EVOLUTION PETROLEUM CORP - Quarter Report: 2012 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, 2012

 

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

 

For the transition period from             to            

 

Commission File Number 001-32942

 

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

 

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

(Address of principal executive offices and zip code)

 

(713) 935-0122

(Registrant’s telephone number, including area code)

 

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

 

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

 

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

 

 

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

 

The number of shares outstanding of the registrant’s common stock, par value $0.001, as of May 8, 2012, was 27,816,963.

 

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

 

TABLE OF CONTENTS

 

		Page
PART I. FINANCIAL INFORMATION		2
ITEM 1.	UNAUDITED CONSOLIDATED CONDENSED FINANCIAL STATEMENTS	2
	Unaudited Consolidated Balance Sheets as of March 31, 2012 and June 30, 2011	2
	Unaudited Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011, and for the nine months ended March 31, 2012 and 2011	3
	Unaudited Consolidated Statements of Cash Flows for the nine months ended March 31, 2012 and 2011	4
	Unaudited Notes to Consolidated Condensed Financial Statements	5
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	12
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	20
ITEM 4.	CONTROLS AND PROCEDURES	21
PART II. OTHER INFORMATION		21
ITEM 1.	LEGAL PROCEEDINGS	21
ITEM 1A.	RISK FACTORS	21
ITEM 2.	UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS	22
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	22
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	22
ITEM 5.	OTHER INFORMATION	22
ITEM 6.	EXHIBITS	22
SIGNATURES		23

 

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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,
		2012			2011
Assets
Current assets
Cash and cash equivalents		$	15,223,417		$	4,247,438
Certificates of deposit		250,000			250,000
Restricted cash from joint interest partner		60,565			118,194
Receivables
Oil and natural gas sales		2,082,481			1,559,404
Joint interest partner		20,622			86,105
Income taxes		20,224			28,680
Other		311			167
Prepaid expenses and other current assets		149,275			67,852
Total current assets		17,806,895			6,357,840
Property and equipment, net of depreciation, depletion, and amortization
Oil and natural gas properties — full-cost method of accounting, of which $695,544 and $2,940,199 at March 31, 2012 and June 30, 2011, respectively, were excluded from amortization.		35,189,511			33,447,564
Other property and equipment		89,943			69,262
Total property and equipment		35,279,454			33,516,826
Other assets		260,753			77,287
Total assets		$	53,347,102		$	39,951,953
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable		$	534,544		$	514,177
Joint interest advances		60,565			105,567
Accrued compensation		620,099			682,850
Royalties payable		529,335			742,651
Income taxes payable		116,224			82,122
Other current liabilities		61,493			84,565
Total current liabilities		1,922,260			2,211,932
Long term liabilities
Deferred income taxes		5,308,762			3,330,266
Asset retirement obligations		945,265			859,586
Deferred rent		74,297			85,412
Unsecured revolving credit agreement		—			—
Total liabilities		8,250,584			6,487,196
Commitments and contingencies (Note 10)
Stockholders’ equity
Preferred stock, par value $0.001; 5,000,000 shares authorized: 8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued and outstanding at March 31, 2012, with a total liquidation preference of $7,932,975 ($25.00 per share)		317			—
Common stock; par value $0.001; 100,000,000 shares authorized and 28,605,163 shares issued; outstanding 27,816,963 shares and 27,612,916 shares at March 31, 2012 and June 30, 2011, respectively.		28,605			28,400
Additional paid-in capital		28,817,290			20,761,209
Retained earnings		17,132,328			13,557,170
		45,978,540			34,346,779
Treasury stock, at cost, 788,200 shares as of March 31, 2012 and June 30, 2011.		(882,022		)	(882,022		)
Total stockholders’ equity		45,096,518			33,464,757
Total liabilities and stockholders’ equity		$	53,347,102		$	39,951,953

 

See accompanying unaudited notes to consolidated condensed 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,
		2012			2011			2012			2011
Revenues
Crude oil		$	4,532,942		$	1,607,521		$	12,212,738		$	3,034,333
Natural gas liquids		128,319			228,050			499,745			669,463
Natural gas		187,273			181,504			667,609			661,807
Total revenues		4,848,534			2,017,075			13,380,092			4,365,603
Operating Costs
Lease operating expenses		662,461			284,577			1,277,848			950,382
Production taxes		15,165			26,308			47,925			54,084
Depreciation, depletion and amortization		316,665			132,516			834,351			358,963
Accretion of asset retirement obligations		20,124			16,233			56,712			43,314
General and administrative expenses *		1,560,658			1,359,161			4,454,091			3,976,115
Total operating costs		2,575,073			1,818,795			6,670,927			5,382,858
Income (loss) from operations		2,273,461			198,280			6,709,165			(1,017,255		)
Other income (expense)
Interest income		6,205			1,562			20,163			13,034
Deferred loan cost amortization and bank fees		(5,577		)	—			(5,577		)	—
Net income (loss) before income tax benefit		2,274,089			199,842			6,723,751			(1,004,221		)
Income tax (provision) benefit		(805,989		)	(29,416		)	(2,686,778		)	227,778
Net Income (loss) attributable to the Company		$	1,468,100		$	170,426		$	4,036,973		$	(776,443	)
Dividends on Preferred Stock		168,575			—			461,815			—
Earnings (loss) attributable to common shareholders		$	1,299,525		$	170,426		$	3,575,158		$	(776,443	)
Basic		$	0.05		$	0.01		$	0.13		$	(0.03	)
Diluted		$	0.04		$	0.01		$	0.11		$	(0.03	)
Weighted average number of common shares
Basic		27,816,963			27,521,957			27,759,487			27,379,023
Diluted		31,785,184			30,833,505			31,558,152			27,379,023

*General and administrative expenses for the three months ended March 31, 2012 and 2011 included non-cash stock-based compensation expense of $354,469 and $392,533, respectively.  For the corresponding nine month periods’ non-cash stock-based compensation expense was $1,126,034 and $1,143,413, respectively.

 

See accompanying unaudited notes to consolidated condensed financial statements.

 

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

 

		Nine Months Ended March 31,
		2012			2011
Cash flows from operating activities
Net Income (loss) attributable to the Company		$	4,036,973		$	(776,443	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		837,673			358,963
Stock-based compensation		1,126,034			1,143,413
Accretion of asset retirement obligations		56,712			43,314
Payments on asset retirement obligations		(30,969		)	(1,847		)
Deferred income taxes		1,978,496			(261,965		)
Deferred rent		(11,115		)	2,833
Other		—			32,080
Changes in operating assets and liabilities:
Receivables from oil and natural gas sales		(523,077		)	(526,375		)
Receivables from income taxes and other		8,346			1,125,374
Due from joint interest partner		78,110			(230,227		)
Prepaid expenses and other current assets		(81,423		)	(70,060		)
Accounts payable and accrued expenses		32,397			273,286
Royalties payable		(213,316		)	433,113
Income taxes payable		34,102			(7,683		)
Net cash provided by (used in) operating activities		7,328,943			1,537,776
Cash flows from investing activities
Proceeds from asset sale		103,184			231,326
Development of oil and natural gas properties		(2,386,332		)	(2,320,102		)
Acquisitions of oil and natural gas properties		(304,272		)	(814,323		)
Capital expenditures for other property and equipment		(47,475		)	—
Maturities of certificates of deposit		—			1,100,000
Other assets		(27,295		)	(25,532		)
Net cash used in investing activities		(2,662,190		)	(1,828,631		)
Cash flows from financing activities
Proceeds from the issuance of restricted stock		—			28
Proceeds from the exercise of stock options		—			106,049
Proceeds from issuances of preferred stock, net		6,930,535			—
Preferred stock dividends paid		(461,815		)	—
Deferred loan costs		(159,494		)	—
Net cash provided by financing activities		6,309,226			106,077
Net increase (decrease) in cash and cash equivalents		10,975,979			(184,778		)
Cash and cash equivalents, beginning of period		4,247,438			3,138,259
Cash and cash equivalents, end of period		$	15,223,417		$	2,953,481

 

Our supplemental disclosures of cash flow information for the nine months ended March 31, 2012 and 2011 are as follows:

 

		Nine Months Ended
		March 31,
		2012			2011
Income taxes paid		$	610,000		$	152,000
Income tax refunds and carry backs received		$	28,680		$	979,177
Non-cash transactions:
Decrease in accounts payable used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties		$	(97,853	)	$	(196,557	)
Increase in accounts payable related to joint venture activities		$	—		$	144,942
Oil and natural gas properties incurred through recognition of asset retirement obligations		$	(59,936	)	$	(25,115	)

 

See accompanying unaudited notes to consolidated condensed financial statements.

 

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Evolution Petroleum Corporation and Subsidiaries

Unaudited Notes to Consolidated Condensed Financial Statements

 

Note 1 — Organization and Basis of Preparation

 

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

 

Interim Financial Statements.  The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).  Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations.  All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included.  The interim financial information and notes hereto should be read in conjunction with the Company’s 2011 Annual Report on Form 10-K for the fiscal year ended June 30, 2011, as filed with the SEC. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.

 

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

 

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

 

Note 2 — Property and Equipment

 

As of March 31, 2012 and June 30, 2011 our oil and natural gas properties and other property and equipment consisted of the following:

 

		March 31, 2012			June 30, 2011
Oil and natural gas properties
Property costs subject to amortization		$	40,654,659		$	35,860,517
Less: Accumulated depreciation, depletion, and amortization		(6,160,702		)	(5,353,152		)
Unproved properties not subject to amortization		695,554			2,940,199
Oil and natural gas properties, net		$	35,189,511		$	33,447,564
Other property and equipment
Furniture, fixtures and office equipment, at cost		$	308,814		$	261,340
Less: Accumulated depreciation		(218,871		)	(192,078		)
Other property and equipment, net		$	89,943		$	69,262

 

Unproved properties not subject to amortization includes: unevaluated acreage of $0.7 million and $2.9 million as of March 31, 2012 and June 30, 2011, respectively, of which (i) $0.7 million as of March 31, 2012 and June 30, 2011, related to our interests in the Delhi Field in Louisiana; and (ii) $6,000 and $2.2 million as of March 31, 2012 and June 30, 2011, respectively, related to Woodford Shale trend in Oklahoma.  Development of our unproved properties is expected to be completed within five years.  Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis.  During the nine months ended March 31, 2012, our

 

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evaluations determined that approximately $2.2 million of our unevaluated Woodford Shale trend property was impaired and, accordingly, was moved to the full cost pool.

 

During the quarter the Company sold a portion of its Woodbine lease rights and realized net proceeds of $103,184 and recorded a corresponding reduction to its full cost pool.  There were no proved reserves associated with these rights.

 

Note 3 — Joint Interest Drilling Arrangement

 

In July 2010, we entered into a drilling arrangement with an industry partner to drill up to five horizontal development wells in the Giddings Field in central Texas.  Our industry partner has funded $7.7 million through March 31, 2012, their portion of the approval for expenditure (“AFE’) for three wells, including a sales line.  As of March 31, 2012, $60,565 of their funding has yet to be expended with respect to those wells.  We have billed our industry partner $20,622 for operating expense recovery and costs incurred for their share of costs.  Amounts pertaining to our industry partner’s share of the joint interest drilling arrangement included in our balance sheet as of March 31, 2012, are as follows:

 

Restricted cash from joint interest partner		$	60,565
Amounts due from joint interest partner		20,622
Accounts payable		8,910
Joint interest advances		60,565

 

Note 4 — Asset Retirement Obligations

 

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligation for the nine months ended March 31, 2012:

 

Asset retirement obligations — beginning of period		$	859,586
Accretion expense		56,712
Payments on asset retirement obligations		(30,969		)
Acquisition of oil and gas properties		153,668
Revision of estimate		(93,732		)
Asset retirement obligations — end of period		$	945,265

 

Note 5 — Stockholders’ Equity

 

Common Stock

 

On September 9, 2011, a contractor of the Company net exercised 20,000 stock options issued under the 2004 Stock Plan for a net issuance of 7,941 shares of our common stock.  The options were granted in March 2008 at an exercise price of $4.10 per share.

 

On August 31, 2011, the Board of Directors authorized the issuance of 161,861 shares of restricted common stock from the 2004 Stock Plan to all employees as a long-term incentive award.  Total unrecognized stock-based compensation expense of $1,029,436 related to the long-term incentive award will be recognized ratably over a four year period as, if and when the restricted common stock vests.

 

On December 5, 2011, a total of 34,245 shares of our restricted common stock were issued pursuant to the 2004 Stock Plan to five outside directors as part of their annual board compensation for calendar year 2012.  The value of the shares issued was $249,955, based on the fair market value on the date of issuance.  All issuances of our common stock were subject to vesting terms per individual stock agreements, which is one year for directors.

 

See Note 6.

 

Series A Cumulative Perpetual Preferred Stock

 

During the nine months ended March 31, 2012, we sold 317,319 shares of our 8.5% Series A Cumulative (perpetual) Preferred Stock at a weighted average sales price of $23.80 per share, with a liquidation preference of $25.00 per share.   All shares were underwritten or sold through McNicoll Lewis & Vlak LLC (MLV), 220,000 of which were sold in an underwritten public offering and 97,319 shares of which were sold under an at-the-market sales agreement (ATM), providing aggregate net proceeds of $6,930,535 after- market discounts, underwriting fees, legal and other expenses of the offerings.  The Series A Cumulative Preferred Stock cannot be converted into our common stock and there are no sinking fund or redemption rights available to holders thereof.  Optional

 

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redemption can only be made by us on or after July 1, 2014 for the stated liquidation value of $25.00 per share plus accrued dividends, or by an acquirer under a change of control prior to such date at redemption prices ranging from $25.25 to $25.75 per share.  With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common shareholders, but subordinate to any of our existing and future debt.  Dividends on the Series A Cumulative Preferred Stock accrue and accumulate at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly at $0.177083 per share, as, if and when declared by our Board of Directors.

 

During the nine months ended March 31, 2012, we paid dividends of $461,815 to holders of our Series A Preferred Stock.

 

Note 6 — Stock-Based Incentive Plan

 

We have granted option awards to purchase common stock (the “Stock Options”), restricted common stock awards (“Restricted Stock”), and/or unrestricted fully vested common stock, to employees, directors, and consultants of the Company and its subsidiaries under the Natural Gas Systems Inc. 2003 Stock Plan (the “2003 Stock Plan”) and the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the “2004 Stock Plan” or together, the “EPM Stock Plans”).  Option awards for the purchase of 600,000 shares of common stock were issued under the 2003 Stock Plan.  The 2004 Stock Plan authorized the issuance of 5,500,000 shares of common stock with an additional 1,000,000 shares authorized by a December 5, 2011 plan amendment approved by a vote of our shareholders.  No shares are available for grant under the 2003 Stock Plan and 1,012,111 shares remain available for grant under the 2004 Stock Plan as of March 31, 2012.

 

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

 

Stock Options and Incentive Warrants

 

Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the three months ended March 31, 2012 and 2011 was $49,252 and $172,728, respectively.  For the nine months ended March 31, 2012, and 2011, non-cash stock-based compensation expense related to Stock Options and Incentive Warrants was $281,390 and $542,299, respectively.

 

There were no Stock Options granted during the nine months ended March 31, 2012 and 2011.

 

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

 

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The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of March 31, 2012, and the changes during the fiscal year:

 

		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, 2011		5,392,820		$	1.84
Granted		—		—
Exercised		(20,000	)	$	4.10
Cancelled or forfeited		—		—
Expired		—		—
Stock Options and Incentive Warrants outstanding at March 31, 2012		5,372,820		$	1.83		$	40,114,930		3.7
Vested or expected to vest at March 31, 2012		5,372,820		$	1.83		$	39,926,985		3.7
Exercisable at March 31, 2012		5,337,191		$	1.82		$	40,114,930		3.7

(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($9.30 as of March 30, 2012) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

 

There were 20,000 Stock Options exercised during the nine months ended March 31, 2012 with an aggregate intrinsic value of $54,000.  There were 86,875 Stock Options that were exercised during the nine months ended March 31, 2011, with an aggregate intrinsic value of $493,923.

 

A summary of the status of our unvested Stock Options and Incentive Warrants as of March 31, 2012 and the changes during the nine months ended March 31, 2012, is presented below:

 

		Number of Stock Options and Incentive Warrants		Weighted Average Grant- Date Fair Value
Unvested at July 1, 2011		173,877		$	2.20
Granted		—		—
Vested		(138,248	)	$	2.14
Forfeited		—		—
Unvested at March 31, 2012		35,629		$	2.41

 

During the nine months ended March 31, 2012 and 2011, there were 138,248 and 289,498 Stock Options and Incentive Warrants that vested with a total grant date fair value of $295,851 and $576,101, respectively.

 

The total unrecognized compensation cost at March 31, 2012, relating to non-vested Stock Options and Incentive Warrants was $72,659.  Such unrecognized expense is expected to be recognized over a weighted average period of 0.44 years.

 

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Restricted Stock

 

Stock-based compensation expense related to Restricted Stock grants for the three months ended March 31, 2012 and 2011 was $305,217 and $219,805, respectively.  Stock-based compensation expense related to Restricted Stock grants for the nine months ended March 31, 2012 and 2011 was $844,644 and $601,114, respectively.

 

The following table sets forth the Restricted Stock transactions for the nine months ended March 31, 2012:

 

		Number of Restricted Shares		Weighted Average Grant-Date Fair Value
Unvested at July 1, 2011		495,689		$	4.30
Granted		196,106		$	6.52
Vested		(176,324	)	$	4.57
Forfeited		—		—
Unvested at March 31, 2012		515,471		$	5.06

 

At March 31, 2012, unrecognized stock compensation expense related to Restricted Stock grants totaled $2,422,316.  Such unrecognized expense will be recognized over a weighted average period of 2.47 years.

 

Note 7 — Income Taxes

 

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

 

There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the nine months ended March 31, 2012.  We believe that we have appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the years ending June 30, 2007 through June 30, 2011.

 

The Company recognized income tax expense of $805,989 and $29,416 for the three months ended March 31, 2012 and 2011,  respectively, with corresponding effective rates of  35.4% and 14.7%.  We recognized income tax expense of $2,686,778 in the nine months ended March 31, 2012 compared to an income tax benefit of $227,778 for the nine months ended March 31, 2011.  Effective tax rates for these 2012 and 2011 nine-month periods were 40.0% and 22.7% respectively.

 

Our effective tax rate for any period may differ from the statutory federal rate due to our state income tax liability in Louisiana and due to stock-based compensation expense related to qualified incentive stock option awards (“ISO awards”), both of which create a permanent tax difference for financial reporting, as these types of awards, if certain conditions are met, are not deductible for federal tax purposes.  The effective tax rate for the nine months ended March 31, 2011 was also affected by additional income tax expense recorded in December 2011 in connection with finalizing the Company’s June 30, 2010 income tax returns.

 

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Note 8 — Net Income (loss) Per Share

 

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

 

		Three Months Ended March 31,						Nine Months Ended March 31,
		2012			2011			2012			2011
Numerator
Net income (loss) attributable to common shareholders		$	1,299,525		$	170,426		$	3,575,158		$	(776,443	)
Denominator*
Weighted average number of common shares — Basic		27,816,963			27,521,957			27,759,487			27,379,023
Effect of dilutive securities:
Common stock warrants issued in connection with equity and financing transactions		66,826			110,940			62,684			—
Stock Options and Incentive Warrants		3,901,395			3,200,608			3,735,981			—
Total weighted average dilutive securities		3,968,221			3,311,548			3,798,665			—
Weighted average number of common shares and dilutive potential common shares used in diluted EPS		31,785,184			30,833,505			31,558,152			27,379,023
Net income (loss) per common share — Basic		$	0.05		$	0.01		$	0.13		$	(0.03	)
Net income (loss) per common share — Diluted		$	0.04		$	0.01		$	0.11		$	(0.03	)

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

 

Outstanding potentially dilutive securities, before adjustment for net exercise, as of March 31, 2012 are as follows:

 

Outstanding Potential Dilutive Securities		Weighted Average Exercise Price			Outstanding at March 31, 2012
Common stock warrants issued in connection with equity and financing transactions		$	2.50		92,635
Stock Options and Incentive Warrants		$	1.83		5,372,820
Total		$	1.84		5,465,455

 

Outstanding potentially dilutive securities as of March 31, 2011 are as follows:

 

Outstanding Potential Dilutive Securities		Weighted Average Exercise Price			Outstanding at March 31, 2011
Common stock warrants issued in connection with equity and financing transactions		$	1.87		159,308
Stock Options and Incentive Warrants		$	1.85		5,392,820
Total		$	1.85		5,552,128

 

Note 9 - Unsecured Revolving Credit Agreement

 

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

 

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

 

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

 

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

 

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

 

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

 

As of March 31, 2012, the Company had no borrowings and no outstanding letters of credit issued under the facility, resulting in an available borrowing base capacity of $5,000,000.  The Company was in compliance with all the covenants of the Credit Agreement.

 

In connection with this agreement the Company incurred $159,494 of debt issuance costs, which have been capitalized in Other Assets and are being amortized on a straight-line basis over the term of the agreement.

 

Note 10 — Commitments and Contingencies

 

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

 

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on August 1, 2016. Future minimum lease commitments as of March 31, 2012 under this operating lease are as follows:

 

For the twelve months ended March 31,
2012		$	159,011
2013		159,011
2014		159,011
2015		159,011
Thereafter		52,203
Total		$	688,247

 

Rent expense for the three months ended March 31, 2012 and 2011 was $36,808 and $36,808, respectively.  For the nine months ended March 31, 2012 and 2011 rent expense was $110,425 and $109,455, 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, 2012 is approximately $588,000.

 

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Note 11 — Subsequent Events

 

Effective April 17, 2012, a wholly owned subsidiary of the Company entered into definitive agreements with Orion Exploration Partners, LLC (“Orion”) to acquire and develop an undivided 45% interest in oil and gas leases, associated surface rights and related assets located in the Mississippian Lime formation aggregating 11,700 acres (5,265 net acres) in 38 sections in Kay County, Oklahoma.  The Company has agreed to contribute cash and a drilling carry to earn its 45% non-operating interest in the joint venture.  Orion is contributing the leases, its portion of the drilling capital, its operating expertise in the area and the Mississippian Lime play.

 

In April we made our initial $4,083,780 cash outlay for the purchase of our 45% share of the JV leasehold and partial prepayment of our drilling and completion costs of the first three commitment wells.  Our acquisition cost also includes carrying our partner for a minor portion of their drilling and completion costs over the next year, not to exceed approximately $2.2 million.

 

Not including any future leases acquired though forced pooling or other additions, the Company’s initial interests are estimated to have up to 25 to 33 potential drilling locations net to the Company, subject to ultimate spacing per horizontal well, including water disposal facilities.  Field operations are expected to begin in May 2012 with the drilling of a water disposal well, followed by the scheduled drilling of two producer wells.  The agreement commits the parties to drill between six and fourteen gross wells over the next twelve months.

 

In April and May 2012, the Company received proceeds totaling $669,845, and the retention of overrides and back-in interests, for the farmout of some of its Woodbine rights at Giddings.

 

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 2011 Annual Report on Form 10-K for the year ended June 30, 2011 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.

 

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

 

Executive Overview

 

General

 

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

 

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

 

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

 

Highlights for our Third Quarter Fiscal 2012 and Project Update

 

Our fiscal year is June 30.  As used below:

 

“Q3-12” & “current quarter” is the three months ended March 31, 2012, the company’s 3rd quarter of fiscal 2012.

 

“Q2-12” & “prior quarter” is the three months ended December 31, 2011, the company’s 2nd quarter of fiscal 2012.

 

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“Q3-11” & “year-ago quarter” is the three months ended March 31, 2011, the company’s 3rd quarter of fiscal 2011.

 

Operations

 

·                  Q3-12 earnings to common shareholders increased 3.1% sequentially to $1.3 million over the prior quarter, while increasing 663% from $0.2 million in the year-ago quarter. Sequentially, BOE sales volumes increased 8% on 9% lower field margins.  Lower margins were due to lower average product prices and higher production costs as further described below.

 

·                  Revenues increased 4.3% sequentially to $4.8 million from $4.6 million in the prior quarter, while increasing 140% from $2.0 million in the year-ago quarter.  The revenue increase over the prior quarter was primarily due to higher oil and natural gas volumes offset by lower NGL and natural gas prices.  The revenue increase over the year-ago quarter was due to increases in oil and gas sales volumes and higher oil prices that more than offset lower NGL volumes and lower prices for NGL and natural gas.

 

·                  Crude oil and NGL volumes accounted for 77% of total sales volumes and 96% of revenues during Q3-12, essentially unchanged from and higher than the 73% share of sales volumes and 91% of revenues in the year-ago quarter.  Total liquids volumes increased 7% sequentially over the prior quarter and 106% over the year-ago quarter, primarily due to increasing crude oil sales from Delhi.  Natural gas volumes also increased 9% sequentially due to workovers at Giddings, and increased 65% over the year-ago quarter primarily due to added production from development wells drilled during fiscal 2011 at Giddings.

 

·                  The blended product price we received in Q3-12 decreased 3% sequentially to $86.08 per BOE from $88.84 in the prior fiscal quarter, while increasing 23% over the $69.94 per BOE received in the year-ago quarter.  Oil prices in the current quarter decreased 1% sequentially to $111.71 per barrel, while increasing 15% over the year-ago quarter.  Our average oil price reflects the large proportion of sales that received favorable Louisiana Light Sweet pricing.  NGL prices decreased 28% sequentially and 16% over the year-ago quarter to $42.15 per barrel.  Meanwhile, natural gas prices decreased 26% sequentially and 38% from the year-ago quarter to $2.46 per MCF.

 

·                  Field margins declined to $68 per BOE compared to $75 in the prior quarter, while increasing 26% from $54 in the year-ago quarter.  Sequentially over the prior quarter, revenue per BOE was lower, and lease operating expense per BOE was higher.  Higher LOE was due in part to continued well work in our Lopez Field to determine an optimum water disposal methods, and in the Giddings Field lease operating expense was impacted by conversion of a well from pumping unit to gas lift and a temporary higher water disposal cost while our wholly owned water disposal well was undergoing servicing.  The improvement in pretax margin per BOE over the year-ago quarter was driven primarily by increased crude oil volumes from our non-cost bearing interests and higher oil prices that offset higher lease operating costs.

 

Projects

 

We are currently active in five primary areas:  an enhanced oil recovery project in northeast Louisiana’s “Delhi Field” that is operated by an industry partner, non-operating leasehold interests in the Mississipian Lime play of Oklahoma, producing oil wells that we operate in the “Lopez Field” of south Texas, producing horizontal wells that we generally operate in the “Giddings Field” of central Texas, and commercialization of our artificial lift technology (“GARP™”).

 

Delhi EOR Project

 

·                  Q3-12 sales volumes at Delhi increased 9.5% sequentially to 405 net barrels of oil per day (5,474 gross BOPD) from 366 net BOPD (4,946 gross BOPD) in the prior quarter, while increasing 177% from 148 net BOPD (2,003 gross BOPD) in the year-ago quarter.

 

·                  Field development and facility installations at Delhi exceeded calendar 2011’s field plan.  As originally planned for calendar 2011 by Denbury as operator, a third test site was installed, 39 wells were completed and an oil production response was achieved from the newly installed site.  As an expansion to the 2011 plan, field development was accelerated through the completion of 11 additional wells associated with the newly installed third test site, while 9 wells associated with the planned fourth test site were completed awaiting that test site’s construction that began in December 2011. The expansion of 2011 field development impacted the timing of projected production contributions from development work completed in 2011.

 

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·                  According to the operator, produced oil gravity is supporting the current projection of a highly miscible flood and potentially better sweep efficiency, both of which suggest improved ultimate recoveries.  Produced oil gravity has remained relatively level at approximately 43 degrees gravity, positive indications that no patterns have reached peak production and miscibility is high.

 

·                  The project was modified in 2011 by adding water re-injection to increase field performance. A plan was implemented early in calendar 2011 by the operator to re-inject produced water back into the producing reservoir instead of a separate reservoir.  Nine injection wells have been drilled down-dip to help maintain reservoir pressure, consequently substantially reducing the required amount of purchased CO2 volumes.    Since purchased CO2 is a major component of operating expense, reduced CO2 purchases can positively impact payout timing of our reversionary working interest, increase profitability and improve overall economics of the project.

 

·                  Delhi crude oil sales continued to benefit from Louisiana Light Sweet pricing (LLS), averaging 10% higher than WTI prices during Q3-12.  The $113 per barrel average price we received at Delhi in Q3-12 was $10 higher than the $103 daily average spot price for WTI delivered at Cushing. We believe that a material premium over WTI for Delhi’s oil may continue over the near term, subject to market factors.

 

Mississippi Lime (Northcentral Oklahoma) - Recent Developments

 

In April 2012, we entered Oklahoma’s Mississippian Lime play as a near term re-investment vehicle for current and projected cash flows from Delhi.  We chose the Mississippian Lime play based on rigid screening criteria that included:

 

·      Fields with known oil resources established by previous vertical wells and suitable for horizontal development

 

·      Reasonable entry cost

 

·      Lowered drilling risk through a partial interest in modest well costs in a statistical play that reduces single event risk

 

·      Compelling pretax economics that are supplemented by application of drilling tax attributes

 

·      Onshore U.S. location that is reasonably accessible and within our region of experience

 

·      Utilization of our engineering and horizontal drilling expertise that could complement the skills of a partner

 

·      Preference toward scalable black oil plays at shallower depths that are “drill ready”

 

In our analysis, the Mississippian Lime play met all of these criteria.  We began joint venture negotiations in December 2011 with a private equity backed partner in Tulsa that is highly focused on the play and an active operator in the area.  The joint venture agreements were executed in April 2012 and initially includes 11,700 net acres within the oily region of the Mississippian Lime play in central Kay County in northcentral Oklahoma that is well defined by historic vertical well production.  The leasehold spans 38 sections with over 24,000 gross acres within an area of mutual interest (AMI), and the leasehold may be expanded through forced pooling, additional open leasing and acquisitions.  The AMI is located just east of the Nemaha Ridge where Range Resources is active, and to the west of the Osage/Kay County line where Halcon recently acquired ~150,000 acres. Multiple industry operators are actively developing the play on all sides of the joint venture leasehold and several horizontal wells have already been completed with good results on three sides of the leasehold.

 

Our initial $4 million cash outlay included the purchase of our 45% share of the JV leasehold and prepayment of a portion of our drilling and completion costs of the first three commitment wells.  Our acquisition cost also includes carrying our partner for a minor portion of their drilling and completion costs over the next year, not to exceed approximately $2 million.

 

Drilling is expected to begin in May 2012 on a salt water disposal well and a second rig is contracted to drill two back-to-back producer wells beginning shortly thereafter.  Including these three wells, the JV agreement commits the partners to drill between six and fourteen gross wells over the first 12 months.

 

We expect that our projected net capital expenditures will be funded by internal sources, including $0.7 million in proceeds we subsequently received through May 2012 for the farmout of some of our Woodbine rights at Giddings.

 

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Lopez Field (South Texas)

 

We continued our testing of high fluid production rates and corresponding high water re-injection rates in the Lopez Field.  Based on the success of our high fluid rate production test during the summer of 2011, we drilled two new producer wells and two salt water injection wells during Q2-12.  However, obtaining consistent high re-injection rates has been an operational challenge and we have been working closely with service companies on the best solutions. We now believe that a combination of acid treatment, higher injection pressure and utilization of an additional salt water disposal reservoir will resolve this hurdle and allow full production.

 

Two of the producing wells are currently producing at planned fluid rates and the third is pending.  Early results suggest that the projected oil cut in the produced fluid is attractive and, consequently, we are planning to renew drilling operations in Lopez in late fiscal 2012.

 

GARP™ (Gas Assisted Rod Pump)

 

Two GARP™ commercialization demonstrations with industry partners are underway.  As reported last quarter, we expected to install GARP™ demonstrations with each of two industry partners by calendar 2011year-end.   The first application was successfully installed and placed onto production on December 2, 2011.  Production testing is ongoing; initial rates are positive and suggest that the technology has extended the life of the previously marginal well and leases for many years, and has potentially added up to 25% more reserves. The results to date have exceeded our stated goals.

 

Due to our staff focusing on extended development work in the Lopez Field, our second commercial demonstration was delayed about one month. Following installation during the recent quarter, production testing is now underway and preliminary results are positive to date.

 

In both demonstration agreements, we are paying the cost of the technology installation and are operating the wells, in return for an equity ownership equivalent to a 50% net profits interest in the first well’s producing formation, and a 99% before payout and 76% after payout working interest in the second well and leases.

 

Giddings Field (Central Texas)

 

Production increased at Giddings due to multiple well workovers and production results from wells put into service in Q3-11.  Sales volumes at Giddings increased 5% sequentially from the prior quarter to 210 BOE per day, mostly due to successful well workovers, and 24.5% over the year-ago quarter due to 0.6 new net wells (3 gross) being brought online in fiscal Q2-11 and Q3-11. Further drilling has been adversely impacted by low natural gas prices.  With remaining PUDs averaging less than 50% oil and NGLs, we are exploring options to maximize our Giddings asset values, including a possible monetization.

 

Woodford Shale (Oklahoma)

 

Despite our success in the western portion of our Wagoner County leasehold and our first vertical test well in our Haskell County leasehold, continued low natural gas prices have led us to keep these projects on hold while considering other options, including a sale of the leases.

 

Finances

 

·                  Working capital increased to $15.9 million compared to $13.9 million at December 31, 2011.  The increase was due to operational cash flows.

 

·                  No shares of Series A Preferred Stock were offered or sold in the recent quarter.  As previously reported, we believe access to this non-convertible perpetual security is a complement to our low risk financing philosophy of remaining debt free, while providing an expandable platform to raise funds as needed to bridge new petroleum investments, market conditions permitting.

 

·                  We initiated an unsecured, senior revolving credit facility with an initial capacity of $5 million.  No amounts have been drawn on this facility, as it remains a backup source of liquidity, primarily to meet any short term needs arising from area of mutual interest agreements we are a party to.

 

·                  We remained debt free and in financial control of our assets.

 

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Liquidity and Capital Resources

 

At March 31, 2012, our working capital was $15.9 million, compared to working capital of $4.1 million at June 30, 2011.  The $11.8 million increase in working capital since June 30, 2011 was due primarily to $6.9 million of net proceeds from sales of our 8.5% Series “A” perpetual non-convertible preferred stock and $8.0 million provided by operations before changes in working capital, partially offset by $2.7 million invested in oil and natural gas properties and the payment of $0.5 million of preferred stock dividends.

 

Cash Flows from Operating Activities

 

For the nine months ended March 31, 2012, cash flows provided by operating activities were $7.3 million, reflecting $8.0 million provided by operations before $0.7 million was used in working capital.  Of the $8.0 million provided, $4.0 million was attributable to net income, $2.0 million from non-cash expenses and $2.0 million from deferred income taxes.

 

For the nine months ended March 31, 2011, operating activities provided $1.5 million of cash flows, reflecting $1.0 million provided by working capital and $0.5 million provided before working capital items resulting from non-cash expenses of $1.5 million partly offset by $0.8 million net loss.

 

Cash Flows from Investing Activities

 

Cash paid for oil and gas capital expenditures during the nine months ended March 31, 2012 and 2011, was $2.7 million and $3.1 million, respectively.  Of the oil and gas capital expenditures during the nine months ended March 31, 2012, $0.3 million was for leasehold acquisitions and $2.4 million was for development activities.  Development expenditures were primarily in the Lopez Field where four new wells were drilled in the previous quarter. Remaining expenditures were mostly in the Giddings Field, including a workover on the Dodd well and installation of our GARP™ technology.

 

Oil and gas capital expenditures incurred were $2.6 million and $2.9 million, respectively, for the nine months ended March 31, 2012 and 2011.  These amounts can be reconciled to cash capital expenditures on the cash flow statement by adjusting them for their respective for changes in accounts payable for capital expenditures as represented in the statement’s supplemental information.

 

During the nine months ended March 31, 2012, we received $0.1 million for the sale of a portion of our Woodbine lease rights, while in the corresponding 2011 period we received $0.2 million from the sales of a Giddings lease.

 

During the nine months ended March 31, 2012, an expiring $0.25 million CD was rolled over commencing a new annual term.   During the nine months ended March 31, 2011, $1.1 million of certificates of deposit matured.

 

Cash Flows from Financing Activities

 

During the nine months ended March 31, 2012, we received $6.9 million of net proceeds from the issuance of 317,319 shares of our 8.5% Series A perpetual preferred stock after all offering costs and we paid $0.5 million of dividends thereon.  In connection with the unsecured revolving credit agreement entered into February 2012, the company incurred deferred loan costs of $159,494.

 

During the nine months ended March 31, 2011, we received $0.1 million due to the exercise of stock options.

 

Capital Budget

 

During the first nine months of fiscal 2012, we have incurred approximately $2.7 million of capital expenditures and currently expect that fiscal 2012 expenditure will be approximately, $8 million to $9 million, the increase resulting from our recently announced Mississippian Lime joint venture. Our approved fiscal 2012 Base Plan provides for capital expenditures of $4 million to as much as $12 million, which can be fully funded from our existing working capital of $15.9 million at March 31, 2012.  We expect to fund any increases over the fiscal 2012 Base Plan out of working capital, internally generated funds from operations, joint ventures, project financing, selective divestments of noncore assets or other appropriate financings, including possible additional issuances of our Series A perpetual non-convertible preferred stock.

 

Results of Operations

 

Three month period ended March 31, 2012 and 2011

 

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

 

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		Three Months Ended
		March 31									%
		2012			2011			Variance			change
Sales Volumes, net to the Company:
Crude oil (Bbl)		40,576			16,604			23,972			144.4	%
NGLs (Bbl)		3,044			4,533			(1,489		)	(32.8	)%
Natural gas (Mcf)		76,244			46,220			30,024			65.0	%
Crude oil, NGLs and natural gas (BOE)		56,327			28,840			27,487			95.3	%
Revenue data:
Crude oil		$	4,532,942		$	1,607,521		$	2,925,421		182.0	%
NGLs		128,319			228,050			(99,731		)	(43.7	)%
Natural gas		187,273			181,504			5,769			3.2	%
Total revenues		$	4,848,534		$	2,017,075		$	2,831,459		140.4	%
Average price:
Crude oil (per Bbl)		$	111.71		$	96.82		$	14.89		15.4	%
NGLs (per Bbl)		42.15			50.31			(8.16		)	(16.2	)%
Natural gas (per Mcf)		2.46			3.93			(1.47		)	(37.5	)%
Crude oil, NGLs and natural gas (per BOE)		$	86.08		$	69.94		$	16.14		23.1	%
Expenses (per BOE)
Lease operating expenses and production taxes		$	12.03		$	10.78		$	1.25		11.6	%
Depletion expense on oil and natural gas properties (a)		$	5.38		$	4.31		$	1.07		24.8	%

 

(a)         Excludes depreciation of office equipment, furniture and fixtures, and other of $10,242 and $8,215, for the three months ended March 31, 2012 and 2011, respectively.  For the three months ended March 31, 2012, amortization of deferred loan costs of $3,323 is also excluded.

 

Earnings Attributable to Common Shareholders   For the three months ended March 31, 2012, we generated earnings of $1,299,525 or $0.04 per diluted share (which includes $354,469 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $4,848,534.  This compares to earnings of $170,426, or $0.01 per diluted share (which includes $392,533 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $2,017,075 for the three months ended March 31, 2011.  The difference was primarily due to an increase in crude oil revenues of $2,295,421 partially offset by $756,278 of increased operating expenses, higher income tax expense of $776,573 and preferred dividends of $168,575.  Additional details of earnings components are explained in greater detail below.

 

Sales Volumes.  Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the three months ended March 31, 2012 increased 95% to 56,327 BOE’s compared to 28,840 BOE’s for the three months ended March 31, 2011.  This is primarily due to 177% BOE volume increase in Delhi Field together with a 25% volume improvement for the Giddings Field.  Our crude oil sales volumes for the three months ended March 31, 2012 included 36,886 barrels from our interests in Delhi and 3,691 barrels from our properties in the Giddings and Lopez Field.  Our crude oil sales volumes for the three months ended March 31, 2011 included 13,329 barrels from our interests in Delhi and 3,275 barrels from our properties in the Giddings Field.  Our NGL volumes for the three months ended March 31, 2012 and 2011 were from our properties in the Giddings Field declined 33% to 3,044 barrels and Giddings Fields natural gas volumes increased 29.9 MMCF, or 65%.

 

Petroleum Revenues.  Crude oil, NGLs and natural gas revenues for the three months ended March 31, 2012 increased 140% compared to the three months ended March 31, 2011.  This was due to higher sales volumes as mentioned above along with a 23% increase in the average price received per BOE, from $70 per BOE for the three months ended March 31, 2011 to $86 per BOE for the three months ended March 31, 2012.

 

Lease Operating Expenses (including production severance taxes).  Lease operating expenses and production taxes for the three months ended March 31, 2012 increased to $366,741, or 118%, to $677,626 compared to the three months ended March 31, 2011. The increase was due primarily to higher costs in the Lopez Field due to added wells and optimization work on salt water disposal

 

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