tax expense and income tax payable wererestated, resulting in additional net income and reduced income taxes payableof approximately $1,072,000.

 

| ** **                | ** **   | **Year Ended June 30,** | ** **   | ** **             | ** **   |
|---------------------------|--------------|----------------------------------------|--------------|------------------------|--------------|
| ** **                | ** **   | **2006**                               | ** **   | **2006**               | ** **   | **Restated** | ** ** |
| ** **                | ** **   | **(as previously reported)** | ** **   | **(as restated)** | ** **   | **Difference** | ** ** |
| ** **                |         |                                   |         |                   |         |   |   |
| **Balance Sheet:**        |         |                                   |         |                   |         |   |   |
| Assets                    |         | $                                      | 48,957,958   |                   | $            | 48,957,958 |   | $ | — |   |
| Liabilities               |         | 17,034,787                             |         | 15,962,562             |         | (1,072,225 | ) |
| Temporary equity          |         | 790,500                                |         | 790,500                |         | — |   |
| Stockholders’ equity |         | 31,132,671                             |         | 32,204,896             |         | 1,072,225 |   |
| *** ***              | *** *** | *** ***                           | *** *** | *** ***           | *** *** | *** *** | *** *** |
| **Income Statement:**     |         |                                   |         |                   |         |   |   |
| Pre-tax Income            |         | 40,706,141                             |         | 40,706,141             |         | — |   |
| Income tax expense        |         | 16,080,000                             |         | 15,007,775             |         | (1,072,225 | ) |
| Net income                |         | $                                      | 24,626,141   |                   | $            | 25,698,366 |   | $ | 1,072,225 |   |

 

**4. Acquisitions and Divestitures**

 

During the year ended June30, 2007, we incurred $597,433 in lease bonuses related to our oil and gasacreage leasing activity, most of which was incurred in the latter half of thefiscal year. Of this amount, $478,147 was incurred on our Initiative IIBypassed Resource plays in Texas, and $119,286 was incurred for our InitiativeIII Unconventional Gas Resource plays in the Mid-Continent Region.

 

On July 21, 2006, we closedthe acquisition of 0.39% in additional mineral royalty and overriding royaltyinterests in the Delhi Holt Bryant Unit, within the Delhi Field in NorthLouisiana, for $85,000 in cash consideration.

 

On September20, 2006, we closed the purchase of a small parcel of land in Tullos,Louisiana, for $11,910, which will be used as a field yard to store tangiblelease and wellhead equipment for our Tullos Field Area operations.

 

The funds usedto acquire both of these properties were funded with monies set aside in ourqualified intermediary (**QI**) bankaccount. The QI account provides us the opportunity to defer therecognition of taxable gain on amounts used from the QI account to acquirelike-kind property within 180 days from the date of the outgoing property salefrom our Delhi Farmout in exchange for assets identified within 45 days of suchsale pursuant to Internal Revenue Code Section 1031.

 

On September28, 2006, we completed the sale of two producing wells to the State ofLouisiana that were located on a state highway expansion project beingconstructed through the Tullos Urania Field. We received net consideration ofapproximately $155,000.

 

In fiscal year2006, we acquired royalty and overriding royalty interests totalingapproximately 7% in the Delhi Holt Bryant Unit (“Delhi Unit”) within the DelhiField, for $1,464,000 of cash consideration, $420,000 of which came from the QIaccount.

 

**5. Asset Retirement Obligations**

 

Asset retirement obligationsare included in long term liabilities on our balance sheet. The following tabledescribes the changes in our asset retirement obligations for the period fromJune 30, 2006 to June 30, 2007:

 

| Asset retirement obligation at June 30,  2006 |   | $      | 123,679 |   |   |
|-----------------------------------------------|--------|--------|---------|--------|--------|
| Liabilities incurred                          |   | — |    |   |
| Accretion expense for 2007                    |   | 17,319 |    |   |
| Revisions to estimates                        |   | — |    |   |
| Asset retirement obligation at June 30,  2007 |   | $      | 140,998 |   |   |

 

33

----

 

**6. Oil and Gas Properties**

 

As of June 30, 2007 and2006, oil and gas properties not subject to amortization totaled $1,924,552 and$52,098, respectively. The significant increase in current year unamortizedcosts primarily consists of leaseholds acquired through a current and ongoingleasing program the Company started in December 2006. These costs are reviewedquarterly to determine when they should be transferred to the full cost pooland amortized.

 

**7. Stock-Based Compensation**

 

Effective July 1,2006, we adopted the fair value recognition provisions of Statement ofFinancial Accounting Standard 123(R) “*Share-BasedPayment”* (“SFAS 123(R)”) using the modified prospective transitionmethod. In addition, the Securities and Exchange Commission issued StaffAccounting Bulletin No. 107 “*Share-BasedPayment*” (“SAB 107”) in March 2005, which provides supplemental SFAS123(R) application guidance based on the views of the SEC. Under the modifiedprospective transition method, compensation cost recognized in the fiscal yearended June 30, 2007 includes: (a) compensation cost for all share-basedpayments granted prior to, but not yet vested as of July 1, 2006, based on thegrant date fair value estimated in accordance with the original provisions ofSFAS No. 123, and (b) compensation cost for all share-based paymentsgranted beginning July 1, 2006, based on the grant date fair value estimated inaccordance with the provisions of SFAS 123(R). In accordance with the modifiedprospective transition method, results for prior periods have not beenrestated.

 

The adoption ofSFAS 123(R) resulted in stock compensation expense for the fiscal year endedJune 30, 2007 of approximately $1.6 million. This additional share-basedcompensation expense increased basic and diluted loss per share by $0.06 forthe fiscal year ended June 30, 2007. For the fiscal year ended June 30, 2007,we did not recognize a tax benefit related to stock compensation expensebecause we believe it is more likely than not that the related deferred taxassets, which have been reduced by a full valuation allowance, will not berealized.

 

Weuse the Black-Scholes option-pricing model to estimate option fair values. Theoption-pricing model requires a number of assumptions, of which the mostsignificant are, expected stock price volatility, the expected pre-vestingforfeiture rate and the expected option term (the amount of time from the grantdate until the options are exercised or expire

 

Forperiods prior to July 1, 2006, we applied the intrinsic method to ourstock-based compensation awards to our employees and directors as set forth inAccounting Principles Board (“APB”) Opinion No. 25, “Accounting for StockIssued to Employees,” and related interpretations. Under these principles, no compensationexpense for stock options granted to employees is reflected in net income aslong as the stock options have an exercise price at least equal to the quotedmarket price of the underlying common stock on the date of grant.

 

***Pro Forma Stock Compensation Expense for the fiscalyear ended June 30, 2006***

 

Thefollowing table illustrates the effect on net earnings per share if we hadapplied the fair value recognition provisions of SFAS 123(R) to stock-basedemployee compensation for the year ended June 30, 2006: 

 
| Net income attributable to common  stockholders, as reported    |   | $          | 25,698,366 |   |
|-----------------------------------------------------------------|--------|------------|------------|--------|
| Plus: share based compensation expense  determined under APB 25 |   | 171,537    |       |
| Less: compensation expense determined under  Fair Value Method  |   | (1,543,690 | )          |
| Pro forma net income attributable to common  stockholders       |   | $          | 24,326,213 |   |
|                                                            |   |       |       |
| Basic earnings per common share:                                |   |       |       |
| As reported                                                     |   | $          | 1.03       |   |
| Pro Forma                                                       |   | $          | 0.97       |   |
|                                                            |   |       |       |
| Diluted earnings per common share:                              |   |       |       |
| As reported                                                     |   | $          | 1.01       |   |
| Pro Forma                                                       |   | $          | 0.95       |   |

 

Thefair values of options and warrants granted during the years ended June 30,2007 and 2006 were estimated at the date of grant using the Black-Scholesoptions pricing model assuming no dividends and with the following weightedaverage assumptions:  

 
| ** **                  | ** ** | **Year ended** | ** ** |
|-----------------------------|------------|---------------------|------------|
| ** **                  | ** ** | **June 30,**   | ** ** |
| ** **                  | ** ** | **2007**            | ** ** | **2006** | ** ** |
| Risk-free rate              |       | 4.8                 | %          | 4.2% - 4.9% |   |
| Expected term (in years)    |       | 6.25                |       | 2 -4 |   |
| Weighted-average volatility |       | 163                 | %          | 104% - 159% |   |

 

34

----

 

Volatilitiesare based on the historical volatility of our closing common stock price. Expectedterm of options and warrants granted represents the period of time that optionsand warrants granted are expected to be outstanding. The risk-free rate forperiods within the contractual life of the options and warrants is based on thecomparable U.S. Treasury rates in effect at the time of each grant. Theweighted average grant-date fair value of options granted during the yearsended June 30, 2007 and 2006 was $2.71 and $1.31, respectively. There were noemployee options or warrants exercised for the fiscal years ended June 30, 2007and 2006.

 

***Stock Options and Warrants***

 

Forthe year ended June 30, 2007, we issued 150,000 stock options to an employee aspart of their compensation for employment. The options were granted at themarket price on the date of grant, and vests over four years. For the yearended June 30, 2007, no warrants were granted and no options or warrants havebeen exercised, canceled or forfeited. As of June 30, 2007, we had 1,037,500 ofwarrants outstanding to officers of the Company issued outside of the 2003Stock Option Plan and the 2004 Stock Plan, exclusive of warrants for capitalraising services.

 

Thefollowing table sets forth the stock option and warrant transactions for theyear ended June 30, 2007:

 
| ** **                                         | ** ** | **Number of  Options/Warrants** | ** ** | **Weighted  Average Grant  Price** | ** ** | **Aggregate  Intrinsic  Value (1)** | ** ** | **Weighted  Average  Remaining  Contractual  Term (in years)** | ** ** |
|----------------------------------------------------|------------|--------------------------------------|------------|-----------------------------------------|------------|------------------------------------------|------------|--------------------------------------------------------------------------|------------|
| Options and warrants outstanding at July 1,  2006  |       | 3,798,500                            |       | $                                       | 1.49       |                                     |       |                                                                     |       |   |
|                                               |       |                                 |       |                                    |       |                                     |       |                                                                     |       |
| Granted                                            |       | 150,000                              |       | $                                       | 2.71       |                                     |       |                                                                     |       |   |
| Exercised                                          |       | 0                                    |       |                                    |       |                                     |       |                                                                     |       |
| Canceled, forfeited, or expired                    |       | 0                                    |       |                                    |       |                                     |       |                                                                     |       |
|                                               |       |                                 |       |                                    |       |                                     |       |                                                                     |       |
| Options and warrants outstanding at June  30, 2007 |       | 3,948,500                            |       | $                                       | 1.54       |                                     | $          | 5,979,325                                                                |       | 7.8 |   |
|                                               |       |                                 |       |                                    |       |                                     |       |                                                                     |       |
| Options and warrants exercisable at June  30, 2007 |       | 2,386,625                            |       | $                                       | 1.37       |                                     | $          | 4,013,059                                                                |       | 7.7 |   |

 

----

(1)Based upon the difference between the market price of our common stock on thelast trading date of the fiscal year and the option or warrant exercise priceof in-the-money stock options or warrants.

 

Asummary of the status of our non-vested options and warrants as of June 30,2007, and the changes during the year ended June 30, 2007, is presented below:

 
| ** **                      | ** ** | **Number of  Options and  Warrants** | ** ** | **Weighted Average  Grant-Date Fair  Value** | ** ** |
|---------------------------------|------------|------------------------------------------------|------------|--------------------------------------------------------|------------|
|                            |       |                                           |       |                                                   |       |
| Non-vested at July 1, 2006      |       | 2,335,532                                      |       | $                                                      | 1.66       |   |
|                            |       |                                           |       |                                                   |       |
| Granted                         |       | 150,000                                        |       | $                                                      | 2.61       |   |
|                            |       |                                           |       |                                                   |       |
| Vested                          |       | (923,657                                       | )          |                                                   |       |
| Canceled, forfeited, or expired |       | 0                                              |       |                                                   |       |
|                            |       |                                           |       |                                                   |       |
| Non-vested at June 30, 2007     |       | 1,561,875                                      |       | $                                                      | 1.51       |   |

 

AtJune 30, 2007, unrecognized stock-based compensation expense related tonon-vested stock option and warrant grants totaled approximately $2.2 million. Thisunrecognized expense will be amortized on a straight-line basis per grant overa weighted average remaining life of approximately 2.1 years.

 

35

----

 

***Restricted Stock***

 

Forthe year ended June 30, 2007, we issued a total of 57,242 shares of commonstock pursuant to the stock grants described in the next paragraph. Werecognized compensation expense over the vesting period of these shares. Duringthe year ended June 30, 2007, we recognized aggregate compensation expense of$94,633 related to these outstanding restricted stock grants.

 

OnOctober 5, 2006, we granted 20,000 shares of restricted stock with a grant datefair value of $2.71 per share to a new employee as a sign on bonus. On December14, 2006, we granted a total of 37,242 shares (or 12,414 shares to each of ourthree independent outside directors) of restricted stock with a weightedaverage grant date fair value $2.90 per share. Such restricted stock grantsvest over a one-year period. Each of the above restricted stock grants issubject to forfeiture, and cannot be sold, transferred or disposed of duringthe restriction period. We recognize compensation expense over the vestingperiod of these shares.

 

Thefollowing table sets forth the restricted stock transactions for the year endedJune 30, 2007:

 
| ** **                      | ** ** | **Number of  Restricted  Shares** | ** ** | **Weighted  Average  Grant-Date  Fair Value** | ** ** |
|---------------------------------|------------|----------------------------------------|------------|----------------------------------------------------|------------|
|                            |       |                                   |       |                                               |       |
| Outstanding at July 1, 2006     |       | 25,000                                 |       | $                                                  | 1.61       |   |
|                            |       |                                   |       |                                               |       |
| Granted (1)                     |       | 57,242                                 |       | $                                                  | 2.83       |   |
|                            |       |                                   |       |                                               |       |
| Vested                          |       | (44,310                                | )          |                                               |       |
| Canceled, forfeited, or expired |       | 0                                      |       |                                               |       |
|                            |       |                                   |       |                                               |       |
| Outstanding at end of period    |       | 37,932                                 |       | $                                                  | 2.85       |   |

 

----

(1)The weighted average grant date fair value of restricted stock granted for theyear ended June 30, 2007 was $2.83. The weighted average grant date fair valueof restricted stock granted for the year ended June 30, 2006 was $1.61.

 

At June 30, 2007,unrecognized stock compensation expense related to restricted stock totaledapproximately $68,000. Such unrecognized expense will be recognized as vestingoccurs over a weighted average period of 0.5 years.

 

**8. Common Stock, Stock Optionsand Warrants**

 

CommonStock

 

During the year ended June30, 2007, we reclassified $790,500 from temporary to permanent equity asdiscussed in the Registration Rights section below.

 

During the quarter endedMarch 31, 2007, we issued 20,000 shares of common stock to an employee as partof an incentive compensation package for employment. Also, three outsidedirectors each received 12,414 shares of restricted common stock as part of arevised compensation plan for directors. All issuances of common stock aresubject to vesting terms per individual stock agreements.

 

During the quarter endedDecember, 31, 2006, we entered into an amended consulting agreement whereby theconsultant continues to provide investor relations services. For this, theCompany agreed to issue to the consultant 50,000 shares of common stock, whichis subject to monthly vesting, over a twelve month period. The effective dateof the agreement is November 1, 2006.

 

During the year ended June30, 2006, we raised gross proceeds of $790,500 from the sale of our commonstock in a private equity offering and $209,235 from the issuance of warrantsto Prospect Energy Corporation (Prospect) with respect to their additional loan.A total of 351,335 shares were sold at a price of $2.25 per share. We paidChadbourn Securities and Laird Q. Cagan, a placement agent fee consisting of(i) cash equal to 8% of the gross proceeds, or $63,240 and (ii) warrantsexercisable for up to 14,054 shares of our common stock at an exercise price of$2.25 per share.

 

As part of the repayment ofthe Prospect loan, Prospect demanded payment of an additional 100,000 warrantsexercisable at a price of $2.71 per share. While we disagreed with thejustification for the demand, we elected to issue the warrants. Since Prospectelected to immediately exercise the warrants, the impact of the issuance of thedisputed warrants was negligible.

 

During the fiscal year 2006,we issued an aggregate 88,000 shares of common stock to individual consultantsfor services rendered; issued 160,000 shares of common stock to Rubicon MasterFund  as compensation for not securing aneffective registration on previously issued shares per the agreement; andlastly, various holders exercised their warrants into 1,278,064 shares ofcommon stock.

 

Options and Warrants issuedto Employees and Directors

 

2003 Stock Option Plan

 

36

----

 

Old NGS adopted a stockoption plan in 2003 (the “2003 Plan”). The purpose of the 2003 Plan was tooffer selected individuals an opportunity to acquire a proprietary interest inthe success of Old NGS, or to increase such interest, by purchasing shares ofthe Old NGS common stock. The 2003 Plan provided both for the direct award orsale of shares and for the grant of options to purchase shares in an aggregateamount not to exceed 4,000,000 shares. Options granted under the Plan includednon-statutory options as well as incentive stock options intended to qualifyunder Section 422 of the Internal Revenue Code. Of the options to purchase600,000 shares granted under the 2003 Plan by Old NGS, all were assumed byReality Interactive, Inc., predecessor to the Company. Of these, options topurchase 250,000 shares were granted to each of Messrs. Herlin and McDonald.These options were accounted for under APB 25.

 

2004 Stock Plan

 

On August 3, 2004, weadopted our 2004 Stock Plan (the “2004 Plan”). The purpose of the 2004 Plan isto offer selected individuals an opportunity to acquire a proprietary interestin our success, or to increase such interest, by purchasing our shares ofcommon stock. The 2004 Plan provides both for the direct award or sale ofshares and for the grant of options or warrants to purchase shares in anaggregate amount not to exceed 4,000,000 shares. Options granted under the 2004Plan may include non-statutory options as well as incentive stock optionsintended to qualify under Section 422 of the Internal Revenue Code.

 

During the twelve monthended June 30, 2007, the company awarded a stock option to purchase 150,000shares of common stock upon exercise of outstanding option under the 2004 StockPlan to an employee, subject to vesting requirements per the agreement, anddirect stock grants in the amount of 57,242 to our outside directors and anemployee, leaving 1,286,758 shares of common stock available for issuance underthe 2004 Stock Plan. See footnote 18 Subsequent events for additional stockoptions granted after the fiscal year ending June 30, 2007.

 

During the year ended June30, 2006, the company awarded stock options to purchase 761,000 shares ofcommon stock upon exercise of outstanding options under the 2004 Stock Plan toemployees and directors, all subject to various vesting requirements, leaving1,494,000 shares of common stock available for issuance under the 2004 StockPlan, after taking into account awards to non-employees totaling 50,000 shares.

 

Non-Plan Warrants toEmployees

 

No warrants were issued toemployees during the fiscal year ended June 30, 2007.

 

During the year ended June30, 2006, as part of their annual incentive compensation and in lieu of cashbonuses, Mr. Herlin was awarded warrants to purchase 400,000 shares of commonstock, 150,000 of which were immediately vested in lieu of a cash bonus and250,000 of which vest over four years, and Mr. McDonald was awarded warrants topurchase 150,000 shares, 100,000 of which were immediately vested in lieu of acash bonus and 50,000 of which vest over four years. These warrants weregranted at “at the money” on the grant date and have a contractual life of 10years.

 

Options,Warrants and Grants to Non-Employees

 

At June 30, 2007,outstanding warrants and options, excluding employees, to purchase the Company’scommon shares were as follows: 

 
| ** **                         | ** ** | **Warrants and Stock Options Outstanding** | ** ** |
|------------------------------------|------------|----------------------------------------------------------------|------------|
| ** **                         | ** ** | **(excludes employees)**                                  | ** ** |
| ** **                         | ** ** | **Range of**                                              | ** ** | **Outstanding at** | ** ** | **Exercisable at** | ** ** |
| **Holders**                        | ** ** | **Exercisable Prices**                                    | ** ** | **June 30, 2007** | ** ** | **June 30, 2007** | ** ** |
|                               |       |                                                           |       |   |   |   |   |   |   |
| Cagan McAfee Capital Partners, LLC |       | $                                                              | 1.00       |   | $ | 1.00 |   | 165,000 |   | 165,000 |   |
|                               |       |                                                           |       |   |   |   |   |   |   |
| Chadbourn Securities, Inc.         |       | $                                                              | 1.50       |   | $ | 2.50 |   | 9,463 |   | 9,463 |   |
|                               |       |                                                           |       |   |   |   |   |   |   |
| Laird Q. Cagan                     |       | $                                                              | 1.00       |   | $ | 2.50 |   | 171,308 |   | 171,308 |   |
|                               |       |                                                           |       |   |   |   |   |   |   |
| Steven D. Lee                      |       | $                                                              | 0.001      |   | $ | 1.80 |   | 110,000 |   | 110,000 |   |
|                               |       |                                                           |       |   |   |   |   |   |   |
| Others                             |       | $                                                              | 1.00       |   | $ | 2.00 |   | 69,750 |   | 69,750 |   |
|                               |       |                                                           |       |   |   |   |   |   |   |
| Total                              |       |                                                           |       |   |   | 525,521 |   | 525,521 |   |

 

During fiscal year endedJune 30, 2007, the Company made a direct stock grant for 50,000 shares toLiviakis Communications for another year of investor relations services. Also,25,000 warrants were cashless exercised in May 2007 resulting in 16,987 sharesof common stock issued.

 

During fiscal year endedJune 30, 2006, we issued warrants to purchase 14,054 shares of common stock inconnection with capital raising services to Laird Q. Cagan and ChadbournSecurities, Inc., and a stock option to purchase 50,000 shares to Steve D. Leeunder the 2004 Stock 

 

37

----

 

Plan. Mr. Lee’s grant gaverise to $39,275 of share based compensation expense under SFAS 123, to bespread over a six month vesting term, beginning March 2006. Fair value wasderived using the Black-Scholes model using the following assumptions:Volatility - 150%, Risk Free Rate - 4.50%, Estimated Term - 1 year, andDividends - 0.

 

In addition, the Companyalso made direct stock grants for 78,000 shares to Liviakis Communications forinvestor relations services and a direct stock grant for 10,000 shares to athird party consultant for services rendered. (Both grants are excluded fromthe table above)  The Liviakis stockgrant gave rise to $204,282 of expense, spread over a six month vestingschedule, beginning monthly in May 2006, and the consultant stock grant givesrise to $12,091 of immediate expense. The fair value of both direct stockgrants under SFAS 123 was equivalent to the fair value of our stock on the dateof grants.

 

During the fiscal year ended2006, 1,864,500 warrants were (cashless) exercised resulting in 1,278,064shares of common stock issued

 

**RegistrationRights**

 

Underthe terms of a private placement of 351,335 shares of our common stock, whichwe closed on June 10, 2006, the stock subscription agreement was subject to aregistration rights agreement requiring us to use our reasonable efforts toregister the stock subsequent to the demand of 40% of the holders of such stock.Such demand could not become effective, however, until the price of our commonstock exceeded at least $14.23 per share, (approximately 6.3 times thesubscription price). There were no specified damages for our failure toregister, nor a specified timetable for obtaining such registration, exceptthat the registration was to be undertaken by us as soon as practicable and wasto stay effective for 120 days, or if such registration statement was on FormS-3 and provided for sales of securities from time to time pursuant to Rule 415under the Securities Act, for up to one year. Until the demand registrationright terminated, SEC rules required us to classify the proceeds as “temporaryequity”,until such time as the registration rights had terminated. We believethe demand registration rights terminated as of June 10, 2007, as all holderswere able to freely sell their shares under Rule 144. Consequently, wereclassified the shares from temporary equity to permanent equity on ourbalance sheet at June 30, 2007.

 

Under the terms of a privateplacement of 1,200,000 shares of our common stock with the Rubicon Fund on May6, 2005, we contemporaneously entered into a registration rights agreement (the“RRA”). The RRA required us, among other things, to obtain and maintain aneffective registration statement with the SEC for Rubicon’s shares, failingwhich, would have subjected us to the payment of penalties not to exceed 1% ofthe share proceeds, or $30,000, for each month of non-compliance. Penaltieswere to be incurred for each month for which a registration statement had notbecome effective, beginning October 6, 2005. Penalties were also to be incurredfor any month for which effectiveness has not been maintained prior to theshares becoming tradable under Rule 144, but in no event would total penaltiescumulatively exceed 8% or $240,000. In January 2006, we entered into a mutualagreement with Rubicon that eliminated their demand registration rights and anypenalties, historic and future, in exchange for 160,000 shares of common stock.

 

We have also entered intoregistration rights agreements with others, the effect of which gives theholders the right to “piggyback” their shares, from time to time, as weregister other shares. Alternatively, we may be required to register shares onForm S-3 under certain conditions.

 

**9. Related Party Transactions**

 

Laird Q. Cagan, the Chairmanof our Board of Directors, is a Managing Director of Cagan McAfee CapitalPartners, LLC (“CMCP”). CMCP performs financial advisory services for uspursuant to a written agreement and is paid a monthly retainer of $5,000 permonth. In addition, Mr. Cagan is a registered representative of ChadbournSecurities, Inc. (“Chadbourn”), our non-exclusive placement agent for privatefinancings. Pursuant to the Agreement between Mr. Cagan, Chadbourn and us, asamended, we pay a cash fee equal to 8% of the first $1 million of gross equityproceeds and declining by 1% for each subsequent $1million of gross proceeds toa minimum rate of 4%, and warrants equal to 4% of the shares placed by CMCP. Nofurther financings are currently contemplated through Chadbourn Securities.

 

During the fiscal year endedJune 30, 2007, we expensed and paid CMCP $60,000 in monthly retainers.

 

During fiscal year endedJune 30, 2006, we expensed and paid CMCP $95,000 for monthly retainers, issuedwarrants to purchase 14,054 shares of common stock to Laird Q. Cagan andChadbourn Securities, Inc. and paid a $63,240 cash commission to Chadbourn inconnection with capital raising services (a portion of which Mr. Caganreceives). Also, in March 2006 Mr. Cagan loaned us $250,000, pursuant to asecured promissory note bearing interest at 10% per annum, for general workingcapital purposes. On June 13, 2006, we repaid the loan in full includingaccrued interest, or $257,058.

 

38

----

 

**10. Supplemental Disclosuresabout Oil and Gas Producing Properties (unaudited)**

 

Net Capitalized Costs

 

Evaluated and unevaluatedcapitalized costs related to our oil and gas producing activities aresummarized as follows:

 
| ** **                         | ** ** | **Year Ended June 30,  2007** | ** ** | **Year Ended June 30,  2006** | ** ** |
|------------------------------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|
| Capitalized costs - Full Cost      |       | $                                            | 4,187,440  |                                         | $          | 3,878,551 |   |
|                               |       |                                         |       |                                         |       |
| Capitalized costs - Non-Amortizing |       | 1,924,552                                    |       | 52,098                                       |       |
|                               |       |                                         |       |                                         |       |
| Total                              |       | 6,111,992                                    |       | 3,930,649                                    |       |
|                               |       |                                         |       |                                         |       |
| Less accumulated depletion         |       | (652,439                                     | )          | (371,624                                     | )          |
|                               |       |                                         |       |                                         |       |
| Net capitalized costs              |       | $                                            | 5,459,553  |                                         | $          | 3,559,025 |   |

 

Unproved properties notsubject to amortization at June 30, 2007 consisted of mainly leasehold acreageleased and related Landman broker costs incurred through our current leasingprogram. These costs are expected to be evaluated within the next two years.

 

CostsIncurred in Oil and Gas Acquisition, Exploration and Development

 

Costsincurred in oil and gas property acquisition, exploration and developmentactivities which have been capitalized are summarized as follows:

 
| ** **                  | ** ** | **Year Ended June 30, 2007** | ** ** | **Year Ended June 30, 2006** | ** ** |
|-----------------------------|------------|--------------------------------------------------|------------|--------------------------------------------------|------------|
| Property acquisition costs: |       |                                             |       |                                             |       |
| Proved                      |       | $                                                | 725,884    |                                             | $          | 1,448,239 |   |
| Unproved                    |       | 1,192,873                                        |       | (9,788                                           | )          |
| Exploration costs           |       | —                                           |       | —                                           |       |
| Development costs           |       | 417,964                                          |       | 2,283,517                                        |       |
| Total                       |       | $                                                | 2,336,721  |                                             | $          | 3,721,968 |   |

 

Results of Operations fromOil and Gas Producing Activities (unaudited)

 

Our results of operationsfrom oil and gas producing activities are presented below for fiscal years 2007and 2006. The following table includes revenues and expenses associateddirectly with our oil and gas producing activities. It does not include anyinterest costs or general and administrative costs and, therefore, is notnecessarily indicative of the contribution to consolidated net operatingresults of our oil and gas operations.

 
| ** **                                                                                                     | ** ** | **Year Ended June 30,  2007** | ** ** | **Year Ended June 30,  2006** | ** ** |
|----------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|
| Oil and gas sales                                                                                              |       | $                                            | 1,866,878  |                                         | $          | 2,861,414 |   |
| Production expenses                                                                                            |       | (1,370,226                                   | )          | (1,725,760                                   | )          |
| Production taxes                                                                                               |       | (62,426                                      | )          | (86,562                                      | )          |
| Depletion expense                                                                                              |       | (280,815                                     | )          | (402,870                                     | )          |
| Results of operations for oil and gas  producing activities (excluding corporate overhead and financing costs) |       | $                                            | 153,411    |                                         | $          | 646,222 |   |

 

Oil and Gas ReserveQuantities (unaudited)

 

The following table setsforth the net proved reserves of the Company as of July 1, 2007, and thechanges therein for the periods from July 1, 2005 to July 1, 2007. The reserveinformation was prepared by W. D. Von Gonten & Co., independent petroleumengineers. All of the Company’s oil and gas producing activities are located inthe United States.

 
| ** **                     | ** ** | **Oil (bbls)** | ** ** | **Gas (mcf)** | ** ** |
|--------------------------------|------------|---------------------|------------|--------------------|------------|
| Balance, July 1, 2005          |       | 771,883             |       | 732,123            |       |
| Purchases of minerals in place |       | 4,200               |       | 25,800             |       |
| Extensions and discoveries     |       | —              |       | —             |       |

 

39

----

 
| Revisions                      |   | 138,762   |   | —    |   |
|--------------------------------|--------|-----------|--------|-----------|--------|
| Production                     |   | (46,942   | )      | (45,368   | )      |
| Sales of minerals in place     |   | (407,403  | )      | (686,755  | )      |
| Balance, July 1, 2006 (1)      |   | 460,500   |   | 25,800    |   |
|                           |   |      |   |      |   |
| Purchases of minerals in place |   | —    |   | —    |   |
| Extensions and discoveries     |   | 694,300   |   | 3,838,000 |   |
| Revisions                      |   | (38,800   | )      | (25,800   | )      |
|                           |   |      |   |      |   |
| Production                     |   | (28,800   | )      | —    |   |
|                           |   |      |   |      |   |
| Sales of minerals in place     |   | (3,200    | )      | —    |   |
| Balance, July 1, 2007 (2)      |   | 1,084,000 |   | 3,838,000 |   |
|                           |   |      |   |      |   |
| **Proved developed reserves:** |   |      |   |      |   |
| July 1, 2005                   |   | 540,360   |   | 396,600   |   |
| July 1, 2006                   |   | 460,500   |   | 25,800    |   |
| July 1, 2007                   |   | 389,700   |   | —    |   |

 

----

(1)          During fiscal 2006, our proved reserves were reduced by the DelhiFarmout, offset by an increase in proved reserves in the Tullos Field Area dueto the increase in commodity prices and additional proved developednon-producing reserves associated with shut-in wells.

 

(2)          During fiscal 2007, we added 1.333,967 BOE of proved reserve extensionsand discoveries. Of these, 95%, or approximately 1.27 million BOE, wereacquired through leasing activities in our four Texas Bypassed Resourceprojects, requiring an estimated $18.1 million of additional capitalexpenditures to convert these proved reserves to proved developed reserves.

 

**Standardized Measure ofDiscounted Future Net Cash Flows at June 30, 2007 and June 30, 2006 (unaudited)**

 

The information that followshas been developed pursuant to SFAS No. 69 and utilizes reserve and productiondata prepared by independent petroleum consultants. Reserve estimates areinherently imprecise and estimates of new discoveries are less precise than thoseof producing oil and natural gas properties. Accordingly, these estimates areexpected to change as future information becomes available.

 

The estimated discountedfuture net cash flows from estimated proved reserves are based on prices andcosts as of the date of the estimate unless such prices or costs arecontractually determined at such date. Actual future prices and costs may bematerially higher or lower. Actual future net revenues also will be affected byfactors such as actual production, supply and demand for oil and natural gas,curtailments or increases in consumption by natural gas purchasers, changes ingovernmental regulations or taxation and the impact of inflation on costs.Future income tax expense has been reduced for the effect of available netoperating loss carryforwards.

 
| ** **               | ** ** | **Year Ended June 30,  2007** | ** ** | **Year Ended June 30,  2006** | ** ** |
|--------------------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|
| Future cash inflows      |       | $                                            | 97,669,992 |                                         | $          | 32,874,568 |   |
|                     |       |                                         |       |                                         |       |
| Future production costs  |       | (29,044,113                                  | )          | (18,167,012                                  | )          |
|                     |       |                                         |       |                                         |       |
| Future development costs |       | (18,616,000                                  | )          | (566,000                                     | )          |
|                     |       |                                         |       |                                         |       |
| Future income taxes      |       | (17,012,000                                  | )          | (2,687,000                                   | )          |
| Future net cash flows    |       | $                                            | 32,997,879 |                                         | $          | 11,454,556 |   |
|                     |       |                                         |       |                                         |       |
| 10% annual discount      |       | (11,007,581                                  | )          | (4,943,196                                   | )          |
| Standardized Measure     |       | $                                            | 21,990,298 |                                         | $          | 6,511,360 |   |

 

**Changes in Standardized Measure**

 

The following table setsforth the changes in standardized measure of discounted future net cash flowsfor the period from the years ended June 30, 2007 and 2006:

 

40

----

 
| ** **                                                         | ** ** | **Year Ended June 30,  2007** | ** ** | **Year Ended June 30,  2006** | ** ** |
|--------------------------------------------------------------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|
|                                                               |       |                                         |       |                                         |       |
| Standardized Measure, beginning balance                            |       | $                                            | 6,511,360  |                                         | $          | 13,241,078 |   |
| Net changes in income taxes                                        |       | (9,547,068                                   | )          | 1,445,256                                    |       |
| Oil and gas sales, net of costs                                    |       | (434,226                                     | )          | (1,049,092                                   | )          |
| Discoveries, extensions and transfers                              |       | 43,710,638                                   |       | 239,382                                      |       |
| Purchase of minerals in place                                      |       | —                                       |       | 354,679                                      |       |
| Sale of minerals in place                                          |       | (178,245                                     | )          | (12,916,340                                  | )          |
| Changes in prices and costs                                        |       | 254,874                                      |       | 1,403,539                                    |       |
| Change in development costs                                        |       | (16,050,414                                  | )          | 1,116,590                                    |       |
| Previously estimated development costs  incurred during the period |       | 86,000                                       |       | —                                       |       |
| Accretion discount                                                 |       | 651,136                                      |       | 1,324,108                                    |       |
| Revisions of estimates and other                                   |       | (3,013,757                                   | )          | 1,352,160                                    |       |
| Standardized Measure, ending balance                               |       | $                                            | 21,990,298 |                                         | $          | 6,511,360 |   |

 

**11. Restricted Deposits**

 

During fiscal 2007, allprior year restricted deposits totaling $326,835 had been reclassified toeither cash or other assets. In October 2006, we redeemed a certificate ofdeposit for $25,000 that was originally pledged to the State of Louisiana for futureplugging and abandonment liability for part of the Delhi field. In August 2007,we received official release of our liability from the State of Louisiana forthe Site Specific Trust Account, again for future plugging and abandonmentliability for the Delhi field; therefore, our originally pledged certificate ofdeposit for $301,835 became an un-restricted asset to the Company. Due to amaturity date beyond one year, we reclassified this item as Other assets on ourbalance sheet.

 

In December 2006, due to theexpiration of the like-kind exchange period, approximately $35 million wastransferred from the qualified intermediary account to the Money Market Fund.

 

At June 30, 2006, restricteddeposits totaled $326,835, representing an increase of $25,000 and a decreaseof approximately $560,000 from prior fiscal year end. The increase was for acertificate of deposit pledged to the State of Louisiana for future pluggingand abandonment requirements for five new wells drilled as part of theDevelopment Drilling program in Delhi field. The decrease was the result ofearly loan repayment of the Prospect Facility in May 2006. Pursuant to theterms of our Delhi Farmout arrangement, as soon as the State of Louisianaprocesses the change of operator to Denbury Onshore, LLC and Denbury funds theSite Specific Trust Account accordingly, we will be refunded the full balanceof $326,835. Approximately $226,835 exceeds FDIC insurance limits in depositoryaccounts at Wells Fargo bank.

 

Also, at June 30, 2006, wehad approximately $34.7 million (which is available to us at any time) held inthe qualified intermediary account as discussed in note 12 below. These fundswere invested in a U.S. Government Money Market Fund with short-term durations.

 

**12. Income Taxes**

 

The tax effect ofsignificant temporary differences representing deferred tax assets andliabilities at June 30, 2007 and 2006 are as follows:

 
| ** **                 | ** ** | **Year ended** | ** ** |
|----------------------------|------------|---------------------|------------|
| ** **                 | ** ** | **2007**            | ** ** | **2006** | ** ** |
|                       |       |                |       |   |   |
| Oil & gas properties   |       | $                   | (516,000   | ) | $ | (198,000 | ) |
|                       |       |                |       |   |   |
| Basis in subsidiary stock  |       | 149,000             |       | 149,000 |   |
|                       |       |                |       |   |   |
| Other                      |       | 193,000             |       | 88,000 |   |
|                       |       |                |       |   |   |
| Accrued bonus              |       | 175,000             |       | — |   |
|                       |       |                |       |   |   |
| Gain on sale of property   |       | —              |       | (12,210,000 | ) |
|                       |       |                |       |   |   |
| NOL carryforwards          |       | 5,548,000           |       | 5,598,000 |   |
| Valuation allowance        |       | (5,887,000          | )          | (5,789,000 | ) |
|                       |       |                |       |   |   |
| Net deferred tax liability |       | $                   | (338,000   | ) | $ | (12,362,000 | ) |

 

41

----

 

For year ended June 30, 2007, we have a current income tax expense of $11.4 million (split $10 million for federal income taxes and $1.4 million for state income taxes due) and a deferred tax benefit of approximately $12 million, primarily as a result of the Delhi Farmout in which we received approximately $50 million of pre-tax proceeds. In determining the $11.5 million of current tax expense, we used $39,700 of pre-merger Reality NOL’s.

 

We have established a full valuation allowance against our net deferred tax assets totaling $5.89 million for fiscal year ended 2007, and we will continue to take a full valuation allowance until an appropriate level of profitability is attained. Of this amount, $5.31 million of deferred tax assets are permanently impaired absent a change in Internal Revenue Code Section 382 legal limitations imposed on the Reality NOL’s we inherited in the merger. If not used, our unimpaired tax assets will expire between 2010 and 2023.

 

On June 12, 2006, we consummated the Delhi Farmout as a completed sale for tax purposes. The completed sale designation was important to our ability to consummate IRC Section 1031 like kind exchanges, thus potentially deferring federal income tax liability by rolling the basis of the our Delhi property into similar like kind properties we might have purchased within the short timeframes allowed under current tax law. Of the $50 million of proceeds we received from Denbury Resources for our Delhi Farmout, we placed $35 million in a qualified intermediary (“QI”) account for possible Internal Revenue Code 1031 “like-kind exchanges” (which was available to us at any time) and placed the remaining $15 million in an unrestricted account which triggered immediate taxable “boot” on the $15 million portion we received. As of June 30, 2006, we had approximately $34.7 million of cash held in the QI account, providing us the opportunity to defer the recognition of taxable gain on up to $35 million we received from the Delhi Farmout in the event that like-kind property was purchased within 180 days from the date of the outgoing property sale (being December 9, 2006) for assets identified within 45 days of such sale. As of June 30, 2006, we had utilized $420,000 from the QI account to acquire like-kind property (partially offset by approximately $82,000 of interest income earned on the QI account). As of June 30, 2007, only an additional $159,000 of additional replacement property has been acquired. As such, the remaining deferred gain became a taxable gain in fiscal year end June 30, 2007 by means of an installment sale.

 

The following is areconciliation of the Company’s expected income tax expense (benefit) based onstatutory rates to the actual expense (benefit): 

 
| ** **                                                 | ** ** | **Year ended** | ** ** |
|------------------------------------------------------------|------------|---------------------|------------|
| ** **                                                 | ** ** | **2007**            | ** ** | **2006** | ** ** |
| Income taxes (benefit) at U.S. statutory  rate             |       | $                   | (857,000   | ) | $ | 14,247,000 |   |
|                                                       |       |                |       |   |   |
| State taxes net of federal benefit                         |       | (89,000             | )          | 1,376,000 |   |
|                                                       |       |                |       |   |   |
| Non-deductible interest expense and  deferred compensation |       | 283,000             |       | 456,000 |   |
|                                                       |       |                |       |   |   |
| Deferred tax asset valuation allowance  adjustment         |       | 151,000             |       | (1,160,000 | ) |
|                                                       |       |                |       |   |   |
| IRC section 199 deduction                                  |       | (155,000            | )          | (74,000 | ) |
|                                                       |       |                |       |   |   |
| Other                                                      |       | 28,000              |       | 163,000 |   |
|                                                       |       |                |       |   |   |
| Total                                                      |       | $                   | (639,000   | ) | $ | 15,008,000 |   |

 

The U. S. statutory rate is 35%. The state of Louisiana tax rate, net of federal tax benefit is 3.4%. The blended tax rate is 38.4%

 

The deferred tax asset valuation allowance adjustment is due to an increase in deferred tax assets from the prior year.

 

**13. Operating Leases**

 

Wehave a commitment under an operating lease agreement for office space for ourcorporate headquarters. Total rent expense for the years ended June 30, 2007and 2006 was approximately $81,000 and $43,000, respectively. At June 30, 2007,future minimum rental payments due under this operating lease are as follows:

 
| **Year  ending June 30:** |   |    |      |
|---------------------------|--------|---------|-----------|
| 2008                      |   | $       | 115,074   |   |
| 2009                      |   | 138,089 |      |
| 2010                      |   | 138,089 |      |
| 2011                      |   | 138,089 |      |
| 2012                      |   | 157,268 |      |
| Thereafter                |   | 649,295 |      |
| Total                     |   | $       | 1,335,904 |   |

 

42

----

 

**14. Commodity Contracts**

 

In compliance with the loanagreement we entered into with Prospect Energy in February 2005, we executedthree commodity contracts for approximately 50% of the production volumes thatour outside petroleum engineers estimated for our proved developed producingreserves on a rolling two year basis. Although we paid off the Prospect loan inMay 2006, performance under these contracts remained effective through fiscal2006 and 2007, as described below.

 

The first commoditycontract, with Plains Marketing L.P., covered the sale of 70 barrels of crudeoil per day for a 12 month period from March 2005 through February 2006. Thefixed sale price was based upon the NYMEX WTI (West Texas Intermediate) crudeoil price and monthly settlements, wherein Plains Marketing delivered a fixedprice of $48.35 per barrel to us before adjustment for the basis differentialbetween the NYMEX price and the contract price. This contract was extended forthe months of March 2006 through May 2006 at a fixed price of $52.55 per barrelof oil for 70 barrels of oil per day, extended for the three months of June2006 through August 2006 at a fixed price of $63.45 per barrel of oil for 90barrels of oil per day, and extended for the six months of September 2006through February 2007 at a fixed price of $69.30 per barrel of oil for 90barrels of oil per day.

 

The second commoditycontract was between us and Wells Fargo Bank, N.A. We purchased a series ofprice floors, set at a NYMEX WTI price of $38.00 per barrel of crude oil, basedupon the arithmetic average of the daily settlement price for the first nearbymonth of NYMEX WTI futures, for 2,000 barrels of crude oil per month for March2006 through February 2007. The cost of the hedge was $3.00 per barrel of oil.

 

Our third commodity contractwas with Texla Energy Management, Inc., whereby we sold 100 MMBTU per day at afixed price of $6.21 per MMBTU over a fifteen month period beginning March 1,2005, and ending May 31, 2006.The fixed price was before deduction of a $0.0854per MMBTU fixed gathering charge by Gulf South, the owner of the natural gaspipeline into which we deliver our natural gas from the Delhi Field. This fixedprice included the basis differential from NYMEX to our sales point on the GulfSouth pipeline.

 

Since March 1, 2007, all ofour oil production has been sold to Plains Marketing L.P. under a normal(thirty day “evergreen”) sales contract.

 

**15. Earnings (loss) per Share**

 

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

 
| ** **                                                                                                 | ** ** | **Year ended**         | ** ** |
|------------------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                 | ** ** | ** **                  | ** ** | **June 30, 2006** | ** ** |
| ** **                                                                                                 | ** ** | **June 30, 2007** | ** ** | **(as restated)** | ** ** |
| Numerator:                                                                                                 |       |                        |       |   |   |
| Net income (loss) applicable to common  stockholders                                                       |       | $                           | (1,810,211 | ) | $ | 25,698,366 |   |
| Plus income impact of assumed conversions:                                                                 |       |                        |       |   |   |
| Preferred Stock dividends                                                                                  |       | N/A                         |       | N/A |   |
| Interest on convertible subordinated notes                                                                 |       | N/A                         |       | N/A |   |
|                                                                                                       |       |                        |       |   |   |
| Net income (loss) applicable to common  stockholders plus assumed conversions                              |       | $                           | (1,810,211 | ) | $ | 25,698,366 |   |
|                                                                                                       |       |                        |       |   |   |
| Denominator:                                                                                               |       | 26,706,713                  |       | 25,031,125 |   |
| Affect of potentially dilutive common  shares:                                                             |       |                        |       |   |   |
| Warrants                                                                                                   |       | N/A                         |       | 176,072 |   |
| Employee and director stock options                                                                        |       | N/A                         |       | 348,795 |   |
| Convertible preferred stock                                                                                |       | N/A                         |       | N/A |   |
| Convertible subordinated notes                                                                             |       | N/A                         |       | N/A |   |
| Redeemable preferred stock                                                                                 |       | N/A                         |       | N/A |   |
|                                                                                                       |       |                        |       |   |   |
| Denominator for dilutive earnings per share  - weighted average shares outstanding and assumed conversions |       | 26,706,713                  |       | 25,555,992 |   |
|                                                                                                       |       |                        |       |   |   |
| Earnings (loss) per common share:                                                                          |       |                        |       |   |   |
| Basic                                                                                                      |       | $                           | (0.07      | ) | $ | 1.03 |   |
| Diluted                                                                                                    |       | $                           | (0.07      | ) | $ | 1.01 |   |

 

43

----

 

**16. Major Customers**

 

All of our crude oil iscurrently sold to Plains Marketing L.P. (Plains) and committed through the lifeof our fixed price crude oil sales contracts, which expired with February 2007sales. Effective March 2007, the oil sales contract is a normal (“evergreen”)sales contract with Plains.

 

All of our natural gasproduction was sold to Texla Energy Management. However, since the closing ofthe Delhi Farmout in June 2006, we had no natural gas production to sell.

 

**17. 401(k) Plan**

 

EffectiveFebruary 1, 2007, we implemented a 401(k) Savings Plan which covers allemployees. At our discretion, we may match a certain percentage of the employees’contributions to the plan. The matching percentage is currently 100% of thefirst 4% of each participant’s compensation. Our matching contribution to theplan was approximately $36,000 for the fiscal year ended June 30, 2007.

 

**18. Subsequent Events**

 

On August 3, 2007, we wereadvised of an oil spill in the Tullos Field near one of our leases. At therequest of field agents of the Louisiana Department of Environmental Qualityand the EPA, we agreed to commence a clean up operation that was completed bythe end of August 2007. A detailed analysis of the oil in the spill compared toour produced oil was conducted by an EPA approved laboratory. We believe thatthe various independent analyses show, supported by the formal findings of thelaboratory, that the oil in the spill did not originate from our operations. Wealso believe that most of the estimated $600,000 of costs incurred in thecleanup, before adjustment following audit and negotiation of the billings,will be covered by insurance or reimbursement from the relevant government oilspill funds, but we can give no assurance that such reimbursement will occur. Allclean up costs, net of any reimbursements, will be expensed as incurred.

 

In August 2007, the board ofdirectors approved a resolution to issue a total of 125,000 shares of commonstock options to three new employees as part of their total compensation foremployment. The options are excisable at the closing price of the common stockon the date of issuance and vests in equal amounts quarterly over four yearsand subject to other standard terms and conditions as provided by the Company.

 

In September 2007, the boardof directors approved a resolution to issue a total of 1,010,000 shares ofcommon stock options to existing employees as part of their long term incentivecompensation. The options are excisable at the closing price of the commonstock on the date of issuance and vests in equal amounts quarterly over fouryears and subject to other standard terms and conditions as provided by theCompany.

 

**Report ofIndependent Registered Public Accounting Firm**

 

The Board of Directors andStockholders

Evolution PetroleumCorporation

Houston, Texas

 

We have audited theaccompanying consolidated balance sheets of Evolution Petroleum Corporation as ofJune 30, 2007 and 2006 and the related consolidated statements of operations,stockholders’ equity, and cash flows for the years ended June 30, 2007 and2006. These consolidated financial statements are the responsibility of theCompany’s management. Our responsibility is to express an opinion on theseconsolidated financial statements based on our audits.

 

We conducted our audits inaccordance with the standards of the Public Company Accounting Oversight Board(United States). Those standards require that we plan and perform the audits toobtain reasonable assurance about whether the financial statements are free ofmaterial misstatement. The Company has determined that it is not required tohave, nor were we engaged to perform, an audit of its internal control overfinancial reporting. Our audit included consideration of internal control overfinancial reporting as a basis for designing audit procedures that areappropriate in the circumstances, but not for the purpose of expressing anopinion on the effectiveness of the Company’s internal control over financialreporting. Accordingly, we express no such opinion. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements. An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well asevaluating the overall financial statement presentation. We believe that ouraudits provide a reasonable basis for our opinion.

 

In our opinion, the consolidatedfinancial statements referred to above present fairly, in all materialrespects, the consolidated financial position of Evolution PetroleumCorporation and subsidiaries as of June 30, 2007 and 2006, and the consolidatedresults of their operations and their cash flows for each of the years thenended in conformity with accounting principles generally accepted in the UnitedStates of America.

 

44

----

 

Asdiscussed in Note 3 to the financial statements, the Company has restated theaccompanying financial statements to correct an error in the tax provision.

 

Asdiscussed in Note 7 to the consolidated financial statements, the Companyadopted Statement of Accounting Standards No. 123 (revised 2004), “Share-Based Payment,”during the year ended June 30, 2007.

 

 **HEIN &ASSOCIATES LLP**

 

Houston, Texas

September 25, 2007

 

**ITEM 8.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIALDISCLOSURE.**

 

None.

 

**ITEM 8A.CONTROLS AND PROCEDURES.**

 

We  maintain disclosure controls and proceduresthat are designed to ensure that information required to be disclosed by us inreports that we file or submit under the Exchange Act is recorded, processed,summarized and reported within the time periods specified in the rules andforms of the SEC and that such information is accumulated and communicated toour management, including our Chief Executive Officer and Chief FinancialOfficer, as appropriate, to allow timely decisions regarding requireddisclosure. As required by SEC Rule 13a-15(b), we carried out an evaluation,under the supervision and with the participation of our management, includingour Chief Executive Officer and Chief Financial Officer, of the effectivenessof the design and operation of our disclosure controls and procedures as of theend of the period covered by this report.

 

Based on the foregoing,our  Chief Executive Officer and ChiefFinancial Officer concluded that, as of the end of the period covered by thisreport, our disclosure controls and procedures were effective in ensuring thatthe information required to be disclosed in reports we file or submit under theExchange Act is recorded, processed, summarized and reported within the timeperiods specified in the SEC rules and forms and that such information is accumulated and communicated to ourmanagement, including our Chief Executive Officer and Chief Financial Officer,as appropriate, to allow timely decisions regarding required disclosure.

 

There was no change in ourinternal control over financial reporting during our last fiscal quarter thathas materially affected, or is reasonably likely to materially affect, ourinternal control over financial reporting.

 

**ITEM 8B.OTHER INFORMATION.**

 

None.

 

**PART III**

 

**ITEM 9.DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS AND CORPORATEGOVERNANCE COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT.**

 

Incorporated by reference tothe Company’s Proxy Statement to be filed with the Commission pursuant toRegulation 14A within 120 days of the end of the Company’s 2007 fiscal year.

 

**ITEM 10.EXECUTIVE COMPENSATION.**

 

Incorporated by reference tothe Company’s Proxy Statement to be filed with the Commission pursuant toRegulation 14A within 120 days of the end of the Company’s 2007 fiscal year.

 

**ITEM 11.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDERS MATTERS.**

 

Incorporated by reference tothe Company’s Proxy Statement to be filed with the Commission pursuant toRegulation 14A within 120 days of the end of the Company’s 2007 fiscal year.

 

**ITEM 12.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE.**

 

Incorporated by reference tothe Company’s Proxy Statement to be filed with the Commission pursuant toRegulation 14A within 120 days of the end of the Company’s 2007 fiscal year.

 

45

----

 

**ITEM 13.EXHIBITS.**

 

**Index ofExhibits**

 

****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)                                                              |
|                    |           |                                                                                                                                                                                                                                                      |
| 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)               |
|                    |           |                                                                                                                                                                                                                                                      |
| 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                                                                                                                                |

 

46

----

 
|   |   | 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)                                                              |
|   |   |                                                                                                                                                                                                                                                                             |
| 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)                                                                                                          |

 

47

----

 
| 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)                                                       |
|   |   |                                                                                                                                                                                                                            |
| 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)                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                            |
| 23.2   |   | Consent  of W. D. Von Gonten & Co. (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)                                                                               |

 

**ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES.**

 

Incorporated by reference tothe Company’s Proxy Statement to be filed with the Commission pursuant toRegulation 14A within 120 days of the end of the Company’s 2007 fiscal year.

 

48

----

 

**SIGNATURES**

 

In accordance with Section13 or 15(d) of the Securities Exchange Act of 1934, the registrant caused thisreport to be signed on its behalf by the undersigned, thereunto duly authorizedin the City of Houston, Texas, on the date indicated.

 
| **Evolution Petroleum Corporation** |
|-------------------------------------|
|                                |   |
|                                | *By:* | */s/* | *ROBERT  S. HERLIN* |   |
|                                |   | *Robert  S. Herlin* |
|                                |   | *Chief  Executive Officer* |
|                                |   | *(Principal  Executive Officer)* |
|                                |   |   |
|                                |   |   |
|                                | *By:* | */s/* | *STERLING  H. MCDONALD* |   |
|                                |   | *Sterling  H. McDonald* |
|                                |   | *Vice  President and Chief Financial Officer* |
|                                |   | *(Principal  Financial and* |
|                                |   | *Accounting  Officer)* |
| *Date: September 28, 2007*          | * * | * * |

 

In accordance with theSecurities Exchange Act of 1934, this report has been signed below by thefollowing persons on behalf of the registrant and in the capacities and on thedates indicated.

 

 
| **Date**             |   | **Signature** |                | **Title** |
|----------------------|--------|---------------|---------------------|-----------|
|                 |   |          |                |      |   |
| *September 28, 2007* |   | */s/*         | *E. J.  DIPAOLO*    | * *  | * * | *Director* |
|                 |   |          | *E. J.  DiPaolo*    |      |   |
|                 |   |          |                |      |   |
|                 |   |          |                |      |   |
| *September 28, 2007* |   | */s/*         | *GENE  STOEVER*     | * *  | * * | *Director* |
|                 |   |          | *Gene  Stoever*     |      |   |
|                 |   |          |                |      |   |
|                 |   |          |                |      |   |
| *September 28, 2007* |   | */s/*         | *WILLIAM  DOZIER*   | * *  | * * | *Director* |
|                 |   |          | *William  Dozier*   |      |   |
|                 |   |          |                |      |   |
|                 |   |          |                |      |   |
| *September 28, 2007* |   | */s/*         | *LAIRD Q.  CAGAN*   | * *  | * * | *Chairman  of the Board* |
| * *             |   |          | *Laird Q.  Cagan*   |      | * * |
| * *             |   |          | * *            |      | * * |
| * *             |   |          | * *            |      | * * |
| *September 28, 2007* |   | */s/*         | *ROBERT  S. HERLIN* | * *  | * * | *Director* |
|                 |   |          | *Robert S.  Herlin* |      |   |
|                      |        |               |                     |           |  |  |  |  |  |  |

 

49

----