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EVOLUTION PETROLEUM CORP - Quarter Report: 2008 December (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 December 31, 2008

 

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

 

For the transition period from               to

 

Commission File Number 001-32942

 

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

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

 

Indicate by check mark whether the registrant is a 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  o

 

Non-accelerated filer  o

 

Smaller reporting company  x

 

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 February 17, 2009, was 26,259,147.

 

 

 



Table of Contents

 

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

 

 

Page

 

 

 

PART I. FINANCIAL INFORMATION

 

 

 

 

ITEM 1.

CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

3

 

 

 

 

Consolidated Balance Sheets (unaudited) as of December 31, 2008 and June 30, 2008

3

 

Consolidated Statements of Operations (unaudited) for the three and six months ended December 31, 2008 and 2007

4

 

Consolidated Statements of Cash Flows (unaudited) for the six months ended December 31, 2008 and 2007

5

 

Notes to Consolidated Condensed Financial Statements (unaudited)

6

 

 

 

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

16

 

 

 

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

26

 

 

 

ITEM 4.

CONTROLS AND PROCEDURES

27

 

 

PART II. OTHER INFORMATION

 

 

 

ITEM 1.

LEGAL PROCEEDINGS

27

 

 

 

ITEM 1A.

RISK FACTORS

28

 

 

 

ITEM 2.

UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS

28

 

 

 

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

28

 

 

 

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

29

 

 

 

ITEM 5.

OTHER INFORMATION

29

 

 

 

ITEM 6.

EXHIBITS

30

 

 

SIGNATURES

31

 

2


 


Table of Contents

 

PART I — FINANCIAL INFORMATION

 

ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

 

Evolution Petroleum Corporation and Subsidiaries

Consolidated Balance Sheets

(Unaudited)

 

 

 

December 31,
2008

 

June 30,
2008

 

Assets

 

 

 

 

 

Current assets

 

 

 

 

 

Cash and cash equivalents

 

$

8,514,708

 

$

11,272,280

 

Certificates of deposit

 

1,500,000

 

 

Receivables

 

 

 

 

 

Oil and natural gas sales

 

407,775

 

2,066,300

 

Income tax

 

 

478,599

 

Other

 

159,638

 

86,966

 

Income taxes recoverable

 

 

3,625,987

 

Prepaid expenses and other current assets

 

156,996

 

270,938

 

Total current assets

 

10,739,117

 

17,801,070

 

 

 

 

 

 

 

Property and equipment, net of depreciation, depletion, and amortization

 

 

 

 

 

Oil and natural gas properties — full cost method of accounting, of which $9,467,090 at December 31, 2008 and $7,573,507 at June 30, 2008 were excluded from amortization)

 

27,496,976

 

22,047,233

 

Other property and equipment

 

168,011

 

161,027

 

Total property and equipment

 

27,664,987

 

22,208,260

 

 

 

 

 

 

 

Other assets, net

 

353,400

 

356,518

 

 

 

 

 

 

 

Total assets

 

$

38,757,504

 

$

40,365,848

 

 

 

 

 

 

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities

 

 

 

 

 

Accounts payable

 

$

2,374,360

 

$

2,892,459

 

Accrued expenses

 

555,130

 

805,262

 

Royalties payable

 

191,276

 

473,327

 

Total current liabilities

 

3,120,766

 

4,171,048

 

 

 

 

 

 

 

Long term liabilities

 

 

 

 

 

Deferred income taxes

 

2,682,921

 

2,901,929

 

Asset retirement obligations

 

334,668

 

215,056

 

Deferred rent

 

75,969

 

74,081

 

 

 

 

 

 

 

Total liabilities

 

6,214,324

 

7,362,114

 

 

 

 

 

 

 

Commitments and contingencies (Note 11)

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity

 

 

 

 

 

Common Stock; par value $0.001; 100,000,000 shares authorized; issued 27,007,234 shares; outstanding 26,219,034 and 26,870,439 as of December 31, 2008 and June 30, 2008, respectively.

 

27,007

 

26,870

 

Additional paid-in capital

 

15,465,506

 

14,188,841

 

Retained earnings

 

17,932,689

 

18,788,023

 

 

 

33,425,202

 

33,003,734

 

Less cost of common stock in treasury, 788,200 shares as of December 31, 2008.

 

(882,022

)

 

Total stockholders’ equity

 

32,543,180

 

33,003,734

 

 

 

 

 

 

 

Total liabilities and stockholders’ equity

 

$

38,757,504

 

$

40,365,848

 

 

See accompanying notes to consolidated financial statements.

 

3



Table of Contents

 

Evolution Petroleum Corporation and Subsidiaries

Consolidated Statements of Operations

(unaudited)

 

 

 

Three Months Ended
December 31,

 

Six Months Ended
December 31,

 

 

 

2008

 

2007

 

2008

 

2007

 

Revenues

 

 

 

 

 

 

 

 

 

Crude oil

 

$

407,194

 

$

607,877

 

$

1,986,264

 

$

1,110,150

 

Natural gas liquids

 

235,293

 

21,294

 

990,738

 

21,294

 

Natural gas

 

389,295

 

23,478

 

969,766

 

23,478

 

Total revenues

 

1,031,782

 

652,649

 

3,946,768

 

1,154,922

 

 

 

 

 

 

 

 

 

 

 

Operating Costs

 

 

 

 

 

 

 

 

 

Lease operating expense

 

313,406

 

361,192

 

649,310

 

671,502

 

Production taxes

 

21,776

 

15,808

 

107,772

 

33,364

 

Depreciation, depletion and amortization

 

504,291

 

123,116

 

1,149,173

 

233,559

 

Accretion of asset retirement obligations

 

6,124

 

4,851

 

11,861

 

9,546

 

General and administrative *

 

1,662,627

 

1,467,678

 

3,127,467

 

2,795,996

 

Total operating costs

 

2,508,224

 

1,972,645

 

5,045,583

 

3,743,967

 

 

 

 

 

 

 

 

 

 

 

Loss from operations

 

(1,476,442

)

(1,319,996

)

(1,098,815

)

(2,589,045

)

 

 

 

 

 

 

 

 

 

 

Other income

 

 

 

 

 

 

 

 

 

Interest income

 

17,782

 

266,740

 

91,428

 

607,821

 

 

 

 

 

 

 

 

 

 

 

Net loss before income tax benefit

 

(1,458,660

)

(1,053,256

)

(1,007,387

)

(1,981,224

)

 

 

 

 

 

 

 

 

 

 

Income tax benefit

 

(454,889

)

(282,399

)

(152,053

)

(568,986

)

 

 

 

 

 

 

 

 

 

 

Net loss

 

$

(1,003,771

)

$

(770,857

)

$

(855,334

)

$

(1,412,238

)

 

 

 

 

 

 

 

 

 

 

Loss per common share

 

 

 

 

 

 

 

 

 

Basic and Diluted

 

$

(0.04

)

$

(0.03

)

$

(0.03

)

$

(0.05

)

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares

 

 

 

 

 

 

 

 

 

Basic and Diluted

 

26,351,277

 

26,777,366

 

26,598,473

 

26,776,800

 


*General and administrative expenses for the three month period ended December 31, 2008 and 2007 included non cash stock-based compensation expense of $584,525 and $441,564, respectively. General and administrative expenses for the six month period ended December 31, 2008 and 2007 included non cash stock-based compensation expense of $1,108,250 and $817,571, respectively.

 

See accompanying notes to consolidated financial statements.

 

 

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Table of Contents

 

Evolution Petroleum Corporation and Subsidiaries

 Consolidated Statements of Cash Flow

(Unaudited)

 

 

 

Six Months Ended
December 31,

 

 

 

2008

 

2007

 

Cash flows from operating activities

 

 

 

 

 

Net loss

 

$

(855,334

)

$

(1,412,238

)

Adjustments to reconcile net loss to net cash provided by(used in) operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

1,149,173

 

233,559

 

Stock-based compensation

 

1,108,250

 

817,571

 

Accretion of asset retirement obligations

 

11,861

 

9,546

 

Deferred income taxes

 

(219,008

)

 

Deferred rent

 

1,888

 

24,903

 

Changes in operating assets and liabilities:

 

 

 

 

 

Receivables from oil and natural gas sales

 

1,658,525

 

(176,593

)

Receivables from income taxes and other

 

4,031,914

 

(811,595

)

Prepaid expenses and other current assets

 

113,942

 

85,261

 

Accounts payable and accrued expenses

 

(314,436

)

(102,658

)

Royalties payable

 

(282,051

)

9,767

 

Net cash provided by (used in) operating activities

 

6,404,724

 

(1,322,477

)

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

Development of oil and natural gas properties

 

(4,723,006

)

(529,262

)

Acquisitions of oil and natural gas properties

 

(2,033,874

)

(4,395,050

)

Proceeds from asset sale

 

 

31,582

 

Capital expenditures for other equipment

 

(26,602

)

(53,625

)

Purchases of certificates of deposit

 

(1,500,000

)

 

Other assets

 

3,118

 

(2,020

)

Net cash used in investing activities

 

(8,280,364

)

(4,948,375

)

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

Proceeds from issuance of restricted stock

 

90

 

26

 

Purchase of treasury stock

 

(882,022

)

 

Net cash provided by (used in) financing activities

 

(881,932

)

26

 

 

 

 

 

 

 

Net decrease in cash and cash equivalents

 

(2,757,572

)

(6,270,826

)

 

 

 

 

 

 

Cash and cash equivalents, beginning of period

 

11,272,280

 

27,746,942

 

 

 

 

 

 

 

Cash and cash equivalents, end of period

 

$

8,514,708

 

$

21,476,116

 

 

 

 

 

 

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Income taxes paid

 

$

15,000

 

$

 

Income tax refunds and net operating loss carry-back received

 

$

4,052,631

 

$

 

Non-cash transactions:

 

 

 

 

 

Increase (decrease) in accounts payable used to acquire oiland natural gas leasehold interests and develop oil andnatural gas properties.

 

$

(285,333

)

$

985,571

 

Oil and natural gas properties incurred through recognitionof asset retirement obligations.

 

$

107,751

 

$

 

Common stock issued in lieu of a portion of 2008 cash bonusaccrued at June 30, 2008.

 

$

168,462

 

$

 

 

See accompanying notes to consolidated financial statements.

 

5


 


Table of Contents

 

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1 Organization and Basis of Preparation

 

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

 

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

 

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

 

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

 

Note 2 — Recent Accounting Pronouncements

 

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

 

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

 

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

 

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Table of Contents

 

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 2 — Recent Accounting Pronouncements (Continued)

 

period beginning on or after December 15, 2008.  SFAS No. 141R would have an impact on accounting for any businesses acquired after the effective date of this pronouncement.

 

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

 

 

Note 3 — Sale of Oil and Natural Gas Properties

 

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

 

Proceeds from sale of properties in the Tullos Field Area

 

$

4,649,241

 

Less payout of a third party carried interest arrangement

 

(168,106

)

Less miscellaneous transaction costs

 

(60,267

)

Net proceeds

 

4,420,868

 

Net book value of our properties in the Tullos Field Area on March 3, 2008

 

 

 

Asset retirement obligation

 

153,886

 

Oil and natural gas properties

 

(1,721,990

)

Other property and equipment

 

(26,721

)

Prepaid expenses and other current assets

 

(178,826

)

Other assets

 

(13,347

)

Remaining credit recorded to oil and natural gas properties

 

$

2,633,870

 

 

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

 

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Table of Contents

 

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

The unaudited pro forma consolidated financial information for the three and six months ended December 31, 2007 are as follows:

 

 

 

Three Months Ended
December 31, 2007

 

Six Months Ended
December 31, 2007

 

 

 

As
Reported

 

Pro
Forma

 

As
Reported

 

Pro
Forma

 

Oil and natural gas revenues

 

$

652,649

 

$

60,116

 

$

1,154,922

 

$

70,422

 

Loss from operations

 

(1,319,996

)

(1,425,170

)

(2,589,045

)

(2,743,395

)

Net loss

 

(770,857

)

(847,831

)

(1,412,238

)

(1,522,260

)

 Loss per common share — basic and diluted

 

$

(0.03

)

$

(0.03

)

$

(0.05

)

$

(0.06

)

 

Note 4 — Property and Equipment

 

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

 

 

 

December 31,
2008

 

June 30,
2008

 

Oil and natural gas properties

 

 

 

 

 

Property costs subject to amortization

 

$

19,791,481

 

$

15,105,766

 

Less: Accumulated depreciation, depletion, and amortization

 

(1,761,595

)

(632,040

)

Unproved properties not subject to amortization

 

9,467,090

 

7,573,507

 

Oil and natural gas properties, net

 

$

27,496,976

 

$

22,047,233

 

 

 

 

 

 

 

Other property and equipment

 

 

 

 

 

Furniture, fixtures and office equipment, at cost

 

258,443

 

231,841

 

Less: Accumulated depreciation

 

(90,432

)

(70,814

)

Other property and equipment, net

 

$

168,011

 

$

161,027

 

 

Unproved properties not subject to amortization includes unevaluated acreage of $7.5 and $5.6 million as of December 31, 2008 and June 30, 2008, respectively.  As of December 31, 2008, this acreage consists of properties in the Giddings Field, our projects in the Woodford Shale trend in Oklahoma, and our Neptune project in South Texas.  As of June 30, 2008, the unevaluated acreage consist of properties in the Giddings Field and our projects in the Woodford Shale trend in Oklahoma.  Unproved properties also consist of approximately $2.0 million as of December 31, 2008 and June 30, 2008 of participating interests through separately acquired royalty and overriding royalty interests aggregating 7.4% of the Delhi Holt Bryant Unit in the Delhi Field in Louisiana.  Subject to industry conditions, evaluation of these properties is expected to be completed within three years.  Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis.

 

If our net oil and natural gas properties, net of related deferred income taxes, exceed the present value of estimated future net cash flows based on period-end commodity prices discounted at 10 percent and plus the cost of unproved oil and natural gas properties not subject to amortization, net of related tax effects, the excess is charged to expense.  Although, we did not have a “ceiling test” impairment as of December 2008, if prices for crude oil and natural gas decline an additional ten percent from their spot price on December 31, 2008, without an equal dollar reduction in capital costs, we would expect to have a write-down of our oil and natural gas properties of approximately $2.6 million.

 

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Table of Contents

 

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 5 Asset Retirement Obligations

 

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligation for the six months ended December 31, 2008:

 

Asset retirement obligations - July 1, 2008

 

$

215,056

 

Liabilities incurred

 

22,480

 

Accretion expense

 

11,861

 

Revisions to previous estimates

 

85,271

 

Asset retirement obligations — December 31, 2008

 

$

4,668

 

 

Note 6 — Stockholders’ Equity

 

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

 

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

 

On December 9, 2008, three outside directors each received 30,000 shares of restricted common stock as part of a compensation plan for directors.  The same outside directors each received 8,633 shares of restricted common stock as part of their compensation plan during the year ended June 30, 2008.  All issuances of common stock were subject to vesting terms per individual stock agreements.

 

Note 7 Stock-Based Incentive Plan

 

We have granted option awards to purchase common stock (the “Stock Options”) and restricted common stock awards  (“Restricted Stock”) to employees, directors, and consultants of the Company and its subsidiaries under the Natural Gas Systems Inc. 2003 Stock Plan (the “2003 Stock Plan”) and the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the “2004 Stock Plan” or together, the “EPM Stock Plans”).  A total of 600,000 awards to purchase an equal number of shares of common stock were issued under the 2003 Stock Plan.  The 2004 Stock Plan authorized the issuance of 5,500,000 shares of common stock.  There are no shares available for grant under the 2003 Stock Plan and, as of December 31, 2008, 597,974 shares remain available for grant under the 2004 Stock Plan.

 

We have also granted common stock warrants, as authorized by the Board of Directors, to employees in lieu of cash bonuses or as incentive awards to reward previous service or provide incentives to individuals to acquire a proprietary interest in the Company’s success and to remain in the service of the Company (the “Incentive Warrants”).  These Incentive Warrants have similar characteristics of the Stock Options.  A total of 1,037,500 Incentive Warrants have been issued, through December 31, 2008, with Board of Directors approval, outside of the EPM Stock Plans.

 

Stock Options and Incentive Warrants

 

Stock-based compensation expense related to Stock Options and Incentive Warrants for the three month period ended December 31, 2008 and 2007 was $499,994 and $403,109, respectively.  Stock-based compensation expense related to Stock Options and Incentive Warrants for the six month period ended December 31, 2008 and 2007 was $945,987 and $704,206, respectively.

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

Note 7 Stock-Based Incentive Plan (Continued)

 

During the six months ended December 31, 2008, we granted Stock Options to purchase 591,090 shares of common stock under the 2004 Stock Plan with a weighted average exercise price of $4.27.  During the six months ended December 31, 2007, we granted Stock Options to purchase 1,335,000 shares of common stock under the 2004 Stock Plan with a weighted average exercise price of $2.43.  The exercise price was determined based on the market price of the Company’s common stock on the date of grant.  The Stock Options granted during the six months ended December 31, 2008 and 2007 generally vest quarterly, on a straight line basis, over a period of four years.  The Stock Options granted during the six months ended December 31, 2008 and 2007 have a contractual life of seven and ten years, respectively.  The weighted average assumptions used to calculate the fair value of these Stock Options and the weighted average fair value of each Stock Option granted is as follows:

 

 

 

Six Months Ended

 

 

 

December 31,

 

 

 

2008

 

2007

 

Expected volatility

 

87.1

%

94.0

%

Expected dividends

 

 

 

Expected term (in years)

 

4.6

 

6.1

 

Risk-free rate

 

3.10

%

4.11

%

Fair value per Stock Option

 

$

2.62

 

$

1.90

 

 

We estimated the fair value of Stock Options and Incentive Warrants issued to employees and directors under SFAS No. 123R at the date of grant using a Black-Scholes-Merton valuation model.  The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.  The expected term (estimated period of time outstanding) of Stock Options and Incentive Warrants is based on the “simplified” method of the estimated expected term for “plain vanilla” options allowed by the SEC Staff Accounting Bulletin (“SAB”) No. 107 and SAB No. 110, and varied based on the vesting period and contractual

 

The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of December 31, 2008, and the changes during the six months then ended:

 

 

 

Number of  Stock Options
and Incentive Warrants

 

Weighted Average
Exercise Price

 

Aggregate
Intrinsic Value 
(1)

 

Weighted
Average
Remaining
Contractual
Term (in
years)

 

 

 

 

 

 

 

 

 

 

 

Stock Options and Incentive Warrants outstanding at July 1, 2008

 

5,483,500

 

$1.81

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Granted

 

591,090

 

$4.27

 

 

 

 

 

Exercised

 

 

 

 

 

 

 

Canceled, forfeited, or expired

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock Options and Incentive Warrants outstanding at December 31, 2008

 

6,074,590

 

$2.05

 

$543,600

 

7.0

 

 

 

 

 

 

 

 

 

 

 

Vested or expected to vest at December 31, 2008

 

6,074,590

 

$2.05

 

$543,600

 

 

 

 

 

 

 

 

 

 

 

 

 

Exercisable at December 31, 2008

 

3,935,063

 

$1.59

 

$543,038

 

6.6

 

 


(1) Based upon the difference between the market price of our common stock on the last trading date of the fiscal quarter ($1.20) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 7 Stock-Based Incentive Plan (Continued)

 

There were no Stock Options or Incentive Warrants that were exercised during the six months ended December 31, 2008 and 2007.

 

A summary of the status of our unvested Stock Options and Incentive Warrants as of December 31, 2008 and the changes during the six months ended December 31, 2008 and 2007, is presented below:

 

 

 

Number of Stock Options
and Incentive Warrants

 

Weighted
Average Grant-
Date Fair Value

 

 

 

 

 

 

 

Unvested at July 1, 2007

 

1,573,125

 

$

1.50

 

 

 

 

 

 

 

Granted

 

1,335,000

 

$

1.90

 

 

 

 

 

 

 

Vested

 

(375,625

)

$

1.35

 

 

 

 

 

 

 

Canceled, forfeited, or expired

 

 

 

 

 

 

 

 

 

Unvested at December 31, 2007

 

2,532,500

 

$

1.73

 

 

 

 

 

 

 

Unvested at July 1, 2008

 

2,003,437

 

$

1.83

 

 

 

 

 

 

 

Granted

 

591,090

 

$

2.62

 

 

 

 

 

 

 

Vested

 

(455,000

)

$

1.69

 

 

 

 

 

 

 

Canceled, forfeited, or expired

 

 

 

 

 

 

 

 

 

Unvested at December 31, 2008

 

2,139,527

 

$

2.08

 

 

The total unrecognized compensation cost at December 31, 2008, relating to non-vested share-based compensation arrangements granted under the EPM Stock Plans and Incentive Warrants was $4,151,838.  Such unrecognized expense is expected to be recognized over a weighted average period of 2.8 years.

 

Restricted Stock

 

For the six months ended December 31, 2008 and 2007, we issued 90,000 and 25,899 shares of restricted common stock, respectively, to three outside directors.  All issuances of common stock are subject to vesting terms per individual stock agreements.

 

Stock-based compensation expense related to Restricted Stock grants for the three month period ended December 31, 2008 and 2007 was $84,531 and $38,455, respectively.  Stock-based compensation expense related to Restricted Stock grants for the six month period ended December 31, 2008 and 2007 was $162,263 and $113,365, respectively.

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 7 Stock-Based Incentive Plan (Continued)

 

The following table sets forth the Restricted Stock transactions for the six months ended December 31, 2008 and 2007:

 

 

 

Number of
Restricted
Shares

 

Weighted
Average
Grant-Date
Fair Value

 

 

 

 

 

 

 

Unvested at July 1, 2007

 

59,449

 

$

2.78

 

 

 

 

 

 

 

Granted

 

25,899

 

$

4.17

 

 

 

 

 

 

 

Vested

 

(59,449

)

$

2.78

 

 

 

 

 

 

 

Forfeited

 

 

 

 

 

 

 

 

 

Unvested at December 31, 2007

 

25,899

 

$

4.17

 

 

 

 

 

 

 

Unvested at July 1, 2008

 

50,898

 

$

4.11

 

 

 

 

 

 

 

Granted

 

90,000

 

$

1.20

 

 

 

 

 

 

 

Vested

 

(50,898

)

$

4.11

 

 

 

 

 

 

 

Forfeited

 

 

 

 

 

 

 

 

 

Unvested at December 31, 2008

 

90,000

 

$

1.20

 

 

At December 31, 2008, unrecognized stock compensation expense related to Restricted Stock grants totaled $101,110.  Such unrecognized expense will be recognized over a weighted average period of 0.9 years.

 

Note 8 Income Taxes

 

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

 

There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits as of the date of adoption of FIN 48 and through December 31, 2008.

 

We recognized a tax benefit of 31% and 27% for the three months ended December 31, 2008 and 2007, respectively, and a tax benefit of 15% and 29% for the six months ended December 31, 2008 and 2007, respectively.  The primary reconciling item of our income tax benefit at the statutory federal rate to our effective income tax benefit is stock-based compensation related to our qualified incentive stock option awards.

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 9 Related Party Transactions

 

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

 

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

 

During the three and six months ended December 31, 2008 and 2007, we expensed and paid CMCP $15,000 and $30,000, respectively, through monthly retainers of $5,000.  There were no other earned fees by CMCP during these periods.

 

See also Note 6 for equity transactions with related parties.

 

Note 10 — Earnings (loss) Per Share (“EPS”)

 

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

 

 

 

Three Months Ended
December 31,

 

Six Months Ended
December 31,

 

 

 

2008

 

2007

 

2008

 

2007

 

Numerator

 

 

 

 

 

 

 

 

 

Net loss

 

$

(1,003,771

)

$

(770,857

)

$

(855,334

)

$

(1,412,238

)

 

 

 

 

 

 

 

 

 

 

Denominator

 

 

 

 

 

 

 

 

 

Weighted average number of common shares — basic and diluted

 

26,351,277

 

26,777,366

 

26,598,473

 

26,776,800

 

 

 

 

 

 

 

 

 

 

 

Net Loss per common share — basic and diluted

 

$

(0.04

)

$

(0.03

)

$

(0.03

)

$

(0.05

)

 

Total potentially dilutive securities outstanding as of December 31, 2008 are as follows:

 

Outstanding Potential Dilutive Securities

 

Weighted
 Average
Exercise Price

 

Outstanding at December 31, 2008

 

 

 

 

 

 

 

Common stock warrants issued in connection with equity and financing transactions

 

$

1.40

 

401,058

 

Stock Options and Incentive Warrants

 

$

2.05

 

6,074,590

 

Non-vested Restricted Stock

 

N/A

 

90,000

 

 

 

 

 

6,565,648

 

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 11 — Commitments and Contingencies

 

Environmental clean-up.  On August 3, 2007, we were advised of an oil spill in the Tullos Field near one of our leases. At the request of field agents of the Louisiana Department of Environmental Quality and the Environmental Protection Agency (“EPA”), we agreed to commence a clean-up operation that was completed by the end of August 2007. A detailed analysis of the oil in the spill compared to the Company’s produced oil was conducted by an EPA approved laboratory.  We believe that the oil in the spill did not originate from our operations, supported by the formal findings of the laboratory.  We received insurance reimbursements of $484,197 in October 2007 and $217,668 in March 2008.  These reimbursements covered all of our actual cleanup costs except a $5,000 insurance deductible and excluding our legal fees, in-house administrative costs, and any possible EPA expense reimbursements and fines that might be billed.

 

On May 5, 2008, we received a letter from the EPA proposing a  $5,500 fine related to the oil spill.  In August we paid the fine under a settlement with the EPA where we agreed to pay the $5,500 fine with no admission of liability.  We have also received a bill from the United States Coast Guard of approximately $76,000 for expense reimbursement.  We believe this claim is not supported by independent investigation.  As of the date of this filing, we have requested further verification from the United States Coast Guard to support their claim. If ultimately paid, we believe that such reimbursements are covered by our insurance.

 

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

 

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

 

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

 

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

 

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 11 — Commitments and Contingencies (Continued)

 

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on August 1, 2016. Future minimum lease commitments as of December 31, 2008 under this operating lease are as follows:

 

For the twelve months ended December 31,

 

 

 

2009

 

$

138,089

 

2010

 

138,089

 

2011

 

146,806

 

2012

 

159,011

 

2013

 

159,011

 

Thereafter

 

410,779

 

Total

 

$

1,151,785

 

 

Rent expense for the three months ended December 31, 2008 and 2007 was 35,466.  Rent expense for the six months ended December 31, 2008 and 2007 was 70,933.

 

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 December 31, 2008 is approximately $499,000.

 

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Table of Contents

 

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

 

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

 

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

 

Executive Overview

 

General

 

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

 

Our strategy is intended to generate scalable development opportunities at normally pressured depths, exhibiting relatively low completion risk, generally longer and more predictable production lives, less expenditures on infrastructure and lower operational risks.

 

Within this overall strategy, we pursue three specific initiatives:

 

I

 

Enhanced oil recovery (“EOR”), using miscible and immiscible gas flooding;

 

 

 

II

 

Conventional redevelopment of bypassed primary resources within mature oil and natural gas fields utilizing modern technology and our expertise; and

 

 

 

III

 

Unconventional gas resource development, using modern stimulation and completion technologies.

 

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

 

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

 

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Table of Contents

 

 

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

 

Our long term strategy and primary focus continue to be on increasing share value through the identification and acquisition of resources and conversion of those resources into proved reserves through our expertise and technology.  Our focus is on the following value-added activities, including (i) project identification and leasing of reserves that we believe will be categorized as proved undeveloped, and (ii) selective drilling activities to move existing reserves into the proved category.

 

Highlights for our Second Quarter Fiscal Year 2009

 

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

 

Sales volumes increased 228% during our second quarter in fiscal year 2009 vs. our second quarter in fiscal year 2008.  Our increase in sales volumes for the quarter were solely attributable to our production in the Giddings Field.  Our properties in the Tullos Field Area, which were sold on March 3, 2008, accounted for approximately 85% of total sales volumes for the three months ended December 31, 2007.

 

We lowered per barrel lifting costs by 72% during our most recent quarter vs. the prior year quarter, while depletion increased approximately $6 per BOE. Lifting costs (lease operating and severance tax, on a combined per unit of sales basis) were $12.54 per BOE during the quarter ended December 31, 2008, which included only production from our properties in the Giddings Field.  During the quarter ended December 31, 2007, where our production was primarily from our properties in the Tullos Field Area, lifting costs averaged $44.63 per Bbl of crude oil.  Due to additions of higher valued, higher cost reserves at the Giddings Field during the period, our depletion rate rose from $13.29 to $19.07 per BOE.

 

·                  We remained financially strong

 

We ended the quarter with $10.0  million of cash and cash equivalents and short-term certificates of deposit and $7.6 million of working capital, compared to $11.3 million of cash and cash equivalents and $13.6 million of working capital  at June 30, 2008.   We incurred $6.6 million in capital expenditures for oil and natural gas leasehold and development costs during the six months ended December 31, 2008.

 

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Table of Contents

 

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

 

We  repurchased 788,200 shares of our common shares at an average price of $1.10 per share, plus transaction costs, from an unaffiliated accredited investor.  We believe the acquisition of our shares at these levels is highly accretive to existing shareholder value based on our internal calculations of the net present value of our proved and unproved assets.  At this time, we currently have no plan to repurchase any more common shares.

 

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

 

Looking Forward in 2009

 

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

 

Increased production from two re-entry wells beginning in our third fiscal quarter 2009.  The first fiscal 2009 Giddings Field re-entry well, the Hilton Yeagua #1, was recently completed and placed onto production during mid-January 2009.  A second re-entry well, the Pearson #1, began drilling in late December 2008 and was completed and placed on production in late January 2009.  As of early February, the two wells were producing at a combined rate of 580 boepd, and we own a 100% working interest and approximately 79% revenue interest in the two wells. Wells of this type in the Giddings Field  generally exhibit high initial decline rates, however, the initial production rates were higher than projected

 

Completion of the CO2 pipeline to Delhi and initiation ofCO2  injection is expected in the second calendar quarter of 2009 (source: public presentations by Operator).

 

Production from Delhi expected in calendar 2009.  First oil production is expected to begin within six months following first injection of CO2, or sometime in late calendar 2009. We believe that production response in the Delhi Field resulting from the injection of CO2 will lead to substantial net proved reserves.

 

We expect to initiate pilot drilling within our shallow Woodford Shale projects. Current plans for fiscal 2009 include the drilling of up to five vertical wells to depths of about 1500’ to utilize air drilling to develop what we believe will be substantial low cost gas reserves.

 

We expect to initiate pilot drilling within our Neptune heavy oil project in South Texas.  We recently completed the leasing of approximately 1500 net acres where we intend to drill infill wells within an existing moderately heavy oil field.  The infill, or downspaced, wells have already been proved in expected reserves by another operator and we expect to apply our specialized completion technology to enhance recovery.

 

·                  Further declines of oil and natural gas prices could result in a significant impairment of our full-cost pool.

 

The current recessionary economic environment has resulted in lower demand for oil and natural gas, resulting in severely declining commodity prices, while the decline in oilfield capital costs has lagged.  If prices for crude oil and natural gas decline an additional ten percent from their spot price on December 31, 2008, without an equal dollar reduction in capital costs, we would expect to have a write-down of our oil and natural gas properties of approximately $2.6 million.

 

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Table of Contents

 

Liquidity and Capital Resources

 

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

 

At December 31, 2008, our working capital was $7.6 million and we continued to be debt free.  This compares to working capital of $13.6 million at June 30, 2008.  The decrease in working capital of $6.0 million since June 2008 was due to cash of $6.8 million used for investing activities, primarily for investments in oil and natural gas properties, cash used of  $0.9 million to repurchase our common stock, a decrease of $5.8 million in receivables and other current assets, primarily from the collection of income tax receivables, partially offset by cash of $6.4 million provided by operations and a decrease of $1.1 million in current liabilities.

 

Cash flows provided by operating activities for the six months ended December 31, 2008 were $6.4 million.  Cash flows provided by operations includes cash proceeds of $5.3 million from oil and natural gas production primarily from our properties in the Giddings Field, cash proceeds of $0.1 million from interest income, cash proceeds of $4.1 million from income tax refunds, primarily from our 2008 tax year net operating loss carry-back, offset by $3.1 million of cash payments for operating activities, including lease operating expenses, production taxes, and salaries and wages.  This compares to $1.3 million of cash used in operations for the six months ended December 31, 2007, which includes $0.9 million of cash proceeds from oil and natural gas production primarily from our properties in the Tullos Field Area, which we sold on March 3, 2008, cash proceeds from interest income of $0.6 million, offset by $2.8 million of cash payments for operating activities, including lease operating expenses, production taxes, and salaries and wages.

 

Cash flows used in investing activities totaled $8.3 million during the six months ended December 31, 2008, and notwithstanding the purchase of certificates of deposit of $1.5 million with maturities no greater than twelve months, our investing activities were primarily for development activities in the Giddings Field and leasehold acquisition costs in the Giddings Field, our Woodford Shale projects in Oklahoma and our Neptune project in South Texas.  Our cash flows from investing activities includes net payments on accounts payable of $0.3 million from June 30, 2008, relating to expenditures for oil and natural gas properties.  This compared to $4.9 million used in investing activities for the six months ended December 31, 2007, primarily for investments in oil and natural gas properties at the Giddings Field.

 

Cash flows used in financing activities for the six months ended December 31, 2008 were $0.9 million.  On October 30, 2008, we repurchased 788,200 shares of common stock at an average price of $1.10 per share, plus approximately $15,000 of transaction costs, from an unaffiliated accredited investor.  At this time, the company has no plan to repurchase any more common shares.  Cash flows from financing activities for the six months ended December 31, 2007 were insignificant.

 

We incurred $6.6 million in capital expenditures for oil and natural gas leasehold and development costs during the six months ended December 31, 2008, which includes $0.1 million related to costs incurred due to the recognition of asset retirement obligations. Of the $6.6 million, $2.0 million was incurred for leasehold acquisitions and $4.6 million was incurred for development activities.  For the six months ended December 31, 2007, we incurred $5.9 million in capital expenditures (which includes a net increase in accounts payable of $1.0 million from June 30, 2007 related to capital expenditures) for oil and natural gas leasehold and development costs, primarily leasehold acquisitions in the Giddings Field.

 

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Table of Contents

 

Since our wells in the Giddings Field tend to produce a large portion of their reserves relatively quickly, we believe that it is in our shareholders’ best interests to slow the development of our properties in the Giddings Field until expectations of higher commodity prices may be realized.  Our Revised 2009 Plan provides for drilling up to three re-entry wells in the Giddings Field, which is a reduction from the previous ten well re-entry plan, subject to future changes in commodity prices and market conditions.  The first fiscal 2009 Giddings Field re-entry well, the Hilton Yeagua #1, was recently completed and placed onto production during mid-January 2009.  A second re-entry well, the Pearson #1, began drilling in late December 2008 and was completed and placed on production in late January 2009.  As of early February, the two wells were producing at a combined rate of 580 boepd, and we own a 100% working interest and approximately 78-80% revenue interest in the two wells.

 

Additionally, initial test drilling of up to five low-cost vertical wells is planned within our shallow Woodford Shale project in Oklahoma.  It is our intention to potentially quantify and convert that potential resource into proved and probable reserves, with possible further proved extensions from these wells if the SEC implements its proposed new rules on proved reserves.  Similarly, we expect to drill up to three low cost wells in our new Texas project, with the expectation of potentially establishing additional proved reserves of moderately heavy oil associated with water at shallow depths.

 

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Table of Contents

 

Results of Operations

 

Three months ended December 31, 2008 compared with the three months ended December 31, 2007

 

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

 

 

 

Three Months Ended

 

 

 

 

 

 

 

December 31

 

 

 

%

 

 

 

2008

 

2007

 

Variance

 

change

 

 

 

 

 

 

 

 

 

 

 

Production Volumes, net to the Company:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (Bbl)

 

7,346

 

6,481

 

865

 

13

%

 

 

 

 

 

 

 

 

 

 

Natural gas liquids (“NGLs”) (Bbl)

 

7,682

 

388

 

7,294

 

1,880

%

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

66,929

 

3,617

 

63,312

 

1,750

%

Crude oil, NGLs and natural gas (BOE)

 

26,183

 

7,472

 

18,711

 

250

%

 

 

 

 

 

 

 

 

 

 

Sales Volumes, net to the Company:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (Bbl)

 

7,098

 

6,927

 

171

 

2

%

 

 

 

 

 

 

 

 

 

 

NGLs (Bbl)

 

7,682

 

388

 

7,294

 

1,880

%

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

66,929

 

3,617

 

63,312

 

1,750

%

Crude oil, NGLs and natural gas (BOE)

 

25,935

 

7,918

 

18,017

 

228

%

 

 

 

 

 

 

 

 

 

 

Revenue data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

$

407,194

 

$

607,877

 

$

(200,683

)

(33

)%

 

 

 

 

 

 

 

 

 

 

NGLs

 

235,293

 

21,294

 

213,999

 

1,005

%

 

 

 

 

 

 

 

 

 

 

Natural gas

 

389,295

 

23,478

 

365,817

 

1,558

%

Total revenues

 

$

1,031,782

 

$

652,649

 

$

379,133

 

58

%

 

 

 

 

 

 

 

 

 

 

Average price:

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

57.37

 

$

87.75

 

$

(30.38

)

(35

)%

NGLs (per Bbl)

 

30.63

 

54.88

 

(24.25

)

(44

)%

Natural gas (per Mcf)

 

5.82

 

6.49

 

(0.67

)

(10

)%

Crude oil, NGLs and natural gas (per BOE)

 

$

39.78

 

$

82.43

 

$

(42.65

)

(52

)%

 

 

 

 

 

 

 

 

 

 

Expenses (per BOE)

 

 

 

 

 

 

 

 

 

Lease operating expenses and production taxes (a)

 

$

12.54

 

$

44.63

 

$

(32.09

)

(72

)%

Depletion expense on oil and natural gas properties (b)

 

$

19.07

 

$

13.29

 

$

5.78

 

43

%


(a)          Excludes non-recurring expenses related to the oil spill in the Tullos Field Area of $10,000 and $23,591 for the three months ended December 31, 2008 and 2007, respectively.

 

(b)         Excludes depreciation of furniture and fixtures of $9,794 and $17,870, for the three months ended December 31, 2008 and 2007, respectively.

 

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Table of Contents

 

Net income (loss). For the three months ended December 31, 2008, we reported a net loss of $1,003,771, or $0.04 loss per share (which includes $1.1 million of non-cash charges related to stock-based compensation, depreciation, depletion, and amortization, and accretion on asset retirement obligations) on total oil and natural gas revenues of $1,031,782.  This compares to a net loss of $770,857, or $0.03 loss per share (which includes $0.6 million of non-cash charges related to stock-based compensation, depreciation, depletion, and amortization, and accretion on asset retirement obligations) on total oil and natural gas revenues of $652,649 for the three months ended December 31, 2007.  The increase in loss is attributable to an increase depreciation, depletion and amortization of $381,175, and an increase in general and administrative expenses of $194,949, a decrease in interest income of $248,958, offset by an increase in revenues of $379,133, a decrease in lease operating expense and production taxes of $41,818, an increase in our income tax benefit of $172,490.  Additional details of the components of net loss 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 December 31, 2008 increased 228% to 25,935 BOE, compared to 7,918 BOE for the three months ended December 31, 2007.  The increase in sales volumes is due to production of crude oil, NGLs and natural gas from our properties in the Giddings Field.  Our properties in the Tullos Field Area, which were sold on March 3, 2008, accounted for 85% of total sales volumes for the three months ended December 31, 2007.

 

Production.  Oil production will vary from oil sales volumes by changes in crude oil inventories, which are not carried on our balance sheet.  Crude oil, NGLs and natural gas production for the three months ended December 31, 2008 increased 250% to 26,183 BOE, compared to 7,472 BOE for the three months ended December 31, 2007.  The increase is due to crude oil, NGLs and natural gas production from our properties in the Giddings Field.  Production from our properties in the Tullos Field Area, which were sold on March 3, 2008, accounted for 84% of production for the three months ended December 31, 2007.

 

Oil, NGLs and Natural Gas Revenues.  Crude oil, NGLs and natural gas revenues for the three months ended December 31, 2008 increased 58% from the comparable quarter in the previous fiscal year.  This was due to increased sales of NGLs and natural gas during the three months ended December 31, 2008 in our properties in the Giddings Field, whereas we had very little production in our properties in the Giddings Field during the three months ended December 31, 2007.  Increased production was offset by a 35% decrease in our average price of a Bbl of oil, from $88 per Bbl for the three months ended December 31, 2007 to $57 per Bbl for the three months ended December 31, 2008.  Our properties in the Giddings Field generated approximately 100% of our revenues for the three months ended December 31, 2008.  Oil revenues from our properties in the Tullos Field Area, which was sold in March 2008, accounted for 91% of total revenues for the three months December 31, 2007.

 

Lease Operating Expenses (including production severance taxes).  Lease operating expenses and production taxes for the three months ended December 31, 2008 decreased approximately 14% from the comparable quarter in the prior fiscal year. Fewer higher producing wells in the Giddings Field compared to numerous lower producing wells in the Tullos Field Area are contributing more efficient operations and decreasing lease operating costs, which is partially offset by higher production taxes in the Giddings Field as compared to the Tullos Field Area where the majority of our production was during the previous period.  The higher production taxes are due to higher revenues and a higher tax rate in our Texas properties compared to our production from our Louisiana properties in the comparable quarter in the previous fiscal year, even after adjusting for the Texas limited severance tax holiday on wells restored to production.  On a BOE basis, lease operating expenses (including production severance taxes) decreased by 72% over the comparable three month period in the prior fiscal year, due to higher sales volumes at Giddings in the current period as compared to lower sales volumes at the Tullos Field in the comparable prior year period.

 

General and Administrative Expenses (“G&A”).  G&A expenses increased 13% to $1.7 million for the three months ended December 31, 2008, compared to $1.5 million for the three months ended December 31, 2007.  Higher overall compensation expenses for estimated bonuses and new hires, and including non-cash stock-based compensation, accounted for the majority of the increase.  New hires are primarily associated with the build up of our infrastructure to accommodate our operations in the Giddings Field.  Non-cash stock-based compensation expense was $584,525 (35% of total G&A) and $441,564 (30% of total G&A) for the three months ended December 31, 2008 and 2007, respectively.  Non-cash stock-based compensation is an integral part  of total staff compensation utilized to recruit quality staff from other, more established companies.

 

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Table of Contents

 

Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A expense increased by $381,175 to $504,291 for the three months ended December 31, 2008, compared to $123,116 for the three months ended December 31, 2007.  The increase is primarily due to a higher depletion rate ($19 vs. $13) per BOE and a 228% increase in sales volumes.  The increase in the depletion rate is due to the higher development cost of PUDs in the Giddings Field that we added in amount far in excess of the volume of lower cost PDP’s in our properties in the Tullos Field Area, which we sold in March 2008.  Proved reserves in the Giddings Field typically are higher cost, but higher valued, compared to the long life, high operating cost proved reserves in the Tullos Field Area.

 

Interest Income.  Interest income for the three months ended December 31, 2008 decreased $248,958 to $17,782, compared to $266,740 for the three months ended December 31, 2007.  The decrease in interest income is due to lower available cash balances averaging $8.9 million during the three months ended December 31, 2008, as compared to cash balances averaging $23.2 million during the three months ended December 31, 2007, combined with a lower interest rate environment during the three months ended December 31, 2008.  The lower cash balance is primarily due to cash used to pay for additions to our oil and natural gas properties.

 

23


 

 


Table of Contents

 

Six months ended December 31, 2008 compared with the six months ended December 31, 2007

 

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

 

 

 

Six Months Ended

 

 

 

 

 

 

 

December 31

 

 

 

%

 

 

 

2008

 

2007

 

Variance

 

change

 

 

 

 

 

 

 

 

 

 

 

Production Volumes, net to the Company:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil and natural gas liquids (Bbl)

 

20,055

 

13,841

 

6,214

 

45

%

 

 

 

 

 

 

 

 

 

 

Natural gas liquids (“NGLs”) (Bbl)

 

18,745

 

388

 

18,357

 

4,731

%

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

128,075

 

3,617

 

124,458

 

3,441

%

Crude oil, NGLs and natural gas (BOE)

 

60,146

 

14,832

 

45,314

 

306

%

 

 

 

 

 

 

 

 

 

 

Sales Volumes, net to the Company:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (Bbl)

 

19,933

 

13,961

 

5,972

 

43

%

 

 

 

 

 

 

 

 

 

 

NGLs (Bbl)

 

18,745

 

388

 

18,357

 

4,731

%

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

128,075

 

3,617

 

124,458

 

3,441

%

Crude oil, NGLs and natural gas (BOE)

 

60,024

 

14,952

 

45,072

 

301

%

 

 

 

 

 

 

 

 

 

 

Revenue data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

$

1,986,264

 

$

1,110,150

 

$

876,114

 

79

%

 

 

 

 

 

 

 

 

 

 

NGLs

 

990,738

 

21,294

 

969,444

 

4,553

%

 

 

 

 

 

 

 

 

 

 

Natural gas

 

969,766

 

23,478

 

946,288

 

4,031

%

Total revenues

 

$

3,946,768

 

$

1,154,922

 

$

2,791,846

 

242

%

 

 

 

 

 

 

 

 

 

 

Average price:

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

99.65

 

$

79.52

 

$

20.13

 

25

%

NGLs (per Bbl)

 

52.85

 

54.88

 

(2.03

)

(4

)%

Natural gas (per Mcf)

 

7.57

 

6.49

 

1.08

 

17

%

Crude oil, NGLs and natural gas (per BOE)

 

$

65.75

 

$

77.24

 

$

(11.49

)

(15

)%

 

 

 

 

 

 

 

 

 

 

Expenses (per BOE)

 

 

 

 

 

 

 

 

 

Lease operating expenses and production taxes (a)

 

$

12.35

 

$

44.59

 

$

(32.24

)

(72

)%

Depletion expense on oil and natural gas properties (b)

 

$

18.82

 

$

13.20

 

$

5.62

 

43

%


(c)          Excludes non-recurring expenses related to the oil spill in the Tullos Field Area of $15,500 and $38,123, for the six months ended December 31, 2008 and 2007, respectively.

 

(d)         Excludes depreciation of furniture and fixtures of $19,618 and $36,121, for the six months ended December 31, 2008 and 2007, respectively.

 

Net income (loss). For the six months ended December 31, 2008, we reported a net loss of $855,334, or $0.03 in loss per share (which includes $2.3 million of non-cash charges related to stock-based compensation, depreciation, depletion, and amortization, and accretion on asset retirement obligations) on total oil and natural gas revenues of $3,946,768.  This compares to a net loss of $1,412,238, or $0.05 loss per share (which includes $1.1 million of non-cash charges related to stock-based compensation, depreciation, depletion, and amortization, and accretion on asset retirement obligations) on total oil and natural gas revenues of $1,154,922 for the six months ended December 31, 2007.  The decrease in our net loss is primarily attributable to an increase in revenues of $2,791,846, partially offset by increases in lease operating expense and production taxes of $52,216, an increase in depreciation, depletion and amortization of $915,614, an increase in general and administrative expenses of $331,471 and a decrease in interest income earned of $516,393.  Additional details of the components of net loss are explained in greater detail below.

 

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Table of Contents

 

Sales Volumes.  Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the six months ended December 31, 2008 increased 301% to 60,024 BOE, compared to 14,952 BOE for the six months ended December 31, 2007.  The increase in sales volumes is due to production of crude oil, NGLs and natural gas from our properties in the Giddings Field.  Our properties in the Tullos Field Area, which were sold on March 3, 2008, accounted for 91% of total sales volumes for the six months ended December 31, 2007.

 

Production.  Oil production will vary from oil sales volumes by changes in crude oil inventories, which are not carried on our balance sheet.  Crude oil, NGLs and natural gas production for the six months ended December 31, 2008 increased 306% to 60,146 BOE, compared to 14,832 BOE for the six months ended December 31, 2007.  The increase is due to crude oil, NGLs and natural gas production from our properties in the Giddings Field.  Production from our properties in the Tullos Field Area, which were sold on March 3, 2008, accounted for 91% of production for the six months ended December 31, 2007.

 

Oil, NGLs and Natural Gas Revenues.  Crude oil, NGLs and natural gas revenues for the six months ended December 31, 2008 increased 242% from the comparable period in the previous fiscal year.  This was due to a 25% increase in our average price of a Bbl of oil, from $80 per Bbl for the six months ended December 31, 2007 to $100 per Bbl for the six months ended December 31, 2008, along with sales of NGLs and natural gas during the six months ended December 31, 2008, whereas there were very little sales of NGLs and natural gas during the six months ended December 31, 2007.  Our properties in the Giddings Field generated approximately 100% our revenues for the six months ended December 31, 2008.  Oil revenues from our properties in the Tullos Field Area, which was sold in March 2008, accounted for 94% of total revenues for the six months ended December 31, 2007.

 

Lease Operating Expenses (including production severance taxes).  Lease operating expenses and production taxes for the six months ended December 31, 2008 increased approximately 7% from the comparable six month period in the prior fiscal year.    The increase for the six months ended December 31, 2008 is attributable to higher production taxes in the Giddings Field as compared to the Tullos Field Area where the majority of our production was during the previous period.  The higher production taxes are due to higher revenues and a higher tax rate in our Texas properties compared to our production from our Louisiana properties in the comparable period in the previous fiscal year, even after adjusting for the Texas limited severance tax holiday on wells restored to production.  The higher production taxes was partially offset by a decrease in lease operating costs, due to fewer higher producing wells in the Giddings Field compared to numerous lower producing wells in the Tullos Field Area.  On a BOE basis, lease operating expenses (including production severance taxes) decreased by 72% over the comparable six month period in the prior fiscal year, due to higher sales volumes at Giddings in the current period as compared to lower sales volumes at the Tullos Field in the comparable prior year period.

 

General and Administrative Expenses (“G&A”).  G&A expenses increased 12% to $3.1 million for the six months ended December 31, 2008, compared to $2.8 million for the six months ended December 31, 2007.  Higher overall compensation expenses for estimated bonuses and new hires, and including non-cash stock-based compensation, accounted for the majority of the increase.  New hires are associated with a build up of our infrastructure to accommodate our operations in the Giddings Field.  Non-cash stock-based compensation expense was $1,108,250 (35% of total G&A) and $817,571 (29% of total G&A) for the six months ended December 31, 2008 and 2007, respectively.  Non-cash stock-based compensation is an integral part  of total staff compensation utilized to recruit quality staff from other, more established companies.

 

Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A expense increased by $915,614 to $1,149,173 for the six months ended December 31, 2008, compared to $233,559 for the six months ended December 31, 2007.  The increase is primarily due to a higher depletion rate ($19 vs. $13) per BOE and a 301% increase in sales volumes.  The increase in the depletion rate is due to the higher development cost of PUDs in the Giddings Field that we added in amount far in excess of the volume of lower cost PDP’s in our properties in the Tullos Field Area, which we sold in March 2008.  Proved reserves in the Giddings Field typically are higher cost, but higher valued, compared to the long life, high operating cost proved reserves in the Tullos Field Area.

 

Interest Income.  Interest income for the six months ended December 31, 2008 decreased $516,393 to $91,428, compared to $607,821 for the six months ended December 31, 2007.  The decrease in interest income is due to lower available cash balances averaging $9.6 million during the six months ended December 31, 2008, as compared to cash balances averaging $24.8 million during the six months ended December 31, 2007, combined with a lower interest rate environment during the six months ended December 31, 2008.  The lower cash balance is primarily due to cash used to pay for additions to our oil and natural gas properties.

 

25



Table of Contents

 

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 high price increases.  With the general rise in the price of oil and natural gas products over the last three years, increased prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services, have also increased, thereby escalating our lease operating expenses and our capital expenditures.  Most recently, we have seen a precipitous decline in both petroleum product prices, drilling and oilfield services, although product prices, operating costs and development costs may not always move in tandem.  Such declines as of December 31, 2008 are reflected in our ceiling test calculations.

 

Known Trends and Uncertainties.  General worldwide economic conditions have deteriorated due to credit conditions impacted by the sub-prime mortgage turmoil and other factors.  Concerns over slower or declining economic growth are affecting numerous industries, companies, as well as consumers, which has resulted in reduced demand for crude oil and natural gas.  If demand continues to decrease in the future, it may continue to 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 seasonal, except for certain rare 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, generally based on higher demand for natural gas in the summer and winter and higher demand for downstream oil products during the summer driving season.

 

Off Balance Sheet Arrangements

 

The Company has no off-balance sheet arrangements to report during the second quarter ending December 31, 2008.

 

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

 

Information about market risks for the three months ended December 31, 2008, did not change materially from the disclosures in Item 7A. of our Annual Report on Form 10-K for the year ended June 30, 2008 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 the year ended June 30, 2008.

 

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 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.

 

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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 the Company’s 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 December 31, 2008 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 December 31, 2008 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

 

On August 3, 2007, we were advised of an oil spill in the Tullos Field near one of our leases. At the request of field agents of the Louisiana Department of Environmental Quality and the Environmental Protection Agency (“EPA”), we agreed to commence a clean-up operation that was completed by the end of August 2007. A detailed analysis of the oil in the spill compared to the Company’s produced oil was conducted by an EPA approved laboratory.  We believe that the oil in the spill did not originate from our operations, supported by the formal findings of the laboratory.  We received insurance reimbursements of $484,197 in October 2007 and $217,668 in March 2008.  These reimbursements covered all of our actual cleanup costs except a $5,000 insurance deductible and excluding our legal fees, in-house administrative costs, and any possible EPA expense reimbursements and fines that might be billed.

 

On May 5, 2008, we received a letter from the EPA proposing a  $5,500 fine related to the oil spill.  In August we paid the fine under a settlement with the EPA where we agreed to pay the $5,500 fine with no admission of liability.  We have also received a bill from the United States Coast Guard of approximately $76,000 for expense reimbursement.  We believe this claim is not supported by independent investigation.  As of the date of this filing, we have requested further verification from the United States Coast Guard to support their claim. If ultimately paid, we believe that such reimbursements are covered by our insurance.

 

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

 

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

 

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

 

ITEM 1A. RISK FACTORS

 

The following is an update of the risk factors set forth in the Company’s Annual Report on Form 10-K for the year ended June 30, 2008.  Other than set forth below, there have been no material changes in our risk factors from the information provided in Item 1A. Risk Factors in the Form 10-K.

 

We could be adversely affected by a recession in the United States or global economy.

 

The current recessionary economic environment has resulted in lower demand for oil and natural gas, resulting in a decline of commodity prices.  If the current recessionary environment continues we will continue to have low demand for petroleum products, lower realized prices and increased operating losses.  These factors will negatively impact our operations and may limit our growth.

 

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

Period

 

(a) Total Number of
Shares (or Units)
Purchased

 

(b) Average
Price Paid
per Share (or Unit)

 

(c) Total Number of
Shares (or Units)
Purchased as Part of
Publicly Announced
Plans or Programs

 

(d) Maximum
Number (or
Approximate
Dollar Value) of
Shares (or Units)
that May Yet Be
Purchased Under
the Plans or
Programs

October 30, 2008

 

(1)  788,200

 

$

1.12

 

 


(1) The repurchase was from an unaffiliated accredited investor through a negotiated transaction.

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

 

Not applicable.

 

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

 

The following items were presented for approval to stockholders of record on October 24, 2008 at the Company’s annual meeting of stockholders which was held on December 9, 2008 in Houston, Texas:

 

1.               Election of Directors:  The following nominees were elected to serve as Directors of Evolution Petroleum Corporation until the 2009 annual meeting of stockholders, or until their successors are elected and qualified:

 

 

 

For

 

Withheld

Laird Q. Cagan

 

23,916,795

 

138,826

E. J. DiPaolo

 

23,889,770

 

165,851

William Dozier

 

23,970,483

 

85,138

Robert S. Herlin

 

23,970,483

 

85,138

Kelly W. Loyd

 

23,970,483

 

85,138

Gene Stoever

 

23,970,470

 

85,151

 

No other person received any votes.

 

2.               Ratification of Hein & Associates LLP, as independent registered public accounting firm of the Company for the fiscal year ending June 30, 2009.  The voting was as follows:

 

For

 

Against

 

Withheld

23,883,702

 

167,878

 

4,041

 

All matters received the required number of votes for approval.

 

ITEM 5. OTHER INFORMATION

 

(a)  Effective December 31, 2008, the Company and Laird Q. Cagan, a member of our Board of Directors, agreed to modify that certain  letter agreement dated February 13, 2006 between the Company and Cagan McAfee Capital Partners, LLC to eliminate the cash advisory services fee of $5,000 per month.  In conjunction with this modification, the Company agreed to provide remuneration to Mr. Cagan consistent with that provided to the other outside members of our Board of Directors.

 

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ITEM 6. EXHIBITS

 

A.           Exhibits

 

10.1

 

Form of Indemnification Agreement between Evolution Petroleum Corporation. and each of its directors and officers. (Incorporated by reference to Exhibit 10.1of the Company’s Form 8-K, filed September 22, 2006)

 

 

 

31.1

 

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

 

 

 

31.2

 

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

 

 

 

32.1

 

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

 

 

 

32.2

 

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

 

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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)

 

 

Date: February 17, 2009

 

By:

/s/ STERLING H. MCDONALD

 

 

 

 

Sterling H. McDonald

 

 

 

 

Vice-President and Chief Financial Officer

 

 

 

 

 

Principal Financial and Accounting

 

 

 

 

 

Officer

 

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