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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 September 30, 2012

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)

Not Applicable

(Former name, former address and former fiscal year if changed since last report)

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:  x  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 November 2, 2012, was 28,051,963.

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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 Condensed Balance Sheets

(Unaudited)

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Operations

(Unaudited)

*General and administrative expenses for the three months ended September 30, 2012 and 2011 included non-cash stock-based compensation expense of $353,790 and $416,695, respectively.

See accompanying notes to consolidated condensed financial statements.

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Condensed Statements of Cash Flows

(Unaudited)

Our supplemental disclosures of cash flow information for the three months ended September 30, 2012 and 2011 are as follows:

See accompanying notes to consolidated condensed financial statements.

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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 2012 Annual Report on Form 10-K for the fiscal year ended June 30, 2012, 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., Evolution Operating Co., Inc. and Evolution Petroleum OK, 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 September 30, 2012 and June 30, 2012 our oil and natural gas properties and other property and equipment consisted of the following:

Unproved properties not subject to amortization consists of unevaluated acreage of $7.8 million and $6.0 million as of September 30, 2012 and June 30, 2012, respectively, for our properties in the Mississippi Lime in Oklahoma.  Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis.  Based on this evaluation there were no impaired properties for the three months ended September 30, 2012.  During the corresponding prior year period, we transferred approximately $0.8 million of impaired assets, reflecting principally Woodford Shale properties, from our unevaluated pool to our full cost pool.

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Note 3 — Joint Interest Agreement

Effective April 17, 2012, a wholly owned subsidiary of the Company entered into definitive agreements with Orion Exploration Partners, LLC (“Orion”) to acquire and develop interests in oil and gas leases, associated surface rights and related assets located in the Mississippian Lime formation in Kay County in North Central Oklahoma.  The Company agreed to contribute cash and a drilling carry to maintain its  non-operated working interest in the joint venture.  Orion contributed the leases, its portion of the drilling capital, its operating expertise in the area and the Mississippian Lime play.  The agreement commits the parties to drill between six and fourteen gross wells by April 17, 2013.  To date one salt water disposal well and one producer well have been completed..

Our participation in this joint venture is reflected on our September 30, 2012 and June 30, 2012 balance sheets by the items below.  Included in the $1.4 million June 30, 2012 advance to our joint interest operating partner is an accrued $1,142,716 drilling cash call, which is also reflected in the due to joint interest partner balance.

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 three months ended September 30, 2012:

Note 5 — Stockholders’ Equity

Common Stock

On July 9, 2012, a contractor of the Company net exercised 30,000 stock options for a net issuance of 15,512 shares of common stock.  The options were granted in March 2008 at an exercise price of $4.10 per share. See Note 6.

On September 6, 2012, the Board of Directors authorized and the Company issued 154,227 shares of restricted common stock from the 2004 Stock Plan to all employees as a long-term incentive award.  Total unrecognized stock-based compensation expense of $1,223,020 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.

Series A Cumulative Perpetual Preferred Stock

There were no sales during the three months ended September 30, 2012.  During the three months ended September 30, 2011, we sold 282,255 shares of our 8.5% Series A Cumulative (perpetual) Preferred Stock with a liquidation preference of $25.00 per share, 220,000 of which were sold in an underwritten public offering and 62,255 shares of which were sold under an at-the-market sales agreement (ATM), providing aggregate net proceeds of $6,054,456 after market discounts, underwriting fees, legal and other expenses of the offerings.  The Series A Cumulative Preferred Stock cannot be converted into our common stock and there are no sinking fund or redemption rights available to holders thereof.  Optional redemption can only be made by us on or after July 1, 2014 for the stated liquidation value of $25.00 per share plus accrued dividends, or by an acquirer under a change of control prior to such date at redemption prices ranging from $25.25 to $25.75 per share.  With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common shareholders, but subordinate to any of our existing and future debt.  Dividends on the Series A Cumulative Preferred Stock accrue and accumulate at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly at $0.177083 per share, as, if and when declared by our Board of Directors.

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During the three months ended September 30, 2012 and 2011, we paid dividends of $168,575 and $127,835, respectively, to holders of our Series A Preferred Stock.

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 6,500,000 shares of common stock.  No shares are available for grant under the 2003 Stock Plan and 857,884 shares remain available for grant under the 2004 Stock Plan as of October 31, 2012.

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 MKT (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 September 30, 2012 and 2011 was $26,274 and $172,729, respectively.

There were no Stock Options granted during the three months ended September 30, 2012 and 2011.

The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of September 30, 2012, 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 ($8.08 as of September 30, 2012) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

There were 30,000 Stock Options exercised during the three months ended September 30, 2012 with an aggregate intrinsic value of $131,700.

A summary of the status of our unvested Stock Options and Incentive Warrants as of September 30, 2012 and the changes during the three months ended September 30, 2012, is presented below:

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During the three months ended September 30, 2012 and 2011, there were 18,922 and 86,083 Stock Options and Incentive Warrants that vested with a total grant date fair value of $46,359 and $162,697, respectively.

As of August 31, 2012 all compensation costs attributable to Stock Options and Incentive Warrants had been recognized.

Restricted Stock

Stock-based compensation expense related to Restricted Stock grants for the three months ended September 30, 2012 and 2011 was $327,516 and $249,966, respectively.

The following table sets forth the Restricted Stock transactions for the three months ended September 30, 2012:

For the 154,227 shares awarded above, the grant date fair value reflects the stock’s closing price on the first trading day before the grant date.  See Note 5.   At September 30, 2012, unrecognized stock compensation expense related to Restricted Stock grants totaled $3,014,246.  Such unrecognized expense will be recognized over a weighted average period of 2.9 years.

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Note 7 — Fair Value Measurement

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

The three levels are defined as follows:

Level 1 — Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 — Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 — Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Fair Value of Financial Instruments.  The Company’s other financial instruments consist of cash and cash equivalents, certificates of deposit, receivables and payables. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments.

Other Fair Value Measurements.  The initial measurement of asset retirement obligations at fair value is calculated using discounted future cash flows of internally estimated costs. Significant Level 3 inputs used in the calculation of asset retirement obligations include the costs of plugging and abandoning wells, surface restoration and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input values, which the Company reviews quarterly.

Note 8 — 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 three months ended September 30, 2012.  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, 2007 through June 30, 2011.

The Company recognized income tax expense of $760,218 and $872,594 for the three months ended September 30, 2012 and 2011,  respectively, with corresponding effective rates of  39.6% and  43.3%.

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

Note 9 — Net Income Per Share

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

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Outstanding potentially dilutive securities as of September 30, 2012 were as follows:

Outstanding potentially dilutive securities as of September 30, 2011 were as follows:

Note 10 - Unsecured Revolving Credit Agreement

On February 29, 2012, Evolution Petroleum Corporation entered into a Credit Agreement (the “Credit Agreement”) with Texas Capital Bank, N.A. (the “Lender”).  The Credit Agreement provides the Company with a revolving credit facility (the “facility”) in an amount up to $50,000,000 with availability governed by an Initial Borrowing Base of $5,000,000.  A portion of the facility not in excess of $1,000,000 is available for the issuance of letters of credit.

The facility is unsecured and has a four year term.  The Company’s subsidiaries guaranteed the Company’s obligations under the facility.  The proceeds of any loans under the facility are to be used by the Company for the acquisition and development of Oil and Gas Properties (as defined in the facility), the issuance of letters of credit, and for working capital and general corporate purposes.

Semi-annually, the Borrowing Base and a Monthly Reduction Amount are re-determined from reserve reports.  Requests by the Company to increase the $5,000,000 initial amount are subject to the Lender’s credit approval process, and are also limited to 25% of the value Oil and Gas Properties.

At the Company’s option, borrowings under the facility bear interest at a rate of either (i) an adjusted LIBOR rate (LIBOR rate divided by the remainder of 1 less the Lender’s Regulation D reserve requirement), or (ii) an adjusted Base Rate equal to the greater of the Lender’s prime rate or the sum of 0.50% and the Federal Funds Rate. A maximum of three LIBOR based loans can be outstanding at any time.  Allowed loan interest periods are one, two, three and six months.  LIBOR interest is payable at the end of the interest period except for six-month loans for which accrued interest is payable at three months and at end of term.  Base Rate interest is payable monthly.  Letters of credit bear fees reflecting 3.5% per annum rate applied to their principal amounts and are due when transacted.  Their maximum term is one year.

A commitment fee of 0.50% per annum accrues on unutilized availability and is payable quarterly.  The Company is responsible for certain administrative expenses of the Lender over the life of the Credit Agreement as well as for compensating the Lender $50,000 for incurred loan costs upon closing.

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The Credit Agreement also contains financial covenants including a requirement that the Company maintain a current ratio of not less than 1.5 to 1; a ratio of total funded Indebtedness to EBITDA of not more than 2.5 to 1, and a ratio of EBITDA to interest expense of not less than 3 to 1.  The agreement specifies certain customary covenants, including restrictions on the Company and its subsidiaries from pledging their assets, incurring defined Indebtedness outside of the facility other that permitted indebtedness, and it restricts certain asset sales.  Payments of dividends for the Series A Preferred are only restricted by the EBITDA to interest coverage ratio, wherein Series A dividends are a 1X deduction from EBITDA (as opposed to a 3:1 requirement if dividends were treated as interest expense).  The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the Lender may declare all amounts outstanding under the Credit Agreement to be immediately due and payable.

As of September 30, 2012, the Company had no borrowings and no outstanding letters of credit issued under the facility, resulting in an available borrowing base capacity of $5,000,000.  The Company was in compliance with all the covenants of the Credit Agreement.

In connection with this agreement the Company incurred $179,468 of debt issuance costs, which have been capitalized in Other Assets and are being amortized on a straight-line basis over the term of the agreement.

Note 11 — 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 September 30, 2012 under this operating lease are as follows:

Rent expense for the three months ended September 30, 2012 and 2011 was $36,808 and $36,808, respectively.

Employment Contracts.  We have employment agreements with the Company’s three named officers.  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 September 30, 2012 is approximately $685,000.

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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended June 30, 2012 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K.  Any terms used but not defined herein have the same meaning given to them in the Form 10-K.

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 2012 Annual Report on Form 10-K for the year ended June 30, 2012 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

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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 net asset values on a per share basis.  In doing so, we depend on a conservative capital structure, allowing us to maintain financial control of our assets for the benefit of our shareholders, including approximately 24% 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 Reservoir Development.

We expect to fund our base fiscal 2013 development plan from working capital, with any increases to the base plan funded out of working capital, net cash flows from our properties in the Giddings and Delhi Fields and appropriate financing vehicles, including possible additional issuances of our Series A perpetual non-convertible preferred stock.

Highlights for our First Quarter Fiscal 2013 and Project Update

“Q1-13” & “current quarter” is the three months ended September 30, 2012, the company’s 1st quarter of fiscal 2013.

“Q4-12” & “prior quarter” is the three months ended June 30, 2012, the company’s 4th quarter of fiscal 2012.

“Q1-12” & “year-ago quarter” is the three months ended September 30, 2011, the company’s 1st quarter of fiscal 2012.

Operations

·                  Q1-13 net income available to common shareholders increased 6.9% sequentially to $1.0 million compared to $0.9 million in the prior quarter and slightly declined 2.4% from $1.0 million in the year-ago quarter.  Sequentially, lower field margins were offset by lower income taxes and slightly better BOE volumes.  The lower margin, as described below, reflects decreased average product prices partially offset by lower LOE.

·                  Current quarter revenue decreased 6.3% sequentially to $4.3 million from $4.6 million in the prior quarter, while increasing 10.5% from $3.9 million in the year-ago quarter.  The sequential decline primarily reflects lower Delhi revenue partially offset by higher natural gas revenue.  The increase from the year-ago quarter is due to higher Delhi revenue partially offset by decreases in NGL and natural gas revenues.

·                  Crude oil and NGL volumes accounted for 80% of volumes and 96% of revenues during Q1-13 compared sequentially to 81% of volume and 97% of revenues in the prior quarter, while the year-ago quarter volumes were 78% of volume and 94% of revenue.  Total liquids volumes declined sequentially 0.6% while increasing 16% compared to the year-ago quarter.  Delhi oil volumes decreased 3% from the prior quarter and increased 15% compared

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to the year-ago quarter.   Current quarter Delhi production was impacted by the operator temporarily restricting production.  Natural gas volumes, all in Giddings, also increased 13% sequentially, and increased 14% over the year-ago quarter due to improved performance of wells and prior quarter workovers.

·                  The blended product price we received in Q1-13 decreased sequentially to $80.30 per BOE from $86.91 in the prior quarter, while declining from $83.01 in the year-ago quarter.  Current quarter oil prices declined 6% sequentially to $102.49 and decreased 2% compared to the year-ago quarter.  Our average oil price reflects the large proportion of sales from Delhi that received favorable Louisiana Light Sweet pricing.  NGL prices decreased 15% sequentially and 34% from the year-ago quarter to $35.38, while natural gas prices increased 19% sequentially and decreased 38% from the year-ago quarter to $2.53.

·                  Field margin declined to $68 per BOE compared to $73 in the prior quarter and the year-ago quarter.  Compared to the prior quarter, lower revenue per BOE was partially offset by reduced LOE and slightly lower DD&A per BOE.  LOE decreased primarily due to reduced salt water disposal costs at Giddings Field, resolved water injection issues at Lopez Field and decreased parts and supplies expenses for both fields.  The lower field margin compared to the year ago quarter reflects lower revenue per BOE together with higher LOE and DD&A rates.

Projects

Delhi EOR Project

·                  Production in our enhanced oil recovery project temporarily decreased 3% sequentially and increased 15% over the year-ago quarter to 5,057 gross BOPD (374 BOPD net to our 7.4% royalty interest).  The current quarter included two months of production restricted by the operator due to process cooling limitations, compared to only one month of restricted production during the prior quarter.  Production restrictions were lifted during September and production returned to previous unrestricted levels. Peak gross production is forecasted by our independent reservoir engineer to steadily increase to approximately 11,800 BOPD by late 2017. Our working interest reversion that is forecasted to occur in late calendar 2013 will more than triple our revenue interest from 7.4% to 26.5%, while our cost bearing interest increases from 0% to 23.9%.

·                  Realized oil prices at Delhi decreased 6% sequentially and 2% from the year-ago quarter to $103.78 per BO.  Realized prices were $110.09 per BO in the previous quarter and $105.78 in the year-ago quarter.

·                  Extension of the project into the eastern half of the field continued with $24 million gross expenditures made by the operator during the current quarter and over $60 million gross expenditures so far in calendar 2012 none of which is required to be funded by us.  Proved oil reserves net to our interest were already 68% developed and probable reserves were 46% developed at our recent fiscal yearend, based on our independent engineer’s June 30, 2012 report as filed in our 2012 Form 10-K.

Mississippi Lime

·                    The operator completed the drilling of our first two Mississippian Lime wells in Kay County, OK - the Sneath with our 45% working interest and the Hendrickson with our 36.6% working interest. These two wells are the first of 114 gross probable drilling locations assigned in the independent engineer’s report of June 30, 2012, as filed with our most recent Form 10-K. As previously reported, the operator drilled and completed a salt water disposal well in the previous quarter.

·                  The Sneath well was hydraulically fractured in 12 stages and completed in late October in approximately 3,100’ of lateral section and subsequently was put on production to begin removing injected and reservoir water to permit oil and gas production. The Mississippian Lime typically requires partial depressuring to allow oil and gas to mobilize into the well bore.

·                  The Hendrickson well was hydraulically fractured in 10 stages and completed in early November in approximately 4,000’ of lateral section with production operations expected to begin shortly.

·                  We are evaluating the eastern portion of the play to expand our footprint.

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GARP® (Gas Assisted Rod Pump)

·                    We completed the commercial installation of GARP® in a fourth well in the Iola Field in Grimes County, Texas. The well was restored from no production to a rate of approximately 5 BOPD and 90 MCFD of liquids rich natural gas that is being processed for NGL.

·                  Our three previous commercial installations of GARP® continue performing well. As of early November, our four installations are producing 55-60 BOEPD gross (27-30 BOEPD net).

Lopez Field (South Texas)

·                  We expanded our salt water disposal capacity on one lease to allow a consistent water disposal rate that has increased our steady oil production rate to approximately 8 BOPD from our Garcia #1, the first oil well we drilled in the Lopez Field.

·                  Our second drilled oil well continues to steadily produce more than 15 BOPD, a higher rate than originally expected or that is projected in our reserve report.

·                  We received our permit to begin producing our third drilled oil well, have put the well on production and are currently dewatering.

·                  We continue to evaluate the long term potential of our South Texas project compared to other projects in our portfolio as to scale, profitability and timing.

Giddings Field (Central Texas)

·                  Giddings daily production increased 12% sequentially and 11% over the year-ago quarter to 194 net BOEPD.  A portion of the increase from 173 BOED in the prior quarter and from 175 net BOED in the year-ago quarter was from new GARP® production.  All of our non-GARP® wells in the Giddings Field are in their stable decline phase.

·                  We have entered into agreements in principle to divest portions of our Giddings assets in order to better focus our resources on the Mississippian Lime and GARP® projects that offer substantially more potential.

Liquidity and Capital Resources

At September 30, 2012, our working capital was $12.8 million, compared to working capital of $11.7 million at June 30, 2012.  The $1.1 million increase in working capital since June 30, 2012 was due primarily to decreases of $1.9 million in payables to our joint venture partner in the Mississipian Lime play, and $0.7 million of accrued compensation, partially offset by a cash decrease of $ 1.3 million.

Cash Flows from Operating Activities

For the three months ended September 30, 2012, cash flows provided by operating activities were $1.6 million, reflecting $2.4 million provided by operations before $0.8 million was used in working capital.  Of the $2.4 million provided before working capital changes, $1.2 million was due to net income and $1.2 million was due primarily to non-cash expenses.

For the three months ended September 30, 2011, $1.9 million of cash flows was provided by operating activities, reflecting $2.2 million provided by operations before $0.3 million was used in working capital.  Of the $2.2 million provided before working capital changes, $1.1 million was due to net income and $1.1 million was attributable primarily to non-cash expenses.

Cash Flows from Investing Activities

Cash paid for oil and gas capital expenditures during the three ended September 30, 2012 was $2.6 million.  Development activities were predominantly in the Mississippi Lime, where one salt water disposal well and one producer well were completed and a second producer well spudded with completion expected in our next fiscal quarter.  In Giddings, expenditures were centered on installing GARP® on a fourth well.

Cash paid for oil and gas capital expenditures during the three months ended September 30, 2011, was $0.5 million with expenditures primarily divided between our Giddings and Lopez fields.

Oil and gas capital expenditures incurred were $2.1 million and $0.4 million, respectively, for the three months ended September 30, 2012 and 2011.  These amounts can be reconciled to cash capital expenditures on their respective cash flow statements by adjusting

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them for changes in accounts payable and amounts owed to joint venture partners for capital expenditures as represented in the supplemental information.

Cash Flows from Financing Activities

In the three months ended September 30, 2012, we paid preferred dividends of $0.2 million.

During the three months ended September 30, 2011, we received $6.1 million of net proceeds from the issuance of 282,255 shares of our 8.5% Series A perpetual preferred stock after all offering costs and we paid $0.1 million of dividends thereon.

Capital Budget

Our approved fiscal 2013 Base Plan provides for up to $10 million of capital expenditures, the remaining balance of which can be funded from our existing working capital of $12.8 million at September 30, 2012.  We expect to fund any increases over the fiscal 2013 Base Plan out of working capital, internally generated funds from operations, joint ventures, project financing, selective divestments of noncore assets or other appropriate financings, including possible additional issuances of our Series A perpetual non-convertible preferred stock.

Results of Operations

Three month period ended September 30, 2012 and 2011

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

(a)         Excludes depreciation of office equipment, furniture and fixtures, and other assets of $12,249 and $7,829, for the three months ended September 30, 2012 and 2011, respectively.

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Net Income Available to Common Shareholders.  For the three months ended September 30, 2012, we generated net income of $990,951, or $0.03 per diluted share, (which includes $353,790 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $4,291,546.  This compares to a net income of $1,015,683, or $0.03 per diluted share, (which includes $416,695 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $3,884,856 for the year-ago quarter.  Increased revenue and lower income tax expenses were offset by higher operating expenses.  Additional details of the components of net income are explained in greater detail below.

Sales Volumes.  Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the three months ended September 30, 2012 increased 14% to 53,441 BOE’s compared to 46,800 BOE’s for the year-ago quarter.  This 6,641 volume increase primarily reflects production and sales volumes increases in Delhi, Giddings, and South Texas fields, partially offset by a decrease in our Woodford properties which have been shut in.  Our crude oil sales volumes for the current quarter include 34,453 from our interests in Delhi and 4,629 barrels from the Giddings and Lopez fields. Our crude oil sales volumes for the year-ago quarter included 29,947 barrels from our interests in Delhi and 3,213 barrels from our properties in the Giddings and Lopez fields.  Our NGL volumes for the three months ended September 30, 2012 and 2011, all from the Giddings Field, and declined 4% to 3,381 barrels.  Current quarter natural gas volumes, virtually all produced at Giddings, increased 9% to 65,869 mcf from 60,717 in the year-ago quarter.  For the current quarter, there was no gas production from our now shut in Woodford properties that produced 2,793 mcf during the year-ago quarter.

Petroleum Revenues.  Crude oil, NGLs and natural gas revenues totaling $4.3 million for the current quarter increased $0.4 million, or 11%, from $3.9 million in the year-ago quarter due to 14% higher sales volumes partially offset by a 3.3% price decline.  Prices per BOE were $80.30 and $83.01, respectively, for the current and year-ago quarter.

Lease Operating Expenses (including production severance taxes).  Lease operating expenses and production taxes for the current quarter increased $120,590, or 56%, to $337,542 compared to the year-ago quarter.  Of this increase approximately $63,000 for Giddings and $36,000 for Lopez are primarily attributable to seven wells brought on line subsequent to  the year-ago quarter.  The remainder of variance primarily is due to higher maintenance and repairs for previously existing wells.  Lease operating expense and production tax per barrel of oil equivalent increased 36% from $4.64 per BOE during year-ago quarter to $6.32 per BOE current quarter.

General and Administrative Expenses (“G&A”).  G&A expenses increased 21% from $1.7 million during the three months ended September 30, 2012 from $1.4 million in the year-ago quarter.   The increase was due primarily to a higher bonus accrual, legal expenses, and public company expenses, partially offset by lower stock compensation expense. Stock-based compensation was $353,790 (21% of total G&A) for the current quarter compared to $416,695 (30% of total G&A) for the year-ago quarter.  Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and retain staff and, as a result, likely will continue to be a significant component of our G&A costs.

Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A increased by 25% to $296,917 for the three months ended September 30, 2012, compared to $236,891 for the year-ago quarter. This change was principally due to an 9% increase in depletion rate from $4.89 per BOE in the year-ago quarter to $5.33 in the current quarter together with volume growth of 14% as described above.

Inflation.  Although the general inflation rate in the United States, as measured by the Consumer Price Index and the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services.  Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services greatly impact our lease operating expenses and our capital expenditures.  During fiscal 2012, we saw material increases in certain oil field services and materials.  Product prices, operating costs and development costs may not always move in tandem.

Known Trends and Uncertainties.  General worldwide economic conditions continue to be uncertain and volatile.  Concerns over uncertain future economic growth are affecting numerous industries, companies, as well as consumers, which impact demand for crude oil and natural gas.  If demand decreases in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues and working capital going forward.  In addition, our lease operating expenses and their percentage of our revenues are likely to increase as our working interest production increases at our Mississippian Lime Play, reversion of our back-interest at Delhi or other additions to our working interest production that would dilute extraordinary margins we have enjoyed from our mineral and overriding royalty interests at Delhi.

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

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Off Balance Sheet Arrangements

The Company has no off-balance sheet arrangements to report during the quarter ending September 30, 2012.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Information about market risks for the three months ended September 30, 2012, did not change materially from the disclosures in Item 7A. of our Annual Report on Form 10-K for the year ended June 30, 2012 except as noted below.  As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for our fiscal year ended June 30, 2012.

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents.  Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital, as, if and when needed. Lower prices may also reduce the amount of oil and natural gas that we can economically produce.  Although our current production base may not be sufficient enough to effectively allow hedging, we may periodically use derivative instruments to hedge our commodity price risk. We may hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. We may use futures contracts, swaps and fixed price physical contracts to hedge our commodity prices. Realized gains and losses from our price risk management activities are recognized in oil and natural gas sales when the associated production occurs. We presently do not hold or issue derivative instruments for hedging or speculative purposes.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to this Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely decisions regarding required disclosure.

As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)) as of the end of the quarter covered by this report.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that as of September 30, 2012 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, during the quarter ended September 30, 2012 we have determined there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in certain legal proceedings that are described in Part I. Item 3. “Legal Proceedings” and Note 12 — Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 2012 Annual Report. During the quarter ended September 30, 2012, there were no material developments in the status of those proceedings. We believe that the ultimate liability, if any, with respect to these other claims and legal actions will not have a material effect on our financial position or on our results of operations.

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ITEM 1A. RISK FACTORS

Our Annual Report on Form 10-K for the year ended June 30, 2012 includes a detailed discussion of our risk factors. There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended June 30, 2012.

ITEM 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

A.            Exhibits