UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-QSB

 

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

 

For the quarterly period ended December 31, 2006

 

OR

 

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

 

For the transition period               to             

Commission File Number 000-27862

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in charter)

 

820 Gessner, Suite 1340, Houston, Texas 77024
(Address of principal executive offices and zip code)

(713) 935-0122
(Registrant’s telephone number, including area code)

Check whether the registrant (1) 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

 

Check 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 Registrant’s common stock, par value $0.001, as of February 12, 2007, was 26,702,006.

 

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

 

EVOLUTION PETROLEUM CORPORATION, INC.

TABLE OF CONTENTS

				Page Number
PART I. FINANCIAL INFORMATION				3
ITEM 1.		FINANCIAL STATEMENTS		3
		Condensed Consolidated Balance Sheets: December 31, 2006 (unaudited) and June 30, 2006		3
		Condensed Consolidated Statements of Operations (unaudited): For the three and six months ended December 31, 2006 and 2005		4
		Condensed Consolidated Statements of Cash Flows (unaudited): For the three and six months ended December 31, 2006 and 2005		5
		Notes to Condensed Consolidated Financial Statements (unaudited)		6
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS		11
ITEM 3.		CONTROLS AND PROCEDURES		17
PART II. OTHER INFORMATION				18
ITEM 1.		LITIGATION		18
ITEM 2.		UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS		18
ITEM 4.		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		18
ITEM 6.		EXHIBITS		18
SIGNATURES				19

 

2

PART I - FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries
Condensed Consolidated Balance Sheets

		December 31,			June 30,
		2006			2006
		(unaudited)
Assets
Current Assets:
Cash		$	40,129,711		$	9,893,547
Accounts receivable, trade		153,583			132,371
Inventories		177,420			76,917
Prepaid expenses		156,390			157,629
Retainers and deposits		60,595			60,895
Total current assets		40,677,699			10,321,359
Cash in qualified intermediary account for “like-kind” exchanges		—			34,662,368
Oil & Gas properties - full cost		4,022,938			3,878,551
Oil & Gas properties - not amortized		75,441			52,098
Less: accumulated depletion		(476,696		)	(371,624		)
Net oil & gas properties		3,621,683			3,559,025
Furniture, fixtures and equipment, at cost		25,624			16,561
Less: accumulated depreciation		(11,147		)	(7,998		)
Net furniture, fixtures, and equipment		14,477			8,563
Restricted deposits		301,835			326,835
Other assets		76,675			79,808
Total assets		$	44,692,369		$	48,957,958
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$	123,752		$	310,272
Accrued liabilities		123,564			473,782
Income taxes payable		12,420,000			2,978,650
Royalties payable		5,635			47,054
Total current liabilities		12,672,951			3,809,758
Long term liabilities:
Deferred income taxes payable		—			13,101,350
Asset retirement obligations		132,055			123,679
Total liabilities		12,805,006			17,034,787
Common Stock, totaling 351,333 shares subject to demand registration rights		790,500			790,500
Stockholders’ equity:
Common Stock, par value $0.001 per share; 100,000,000 shares authorized, 26,350,672 and 26,300,664, issued and outstanding as of December 31, 2006 and June 30, 2006, respectively, net of 351,333 shares of common stock subject to demand registration rights		26,350			26,300
Additional paid-in capital		10,969,785			10,274,555
Deferred stock compensation		(114,562		)	(265,167		)
Retained earnings		20,215,290			21,096,983
Total stockholders’ equity		31,096,863			31,132,671
Total liabilities and stockholders’ equity		$	44,692,369		$	48,957,958

 

See accompanying notes to condensed consolidated financial statements.

3

Evolution Petroleum Corporation and Subsidiaries
Condensed Consolidated Statements of Operations
(unaudited)

		Three Months Ended December 31,						Six Months Ended December 31,
		2006			2005			2006			2005
Revenues:
Oil sales		$	426,459		$	557,439		$	895,483		$	1,043,834
Gas sales		—			278,955			—			336,888
Price risk management activities		—			(5,458		)	(14		)	(6,902		)
Total revenues		426,459			830,936			895,469			1,373,820
Operating Costs:
Production expenses		327,473			398,686			651,592			862,876
Production taxes		(4,357		)	21,536			30,303			36,020
Depreciation, depletion and amortization		46,350			114,431			108,221			191,681
General and administrative *		960,515			662,106			1,999,706			1,246,384
Total operating costs		1,329,981			1,196,759			2,789,822			2,336,961
Loss from operations		(903,522		)	(365,823		)	(1,894,353		)	(963,141		)
Other income and expense:
Interest income		503,318			14,955			1,034,113			33,892
Interest expense		—			(191,016		)	—			(412,694		)
Gain/(loss) on sale of assets		(21,453		)	—			(21,453		)	—
Total other income and expense		481,865			(176,061		)	1,012,660			(378,802		)
Net loss		$	(421,657	)	$	(541,884	)	$	(881,693	)	$	(1,341,943	)
Net Loss per common share
Basic and Diluted		$	(0.02	)	$	(0.02	)	$	(0.03	)	$	(0.05	)
Weighted average number of common shares
Basic and Diluted		26,685,151			24,780,405			26,668,575			24,778,730

 

See accompanying notes to condensed consolidated financial statements.

*General and administrative expenses include non cash stock compensation expense of $371,604, $156,277, $861,477 and $269,351 for the three months ended December 31, 2006 and 2005, and the six months ended December 31, 2006 and 2005, respectively.

 

4

Evolution Petroleum Corporation and Subsidiaries
Condensed  Consolidated Statements of Cash Flows
(unaudited)

		Six Months			Six Months
		Ended December			Ended December
		31, 2006			31, 2005
Cash flows from operating activities:
Net loss		$	(881,693	)	$	(1,341,943	)
Adjustments to reconcile net loss to net cash used by operating activities:
Depletion		105,072			189,348
Depreciation		3,149			2,333
Non-cash stock based compensation expense		861,477			269,351
Accretion of asset retirement obligations		8,376			14,065
Accretion of debt discount and non-cash loan costs		—			130,178
Other non cash items		—			50,232
Changes in assets and liabilities:
Accounts receivable		(21,212		)	(15,401		)
Inventories		(100,503		)	(232,777		)
Accounts payable		(186,520		)	159,772
Royalties payable		(41,419		)	33,873
Accrued liabilities		(350,218		)	(15,245		)
Income taxes payable		(3,660,000		)	—
Prepaid expenses		1,239			(48,484		)
Net cash used by operating activities		(4,262,252		)	(804,698		)
Cash flows from investing activities:
Development of oil and gas properties		(222,054		)	(1,296,019		)
Acquisitions of oil and gas properties		(101,054		)	—
Proceeds from asset sale, net		155,378			—
Capital expenditures for furniture, fixtures and equipment		(9,063		)	(2,571		)
Cash transferred from qualified intermediary account		34,662,368			—
Retainer and deposits		25,300			(15,174		)
Other assets		3,133			9,993
Net cash provided (used) in investing activities		34,514,008			(1,303,771		)
Cash flow from financing activities:
Payments on notes payable		—			(6,754		)
Equity and transaction costs		(15,592		)	—
Net cash used by financing activities		(15,592		)	(6,754		)
Net increase (decrease) in cash and cash equivalents		30,236,164			(2,115,223		)
Cash and cash equivalents, beginning of period		9,893,547			2,548,688
Cash and cash equivalents, end of period		$	40,129,711		$	433,465
Supplemental disclosure of cash flow information:
Interest paid		$	—		$	282,516
Income taxes paid		$	3,660,000		$	—

 

See accompanying notes to condensed consolidated financial statements.

 

5

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. Organization and Basis of Preparation

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

Our stock is traded on the American 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.  Prior to May 26, 2004, our stock was quoted on the OTC Bulletin Board under the symbol RLYI.OB.  Concurrently with the listing of our shares on the AMEX during July, 2006, we changed our name from Natural Gas Systems, Inc. to Evolution Petroleum Corporation to avoid confusion with similar names traded on the AMEX and to better reflect our business model.

At December 31, 2006, we conducted operations through our 100% working interests in our Tullos Field Area and our non-operated interests in our Delhi Field, all located onshore in Louisiana.  Our Tullos Field Area consists of approximately 155 producing wells out of 267 well bores across 599 acres of high water cut primary reserve production, which we believe may be a candidate for redevelopment using modern technology.  Our non-operated interests in the 13,636 acre Delhi Field consist of a 7.4% overriding and mineral royalty interest in the Delhi Holt Bryant Unit, a 25% reversionary working interest in the Delhi Holt Bryant Unit, and a 25% working interest in certain other depths in the Delhi Field.  Our Delhi Holt Bryant Unit is scheduled for redevelopment using CO2 enhanced oil recovery technology.

The accompanying unaudited condensed consolidated 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 instructions to Form 10-QSB and Item 310(b) of Regulation S-B.  All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the results of operations for the interim periods have been included. All inter-company transactions are eliminated upon consolidation. The interim financial information and notes hereto should be read in conjunction with our 2006 Annual Report on Form 10-KSB for the year ended June 30, 2006, as filed with the Securities and Exchange Commission. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

2. Recent Accounting Pronouncements

On July 13, 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 (“FIN 48”),”Accounting for Uncertainty in Income Taxes — an interpretation of FAS 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently assessing the implementation of FIN 48 and its impact on our financial statements.

In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 108. This Bulletin provides the Staff’s views on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. The guidance in SAB No. 108 is effective for financial statements of fiscal years ending after November 15, 2006. Adoption of this guidance is not expected to materially impact our financial statements.

3. Loss per Share

Basic earnings per share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share are determined on the assumption that outstanding stock options have been converted using the average price for the period. For purposes of computing earnings per share in a loss year, potential common shares have been excluded from the computation of weighted average common shares outstanding, because their effect is antidilutive.

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

		Three Months Ended December 31,						Six Months Ended December 31,
		2006			2005			2006			2005
Numerator:
Net loss		$	(421,657	)	$	(541,884	)	$	(881,693	)	$	(1,341,943	)
Plus income impact of assumed conversions:
Preferred stock dividends		N/A			N/A			N/A			N/A
Interest on convertible subordinated notes		N/A			N/A			N/A			N/A
Net loss		$	(421,657	)	$	(541,884	)	$	(881,693	)	$	(1,341,943	)
Denominator:		26,685,151			24,780,405			26,668,575			24,778,730
Affect of potentially dilutive common shares:
Warrants		N/A			N/A			N/A			N/A
Employee and director stock options		N/A			N/A			N/A			N/A
Convertible preferred stock		N/A			N/A			N/A			N/A
Convertible subordinated notes		N/A			N/A			N/A			N/A
Redeemable preferred stock		N/A			N/A			N/A			N/A
Denominator for dilutive earnings per share - weighted average shares		26,685,151			24,780,405			26,668,575			24,778,730
Net Loss per common share:
Basic and diluted		$	(0.02	)	$	(0.02	)	$	(0.03	)	$	(0.05	)

 

4. Contingent Liabilities

On November 17, 2005, a multi-plaintiff lawsuit was filed in the Fifth Judicial District Court, Richland Parish, Louisiana, against 26 defendants, including two of our subsidiaries, Arkla Petroleum L.L.C. (“Arkla”) and NGS Sub Corp (together with Arkla, the “Subsidiaries”). We were served with the lawsuit in February 2006.

The plaintiffs claim to be landowners whose property (including the soil, surface water, and groundwater) has allegedly been contaminated by oil and gas exploration, production and development activities conducted by the defendants on the plaintiffs’ property and adjoining land since the 1930s (including activities by Arkla as operator of the Delhi Field subsequent to Arkla’s formation in 2002 and our acquisition of Arkla in 2003, and activities since NGS Sub Corp’s acquisition of a 100% working interest in the Delhi Field in 2003). The plaintiffs claim that the defendants knew of the alleged dangerous nature of the contamination and actively concealed it rather than remedy the problem, and that plaintiffs discovered such damage solely within the statute of limitations period of one year prior to the filing of their complaint.

The plaintiffs are seeking unspecified compensatory damages and punitive damages, as well as an order that the defendants restore the property and prevent further contamination. Our ultimate exposure related to this lawsuit is not currently determinable, but could, if adversely determined, have a material adverse effect on our financial condition. Our costs to defend this action could also have a material adverse effect on our financial condition.

During the three months ended March, 2006, we filed our response and Motion to Stay Proceedings and Dilatory and Declinatory Exceptions with respect to this proceeding.

During the quarter ended June 2006, the Governor of the State of Louisiana signed into law new legislation addressing complaints similar to and, we believe, including those complaints filed against us. Although the intention of the legislation was designed to limit plaintiff complaints and remedies by possibly deferring first to administrative experts within the Louisiana State Departments of Environmental Quality and Natural Resources, it is unclear at this time the impact of such legislation.

There were no new developments in this case during the quarter ended December 31, 2006.

On October 11, 2006 Sybil  J. Dominique, Individually, et al., filed a lawsuit in the District Court of Dallas County Texas, against Amerada Hess Corporation and 73 other defendants, including one of our subsidiaries, Arkla Petroleum, LLC (“Subsidiary”) alleging workplace exposure to benzene caused the death of her spouse.  We were served notice of the lawsuit on October 31, 2006.  On January 5, 2007, the plaintiffs filed a Notice of Nonsuit without Prejudice, thereby dismissing us from the suit.

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5. Stock-Based Compensation

Adoption of SFAS 123(R)

Effective July 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standard 123(R) “Share-Based Payment” (“SFAS 123(R)”) using the modified prospective transition method. In addition, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 107 “Share-Based Payment” (“SAB 107”) in March 2005, which provides supplemental SFAS 123(R) application guidance based on the views of the SEC. Under the modified prospective transition method, compensation cost recognized in the three and six months ended December 31, 2006 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of July 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all share-based payments granted beginning July 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R). In accordance with the modified prospective transition method, results for prior periods have not been restated.

The adoption of SFAS 123(R) resulted in stock compensation expense for the three and six months ended December 31, 2006 of approximately $315,000 and $671,000 of the $372,000 and $861,000 of total stock compensation expense that we recorded as general and administrative expenses in the consolidated condensed statement of operations.  This additional share-based compensation expense increased basic and diluted loss per share by $0.01 for the three and six months ended December 31, 2006 resulting in reported basic and diluted loss per share of ($0.02) and ($0.03), respectively for the three and six months ended December 31, 2006.   For the current period ended, we did not recognize a tax benefit from the stock compensation expense because we believe it is more likely than not that the related deferred tax assets, which have been reduced by a full valuation allowance, will not be realized.

We use the Black-Scholes option-pricing model to estimate option fair values. The option-pricing model requires a number of assumptions, of which the most significant are, expected stock price volatility, the expected pre-vesting forfeiture rate and the expected option term (the amount of time from the grant date until the options are exercised or expire). For stock options issued subsequent to our adoption of 123(R), expected volatility, pre-vesting forfeitures and option term will be calculated using SAB 107 guidance.

For periods prior to July 1, 2006, we applied the intrinsic method to our stock-based compensation awards to our employees as set forth in Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations.  Under these principles, no compensation expense for stock options granted to employees is reflected in net income as long as the stock options have an exercise price equal to the quoted market price of the underlying common stock on the date of grant.

Pro-Forma Stock Compensation Expense for the Three and Six Months Ended December 31, 2005

The following table illustrates the effect on net loss and earnings per share if we had applied the fair value recognition provisions of SFAS 123(R) to stock-based employee compensation for the three and six months ended December 31, 2005.

		Three Months Ended			Six Months Ended
		December 31, 2005			December 31, 2005
Net loss		$	(541,884	)	$	(1,341,943	)
Add: Total stock based employee compensation benefit reported in net loss net of related tax effects		73,996			116,880
Deduct: Total stock based employee compensation benefit determined under fair value of all awards, net of related tax effects		(372,074		)	(628,431		)
Pro forma net loss		$	(839,962	)	$	1,853,494	)
Per share data:
basic and diluted, as reported		$	(0.02	)	$	(0.05	)
basic and diluted, pro forma		$	(0.03	)	$	(0.07	)

 

The fair values of options and warrants granted during the three and six months ended December 31, 2006 and 2005 were estimated at the date of grant using the Black-Scholes options pricing model assuming no dividends and with the following weighted average assumptions for grants in 2006 and 2005:

 

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Volatilities are based on the historical volatility of our closing common stock price.  Expected term of options and warrants granted represents the period of time that options and warrants granted are expected to be outstanding.   The risk-free rate for periods within the contractual life of the options and warrants is based on the comparable U.S. Treasury rates in effect at the time of each grant.

The weighted average grant-date fair value of options granted during the three months ended December 31, 2006 and 2005 was $2.61 and $0.98, respectively.  The weighted average grant-date fair value of options granted during the six months ended December 31, 2006 and 2005 was $2.61 and $0.94, respectively.  There have been no options or warrants exercised for the three and six months ended December 31, 2006 and 2005.

Stock Options and Warrants as of the Three and Six Months Ended December 31, 2006

We maintain stock option plans under which we may grant incentive stock options and non-qualified stock options to officers, employees, consultants and non-employee directors.  Under our 2003 Stock Option Plan, 600,000 shares of our common stock were approved to be issued or transferred to certain officers, employees, consultants, and non-employee directors pursuant to stock based awards granted.  No shares remain available for grant under the 2003 Stock Option plan.  Under our 2004 Stock Plan, a maximum of 4,000,000 shares of our common stock was approved to be issued or transferred to certain officers, employees, consultants and non-employee directors pursuant to future stock based awards granted.  As of December 31, 2006, 1,344,000 shares remain available for grant under the 2004 Stock Plan.  The Company has a policy of issuing new shares upon the exercise of stock options, awarding significant amounts of stock options to new employees and regularly awarding stock options to employees on an annual basis.  Stock options and warrants are generally granted at the market price on the date of grant.  The granted options and warrants have generally vested over four years for officers and employees; generally over two years for non-employee directors, and generally over one year for consultants.  The granted options and warrants generally have ten year contractual terms.

For the three and six months ended December 31, 2006, no warrants were granted and no warrants have been exercised.  As of December 31, 2006, we had 1,037,500 of warrants outstanding to officers, employees, consultants and non-employee directors issued outside of the 2003 Stock Option Plan and the 2004 Stock Plan, exclusive of warrants for capital raising services.

The following table sets forth the stock option and warrant transactions for the six months ended December 31, 2006:

		Number of Options and 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		$	2.61
Exercised		0
Canceled, forfeited, or expired		0
Options and warrants outstanding at December 31, 2006		3,948,500		$	1.54		$	5,675,650		8.3
Options and warrants exercisable at December 31, 2006		1,979,750		$	1.34		$	3,290,134		8.1

(1) Based upon the difference between the market price of our common stock on the last trading date of the quarter and the option or warrant exercise price of in-the-money option or warrants.

A summary of the status of our non-vested options and warrants as of December 31, 2006, and the changes during the six months ended December 31, 2006, is presented below:

 

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At December 31, 2006, unrecognized stock based compensation expense related to non-vested stock option and warrant grants totaled approximately $2.76 million.  This unrecognized expense will be amortized on a straight-line basis over a weighted average remaining life of approximately 2.54 years.

Restricted Stock for the period ended December 31, 2006

On October 5, 2006, we granted 20,000 shares of restricted stock with a grant date fair value of $2.71 per share to an employee.  On December 14, 2006, we granted a total of 37,242 shares (or 12,414 shares to each of our three independent outside directors) of restricted stock with a weighted average grant date fair value $2.90 per share.  Such restricted stock grants vest over a one-year period.  Each of the above restricted stock grants is subject to forfeiture, and cannot be sold, transferred or disposed of during the restriction period.  We will recognize compensation expense over the vesting period of these shares.  During the three and six months ended December 31, 2006, we recognized aggregate compensation expense of $13,547 and $13,547, respectively, related to outstanding restricted stock grants.

The following table sets forth the restricted stock transactions for the six months ended December 31, 2006:

(1)   The weighted average grant date fair value of restricted stock granted for the six months ended December 31, 2006 was $2.83.  The weighted average grant date fair value of restricted stock granted for the six months ended December 31, 2005 was $1.61.

(2)   Based upon the closing market price of our common stock on the last trading date of the quarter.

At December 31, 2006, unrecognized stock compensation expense related to restricted stock totaled approximately $149,000.  Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 0.9 years.

6. Common Stock

During the quarter ended December, 31, 2006, the Company entered into an amended consulting agreement whereby the consultant continues to provide investor relations services.  For this, the company agreed to issue to the consultant 50,000 shares of common stock, which is subject to monthly vesting, over a twelve month period.  The effective date of the agreement is November 1, 2006.

During the six months ended December 31, 2006, we incurred approximately $15,592 of costs related to filing registration statements for previous equity raised, as compared to approximately $6,800 to repay notes payable in the comparable 2005 period.

7. Commodity Hedging and Price Risk Management Activities

Pursuant to the terms of our previous credit facility, we entered into financial instruments covering approximately 50% of our expected oil and gas production from proved developed producing properties on a two year rolling basis.  We used reserve report data prepared by W. D. Von Gonten & Co., our independent petroleum engineering firm, to estimate our future production for hedging purposes.  As we may elect under FAS 133, Accounting for Derivative Instruments and Hedging Activities, we have designated our physical delivery contracts as normal delivery sale contracts.  For the oil price floors (the “Puts”) we purchased, we have not fulfilled the documentation requirements of FAS 133.  As a result, the Put contracts are “marked-to-market”, with the unrealized gain or loss reflected in our statement of operations.  Since July 31, 2005, we had the following financial instruments in place:

(i)                                                       2,100 Bbls of oil to be delivered monthly from March 2005 through February 2006 to Plains Oil Marketing LLC, at $48.35 per barrel, plus or minus changes in basis between: (a) the arithmetic daily average of the prompt month “Light Sweet Crude Oil” contract reported by the New York Mercantile Exchange, and (b) Louisiana field posted price. This is accounted for as a normal delivery sales contract.  This contract was extended for the months of March 2006 through May 2006 for 70 Bbls of oil per day at a fixed price of $52.55 per barrel of oil, and extended again for the months of June 2006 through August 2006 for 90 Bbls of oil per day at a fixed price $63.45 per barrel of oil.  Lastly, on January 27, 2006 we extended our crude oil contracts with Plains Oil Marketing, LLC for an additional six months, covering the periods September 2006 through February 2007.  The contract requires us to deliver 90 Bbls of oil per day, in exchange for a fixed price of $69.30 per Bbl, plus or minus NYMEX to posted field price basis risk.  In the case of production

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shortfalls, the required barrels are purchased at the current market price per Plains Oil Marketing price bulletins.

(ii)                                                    100 Mcfd of natural gas at a fixed price of $6.21, delivered through our Delhi Field sales tap into Gulf South’s pipeline, for the account of Texla for deliveries from March 2005 to May 2006.  This is accounted for as a normal delivery sales contract.

(iii)                                                 Purchase of a non-physical Put contract at $38.00 per barrel for 2,000 Bbls of crude oil production from March 2006 through February 2007.  This is accounted for as a “mark-to-market” derivative investment.  As of December 2006, the market value of the Put contract was zero.

8. Related Party Transactions

Laird Q. Cagan, Chairman of our Board, is a Managing Director and co-owner of Cagan McAfee Capital Partners, LLC (“CMCP”). CMCP performs financial advisory services to us pursuant to a written agreement, earning a monthly retainer of $5,000. In addition, Mr. Cagan, as a registered representative of Chadbourn Securities, Inc. (“Chadbourn”), has served as the Company’s placement agent in private equity financings, typically earning cash fees equal to 8% of gross equity proceeds, declining to 4% subject to the amount of equity raised, and a fixed 4% warrant fee.  Mr. Cagan receives no additional compensation for serving as a director or as the Chairman of our Board.

For the periods ended November 30, 2005, CMCP earned a monthly retainer of $15,000.  In December 2005, we renegotiated our agreement with CMCP, and the monthly retainer fee has decreased from $15,000 per month to $5,000 per month effective December 1, 2005. The retainer includes payment for the services of Mr. Cagan as Chairman of our Board.   In addition, for the three and six months ended December 31, 2005, Mr. Cagan, as a registered representative of Chadbourn Securities, Inc. (“Chadbourn”), has served as the Company’s placement agent in private equity financings, typically earning cash fees equal to 8% of gross equity proceeds and warrants equal to 8% of the shares purchased, exercisable over seven years, net of any similar payments made to third parties.

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

During our fiscal quarter ended December 31, 2006, we expensed and paid CMCP $15,000 in monthly retainers.  There were no other earned fees by CMCP.

9. Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 143”) provides accounting requirements for retirement obligations associated with tangible long-lived assets, including: 1) the timing of liability recognition; 2) initial measurement of the liability; 3) allocation of asset retirement cost to expense; 4) subsequent measurement of the liability; and 5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.

The reconciliation of the beginning and ending asset retirement obligation for the period ending December 31, 2006 is as follows:

 

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS

 This Form 10-QSB and the information referenced herein contain forward-looking statements. 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. We use the terms, “EPM,” “Company,” “we,” “us” and “our” to refer to Evolution Petroleum Corporation.  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 gas, operating risks and other risk factors as described in our 2006 Annual Report on Form 10-KSB 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.

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Business

Evolution Petroleum Corporation, formerly Natural Gas Systems, Inc., is a petroleum company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas. We acquire established oil and gas properties and exploit them through the application of conventional and specialized technology to increase production, ultimate recoveries, or both.

At December 31, 2006, we conducted operations through our 100% working interests in our Tullos Field Area and our non-operated interests in our Delhi Field, all located onshore in Louisiana.  Our Tullos Field Area consists of approximately 155 producing wells out of 267 well bores across 599 acres, with high water cut primary reserve production that we believe may be a candidate for redevelopment using modern technology.  Our non-operated interests in the 13,636 acre Delhi Field consist of a 7.4% overriding and mineral royalty interest in the Delhi Holt Bryant Unit, a 25% reversionary working interest in the Delhi Holt Bryant Unit, and a 25% working interest in certain other depths in the Delhi Field.  Our Delhi Holt Bryant Unit is scheduled for redevelopment using CO2 enhanced oil recovery technology by the operator.

We are focused on an overall strategy of acquiring controlling working interests in oil and gas resources within established fields and redeveloping those fields through the application of capital and technology to convert the oil and gas resources into profitable producing reserves. Our strategy is intended to generate scalable development opportunities at normally pressured depths, exhibiting relatively low completion risk, generally longer and more predictable production lives, less expenditures on infrastructure and lower operational risks. Within this overall strategy, we have established three specific business initiatives:

I               Enhanced oil recovery (EOR) using miscible and immiscible gas flooding;

II             Technology based redevelopment of mature oil and gas fields to recover bypassed resources; and

III            Unconventional gas reservoir development using modern stimulation and completion technologies.

In June 2006 we completed a major milestone in executing our EOR Initiative I.  At that time, we closed the sale of part of our interests in our Delhi Field in the form of a farmout (the “Delhi Farmout”).  As previously reported, terms of the Delhi Farmout include:

·                  We received $50 million in pre-tax cash at closing.

·                  We conveyed 100% of the working interests in the Delhi Holt Bryant Unit to Denbury Resources, retaining a 25% back-in working interest after a $200 million simple payout, excluding capital expenditures.

·                  We retained separate override and mineral royalty interests equal to approximately 7.4% on all future production from the Delhi Holt Bryant Unit.

·                  We retained a 25% working interest in certain other depths in the Delhi Field.

·                  We received a commitment by Denbury Resources to install a CO2 enhanced oil recovery project, at Denbury’s sole capital cost and expense, subject to financial penalties of up to $36 million for Denbury’s failure to expend $100 million over six and one-half years, with yearly cumulative benchmarks beginning with the period ending December 31, 2007.

We are currently engaged in reviewing or implementing additional development opportunities in all three initiatives.

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Summary Results

Financial Update

 

Financially, we are a markedly stronger company at December 31, 2006, as compared to one year earlier.

At December 31, 2006, our working capital, predominately cash, was approximately $28 million and we were debt free. This compares to approximately $0.6 million of working capital and $3 million of long-term notes payable, net of discount, at December 31, 2005.

As a proxy for cash flow from operations, EBTDA (Earnings before taxes, depletion, depreciation, amortization and other non-cash charges excluding deferred income taxes) is dramatically improved. EBTDA is a non-GAAP measure which includes the effect of our net interest income for some periods and net interest expense for other periods, as reconciled to GAAP and explained further at the end of this Item II below.

EBTDA was approximately $96,000 during the six months ended December 31, 2006, as compared to approximately $(686,000) in the comparable 2005 period.  The improvement was due mostly to earnings from our $40+ million in short term investments, combined with an approximate $413,000 reduction in interest expense during the current six month period, as compared to the comparable 2005 period.

Our net loss decreased 34% for the six months ended December 31, 2006, as compared to the comparable 2005 period.

For the six months ended December 31, 2006, our net loss was approximately $882,000, of which approximately $862,000 was due to non-cash stock compensation expense recorded in accordance with SFAS 123(R).  For the six months ended December 31, 2005, our net loss was approximately $1,342,000, of which approximately $269,000 was due to non-cash stock compensation expense recorded under APB 25.

All of these improvements are a direct result of the Delhi Farmout we completed in June 2006, despite the associated near term loss of our Delhi oil and gas production resulting from the Delhi Farmout and higher non-cash stock compensation expense due to our July 1, 2006 adoption of SFAS 123(R).

Concerning the $35 million of partial proceeds we received from the Delhi Farmout to fund a Qualified Intermediary account (“QI”) for possible like-kind exchanges in June 2006, we used approximately $579,000 to purchase additional properties, mostly consisting of Delhi Holt-Brant royalty interests.  Based on the other like-kind properties we were limited to purchasing through the QI account, we ultimately decided to pursue other properties and projects outside of this tax deferred structure.  We believe this decision will provide a higher return to our shareholders, despite forgoing a tax deferral.  As required by law, we closed the QI account within 180 days from its inception, withdrawing approximately $35.3 million during December, 2006, inclusive of approximately $844,000 of interest earned thereon.

Looking ahead, in the short term we can expect that our cash flow from operations and EBTDA will be adversely affected by reduced interest income on approximately $12.4 million scheduled to be remitted for income tax payments related to the Delhi Farmout over the next few months, cash expended in acquiring and developing new producing sources through our ongoing projects, and development expenditures aimed at improving our Tullos Field area production.  We anticipate that these adverse impacts should be increasingly offset by revenues from our new projects as, if and when they become operational.

Operational Update

Concerning future production opportunities from our planned CO2-EOR project at our 13,626 acre Delhi Holt Bryant Unit, the operator has advised us they are currently engaged in obtaining right-of-ways and pipeline route surveys.  Further, we are advised that pipeline construction is scheduled to begin in late 2007, and CO2 injection is now projected to begin in the second quarter of 2008.  We view this as a positive development.

Concerning our Tullos Field Area operations, we have experienced a 13% loss in production during the six months ended December 31, 2006, compared to the 2005 comparable period.  This was mostly due to three saltwater disposal wells being temporarily shut down, including one for high water caused by heavy rain in the area.  Production losses were exacerbated by the diversion of our only available service rig from repair and maintenance activities to our capital program to install additional saltwater disposal capacity to assist future production.

Also at Tullos, we have recently implemented an Initiative II capital program aimed at capturing bypassed oil reserves in this field.  Our initial test is expected to take place during March of this year.  Should this test prove successful, the production technology we are using could be applicable throughout our Tullos Field area, in addition to many other fields with similar high water cut reservoirs.

Looking forward, we continue to focus our staff and the cash proceeds we received from our Delhi Farmout toward identifying, acquiring and executing additional oil and gas development projects fitting within our Initiatives I-III described in the Business section above.  At December 31, 2006, we had at least $28 million of un-levered after-tax cash resources to fund these initiatives and our working capital needs.  It is our intention to commit most of these cash resources to “seed” new projects through a “proof of concept” stage, followed by outside financing in the form of insulated project financing to complete each development stage.

Results of Operations

Three months ended December 31, 2006 compared to three months ended December 31, 2005

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

		Three Months Ended
		December 31,
		2006			2005			Variance			% change
Sales Volumes, net to EPM:
Oil (Bbl)		6,080			11,828			(5,748		)	-49	%
Gas (Mcf)		0			23,977			(23,977		)	-100	%
Oil and Gas (Boe)		6,080			15,824			(9,744		)	-62	%
Revenue data (a):
Oil revenue		$	426,459		$	551,981		$	(125,522	)	-23	%
Gas revenue		0			278,955			(278,955		)	-100	%
Total oil and gas revenues		$	426,459		$	830,936		$	(404,477	)	-49	%
Average prices (a):
Oil (per Bbl)		$	70.14		$	46.67		$	23.47		50	%
Gas (per Mcf)		0			11.63			(11.63		)	-100	%
Oil and Gas (per Boe)		70.14			52.51			17.63			34	%
Expenses (per Boe)
Lease operating expenses and production taxes		$	53.14		$	26.56		$	26.59		100	%
Depletion expense on oil and gas properties		7.65			7.10			0.55			8	%

(a) Includes the cash settlement of hedging contracts

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Net Loss. For the three months ended December 31, 2006, we reported a net loss of approximately $422,000 or $0.02 loss per share on total oil and gas revenues of approximately $427,000, as compared to a net loss of $542,000 or $0.02 loss per share on total oil and gas revenues of $831,000 for the three months ended December 31, 2005.  The improvement in our net loss is attributable primarily to approximately $503,000 of interest income earned and no interest expense charged in the current quarter, versus approximately $15,000 of interest income earned and $191,000 of interest expense charged in the comparable quarter of the prior year.  Offsetting income were lower oil revenues of approximately $404,000 and higher operating costs (includes production expenses, production taxes, depletion expense and general and administrative costs) of approximately $133,000, all of which are explained in greater detail below.  In addition, for the period ended December 31, 2006, a loss on sale of asset (Delhi Field) was recorded for approximately $21,500 for the settlement of a sales and use tax audit.

Sales Volumes. Oil sales volumes, net to our interest, for the three months ended December 31, 2006 decreased 49% to 6,080 Bbls, compared to 11,828 Bbls for the three months ended December 31, 2005.  The decrease in oil sales volumes is primarily due to a loss of production from the Delhi Farmout, in addition to decreases in production from the Tullos Field area by approximately 19%.

Net natural gas volumes sold for the three months ended December 31, 2006 were zero due to the Delhi Farmout, as compared to 23,977 Mcfs for the three months ended December 31, 2005.

On a BOE basis, total sales volumes decreased 62% in the current quarter when compared to the prior year quarter.

Production. Oil production varies from oil sales volumes by changes in crude oil inventories, which are not carried on our balance sheet.  Net working interest oil production for the three months ended December 31, 2006 decreased 45% to 6,542 Bbls, compared to 11,860 Bbls for the three months ended December 31, 2005.  This is primarily due to the loss of production from the Delhi Farmout.  Net natural gas production for the three months ended December 31, 2006 decreased 100% to zero, compared to 23,977 Mcfs for the three months ended December 31, 2005, again due to the Delhi Farmout.

Oil and Gas Revenues. Revenues presented in the table above and discussed herein represent revenue from sales of our oil and natural gas production volumes, net to our interest.  Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts.  Realized prices may differ from market prices in effect during the periods, depending on when the fixed delivery contract was executed.

Oil and gas revenues decreased 49% for the three months ended December 31, 2006, compared to the same period in 2005, as a result of a 62% decrease in sales volumes (on a BOE basis) due primarily to the sale Delhi Farmout and slight decreases to sales in the Tullos Field area.  Offsetting the decrease in revenues was a 50% increase in net realized oil prices from approximately $47 per barrel to approximately $70 per barrel.

Lease Operating Expenses (including production severance taxes). Lease operating expenses for the three months ended December 31, 2006 decreased approximately 23% from the comparable 2005 period. The decrease in operating expenses in 2006 is primarily attributable to fewer operated wells due to the Delhi Farmout.  On a BOE basis, lease operating expenses increased during the quarter by 100% over the comparable 2005 quarter, primarily due to lower oil production at Tullos Field area due to required workovers on saltwater disposal wells and unusually high workover costs on those saltwater disposal wells as well as the sale of the Delhi production that had a lower LOE per barrel. In the current quarter, production in the Tullos Area was reduced due to three saltwater disposal wells temporarily shut down, including one for high water caused by heavy rain in the area.  The prior quarter’s high rate per BOE was due to uncharacteristically high workover costs and a corresponding reduction in production volumes at our Delhi Field.

General and Administrative Expenses (G&A). General and administrative expenses were up 45% to approximately $960,000 for the three months ended December 31, 2006, compared to approximately $662,000 for the three months ended December 31, 2006.  Higher non-cash stock compensation expense, and to a lesser extent increases to salary & wages for a new employee, accounted for the majority of the increase to G&A expenses in the current quarter.  Non-cash stock compensation expense was approximately $372,000 and $156,000 for the 2006 and 2005 three month periods, respectively.

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Depreciation, Depletion & Amortization Expense (DD&A). DD&A expense decreased approximately $68,000 to approximately $46,000 for the three months ended December 31, 2006 from $114,000 for the same period in 2005.  The decrease is primarily due to a lower depletion expense as a result of a 62% decrease in sales volumes (on a BOE basis) due to the Delhi Farmout and decreases to oil sales at Tullos Field area, offset by slight increases in the average depletion rate from $7.10 to $7.65 per BOE.

Interest Income. Interest income for the three months ended December 31, 2006 increased approximately $488,000 to approximately $503,000, compared to approximately $15,000 for the three months ended December 31, 2005.  The increase in interest income is primarily due to higher interest earned on higher available cash balances of approximately $40 million in the current quarter, as compared to cash of less than $500,000 in the prior comparable quarter.

Interest Expense. Due to the repayment of all of our debt in May 2006, interest expense for the three months ended December 31, 2006 decreased to zero from approximately $191,000 for the three months ended December 31, 2005.

Six months ended December 31, 2006 compared to six months ended December 31, 2005

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

		Six Months Ended
		December 31,
		2006			2005			Variance			% change
Sales Volumes, net to EPM:
Oil (Bbl)		13,775			20,794			(7,019		)	-34	%
Gas (Mcf)		0			33,827			(33,827		)	-100	%
Oil and Gas (Boe)		13,775			26,432			(12,657		)	-48	%
Revenue data (a):
Oil revenue		$	895,469		$	1,036,932		$	(141,463	)	-14	%
Gas revenue		0			336,888			(336,888		)	-100	%
Total oil and gas revenues		$	895,469		$	1,373,820		$	(478,351	)	-35	%
Average prices (a):
Oil (per Bbl)		$	65.01		$	49.87		$	15.14		30	%
Gas (per Mcf)		0			9.96			(9.96		)	-100	%
Oil and Gas (per Boe)		65.01			51.98			13.03			25	%
Expenses (per Boe)
Lease operating expenses and production taxes		$	49.50		$	34.01		$	15.49		46	%
Depletion expense on oil and gas properties		7.69			7.16			0.53			7	%

(a) Includes the cash settlement of hedging contracts

Net Loss. For the six months ended December 31, 2006, we reported a net loss of approximately $882,000 or $0.03 loss per share on total oil and gas revenues of approximately $895,000, as compared to a net loss of $1,342,000 or $0.05 loss per share on total oil and gas revenues of $1,374,000 for the six months ended December 31, 2005.  The improvement in our net loss is attributable primarily to approximately $1,034,000 of interest income earned and no interest expensed charged in the current quarter, versus approximately $34,000 of interest income earned and $413,000 of interest expense charged in the comparable period of the prior year.  Offsetting income were lower oil and gas revenues of approximately $479,000 and higher operating costs (includes production expenses, production taxes, depletion expense and general and administrative costs) of approximately $453,000, all of which are explained in greater detail below.  In addition, for the period ended December 31, 2006, a loss on sale of asset (Delhi Field) was recorded for approximately $21,500 for the settlement of a sales and use tax audit.

Sales Volumes. Oil sales volumes, net to our interest, for the six months ended December 31, 2006 decreased 34% to 13,775 Bbls, compared

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to 20,794 Bbls for the six months ended December 31, 2005.  The decrease in oil sales volumes is primarily due to a loss of production from the Delhi Farmout, in addition to decreases in oil production from the Tullos Field area by approximately 13%.

Net natural gas volumes sold for the six months ended December 31, 2006 were zero due to the Delhi Farmout, as compared to 33,827 Mcfs for the six months ended December 31, 2005.

On a BOE basis, total sales volumes decreased 48% in the current period when compared to the prior year period.

Production. Oil production varies from oil sales volumes by changes in crude oil inventories, which are not carried on our balance sheet.  Net working interest oil production for the six months ended December 31, 2006 decreased 13% to 14,144 Bbls, compared to 16,195 Bbls for the six months ended December 31, 2005.  This is primarily due to the loss of production from the Delhi Farmout.  Net natural gas production for the six months ended December 31, 2006 decreased 100% to zero, compared to 33,827 Mcfs for the six months ended December 31, 2005, again due to the Delhi Farmout.

Oil and Gas Revenues. Revenues presented in the table above and discussed herein represent revenue from sales of our oil and natural gas production volumes, net to our interest.  Production sold under fixed price delivery contracts, which have been designated for the normal purchase and sale exemption under SFAS 133, are also included in these amounts.  Realized prices may differ from market prices in effect during the periods, depending on when the fixed delivery contract was executed.

Oil and gas revenues decreased 35% for the six months ended December 31, 2006, compared to the same period in 2005, as a result of a 48% decrease in sales volumes (on a BOE basis) due primarily to the Delhi Farmout and decreases to sales in the Tullos Field area.  Offsetting the decrease in revenues was a 30% increase in net realized oil prices from approximately $50 per barrel to approximately $65 per barrel for the six months ended December 31, 2006.

Lease Operating Expenses (including production severance taxes). Lease operating expenses for the six months ended December 31, 2006 decreased approximately 24% from the comparable 2005 period. The decrease in operating expenses in 2006 is primarily attributable to fewer operated wells due to the Delhi Farmout.  On a BOE basis, lease operating expenses increased during the period by approximately 46% over the comparable 2005 period, primarily due to lower oil production at Tullos Field area due to required workovers on saltwater disposal wells and unusually high workover costs on those saltwater disposal wells as well as the sale of the Delhi production that had a lower LOE per barrel.   In the current period, production in the Tullos Area was reduced due to three saltwater disposal wells temporarily shut down, including one for high water caused by heavy rain in the area and the diversion of our only available service rig and crew from repair and maintenance to our capital program.  The prior quarter’s high rate per BOE was due to uncharacteristically high workover costs and a corresponding reduction in production volumes at our Delhi Field.

General and Administrative Expenses (G&A). General and administrative expenses increased approximately 60% to approximately $2,000,000 for the six months ended December 31, 2006, compared to approximately $1,246,000 for the six months ended December 31, 2006.  Higher non-cash stock compensation expense and increases to salary & wages for annual bonuses plus a new employee hire accounted for the majority of the increase to G&A expenses in the period.  Non-cash stock compensation expense was approximately $861,000 and $269,000 for the 2006 and 2005 six month periods, respectively.

Depreciation, Depletion & Amortization Expense (DD&A). DD&A expense decreased approximately $84,000 to approximately $108,000 for the six months ended December 31, 2006 from $192,000 for the same period in 2005.  The decrease is primarily due to a lower depletion expense as a result of a 48% decrease in sales volumes (on a BOE basis) due to the Delhi Farmout and decreases to oil sales at Tullos Field area, offset by slight increases in the average depletion rate from $7.16 to $7.69 per BOE.

Interest Income. Interest income for the six months ended December 31, 2006 increased approximately $1,000,000 to approximately $1,034,000, compared to approximately $34,000 for the six months ended December 31, 2005.  The increase in interest income is primarily due to higher interest income earned on higher available cash balances of approximately $40 million in the current period, as compared to cash of less than $500,000 in the prior comparable period.

Interest Expense. Due to the repayment of all of our debt in May 2006, interest expense for the six months ended December 31, 2006 decreased to zero from approximately $413,000 for the six months ended December 31, 2005.

Liquidity and Capital Resources

As of December 31, 2006, we had approximately $40 million of unrestricted cash, inclusive of approximately $34.7 million of cash that was transferred from the qualified intermediary (“QI”) account that was previously set up for possible Internal Revenue Code Section 1031 “like-kind exchanges”.  This transfer occurred in mid December, shortly after the expiration of the 1031 period.  In the quarter ended December 31, 2006, we used approximately $62,000 of 1031 “like-kind exchanges” funds to purchase tangible equipment.  Of the $12.4 million tax liability associated with the final disbursement from the QI account, 75% and 25% of this amount will be deposited with the U. S. Treasury on March 15, 2007 and June 15, 2007, respectively.  On a pro forma basis, following payment of our estimated federal income tax liability, our unrestricted cash position as of February 12, 2007 is approximately $28 million.

At December 31, 2006 we had approximately $28 million of positive working capital, as compared to $0.6 million of positive working capital

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at December 31, 2005.  Our working capital at December 31, 2006 included approximately $34.7 million of cash we withdrew from the QI account and the $12.4 million of current tax liability associated with such receipt.

Cash flow used by our operating activities was $4.3 million for the six months ended December 31, 2006, as compared to $0.8 million used during the comparable period ended December 31, 2005.  The primary expenditure in the 2006 period was a $3 million estimated federal income tax payment and a $0.66 million estimated state income tax payment to cover our prior fiscal year and the first quarter estimate for fiscal 2007.

Cash flow used by investing activities was approximately $148,000 for the six months ended December 31, 2006, net of approximately $34.7 million of cash transferred from the qualified intermediary account, which was closed in December 2006 due to the expiration of the “like-kind exchange” window. Approximately $185,000 was received for the sale of two Tullos Field Area wells to the State of Louisiana, offset by approximately $30,000 in legal fees to close the transaction.  Approximately $101,000 was used to acquire additional royalty and overriding royalty interests in the Delhi Holt Bryant Unit and a small parcel of land to be used as a field office in Tullos, Louisiana, and $222,000 was used to develop our oil and gas properties.  In the prior fiscal comparable period we used approximately $1.3 million to develop our properties, primarily related to the Development drilling program at our Delhi Field.

During the six months ended December 31, 2006, we incurred approximately $15,592 of costs related to filing registration statements for previous equity raising matters, as compared to approximately $6,800 to repay notes payable in the comparable 2005 period.

Going forward, we plan on using the majority of our after-tax cash resources to “seed” new development projects within our Initiatives I-III outlined in the Overview section above.  It is currently our intention to bring these projects through a proof of concept phase, followed by raising some form of insulated project financing specific to each project.

Off Balance Sheet Arrangements

Pursuant to the terms of our previous credit facility, we entered into financial instruments covering approximately 50% of our expected oil and gas production from proved developed producing properties on a two year rolling basis.  We used reserve report data prepared by W. D. Von Gonten & Co., our independent petroleum engineering firm, to estimate our future production for hedging purposes.  As we may elect under FAS 133, Accounting for Derivative Instruments and Hedging Activities, we have designated our physical delivery contracts as normal delivery sale contracts.  For the oil price floors (the “Puts”) we purchased, we have not fulfilled the documentation requirements of FAS 133.  As a result, the Put contracts are “marked-to-market”, with the unrealized gain or loss reflected in our statement of operations.  Since July 31, 2005, we had the following financial instruments in place:

(i)                                                       2,100 Bbls of oil to be delivered monthly from March 2005 through February 2006 to Plains Oil Marketing LLC, at $48.35 per barrel, plus or minus changes in basis between: (a) the arithmetic daily average of the prompt month “Light Sweet Crude Oil” contract reported by the New York Mercantile Exchange, and (b) Louisiana field posted price. This is accounted for as a normal delivery sales contract.  This contract was extended for the months of March 2006 through May 2006 for 70 Bbls of oil per day at a fixed price of $52.55 per barrel of oil, and extended again for the months of June 2006 through August 2006 for 90 Bbls of oil per day at a fixed price $63.45 per barrel of oil.  Lastly, on January 27, 2006 we extended our crude oil contracts with Plains Oil Marketing, LLC for an additional six months, covering the periods September 2006 through February 2007.  The contract requires us to deliver 90 Bbls of oil per day, in exchange for a fixed price of $69.30 per Bbl, plus or minus NYMEX to posted field price basis risk.  In the case of production shortfalls, the required barrels are purchased at the current market price per Plains Oil Marketing price bulletins.

(ii)                                                    100 Mcfd of natural gas at a fixed price of $6.21, delivered through our Delhi Field sales tap into Gulf South’s pipeline, for the account of Texla for deliveries from March 2005 to May 2006.  This is accounted for as a normal delivery sales contract.

(iii)                                                 Purchase of a non-physical Put contract at $38.00 per barrel for 2,000 Bbls of crude oil production from March 2006 through February 2007.  This is accounted for as a “mark-to-market” derivative investment.  As of December 2006, the market value of the Put contract was zero.

Non-GAAP Financial Measures

The United States Securities and Exchange Commission has adopted disclosure requirements for public companies concerning Non-GAAP financial measures. GAAP refers to generally accepted accounting principles. We must reconcile the Non-GAAP financial measure to related GAAP information.

Earnings before tax, depreciation and amortization

Earnings before tax, depreciation and amortization, EBTDA, is a Non-GAAP financial measure. We believe EBTDA is relevant because it is a proxy for cash generated by operations to fund our available capital programs, while taking into account the significant (i) non cash charges in our income statement, mostly due to non-cash stock compensation expense (ii) net interest income generated in some periods, versus net interest expense incurred in other periods and (iii) non-taxable income in some periods versus tax liabilities arising from gain on sale of assets in other periods. EBTDA should not be considered in isolation from or as a substitute for net income, as an indication of operating performance or cash flows from operating activities or as a measure of liquidity. EBTDA and as we calculate it, may not be comparable to EBTDA measures reported by other companies. In addition, EBTDA does not represent funds available for discretionary use.  A reconciliation of our consolidated net income to EBTDA is as follows:

RECONCILIATION TO GAAP INFORMATION

		Six Months Ended December 31, 2006			Six Months Ended December 31, 2005
Net Loss (GAAP)		$	(881,693	)	$	(1,341,943	)
Depreciation, depletion, amortization and other non-cash charges excluding deferred income taxes		978,074			655,507
Income Tax expense		0			0
Earnings before tax, depreciation and amortization (Non-GAAP)		$	96,381		$	(686,436	)

 

 

ITEM 3. 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. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

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 the Company’s Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the quarter covered by this report. Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that 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.

There has been no change in our internal control over financial reporting during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1.  LITIGATION

On October 11, 2006 Sybil  J. Dominique, Individually, et al., filed a lawsuit in the District Court of Dallas County Texas, against Amerada Hess Corporation and 73 other defendants, including one of our subsidiaries, Arkla Petroleum, LLC (“Subsidiary”) alleging workplace exposure to benzene caused the death of her spouse.  We were served notice of the lawsuit on October 31, 2006.  On January 5, 2007, the plaintiffs filed a Notice of Nonsuit without Prejudice, thereby dismissing us from the suit.

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

During the quarter ended December, 31, 2006, the Company entered into an amended consulting agreement with Liviakis Financial Communications, Inc. whereby the consultant continues to provide investor relations services for the Company.  For this, the Company agreed to issue to the consultant an aggregate of 50,000 shares of common stock, which is subject to monthly vesting, over a twelve month period.  The effective date of the agreement is November 1, 2006.  The Company issued the shares in reliance on the exemption afforded by Section 4(2) under the Securities Act of 1933, as amended, based on representations, warranties and agreements made by the consultant in the consulting agreement.

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

The following matters were submitted to a vote of security holders during Evolution Petroleum’s Annual Meeting of Stockholders held on December 6, 2006:

1.               Election of Directors — The following nominees were elected to serve as Directors of Evolution Petroleum Corporation until the 2007 Annual Meeting of Stockholders:

 

No other person received any votes.

2.               Ratification of the appointment of Hein & Associates LLP, as independent accountants of the Company for the fiscal year ending June 30, 2007.  The voting was as follows:

 

ITEM 6. EXHIBITS

A.           Exhibits

10.1                           Third Amendment to Consulting Agreement between Liviakis Financial Communications, Inc. and Evolution Petroleum dated November 14, 2006.

31.1                           Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.

31.2                           Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.

32.1                           Certification of Chief Executive Officer pursuant Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended and 18 U.S.C. Section 1350.

32.2                           Certification of Chief Financial Officer pursuant Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended and 18 U.S.C. Section 1350.

 

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