EVOLUTION PETROLEUM CORP - Quarter Report: 2009 March (Form 10-Q)

Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended March 31, 2009

 

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

 

For the transition period from        to       

 

Commission File Number 001-32942

 

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

 

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

(Address of principal executive offices and zip code)

 

(713) 935-0122

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes:  o  No: o

 

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

 

 

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

 

The number of shares outstanding of the registrant’s common stock, par value $0.001, as of May 14, 2009, was 26,259,147.

 

 

Table of Contents

 

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

 

PART I. FINANCIAL INFORMATION				3
ITEM 1.		CONSOLIDATED CONDENSED FINANCIAL STATEMENTS		3
		Consolidated Balance Sheets (unaudited) as of March 31, 2009 and June 30, 2008		3
		Consolidated Statements of Operations (unaudited) for the three and nine months ended March 31, 2009 and 2008		4
		Consolidated Statements of Cash Flows (unaudited) for the nine months ended March 31, 2009 and 2008		5
		Notes to Consolidated Condensed Financial Statements (unaudited)		6
ITEM 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		16
ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		25
ITEM 4.		CONTROLS AND PROCEDURES		26
PART II. OTHER INFORMATION				26
ITEM 1.		LEGAL PROCEEDINGS		26
ITEM 1A.		RISK FACTORS		27
ITEM 2.		UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS		27
ITEM 3.		DEFAULTS UPON SENIOR SECURITIES		27
ITEM 4.		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		27
ITEM 5.		OTHER INFORMATION		27
ITEM 6.		EXHIBITS		28
SIGNATURES				29

 

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PART I — FINANCIAL INFORMATION

 

ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

Evolution Petroleum Corporation and Subsidiaries

Consolidated Balance Sheets

(Unaudited)

 

		March 31,			June 30,
		2009			2008
Assets
Current assets
Cash and cash equivalents		$	4,900,219		$	11,272,280
Certificates of deposit		1,740,944			—
Receivables
Oil and natural gas sales		487,953			2,066,300
Income taxes		6,689			478,599
Other		164,243			86,966
Income taxes recoverable		1,545,922			3,625,987
Prepaid expenses and other current assets		123,231			270,938
Total current assets		8,969,201			17,801,070
Property and equipment, net of depreciation, depletion, and amortization
Oil and natural gas properties — full cost method of accounting, of which $9,845,303 at March 31, 2009 and $8,754,429 at June 30, 2008 were excluded from amortization		28,495,507			22,047,233
Other property and equipment		159,681			161,027
Total property and equipment		28,655,188			22,208,260
Other assets, net		356,399			356,518
Total assets		$	37,980,788		$	40,365,848
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable		$	629,132		$	2,892,459
Accrued payroll		561,283			772,559
Royalties payable		208,223			473,327
Other current liabilities		67,106			32,703
Total current liabilities		1,465,744			4,171,048
Long term liabilities
Deferred income taxes		3,791,348			2,901,929
Asset retirement obligations		602,894			215,056
Deferred rent		76,914			74,081
Total liabilities		5,936,900			7,362,114
Commitments and contingencies (Note 12)
Stockholders’ equity
Common stock; par value $0.001; 100,000,000 shares authorized; issued 27,047,347 shares; outstanding 26,259,147 and 26,870,439 as of March 31, 2009 and June 30, 2008, respectively.		27,047			26,870
Additional paid-in capital		16,002,791			14,188,841
Retained earnings		16,896,072			18,788,023
		32,925,910			33,003,734
Treasury stock, at cost, 788,200 shares as of March 31, 2009.		(882,022		)	—
Total stockholders’ equity		32,043,888			33,003,734
Total liabilities and stockholders’ equity		$	37,980,788		$	40,365,848

 

See accompanying notes to consolidated financial statements.

 

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Evolution Petroleum Corporation and Subsidiaries

 Consolidated Statements of Operations

(unaudited)

 

		Three Months Ended						Nine Months Ended
		March 31,						March 31,
		2009			2008			2009			2008
Revenues
Crude oil		$	351,684		$	554,498		$	2,337,948		$	1,664,648
Natural gas liquids		350,891			90,405			1,341,629			111,699
Natural gas		461,889			99,799			1,431,655			123,277
Total revenues		1,164,464			744,702			5,111,232			1,899,624
Operating Costs
Lease operating expense		255,710			300,186			905,020			971,688
Production taxes		29,750			12,867			137,522			46,231
Depreciation, depletion and amortization		759,836			139,086			1,909,009			372,645
Accretion of asset retirement obligations		12,591			7,110			24,452			16,656
General and administrative *		1,595,402			1,266,427			4,722,869			4,062,423
Total operating costs		2,653,289			1,725,676			7,698,872			5,469,643
Loss from operations		(1,488,825		)	(980,974		)	(2,587,640		)	(3,570,019		)
Other income
Interest income		8,024			165,014			99,452			772,835
Net loss before income tax benefit		(1,480,801		)	(815,960		)	(2,488,188		)	(2,797,184		)
Income tax benefit		(444,184		)	(279,975		)	(596,237		)	(848,961		)
Net loss		$	(1,036,617	)	$	(535,985	)	$	(1,891,951	)	$	(1,948,223	)
Loss per common share
Basic and Diluted		$	(0.04	)	$	(0.02	)	$	(0.07	)	$	(0.07	)
Weighted average number of common shares
Basic and Diluted		26,219,034			26,784,473			26,495,176			26,779,339

 

*General and administrative expenses for the three month period ended March 31, 2009 and 2008 included non-cash stock-based compensation expense of $537,285 and $493,872, respectively.  General and administrative expenses for the nine month period ended March 31, 2009 and 2008 included non cash stock-based compensation expense of $1,645,535 and $1,311,443, respectively.

 

See accompanying notes to consolidated financial statements.

 

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Evolution Petroleum Corporation and Subsidiaries

 Consolidated Statements of Cash Flow

(Unaudited)

 

		Nine Months Ended March 31,
		2009			2008
Cash flows from operating activities
Net loss		$	(1,891,951	)	$	(1,948,223	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		1,909,009			372,645
Stock-based compensation		1,645,535			1,311,443
Accretion of asset retirement obligations		24,452			16,656
Settlement of asset retirement obligations		(90,761		)	—
Deferred income taxes		889,419			—
Deferred rent		2,833			25,847
Changes in operating assets and liabilities:
Receivables from oil and natural gas sales		1,578,347			(190,261		)
Receivables from income taxes and other		2,474,698			(915,825		)
Prepaid expenses and other current assets		147,707			286,961
Accounts payable and accrued expenses		(256,805		)	(146,399		)
Royalties payable		(265,104		)	(259		)
Net cash provided by (used in) operating activities		6,167,379			(1,187,415		)
Cash flows from investing activities
Net proceeds from the sale of the Tullos Assets		—			4,420,868
Proceeds from other asset sales		—			31,582
Development of oil and natural gas properties		(7,411,549		)	(4,109,932		)
Acquisitions of oil and natural gas properties		(2,477,133		)	(6,946,157		)
Capital expenditures for other equipment		(28,041		)	(79,305		)
Purchases of certificates of deposit		(1,740,944		)	—
Other assets		119			(1,375		)
Net cash used in investing activities		(11,657,548		)	(6,684,319		)
Cash flows from financing activities
Proceeds from issuance of restricted stock		130			76
Purchase of treasury stock		(882,022		)	—
Net cash provided by (used in) financing activities		(881,892		)	76
Net decrease in cash and cash equivalents		(6,372,061		)	(7,871,658		)
Cash and cash equivalents, beginning of period		11,272,280			27,746,942
Cash and cash equivalents, end of period		$	4,900,219		$	19,875,284

 

See accompanying notes to consolidated financial statements.

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1 — Organization and Basis of Preparation

 

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

 

Interim Financial Statements.  The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).  Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations.  All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included.  The interim financial information and notes hereto should be read in conjunction with the Company’s 2008 Annual Report on Form 10-K for the year ended June 30, 2008, as filed with the SEC. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

 

Principles of Consolidation and Reporting.  Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made to conform to the current presentation.  Such reclassifications have no impact on previously reported income or stockholders’ equity.

 

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

 

Note 2 — Recent Accounting Pronouncements

 

New Accounting Standards.  The following discloses the existence and effect of accounting standards issued but not yet adopted by us with respect to accounting standards that may have an impact on the Company when adopted in the future.

 

Modernization of Oil and Gas Reporting.  On December 31, 2008 the SEC released new requirements for reporting oil and gas reserves.  The new disclosure requirements, when effective, provide for consideration of new technologies in evaluating reserves, allows companies to disclose their probable and possible reserves to investors, requires reporting of oil and gas reserves using an average price based on the prior 12-month period rather than year-end prices, revises the disclosure requirements for oil and gas operations, and revises accounting for the limitation on capitalized costs for full cost companies.  The new rule is expected to be effective for fiscal years ending on or after December 31, 2009, although the transition may be extended.  A company may not apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required.  We have not yet evaluated the effects the new rule will have on our financial statements.

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 2 — Recent Accounting Pronouncements (Continued)

 

Accounting for Business Combinations.  In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141R, Business Combinations (“SFAS No. 141R”), which replaces SFAS No. 141,  Business Combinations.  SFAS No. 141R establishes principles and requirements for determining how an enterprise recognizes and measures the fair value of certain assets and liabilities acquired in a business combination, including non-controlling interests, contingent consideration, and certain acquired contingencies.  SFAS No. 141R also requires acquisition-related transaction expenses and restructuring costs be expensed as incurred rather than capitalized as a component of the business combination.  SFAS No. 141R will be applicable prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  SFAS No. 141R would have an impact on accounting for any businesses acquired after the effective date of this pronouncement.

 

Accounting for Fair Value Measurements.  In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”).  SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements.  SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007.  The provisions of SFAS No. 157 will be applied prospectively as of the beginning of the fiscal year in which it is initially applied except for, among other items, a financial instrument that was measured at fair value at initial recognition under Statement 133 using the transaction price in accordance with the guidance in footnote 3 of Issue 02-3 prior to initial application of SFAS No. 157.  In February 2008, the FASB deferred the effective date of SFAS No. 157 by one year for nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis and amended SFAS No. 157 to exclude SFAS No. 13, Accounting for Leases, and its related interpretive accounting pronouncements that address leasing transactions.  SFAS No. 157 did not have an impact on our financial statements when adopted on July 1, 2008.  We are currently evaluating what the impact, if any, of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities will have on our financial statements.

 

Accounting for Earnings Per Share.  In June 2008, the FASB issued Staff Position No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP No. EITF 03-6-1”).  FSP No. EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in FASB Statement No. 128, Earnings Per Share.  FSP No. EITF 03-6-1 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2008; early adoption is not permitted.  The adoption of FSP No. EITF 03-6-1 will be effective for us for interim and annual periods ending after July 1, 2009.  We are currently evaluating what the impact, if any, of FSP No. EITF 03-6-1 will have on our earnings per share.

 

Note 3 — Sale of Oil and Natural Gas Properties

 

On March 3, 2008, NGS Sub Corp., a Delaware corporation wholly owned by EPM (“NGS Sub”), pursuant to an Asset Purchase and Sale Agreement (the “Asset Sale Agreement”) dated February 15, 2008, completed the sale of its 100% working interest and approximately 79% average net revenue interest in producing and shut-in crude oil wells, water disposal wells, equipment and improvements (the “Tullos Assets”) located in the Tullos Urania, Colgrade and Crossroads Fields in LaSalle and Winn Parishes, Louisiana (the “Tullos Field Area”).  The following table presents the transaction and its affect on our financial statements.

 

Proceeds from sale of properties in the Tullos Field Area		$	4,649,241
Less payout of a third party carried interest arrangement		(168,106		)
Less miscellaneous transaction costs		(60,267		)
Net proceeds		4,420,868
Net book value of our properties in the Tullos Field Area on March 3, 2008
Asset retirement obligation		153,886
Oil and natural gas properties		(1,721,990		)
Other property and equipment		(26,721		)
Prepaid expenses and other current assets		(178,826		)
Other assets		(13,347		)
Remaining credit recorded to oil and natural gas properties		$	2,633,870

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 3 — Sale of Oil and Natural Gas Properties (Continued)

 

The following unaudited pro forma consolidated financial information is presented for illustrative purposes only and presents the pro forma operating results for the Company for the three and nine months ended March 31, 2008 as though the disposition of our properties in the Tullos Field Area occurred on July 1, 2007.  The unaudited pro forma consolidated financial information is not intended to be indicative of the operating results that actually would have occurred if the transaction had been consummated at the beginning of the period presented, nor is the information intended to be indicative of future operating results.

 

The unaudited pro forma consolidated financial information for the three and nine month period ended March 31, 2008 are as follows:

 

		Three Months Ended						Nine Months Ended
		March 31, 2008						March 31, 2008
		As Reported			Pro Forma			As Reported			Pro Forma
Oil and natural gas revenues		$	744,702		$	351,884		$	1,899,624		$	422,306
Loss from operations		(980,974		)	(1,058,866		)	(3,570,019		)	(3,802,261		)
Net loss		(535,985		)	(587,150		)	(1,948,223		)	(2,109,979		)
Loss per common share — basic and diluted		$	(0.02	)	$	(0.02	)	$	(0.07	)	$	(0.08	)

 

Note 4 — Property and Equipment

 

We utilize the full cost method of accounting for costs related to the development and acquisition of oil and natural gas reserves.  Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs, less accumulated amortization and related deferred income taxes (the “Net Capitalized Costs”), are subject to a “ceiling test” that limits such costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent (the “Standardized Measure”) plus the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)), plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and net of related income taxes (the “Ceiling”).  Any costs in excess of the Ceiling are written off as a non-cash expense.  The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling.  Full cost companies must use the prices in effect at the end of each fiscal quarter, with consideration of price changes only to the extent of contractual arrangements, to calculate the Standardized Measure.  Favorable price changes subsequent to the balance sheet date and prior to the release of financial statements may be considered to avoid an impairment.  The Ceiling determined with the Standardized Measure of our proved reserves, calculated based upon March 31, 2009 quoted market prices ($3.37 per MMBtu for Houston Ship Channel natural gas and $49.66 per barrel for NYMEX oil, adjusted for market differentials), exceeded our Net Capitalized Costs by approximately $180,000, or less than 1% of our net oil and natural gas property costs.  However, due to the increases in crude oil and natural gas prices subsequent to March 31, 2009, our Ceiling has increased over and above our Net Capitalized Costs, and as such, we did not have an impairment of our oil and natural gas properties as of March 31, 2009.

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 4 — Property and Equipment  (Continued)

 

As of March 31, 2009 and June 30, 2008 our oil and natural gas properties and other property and equipment consisted of the following:

 

		March 31, 2009			June 30, 2008
Oil and natural gas properties
Property costs subject to amortization		$	21,161,866		$	13,924,844
Less: Accumulated depreciation, depletion, and amortization		(2,511,662		)	(632,040		)
Unproved properties not subject to amortization		9,845,303			8,754,429
Oil and natural gas properties, net		$	28,495,507		$	22,047,233
Other property and equipment
Furniture, fixtures and office equipment, at cost		259,882			231,841
Less: Accumulated depreciation		(100,201		)	(70,814		)
Other property and equipment, net		$	159,681		$	161,027

 

Unproved properties not subject to amortization includes unevaluated acreage of $7.8 and $6.8 million as of March 31, 2009 and June 30, 2008, respectively.  As of March 31, 2009, this acreage consists of properties in the Giddings Field, our projects in the Woodford Shale trend in Oklahoma, and our Neptune project in South Texas.  As of June 30, 2008, the unevaluated acreage consisted of properties in the Giddings Field and our projects in the Woodford Shale trend in Oklahoma.  Unproved properties also include approximately $2.0 million as of March 31, 2009 and June 30, 2008 of participating interests through separately acquired royalty and overriding royalty interests aggregating 7.4% of the Delhi Holt Bryant Unit in the Delhi Field in Louisiana.  Subject to industry conditions, evaluation of these properties is expected to be completed within three years.  Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis.

 

The following table provides a summary of costs that are not being amortized as of March 31, 2009, by the fiscal year in which the costs were incurred:

 

					During the
					Nine Months Ended			During the Year Ended June 30,
					March 31,									2006 and
Costs excluded from amortization		Total			2009			2008			2007			Prior
Leasehold acquisition costs		$	7,890,926		$	1,452,174		$	5,495,568		$	943,184		$	—
Royalty and overriding royalty interests		1,954,377			3,636			—			966,794			983,947
		$	9,845,303		$	1,455,810		$	5,495,568		$	1,909,978		$	983,947

 

Note 5 — Asset Retirement Obligations

 

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligation for the nine months ended March 31, 2009:

 

Asset retirement obligations - July 1, 2008		$	215,056
Liabilities incurred		185,770
Liabilities settled		(90,761		)
Accretion expense		24,452
Revisions to previous estimates		268,377
Asset retirement obligations — March 31, 2009		$	602,894

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 6 — Stockholders’ Equity

 

On August 19, 2008, the Board of Directors authorized the issuance of 46,795 shares of common stock to certain employees who elected to receive these shares in lieu of a portion of their fiscal 2008 cash bonus.  The value of the shares issued was $168,462, based on the fair market value on the date of issuance, or $3.60 per share.  See Note 7.

 

On October 30, 2008, we repurchased 788,200 shares of common stock at an average price of $1.10 per share, plus approximately $15,000 of transaction costs, from an unaffiliated accredited investor.  At this time, we currently have no plan to repurchase any more common shares.

 

On December 9, 2008, three outside directors each received 30,000 shares of restricted common stock, with a per share price of $1.20, as part of a compensation plan for outside directors.  The same outside directors each received 8,633 shares of restricted common stock, with a per share price of $4.17, as part of their compensation plan during the calendar year 2008.  All issuances of common stock were subject to vesting terms per individual stock agreements, which is generally one year for directors.

 

On January 16 and February 10, 2009, we issued 24,324 and 15,789 shares of restricted common stock, respectively, to Mr. Cagan as compensation for his services as a director, in lieu of the $5,000 monthly advisor fee previously paid to CMCP.   The 15,789 share award was elected by Mr. Cagan in lieu of cash retainers and fees for his board service during calendar 2009.   These issuances of common stock are subject to vesting terms per the individual stock agreements, which is generally one year for directors.

 

Note 7 — Stock-Based Incentive Plan

 

We have granted option awards to purchase common stock (the “Stock Options”) and restricted common stock awards  (“Restricted Stock”) to employees, directors, and consultants of the Company and its subsidiaries under the Natural Gas Systems Inc. 2003 Stock Plan (the “2003 Stock Plan”) and the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the “2004 Stock Plan” or together, the “EPM Stock Plans”).  Option awards for the purchase of 600,000 shares of common stock were issued under the 2003 Stock Plan.  The 2004 Stock Plan authorized the issuance of 5,500,000 shares of common stock.  There are no shares available for grant under the 2003 Stock Plan and, as of March 31, 2009, 557,861 shares remain available for grant under the 2004 Stock Plan.

 

We have also granted common stock warrants, as authorized by the Board of Directors, to employees in lieu of cash bonuses or as incentive awards to reward previous service or provide incentives to individuals to acquire a proprietary interest in the Company’s success and to remain in the service of the Company (the “Incentive Warrants”).  These Incentive Warrants have similar characteristics of the Stock Options.  A total of 1,037,500 Incentive Warrants have been issued, with Board of Directors approval, outside of the EPM Stock Plans.

 

On August 19, 2008, the Board of Directors authorized the issuance of 46,795 shares of common stock from the 2004 Stock Plan to certain employees who elected to receive these shares in lieu of a portion of their fiscal 2008 cash bonus.  The value of the shares issued was $168,462, based on the fair market value on the date of issuance, or $3.60 per share.

 

Stock Options and Incentive Warrants

 

Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the three month period ended March 31, 2009 and 2008 was $500,000 and $416,143, respectively.  Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the nine month period ended March 31, 2009 and 2008 was $1,445,987 and $1,120,349, respectively.

 

During the nine months ended March 31, 2009, we granted Stock Options to purchase 591,090 shares of common stock under the 2004 Stock Plan with a weighted average exercise price of $4.27.  During the nine months ended March 31, 2008, we granted Stock Options to purchase 1,385,000 shares of common stock under the 2004 Stock Plan with a weighted average exercise price of $2.49.  The exercise price was determined based on the market price of the Company’s common stock on the date of grant.  The Stock Options granted during the nine months ended March 31, 2009 and 2008 generally vest quarterly, on a straight line basis, over a period of four years.  The Stock Options granted during the nine months ended March 31, 2009 and 2008 have a contractual life of seven and ten years, respectively.  The weighted average assumptions used to calculate the fair value of these Stock Options and the weighted average fair value of the Stock Options granted are as follows:

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 7 — Stock-Based Incentive Plan (Continued)

 

 

We estimated the fair value of Stock Options and Incentive Warrants issued to employees and directors under SFAS No. 123R at the date of grant using a Black-Scholes-Merton valuation model.  The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.  The expected term (estimated period of time outstanding) of Stock Options and Incentive Warrants is based on the “simplified” method of the estimated expected term for “plain vanilla” options allowed by the SEC Staff Accounting Bulletin (“SAB”) No. 107 and SAB No. 110, and varied based on the vesting period and contractual term of the Stock Options or Incentive Warrants.   Expected volatility is based on the historical volatility of the Company’s closing common stock price and that of an evaluation of a peer group of similar companies trading activity.  We have not declared any cash dividends on the Company’s common stock.

 

The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of March 31, 2009, and the changes during the nine months then ended:

 

		Number of  Stock Options and Incentive Warrants		Weighted Average Exercise Price			Aggregate Intrinsic Value  (1)			Weighted Average Remaining Contractual Term (in years)
Stock Options and Incentive Warrants outstanding at July 1, 2008		5,483,500		$	1.81
Granted		591,090		$	4.27
Exercised		—		—
Canceled, forfeited, or expired		—		—
Stock Options and Incentive Warrants outstanding at March 31, 2009		6,074,590		$	2.05		$	1,789,330		6.7
Vested or expected to vest at March 31, 2009		6,074,590		$	2.05		$	1,789,330		6.7
Exercisable at March 31, 2009		4,244,263		$	1.66		$	1,702,874		6.4

 

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($1.88 as of March 31, 2009) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

 

There were no Stock Options or Incentive Warrants that were exercised during the nine months ended March 31, 2009 and 2008.

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 7 — Stock-Based Incentive Plan (Continued)

 

A summary of the status of our unvested Stock Options and Incentive Warrants as of March 31, 2009 and the changes during the nine months ended March 31, 2009, is presented below:

 

		Number of Stock Options and Incentive Warrants		Weighted Average Grant- Date Fair Value
Unvested at July 1, 2008		2,003,437		$	1.83
Granted		591,090		$	2.62
Vested		(764,200	)	$	1.78
Forfeited		—		—
Unvested at March 31, 2009		1,830,327		$	2.13

 

The total unrecognized compensation cost at March 31, 2009, relating to non-vested share-based compensation arrangements granted under the EPM Stock Plans and Incentive Warrants was $3,651,844.  Such unrecognized expense is expected to be recognized over a weighted average period of 2.6 years.  Unrecognized compensation related to non-vested share-based compensation arrangements are not adjusted for a decline in the underlying stock price subsequent to the date of the award.

 

Restricted Stock

 

For the nine months ended March 31, 2009, we issued 130,113 shares of restricted common stock to certain members of our board of directors.

 

For the nine months ended March 31, 2008, we issued 25,899 and 50,000 shares of restricted common stock to certain members of our board of directors and a consultant, respectively.

 

Stock-based compensation expense related to Restricted Stock grants for the three month period ended March 31, 2009 and 2008 was $37,285 and $77,729, respectively.  Stock-based compensation expense related to Restricted Stock grants for the nine month period ended March 31, 2009 and 2008 was $199,548 and $191,094, respectively.

 

The following table sets forth the Restricted Stock transactions for the nine months ended March 31, 2009:

 

		Number of Restricted Shares		Weighted Average Grant-Date Fair Value
Unvested at July 1, 2008		50,898		$	4.11
Granted		130,113		$	1.29
Vested		(50,898	)	$	4.11
Forfeited		—		—
Unvested at March 31, 2009		130,113		$	1.29

 

At March 31, 2009, unrecognized stock compensation expense related to Restricted Stock grants totaled $123,783.  Such unrecognized expense will be recognized over a weighted average period of 0.8 years.

 

12

 

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 8 — Supplemental Disclosure of Cash Flow Information

 

Our supplemental disclosures of cash flow information for the nine months ended March 31, 2009 and 2008 are as follows:

 

		Nine Months Ended
		March 31,
		2009			2008
Income taxes paid:		$	15,000		$	33,879
Income tax refunds and net operating loss carry-back received:		$	4,052,631		—
Non-cash transactions:
Increase (decrease) in accounts payable used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties:		$	(2,014,933	)	$	2,081,781
Oil and natural gas properties incurred through recognition of asset retirement obligations:		$	454,147		$	170,890
Common stock issued in lieu of a portion of 2008 cash bonus accrued at June 30, 2008:		$	168,462		$	—

 

Note 9 — Income Taxes

 

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

 

There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits as of the date of adoption of FIN 48 and through March 31, 2009.

 

We recognized a tax benefit of 30% and 34% for the three months ended March 31, 2009 and 2008, respectively, and a tax benefit of 24% and 30% for the nine months ended March 31, 2009 and 2008, respectively.  Stock-based compensation expense related to our qualified incentive stock option awards is our most significant permanent difference in reconciling our income tax benefit at the statutory federal rate to our effective income tax benefit.

 

As of March 31, 2009, we expect to recover approximately $1.5 million in federal and state income taxes paid during the tax year ended June 30, 2007, arising from an estimated carry-back of income tax losses incurred during the nine months ended March 31, 2009.  Significant intangible drilling costs were incurred during the 2009 fiscal year, which we will elect to deduct for federal and state income tax purposes.  Under GAAP and specifically the full cost accounting method, intangible drilling costs are capitalized as part of oil and natural gas properties, and depleted using the unit-of-production method.  The deduction of intangible drilling costs creates a significant difference in the income tax and book basis of our oil and natural gas properties and resulted in an increase in our net deferred tax liability, from $2.9 million as of June 30, 2008, to $3.8 million as of March 31, 2009.

 

Note 10 — Related Party Transactions

 

Laird Q. Cagan, a member of our Board of Directors, is a Managing Director and co-owner of Cagan McAfee Capital Partners, LLC (“CMCP”). CMCP has performed financial advisory services to us pursuant to a written agreement amended in November 2005 (the “Agreement”), providing for a retainer of $5,000 per month.  Also pursuant to the Agreement, Mr. Cagan, as a registered representative of Chadbourn Securities Inc. (“Chadbourn”) and as a partner of CMCP could serve as our placement agent in private equity financings, wherein CMCP could earn cash fees equal to 8% of gross equity proceeds, declining to 4% subject to the amount of equity raised through CMCP, and a fixed 4% warrant fee.  During the term of the Agreement , Mr. Cagan received no compensation for serving as a director or as the Chairman of our Board of Directors.   Effective December 31, 2008, the Agreement was modified to remove the monthly retainer and Mr. Cagan was re-elected as a director of our Board with remuneration consistent with other outside directors of our Board.

 

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

 

13

 

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 10 — Related Party Transactions (Continued)

 

During the three months ended March 31, 2009 we did not pay CMCP any fee related to the Agreement.  During the nine months ended March 31, 2009, we expensed and paid $30,000, through monthly retainers of $5,000 through December 31, 2008.  During the three and nine months ended March 31, 2008, we expensed and paid CMCP $15,000 and $45,000, respectively, through monthly retainers of $5,000.  There were no other earned fees by CMCP during these periods.

 

See also Note 6 for equity transactions with related parties.

 

Note 11 — Earnings (loss) Per Share (“EPS”)

 

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

 

		Three Months Ended March 31,						Nine Months Ended March 31,
		2009			2008			2009			2008
Numerator
Net loss		$	(1,036,617	)	$	(535,985	)	$	(1,891,951	)	$	(1,948,223	)
Denominator
Weighted average number of common shares — basic and diluted		26,219,034			26,784,473			26,495,176			26,779,339
Net loss per common share — basic and diluted		$	(0.04	)	$	(0.02	)	$	(0.07	)	$	(0.07	)

 

Total potentially dilutive securities outstanding as of March 31, 2009 are as follows:

 

Outstanding Potential Dilutive Securities		Weighted Average Exercise Price			Outstanding at March 31, 2009
Common stock warrants issued in connection with equity and financing transactions		$	1.40		401,058
Stock Options and Incentive Warrants		$	2.05		6,074,590
					6,475,648

 

Note 12 — Commitments and Contingencies

 

Environmental clean-up.  On August 3, 2007, we were advised of an oil spill in the Tullos Field near one of our leases. At the request of field agents of the Louisiana Department of Environmental Quality and the Environmental Protection Agency (“EPA”), we agreed to commence a clean-up operation that was completed by the end of August 2007. A detailed analysis of the oil in the spill compared to the Company’s produced oil was conducted by an EPA approved laboratory.  We believe that the oil in the spill did not originate from our operations, supported by the formal findings of the laboratory.  We received insurance reimbursements of $484,197 in October 2007, $217,668 in March 2008, and $75,514 in February 2009.  These reimbursements covered all of our actual cleanup costs except a $5,000 insurance deductible and excluding our legal fees, in-house administrative costs, and any possible EPA expense reimbursements and fines that might be billed.  As of March 31, 2009, we believe all matters related to this oil spill have been settled, with the exception of an invoice from the United States Coast Guard for approximately $20,000 for penalties and interest, which we believe is unsupported and plan to appeal.

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 12 — Commitments and Contingencies (Continued)

 

Litigation.  The Company is subject to various lawsuits and other claims in the normal course of business.  In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdiction in which we operate.  We establish reserves for specific liabilities in connection with regulatory and legal actions that we deem to be probable and estimable.  No amounts have been accrued in our financial statements with respect to any legal or regulatory matters as we believe the matters have a remote chance of resulting in a significant judgment.

 

In July 2008, a multi-plaintiff lawsuit was filed in the twenty-eighth Judicial District Court, Lasalle Parish, Louisiana, against 15 defendants, including Four Star Development Corporation, a former indirect wholly owned subsidiary of the Company, which was sold on March 3, 2008, as part of our sale of the Tullos Field Area.  Plaintiffs claim that the defendants’ oil and natural gas exploration, development and production activities on their properties have caused soil and ground water contamination as a result of the release of hydrocarbons and drilling fluids. Plaintiffs seek damages for testing, clean-up and remediation of the properties as well as diminution in their value and mental anguish and emotional distress to the individual plaintiffs, unjust enrichment and punitive damages for alleged concealment of ongoing activities.  At this time, we are not a party to the litigation and are unable at this time to determine the exposure, if any, to the Company.

 

In November 2005, a multi-plaintiff lawsuit was filed in the Fifth Judicial District Court, Richland Parish, Louisiana, against 18 defendants including NGS Sub Corp. and Arkla Petroleum LLC, the Company’s direct and indirect wholly owned subsidiaries (the “Subsidiaries”), as working interest owners/operators of various oil and natural gas leases in the Delhi Field.  Plaintiffs claim that the defendants’ oil and natural gas exploration, development and production activities on their properties have caused soil and ground water contamination as a result of the release of hydrocarbons and drilling fluids. Plaintiffs seek damages for testing, clean-up and remediation of the properties as well as diminution in their value and mental anguish to the individual plaintiffs, unjust enrichment and punitive damages for alleged concealment of ongoing activities.

 

Defendants have answered Plaintiffs’ suit denying all claims. Trial is set before a jury in Richland Parish for July 13, 2009.  We are vigorously contesting all of Plaintiffs’ claims.  The case is currently in discovery and, at this time, we are unable to predict the outcome.

 

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on August 1, 2016. Future minimum lease commitments as of March 31, 2009 under this operating lease are as follows:

 

For the twelve months ended March 31,

 

 

Rent expense for the three months ended March 31, 2009 and 2008 was $39,232 and $35,466, respectively.  Rent expense for the nine months ended March 31, 2009 and 2008 was $110,165 and $106,399, respectively.

 

Employment Contracts.  We have entered into employment agreements with the Company’s three senior executives.  The employment contracts provide for a severance package for termination by the Company for any reason other than cause or permanent disability, or in the event of a constructive termination, that includes payment of base pay and certain medical and disability benefits from six months to a year after termination.   The total contingent obligation under the employment contracts as of March 31, 2009 is approximately $499,000.

 

15

 

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

This Form 10-Q and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in our 2008 Annual Report on Form 10-K for the year ended June 30, 2008 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.

 

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

 

Executive Overview

 

General

 

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

 

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 pursue three specific initiatives:

 

	I		Enhanced oil recovery (“EOR”), using miscible and immiscible gas flooding;
	II		Conventional redevelopment of bypassed primary resources within mature oil and natural gas fields utilizing modern technology and our expertise; and
	III		Unconventional gas resource development, using modern stimulation and completion technologies.

 

Our most significant asset is within our EOR Initiative in the 13,636 acre Delhi Field, located in northeast Louisiana.  Our non-operated interests consist of 7.4% in overriding and mineral royalty interests and a 25% after pay-out reversionary working interest in the Delhi Field Holt Bryant Unit, along with a 25% working interest in certain other depths in the Delhi Field resulting from the Farmout we completed on June 12, 2006 with Denbury Onshore LLC, a subsidiary of Denbury Resources Inc. (“Denbury”) (the “Delhi Farmout”).  The Holt Bryant Unit is currently being redeveloped by the operator, Denbury, using CO2 enhanced oil recovery technology and a dedicated portion of Denbury’s proved CO2 reserves in the Jackson Dome, located approximately 100 miles east of Delhi.  According to public presentations released by Denbury, injection of CO2 is expected to begin in the third quarter of calendar 2009, followed by projected increases in oil production about early 2010.

 

Since our closing of the Delhi Farmout, we have focused on developing projects in our other initiatives, particularly through conventional redevelopment of bypassed resources in the Giddings Field using horizontal drilling methods, the leasing of unconventional gas shale projects in the Woodford Shale Trend in Oklahoma and the leasing of Neptune, a heavy oil project in S. Texas.  Conceptually, our plan going forward can be illustrated as follows:

 

16

 

 

As indicated by the above chart, (volumes are representative and not to scale), we are funding our development projects in the Giddings Field and leasing and development activities in our gas shale projects from our working capital resources.  We expect that net cash flows from our properties in the Giddings Field, our current cash resources and cash flows from the Delhi Project will be used to fund full development our gas shale projects and other new projects.  We may utilize project financing in the future for both Giddings and our gas shale projects.

 

Our long term strategy and primary focus continue to be on increasing share value through the identification and acquisition of resources and conversion of those resources into proved reserves through our expertise and technology.  Near term, our focus is on (i) project identification and leasing of reserves that we believe will be categorized as proved undeveloped, and (ii) selective drilling activities to move existing reserves into the proved category.  We are emphasizing long term share value maintenance and growth over near term earnings during the current period of low commodity prices.

 

Highlights for our Third Quarter Fiscal Year 2009

 

·                 The CO2 Pipeline to our Delhi Field has been completed.  On May 5, 2009, the operator reported that the 78 mile Delta Pipeline from Tinsley Field to our Delhi Field has been completed, tested and CO2 fill into the pipeline has begun.

 

·                 The redeployment of our proceeds from the sale of our properties in the Tullos Field Area into the Giddings Field continues to generate positive results.

 

Sales volumes increased 346% during our third quarter in fiscal year 2009 versus our third quarter in fiscal year 2008.  Our increase in sales volumes for the quarter were solely attributable to our production in the Giddings Field.  Our properties in the Tullos Field Area, which were sold on March 3, 2008, accounted for approximately 45% of total sales volumes for the three months ended March 31, 2008.  Production during March 2009 averaged 482 gross (386 net) BOE per day, despite two key wells producing for only two-thirds of the month.

 

17

 

We completed two new re-entry wells in the third fiscal quarter of 2009.  The first fiscal 2009 Giddings Field re-entry well, the Hilton Yegua #1, was completed and placed on production during mid-January 2009.  A second re-entry well, the Pearson #1, was completed and placed on production in late January 2009.  We own a 100% working interest and approximately 79% revenue interest in the two wells.

 

We lowered our field income break-even point by 58%.  During the quarter ended March 31, 2009, lifting costs (lease operating and severance tax, on a combined per unit of sales basis) were $6.88 and depletion rates were $17.57 per BOE at our Giddings Field, equaling a field income break-even point of $24.45 per BOE.  This compares to lifting costs of $44.63 and a depletion rate of $13.29 per BOE, equaling a field income break-even point of $57.92 per BOE for the last full fiscal quarter of production prior to divestiture in early March 2008.

 

·                 The product prices we received declined 65% year over year and declined 31% sequentially.  During the quarter ended March 31, 2009, we received $27.27 per BOE, as compared to $77.82 per BOE during the three months ended March 31, 2008, and $39.78 per BOE during the three months ended December 31, 2008.

 

·                 We remained financially strong.

 

We ended the quarter with $7.5 million of working capital, compared to $7.6 million at December 31, 2008 and $13.6 million at June 30, 2008.  At March 31, 2009, working capital included $6.6 million of cash and cash equivalents, and short-term certificates of deposit, and $1.5 million of recoverable income taxes arising from current year tax losses being carried back to a prior tax year.   We incurred $8.3 million in capital expenditures for oil and natural gas leasehold and development costs during the nine months ended March 31, 2009, which was funded by working capital.  We continue to have no short or long term funded debt other than our payables incurred in the ordinary course of business.

 

We protected our short-term investments during difficult credit market conditions.  We have continually avoided structurally enhanced investment securities, auction rate securities and other higher risk credit instruments.  Instead, we relied upon lower yielding U.S. Government Agency money market funds through July 2008, when we shifted all of our cash equivalents into short-term U.S. Treasury money market funds.  During the second quarter of fiscal 2009, we redeployed some of our cash and cash equivalents into certificates of deposit that mature within a year and that are fully insured by the FDIC.

 

We are still debt free, and expect to remain so during fiscal 2009.

 

Looking Forward in 2009

 

·                 We will maintain our focus on increasing underlying value per share by converting unproved resources to proved reserves.

 

Our Delhi CO2 project is nearing production:

 

·                 CO2 pipeline fill will continue through the second calendar quarter of 2009.

 

·                 Final commissioning of the pipeline is expected in June 2009.

 

·                 A rig will be mobilized for additional field work in the second calendar quarter of 2009.

 

·                 CO2  reservoir injection is scheduled for the summer of 2009.

 

·                 The CO2 processing facility is scheduled to be operational in the fourth calendar quarter of 2009.

 

·                 First oil production is expected to begin within six months following first field injection of CO2 , or sometime around early calendar 2010.  We believe that production response in the Delhi Field resulting from the injection of CO2 will lead to a substantial addition to our net proved reserves.

 

18

 

We expect to initiate pilot drilling within our shallow Woodford Shale projects. Current plans for fiscal 2009 include the drilling or re-entry of up to three vertical wells to depths of about 1,500 feet to utilize air drilling to develop what we believe will be substantial low cost gas reserves.

 

We expect to initiate development drilling within our Neptune heavy oil project in South Texas.  We completed the leasing of approximately 1,500 net acres where we intend to drill infill (or downspaced) wells within an existing moderately heavy oil field.  Production in this field by another operator has established proved reserves on infill spacing.  We also expect to apply our specialized completion technology to further enhance recovery.

 

Further declines of oil and natural gas prices could result in a significant impairment of our full-cost pool. The current recessionary economic environment has resulted in lower demand for oil and natural gas, resulting in volatile commodity price.  Commodity prices at March 31, 2009 ($3.37 per MMBtu for Houston Ship Channel natural gas and $49.66 per barrel for NYMEX oil, adjusted for market differentials), would have caused an impairment of our oil and natural gas properties of approximately $180,000, or less than 1% of our net oil and natural gas property costs.  However, due to the increases in crude oil and natural gas prices subsequent to March 31, 2009, we did not recognize and impairment of our oil and natural gas properties as of March 31, 2009.  Our depletion rate decreased from $19.56 per barrel to $17.57 per barrel during the three months ended March 31, 2009 due to revision of estimated future development costs associated with our proved undeveloped reserves.  Natural gas prices at the wellhead declined from $5.23 per mcf in December 2008 to $3.25 per mcf in March 2009, offset partially by the increase in received oil price from $40.06 to $44.71 per barrel.  Receipts per BOE declined dramatically during the quarter, offset in part by continuing declines in oil field service and drilling costs.  Prices have improved subsequent to March 31, 2009 as of early May 2009.

 

·                 Reductions in General and Administrative Costs

 

We expect a 10% reduction in our fully burdened payroll expenses starting in mid- fourth quarter of fiscal 2009.  During April 2009, we reduced our headcount by two full time employees and one contractor, bringing our staff to eleven full-time employees and two contractors.  We are also reviewing all recurring costs and operations for potential savings.

 

Liquidity and Capital Resources

 

Our primary liquidity needs are to fund strategic property acquisitions, our drilling program, and operating costs.   As disclosed in our quarterly report on Form 10-Q for the quarter ended September 30, 2008, we revised our 2009 capital expenditures budget for fiscal 2009 (the “Revised 2009 Plan”), reducing the overall program by more than half to less than $10 million.  Due to our positive working capital, cash flows from producing properties, no debt and no near term expiring leases, we believe we have the ability to fund or further adjust our capital expenditure budget to capture select opportunities that may arise for the benefit of our shareholders, without the need of additional financing.  Therefore, we believe that our current sources of liquidity are sufficient to fund our ongoing cash requirements.

 

At March 31, 2009, our working capital was $7.5 million and we continued to be debt free.  This compares to working capital of $13.6 million at June 30, 2008.  The decrease in working capital of $6.1 million since June 2008 was due to cash of $9.9 million used for investing activities, primarily for investments in oil and natural gas properties, cash used of  $0.9 million to repurchase our common stock, a decrease of $4.2 million in receivables and other current assets, primarily from the collection of oil and gas receivables and income tax receivables, partially offset by cash of $6.2 million provided by operations and a decrease of $2.7 million in current liabilities, primarily due to payments made on accounts payable for costs incurred for our drilling program.

 

Cash flows provided by operating activities for the nine months ended March 31, 2009 were $6.2 million.  Cash flows provided by operations includes cash proceeds of $6.4 million from oil and natural gas production primarily from our properties in the Giddings Field, cash proceeds of $0.1 million from interest income, cash proceeds of $4.1 million from income tax refunds, primarily from our 2008 tax year net operating loss carry-back, offset by cash payments of $0.1 million for settling liabilities associated with our asset retirement obligations and $4.3 million of cash payments for operating activities, including lease operating expenses, production taxes, and salaries and wages.  This compares to $1.2 million of cash used in operations for the nine months ended March 31, 2008, which includes $1.7 million of cash proceeds from oil and natural gas production primarily from our properties in the Tullos Field Area, which we sold on March 3, 2008, and cash proceeds from interest income of $0.8 million, offset by $3.7 million of cash payments for operating activities, including lease operating expenses, production taxes, and salaries and wages.

 

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Cash flows used in investing activities totaled $11.7 million during the nine months ended March 31, 2009, which includes the purchase of short-term certificates of deposit of $1.8 million.  Our remaining investing activities of $9.9 million were primarily for development activities in the Giddings Field and leasehold acquisition costs in the Giddings Field, our Woodford Shale projects in Oklahoma and our Neptune project in South Texas.  The $9.9 million includes net payments on accounts payable of $2.0 million from June 30, 2008, relating to expenditures for oil and natural gas properties incurred in the prior fiscal period, thus $7.9 million of cash was used for oil and gas properties incurred during this fiscal year.  During the nine months ended March 31, 2008, approximately $11.1 million of cash was used for investments to acquire and develop oil and natural gas property interests and other property and equipment, primarily for investments in oil and natural gas properties at the Giddings Field, and does not include approximately $2.1 million net increase in accounts payable from July 1, 2007 through March 31, 2008, relating to expenditures on oil and natural gas properties.  The sale of the Tullos Assets partially offset our development and acquisition activities by providing net proceeds of approximately $4.4 million for the nine months ended March 31, 2008.

 

Cash flows used in financing activities for the nine months ended March 31, 2009 were $0.9 million.  On October 30, 2008, we repurchased 788,200 shares of common stock at an average price of $1.10 per share, plus approximately $15,000 of transaction costs, from an unaffiliated accredited investor.  Cash flows from financing activities for the nine months ended March 31, 2008 were insignificant.

 

We incurred $8.3 million of capital expenditures for oil and natural gas leasehold and development costs during the nine months ended March 31, 2009, which includes $0.4 million related to the recognition of asset retirement obligations.  Of the $8.3 million, $2.2 million was incurred for leasehold acquisitions and $6.1 million was incurred for development activities.  Development activities were in the Giddings Field and leasehold acquisition costs were for properties in the Giddings Field, our Woodford Shale projects in Oklahoma and our Neptune project in South Texas.  We incurred approximately $13.3 million in capital expenditures for oil and natural gas leasehold and development costs during the nine months ended March 31, 2008, which includes $0.2 million related to the recognition of asset retirement obligations.  Of the $13.3 million, $6.6 million was incurred for leasehold acquisitions and $6.7 million for development costs, primarily in the Giddings Field.

 

Since our wells in the Giddings Field tend to produce a large portion of their reserves relatively quickly, and due to continued economic uncertainty, we believe that it is in our shareholders’ best interests, and consistent with our focus on increasing share value, to slow the development of our properties in the Giddings Field until expectations of higher commodity prices may be realized.  Our Revised 2009 Plan provided for drilling up to three re-entry wells in the Giddings Field, which is a reduction from the previous ten well re-entry plan, subject to future changes in commodity prices and market conditions.  The first fiscal 2009 Giddings Field re-entry well, the Hilton Yegua #1, was completed and placed on production in mid-January 2009.  A second re-entry well, the Pearson #1, began drilling in late December 2008 and was completed and placed on production by late January 2009.  We own a 100% working interest and approximately 79% revenue interest in the two wells.

 

Additionally, during the fourth quarter of our fiscal year 2009, we are planning initial test drilling or re-entry of up to three low-cost vertical wells within our shallow Woodford Shale project in Oklahoma.  It is our intention to potentially quantify and convert that potential resource into higher graded reserves.  Similarly, we expect to initiate drilling of low cost development wells in our new South Texas project beginning the summer of 2009, subject to the price of crude oil, with the expectation of potentially establishing additional proved reserves of moderately heavy oil associated with water at shallow depths.

 

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Results of Operations

 

Three months ended March 31, 2009 compared with the three months ended March  31, 2008

 

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

 

		Three Months Ended
		March 31									%
		2009			2008			Variance			change
Production Volumes, net to the Company:
Crude oil (Bbl)		8,953			6,540			2,413			37	%
Natural gas liquids (“NGLs”) (Bbl)		15,091			1,606			13,485			840	%
Natural gas (Mcf)		112,176			12,287			99,889			813	%
Crude oil, NGLs and natural gas (BOE)		42,740			10,194			32,546			319	%
Sales Volumes, net to the Company:
Crude oil (Bbl)		8,911			5,915			2,996			51	%
NGLs (Bbl)		15,091			1,606			13,485			840	%
Natural gas (Mcf)		112,176			12,287			99,889			813	%
Crude oil, NGLs and natural gas (BOE)		42,698			9,569			33,129			346	%
Revenue data:
Crude oil		$	351,684		$	554,498		$	(202,814	)	(37	)%
NGLs		350,891			90,405			260,486			288	%
Natural gas		461,889			99,799			362,090			363	%
Total revenues		$	1,164,464		$	744,702		$	419,762		56	%
Average price:
Crude oil (per Bbl)		$	39.47		$	93.74		$	(54.27	)	(58	)%
NGLs (per Bbl)		23.25			56.29			(33.04		)	(59	)%
Natural gas (per Mcf)		4.12			8.12			(4.00		)	(49	)%
Crude oil, NGLs and natural gas (per BOE)		$	27.27		$	77.82		$	(50.55	)	(65	)%
Expenses (per BOE)
Lease operating expenses and production taxes		$	6.88		$	32.72		$	(25.84	)	(79	)%
Depletion expense on oil and natural gas properties (a)		$	17.57		$	13.55		$	4.02		30	%

 

(a)          Excludes depreciation of furniture and fixtures of $9,769 and $9,465, for the three months ended March 31, 2009 and 2008, respectively.

 

 

Net loss.  For the three months ended March 31, 2009, we reported a net loss of $1,036,617, or $0.04 loss per share (which includes $1.3 million of non-cash charges related to stock-based compensation, depreciation, depletion, and amortization, and accretion on asset retirement obligations) on total oil and natural gas revenues of $1,164,464.  This compares to a net loss of $535,985, or $0.02 loss per share (which included approximately $0.6 million of non-cash charges related to stock based compensation, depreciation, depletion, and amortization, and accretion on asset retirement liabilities), on total oil and natural gas revenues of $744,702 for the three months ended March 31, 2008.  The increase in loss is attributable to an increase in operating costs of  $927,613 (primarily related to an increase in non-cash charges as noted above), a decrease in interest income of $156,990, offset by an increase in revenues of $419,762 and an increase in our income tax benefit of $164,209.  Additional details of the components of net loss are explained in greater detail below.

 

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