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, 2009

 

 

o

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

 

For the transition period from           to           

 

Commission File Number 001-32942

 

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

Nevada

 

41-1781991

(State or other jurisdiction of incorporation or organization)

 

(IRS Employer Identification No.)

 

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

(Address of principal executive offices and zip code)

 

(713) 935-0122

(Registrant’s telephone number, including area code)

 

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

 

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

 

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

 

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 12, 2010, was 27,161,083.

 

 

 



Table of Contents

 

EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

 

 

 

Page

 

 

 

PART I. FINANCIAL INFORMATION

3

 

 

 

ITEM 1.

CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

3

 

 

 

 

Consolidated Balance Sheets (unaudited) as of December 31, 2009 and June 30, 2009

3

 

Consolidated Statements of Operations (unaudited) for the three and six months ended December 31, 2009 and 2008

4

 

Consolidated Statements of Cash Flows (unaudited) for the six months ended December 31, 2009 and 2008

5

 

Notes to Consolidated Condensed Financial Statements (unaudited)

6

 

 

 

ITEM 2.

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

13

 

 

 

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

21

 

 

 

ITEM 4.

CONTROLS AND PROCEDURES

21

 

 

 

PART II. OTHER INFORMATION

21

 

 

 

ITEM 1.

LEGAL PROCEEDINGS

21

 

 

 

ITEM 1A.

RISK FACTORS

21

 

 

 

ITEM 2.

UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS

21

 

 

 

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

21

 

 

 

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

22

 

 

 

ITEM 5.

OTHER INFORMATION

22

 

 

 

ITEM 6.

EXHIBITS

22

 

 

 

SIGNATURES

23

 

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,

 

June 30,

 

 

 

2009

 

2009

 

Assets

 

 

 

 

 

Current assets

 

 

 

 

 

Cash and cash equivalents

 

$

2,312,212

 

$

3,891,764

 

Certificates of deposit

 

1,651,835

 

2,059,147

 

Receivables

 

 

 

 

 

Oil and natural gas sales

 

542,738

 

532,318

 

Income taxes

 

2,095,126

 

 

Other

 

61,245

 

172,314

 

Income taxes recoverable

 

 

2,055,802

 

Prepaid expenses and other current assets

 

148,260

 

162,441

 

Total current assets

 

6,811,416

 

8,873,786

 

 

 

 

 

 

 

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

 

 

 

 

 

Oil and natural gas properties — full-cost method of accounting, of which $11,082,567 and $9,819,465 at December 31, 2009 and June 30, 2009, respectively, were excluded from amortization

 

29,801,618

 

28,751,178

 

Other property and equipment

 

123,271

 

150,697

 

Total property and equipment

 

29,924,889

 

28,901,875

 

 

 

 

 

 

 

Other assets

 

53,007

 

53,162

 

 

 

 

 

 

 

Total assets

 

$

36,789,312

 

$

37,828,823

 

 

 

 

 

 

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities

 

 

 

 

 

Accounts payable

 

$

747,476

 

$

690,639

 

Accrued liabilities

 

100,028

 

171,052

 

Royalties payable

 

262,127

 

218,477

 

State taxes payable

 

 

157,736

 

Total current liabilities

 

1,109,631

 

1,237,904

 

 

 

 

 

 

 

Long-term liabilities

 

 

 

 

 

Deferred income taxes

 

3,095,161

 

3,721,317

 

Asset retirement obligations

 

758,027

 

664,710

 

Stock bonus (Note 5)

 

 

370,440

 

Accrued compensation

 

210,000

 

 

Deferred rent

 

79,746

 

77,858

 

 

 

 

 

 

 

Total liabilities

 

5,252,565

 

6,072,229

 

 

 

 

 

 

 

Commitments and contingencies (Note 10)

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ equity

 

 

 

 

 

Preferred stock, par value $0.001; 5,000,000 shares authorized; no shares issued or outstanding

 

 

 

Common stock; par value $0.001; 100,000,000 shares authorized; issued 27,949,283 shares and 27,318,517 shares as of December 31, 2009 and June 30, 2009, respectively; outstanding 27,161,083 shares and 26,530,317 shares as of December 31, 2009 and June 30, 2009, respectively

 

27,949

 

27,318

 

Additional paid-in capital

 

17,611,155

 

16,424,868

 

Retained earnings

 

14,779,665

 

16,186,430

 

 

 

32,418,769

 

32,638,616

 

Treasury stock, at cost, 788,200 shares as of December 31, 2009 and June 30, 2009

 

(882,022

)

(882,022

)

 

 

 

 

 

 

Total stockholders’ equity

 

31,536,747

 

31,756,594

 

 

 

 

 

 

 

Total liabilities and stockholders’ equity

 

$

36,789,312

 

$

37,828,823

 

 

See accompanying notes to consolidated financial statements.

 

3



Table of Contents

 

Evolution Petroleum Corporation and Subsidiaries

Consolidated Statements of Operations

(unaudited)

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

December 31,

 

December 31,

 

 

 

2009

 

2008

 

2009

 

2008

 

Revenues

 

 

 

 

 

 

 

 

 

Crude oil

 

$

456,375

 

$

407,194

 

$

959,497

 

$

1,986,264

 

Natural gas liquids

 

280,212

 

235,293

 

565,523

 

990,738

 

Natural gas

 

464,715

 

389,295

 

846,309

 

969,766

 

Total revenues

 

1,201,302

 

1,031,782

 

2,371,329

 

3,946,768

 

 

 

 

 

 

 

 

 

 

 

Operating Costs

 

 

 

 

 

 

 

 

 

Lease operating expense

 

369,928

 

313,406

 

734,774

 

649,310

 

Production taxes

 

16,459

 

21,776

 

34,826

 

107,772

 

Depreciation, depletion and amortization

 

550,142

 

504,291

 

1,167,899

 

1,149,173

 

Accretion of asset retirement obligations

 

15,200

 

6,124

 

29,538

 

11,861

 

General and administrative *

 

1,253,596

 

1,662,627

 

2,506,712

 

3,127,467

 

Total operating costs

 

2,205,325

 

2,508,224

 

4,473,749

 

5,045,583

 

 

 

 

 

 

 

 

 

 

 

Loss from operations

 

(1,004,023

)

(1,476,442

)

(2,102,420

)

(1,098,815

)

 

 

 

 

 

 

 

 

 

 

Other income

 

 

 

 

 

 

 

 

 

Interest income

 

13,785

 

17,782

 

29,009

 

91,428

 

 

 

 

 

 

 

 

 

 

 

Net loss before income tax benefit

 

(990,238

)

(1,458,660

)

(2,073,411

)

(1,007,387

)

 

 

 

 

 

 

 

 

 

 

Income tax benefit

 

288,298

 

454,889

 

666,646

 

152,053

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

$

(701,940

)

$

(1,003,771

)

$

(1,406,765

)

$

(855,334)

 

 

 

 

 

 

 

 

 

 

 

Loss per common share

 

 

 

 

 

 

 

 

 

Basic and Diluted

 

$

(0.03

)

$

(0.04

)

$

(0.05

)

$

(0.03

)

 

 

 

 

 

 

 

 

 

 

Weighted average number of common shares

 

 

 

 

 

 

 

 

 

Basic and Diluted

 

27,092,954

 

26,399,988

 

26,869,488

 

26,646,149

 

 


*General and administrative expenses for the three month period ended December 31, 2009 and 2008 included non-cash stock-based compensation expense of $424,800 and $584,525, respectively. General and administrative expenses for the six month period ended December 31, 2009 and 2008 included non-cash stock-based compensation expense of $816,436 and $1,108,250, respectively.

 

See accompanying notes to consolidated financial statements.

 

4



Table of Contents

 

Evolution Petroleum Corporation and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

 

 

 

Six Months Ended
December 31,

 

 

 

2009

 

2008

 

Cash flows from operating activities

 

 

 

 

 

Net loss

 

$

(1,406,765

)

$

(855,334

)

Adjustments to reconcile net loss to net cash provided by operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

1,167,899

 

1,149,173

 

Stock-based compensation

 

816,436

 

1,108,250

 

Accretion of asset retirement obligations

 

29,538

 

11,861

 

Deferred income taxes

 

(626,156

)

(219,008

)

Deferred rent

 

1,888

 

1,888

 

Other

 

213,118

 

3,118

 

Changes in operating assets and liabilities

 

 

 

 

 

Receivables from oil and natural gas sales

 

(10,420

)

1,658,525

 

Receivables from income taxes and other

 

71,745

 

4,031,914

 

Prepaid expenses and other current assets

 

14,181

 

113,942

 

Accounts payable and accrued expenses

 

139,474

 

(314,436

)

Royalties payable

 

43,650

 

(282,051

)

State taxes payable

 

(157,736

)

 

Net cash provided by operating activities

 

296,852

 

6,407,842

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

Development of oil and natural gas properties

 

(2,222,654

)

(4,723,006

)

Acquisitions of oil and natural gas properties

 

(58,141

)

(2,033,874

)

Capital expenditures for other equipment

 

 

(26,602

)

Purchases of certificates of deposit

 

(1,350,000

)

(1,500,000

)

Maturities of certificates of deposit

 

1,757,312

 

 

Other assets

 

(2,963

)

 

Net cash used in investing activities

 

(1,876,446

)

(8,283,482

)

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

Proceeds from the issuance of restricted common stock

 

42

 

90

 

Purchase of treasury stock

 

 

(882,022

)

Net cash provided by (used in) financing activities

 

42

 

(881,932

)

 

 

 

 

 

 

Net decrease in cash and cash equivalents

 

(1,579,552

)

(2,757,572

)

 

 

 

 

 

 

Cash and cash equivalents, beginning of period

 

3,891,764

 

11,272,280

 

 

 

 

 

 

 

Cash and cash equivalents, end of period

 

$

2,312,212

 

$

8,514,708

 

 

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

 

 

 

Six Months Ended
December 31,

 

 

 

2009

 

2008

 

 

 

 

 

 

 

Income taxes paid

 

$

166,015

 

$

15,000

 

 

 

 

 

 

 

Income tax refunds and carry backs received

 

$

 

$

4,052,631

 

 

 

 

 

 

 

Non-cash transactions:

 

 

 

 

 

Decrease in accounts payable used to acquire oil and natural gas leasehold interests and develop oil and natural gas properties

 

$

(153,661

)

$

(285,333

)

Oil and natural gas properties incurred through recognition of asset retirement obligations

 

$

63,779

 

$

107,751

 

Common stock issued in lieu of a portion of 2008 cash bonus accrued as a short-term liability 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”), including 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 2009 Annual Report on Form 10-K for the year ended June 30, 2009, 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, the amounts recoverable from the carry-back of income tax losses 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 “Modernization Requirements”).  The Modernization Requirements, when effective, provide for consideration of current technology in evaluating reserves, allow companies to disclose their probable and possible reserves to investors, require reporting of oil and gas reserves using an average price based on the prior 12-month period rather than period-end prices, revise the disclosure requirements for oil and gas operations, and revise accounting for the limitation on capitalized costs for full cost companies.  The Modernization Requirements are expected to be effective for fiscal years ending on or after December 31, 2009.  A company may not apply the Modernization Requirements 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 Modernization Requirements will have on our financial statements.

 

The SEC staff issued Staff Accounting Bulletin (“SAB”) 113 (“SAB 113”), which revises portions of the guidance included in SAB Topic 12, Oil and Gas Producing Activities.  Specifically, SAB 113 revises the relevant interpretive guidance in SAB Topic 12 to conform it to the Modernization Requirements.

 

On January 6, 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-03 Extractive Activities - Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures, an update of ASC Topic 932 Extractive Activities - Oil and Gas (“Topic 932”), which substantially aligns the reserve estimation, disclosure requirements, and definitions of Topic 932 with the disclosure requirements of the Modernization Requirements issued by the SEC.

 

6



Table of Contents

 

Note 3 — Property and Equipment

 

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

 

 

 

December 31,
2009

 

June 30,
2009

 

Oil and natural gas properties

 

 

 

 

 

Property costs subject to amortization

 

$

22,913,761

 

$

21,985,950

 

Less: Accumulated depreciation, depletion, and amortization

 

(4,194,710

)

(3,054,237

)

Unproved properties not subject to amortization

 

11,082,567

 

9,819,465

 

Oil and natural gas properties, net

 

$

29,801,618

 

$

28,751,178

 

 

 

 

 

 

 

Other property and equipment

 

 

 

 

 

Furniture, fixtures and office equipment, at cost

 

260,476

 

260,476

 

Less: Accumulated depreciation

 

(137,205

)

(109,779

)

Other property and equipment, net

 

$

123,271

 

$

150,697

 

 

Unproved properties not subject to amortization include unevaluated acreage of $7.5 million as of December 31, 2009 and June 30, 2009, consisting of properties in the Giddings Field in Central Texas, the Woodford Shale trend in Oklahoma, and the Lopez Field in South Texas (our “Neptune oil project”).  Unproved properties also include $2.0 million as of December 31, 2009 and June 30, 2009, of participating interests through royalty and overriding royalty interests aggregating 7.4% in the Delhi Holt Bryant Unit of the Delhi Field in Louisiana and a 25% after payout reversionary working interest in the Delhi Holt Bryant Unit along with a 25% working interest in certain other depths in the Delhi Field.  We incurred $1.0 million and $0.3 million as of December 31, 2009 and June 30, 2009, respectively, related to the drilling of three test wells and re-entry of four test wells on our acreage in Wagoner County in Oklahoma and $0.6 million as of December 31, 2009 on two wells in our acreage in South Texas.  Production testing of our wells in Oklahoma and South Texas is ongoing.  Evaluation of our unproved properties is expected to be completed within one to five years.  Our evaluation of impairment of unproved properties occurs, at a minimum, on a quarterly basis.

 

Note 4 Asset Retirement Obligations

 

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

 

Asset retirement obligations — beginning of period

 

$

664,710

 

Liabilities incurred

 

63,779

 

Accretion

 

29,538

 

Asset retirement obligations — end of period

 

$

758,027

 

 

Note 5 — Stockholders’ Equity

 

On September 8, 2009, the Board of Directors authorized and the Company issued 138,224 unrestricted and fully vested shares of common stock from the 2004 Stock Plan to certain employees for the payment of fiscal 2009 bonuses.  The value of the shares issued was $370,440, based on the fair market value on the date of issuance, or $2.68 per share.  The amount of bonus was accrued as of June 30, 2009 and recognized as a long-term liability. On September 8, 2009, when the shares were issued, the liability was reclassified to stockholders’ equity.

 

On September 8, 2009, the Board of Directors authorized and the Company issued 324,597 shares of restricted common stock from the 2004 Stock Plan to employees as a long-term incentive award.

 

On October 27, 2009, 119,795 shares of common stock were issued through a net cashless exercise of a placement warrant.  The placement warrant, which was issued to Cagan McAfee Capital Partners, LLC (“CMCP”), a related party (See Note 8), on May 26, 2004 in connection with a financing transaction, gave CMCP the right to purchase 165,000 shares, with an exercise price of $1.00 per share (See Note 9).

 

On November 10, 2009, 5,833 shares of common stock were issued through a net cashless exercise of a placement warrant.  The placement warrant, issued on November 30, 2004 in connection with a financing transaction, gave the holder the right to purchase 10,000 shares, with an exercise price of $1.50 per share (See Note 9).

 

7



Table of Contents

 

Note 5 — Stockholders’ Equity (Continued)

 

On December 9, 2009, a total of 42,317 shares of restricted common stock was issued to four outside directors as part of their board compensation for calendar year 2010.  All issuances of common stock were subject to vesting terms per individual stock agreements, which is generally one year for directors.

 

Note 6 Stock-Based Incentive Plan

 

We may grant option awards to purchase common stock (the “Stock Options”), restricted common stock awards (“Restricted Stock”), and unrestricted and fully vested common stock, to employees, directors, and consultants of the Company and its subsidiaries under the Natural Gas Systems Inc. 2003 Stock Plan (the “2003 Stock Plan”) and the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the “2004 Stock Plan” or together, the “EPM Stock Plans”).  Option awards for the purchase of 600,000 shares of common stock were issued under the 2003 Stock Plan.  The 2004 Stock Plan authorized the issuance of 5,500,000 shares of common stock.  No shares are available for grant under the 2003 Stock Plan and, as of December 31, 2009, 501,323 shares remain available for grant under the 2004 Stock Plan.

 

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

 

Stock Options and Incentive Warrants

 

Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the three months ended December 31, 2009 and 2008 was $261,762 and $499,994, respectively.  Non-cash stock-based compensation expense related to Stock Options and Incentive Warrants for the six months ended December 31, 2009 and 2008 was $527,014 and $945,987, respectively.

 

There were no Stock Options granted during the six months ended December 31, 2009.  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.  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 vest quarterly, on a straight line basis, over a period of four years and have a contractual life of seven years.

 

The weighted average assumptions used to calculate the fair value of these Stock Options and the weighted average fair value of each option granted are as follows:

 

 

 

Six Months Ended

 

 

 

December 31,

 

 

 

2009

 

2008

 

Expected volatility

 

 

87.1

%

Expected dividends

 

 

 

Expected term (in years)

 

 

4.6

 

Risk-free rate

 

 

3.10

%

Fair value

 

 

$

2.62

 

 

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

 

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Table of Contents

 

Note 6 Stock-Based Incentive Plan (Continued)

 

The following summary presents information regarding outstanding Stock Options and Incentive Warrants as of December 31, 2009, and the changes during the period:

 

 

 

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, 2009

 

5,485,820

 

$

1.83

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Granted

 

 

 

 

 

 

 

Exercised

 

 

 

 

 

 

 

Cancelled or forfeited

 

 

 

 

 

 

 

Expired

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock Options and Incentive Warrants outstanding at December 31, 2009

 

5,485,820

 

$

1.83

 

$

13,944,050

 

5.9

 

 

 

 

 

 

 

 

 

 

 

Vested or expected to vest

 

5,485,820

 

$

1.83

 

$

13,944,050

 

5.9

 

 

 

 

 

 

 

 

 

 

 

Exercisable at December 31, 2009

 

4,675,447

 

$

1.67

 

$

12,640,049

 

5.7

 

 


(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($4.37 as of December 31, 2009) and the Stock Option or Incentive Warrant exercise price of in-the-money Stock Options and Incentive Warrants.

 

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

 

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

 

 

 

Number of
Stock Options
and Incentive
Warrants

 

Weighted
Average Grant-
Date Fair Value

 

 

 

 

 

 

 

Unvested at July 1, 2009

 

1,091,912

 

$

2.66

 

 

 

 

 

 

 

Granted

 

 

$

 

 

 

 

 

 

 

Vested

 

(281,539

)

$

2.34

 

 

 

 

 

 

 

Unvested at December 31, 2009

 

810,373

 

$

2.77

 

 

During the six months ended December 31, 2009 and 2008, there were 281,539 and 455,000 Stock Options and Incentive Warrants that vested with a total grant date fair value of $658,801 and $768,950, respectively.

 

The total unrecognized compensation cost at December 31, 2009, relating to non-vested Stock Options and Incentive Warrants was $1,532,839.  Such unrecognized expense is expected to be recognized over a weighted average period of 1.9 years.

 

Restricted Stock

 

Stock-based compensation expense related to Restricted Stock grants for the three months ended December 31, 2009 and 2008 was $163,038 and $84,531, respectively.  Stock-based compensation expense related to Restricted Stock grants for the six months ended December 31, 2009 and 2008 was $289,422 and $162,263, respectively.

 

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Table of Contents

 

Note 6 Stock-Based Incentive Plan (Continued)

 

On September 8, 2009, the Board of Directors authorized and the Company issued 324,597 shares of restricted common stock from the 2004 Stock Plan to employees as a long-term incentive award.  Total unrecognized stock-based compensation expense of $869,917 related to the long-term incentive award will be recognized ratably over a four year vesting period.

 

On December 9, 2009, a total of 42,317 shares of restricted common stock was issued to four outside directors as part of their board compensation for calendar year 2010.  Total unrecognized stock-based compensation expense of $167,956 related to board compensation will be recognized ratably over a one year vesting period.  In the previous year, a total of 130,113 shares of restricted common stock was issued to the same outside directors as part of their board compensation for calendar year 2009, and which vested in December 2010.

 

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

 

 

 

Number of
Restricted
Shares

 

Weighted
Average
Grant-Date
Fair Value

 

 

 

 

 

 

 

Unvested at July 1, 2009

 

390,283

 

$

3.37

 

 

 

 

 

 

 

Granted

 

366,914

 

$

2.83

 

 

 

 

 

 

 

Vested

 

(150,401

)

$

3.30

 

 

 

 

 

 

 

Unvested at December 31, 2009

 

606,796

 

$

3.06

 

 

At December 31, 2009, unrecognized stock-based compensation expense related to Restricted Stock grants totaled $1,969,701.  Such unrecognized expense is expected to be recognized over a weighted average period of 3.4 years.

 

Note 7 Income Taxes

 

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

 

Since the FASB required recognition of unrecognized tax benefits and through December 31, 2009, there were no unrecognized tax benefits or accrued interest or penalties associated with unrecognized tax benefits.  We believe that we have appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors, including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the years ending June 30, 2007 through June 30, 2009.

 

Our effective tax rate for any period may differ from the statutory federal rate, due primarily to stock-based compensation related to qualified incentive stock option awards (“ISO awards”), a permanent tax difference for financial reporting, as these types of awards, if certain conditions are met, are not deductible for federal tax purposes.

 

In January 2010, we received $2.1 million from the Internal Revenue Service as a result of the carry-back of our tax loss for the year ended June 30, 2009, for income taxes paid for our year ended June 30, 2007.  Significant intangible drilling costs were incurred during the 2009 fiscal year, of which, we elected to expense approximately $4.8 million for federal income tax purposes.  Under GAAP, and specifically the full-cost accounting method, intangible drilling costs are capitalized as part of oil and natural gas properties, and depleted using the unit-of-production method.  The deduction of intangible drilling costs created a significant difference in the income tax and book basis of our oil and natural gas properties, the most significant component of our deferred income tax liability as of December 31, 2009 and June 30, 2009.

 

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Table of Contents

 

Note 8 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 Colorado Financial Services Corporation 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.  We have not paid placement fees to CMCP under this agreement since May 2006.  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.  During the three months ended September 30, 2008, we expensed and paid CMCP $15,000 through monthly retainers of $5,000.  There were no other transactions with CMCP, except for the exercise of stock warrants during the six months ended December 31, 2009 (See Note 5).

 

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

 

Note 9 — Net loss Per Share

 

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

 

 

 

Three Months Ended
December 31,

 

Six Months Ended
December 31,

 

 

 

2009

 

2008

 

2009

 

2008

 

Numerator

 

 

 

 

 

 

 

 

 

Net loss

 

$

(701,940

)

$

(1,003,771

)

$

(1,406,765

)

$

(855,334

)

 

 

 

 

 

 

 

 

 

 

Denominator*

 

 

 

 

 

 

 

 

 

Weighted average number of common shares — basic and diluted

 

27,092,954

 

26,399,988

 

26,869,488

 

26,646,149

 

 

 

 

 

 

 

 

 

 

 

Net loss per common share — basic and diluted

 

$

(0.03

)

$

(0.04

)

$

(0.05

)

$

(0.03

)

 


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

 

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

 

Outstanding Potential Dilutive Securities

 

Weighted
Average
Exercise Price

 

Outstanding at
December 31, 2009

 

 

 

 

 

 

 

Common stock warrants issued in connection with equity and financing transactions

 

$

1.89

 

173,058

 

Stock Options and Incentive Warrants

 

$

1.83

 

5,485,820

 

Total

 

$

1.83

 

5,658,878

 

 

Total outstanding potentially dilutive securities 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

 

Total

 

$

2.01

 

6,475,648

 

 

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Table of Contents

 

Note 10 — Commitments and Contingencies

 

We are subject to various claims and contingencies in the normal course of business.  In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdiction in which we operate.  We disclose such matters if we believe it is reasonably possible that a future event or events will confirm a loss through impairment of an asset or the incurrence of a liability. We establish reserves if we believe it is probable that a future event or events will confirm a loss and we can reasonably estimate such loss.  Furthermore, we will disclose any matter that is unasserted if we consider it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable.  As of December 31, 2009, and subsequently through the date these financial statements were issued, no claim or unasserted claim existed that required an accrual or disclosure.

 

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, 2009 under this operating lease are as follows:

 

For the year ended December 31,

 

 

 

2010

 

$

138,089

 

2011

 

146,806

 

2012

 

159,011

 

2013

 

159,011

 

2014

 

159,011

 

Thereafter

 

251,767

 

Total

 

$

1,013,695

 

 

Rent expense for the three months ended December 31, 2009 and 2008 was 39,232 and 35,466, respectively.  Rent expense for the six months ended December 31, 2009 and 2008 was 78,962 and 70,933, respectively.

 

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

 

Note 11 Subsequent Events

 

Through February 12, 2010, the date these financial statements were issued, there were no significant subsequent events that would require disclosure or adjustment to the financial statements.

 

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Table of Contents

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following is Management’s Discussion and Analysis (“MD&A”) of our financial position and operating results during the periods included in the accompanying unaudited consolidated financial statements. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes thereto, included elsewhere in this Quarterly Report on Form 10-Q and should further be read in conjunction with our Annual Report on Form 10-K for the year ended June 30, 2009.

 

Forward-Looking Information

 

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 2009 Annual Report on Form 10-K for the year ended June 30, 2009 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.

 

General Overview

 

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 originate project development concepts, capture such opportunities through the acquisition of 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 our EOR project in the 13,636 acre Delhi Field, located in northeast Louisiana.  Our interests consist of 7.4% in overriding and mineral royalty interests, a 25% after pay-out reversionary working interest (20% revenue interest) in the Delhi Field Holt Bryant Unit, and a 25% working interest (20% revenue 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. (the “Operator”) (the “Delhi Farmout”).  The Holt Bryant Unit is currently being redeveloped by the Operator, using CO2 enhanced oil recovery technology and a dedicated portion of the Operator’s proved CO2 reserves in the Jackson Dome, located approximately 100 miles east of Delhi.  On November 12, 2009, the Operator announced that CO2 injection had begun at the Delhi Field and that an initial oil production response was expected by mid-year calendar 2010.

 

Since our closing of the Delhi Farmout, we have focused on developing projects in our other initiatives through conventional redevelopment of oil and rich gas in the Giddings Field using horizontal drilling, development of gas resources in the shallow portion of the Woodford and Caney Shale Trend in Eastern Oklahoma, development of potential oil reserves in the mature Lopez Field within our Neptune oil project in South Texas and development of our proprietary artificial lift technology intended to extend the life of horizontal wells with oil or associated water production.

 

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.

 

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Table of Contents

 

Highlights for our Second Quarter 2010

 

Projects

 

·                 CO2 injection began at Delhi during this fiscal quarter.  As previously reported, the Delhi operator announced that CO2 injection had begun on November 12, 2009, and that they expected first oil production to begin by mid-calendar 2010.

 

·                 Field testing of our proprietary lift technology continues to be successful at Giddings.  We installed the first field application of our lift technology last June in the Donella #1 and the well appears to be capable of economic production, although it was shut-in for compressor repairs at the end of the quarter.  We recently installed a partial application of the lift technology to another producing well at Giddings, the Williams #1, during a normal workover, and the combination of the technology and installation of a rod pump have substantially enhanced production. We also are in early stage discussions with third parties to potentially apply our technology to their marginal, uneconomic or shut-in wells.

 

·                 We are adding a water injection well to our Neptune oil project.  We have completed the drilling of the first two producer wells in the Lopez Field in South Texas within our Neptune oil project and are currently re-entering another well to convert to water injection.  We are also working to obtain electric power in the field, and expect to be able to begin production testing in the third fiscal quarter of 2010.  We hold 1,710 net acres with the potential for up to 111 additional drilling locations, of which four locations have been assigned by our outside reservoir engineer as proved.

 

·                 We initiated production testing in our Oklahoma gas shale project.    During the quarter, we hydraulically fractured a vertical test well in the Woodford Shale and a vertical test well in the Caney Shale in our Wagoner County project.  To date, the Caney well has consistently produced water free at a low gas rate, confirming that the Caney Shale can contribute commercial gas volumes as an add-on to our Woodford production. Initial test production in the Woodford formation was promising, both in gas and water rates, but we are unable to produce this well currently until the water disposal well is deepened to handle the water rate.  This work is underway and we expect to be production testing the Woodford during our third fiscal quarter.

 

Operations

 

·                 Sales volumes increased 22% and product prices declined 5%, resulting in a 16% increase in revenues during our second quarter of fiscal 2010 compared to our second quarter of fiscal 2009.  Essentially 100% of our production for the three months ended December 31, 2009 and 2008 was attributable to our properties in the Giddings Field.  Declines in crude oil and NGL production were more than offset by an increase in natural gas production.  A 29% decline in natural gas prices and a higher gas component in the commodity mix of our sales volumes were partially offset by a 30% increase in oil and NGL prices.  Natural gas accounted for 58% of our volumes sold during the current period compared to 42% for the same period in fiscal 2009.  During the three months ended December 31, 2009, the average price we received was $38.46 per BOE, as compared to $40.29 per BOE during the three months ended December 31, 2008.

 

·                 Our production declines generally have flattened, although net production was impacted by downtime to install our artificial lift technology on the Williams #1 and what we believe to be continued constrained production at the Hilton-Yegua #1 due to a likely obstruction in the horizontal section of the well.  Net production during the quarter averaged approximately 340 net BOE per day, compared to a quarterly rate of 380 net BOE per day and 278 net BOE per day for the three months ended September 30, 2009 and December 31, 2008, respectively.  In particular, our best well, the Pearson #1, has stabilized at a productive gross rate of approximately 1.2 MMCFE per day after eleven months of production.

 

·                 Our field costs have stabilized.  During the three months ended December 31, 2009, lifting costs (lease operating expense and production taxes, on a combined per unit of sales basis) were $12.37 and our depletion rate was $17.27 per BOE, equaling a field income break-even point of $29.64 per BOE.  This compares to lifting costs of $10.95 and a depletion rate of $17.17 per BOE, equaling a field income break-even point of $28.12 per BOE, during the quarter ended September 30, 2009 and lifting costs of $13.09 and a depletion rate of $19.31 per BOE, equaling a field income break-even point of $32.40 per BOE for the quarter ended December 31, 2008.

 

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Table of Contents

 

Finances

 

·                 We ended our 2nd quarter of fiscal 2010 with $5.7 million of working capital, compared to $7.6 million at June 30, 2009.  At December 31, 2009, working capital included $4.0 million of cash, cash equivalents and short-term certificates of deposit, and $2.1 million of income taxes recoverable from federal taxes paid for our year ended June 30, 2007, as a result of a carry-back of our tax loss for the year ended June 30, 2009.  We received payment for the $2.1 million receivable from the Internal Revenue Service in January 2010.  The $1.9 million reduction in our working capital since June 30, 2009, was due to investments of $2.1 million in oil and natural gas properties.

 

·                 Cash flows from operations provided for our general and administrative expenses and funded a portion of our capital expenditures.  Our decrease in working capital since the beginning of our 2010 fiscal year was due entirely to capital spending on our oil and gas projects.  Cash flows from operations were $296,852 during the six months ended December 31, 2009.

 

·                 G&A expense was reduced 25% and 20% during the three and six months ended December 31, 2009, respectively, as compared to the respective periods in the prior fiscal year.  In addition to reduced non-cash stock-based compensation expense, we have reduced our staff and legal costs during the year.

 

·                 We remained debt free. All of our expenditures were funded solely by working capital and we ended the quarter with no funded debt.

 

Looking forward

 

We continue to focus on:

 

Selective low cost testing and development of our portfolio properties.

 

·                 Upgrade our shallow multi-pay shale gas reserves.  Continue our production testing in the Oklahoma shallow Woodford and Caney gas shales to demonstrate production rates, decline curves and ultimate recovery in order to move this project into full scale development.  Market conditions permitting, we also plan to re-enter a well in our mid-depth project in Haskell County, OK to begin testing the Woodford and Caney Shale reservoirs between 4,000’ and 5,000’ depth.

 

·                 Continue to pursue commercial joint ventures utilizing our proprietary artificial lift technology.

 

·                 Establish production in our Neptune oil project.  We expect to begin first production in two producing wells in our 100% owned Neptune oil project in South Texas during our third fiscal quarter, with the goals of upgrading potential reserves and adding oil production.

 

·                 Conduct workovers in Giddings as justified to add net production to cover our overhead.

 

·                 Develop joint venture(s) to drill or monetize undeveloped locations at Giddings.  We are considering these options to accelerate the drilling of our proved and unproved drilling locations, subject to stable natural gas, oil and NGL prices.

 

Continued progress in our Delhi EOR project.

 

·                 First oil production at Delhi is expected by the Operator by mid-calendar 2010.

 

·                 Establish proved reserves at Delhi.  Under current SEC rules, proved reserves cannot be assigned to our Delhi EOR property until the first EOR oil production response, projected by the Operator to occur by mid-year calendar 2010. Alternatively, the SEC’s “Modernization” rules that are scheduled to become effective for us on June 30, 2010, state that reservoir engineers can consider other relevant factors in assigning proved reserves to EOR projects, including current technology, the results of field pilot tests and EOR projects in geologically comparable fields, all of which we believe are characteristics of the EOR project at Delhi.

 

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Table of Contents

 

Continued conservative financial management.

 

·                 Emphasize long-term share value over near-term earnings.

 

·                 Retain financial strength, flexibility and liquidity to assure we obtain proper value of our core assets.

 

·                 Use internally generated funds and our working capital for fiscal 2010 capital plan, while considering joint ventures, project financing, asset redeployments and/or appropriate use of our common stock to fund growth through additional development of our core projects and new projects.

 

Liquidity and Capital Resources

 

For the current fiscal year, we expect to finance our budgeted oil and gas activities through our working capital and our cash flow from operating activities.

 

At December 31, 2009, our working capital was $5.7 million and we continued to be debt free.  This compares to working capital of $7.6 million at June 30, 2009.  The $1.9 million decrease in working capital since June 30, 2009, was due primarily to investments of $2.1 million in oil and natural gas properties (not including $0.1 million incurred related to recognition of asset retirement obligations).  Of the $2.1 million of incurred capital expenditures during the six months ended December 31, 2009, $0.1 million was for leasehold acquisitions and $2.0 million was for development activities.  Development activities were in the Giddings Field in Texas, our Neptune oil project in South Texas, and our gas shale project in Eastern Oklahoma.

 

Cash Flows from Operating Activities

 

Cash flows provided by operating activities for the six months ended December 31, 2009 were $0.3 million.  Cash flows provided by operations include cash receipts of $2.4 million from oil and natural gas sales, primarily from our properties in the Giddings Field, partially offset by $1.9 million of cash payments for operating expenses, including lease operating expenses, production taxes, and salaries and wages, and payment of $0.2 million in state income taxes.  In comparison, cash flows provided by operating activities for the six months ended December 31, 2008 were $6.4 million, which included 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 expenses, including lease operating expenses, production taxes, and salaries and wages.

 

Cash Flows from Investing Activities

 

Cash paid for oil and gas capital expenditures during the six months ended December 31, 2009 and 2008, was $2.3 million and $6.8 million, respectively, which includes net payments on accounts payable of $0.2 million and $0.3 million relating to prior period expenditures for oil and natural gas properties.

 

We purchased $1.4 million and $1.5 million in short-term certificates of deposit during the six months ended December 31, 2009 and 2008, respectively.   During the six months ended December 31, 2009, $1.8 million of certificates of deposit matured.

 

Cash Flows from Financing Activities

 

There were no significant cash flows from financing activities during the six months ended December 31, 2009.  On October 30, 2008, we repurchased 788,200 shares of common stock at an average price of $1.10 per share plus $0.02 in transaction costs from an unaffiliated accredited investor.

 

Capital Budget

 

We previously reported in our annual report for the fiscal year ended June 30, 2009, that we expect capital expenditures of approximately $3.0 million during fiscal year 2010.  As of December 31, 2009, we have incurred $2.1 million for capital expenditures related to our oil and gas activities. Due to our positive working capital, cash flows from producing properties and no debt, we believe that our current sources of liquidity are sufficient to fund our budget.

 

16



Table of Contents

 

Results of Operations

 

Three months ended December 31, 2009 and 2008

 

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

 

 

 

Three Months Ended

 

 

 

 

 

 

 

December 31

 

 

 

%

 

 

 

2009

 

2008

 

Variance

 

change

 

 

 

 

 

 

 

 

 

 

 

Sales Volumes, net to the Company:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (Bbl)

 

6,128

 

7,098

 

(970

)

(14

)%

 

 

 

 

 

 

 

 

 

 

NGLs (Bbl)

 

6,891

 

7,682

 

(791

)

(10

)%

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

109,316

 

64,973

 

44,343

 

68

%

Crude oil, NGLs and natural gas (BOE)

 

31,238

 

25,609

 

5,629

 

22

%

 

 

 

 

 

 

 

 

 

 

Revenue data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

$

456,375

 

$

407,194

 

$

49,181

 

12

%

 

 

 

 

 

 

 

 

 

 

NGLs

 

280,212

 

235,293

 

44,919

 

19

%

 

 

 

 

 

 

 

 

 

 

Natural gas

 

464,715

 

389,295

 

75,420

 

19

%

Total revenues

 

$

1,201,302

 

$

1,031,782

 

$

169,520

 

16

%

 

 

 

 

 

 

 

 

 

 

Average price:

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

74.47

 

$

57.37

 

$

17.10

 

30

%

NGLs (per Bbl)

 

40.66

 

30.63

 

10.03

 

33

%

Natural gas (per Mcf)

 

4.25

 

5.99

 

(1.74

)

(29

)%

Crude oil, NGLs and natural gas (per BOE)

 

$

38.46

 

$

40.29

 

$

(1.83

)

(5

)%

 

 

 

 

 

 

 

 

 

 

Expenses (per BOE)

 

 

 

 

 

 

 

 

 

Lease operating expenses and production taxes

 

$

12.37

 

$

13.09

 

$

(0.72

)

(6

)%

Depletion expense on oil and natural gas properties (a)

 

$

17.27

 

$

19.31

 

$

(2.04

)

(11

)%

 


(a)          Excludes depreciation of office equipment, furniture and fixtures and other equipment of $10,799 and $9,794, for the three months ended December 31, 2009 and 2008, respectively.

 

Net loss.  For the three months ended December 31, 2009, we reported a net loss of $701,940 or $0.03 loss per share (which includes $424,800 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $1,201,302.  This compares to a net loss of $1,003,771, or $0.04 per share (which includes $584,525 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $1,031,782 for the three months ended December 31, 2008.  An increase in our revenues of $169,520 and a decrease in operating expenses of $302,899 were partially offset by a slight decrease in interest income and a decrease of $166,591 in our income tax benefit.  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, 2009 increased 22% to 31,238 BOE, compared to 25,609 BOE for the three months December 31, 2008.  Our sales volumes for the three months ended December 31, 2009 and 2008 were primarily from our properties in the Giddings Field in Texas.  Sales volumes of natural gas increased 68%, while sales volumes of crude oil and NGLs decreased 12% compared to the three months ended December 31, 2008.

 

Petroleum Revenues.  Crude oil, NGLs and natural gas revenues for the three months ended December 31, 2009 increased 16% from the three months ended December 31, 2008.  The increase was due to a 22% increase in sales volumes, partially offset by a 5% decline in the weighted-average price received per BOE, from $40 per BOE for the three months ended December 31, 2008 to $38 per BOE for the three months ended December 31, 2009.

 

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Table of Contents

 

Lease Operating Expenses (including production severance taxes).  Lease operating expenses and production taxes for the three months ended December 31, 2009 increased 15% compared to the three months ended December 31, 2008, primarily due to the additions of three producing wells and ad valorem taxes assessed in calendar year 2009.  Lease operating expense and production taxes per barrel of oil equivalent decreased 6% from $13.09 per BOE during the three months ended December 31, 2008, to $12.37 per BOE during the three months ended December 31, 2009.  Production taxes comprise $0.53 per BOE for the period ended December 31, 2009 compared to $0.85 in the same period of the prior year.

 

General and Administrative Expenses (“G&A”).  G&A expenses decreased 25% to $1.3 million for the three months ended December 31, 2009, compared to $1.7 million for the three months ended December 31, 2008.  The reduction was due to a decrease in non-cash stock-based compensation expense, which was $424,800 (34% of total G&A) and $584,525 (35% of total G&A) for the three months ended December 31, 2009 and 2008, respectively, a 28% reduction in personnel costs, due to a reduction in staff and estimated annual bonus payments, and a reduction of legal fees of approximately $115,000 due to the settlement of the Delhi litigation in July 2009.  Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and, as a result, will likely continue to be a significant component of our G&A costs.

 

Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A increased by 9% to $550,142 for the three months ended December 31, 2009, compared to $504,291 for the three months ended December 31, 2008.  The increase is primarily due to a 22% increase in net sales volumes, partially offset by a lower depletion rate ($17.27 vs. $19.31) per BOE, as a result of the reduction in projected capital expenditures associated with our proved undeveloped locations in our properties in the Giddings Field.

 

Interest Income.  Interest income for the three months ended December 31, 2009 decreased $3,997 to $13,785, compared to $17,782 for the three months ended December 31, 2008.  The decrease in interest income is due to much lower short-term investment balances averaging $4.5 million during the three months ended December 31, 2009, as compared to short-term investment balances averaging $9.8 million during the three months ended December 31, 2008.  We redeployed cash during the end of calendar year 2008 to higher yielding certificates of deposit, which partially offset the loss of interest income from a much lower invested balance.  The lower balances were primarily due to investments in our oil and natural gas properties during the prior twelve months.

 

18



Table of Contents

 

Six months ended December 31, 2009 and 2008

 

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

 

 

 

Six Months Ended

 

 

 

 

 

 

 

December 31

 

 

 

%

 

 

 

2009

 

2008

 

Variance

 

change

 

 

 

 

 

 

 

 

 

 

 

Sales Volumes, net to the Company:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil (Bbl)

 

13,698

 

19,933

 

(6,235

)

(31

)%

 

 

 

 

 

 

 

 

 

 

NGLs (Bbl)

 

15,762

 

18,745

 

(2,983

)

(16

)%

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

220,696

 

126,119

 

94,577

 

75

%

Crude oil, NGLs and natural gas (BOE)

 

66,243

 

59,698

 

6,545

 

11

%

 

 

 

 

 

 

 

 

 

 

Revenue data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

$

959,497

 

$

1,986,264

 

$

(1,026,767

)

(52

)%

 

 

 

 

 

 

 

 

 

 

NGLs

 

565,523

 

990,738

 

(425,215

)

(43

)%

 

 

 

 

 

 

 

 

 

 

Natural gas

 

846,309

 

969,766

 

(123,457

)

(13

)%

Total revenues

 

$

2,371,329

 

$

3,946,768

 

$

(1,575,439

)

(40

)%

 

 

 

 

 

 

 

 

 

 

Average price:

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

70.05

 

$

99.65

 

$

(29.60

)

(30

)%

NGLs (per Bbl)

 

35.88

 

52.85

 

(16.97

)

(32

)%

Natural gas (per Mcf)

 

3.83

 

7.69

 

(3.86

)

(50

)%

Crude oil, NGLs and natural gas (per BOE)

 

$

35.80

 

$

66.11

 

$

(30.31

)

(46

)%

 

 

 

 

 

 

 

 

 

 

Expenses (per BOE)

 

 

 

 

 

 

 

 

 

Lease operating expenses and production taxes

 

$

11.62

 

$

12.68

 

$

(1.06

)

(8

)%

Depletion expense on oil and natural gas properties (a)

 

$

17.22

 

$

18.92

 

$

(1.70

)

(9

)%

 


(a)          Excludes depreciation of office equipment, furniture and fixtures, and other of $24,293 and $19,618, for the six months ended December 31, 2009 and 2008, respectively.

 

Net loss.  For the six months ended December 31, 2009, we reported a net loss of $1,406,765, or $0.05 per share (which includes $816,436 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $2,371,329.  This compares to a net loss of $855,334, or $0.03 per share (which includes $1,108,250 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $3,946,768 for the six months ended December 31, 2008.  A decrease in our revenues of $1,575,439 and a decrease in interest income of $62,419 were partially offset by decreases in operating costs of $571,834, and an increase in our income tax benefit of $514,593.  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 six months ended December 31, 2009 increased 11% to 66,243 BOE, compared to 59,698 BOE for the six months December 31, 2008.  Our sales volumes for the six months ended December 31, 2009 and 2008 were primarily from our properties in the Giddings Field in Texas.  Production of natural gas increased 75%, while production of crude oil and NGLs decreased 24% compared to the six months ended December 31, 2008.

 

Petroleum Revenues.  Crude oil, NGLs and natural gas revenues for the six months ended December 31, 2009 decreased 40% from the six months ended December 31, 2008.  This was due to a 46% decline in the average price received per BOE, from $66 per BOE for the six months ended December 31, 2008 to $36 per BOE for the six months ended December 31, 2009.

 

Lease Operating Expenses (including production severance taxes).  Lease operating expenses and production taxes for the six months ended December 31, 2009 increased 2% compared to the six months ended December 31, 2008, despite the addition of three producing wells.  Lease operating expense and production taxes per barrel of oil equivalent decreased 8% from $12.68 per BOE during the six months ended December 31, 2008, to $11.62 per BOE during the six months ended December 31, 2009.  The decrease is primarily attributable to a decrease in production taxes.  Production taxes were $0.53 per BOE for the six months ended December 31, 2009 compared to $1.81 per BOE the same period in the prior fiscal year.

 

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Table of Contents

 

General and Administrative Expenses (“G&A”).  G&A expenses decreased 20% to $2.5 million for the six months ended December 31, 2009, compared to $3.1 million for the six months ended December 31, 2008.  The reduction was due to a decrease in non-cash stock-based compensation expense, which was $816,436 (33% of total G&A) and $1,108,250 (35% of total G&A) for the six months ended December 31, 2009 and 2008, respectively, a 22% reduction in personnel costs, due to a reduction in staff and estimated annual bonus payments, and a reduction of legal fees of approximately $77,000 due to the settlement of the Delhi litigation in July 2009.  Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and, as a result, will likely continue to be a significant component of our G&A costs.

 

Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A increased by 2% to $1,167,899 for the six months ended December 31, 2009, compared to $1,149,173 for the six months ended December 31, 2008.  The increase is primarily due to an 11% increase in net sales volumes, partially offset by a lower depletion rate ($17.22 vs. $18.92) per BOE, as a result of the reduction in projected capital expenditures associated with our proved undeveloped locations in our properties in the Giddings Field.

 

Interest Income.  Interest income for the six months ended December 31, 2009 decreased $62,419 to $29,009, compared to $91,428 for the six months ended December 31, 2008.  The decrease in interest income is due to much lower short-term investment balances averaging $5.0 million during the six months ended December 31, 2009, as compared to short-term investment balances averaging $10.3 million during the six months ended December 31, 2008.  We redeployed cash during the end of calendar 2008 to higher yielding certificates of deposit, which partially offset the loss of interest income from a much lower invested balance.  The lower balances were primarily due to investments in our oil and natural gas properties during the prior twelve months.

 

Inflation.  Although the general inflation rate in the United States, as measured by the Consumer Price Index and the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services.  With the general rise in the price of oil and natural gas products over two of the last three fiscal 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 substantial decline in both petroleum product prices and drilling and oilfield services costs.  However, product prices, operating costs and development costs may not always move in tandem.

 

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 uncertain future 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 decreases in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues and working capital going forward.

 

Seasonality.  Our business is generally not 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, 2009.

 

20



Table of Contents

 

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

 

Information about market risks for the three months ended December 31, 2009, did not change materially from the disclosures in Item 7A. of our Annual Report on Form 10-K for the year ended June 30, 2009 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, 2009.

 

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.

 

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, 2009 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, 2009 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

 

None.

 

ITEM 1A. RISK FACTORS

 

See risk factors set forth in the Company’s Annual Report on Form 10-K for the year ended June 30, 2009.

 

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

 

None.

 

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

 

Not applicable.

 

21



Table of Contents

 

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

 

The following items were presented for approval to stockholders of record on October 23, 2009 at the Company’s annual meeting of stockholders which was held on December 9, 2009 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

 

20,859,897

 

570,071

 

E. J. DiPaolo

 

19,564,956

 

1,865,012

 

William Dozier

 

19,626,412

 

1,803,556

 

Robert S. Herlin

 

19,995,593

 

1,434,375

 

Kelly W. Loyd

 

21,389,856

 

40,112

 

Gene Stoever

 

19,623,843

 

1,806,125

 

 

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, 2010.  The voting was as follows:

 

For

 

Against

 

Abstain

 

21,312,449

 

20,197

 

46,275

 

 

All matters received the required number of votes for approval.

 

ITEM 5. OTHER INFORMATION

 

None.

 

ITEM 6. EXHIBITS

 

A.           Exhibits

 

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.

 

22



Table of Contents

 

SIGNATURES

 

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

 

EVOLUTION PETROLEUM CORPORATION

(Registrant)

 

 

Date: February 12, 2010

By:

 

/s/ STERLING H. MCDONALD

 

 

 

Sterling H. McDonald

 

 

 

Vice-President and Chief Financial Officer

 

 

 

Principal Financial and Accounting Officer

 

23