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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended December 31, 2010

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

For the transition period from               to               

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

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

(Address of principal executive offices and zip code)

(713) 935-0122

(Registrant’s telephone number, including area code)

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

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

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

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

The number of shares outstanding of the registrant’s common stock, par value $0.001, as of February 10, 2011, was 27,504,566.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

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PART I — FINANCIAL INFORMATION

ITEM 1.  CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries

Consolidated Balance Sheets

(Unaudited)

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Statements of Operations

(Unaudited)

*General and administrative expenses for the three month period ended December 31, 2010 and 2009 included non-cash stock-based compensation expense of $396,394 and $424,800, respectively. General and administrative expenses for the six month period ended December 31, 2010 and 2009 included non-cash stock-based compensation expense of $750,880 and $816,436, respectively.

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

Our supplemental disclosures of cash flow information for the six months ended December 31, 2010 and 2009 are as follows:

See accompanying notes to consolidated condensed financial statements.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 1 — Organization and Basis of Preparation

Nature of Operations.  Evolution Petroleum Corporation (“EPM”) and its subsidiaries (the “Company”, “we”, “our” or “us”), is an independent petroleum company headquartered in Houston, Texas and incorporated under the laws of the State of Nevada.  We are engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas.  We acquire properties with known oil and natural gas resources and exploit them through the application of conventional and specialized technology to increase production, ultimate recoveries, or both.

Interim Financial Statements.  The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).  Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations.  All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included.  The interim financial information and notes hereto should be read in conjunction with the Company’s 2010 Annual Report on Form 10-K for the year ended June 30, 2010, as filed with the SEC. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

Principles of Consolidation and Reporting.  Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries: NGS Sub Corp and its wholly owned subsidiary, Tertiaire Resources Company, NGS Technologies, Inc., and Evolution Operating Corp. Inc.  All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous period may include certain reclassifications that were made to conform to the current presentation.  Such reclassifications have no impact on previously reported loss or stockholders’ equity.

Use of Estimates.  The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies.  We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Note 2 — Property and Equipment

As of December 31, 2010 and June 30, 2010 our oil and natural gas properties and other property and equipment consisted of the following:

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 2 — Property and Equipment (Continued)

Unproved properties not subject to amortization includes unevaluated acreage of $5.3 and $6.0 million as of December 31, 2010 and June 30, 2010, respectively, consisting of properties in the Giddings Field in Central Texas, the Woodford Shale trend in Oklahoma, and, as of June 30, 2010, the Lopez Field in South Texas (our “Neptune Oil Project”).    Unproved properties also includes $0.7 million as of December 31, 2010 and June 30, 2010, relating to our interests in the Delhi Field in Louisiana.  Unproved properties also includes $1.1 and $1.2 million as of December 31, 2010 and June 30, 2010, respectively, related to the drilling of test wells and re-entry wells on our acreage in Wagoner County in Oklahoma.  Production testing of our wells in Oklahoma is ongoing.  Development of our unproved properties is expected to be completed within one to five years.  Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis.

Note 3 — Joint Interest Drilling Arrangement

In July 2010, we entered into a drilling arrangement with an industry partner to drill up to five horizontal development wells in the Giddings Field in central Texas.  Our industry partner has funded $6,335,634 through December 31, 2010, their portion of the initial approval for expenditure (“AFE’) for the first three wells. As of December 31, 2010, $915,276 of their funding has yet to be incurred with respect to those wells.  We have billed our industry partner $537,384 for operating expense recovery and costs incurred for their share of supplemental AFEs.  Amounts pertaining to our industry partner’s share of the joint interest drilling arrangement included in our balance sheet as of December 31, 2010, are as follows:

Note 4 — Asset Retirement Obligations

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligation for the six months ended December 31, 2010:

Note 5 — Stockholders’ Equity

On July 2, 2010, an employee of the Company exercised 6,875 stock options granted in 2007 at an exercise price of $2.33 per share. See Note 6.

On July 2, 2010, a total of 4,215 shares of restricted common stock were forfeited by an employee.  Total unrecognized stock-based compensation expense related to the shares was $11,621.  The shares were cancelled and are available for a future grant in the 2004 Stock Plan.  See Note 6.

On August 9, 2010, a total of 30,233 shares of restricted stock were issued to a new employee as long-term incentive compensation.  The value of the shares issued was $156,000, based on the fair market value on the date of issuance.  The shares are subject to a four year vesting term.  See Note 6.

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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 5 — Stockholders’ Equity (Continued)

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

On September 10, 2010, the Board of Directors authorized and the Company issued 240,478 shares of restricted common stock from the 2004 Stock Plan to certain employees as a long-term incentive award.  Total unrecognized stock-based compensation expense of $1,320,224 related to the long-term incentive award will be recognized ratably over a four year period as the restricted common stock vests.  See Note 6.

On October 1, 2010, a total of 4,845 shares of restricted stock were issued to a new employee as long-term incentive compensation.  The value of the shares issued was $29,118, based on the fair market value on the date of issuance.  The shares are subject to a four year vesting term.

On December 9, 2010, a total of 28,047 shares of restricted common stock was issued to four outside directors as part of their board compensation for calendar year 2011.  The value of the shares issued was $168,000, based on the fair market value on the date of issuance.  All issuances of common stock were subject to vesting terms per individual stock agreements, which is generally one year for directors.

On December 21, 2010, an employee of the Company exercised 30,000 stock options granted in 2003 at an exercise price of $0.001 per share. See Note 6.

Note 6 — Stock-Based Incentive Plan

We may grant option awards to purchase common stock (the “Stock Options”), restricted common stock awards (“Restricted Stock”), and unrestricted fully vested common stock, to employees, directors, and consultants of the Company and its subsidiaries under the Natural Gas Systems Inc. 2003 Stock Plan (the “2003 Stock Plan”) and the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the “2004 Stock Plan” or together, the “EPM Stock Plans”).  Option awards for the purchase of 600,000 shares of common stock were issued under the 2003 Stock Plan.  The 2004 Stock Plan authorized the issuance of 5,500,000 shares of common stock.  No shares are available for grant under the 2003 Stock Plan and, as of December 31, 2010, 180,170 shares remain available for grant under the 2004 Stock Plan.

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

Stock Options and Incentive Warrants

Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the three months ended December 31, 2010 and 2009 was $172,728 and $261,762, respectively.  Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the six months ended December 31, 2010 and 2009 was $369,571 and $527,014, respectively.

There were no Stock Options granted during the six months ended December 31, 2010 and 2009.

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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 6 — Stock-Based Incentive Plan (Continued)

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

The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of December 31, 2010, and the changes during the fiscal year:

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($6.52 as of December 31, 2010) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

There were 36,875 Stock Options exercised during the six months ended December 31, 2010 with an aggregate intrinsic value of $204,101.  There were no Stock Options or Incentive Warrants that were exercised during the six months ended December 31, 2009.

A summary of the status of our unvested Stock Options and Incentive Warrants as of December 31, 2010 and the changes during the six months ended December 31, 2010, is presented below:

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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 6 — Stock-Based Incentive Plan (Continued)

During the six months ended December 31, 2010 and 2009, there were 190,914 and 150,401 Stock Options and Incentive Warrants that vested with a total grant date fair value of $500,195 and $496,323, respectively.

The total unrecognized compensation cost at December 31, 2010, relating to non-vested Stock Options and Incentive Warrants was $699,504.  Such unrecognized expense is expected to be recognized over a weighted average period of 1.1 years.

Restricted Stock

Stock-based compensation expense related to Restricted Stock grants for the three months ended December 31, 2010 and 2009 was $223,666 and $163,038, respectively.  Stock-based compensation expense related to Restricted Stock grants for the six months ended December 31, 2010 and 2009 was $381,309 and $289,422, respectively.

The following table sets forth the Restricted Stock transactions for the six months ended December 31, 2010:

At December 31, 2010, unrecognized stock compensation expense related to Restricted Stock grants totaled $2,427,238.  Such unrecognized expense will be recognized over a weighted average period of 3.1 years.

Note 7 — Income Taxes

We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.

There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the six months ended December 31, 2010.  We believe that we have appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the years ending June 30, 2008 through June 30, 2010.

Our effective tax rate for any period may differ from the statutory federal rate due to our state income tax liability in Louisiana and to stock-based compensation related to qualified incentive stock option awards (“ISO awards”), a permanent tax difference for financial reporting, as these types of awards, if certain conditions are met, are not deductible for federal tax purposes.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 7 — Income Taxes (Continued)

We have recorded an income tax receivable for approximately $1.0 million , as a result of the carry-back of our 2010 income tax loss to our 2007 and 2006 tax years.  Significant intangible drilling costs were incurred during the 2010 fiscal year, of which, we elected to expense approximately $1.3 million for federal income tax purposes.  Under GAAP intangible drilling costs are capitalized as part of oil and natural gas properties, and depleted using the unit-of-production method.  The deduction of intangible drilling costs created a significant difference in the income tax and book basis of our oil and natural gas properties, the most significant component of our net deferred income tax liability as of December 31, 2010 and June 30, 2010.

Note 8 — Net loss Per Share

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

* Potential dilutive common shares are excluded from the computation of net loss per common shares because their effect will always be anti-dilutive.

Outstanding potentially dilutive securities as of December 31, 2010 are as follows:

Outstanding potentially dilutive securities as of December 31, 2009 are as follows:

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Note 9 — Commitments and Contingencies

We are subject to various claims and contingencies in the normal course of business.  In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdiction in which we operate.  We disclose such matters if we believe it is reasonably possible that a future event or events will confirm a loss through impairment of an asset or the incurrence of a liability. We establish reserves if we believe it is probable that a future event or events will confirm a loss and we can reasonably estimate such loss.  Furthermore, we will disclose any matter that is unasserted if we consider it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable.

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on August 1, 2016. Future minimum lease commitments as of December 31, 2010 under this operating lease are as follows:

Rent expense for the three months ended December 31, 2010 and 2009 was $36,324 and $39,232, respectively.  Rent expense for the six months ended December 31, 2010 and 2009 was $72,647 and $78,962, respectively.

Employment Contracts.  We have entered into employment agreements with the Company’s three senior executives.  The employment contracts provide for a severance package for termination by the Company for any reason other than cause or permanent disability, or in the event of a constructive termination, that includes payment of base pay and certain medical and disability benefits from six months to a year after termination.   The total contingent obligation under the employment contracts as of December 31, 2010 is approximately $524,000.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This Form 10-Q and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in our 2010 Annual Report on Form 10-K for the year ended June 30, 2010 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.

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

Executive Overview

General

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

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

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

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

·      Enhanced Oil Recovery (EOR),

·      Bypassed Primary Resources, and

·      Unconventional Shale Gas Development.

We expect to fund our fiscal 2011 development plan from working capital and net cash flows from our properties in the Giddings and Delhi Fields, although we also may utilize appropriate financing or noncore asset sales to fund additional development above our 2011 development plan.

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Highlights for our Second Quarter 2011 and Project Update

Operations

·      Net losses improved by 34% and 33% for the three and six month periods ending December 31, 2010, respectively, from the comparable prior year results.  Our net losses for the three and six month periods ended December 31, 2010 were $461,535 and $946,869, respectively, compared to $701,940 and $1,406,765 for the same periods ended December 31, 2009.  Improvements were driven by an 81% reduction in our DD&A in both periods due to our large addition of proved reserves as of June 30, 2010.

·      Sales volumes decreased 29% in the second quarter of fiscal 2011 versus our second quarter of fiscal 2010, but an increasing proportion of oil production maintained revenues.  Crude oil and NGL volumes increased 10% in the current three month period from the comparable prior year period.  Natural gas volumes declined 57% due to normal production declines at Giddings and a loss of production from our best well, the Pearson #1H. We believe that the Pearson #1H decline is a result of influx of drilling fluid water lost during the drilling of our nearby joint venture Dodd #1H well.  In early February 2011 production was partially re-established and could likely be aided further once the Dodd #1H is put on production in late February 2011.   Overall sales volumes for our properties at Giddings decreased 49% as compared to the three months ended December 31, 2009.

·      The product prices we received increased 39% on a BOE basis during our second quarter of fiscal 2011 versus our second quarter of fiscal 2010.  During the three months ended December 31, 2010, our average received oil price increased 12% to $83.28 per barrel, our received gas liquids price increased 13% to $46.12 per barrel, and our received natural gas price decreased 14% to $3.64 per dry mcf.  On a combined basis, we averaged $53.32 per BOE compared to $38.46 per BOE during the three months ended December 31, 2009.

Projects

·      Delhi Phase I tertiary production sales averaged 1,057 gross BO per day during the month of December, netting Evolution 78 BO per day from its royalty interests.  Evolution’s royalty barrels are free of all expense, including state severance tax until project payout.  Sequentially, our production during our second quarter of fiscal 2011 increased 37% over our first quarter of fiscal 2011 to 6,266 net BO. First EOR production response began in March of 2010, well after the end of second quarter of fiscal 2010, and production response continues to improve past December 2010 from Phase I wells.

·      Implementation of Phase II of our Delhi CO2 EOR project began at the end of our second quarter of fiscal 2011.  Phase II of our Delhi EOR project, which is about double the size of Phase I, was initiated through incremental CO2 injection at the end of December 2010.  Phase III, which is being installed during calendar 2011, and the remaining Phases IV and V are scheduled to include similar numbers of wells as in Phase II, as compared to the much smaller Phase I.  We expect significant increases in EOR production at Delhi from Phase II during the remainder of 2011 with first production response from Phase II expected by midyear 2011.

·      We drilled and completed two additional development wells at Giddings pursuant to our Joint Development Agreement.  As disclosed in our first quarter Form 10-Q, we entered into a joint development agreement (“JDA”) with an industry partner in July of 2010 to develop up to five of our eighteen proved and two probable horizontal drilling locations at Giddings.  These locations produce oil, gas liquids and natural gas reserves in the naturally fractured Austin Chalk, Georgetown and Buda formations. The JDA provides that we operate the drilling of two commitment wells on our proved locations in the Giddings Field, with the potential to add up to three option wells as elected by our partner.  Under the terms of the JDA, we receive a 10% carried working interest in recognition of our costs to date, retain a 10% cost bearing working interest for our cash participation, and retain a 22.5% back-in working interest on each well drilled on our partner’s 80% working interest following a simple two well basket payout and well-by-well simple pay-out on the subsequent wells (bringing our after-payout working interest to 38%).  The leases carry approximately 80% net revenue interest to the 100% working interest.

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To date, we have drilled the two commitment wells and one option well, none of which generated revenue during our second quarter of fiscal 2011.  Our share of net capital expenditures for the three wells in the JDA program to date is approximately $0.7 million. Our JDA partner is awaiting production results from the first three wells before making an election on participation in, and selection of, the remaining two option wells.  We are also exploring opportunities to enter into a second joint venture to develop our remaining drilling locations, which would require an increase in our planned capital expenditures, subject to the terms of such joint venture.

As reported in our prior 10-Q, the first JDA location, the Supak-Brinkman-1H in Burleson County, was a re-entry operation to add a single 4,100’ foot Austin Chalk lateral to an existing wellbore.  Completion operations are underway by first producing back a portion of the water lost to the formation during drilling. The unusually prolonged time it has taken to flow-back a sufficient portion of lost drilling water suggests that we should have minimal expectations for production.  At June 30, 2010, our outside engineers had assigned to the 100% working interest approximately 164,000 net BOE of proved reserves.

Following rig-down of the Supak-Brinkman, we mobilized, rigged up and completed drilling during our second fiscal quarter on the second JDA location, the Dodd #1H in northern Grimes County.  This well included two opposing laterals of 3,200’ and 4,360’ in the Georgetown formation. Production is expected to begin in late February 2011 subject to completion of flow line connections to two gas gatherers and our salt water disposal well. During normal wellbore cleanout operations following completion, we briefly tested the well at a strong production rate and shut-in pressure.  At June 30, 2010, our outside engineers assigned 244,000 net BOE of reserves to the 100% working interest, split evenly between proved and probable reserve categories.

Following rig-down of the Dodd, we mobilized and rigged up on the third JDA location (the first “option” well), the Lightsey-Lightsey #1H in Brazos County, and completed the drilling of a single 4,560’ lateral into the Buda formation.  Following completion of a gas gathering pipeline, the well began first production in early February at a four day average rate of 1.3 MMCFD of liquids rich natural gas and 124 BOPD.  At June 30, 2010, our outside engineers assigned 307,000 net BOE of reserves to the 100% working interest, split evenly between proved and probable reserve categories.

·      We initiated first testing of our mid-depth Woodford Shale project in Haskell County, OK and continued a shallow Woodford test in Wagoner County, OK.  Our second fiscal quarter activity in Oklahoma was mostly focused on our mid-depth Haskell County, OK, Woodford Shale leasehold.  During the quarter, we completed a re-entry into the John Wells #1 at approximately 5,000’ depth and successfully established production.  We are currently installing a gathering pipeline connection and expect to commence gas sales in February 2011.  We also are engaged in unitization of our second Haskell County location and expect to begin the well re-entry by the end of the third fiscal quarter of 2011.  The unitization process allows us to force pool additional acreage and thereby increase our leasehold position while holding the leases through production.  In Wagoner County, we are continuing a production test of the shallow Woodford Shale in our Limon #1 well through an extensive dewatering operation.  We are selectively not exercising lease renewal options in certain areas of our Wagoner leasehold due to test results to date.

·      We continued pursuing commercial joint ventures utilizing our proprietary artificial lift technology.  Based on tests results at Giddings, we believe our technology could re-establish production in many wells throughout Giddings and other fields developed with horizontal wells where liquids are associated with their production.  We are continuing our negotiations with a third party to demonstrate the technology with the intent of gaining an interest in the newly re-established production.  The third party has agreed to the list of target wells and is working internally to finalize the joint venture agreement, but the joint effort is taking longer than expected. Consequently, we also are working on two other commercialization demonstration projects.

·      Exercised lease options and renew other leases. We continue to exercise lease options and renew other leases to maintain high value drilling locations at Giddings and core positions in our leasehold in Oklahoma, as well as provide funds for forced pooling associated with producing Woodford wells in Oklahoma.

·      Following delayed receipt of our water injection permit during the recent quarter, we restarted our production test of the first producing well, and it is averaging approximately 2 BO per day, less than our targeted rate.  We do not expect near term development until improvement test results warrant expansion and we are allowing certain leases to expire without exercising our renewal option.

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Finances

·      We ended our first quarter with $3.2 million of working capital, compared to $4.9 million at June 30, 2010.  At December 31, 2010, working capital included $2.7 million of cash, cash equivalents and short-term certificates of deposit and $1.0 million of income taxes receivable arising from our fiscal year ended June 30, 2010 tax loss carried back to a prior tax year.   The $1.7 million reduction in our working capital since June 30, 2010 was due primarily to investments of $2.3 million in oil and natural gas properties, offset by an asset sale of $0.2 million and positive cash flow generated from our oil and gas properties.  The asset sale included one lower valued proved undeveloped location as of June 30, 2010.

·      We remained debt free. All of our expenditures were funded solely by working capital and we ended our most recent fiscal quarter with no funded debt.

Liquidity and Capital Resources

At December 31, 2010, our working capital was $3.2 million and we continued to be debt free.  This compares to working capital of $4.9 million at June 30, 2010.  The $1.7 million decrease in working capital since June 30, 2010 was due primarily to investments of $2.3 million in oil and natural gas properties, offset by an asset sale of $0.2 million and operating activities.  Of the $2.3 million of capital expenditures incurred during the six months ended December 31, 2010, $0.8 million was for leasehold acquisitions and $1.5 million was for development activities.  Development activities were in the Giddings Field in Texas, our Neptune Oil Project in the Lopez Field in South Texas, and our gas shale project in Eastern Oklahoma.

Cash Flows from Operating Activities

Cash flows used in operating activities for the six months ended December 31, 2010 were $19,007.  Cash flows used in operations included cash receipts of $2.3 million from oil and natural gas sales from our properties in the Giddings Field and our interests in the Delhi Field, less cash payments for operating expenses of $2.2 million, including lease operating expenses, production taxes, salaries and wages, and less $0.2 million in cash payments related to our joint interest partner’s share of capital expenditures and which are due from our joint interest partner.

Cash flows provided by operating activities for the six months ended December 31, 2009 were $0.3 million.  Cash flows provided by operations include cash receipts of $2.4 million from oil and natural gas sales, primarily from our properties in the Giddings Field, partially offset by $1.9 million of cash payments for operating expenses, including lease operating expenses, production taxes, and salaries and wages, and payment of $0.2 million in state income taxes.

Cash Flows from Investing Activities

Cash paid for oil and gas capital expenditures during the six months ended December 31, 2010 and 2009, was $2.0 million and $2.3 million, respectively, which includes net increases (payments) on accounts payable of $0.3 million and ($0.2) million, respectively, relating to expenditures for oil and natural gas properties.

During the six months ended December 31, 2010, $1.1 million of certificates of deposit matured.  During the six months ended December 31, 2009, we purchased $1.4 million in short-term certificates of deposit and $1.8 million of certificates of deposit matured.

Cash Flows from Financing Activities

During the six months ended December 31, 2010 and 2009, there were no significant cash flows from financing activities.

Capital Budget

Our approved fiscal 2011 Plan provides for capital expenditures of approximately $4.0 million.  We expect to fund our fiscal 2011 Plan with internally generated funds, our working capital and pursuant to the JDA we signed in July 2010.  Increases in our activity level over the planned operations will be funded from joint ventures, project financing, selective divestments of noncore assets or potentially from minor equity offerings at attractive stock valuations when capital market conditions improve.

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Results of Operations

Three months ended December 31, 2010 and 2009

The following table sets forth certain financial information with respect to our oil and natural gas operations: