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 March 31, 2007

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

For the transition period                      to                     

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of small business issuer as specified in its charter)

 

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

(Address of principal executive offices and zip code)

(713) 935-0122

(Issuer’s telephone number, including area code)

820 Gessner, Suite 1340, Houston, Texas 77024

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

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past
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 is a shell company (as defined in Rule 12b-2 of the Exchange Act.).  Yes: o  No: x

APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY

PROCEEDINGS DURING THE PRECEDING FIVE YEARS

Check whether the registrant filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Exchange Act after the distribution of securities under a plan confirmed by a court.  Yes: o No: o

APPLICABLE ONLY TO CORPORATE ISSUERS

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date:

The number of shares outstanding of the Registrant’s common stock, par value $0.001, as of May 9, 2007, was 26,759,239.

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

EVOLUTION PETROLEUM CORPORATION, INC.

TABLE OF CONTENTS

				Page
PART I. FINANCIAL INFORMATION
ITEM 1.		FINANCIAL STATEMENTS
		Condensed Consolidated Balance Sheets: March 31, 2007 (unaudited) and June 30, 2006		3
		Condensed Consolidated Statements of Operations (unaudited): For the three and nine months ended March 31, 2007 and 2006		4
		Condensed Consolidated Statements of Cash Flows (unaudited): For the nine months ended March 31, 2007 and 2006		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		18
PART II. OTHER INFORMATION
ITEM 1.		LEGAL PROCEEDINGS		19
ITEM 6.		EXHIBITS		19
SIGNATURES				20

 

2

PART I - FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries

Condensed Consolidated Balance Sheets

		March 31,			June 30,
		2007			2006
		(unaudited)
Assets
Current Assets:
Cash and cash equivalents		$	32,273,816		$	9,893,547
Accounts receivable, trade		168,797			132,371
Inventories		219,518			76,917
Prepaid expenses		112,797			157,629
Retainers and deposits		106,625			60,895
Total current assets		32,881,553			10,321,359
Cash in qualified intermediary account for “like-kind” exchanges		—			34,662,368
Oil & Gas properties - full cost		4,093,446			3,878,551
Oil & Gas properties - not amortized		344,989			52,098
Less: accumulated depletion		(531,374		)	(371,624		)
Net oil & gas properties		3,907,061			3,559,025
Furniture, fixtures and equipment, at cost		86,874			16,561
Less: accumulated depreciation		(13,041		)	(7,998		)
Net furniture, fixtures, and equipment		73,833			8,563
Restricted deposits		301,835			326,835
Other assets		75,116			79,808
Total assets		$	37,239,398		$	48,957,958
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$	302,839		$	310,272
Accrued liabilities		152,725			473,782
Income taxes payable		4,820,000			2,978,650
Royalties payable		6,713			47,054
Total current liabilities		5,282,277			3,809,758
Long term liabilities:
Deferred income taxes payable		—			13,101,350
Deferred rent payable		11,822			—
Asset retirement obligations		136,453			123,679
Total liabilities		5,430,552			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,  26,407,906 and 26,300,664, issued and outstanding as of March 31, 2007 and June 30, 2006, respectively, net of 351,333 shares of common stock subject to demand registration rights		26,408			26,300
Additional paid-in capital		11,311,427			10,274,555
Deferred stock based compensation		(80,194		)	(265,167		)
Retained earnings		19,760,705			21,096,983
Total stockholders’ equity		31,018,346			31,132,671
Total liabilities and stockholders’ equity		$	37,239,398		$	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						Nine Months Ended
		March 31,						March 31,
		2007			2006			2007			2006
Revenues:
Oil sales		$	462,951		$	801,036		$	1,358,433		$	1,844,870
Gas sales		—			83,730			—			420,618
Price risk management activities		—			(6,164		)	(14		)	(13,066		)
Total revenues		462,951			878,602			1,358,419			2,252,422
Operating Costs:
Production expenses		400,408			506,093			1,052,001			1,368,967
Production taxes		13,957			40,936			44,260			76,956
Depreciation, depletion and amortization		56,572			132,366			164,793			324,047
General and administrative *		934,055			593,271			2,933,761			1,839,655
Total operating costs		1,404,992			1,272,666			4,194,815			3,609,625
Loss from operations		(942,041		)	(394,064		)	(2,836,396		)	(1,357,203		)
Other income and expense:
Interest income		487,456			7,626			1,521,570			41,517
Interest expense		—			(221,694		)	—			(634,388		)
Gain/(loss) on sale of assets		—			—			(21,453		)	—
Total other income and expense		487,456			(214,068		)	1,500,117			(592,871		)
Net Loss		$	(454,585	)	$	(608,132	)	$	(1,336,279	)	$	(1,950,074	)
Net Loss per common share
Basic and Diluted		$	(0.02	)	$	(0.02	)	$	(0.05	)	$	(0.08	)
Weighted average number of common shares
Basic and Diluted		26,720,444			25,309,557			26,685,612			24,864,403

 

See accompanying notes to condensed consolidated financial statements.

* Includes non-cash stock compensation expense of $376,008, $112,034, $1,237,485 and $381,385 for the three month period ended March 31, 2007 and 2006, and the nine month period ended March 31, 2007 and 2006, respectively.

4

---

Evolution Petroleum Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flow

(unaudited)

		Nine Months			Nine Months
		Ended March			Ended March
		31, 2007			31, 2006
Cash flows from operating activities:
Net loss		$	(1,336,279	)	$	(1,950,074	)
Adjustments to reconcile net loss to net cash used by operating activities:
Depletion and Depreciation		164,793			324,047
Non-cash stock based compensation expense		1,237,485			381,385
Accretion of asset retirement obligations		12,774			21,391
Deferred rent payable		11,822			—
Accretion of debt discount and non-cash loan costs		—			156,664
Other non-cash items		—			34,727
Non-cash penalty expense		—			240,000
Changes in assets and liabilities:
Accounts receivable		(36,426		)	33,098
Inventories		(142,601		)	(125,755		)
Retainer and deposits		(45,730		)	—
Accounts payable		(7,433		)	325,586
Royalties payable		(40,340		)	11,866
Accrued liabilities		(321,056		)	(55,378		)
Income taxes and deferred income taxes payable		(11,260,000		)	—
Prepaid expenses		44,832			(30,524		)
Net cash used in operating activities		(11,718,159		)	(632,967		)
Cash flows from investing activities:
Development of oil and gas properties		(267,245		)	(3,082,106		)
Acquisition of oil and gas properties		(395,918		)	—
Proceeds from asset sale, net		155,378			—
Capital expenditures for furniture, fixtures and equipment		(70,313		)	(3,004		)
Cash transferred from qualified intermediary account		34,662,368			—
Restricted deposits		25,000			176,385
Other assets		4,692			17,716
Net cash provided in investing activities		34,113,962			(2,891,009		)
Cash flow from financing activities:
Payments on notes payable		—			(6,754		)
Proceeds from notes payable		—			1,040,764
Proceeds from issuance of common stock		57			—
Deferred financing costs		—			(22,654		)
Equity proceeds and transaction costs		(15,591		)	171,763
Net cash provided by (used in) financing activities		(15,534		)	1,183,119
Net increase (decrease) in cash and cash equivalents		22,380,269			(2,340,857		)
Cash and cash equivalents, beginning of period		9,893,547			2,548,688
Cash and cash equivalents, end of period		$	32,273,816		$	207,831
Supplemental disclosure of cash flow information:
Interest paid		$	—		$	443,229
Income taxes paid		$	11,260,000		$	—
Non cash equity adjustment		$	—		$	50,000

 

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 March 31, 2007, 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.  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 and in order to make the financial statements not misleading 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. Net Loss per Share

Basic earnings (loss) 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 (loss) 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 (loss) 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.

6

---

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

		Three Months Ended March 31,						Nine Months Ended March 31,
		2007			2006			2007			2006
Numerator:
Net loss, as reported		$	(454,585	)	$	(608,132	)	$	(1,336,279	)	$	(1,950,074	)
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 applicable to common stockholders plus assumed conversions		$	(454,585	)	$	(608,132	)	$	(1,336,279	)	$	(1,950,074	)
Denominator:		26,720,444			25,039,557			26,685,612			24,864,403
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		26,720,444			25,039,557			26,685,612			24,864,403
Net Loss per common share:
Basic and diluted		$	(0.02	)	$	(0.02	)	$	(0.05	)	$	(0.08	)

 

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 31, 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 30, 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 March 31, 2007.

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.  On January 5, 2007, the plaintiffs filed a Notice of Nonsuit without Prejudice, thereby dismissing us from the suit.

7

---

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 nine months ended March 31, 2007 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 nine months ended March 31, 2007 of approximately $376,000 and $1,238,000, respectively.   Stock compensation expense is 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 and $0.05, respectively for the three and nine months ended March 31, 2007.  For the nine month period ended March 31, 2007, 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.

For the three months ended March 31, 2007, there were no stock options granted.

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 and directors 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 Nine Months Ended March 31, 2006

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 nine months ended March 31, 2006.

		Three Months			Nine Months
		Ended March 31,			Ended March 31,
		2006			2006
Net loss, as reported		$	(608,132	)	$	(1,950,074	)
Add: Total stock based employee compensation benefit reported in net loss		27,328			144,208
Deduct: Total stock based employee compensation benefit determined under fair value of all awards		(567,826		)	(1,196,257		)
Pro forma net loss		$	(1,148,630	)	$	(3,002,123	)
Per share data:
Basic and diluted, as reported		$	(0.02	)	$	(0.08	)
Basic and diluted, pro forma		$	(0.05	)	$	(0.12	)

 

The fair values of options and warrants granted during the three and nine months ended March 31, 2007 and 2006 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 2007 and 2006:

		Three Months Ended				Nine Months Ended
		March 31				March 31
		2007		2006		2007		2006
Weighted average volatility		—		150	%	163	%	147	%
Expected term (in years)		—		4.0		6.25		3.6
Risk-free rate		—		4.5	%	4.8	%	4.5	%

 

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 March 31, 2006 was $1.24.  The weighted average grant-date fair value of options granted during the nine months ended March 31, 2007 and 2006 was $2.61 and $1.15, respectively.  There have been no options or warrants exercised for the three and nine months ended March 31, 2007 and 2006.

8

---

Stock Options and Warrants as of the Three and Nine Months Ended March 31, 2007

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 March 31, 2007, 1,286,758 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 nine months ended March 31, 2007, no warrants were granted and no warrants have been exercised.  As of March 31, 2007, 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 nine months ended March 31, 2007:

		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 March 31, 2007		3,948,500		$	1.54		$	4,000,810		8.0
Options and warrants exercisable at March 31, 2007		2,122,250		$	1.34		$	2,579,079		7.9

 

(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 options or warrants.

A summary of the status of our non-vested options and warrants as of March 31, 2007, and the changes during the nine months ended March 31, 2007, is presented below:

		Number of Options and Warrants		Weighted Average Grant- Date Fair Value
Non-vested at July 1, 2006		2,335,532		$	1.66
Granted		150,000		$	2.61
Vested		(678,032	)
Canceled, forfeited, or expired		0
Non-vested at end of period		1,807,500		$	1.53

 

At March 31, 2007, unrecognized stock based compensation expense related to non-vested stock option and warrant grants totaled approximately $2.5 million.  This unrecognized expense will be amortized on a straight-line basis per grant over a weighted average remaining life of approximately 2.3 years.

Restricted Stock for the period ended March 31, 2007

For the three months ended March 31, 2007, no new restricted stock awards were granted.  However, the Company issued 57,242 shares of common stock pursuant to the stock grants described in the next paragraph.   We recognize compensation expense over the vesting period of these shares.  During the three and nine months ended March 31, 2007, we recognized aggregate compensation expense of $40,543 and $54,090, respectively, related to these outstanding restricted stock grants.

9

---

On October 5, 2006, we granted 20,000 shares of restricted stock with a grant date fair value of $2.71 per share to a new employee as a sign on bonus.  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 recognize compensation expense over the vesting period of these shares.

The following table sets forth the restricted stock transactions for the nine months ended March 31, 2007:

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

 

(1) The weighted average grant date fair value of restricted stock granted for the nine months ended March 31, 2007 was $2.83.  The weighted average grant date fair value of restricted stock granted for the nine months ended December 31, 2005 was $1.61.

At March 31, 2007, unrecognized stock compensation expense related to restricted stock totaled approximately $108,000.  Such unrecognized expense will be recognized as vesting occurs over a weighted average period of 0.7 years.

6.  Common Stock

During the quarter ended March 31, 2007, we issued 20,000 shares of common stock to an employee as part of an incentive compensation package for employment.  Also, three outside directors each received 12,414 shares of common stock as part of a revised compensation plan for directors.  All issuances of common stock are subject to vesting terms per individual stock agreements.

During the quarter ended December, 31, 2006, we 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.

As a result of the private placement of 351,333 of our common shares at $2.25 during fiscal 2006, we became subject to a registration rights agreement requiring us to use our reasonable efforts to register these shares subsequent to the demand of 40% of the holders of such stock.  Such demand cannot become effective, however, until the price of our common stock exceeds at least $14.23 per share, which has not occurred.  There are no specified damages for our failure to register, nor a specified timetable for obtaining such registration, except that the registration shall be undertaken by us as soon as practicable and shall stay effective for 120 days, or if such registration statement is on Form S-3 and provides for sales of securities from time to time pursuant to Rule 415 under the Securities Exchange Act of 1934, for up to one year.  The demand registration rights will terminate when a holder is able to sell all its shares during any three month period under Rule 144, which we believe should occur sometime between the first and second anniversary dates from the June 10, 2006 closing of the offering.  Based on the terms of this registration rights agreement, we have recorded the $790,500 of proceeds as temporary equity.

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

10

---

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 February 28, 2007, all of the Company’s commodity hedging and price risk management activities had expired and were not renewed.

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 amended in November 2005, providing for a retainer of $5,000 per month. In addition, Mr. Cagan, as a registered representative of Chadbourn Securities Inc. (“Chadbourn”) and a partner of CMCP, has served as the Company’s placement agent in private equity financings.  Under the current agreement, CMCP may earn 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.

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

During the three months ended March 31, 2007, we expensed and paid CMCP $15,000 in monthly retainers.  There were no other earned fees by CMCP.

During the nine months ended March 31, 2007, we expensed and paid CMCP $45,000 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 March 31, 2007 is as follows:

Asset retirement obligation at June 30, 2006		$	123,679
Liabilities incurred		—
Liabilities settled		—
Accretion expense		12,774
Asset retirement obligation at March 31, 2007		$	136,453

 

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

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 for the year ended June 30, 2006 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.

11

---

Critical Accounting Policies

Except as noted below, our 2006 Annual Report on Form 10-KSB describes the accounting policies that we believe are critical to the reporting of our financial position and operating results and that require management’s most difficult, subjective or complex judgments.

At March 31, 2007, Management believes that 1) estimates for Asset Retirement Obligations are not critical accounting polices, due to their insignificance to our overall financial position, 2) estimates for the Fair Value of Debt and Equity Transactions are not critical accounting polices, since they are not subject to wide valuation differences and no such transactions currently exist in our balance sheet, and 3) the italicized insertion to the following will add additional clarity to our critical policy for the full cost method of accounting: “Under the rules of the Securities and Exchange Commission (“SEC”) for the full cost method of accounting, the net carrying value of oil and natural gas properties is limited to the sum of the present value (10% discount rate) of the estimated future net cash flows from proved reserves, net of estimated future expenditures to be incurred in developing and producing the proved reserves, based on current prices as of the balance sheet date, and excluding future cash outflows associated with setting asset retirement obligations, plus the lower of cost or estimated fair market value of unproved properties adjusted for related income tax effects.”

This Quarterly Report on Form 10-QSB should be read in conjunction with the discussion contained in our 2006 Annual Report on Form 10-KSB regarding these critical accounting policies.

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 March 31, 2007, we conducted operations through our 100% working interests in the Tullos Field Area and our non-operated interests in the Delhi Field, all located onshore in Louisiana.  The Tullos Field Area consists of approximately 155 producing wells out of 267 well bores across approximately 599 acres with high water-cut oil 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 interests in the Delhi Field Holt Bryant Unit, a 25% reversionary working interest in the Delhi Field Holt Bryant Unit, and a 25% working interest in certain other depths in the Delhi Field.  Our 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 a portion of 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.

 

Having reached a major milestone in executing on our EOR Initiative I with the June 2006 closing of our Delhi Farmout, we are currently engaged in implementing additional development opportunities across our three initiatives, as more fully described below.

Summary Results

Financial Summary

As has been evident over the last three quarters, we continue to be a markedly stronger company as compared to one year earlier.

At March 31, 2007, our working capital, predominately cash & cash equivalents, was approximately $28 million and we continued to be debt free.  This compares to negative working capital of $3.9 million at March 31, 2006, which included approximately $3.8 million of short-term debt net of a $1.2 million capitalized discount for warrants issued to the lender.

As a proxy for cash flow from operations to fund capital programs, EBDDA (Earnings before, depletion, depreciation, amortization, non-cash stock compensation expense and other non-cash charges) is dramatically improved.  EBDDA is a non-GAAP measure which includes the effect of our net interest income, net interest expense and income tax expense across comparable periods, as reconciled to GAAP and explained further at the end of this Item 2 below.

EBDDA was approximately $91,000 for the nine months ended March 31, 2007, as compared to approximately $(792,000) in the comparable 2006 period.  The improvement was due mostly to interest earned from our approximately $40 million in average short term investments, combined with an approximate $634,000 reduction in interest expense during the current nine month period, as compared to the comparable 2006 period.

For the nine months ended March 31, 2007, our net loss decreased 31% from the comparable prior period to approximately $1.3 million, of which approximately $1.2 million was due to non-cash stock compensation expense recorded in accordance with SFAS 123(R).  For the nine months ended March 31, 2006, our net loss was approximately $2 million, of which approximately $381,000 was due to non-cash stock compensation expense recorded under APB 25.

All of these improvements are a direct result of the Delhi Farmout that we completed in June 2006, net of the associated loss of our Delhi oil and gas production.

12

---

Looking ahead, in the short term we can expect that our cash flow from operations and EBDDA will be adversely affected by reduced interest income on approximately $11.3 million of cash balances we have already remitted for income tax payments, and approximately $4.8 million we expect to remit on June 15, 2007 for income tax payments related to the Delhi Farmout, up to $6 million of  expenditures we have budgeted to acquire leasehold interests in our seven new projects currently underway, and development expenditures to bring these projects to fruition.  We anticipate that these adverse impacts should be increasingly offset by revenues from our new projects as, if and when they become operational.

Operational Summary

The operator of our Initiative I CO2-EOR project in the 13,626 acre Delhi Holt Bryant Unit has publicly announced that they expect CO2 injection will begin in 2008.  We continue to view the operator’s announcements as positive developments for our shareholders.

As reported to you in our last fiscal quarter, we continue to focus our personnel and approximately $28 million of unrestricted cash resources (net of $4.8 million of income taxes payable at March 31, 2007) on additional Initiative I, II and III projects, seven of which are currently underway.  Of these projects, five qualify as Initiative II - Bypassed Resource plays and two qualify as Initiative III — Unconventional Gas Resource plays.

Leasing in four of our five Initiative II Bypassed Resource plays has been in motion since December 2006.  We already own the fifth Initiative II project in our Tullos Urania Field Area.  Leasing in our two Initiative III Unconventional Gas Resource plays did not begin until after March 31, 2007, and therefore are not reflected in our results.

During our current fiscal year, we have expended approximately $295,000 on leasehold acquisition costs related to these new projects, about 90% of which occurred in the quarter ended March 31, 2007.  Over 90% of these leasehold costs were expended on Initiative II projects, as our Initiative III projects were only recently approved by our Board of Directors for leasing.  Since all of our Initiative II projects are adjacent to current or past offsetting production, we are targeting specific well site locations, which we believe may provide us the opportunity to acquire proved or high quality unproved resources upon leasing the parcels necessary to establish each drilling unit.  It is our intention to begin a development drilling program on this acreage around the end of this calendar year, with the objective of adding proved producing reserves to fill in the period prior to our expected Delhi EOR production ramp-up.

Concerning the Initiative II Bypassed Resource project underway at our Tullos Urania Field Area, we attempted a re-entry into an existing well during March 2007 to test a production/completion method which we believe could have wide applicability to increasing production and ultimate recoveries for heavy oil reservoirs overlying large volumes of water.  The age and condition of the well casing were not adequate to allow a useful test of the technology; therefore, we have elected to test the technology on a newly drilled well prior to calendar year end.  If successful, we see broad application for this method across other oil fields exhibiting similar formation and production characteristics, in addition to its application to the Tullos Urania Area property we already own.

In late April our Board authorized us to proceed with leasehold acquisitions of two Initiative III - Unconventional Gas Resource plays.  In contrast to our current Initiative II – Bypassed Resource plays, these projects require the acquisition of large, fairly contiguous land parcels containing the targeted reservoir rock that is an extension of, but not adjacent to or offsetting, existing production.  Consequently, we expect the development of these properties will require more time to develop than the Initiative II projects currently underway.

With respect to new Initiative I – EOR plays, we continue to screen projects for acquisition.

As previously forecast, BOE sales have declined in the current period.  For the nine months ended March 31, 2007, BOE sales declined 51%, as compared to the comparable 2006 period.  This was due mostly to production lost through the Delhi Farmout, as we had expected for the near term.  Production at our Tullos Urania Field Area also declined 14% during this period, primarily due to three saltwater disposal wells temporarily shut-in for casing leaks or high water caused by heavy rain in the area, as well as the diversion of our only available service rig and crew from repair and maintenance to our capital program.

Over the past six months, we have begun expanding our operating team to carry out our emerging development drilling projects.  To accommodate this growth and future growth, in March 2007 we leased approximately 8,000 square feet of corporate office space for nine years under a sublease.  The terms of the sublease include rent at about 65% of the current market rate for direct lease property in the same building, located in the Energy Corridor.

Looking forward, we continue to focus our staff and our significant cash resources on executing the Initiative I, II and III projects described above.  It remains our intention to commit most of these cash resources to “seed” these new projects through a “proof of concept” stage, followed by outside financing in the form of insulated project financing to complete each development stage with minimal shareholder dilution.

13

Results of Operations

Three months ended March 31, 2007 compared to three months ended March 31, 2006

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

		Three Months Ended
		March 31,									%
		2007			2006			Variance			change
Sales Volumes, net to EPM:
Oil (Bbl)		7,164			14,496			(7,332		)	-51	%
Gas (Mcf)		—			10,003			(10,003		)	-100	%
Oil and Gas (Boe)		7,164			16,163			(8,999		)	-56	%
								—
Revenue data (a):								—
Oil revenue		$	462,951		$	794,872		$	(331,921	)	-42	%
Gas revenue		—			83,730			(83,730		)	-100	%
Total oil and gas revenues		$	462,951		$	878,602		$	(415,651	)	-47	%
Average prices (a):
Oil (per Bbl)		$	64.62		$	54.83		$	9.79		18	%
Gas (per Mcf)		—			8.37			(8.37		)	-100	%
Oil and Gas (per Boe)		$	64.62		$	54.36		$	10.26		19	%
Expenses (per Boe)
Lease operating expenses and production taxes		$	57.84		$	33.84		$	24.00		71	%
Depletion expense on oil and gas properties		$	7.81		$	8.12		$	(0.31	)	-4	%

 

(a) Includes the cash settlement of hedging contracts

Net Loss. For the three months ended March 31, 2007, we reported a net loss of approximately $455,000 or $0.02 loss per share on total oil and gas revenues of approximately $463,000, as compared to a net loss of $608,000 or $0.02 loss per share on total oil and gas revenues of $879,000 for the three months ended March 31, 2006.  The improvement in our net loss is attributable primarily to approximately $488,000 of interest income earned and no interest expense charged in the current quarter, versus approximately $8,000 of interest income earned and $222,000 of interest expense charged in the comparable quarter of the prior year.  Offsetting income were lower oil and gas revenues primarily due to the Delhi Farmout and higher operating costs (includes production expenses, production taxes, depletion expense and general and administrative costs) of approximately $132,000, all of which are explained in greater detail below.

Sales Volumes.  Oil sales volumes, net to our interest, for the three months ended March 31, 2007 decreased 51% to 7,164 Bbls, compared to 14,496 Bbls for the three months ended March 31, 2006.  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 18%.

Net natural gas volumes sold for the three months ended March 31, 2007 were zero due to the Delhi Farmout, as compared to 10,003 Mcfs for the three months ended March 31, 2006.

On a BOE basis, total sales volumes decreased 56% 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 March 31, 2007 decreased 52% to 6,610 Bbls, compared to 13,890 Bbls for the three months ended March 31, 2006.  This was primarily due to the loss of production from the Delhi Farmout.  Net natural gas production for the three months ended March 31, 2007 decreased 100% to zero, compared to 10,003 Mcfs for the three months ended March 31, 2006, 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 47% for the three months ended March 31, 2007, compared to the same period in 2006, as a result of a 56% decrease in sales volumes (on a BOE basis) due primarily to the Delhi Farmout and a slight decrease in sales in the Tullos Field area.  Offsetting the decrease in revenues was an 18% increase in net realized oil prices from approximately $55 per barrel to approximately $65 per barrel.

14

---

Lease Operating Expenses (including production severance taxes).  Lease operating expenses for the three months ended March 31, 2007 decreased approximately 24% from the comparable 2006 period. The decrease in operating expenses in 2007 is primarily attributable to fewer operated wells due to the Delhi Farmout.  On a BOE basis, lease operating expenses increased during the quarter by 71% over the comparable 2006 quarter, primarily due to lower oil production at Tullos Field area resulting from 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 for casing leaks and 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 57% to approximately $934,000 for the three months ended March 31, 2007, compared to approximately $593,000 for the three months ended March 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 $376,000 and $112,000 for the 2007 and 2006 three month periods, respectively.

Depreciation, Depletion & Amortization Expense (DD&A).  DD&A expense decreased approximately $76,000 to approximately $57,000 for the three months ended March 31, 2007 from $132,000 for the same period in 2006.  The decrease is primarily due to a lower depletion expense as a result of a 56% decrease in sales volumes (on a BOE basis) due to the Delhi Farmout and decreases to oil sales at Tullos Field area and a slight decrease in the average depletion rate from $8.12 to $7.81per BOE.

Interest Income. Interest income for the three months ended March 31, 2007 increased approximately $480,000 to approximately $488,000, compared to approximately $8,000 for the three months ended March 31, 2006.  The increase in interest income is primarily due to higher interest earned on higher available cash balances of approximately $40,000,000 during most of the current quarter, as compared to average cash of approximately $248,000 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 March 31, 2007 decreased to zero from approximately $222,000 for the three months ended March 31, 2006.

Nine months ended March 31, 2007 compared to nine months ended March 31, 2006

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

		Nine Months Ended
		March 31,									%
		2007			2006			Variance			change
Sales Volumes, net to EPM:
Oil (Bbl)		20,939			35,277			(14,338		)	-41	%
Gas (Mcf)		—			43,962			(43,962		)	-100	%
Oil and Gas (Boe)		20,939			42,604			(21,665		)	-51	%
								—
Revenue data (a):								—
Oil revenue		$	1,358,419		$	1,831,804		$	(473,385	)	-26	%
Gas revenue		—			420,618			(420,618		)	-100	%
Total oil and gas revenues		$	1,358,419		$	2,252,422		$	(894,003	)	-40	%
Average prices (a):
Oil (per Bbl)		$	64.88		$	51.93		$	12.95		25	%
Gas (per Mcf)		—			9.57			(9.57		)	-100	%
Oil and Gas (per Boe)		$	64.88		$	52.87		$	12.01		23	%
Expenses (per Boe)
Lease operating expenses and production taxes		$	52.35		$	33.94		$	18.42		54	%
Depletion expense on oil and gas properties		$	7.73		$	7.52		$	0.21		3	%

 

(a) Includes the cash settlement of hedging contracts

 

15

---

Net Loss. For the nine months ended March 31, 2007, we reported a net loss of approximately $1,336,000 or $0.05 loss per share on total oil and gas revenues of approximately $1,358,000, as compared to a net loss of $1,950,000 or $0.08 loss per share on total oil and gas revenues of $2,252,000 for the nine months ended March 31, 2006.  The improvement in our net loss is attributable primarily to approximately $1,522,000 of interest income earned and no interest expensed charged in the current quarter, versus approximately $42,000 of interest income earned and $634,000 of interest expense charged in the comparable period of the prior year.  Offsetting income were lower oil and gas revenues of approximately $894,000 and higher operating costs (includes production expenses, production taxes, depletion expense and general and administrative costs) of approximately $585,000, all of which are explained in greater detail below.  In addition, for the nine month period ended March 31, 2007, 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 nine months ended March 31, 2007 decreased 41% to 20,939 Bbls, compared to 35,277 Bbls for the nine months ended March 31, 2006.  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 14%.

Net natural gas volumes sold for the nine months ended March 31, 2007 were zero due to the Delhi Farmout, as compared to 43,962 Mcfs for the nine months ended March 31, 2006.

On a BOE basis, total sales volumes decreased 51% 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 nine months ended March 31, 2007 decreased 43%% to 20,754 Bbls, compared to 36,390 Bbls for the nine months ended March 31, 2006.  This is primarily due to the loss of production from the Delhi Farmout.  Net natural gas production for the nine months ended March 31, 2007 decreased 100% to zero, compared to 43,962 Mcfs for the nine months ended March 31, 2006, 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 40% for the nine months ended March 31, 2007, compared to the same period in 2006, as a result of a 51% 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 25% increase in net realized oil prices from approximately $52 per barrel to approximately $65 per barrel for the nine months ended March 31, 2007.

Lease Operating Expenses (including production severance taxes).  Lease operating expenses for the nine months ended March 31, 2007 decreased approximately 24% from the comparable 2006 period. The decrease in operating expenses 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 54% over the comparable 2006 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 for high water caused by heavy rain in the area as well as 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 59% to approximately $2,934,000 for the nine months ended March 31, 2007, compared to approximately $1,840,000 for the nine months ended March 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 $1,238,000 and $381,000 for the 2007 and 2006 nine month periods, respectively.

Depreciation, Depletion & Amortization Expense (DD&A).  DD&A expense decreased approximately $159,000 to approximately $165,000 for the nine months ended March 31, 2007 from $324,000 for the same period in 2006.  The decrease is primarily due to a lower depletion expense as a result of a 51% 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 $7.52 to $7.73 per BOE.

Interest Income. Interest income for the nine months ended March 31, 2007 increased approximately $1,480,000 to approximately $1,522,000 compared to approximately $42,000 for the nine months ended March 31, 2006.  The increase in interest income is primarily due to higher interest income earned on higher available cash balances of approximately $40,000,000 in the current period, as compared to cash averaging approximately $1,000,000 in the prior comparable period.

Interest Expense. Due to the repayment of all of our debt in May 2006, interest expense for the nine months ended March 31, 2007 decreased to

16

---

zero from approximately $634,000 for the nine months ended March 31, 2006.

Liquidity and Capital Resources

At March 31, 2007, we had approximately $27.6 million of positive working capital, as compared to $3.9 million of negative working capital at March 31, 2006.  Our working capital at March 31, 2007 includes approximately $32 million of cash equivalents and approximately $4.8 million of remaining tax liabilities arising from the Delhi Farmout.

Cash flow used by our operating activities for the nine months ended March 31, 2007 was $11.7 million, as compared to $0.6 million used during the comparable period ended March 31, 2006.  Of the $11.7 million used in the current nine month period, $11.3 million was used to pay estimated federal and state income tax deposits related to the $50 million of proceeds we received from the Delhi Farmout in June 2006.

Cash flow used by investing activities for the nine months ended March 31, 2007 was approximately $0.5 million, 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 as required by the Revenue Service. 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 $396,000 was used to acquire new leases, acquire additional royalty and overriding royalty interests in the Delhi Holt Bryant Unit, acquire a small parcel of land to be used as a field office in Tullos, Louisiana and for land broker fees, while approximately $267,000 was used to develop our oil and gas properties.  In the prior fiscal comparable period we used approximately $3.1 million to develop our properties, primarily related to the 2005 Development Drilling Program at our Delhi Field.

Cash flow used by financing activities for the nine months ended March 31, 2007, was approximately $16,000 for costs related to filing registration statements for previous equity raising matters.  This compared to cash flow provided by financing activities totaling approximately $1.2 million in the comparable 2006 period, the majority of which represented proceeds from the exercise of warrants issued with our debt.

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 February 28, 2007, the market value of the Put contract was zero.

As of February 28, 2007, all of the Company’s commodity hedging and price risk management activities have expired and have not been renewed.

17

---

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 depletion, depreciation, amortization, non-cash stock compensation expense and other non-cash charges (EBDDA)

Earnings before, depletion, depreciation, amortization, non-cash stock compensation expense and other non-cash charges, EBDDA, is a non-GAAP financial measure. We believe EBDDA is relevant because it is a proxy for cash generated by operations to fund our 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 gains on the sale of assets in other periods.  EBDDA should not be considered in isolation from or as a substitute for net income, as an indication of operating performance or as a measure of liquidity. EBDDA, as we calculate it, may not be comparable to EBDDA measures reported by other companies. EBDDA is not the same measure as EBITDA (Earnings before interest, tax, depreciation and amortization). Whereas EBDDA, as we calculate it, retains interest income, interest expense and income tax expense in earnings, EBITDA typically excludes these items from earnings. A reconciliation of our consolidated net income to EBDDA is as follows:

RECONCILIATION TO GAAP INFORMATION

		Nine Months Ended March 31, 2007			Nine Months Ended March 31, 2006
Net Loss (GAAP)		$	(1,336,279	)	$	(1,950,074	)
Depreciation, depletion, amortization, and other non-cash charges		189,389			776,829
Non-cash stock compensation expense		1,237,485			381,385
EBDDA (Non-GAAP)		$	90,595		$	(791,860	)

 

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.

18

---

PART II - OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

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.  On January 5, 2007, the plaintiffs filed a Notice of Nonsuit without Prejudice, thereby dismissing us from the suit.

ITEM 6. EXHIBITS

A.           Exhibits

	4.1	Natural Gas Systems, Inc. 2003 Stock Plan Adopted on September 25, 2003 (Incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-8 filed on January 24, 2007).
	4.2	Natural Gas Systems, Inc. 2004 Stock Plan (Incorporated by reference to Exhibit A of the Company’s Information Statement on Schedule 14C filed on August 9, 2004).
	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.

 

19