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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)

 

Nevada

 

41-1781991

(State or other jurisdiction of incorporation or organization)

 

(IRS Employer Identification No.)

 

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.

 

Large accelerated filer o

 

Accelerated filer x

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

 

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

 

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

 

 

 



Table of Contents

 

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

 

1



Table of Contents

 

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.

 

2



Table of Contents

 

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.

 

3



Table of Contents

 

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.

 

4



Table of Contents

 

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

 

5



Table of Contents

 

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

 

6



Table of Contents

 

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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Table of Contents

 

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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methods, together with conversion of a Giddings Field producing well from pumping unit to gas lift and temporarily higher water disposal costs while our wholly owned disposal well was being serviced.  Lease operating expense and production tax per barrel of oil equivalent increased 12% from $10.78 per BOE during the three months ended March 31, 2011, to $12.03 per BOE during the three months ended March 31, 2012.

 

General and Administrative Expenses (“G&A”).  G&A expenses increased 15% from $1.4 million during the three months ended March 31, 2011 to $1.6 million during the three months ended March 31, 2012. The increase was due primarily to higher legal, consulting, board fees and bonus expenses.  Stock-based compensation was $354,469 (23% of total G&A) for the three months ended March 31, 2012, compared to $392,533 (29% of total G&A) for the three months ended March 31, 2011.  Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other more established companies, and to retain staff.  As a result, non-cash stock compensation will continue to be a significant component of our G&A costs in the near term.

 

Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A increased by 139% to $316,665 for the three months ended March 31, 2012, compared to $132,516 for the three months ended March 31, 2011. The increase was due to a higher depletion rate ($5.38 vs. $4.31) per BOE and a significant increase in sales volumes as described above. The higher depletion rate was due to the projected acceleration in our working interest reversion date, per the June 30, 2011 reserve report, at Delhi that resulted in our now bearing a pro rata share of capital expenditures for the last phase of development, partially offset by increased proved reserves.

 

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Nine 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:

 

 

 

Nine months Ended

 

 

 

 

 

 

 

March 31

 

 

 

%

 

 

 

2012

 

2011

 

Variance

 

change

 

 

 

 

 

 

 

 

 

 

 

Sales Volumes, net to the Company:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (Bbl)

 

111,250

 

34,670

 

76,580

 

220.9

%

 

 

 

 

 

 

 

 

 

 

NGLs (Bbl)

 

9,711

 

14,621

 

(4,910

)

(33.6

)%

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

206,841

 

163,735

 

43,106

 

26.3

%

Crude oil, NGLs and natural gas (BOE)

 

155,435

 

76,580

 

78,855

 

103.0

%

 

 

 

 

 

 

 

 

 

 

Revenue data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

$

12,212,738

 

$

3,034,333

 

$

9,178,405

 

302.5

%

 

 

 

 

 

 

 

 

 

 

NGLs

 

499,745

 

669,463

 

(169,718

)

(25.4

)%

 

 

 

 

 

 

 

 

 

 

Natural gas

 

667,609

 

661,807

 

5,802

 

0.9

%

Total revenues

 

$

13,380,092

 

$

4,365,603

 

$

9,014,489

 

206.5

%

 

 

 

 

 

 

 

 

 

 

Average price:

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

109.78

 

$

87.52

 

$

22.26

 

25.4

%

NGLs (per Bbl)

 

51.46

 

45.79

 

5.67

 

12.4

%

Natural gas (per Mcf)

 

3.23

 

4.04

 

(0.81

)

(20.1

)%

Crude oil, NGLs and natural gas (per BOE)

 

$

86.08

 

$

57.01

 

$

29.07

 

51.0

%

 

 

 

 

 

 

 

 

 

 

Expenses (per BOE)

 

 

 

 

 

 

 

 

 

Lease operating expenses and production taxes

 

$

8.53

 

$

13.12

 

$

(4.59

)

(35.0

)%

Depletion expense on oil and natural gas properties (a) 

 

$

5.17

 

$

4.35

 

$

0.82

 

18.9

%

 


(a)          Excludes depreciation of office equipment, furniture and fixtures, and other of $26,794 and $25,555 for the nine months ended March 31, 2012 and 2011, respectively.  For the nine months ended March 31, 2012, amortization of deferred loan costs of $3,323 is also excluded.

 

Earnings (Loss) Attributable to Common Shareholders.  For the nine months ended March 31, 2012, we generated earnings of $3,575,158, or $0.11  per diluted share (which includes $1,126,034 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $13,380,092.  This compares to a loss of $776,443, or $0.03 per share, (which includes $1,143,413 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $4,365,603 for the nine months ended March 31, 2011.  The increase in earnings was primarily due to a $9,178,405 increase in crude oil revenue partially offset by increased operating expenses of $1,288,069,  higher income tax expense of $2,914,556 and preferred dividends of $461,815.  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 nine months ended March 31, 2012 increased 103% to 155,435 BOE’s compared to 76,580 BOE’s for the nine months ended March 31, 2011.  This is primarily due to significant production and sales volume increases in Delhi Field together with slight production improvements in Oklahoma, Lopez and the Giddings Fields.  Our crude oil sales volumes for the nine months ended March 31, 2012 included 100,531 barrels from our interests in Delhi and 10,720 barrels from our properties in the Giddings and Lopez Fields.  Our crude oil sales volumes for the nine months ended March 31, 2011 included 24,153 barrels from our interests in Delhi and 10,517 barrels from our properties in the Giddings and Lopez Fields.  Our NGL volumes for the nine months ended March 31, 2012 and 2011 were from our properties in the Giddings Field, and declined 34% to 9,711 barrels.  For the corresponding periods, natural gas volumes, from our Giddings Field and Oklahoma properties increased 26% to 206.8 MMCF.

 

Petroleum Revenues.  Crude oil, NGLs and natural gas revenues for the nine months ended March 31, 2012 increased 207% compared to the nine months ended March 31, 2011.  This was due to higher sales volumes, as mentioned above, along with a 51% increase in

 

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the average price received per BOE, from $57 per BOE for the nine months ended March 31, 2011 to $86 per BOE for the nine months ended March 31, 2012.

 

Lease Operating Expenses (including production severance taxes).  Lease operating expenses and production taxes of $1,325,773 for the nine months ended March 31, 2012 increased $321,307, or 32%, compared to $1,004,466 for the nine months ended March 31, 2011.  This increase primarily reflects higher Lopez expense due primarily to added wells and optimization of salt water disposal methods, partially offset by lower expenditures for the Giddings Field.  Lease operating expense and production tax per barrel of oil equivalent decreased 35% from $13.12 per BOE during the nine months ended March 31, 2011, to $8.53 per BOE during the nine months ended March 31, 2012.

 

General and Administrative Expenses (“G&A”).  G&A expenses increased 12% from $4.0 million during the nine months ended March 31, 2011 to $4.5 million during the nine months ended March 31, 2012. The increase was due primarily higher legal, consulting, bonus and salary expenses, the later primarily related to September 1, 2011 pay rate increases.  Stock-based compensation was $1,126,034 (25% of total G&A) for the nine months ended March 31, 2012, compared to $1,143,413 (29% of total G&A) for the nine months ended March 31, 2011.  Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and retain staff and, as a result, likely will continue to be a significant component of our G&A costs.

 

Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A increased by 132% to $834,351 for the nine months ended March 31, 2012, compared to $358,963 for the nine months ended March 31, 2011. The increase was due to higher depletion rate ($5.17 vs. $4.35) per BOE and the significant increase in sales volumes as described above. The higher depletion rate was due to the projected acceleration in the working interest reversion date at Delhi that resulted in our bearing a pro rata share of capital expenditures for calendar 2014 development, partially offset by increased proved reserves.

 

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

 

Known Trends and Uncertainties.  General worldwide economic conditions continue to be uncertain and volatile.  Concerns over uncertain future economic growth are affecting numerous industries, companies, as well as consumers, which impact demand for crude oil and natural gas.  If demand decreases in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues and working capital going forward.

 

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

 

Off Balance Sheet Arrangements

 

The Company has no off-balance sheet arrangements to report during the quarter ending March 31, 2012.

 

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

 

Information about market risks for the three months ended March 31, 2012, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended June 30, 2011 except as noted below.  As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for our fiscal year ended June 30, 2011.

 

Interest Rate Risk

 

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

 

Commodity Price Risk

 

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital, as, if and when needed. Lower prices may also reduce the amount of oil and natural gas that we can economically produce.  Although our current production base may not be sufficient enough to effectively allow hedging, we may periodically use derivative instruments to hedge our commodity price risk. We may hedge a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our exposure to price

 

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Table of Contents

 

fluctuations. We may use futures contracts, swaps and fixed price physical contracts to hedge our commodity prices. Realized gains and losses from our price risk management activities are recognized in oil and natural gas sales when the associated production occurs. We presently do not hold or issue derivative instruments for hedging or speculative purposes.

 

ITEM 4. CONTROLS AND PROCEDURES

 

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

 

As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)) as of the end of the quarter covered by this report.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2012 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

 

During the quarter ended March 31, 2012 there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

PART II - OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

 

We are involved in certain legal proceedings as described in Part I - Item 3 “Legal Proceedings” and Note 12 — Commitments and Contingencies under Part II - Item 8, “Financial Statements”, in our 2011 Annual Report.

 

On March 29, 2012, the Fifth District Court of Richland Parish Louisiana dismissed the case against the Company and our wholly owned subsidiary NGS Sub Corp. brought by John C. McCarthy et. al. (the “plaintiffs”) in July 2011.  Plaintiffs alleged, among other claims, that we fraudulently and wrongfully purchased plaintiffs’ income royalty rights in the Delhi Field Unit in the Holt-Bryant Reservoir in May 2006.  The Court found that plaintiffs had “no cause of action” under Louisiana law.

 

ITEM 1A. RISK FACTORS

 

Our Annual Report on Form 10-K for the year ended June 30, 2011 includes a detailed discussion of our risk factors. The following risk factors update and should be considered in addition to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended June 30, 2011. There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended June 30, 2012 and in our Form 10-Q for the period ended December 31, 2011.

 

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Table of Contents

 

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

 

None.

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

 

Not applicable.

 

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

 

Not applicable.

 

ITEM 5. OTHER INFORMATION

 

None.

 

ITEM 6. EXHIBITS

 

A.           Exhibits

 

10.1*

 

Credit Agreement dated February 29, 2012 among Evolution Petroleum Corporation, the Guarantors and Texas Capital Bank N.A. (incorporated by reference as Exhibit 10.1 to the Company’s Form 8-K filed with the SEC on March 6, 2012.)

 

 

 

31.1

 

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

 

 

 

31.2

 

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

 

 

 

32.1

 

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

 

 

 

32.2

 

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

 

 

 

101.INS

 

XBRL Instance Document

 

 

 

101.SCH

 

XBRL Taxonomy Extension Schema Document

 

 

 

101.CAL

 

XBRL Taxonomy Extension Calculation Linkbase Document

 

 

 

101.DEF

 

XBRL Taxonomy Extension Definition Linkbase Document

 

 

 

101.LAB

 

XBRL Taxonomy Extension Label Linkbase Document

 

 

 

101.PRE

 

XBRL Taxonomy Extension Presentation Linkbase Document

 


* Previously filed.

 

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Table of Contents

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

EVOLUTION PETROLEUM CORPORATION

(Registrant)

 

 

 

By:

/s/ STERLING H. MCDONALD

 

 

Sterling H. McDonald

 

 

Vice-President and Chief Financial Officer

 

 

 

Principal Financial Officer and

 

 

 

Principal Accounting Officer

 

 

Date: May 10, 2012

 

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