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Edge Petroleum 10-Q 2005

Documents found in this filing:

  1. 10-Q
  2. Ex-31.1
  3. Ex-31.2
  4. Ex-32.1
  5. Ex-32.2
  6. Ex-32.2

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-Q

 

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31, 2005

 

OR

 

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 0-22149

 

EDGE PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

 

Delaware

 

76-0511037

(State or other jurisdiction of
incorporation or organization)

 

(I.R.S. Employer
Identification No.)

 

 

 

1301 Travis, Suite 2000

Houston, Texas 77002

(Address of principal executive offices)

(Zip code)

 

 

 

(713) 654-8960

(Registrant’s telephone number, including area code)

 

 

Indicate by checkmark 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   ý   No   o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).     Yes   ý   No   o

 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

 

Class

 

Outstanding at May 3, 2005

 

 

 

Common Stock

 

17,118,587

 

 



 

EDGE PETROLEUM CORPORATION

 

Table of Contents

 

 

Part I. Financial Information

 

 

Item 1. Financial Statements:

 

 

Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004

 

 

Consolidated Statements of Operations for the Three Months in the Periods Ended March 31, 2005 and March 31, 2004

 

 

Consolidated Statements of Other Comprehensive Income for the Three Months in the Periods Ended March 31, 2005 and March 31, 2004

 

 

Consolidated Statements of Cash Flows for the Three Months in the Periods Ended March 31, 2005 and March 31, 2004

 

 

Consolidated Statements of Stockholders’ Equity as of March 31, 2005 and December 31, 2004

 

 

Notes to the Consolidated Financial Statements

 

 

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

 

 

Item 3. Qualitative and Quantitative Disclosures About Market Risk

 

 

Item 4. Controls and Procedures

 

Part II. Other Information

 

 

Item 1. Legal Proceedings

 

 

Item 2. Unregistered Sale of Equity Securities and Use of Proceeds

 

 

Item 3. Defaults Upon Senior Securities

 

 

Item 4. Submission of Matters to a Vote of Security Holders

 

 

Item 5. Other Information

 

 

Item 6. Exhibits

 

Signatures

 

 

2



 

PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

EDGE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

 

 

 

March 31,
2005

 

December 31,
2004

 

 

 

(Unaudited)

 

 

 

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

$

4,637,128

 

$

2,267,423

 

Accounts receivable, trade, net of allowance of $525,248 at March 31, 2005 and December 31, 2004

 

14,097,880

 

13,715,890

 

Accounts receivable, joint interest owners, net of allowance of $93,000 and $82,000 at March 31, 2005 and December 31, 2004, respectively

 

2,233,619

 

5,911,073

 

Deferred income taxes

 

2,098,966

 

660,223

 

Derivative financial instruments

 

 

1,824,790

 

Other current assets

 

2,536,694

 

1,445,923

 

 

 

 

 

 

 

Total current assets

 

25,604,287

 

25,825,322

 

PROPERTY AND EQUIPMENT, Net – full cost method of accounting for oil and natural gas properties (including unproved costs of $14.2 million and $15.5 million at March 31, 2005 and December 31, 2004, respectively)

 

170,059,552

 

165,840,345

 

 

 

 

 

 

 

OTHER ASSETS

 

248,745

 

284,280

 

 

 

 

 

 

 

TOTAL ASSETS

 

$

195,912,584

 

$

191,949,947

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable, trade

 

$

2,315,190

 

$

3,141,235

 

Accrued liabilities

 

12,368,425

 

13,065,487

 

Asset retirement obligation – current portion

 

195,762

 

193,647

 

Derivative financial instruments

 

2,600,095

 

468,308

 

Total current liabilities

 

17,479,472

 

16,868,677

 

ASSET RETIREMENT OBLIGATION – long-term portion

 

2,038,411

 

1,995,441

 

 

 

 

 

 

 

DEFERRED TAX LIABILITY

 

5,503,824

 

2,618,934

 

 

 

 

 

 

 

LONG-TERM DEBT

 

10,000,000

 

20,000,000

 

 

 

 

 

 

 

Total liabilities

 

35,021,707

 

41,483,052

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (NOTE 9)

 

 

 

 

 

 

 

 

 

 

 

STOCKHOLDERS’ EQUITY

 

 

 

 

 

Preferred stock, $0.01 par value; 5,000,000 shares authorized; none issued and outstanding

 

 

 

Common stock, $0.01 par value; 25,000,000 shares authorized; 17,114,555 and 16,535,901 shares issued and outstanding at March 31, 2005 and December 31, 2004, respectively

 

171,145

 

165,359

 

Additional paid-in capital

 

134,649,661

 

126,957,059

 

Retained earnings

 

26,819,337

 

22,095,807

 

Accumulated other comprehensive income (loss)

 

(749,266

)

1,248,670

 

 

 

 

 

 

 

Total stockholders’ equity

 

160,890,877

 

150,466,895

 

 

 

 

 

 

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

 

$

195,912,584

 

$

191,949,947

 

 

See accompanying notes to consolidated financial statements.

 

3



 

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

 

 

 

Three Months Ended
March 31,

 

 

 

2005

 

2004

 

OIL AND NATURAL GAS REVENUE:

 

 

 

 

 

Oil and natural gas sales

 

$

23,928,689

 

$

15,796,491

 

Gain (loss) on hedging and derivatives

 

(984,844

)

18,166

 

Total revenue

 

22,943,845

 

15,814,657

 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

Oil and natural gas operating expenses

 

2,242,465

 

1,205,073

 

Severance and ad valorem taxes

 

1,866,488

 

1,044,714

 

Depletion, depreciation, amortization and accretion

 

8,635,629

 

5,242,416

 

General and administrative expenses:

 

 

 

 

 

Deferred compensation – repriced options

 

261,904

 

1,111,099

 

Deferred compensation – restricted stock

 

143,599

 

96,500

 

Bad debt expense

 

11,000

 

 

Other general and administrative expenses

 

2,478,725

 

1,900,827

 

 

 

 

 

 

 

Total operating expenses

 

15,639,810

 

10,600,629

 

 

 

 

 

 

 

OPERATING INCOME

 

7,304,035

 

5,214,028

 

OTHER INCOME AND EXPENSE:

 

 

 

 

 

Interest income

 

32,346

 

4,008

 

Interest expense, net of amounts capitalized

 

 

(114,278

)

Amortization of deferred loan costs

 

(35,535

)

(29,636

)

 

 

 

 

 

 

INCOME BEFORE INCOME TAXES

 

7,300,846

 

5,074,122

 

 

 

 

 

 

 

INCOME TAX EXPENSE

 

(2,577,316

)

(1,790,886

)

 

 

 

 

 

 

NET INCOME

 

$

4,723,530

 

$

3,283,236

 

 

 

 

 

 

 

BASIC EARNINGS PER SHARE

 

$

0.28

 

$

0.26

 

 

 

 

 

 

 

DILUTED EARNINGS PER SHARE

 

$

0.27

 

$

0.25

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING

 

17,042,389

 

12,725,951

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING

 

17,692,122

 

13,317,839

 

 

See accompanying notes to consolidated financial statements.

 

4



 

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (Unaudited)

 

 

 

Three Months Ended March 31,

 

 

 

2005

 

2004

 

 

 

 

 

 

 

NET INCOME

 

$

4,723,530

 

$

3,283,236

 

 

 

 

 

 

 

OTHER COMPREHENSIVE INCOME (LOSS), net of tax:

 

 

 

 

 

 

 

 

 

 

 

Change in fair value of outstanding hedging and derivative instruments (1)

 

(1,659,966

)

(616,269

)

 

 

 

 

 

 

Reclassification of hedging and derivative losses (2)

 

(337,970

)

48,657

 

 

 

 

 

 

 

Other comprehensive loss

 

(1,997,936

)

(567,612

)

 

 

 

 

 

 

COMPREHENSIVE INCOME

 

$

2,725,594

 

$

2,715,624

 


 

 

 

 

 

(1) net of income tax benefit

 

$

893,828

 

$

331,837

 

 

 

 

 

 

 

(2) net of income tax (expense) benefit

 

$

181,984

 

$

(32,460

)

 

See accompanying notes to the consolidated financial statements.

 

5



 

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

 

 

 

Three Months Ended March 31,

 

 

 

2005

 

2004

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net income

 

$

4,723,530

 

$

3,283,236

 

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

 

 

 

 

 

Loss (gain) on the fair value of derivative

 

882,830

 

(45,466

)

Deferred income taxes

 

2,577,316

 

1,790,886

 

Depletion, depreciation, amortization and accretion

 

8,635,629

 

5,242,416

 

Amortization of deferred loan costs

 

35,535

 

29,636

 

Deferred compensation

 

405,503

 

1,207,599

 

Bad debt expense

 

11,000

 

 

Changes in assets and liabilities:

 

 

 

 

 

Increase in accounts receivable, trade

 

(381,990

)

(1,017,896

)

Decrease in accounts receivable, joint interest owners

 

3,666,454

 

595,645

 

Increase in other assets

 

(1,090,771

)

(300,231

)

Decrease in accounts payable, trade

 

(826,045

)

(125,196

)

Increase (decrease) in accrued liabilities

 

(669,981

)

1,769,875

 

Increase in accrued interest payable

 

 

45,195

 

 

 

 

 

 

 

Net cash provided by operating activities

 

17,969,010

 

12,475,699

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Oil and natural gas property and equipment additions

 

(12,809,751

)

(11,345,294

)

Proceeds from the sale of oil and natural gas properties

 

 

40,000

 

 

 

 

 

 

 

Net cash used in investing activities

 

(12,809,751

)

(11,305,294

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Payments of long-term debt

 

(10,000,000

)

(1,000,000

)

Net proceeds from issuance of common stock

 

7,210,446

 

1,323,870

 

Deferred loan costs

 

 

(355,629

)

 

 

 

 

 

 

Net cash used in financing activities

 

(2,789,554

)

(31,759

)

 

 

 

 

 

 

NET INCREASE IN CASH AND CASH EQUIVALENTS

 

2,369,705

 

1,138,646

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

 

2,267,423

 

1,327,081

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, END OF PERIOD

 

$

4,637,128

 

$

2,465,727

 

 

See accompanying notes to consolidated financial statements.

 

6



 

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

 

 

 



Common Stock

 

Additional
Paid-in Capital

 

Retained
Earnings

 

Accumulated
Other
Comprehensive
Income (Loss)

 

Total
Stockholders’
Equity

 

Shares

 

Amount

BALANCE,
DECEMBER 31, 2004

 

16,535,901

 

$

165,359

 

$

126,957,059

 

$

22,095,807

 

$

1,248,670

 

$

150,466,895

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of common stock

 

578,654

 

5,786

 

7,231,741

 

 

 

7,237,527

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred compensation – restricted stock

 

 

 

143,599

 

 

 

143,599

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred compensation – repriced options

 

 

 

261,904

 

 

 

261,904

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Change in valuation of hedging instruments

 

 

 

 

 

(1,997,936

)

(1,997,936

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tax benefit associated with exercise of non-qualified stock options

 

 

 

55,358

 

 

 

55,358

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

4,723,530

 

 

4,723,530

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE, March 31, 2005

 

17,114,555

 

$

171,145

 

$

134,649,661

 

$

26,819,337

 

$

(749,266

)

$

160,890,877

 

 

See accompanying notes to consolidated financial statements.

 

7



 

EDGE PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

The financial statements included herein have been prepared by Edge Petroleum Corporation, a Delaware corporation (“we”, “our”, “us” or the “Company”), without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and reflect all adjustments which are, in the opinion of management, necessary to present a fair statement of the results for the interim periods on a basis consistent with the annual audited consolidated financial statements.  All such adjustments are of a normal recurring nature.  The results of operations for the interim periods are not necessarily indicative of the results to be expected for an entire year.  Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. These financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2004.

 

Oil and Natural Gas Properties - Investments in oil and natural gas properties are accounted for using the full-cost method of accounting. The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry.  There are two allowable methods of accounting for oil and gas business activities:  the successful-efforts method and the full-cost method.  There are several significant differences between these methods. Among these differences is that, under the successful-efforts method, costs such as geological and geophysical (“G&G”), exploratory dry holes and delay rentals are expensed as incurred whereas under the full-cost method these types of charges are capitalized to their respective full-cost pool.  In the measurement of impairment of oil and gas properties, the successful-efforts method of accounting follows the guidance provided in Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations.  The full-cost method follows guidance provided in SEC Regulation S-X Rule 4-10, where impairment is determined by comparing the net book value (full-cost pool) to the future net cash flows discounted at 10 percent using commodity prices in effect at the end of the reporting period.

 

In accordance with the full-cost method of accounting, all costs associated with the exploration, development and acquisition of oil and natural gas properties, including salaries, benefits and other internal costs directly attributable to these activities are capitalized within a cost center.  The Company’s oil and natural gas properties are located within the United States of America and constitute one cost center. The Company also capitalizes a portion of interest expense on borrowed funds.  Employee related costs that are directly attributable to exploration and development activities are also capitalized.  These costs are considered to be direct costs based on the nature of their function as it relates to the exploration and development activities.

 

Oil and natural gas properties are amortized based on a unit-of-production method using estimates of proved reserve quantities. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel equals six Mcf. Investments in unproved properties are not amortized until proved reserves associated with the prospects can be determined or until impairment occurs.  Oil and natural gas properties include costs of $14.2 million and $15.5 million at March 31, 2005 and December 31, 2004, respectively, related to unproved property, which were excluded from capitalized costs being amortized. Unproved properties are evaluated quarterly, and as needed, for impairment on a property-by-property basis.  If the results of an assessment indicate that an unproved property is impaired, the amount of impairment is added to the proved oil and natural gas property costs to be amortized.  In accordance with SEC Staff Accounting Bulletin (“SAB”) No. 106, “Interaction of Statement 143 and the Full Cost Rules,” the amortizable base includes estimated future development and dismantlement costs, and restoration and abandonment costs, net of estimated salvage values.

 

8



 

In addition, the capitalized costs of oil and natural gas properties are subject to a “ceiling test,” whereby to the extent that such capitalized costs subject to amortization in the full-cost pool (net of accumulated depletion, depreciation and amortization, asset retirement obligations and related deferred taxes) exceed the present value (using a 10% discount rate) of estimated future net after-tax cash flows from proved oil and natural gas reserves, such excess costs are charged to expense.  Once incurred, an impairment of oil and natural gas properties is not reversible at a later date.  In accordance with SAB No.103, “Update of Codification of Staff Accounting Bulletins,” derivative instruments qualifying as cash flow hedges are included in the computation of limitation on capitalized costs.  The period-end price was between the cap and floor established by the Company’s hedge contracts at March 31, 2005 and thus no impact was included in the calculation.  Impairment of oil and natural gas properties is assessed on a quarterly basis in conjunction with the Company’s quarterly and annual filings with the SEC.  No impairment related to the ceiling test was required during the three-month periods ended March 31, 2005 or 2004.

 

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves.

 

Inventories – Inventories consist principally of tubular goods and production equipment for wells and facilities. They are stated at the lower of weighted-average cost or market.

 

Asset Retirement Obligations – The Company records a liability for legal obligations associated with the retirement of tangible long-lived assets in the period in which they are incurred in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations.” The Company adopted this policy effective January 1, 2003, using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated accretion and depletion. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and gas properties is increased. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.

 

At January 1, 2003, the Company recorded the present value of its future Asset Retirement Obligations (“ARO”) for oil and natural gas properties and related equipment. The changes to the ARO during the periods ended March 31, 2005 and 2004 are as follows:

 

 

 

Three Months Ended March 31,

 

 

 

2005

 

2004

 

ARO, Beginning of Period

 

$

2,189,088

 

$

1,811,995

 

Liabilities incurred in the current period

 

61,649

 

86,311

 

Liabilities settled in the current period

 

(49,950

)

(83,647

)

Accretion expense

 

33,386

 

26,285

 

Revisions

 

 

 

ARO, End of Period

 

$

2,234,173

 

$

1,840,944

 

 

 

 

 

 

 

Current Portion

 

$

195,762

 

$

391,982

 

Long Term Portion

 

$

2,038,411

 

$

1,448,962

 

 

During the three months ended March 31, 2005, ARO liabilities incurred include nine new well obligations and liabilities settled include eight wells that were plugged.

 

Stock-Based Compensation - The Company accounts for stock compensation plans under the intrinsic value method of Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.”  No compensation expense is recognized for stock options that had an exercise price equal to or greater than the market value of the underlying common stock on the date of grant.  As allowed by SFAS No. 123, “Accounting for Stock-Based Compensation,” the Company has continued to apply APB Opinion No. 25 for purposes of determining net income.  In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-

 

9



 

Based Compensation – Transition and Disclosure – an amendment of FASB Statement No. 123” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation.  Additionally, the statement amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based compensation and the effect of the method used on reported results.

 

Had compensation expense for stock-based compensation been determined based on the fair value at the date of grant, the Company’s net income and earnings per share would have been as follows:

 

 

 

Three Months Ended March 31,

 

 

 

2005

 

2004

 

Net income as reported

 

$

4,723,530

 

$

3,283,236

 

Add:

 

 

 

 

 

Stock based employee compensation expense included in reported net income, net of related income tax

 

263,577

 

718,942

 

Deduct:

 

 

 

 

 

Total stock based employee compensation expense determined under fair value based method for all awards, net of related income tax

 

(124,745

)

(55,201

)

Pro forma net income

 

$

4,862,362

 

$

3,946,977

 

 

 

 

 

 

 

Earnings Per Share:

 

 

 

 

 

Basic – as reported

 

$

0.28

 

$

0.26

 

Basic – pro forma

 

$

0.29

 

$

0.31

 

 

 

 

 

 

 

Diluted – as reported

 

$

0.27

 

$

0.25

 

Diluted – pro forma

 

$

0.27

 

$

0.30

 

 

The Company is also subject to reporting requirements of FASB Interpretation No. (“FIN”) 44, “Accounting for Certain Transactions involving Stock Compensation” that requires a non-cash charge to deferred compensation expense if the market price of the Company’s common stock at the end of a reporting period is greater than the exercise price of certain stock options.  After the first such adjustment is made, each subsequent period is adjusted upward or downward to the extent that the market price exceeds the exercise price of the options.  The charge is related to non-qualified stock options granted to employees and directors in prior years and re-priced in May 1999, as well as certain options newly issued in conjunction with the repricing. A pre-tax charge of $0.3 million and $1.1 million was required for the three months ended March 31, 2005 and 2004, respectively.

 

Accounting Pronouncements – In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” This statement requires companies to measure the cost of employee services in exchange for an award of equity instruments based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period. SFAS No. 123(R) amends the original SFAS No. 123 and 95 that had allowed companies to choose between expensing stock options or showing pro forma disclosure only. This statement eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25. We currently account for our stock-based compensation plans under the principles prescribed by APB Opinion No. 25. Accordingly, no stock option compensation cost is reflected in net income, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. The adoption of SFAS No. 123(R) will impact our results of operations, but will have no impact on our overall financial position. In March 2005, the SEC issued SAB No. 107. Among other things, SAB No. 107 provides interpretive guidance related to the interaction between SFAS No. 123(R) and certain SEC rules and regulations, as well as provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. SFAS No. 123(R) was to become effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005, but on April 14, 2005, the SEC issued press release 2005-57, which amends the compliance date of SFAS No. 123(R)for fiscal years beginning after June 15, 2005. We anticipate adopting the provisions of SFAS No. 123(R) in the first quarter of 2006 using the modified prospective method for transition.

 

10



 

Under this method we will recognize compensation expense for all stock-based awards granted or modified on or after July 1, 2005, as well as any previously granted awards that are not fully vested as of July 1, 2005. Compensation expense will be measured based on the fair value of the awards previously calculated in developing the pro forma disclosures in accordance with the provisions of SFAS No. 123 (see Stock-Based Compensation above). The Company expects the impact to be immaterial due to the fact that the Company has not issued options since April 2004 and there will only be a minimal amount of unvested options as of our adoption date. SFAS No. 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost be reflected as a financing cash flow, rather than as an operating cash flow as currently required.

 

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”).  FIN 47 clarifies that the term, “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity.  Even though uncertainty about the timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional.  Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated.  Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists.  The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred generally upon acquisition, construction, or development or through the normal operation of the asset.  SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation.  FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.  FIN 47 is effective no later than the end of reporting periods ending after December 15, 2005.  Retrospective application for interim financial information is permitted but is not required.  Early adoption of FIN 47 is encouraged.  The Company is currently evaluating what impact FIN 47 will have on its financial statements, but at this time, it does not believe that the adoption of FIN 47 will have a material effect on the Company’s financial position, results of operations or cash flows.

 

Reclassifications - Certain reclassifications of prior period statements have been made to conform to current reporting practices.

 

2.   LONG TERM DEBT

 

Effective December 31, 2003, the Company entered into a new amended and restated credit facility (the “Credit Facility”) which permits borrowings up to the lesser of (i) the borrowing base or (ii) $100 million.  Borrowings under the Credit Facility bear interest at a rate equal to prime plus 0.50% or LIBOR plus 2.25%.  At March 31, 2005, the interest rate applied to our outstanding balance was 6.25%. As of March 31, 2005, $10.0 million in borrowings were outstanding under the Credit Facility.  The Credit Facility matures December 31, 2006 and is secured by substantially all of the Company’s assets.

 

Effective December 29, 2004, the Credit Facility’s borrowing base was increased from $48.0 million to $65.0 million. The borrowing base under the Credit Facility was increased as a result of the asset acquisition that closed December 29, 2004 and drilling activities since the last redetermination. The Company’s available borrowing capacity under this facility was $55.0 million at March 31, 2005. The borrowing base is currently being redetermined by the lender and the Company expects to be notified of any changes by the end of May 2005.

 

The Credit Facility provides for certain restrictions, including but not limited to, limitations on additional borrowings, sales of oil and natural gas properties or other collateral, and engaging in merger or consolidation transactions. The Credit Facility also prohibits dividends and certain distributions of cash or properties and certain liens.  The Credit Facility also contains the following financial covenants, among others:

 

                  The EBITDAX to Interest Expense ratio requires that the ratio of (a) consolidated EBITDAX (defined as EBITDA plus similar non-cash items and exploration and abandonment expenses for

 

11



 

such period) of the Company for the four fiscal quarters then ended to (b) the consolidated interest expense of the Company for the four fiscal quarters then ended, not be less than 3.5 to 1.0.

 

                  The Working Capital ratio requires that the amount of the Company’s consolidated current assets less its consolidated current liabilities, as defined in the agreement, be at least $1.0 million. For the purposes of calculating the Working Capital ratio, current assets is adjusted for unused capacity under credit agreement and derivative financial instruments, and current liabilities is adjusted for derivative financial instruments and asset retirement obligations.

 

                  The Maximum Leverage ratio requires that the ratio, as of the last day of any fiscal quarter, of (a) Total Indebtedness (as defined in the Credit Facility) as of such fiscal quarter to (b) an amount equal to consolidated EBITDAX for the two quarters then ended times two, not be greater than 3.0 to 1.0.

 

Consolidated EBITDAX is a component of negotiated covenants with our lender and is presented here as part of the Company’s disclosure of its covenant obligations.

 

3.   SHELF REGISTRATION STATEMENT

 

The Company filed a $150 million shelf registration statement with the SEC, which became effective in May 2004. Under the shelf registration statement, the Company may issue, from time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities in one or more offerings to those persons who agree to purchase our securities. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance that the Company will or could sell any such securities. The Company’s ability to utilize this shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities will depend upon, among other things, market conditions and the existence of investors who wish to purchase the Company’s securities at prices acceptable to the Company.

 

The Company completed an offering on December 21, 2004 of 3.5 million shares of its common stock under the Company’s shelf registration statement, which generated net proceeds of $47.8 million, before direct costs of the offering of $0.6 million. These funds were used to finance the asset acquisition that closed December 29, 2004 and fund other general corporate purposes. On January 5, 2005, the underwriters exercised their over-allotment option for an additional 525,000 shares of common stock, which generated additional net proceeds of $7.2 million. These funds were used to reduce outstanding debt. Each of these sales was made under the Company’s shelf registration statement. At March 31, 2005, the Company had $91.8 million remaining for issuance under its shelf registration statement.

 

4.   EARNINGS PER SHARE

 

The Company accounts for earnings per share in accordance with SFAS No. 128, “Earnings per Share,” which establishes the requirements for presenting earnings per share (“EPS”).  SFAS No. 128 requires the presentation of “basic” and “diluted” EPS on the face of the income statement.  Basic earnings per common share amounts are calculated using the average number of common shares outstanding during each period.  Diluted earnings per common share assumes the exercise of all stock options and warrants having exercise prices less than the average market price of the common stock during the periods, using the treasury stock method.

 

The following is a reconciliation of the numerators and denominators of basic and diluted earnings per common share computations, in accordance with SFAS No. 128, for the three-month periods ended March 31, 2005 and 2004:

 

12



 

 

 

Three Months Ended March 31, 2005

 

Three Months Ended March 31, 2004

 

 

 

Income
(Numerator)

 

Shares
(Denominator)

 

Per Share
Amount

 

Income
(Numerator)

 

Shares
(Denominator)

 

Per
Share
Amount

 

Basic EPS

 

 

 

 

 

 

 

 

 

 

 

 

 

Income available to common stockholders

 

$

4,723,530

 

17,042,389

 

$

0.28

 

$

3,283,236

 

12,725,951

 

$

0.26

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock

 

 

149,864

 

 

 

123,033

 

 

Common stock options

 

 

499,869

 

(0.01

)

 

468,855

 

(0.01

)

Diluted EPS

 

 

 

 

 

 

 

 

 

 

 

 

 

Income available to common stockholders

 

$

4,723,530

 

17,692,122

 

$

0.27

 

$

3,283,236

 

13,317,839

 

$

0.25

 

 

5.   INCOME TAXES

 

The Company accounts for income taxes under the provisions of SFAS No. 109, “Accounting for Income Taxes,” which provides for an asset and liability approach in accounting for income taxes.  Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributable to temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes.

 

The Company currently estimates that its effective tax rate for the year ending December 31, 2005 will be approximately 35.3%.  A provision for income taxes of $2.6 million and $1.8 million was reported for the three months ended March 31, 2005 and 2004, respectively. The Company was not required to pay income taxes in 2004 or 2003 because of the generation of net operating losses from drilling activity.

 

6.   SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES

 

The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. A summary of non-cash investing and financing activities for the three months ended March 31, 2005 and 2004 is presented below:

 

Description

 

Number of
Shares
Issued

 

Fair Market
Value

 

Three months ended March 31, 2005:

 

 

 

 

 

Shares issued to satisfy restricted stock grants

 

37,344

 

$

324,084

 

Shares issued to fund the Company’s matching contribution under the Company’s 401-k plan

 

1,910

 

$

27,081

 

Three months ended March 31, 2004:

 

 

 

 

 

Shares issued to satisfy restricted stock grants

 

56,136

 

$

354,183

 

Shares issued to fund the Company’s matching contribution under the Company’s 401 (k) plan

 

1,590

 

$

17,575

 

 

For the three months ended March 31, 2005 and 2004, the non-cash portion of Asset Retirement Costs was $11,699 and $2,664, respectively.  A supplemental disclosure of cash flow information for the three months ended March 31, 2005 and 2004 is presented below:

 

13



 

 

 

For the Three Months Ended
March 31,

 

 

 

2005

 

2004

 

Cash paid during the period for:

 

 

 

 

 

Interest, net of amounts capitalized

 

$

 

$

69,083

 

 

Interest paid for the three months ended March 31, 2005 and 2004 excludes amounts capitalized of $223,918 and $88,555, respectively. The Company was not required to pay income taxes in 2004 or 2003.

 

7.   HEDGING AND DERIVATIVE ACTIVITIES

 

Due to the volatility of oil and natural gas prices, the Company periodically enters into price-risk management transactions (e.g., swaps, collars and floors) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations.  While the use of these arrangements limits the Company’s ability to benefit from increases in the price of oil and natural gas, it also reduces the Company’s potential exposure to adverse price movements.  The Company’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit the Company’s potential gains from future increases in prices.  None of these instruments are used for trading purposes. On a quarterly basis, the Company’s management sets all of the Company’s price-risk management policies, including volumes, types of instruments and counterparties. These policies are implemented by management through the execution of trades by the Chief Financial Officer after consultation and concurrence by the President and Chairman of the Board.  The Board of Directors continuously monitors the Company’s policies and trades.

 

All of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” These derivative instruments are intended to hedge our price risk and may be considered hedges for economic purposes, but certain of these transactions may not qualify for cash flow hedge accounting. All derivative instrument contracts are recorded on the balance sheet at fair value. For those derivative instrument contracts that qualify for cash flow hedge accounting, the effective portion of the changes in the fair value of the contracts is recorded in other comprehensive income and the ineffective portion of the changes in the fair value of the contracts is recorded in revenue as they occur. While the contract is outstanding, the ineffective gain or loss may increase or decrease until settlement of the contract depending on the fair value at the measurement dates. When the hedged production is sold, the realized gains and losses on the contracts are removed from other comprehensive income and recorded in revenue. The Company is currently accounting for its natural gas contracts as cash flow hedges of future cash flows from the sale of natural gas. For those derivative instrument contracts that either do not qualify for cash flow hedge accounting or the Company does not designate as hedges of future cash flows, the changes in fair value are not deferred through other comprehensive income, but rather recorded in revenue immediately as unrealized gains or losses. The Company did not apply cash flow hedge accounting to its crude oil collars entered into in May/August of 2004, because although they were economic hedges, they did not qualify for hedge accounting.

 

For the three months ended March 31, 2005 and 2004, the Company included in revenue realized and unrealized losses of $1.0 million and gains of $18,166, respectively, related to its natural gas hedges and oil derivatives. There was no ineffectiveness recognized during the three months ended March 31, 2005 or 2004.

 

 

 

Three Months Ended March 31,

 

 

 

2005

 

2004

 

Natural gas hedging contract settlements

 

$

156,500

 

$

 

Oil derivative contract settlements

 

(258,514

)

 

Hedge premium reclassification

 

 

(27,300

)

Oil derivative contract unrealized change in fair value

 

(882,830

)

45,466

 

Gain (loss) on hedging and derivatives

 

$

(984,844

)

$

18,166

 

 

14



 

The outstanding hedges at March 31, 2005 and December 31, 2004 impacting the balance sheet were as follows:

 

Transaction Date

 

Transaction Type

 

Beginning

 

Ending

 

 

 

 

 

Fair Value of Outstanding Hedging and
Derivative Contracts as of

 

Price

 

Volumes

March 31, 2005

 

December 31,
2004 (4)

Per Unit

 

Per Day

Natural Gas (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

05/04

 

Collar

 

01/01/2005

 

03/31/2005

 

$5.00-$10.39

 

10,000MMbtu

 

$

 

$

92,703

 

07/04

 

Collar

 

04/01/2005

 

06/30/2005

 

$5.00-$7.53

 

10,000MMbtu

 

(209,874

)

9,162

 

07/04

 

Collar

 

07/01/2005

 

09/30/2005

 

$5.00-$7.67

 

10,000MMbtu

 

(576,687

)

(41,210

)

10/04

 

Collar

 

01/01/2005

 

12/31/2005

 

$6.00-$9.52

 

10,000MMbtu

 

(366,156

)

1,860,375

 

Crude Oil (2):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

03/04

 

Collar

 

04/01/2004

 

12/31/2004

 

$30.00-$35.50

 

400Bbl

 

 

(96,240

)

05/04(08/04) (3)

 

Collar

 

01/01/2005

 

12/31/2005

 

$35.00-$40.00

 

200/290Bbl

 

(1,447,378

)

(468,308

)

 

 

 

 

 

 

 

 

 

 

 

 

$

(2,600,095

)

$

1,356,482

 

 


(1)   The Company’s current hedging activities for natural gas were entered into on a per MMbtu delivered price basis, using the Houston Ship Channel Index, with settlement for each calendar month occurring five business days following the expiration date.

 

(2)   Hedge accounting is not applied to the Company’s collars on crude oil, which were entered into on a per barrel delivered price basis, using the West Texas Intermediate Index, with settlement for each calendar month occurring five business days following the expiration date. The change in fair value is reflected in net revenue for the applicable period.

 

(3)   In August 2004, the Company replaced the contract that was entered into May 2004 with a new contract that changes the volume and pricing terms. The put option is on 200 Bbl/D and the call option is on 290 Bbl/D. This transaction was completed at no additional cost to the Company.

 

(4)   The fair value of the Company’s outstanding transactions is presented on the balance sheet by counterparty. Our counterparties net our positions with them, but we cannot present the net of the two counterparty positions because we do not have legal right of offset. Therefore one counterparty is presented in the Derivative Asset and one is presented in the Derivative Liability. The crude oil collar with a balance of ($468,308) is presented as a liability and the remaining contracts are presented as an asset. All contracts are considered current.

 

8.   ASSET ACQUISITION

 

On December 29, 2004, the Company consummated the acquisition of interests in certain oil and natural gas properties located in South Texas from Contango Oil & Gas Company (“Contango”). The final cash purchase price for the acquisition was $40.1 million, which was adjusted from the original price of $50.0 million for the results of operations between the July 1, 2004 effective date and the December 29, 2004 closing date pursuant to the closing adjustment provisions. The Company also realized other acquisition costs of approximately $135,200 related to professional fees for assistance with the transaction. The purchase price was funded from the net proceeds of a public offering of common stock completed December 21, 2004 (see Note 3).

 

The following unaudited pro forma results for the three-months ended March 31, 2004 show the effect on the Company’s consolidated results of operations as if the asset acquisition had occurred on January 1, 2003 and are derived from the pro forma results as reported on Form 8-K/A filed April 5, 2005. They are the result of combining the statement of income of Edge with the statements of revenues and direct operating expenses for the acquired properties adjusted for (1) the completion of the public offering of common stock to finance the cash purchase price, (2) assumption of ARO liabilities and accretion expense for the properties acquired, (3) depletion, depreciation and amortization expense applied to the adjusted basis of the properties acquired using the purchase method of accounting, and (3) the related income tax effects of these adjustments based on the applicable statutory rates. The statements of revenues and direct operating expenses for the acquired assets exclude all other historical Contango expenses.  As a result, certain estimates and judgments were made in preparing the pro forma adjustments, including as to the incremental expenses associated with the acquired assets.  The pro forma information includes numerous assumptions, and is not necessarily indicative of future results of operations:

 

15



 

 

 

For the Quarter Ended
March 31, 2004

 

 

 

(unaudited)

 

 

 

(In thousands, except per
share amounts)

 

Revenue

 

$

22,363

 

Net income

 

$

6,450

 

Net income per common share:

 

 

 

Basic

 

$

0.39

 

Diluted

 

$

0.37

 

 

9.   COMMITMENTS AND CONTINGENCIES

 

From time to time the Company is a party to various legal proceedings arising in the ordinary course of business.  While the outcome of lawsuits cannot be predicted with certainty, the Company is not currently a party to any proceeding that it believes, if determined in a manner adverse to the Company, could have a potential material adverse effect on its financial condition, results of operations or cash flows.

 

During the second quarter of 2004, the Company received notice that its franchise tax returns for the State of Texas would be audited for the tax years 1999 through 2002. After reviewing documents submitted, the agent representing the Office of the Comptroller of the State of Texas proposed adjustments to the calculation that would result in an increased franchise tax liability.  The agent maintained that transfers by the parent company to its subsidiaries that the Company classified as intercompany loans should instead be classified as equity investments in the subsidiary. The State of Texas originally proposed that the franchise tax liability of the subsidiaries would be increased by approximately $3.0 million for the four-year period under audit.

 

During the third quarter of 2004 the agent reduced the proposed franchise tax deficiency adjustment to the Company and its subsidiaries to an aggregate of $467,000. In the fourth quarter of 2004, there was an informal hearing at the local Comptroller’s Office during which the agent indicated he would formally assess the proposed deficiency.  On March 24, 2005, the Company received such deficiency assessment in the amount of $471,482, including penalty and interest.  The Company responded on April 21, 2005 with a request for a formal redetermination hearing.  The Company intends to continue to vigorously contest the assessment through appropriate administrative levels in the Comptroller’s Office and any other available means.  Due to its intention to continue to vigorously contest the proposed adjustments, the Company has not recognized any provision for the additional franchise taxes that would result from the proposed deficiency.

 

16



 

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 significant factors that have affected certain aspects of our financial position and operating results during the periods included in the accompanying unaudited condensed consolidated financial statements. The following MD&A is intended to help the reader understand Edge Petroleum Corporation (“Edge”). This discussion should be read in conjunction with the accompanying unaudited condensed consolidated financial statements included elsewhere in this Form 10-Q and with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our audited consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2004.

 

FORWARD LOOKING STATEMENTS

 

The statements contained in all parts of this document, including, but not limited to, those relating to our outlook, the effects of our acquisitions, our financing plans related thereto, including any increase in our credit line, issuance of equity or debt, contribution of acquisition and any other benefit of such acquisition, our ability to access the capital markets to raise additional capital, our debt-to-total capital ratio, our drilling plans, our natural gas and oil production volumes, our 3-D project portfolio, our ability to hedge our risks, capital expenditures and capital program, future capabilities, the sufficiency of capital resources and liquidity to support working capital and capital expenditure requirements, sufficiency, growth and reinvestment of cash flows, our ability to control the timing of our future exploration and development requirements, use of NOLs, tax rates, the outcome of litigation and audits, the impact of changes in interest rates on our estimates of asset retirement obligations, production declines, the commodity pricing environment and the state of the economy and any other statements regarding future operations, financial results, business plans, sources of liquidity and cash needs and other statements that are not historical facts are forward looking statements.  When used in this document, the words “anticipate,” “estimate,” “expect,” “may,” “project,” “believe,” “budgeted,” “intend,” “plan,” “potential,” “forecast,” “might,” “predict,” “should” and similar expressions are intended to be among the statements that identify forward looking statements.  Such statements involve risks and uncertainties, including, but not limited to, those relating to the results of and our dependence on our exploratory and development drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, our dependence on key personnel, our reliance on technological development and possible obsolescence of the technology currently used by us, the significant capital requirements of our exploration and development and technology development programs, the potential impact of government regulations and liability for environmental matters, results of litigation and audits, expansion of our capital budgets, our ability to manage our growth and achieve our business strategy, competition from larger oil and gas companies, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, risks relating to acquisitions and other factors detailed in our Form 10-K and other filings with the Securities and Exchange Commission (“SEC”).  Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward looking statements attributable to the Company or the persons acting on its behalf are expressly qualified in their entirety by the reference to these risks and uncertainties. The Company undertakes no obligation to publicly update or revise any forward looking statements, whether as a result of new information, future events or otherwise.

 

GENERAL OVERVIEW

 

Edge Petroleum Corporation is a Houston-based independent energy company that focuses its exploration, production and marketing activities in selected onshore basins of the United States. In late 1998, we undertook a top-level management change and began a shift in strategy from pure exploration which focused more on prospect generation to our current strategy which focuses on a balanced program of exploration, exploitation and development and acquisition of oil and gas properties. Our company generates revenues, income and cash flows by producing and marketing oil and natural gas produced from our oil and natural gas properties. We make significant capital expenditures in our exploration, development, and acquisition activities that allow us to continue generating revenue, income and cash flows. In December 2003, we acquired 100 percent of the outstanding stock of Miller Exploration Company (“Miller”).  The transaction was treated as a tax-free reorganization and accounted for as a

 

17



 

purchase business combination. Miller continues to conduct exploration and development activities as a wholly-owned subsidiary of Edge. In December 2004, we acquired substantially all of the operating assets of Contango Oil & Gas Company (“Contango”) for a cash purchase price financed by proceeds from a public offering of our common stock. This acquisition is herein referred to as the Contango Asset Acquisition.

 

This overview provides our perspective on the individual sections of MD&A, as well as helpful hints for reading these pages. Our MD&A includes the following sections:

 

                  Industry and Economic Factors – a general description of value drivers of our business as well as opportunities, challenges and risks related to the oil and gas industry.

 

                  Approach to the Business – additional information regarding our approach and strategy.

 

                  Acquisitions and Divestitures - information about significant changes in our business structure.

 

                  Outlook – additional discussion relating to management’s outlook to the future of our business.

 

                  Critical Accounting Policies and Estimates – a discussion of certain accounting policies that require critical judgments and estimates.

 

                  Results of Operations – an analysis of our Company’s consolidated results for the periods presented in our financial statements.

 

                  Liquidity and Capital Resources - an analysis of cash flows, sources and uses of cash, and contractual obligations.

 

                  Risk Management Activities – Derivatives & Hedging - supplementary information regarding our Company’s price-risk management activities involving commodity contracts that are accounted for at fair value.

 

                  Tax Matters – supplementary discussion of income tax matters.

 

                  Recently Issued Accounting Pronouncements – a discussion of certain accounting pronouncements recently issued that may impact our future results.

 

Industry and Economic Factors

 

In managing our business, we must deal with many factors inherent in our industry.  First and foremost is the fluctuation of oil and gas prices.  Historically, oil and gas markets have been cyclical and volatile, with future price movements, which are difficult to predict.  While our revenues are a function of both production and prices, wide swings in commodity prices have most often had the greatest impact on our results of operations. We have no way to predict those prices or to control them without losing some advantage of the upside potential. The oil and gas industry has continued to experience a high commodity price environment in 2005 which has positively impacted the entire industry as well as our Company.

 

Our operations entail significant complexities.  Advanced technologies requiring highly trained personnel are utilized in both exploration and production.  Even when the technology is properly used, we may still not know conclusively if hydrocarbons will be present or the rate at which they will be produced.  Exploration is a high-risk activity, often times resulting in no commercially productive reserves being discovered. Moreover, costs associated with operating within our industry are substantial.

 

Our business, as with other extractive industries, is a depleting one in which each gas equivalent produced must be replaced or our business, and a critical source of our future liquidity, will shrink.

 

18



 

The oil and gas industry is highly competitive.  We compete with major and diversified energy companies, independent oil and gas businesses and individual operators in exploration, production, marketing and acquisition activities.  In addition, the industry as a whole competes with other businesses that supply energy to industrial and commercial end users.

 

Extensive federal, state and local regulation of the industry significantly affects our operations.  In particular, our activities are subject to stringent operational and environmental regulations.  These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and gas wells and related facilities.  These regulations may become more demanding in the future.

 

Approach to the Business

 

Profitable growth of our business will largely depend upon our ability to successfully find and develop new proved reserves of oil and natural gas in a cost-effective manner.  In order to achieve an overall acceptable rate of growth, we seek to maintain a prudent blend of low, moderate and higher risk exploration and development projects.  We also attempt to make selected acquisitions of oil and gas properties to augment our growth and provide future drilling opportunities.  To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins.  We periodically hedge our exposure to volatile oil and gas prices on a portion of our production to reduce price risk. As of March 31, 2005, we had hedge contracts in place covering approximately 44% and 29% of our remaining expected 2005 natural gas and crude oil production, respectively, or approximately 38% of total production on an Mcfe basis, before any acquisitions that may occur.

 

Implementation of our business approach relies on our ability to fund ongoing exploration and development projects with cash flow provided by operating activities and external sources of capital. Our Board approved a 2005 capital budget of $63 million. Based on current expectations for production volumes and commodity prices, we expect to fund those capital expenditures from internally generated cash from operating activities.  We do not typically include acquisitions in our budgeted capital expenditures, but expect to fund those with either borrowings under our credit facility or offerings of common stock or other securities under our shelf registration statement or other sources.

 

We reduced debt by $10.0 million in the first three months of 2005 to $10.0 million at March 31, 2005. As of that date, our debt to total capital ratio was approximately 5.9%, which we believe leaves us with the financial flexibility to continue to execute our business strategies.

 

Acquisitions and Divestitures

 

Acquisitions - On December 29, 2004 we successfully completed the acquisition of oil and natural gas properties located in South Texas for a final adjusted cash purchase price of $40.1 million, before other acquisition costs of approximately $135,200. The original purchase price of $50 million was subject to adjustment for the results of operations between the July 1, 2004 effective date and the December 29, 2004 closing date, pursuant to the post-closing adjustments provision. We financed the acquisition with proceeds from a public offering of our common stock under our current shelf registration (see Note 3 to our consolidated financial statements). The properties acquired consist of 39 non-operated producing wells with working interests ranging from approximately 41% to 75% and net revenue interests ranging from 29% to 56%. The addition of these properties increased our production and activity levels during this quarter. These properties, located primarily in Jim Hogg County, Texas and producing primarily from the Queen City formation, are in a geographic area that has been one of our most active and successful areas of focus in recent years. In addition to estimated proved reserves, our technical team identified a substantial number of additional drilling locations on undeveloped acreage with attractive exploitation and exploration potential, therefore, we allocated $6 million of the purchase price to the unproved property category. We began work on these undeveloped locations during the first three months of 2005.

 

Divestitures - We regularly review our asset base for the purpose of identifying non-core assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. While we generally do not dispose of assets solely for the purpose of reducing debt, such

 

19



 

dispositions can have the result of furthering our objective of financial flexibility through reduced debt levels. During the three months ended March 31, 2005, there were no divestitures as compared to the first three months of 2004, during which we divested oil and natural gas properties in Louisiana generating net proceeds of $40,000.

 

Outlook

 

We expect to continue our acquisition program in 2005, as we seek to further our growth. We expect our drilling program to increase from 49 wells (26.910 net) in 2004 to approximately 50 to 55 wells (28 to 31 net) in 2005. Our expected capital program, excluding acquisitions, will be approximately $63 million. Our expected production volumes combined with a strong commodity-pricing environment, that if sustained, as expected for the remainder of the year is anticipated to produce record cash flow. In order to manage our realized and anticipated growth, we increased our headcount from 35 employees as of December 31, 2003 to 51 employees as of December 31, 2004, and again to 53 as of March 31, 2005 resulting in increased G&A costs for 2005. We expect to continue to add to our staff levels for the remainder of 2005 in response to past and anticipated growth. To help protect against the possibility that commodity prices do not remain at the current levels, we have entered into several hedges covering approximately 44% of our expected natural gas production and 29% of our expected crude oil production streams for the remainder of 2005 to offset the negative impact of potential downward price movements. This equates to approximately 38% of total production on an Mcfe basis.

 

Our outlook and the expected results described above are both subject to change based upon factors that include but are not limited to drilling results, commodity prices, access to capital, the acquisitions market and factors referred to in “Forward Looking Statements.”

 

Critical Accounting Policies and Estimates

 

The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, contingent assets and liabilities and the related disclosures in the accompanying financial statements.  Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:

 

                  it requires assumptions to be made that were uncertain at the time the estimate was made, and

 

                  changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.

 

All other significant accounting policies that we employ are presented in the notes to the consolidated financial statements. The following discussion presents information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate.

 

Nature of Critical Estimate Item: Oil & Natural Gas Reserves - Our estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions.  The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment.  For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results.  In addition, as prices and cost levels change from year to year, the economics of producing the reserves may change and therefore the estimate of proved reserves also may change.  Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements.

 

20



 

Assumptions/Approach Used: Units-of-production method to amortize our oil and natural gas properties - The quantity of reserves could significantly impact our depletion expense. Any reduction in proved reserves without a corresponding reduction in capitalized costs will increase the depletion rate.

 

“Ceiling” Test  - The full-cost method of accounting for oil and gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full-cost ceiling calculation. The ceiling is the discounted present value of our estimated total proved reserves adjusted for taxes and the impact of hedges on pricing, using a 10% discount rate. To the extent that our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of oil and gas properties is not reversible at a later date even if oil and gas prices increase. No such impairment was required in the three months ended March 31, 2005 and 2004. This calculation of our proved reserves could significantly impact our ceiling limitation used in determining whether an impairment of our capitalized costs is necessary. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs, but rather are based on prices and costs in effect as of the end of the period. Oil and natural gas prices used in the reserve valuation at March 31, 2005 were $55.40 per barrel and $7.32 per MMbtu.

 

Effect if different assumptions used: Units-of-production method to amortize our oil and natural gas properties - A 10% increase or decrease in reserves would have decreased or increased, respectively, our depletion expense for the quarter by approximately 10%.

 

“Ceiling” limitation test  - The most likely factor to contribute to a ceiling test impairment is the price used to calculate the reserve limitation threshold. A significant reduction in the prices at a future measurement date could trigger a full-cost ceiling impairment. At March 31, 2005, we had a cushion (i.e. the excess of the ceiling over our capitalized costs) of $108.3 million. A 10% increase or decrease in prices used would have increased or decreased our cushion by approximately 36%. Our hedging program would serve to mitigate some of the impact of any price decline. Our hedges did not impact the ceiling test this quarter, and would not have if the price was 10% lower as these prices were within the collars, but had we increased the price by 10% the price would have exceeded our hedge caps and therefore resulted in a decrease in the ceiling of $0.8 million. Another likely factor to contribute to a ceiling test impairment is a revised estimate of reserves. A 10% increase or decrease in reserve volume would have increased or decreased our cushion by approximately 28%.

 

Nature of Critical Estimate Item: Unproved Property Impairment - We have elected to use the full-cost method to account for our oil and gas activities. Investments in unproved properties are not amortized until proved reserves associated with the prospects can be determined or until impairment occurs.  Unproved properties are evaluated quarterly for impairment on a property-by-property basis.  If the results of an assessment indicate that an unproved property is impaired, the amount of impairment is added to the proved oil and natural gas property costs to be amortized.

 

Assumptions/Approach Used: At March 31, 2005, we had $14.2 million allocated to unproved property. This allocation is based on the estimation by the technical team of whether the property has potential attributable reserves. Therefore, the assessment made by our technical team of the potential reserves will determine whether costs are moved from the unproved category to the full-cost pool for depletion or whether an impairment is taken.

 

Effect if different assumptions used: A 10% increase or decrease in the unproved property balance (i.e. transfer to full-cost pool) would have increased or decreased our depletion expense by approximately 1% for the quarter ended March 31, 2005.

 

Nature of Critical Estimate Item: Asset Retirement Obligations - We have certain obligations to remove tangible equipment and restore land at the end of oil and gas production operations.  Our removal and restoration

 

21



 

obligations are primarily associated with plugging and abandoning wells. Previously, the costs associated with this activity were capitalized to the full-cost pool and charged to income through depletion. We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” effective January 1, 2003, as discussed in Note 1 to our Consolidated Financial Statements.  SFAS No. 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets (“asset retirement obligations” or “ARO”).  Primarily, the new statement requires us to estimate asset retirement costs for all of our assets, inflation adjust those costs to the forecast abandonment date, discount that amount using a credit-adjusted-risk-free rate back to the date we acquired the asset or obligation to retire the asset and record an ARO liability in that amount with a corresponding addition to our asset value. We then accrete the liability quarterly using the period-end effective credit-adjusted-risk-free rate. As new wells are drilled or purchased, their initial asset retirement cost and liability is calculated and recorded. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost (included in the full-cost pool); therefore, abandonment costs will almost always approximate the estimate. When wells are sold the related liability and asset costs are removed from the balance sheet.

 

Assumptions/Approach Used: Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal.  Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the estimate of the present value calculation of our AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted-risk-free-rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments.

 

Effect if different assumptions used: Since there are so many variables in estimating AROs, we attempt to limit the impact of management’s judgment on certain of these variables by using input of qualified third parties. We engage independent engineering firms to evaluate our properties annually. We use the remaining estimated useful life from the year-end reserve reports by our independent reserve engineers in estimating when abandonment could be expected for each property. We utilize a three-year average rate for inflation to diminish any significant volatility that may be present in the short term. We expect to see our calculations impacted significantly if interest rates move from their current lows, as the credit-adjusted-risk-free rate is one of the variables used on a quarterly basis. Our technical team developed a standard cost estimate based on historical costs, industry quotes and depth of wells. Unless we expect a well’s plugging to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of a discount factor and some significant calculations, could differ from actual results, despite all our efforts to make an accurate estimate.

 

Nature of Critical Estimate Item: Income Taxes - In accordance with the accounting for income taxes under SFAS No. 109, Accounting for Income Taxes, we have recorded a deferred tax asset and liability to account for the expected future tax benefits and consequences of events that have been recognized in our financial statements and our tax returns. There are several items that result in deferred tax asset and liability impact to the balance sheet, but the largest of which is income taxes and the impact of net operating loss (“NOL”) carryforwards. We routinely assess the realizability of our NOL carryforwards that resulted from substantial income tax deductions, prior year losses and acquisitions. We consider future taxable income in making such assessments.  If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance.

 

Assumptions/Approach Used: Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices). The Company is not currently required to pay any federal income taxes because of the prior generation of NOL’s.

 

22



 

Effect if different assumptions used: We have engaged an independent public accounting firm to assist us in applying the numerous and complicated tax law requirements. However, despite our attempt to make an accurate estimate, the ultimate utilization of our NOL carryforwards is highly dependent upon our actual production and the realization of taxable income in future periods. If we estimate that some or all of our NOL carryforwards are more likely than not going to expire or otherwise not be utilized to reduce future tax, we would record a valuation allowance to remove the benefit of those NOL carryforwards from our financial statements.

 

Nature of Critical Estimate Item: Derivative & Hedging Activities - Due to the instability of oil and natural gas prices, we may enter into, from time to time, price-risk management transactions (e.g., swaps, collars and floors) for a portion of our oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from commodity price fluctuations. While all of these transactions are economic hedges of price risk, different accounting treatment may apply depending on if they qualify for cash flow hedge accounting. In accordance with SFAS No. 133, all transactions are recorded on the balance sheet at fair value.

 

Hedge Contracts - We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used for hedging are expected to be highly effective in offsetting changes in cash flows of the hedged transactions.  In the event it is determined that the use of a particular derivative may not be or has ceased to be effective in pursuing a hedging strategy, hedge accounting is discontinued prospectively. The ongoing measurement of effectiveness determines whether the change in fair value is deferred through other comprehensive income (“OCI”) on the balance sheet or recorded immediately in revenue on the income statement. The effective portion of the changes in the fair value of hedge contracts is recorded initially in OCI. When the hedged production is sold, the realized gains and losses on the hedge contracts are removed from OCI and recorded in revenue. Ineffective portions of the changes in the fair value of the hedge contracts are recognized in revenue as they occur. While the hedge contract is outstanding, the ineffective gain or loss may increase or decrease until settlement of the contract.

 

Derivative Contracts - For transactions not accounted for using cash flow hedge accounting, the change in the fair value of the derivative contract is reflected in revenue immediately, i.e. not deferred through OCI, and there is no measurement of effectiveness.

 

Assumptions/Approach Used: Estimating the fair values of derivative instruments requires complex calculations, including the use of a discounted cash flow technique, estimates of risk and volatility, and subjective judgment in selecting an appropriate discount rate. In addition, the calculations use future market commodity prices, which although posted for trading purposes, are merely the market consensus of forecasted price trends. The results of the fair value calculations cannot be expected to represent exactly the fair value of our commodity hedges. We currently obtain the fair value of our positions from our counterparties. Our practice of relying on our counterparties who are more specialized and knowledgeable in preparing these complex calculations reduces our management’s input.

 

Effect if different assumptions used: At March 31, 2005, a 10% change in the commodity price per unit, as long as the price is either above the ceiling or below the floor price, would cause the fair value total of our derivative financial instrument to increase or decrease by approximately $248,200.

 

Results of Operations

 

This section includes discussion of our results of operations for the three-month period ended March 31, 2005 as compared to the same period of the prior year.  We are an independent energy company engaged in the exploration, development, acquisition and production of oil and natural gas.  Our resources and assets are managed and our results reported as one operating segment.  We conduct our operations primarily along the onshore United States Gulf Coast, with our primary emphasis in South Texas, Louisiana, and southeast New Mexico.

 

23



 

First Quarter 2005 Compared to the First Quarter 2004

 

Revenue and Production

 

Total revenue increased 45% from the first quarter of 2004 to the comparable 2005 period.  For the three months ended March 31, 2005 and 2004, our product mix contributed the following percentages of production and revenues:

 

 

 

REVENUES (1)

 

PRODUCTION

 

 

 

2005

 

2004

 

2005

 

2004

 

Natural Gas (Mcf)

 

81

%

82

%

76

%

77

%

Natural gas liquids (Bbls)

 

7

%

7

%

12

%

13

%

Crude oil (Bbl)

 

12

%

11

%

12

%

10

%

 

 

 

 

 

 

 

 

 

 

Total (Mcfe)

 

100

%

100

%

100

%

100

%

 


(1) Includes effect of hedging and derivative transactions.

 

The following table summarizes volume and price information with respect to our oil and gas production for the three-month periods ended March 31, 2005 and 2004:

 

 

 

 

 

 

 

2005 Period Compared
to 2004 Period

 

 

 

Three Months Ended
March 31,

 

$
Increase
(Decrease)

 

%
Increase
(Decrease)

 

 

 

2005

 

2004

 

Production Volumes:

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

3,202,230

 

2,421,980

 

780,250

 

32

%

Natural gas liquids (Bbls)

 

84,089

 

69,485

 

14,604

 

21

%

Oil and condensate (Bbls)

 

83,011

 

53,828

 

29,183

 

54

%

Natural gas equivalent (Mcfe)

 

4,204,827

 

3,161,858

 

1,042,969

 

33

%

Average Sales Price:

 

 

 

 

 

 

 

 

 

Natural gas ($ per Mcf)(1)

 

$

5.78

 

$

5.36

 

$

0.42

 

8

%

Natural gas liquids ($ per Bbl)

 

$

17.48

 

$

15.03

 

$

2.45

 

16

%

Oil and condensate ($ per Bbl)(1)

 

$

47.76

 

$

32.75

 

$

15.01

 

46

%

Natural gas equivalent ($ per Mcfe)(1)

 

$

5.69

 

$

5.00

 

$

0.69

 

14

%

Natural gas equivalent ($ per Mcfe)(2)

 

$

5.46

 

$

5.00

 

$

0.46

 

9

%

Operating Revenue:

 

 

 

 

 

 

 

 

 

Natural gas (1)

 

$

18,494,831

 

$

12,988,951

 

$

5,505,880

 

42

%

Natural gas liquids

 

1,469,575

 

1,044,404

 

425,171

 

41

%

Oil and condensate (1)

 

3,964,283

 

1,763,136

 

2,201,147

 

125

%

Gain (loss) on hedging and derivatives

 

(984,844

)

18,166

 

(1,003,010

)

(5,521

)%

Total

 

$

22,943,845

 

$

15,814,657

 

$

7,129,188

 

45

%

 


(1) Excludes the effect of hedging and derivative transactions.

(2) Includes the effect of hedging and derivative transactions.

 

Our revenue is sensitive to changes in prices received for our products.  A substantial portion of our production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control.  Imbalances in the supply and demand for oil and natural gas can have a dramatic effect on the prices we receive for our production.  Political instability and availability of alternative fuels could impact worldwide supply, while the economy, weather and other factors outside of our control could impact demand.

 

Natural gas revenue, excluding hedging activity, increased 42% for the three months ended March 31, 2005 over the same period in 2004 due to significantly higher production and higher realized prices. Average natural gas

 

24



 

production increased 32% from 2.4 Bcfe in the three months ended March 31, 2004 to 3.2 Bcfe in the comparable 2005 period due to production from new wells acquired on December 29, 2004 in South Texas, new wells drilled, primarily on our Encinitas, Gato Creek, southeast New Mexico and Miller properties, partially offset by natural declines at our O’Connor Ranch East, Brandon and Duson-Horst properties. The overall increase in production compared to the prior year period resulted in an increase in revenue of approximately $4.2 million (based on 2004 comparable period pre-hedge prices).  Excluding the effect of hedges, the average natural gas sales price for production in the first quarter of 2005 was $5.78 per Mcf compared to $5.36 per Mcf for the same period in 2004.  This increase in average price received resulted in increased revenue of approximately $1.3 million (based on current year production).

 

Revenue from the sale of NGLs increased 41% for the three months ended March 31, 2005 over the same period in 2004. Production volumes for NGLs increased 21%, from 69.9 MBbls for the three months ended March 31, 2004 to 84.1 MBbls for the three months ended March 31, 2005 due primarily to increased production from new wells at Encinitas and Gato Creek, partially offset by natural declines on our Brandon and Duson-Horst properties. The increase in NGL production increased revenue by approximately $219,500 (based on 2004 comparable period average prices).  Higher average realized prices for the three months ended March 31, 2005 resulted in an increase in revenue of approximately $205,700 (based on current year production).  The average realized price for NGLs for the three months ended March 31, 2005 was $17.48 per barrel compared to $15.03 per barrel for the same period in 2004.

 

Revenue from the sale of oil and condensate, excluding derivative activity, increased 125% for the three months ended March 31, 2005 as compared to the comparable prior year period in 2004 due to higher price environment and increased production. The average realized price for oil and condensate before the derivative losses for the three months ended March 31, 2005 was $47.76 per barrel compared to $32.75 per barrel in the same period of 2004.  These higher average prices for the first quarter of 2005 resulted in an increase in revenue of approximately $1.2 million (based on current year production).  Production volumes for oil and condensate increased 54% to 83.0 MBbls for the three months ended March 31, 2005 compared to 53.8 MBbls for the same prior year period due primarily to production from the properties acquired on December 29, 2004 from Contango, as well as new wells drilled.  The increase in oil and condensate production resulted in an increase in revenue of approximately $955,900 (based on 2004 comparable period average prices).

 

Losses on hedging and derivatives increased significantly for the three months ended March 31, 2005 over the same period in 2004 due to the change in the fair market value of the outstanding derivative contracts as a result of volatile commodity prices and cash settlements on expiring contracts. Oil and condensate revenues were decreased by realized and unrealized losses on our oil derivatives. For the three months ended March 31, 2005, we recorded $258,514 of realized losses on oil derivatives settlements and $882,830 of unrealized losses representing the change in the mark-to-market fair value of our outstanding oil derivative contracts. We did not apply hedge accounting to these transactions.  See Note 7 to our consolidated financial statements.  These losses account for a $13.75 per barrel decrease in the realized oil price for the three months ended March 31, 2005 from $47.76 per barrel to $34.01 per barrel. At March 31, 2004 we had an unrealized gain of $45,466, representing an increase in our realized oil price of $0.84 per barrel. Should the crude oil prices decrease from the current levels, we would realize lower revenues, but our oil derivative losses would also decrease and could possibly result in a gain position. Included within natural gas revenue for the three months ended March 31, 2005 was $156,500 representing realized gains from hedging contract settlements.  These gains increased the effective natural gas sales price by $0.05 per Mcf for the three months ended March 31, 2005.  Should natural gas prices continue to decrease from the high levels of late 2004, this could materially affect our revenues that are not hedged. For the three months ended March 31, 2004, we recognized $27,300 of the premium paid for a natural gas hedge entered into in 2003.  This loss decreased the effective natural gas sales price by $0.01 per Mcf.

 

Costs and Operating Expenses

 

The table below presents a detail of our expenses for the three months ended March 31, 2005 and 2004:

 

25



 

 

 

 

 

 

 

2005 Period Compared
to 2004 Period

 

 

 

Three Months Ended
March 31,

 

$
Increase
(Decrease)

 

%
Increase
(Decrease)

 

 

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas operating expenses

 

$

2,242,465

 

$

1,205,073

 

$

1,037,392

 

86

%

Severance and ad valorem taxes

 

1,866,488

 

1,044,714

 

821,774

 

79

%

Depreciation, depletion, amortization and accretion:

 

 

 

 

 

 

 

 

 

Oil and gas property and equipment

 

8,540,134

 

5,129,154

 

3,410,980

 

67

%

Other assets

 

62,109

 

86,977

 

(24,868

)

(29

)%

ARO accretion

 

33,386

 

26,285

 

7,101

 

27

%

General and administrative:

 

 

 

 

 

 

 

 

 

Deferred compensation – repriced options

 

261,904

 

1,111,099

 

(849,195

)

(76

)%

Deferred compensation – restricted stock

 

143,599

 

96,500

 

47,099

 

49

%

Bad debt expense

 

11,000

 

 

11,000

 

*

 

Other general and administrative

 

2,478,725

 

1,900,827

 

577,898

 

30

%

 

 

15,639,810

 

10,600,629

 

5,039,181

 

48

%

Other expense, net

 

3,189

 

139,906

 

(136,717

)

(98

)%

Total

 

$

15,642,999

 

$

10,740,535

 

$

4,902,464

 

46

%

 


*Not meaningful

 

Oil and natural gas operating expenses for the three months ended March 31, 2005 increased 86% over the same period of 2004. The December 29, 2004 acquisition of properties in South Texas contributed 41% of the increase in costs. Wells drilled since the first quarter of 2004 further increased the costs for the first quarter of 2005 compared to the prior year.  We also realized higher expenses for the fourth quarter 2004 than originally estimated in our year-end accruals for our States, Encinitas, O’Connor Ranch and other properties, which equated to 26% of the increase in costs. We have begun to experience increased costs due to increased demand for oil field products and services. The oil and natural gas industry tends to be cyclical in nature, and the demand for goods and services of oil field companies, suppliers and others associated with the industry can put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. When commodity prices decline, associated costs do not necessarily decline at the same rate. These various cost increases have led to an increase in lease operating expenses to $0.53 per Mcfe for the three months ended March 31, 2005 from $0.38 per Mcfe for the same prior year period.

 

Severance and ad valorem taxes for the three months ended March 31, 2005 increased 79% from the first quarter of 2004.  Severance tax expense for the first quarter of 2005 was 60% higher than the comparable prior year period as a result of higher revenue. Our severance tax expense is levied on our oil and gas revenue dollars (excluding hedging and derivative impact), so if commodity prices remain high, we expect to continue to incur higher severance tax expense. For the three months ended March 31, 2005, severance tax expense was approximately 6.2% of revenue subject to severance taxes compared to 6.0% of revenue subject to severance taxes for the comparable 2004 period. The increase in tax as a percent of revenue was due primarily to a shift in our revenue stream to properties with higher severance tax rates. Ad valorem tax expense for the first quarter of 2005 was impacted by increased accruals for the estimated costs related to the addition of the South Texas properties acquired on December 29, 2004.  On an equivalent basis, severance and ad valorem taxes averaged $0.44 per Mcfe and $0.33 per Mcfe for the three months ended March 31, 2005 and 2004, respectively.

 

Depletion, depreciation, and amortization (“DD&A”) and accretion expense for the three months ended March 31, 2005 totaled $8.6 million compared to $5.2 million for the three months ended March 31, 2004.

 

26



 

Depletion on our oil and natural gas properties increased 67% for the first quarter of 2005 compared to the same period of 2004 due to an increase in production levels and in the unit-of-production depletion rate from $1.62 per Mcfe in the first quarter 2004 as compared to $2.03 per Mcfe in the first quarter of 2005. The increase in depletion expense from the higher production levels in the first quarter of 2005 as compared to the same period of 2004 resulted in an increase in expense of approximately $1.7 million. The increase in rate for the first quarter of 2005 compared to the first quarter of 2004 added approximately $1.7 million in depletion expense. Our rate has increased due to increased spending on our drilling program with disproportionate reserve additions. Depreciation of furniture and fixtures decreased 29% compared to the prior year first quarter due to several larger depreciable assets that became fully depreciated by year-end 2004 and are not currently contributing to expense. Accretion expense associated with our asset retirement obligations for the three months ended March 31, 2005 increased 27% over the first quarter of 2004 for the new obligations incurred from the wells drilled in 2004 and those South Texas properties acquired on December 29, 2004.

 

Total G&A for the three months ended March 31, 2005 was $2.9 million, a decrease of 7% compared to the prior year first quarter total of $3.1 million. Pursuant to FIN 44 discussed in Note 1 to the consolidated financial statements, G&A costs include deferred compensation related to repriced options, deferred compensation related to restricted stock grants and other G&A costs. A FIN 44 charge of $261,904 was incurred for the three months ended March 31, 2005 compared to $1.1 million in the same period of 2004. Amortization related to restricted stock awards granted over the past three years totaled $143,599 and $96,500, respectively, for the three months ended March 31, 2005 and 2004. The increase relates to new grants that have occurred since the first quarter of 2004. We recorded $11,000 of bad debt expense and increased our allowance related to JIB Accounts Receivable. Other G&A for the three months ended March 31, 2005, which does not include the deferred compensation expenses discussed above, totaled $2.5 million, a 31% increase from the comparable 2004 period total of $1.9 million. The increase in other G&A was attributable to higher salaries and benefits, due in part to higher staffing levels, as well as higher rent expense for additional office space, franchise tax expense, regulatory fees for increased outstanding common stock and costs relating to strategic planning. For the three months ended March 31, 2005 and 2004, overhead reimbursement fees reduced G&A costs by $50,402 and $46,477, respectively. Capitalized G&A costs further reduced other G&A by $713,700 and $507,064 for the three months ended March 31, 2005 and 2004, respectively.  Other G&A on a unit of production basis for the three months ended March 31, 2005 was $0.59 per Mcfe compared to $0.60 per Mcfe for the comparable 2004 period.

 

Other income (expense) for the three months ended March 31, 2005 excludes interest expense because 100% of our interest expense for the quarter was capitalized as compared to $114,278 of expense in the same 2004 period. We incurred higher interest costs for the three months ended March 31, 2005 than for the same period of 2004, but we capitalized all of our expense as a result of our unproved property balance exceeding our debt balance. Interest expense, including facility fees, was $223,918 for the first quarter of 2005 on weighted average debt of approximately $12.0 million compared to interest expense of $202,833 on weighted average debt of approximately $20.9 million for the first quarter of 2004.  Capitalized interest for the three months ended March 31, 2005 totaled $223,918 compared to $88,555 in the same prior year period.  We also recorded amortization of deferred loan costs of $35,535 during the first quarter of 2005 as compared to $29,636 for the same prior year period related to our amended credit facility.

 

An income tax provision was recorded for the three months ended March 31, 2005 and 2004 of $2.6 million and $1.8 million, respectively. The increase resulted from higher pre-tax income in 2005 as compared to 2004.

 

For the three months ended March 31, 2005, we had net income of $4.7 million, or $0.28 basic earnings per share and $0.27 diluted earnings per share, as compared to net income of $3.3 million, or $0.26 basic earnings per share and $0.25 diluted earnings per share in the comparable 2004 period.  Basic weighted average shares outstanding increased for the three months ended March 31, 2005 over the same period 2004 primarily due to the stock offering completed in December 2004 and the related over-allotment exercise in January 2005. We issued a total of 4,025,000 shares in these transactions.

 

27



 

Liquidity and Capital Resources

 

Our primary ongoing source of capital is the cash flow generated from our operating activities supplemented by borrowings under our credit facility.  Net cash generated from operating activities is a function of production volumes, commodity prices (which are inherently volatile and unpredictable), operating efficiency and capital spending. Our business, as with other extractive industries, is a depleting one in which each gas equivalent unit produced must be replaced or our business, and a critical source of our future liquidity, will shrink. Our overall existing production has a decline rate of approximately 17% per year.  Less predictable than production declines from our proved reserves is the impact of constantly changing oil and natural gas prices on cash flows and, therefore capital budgets.  We attempt to mitigate the price risk with our hedging program. Reserves and production volumes are influenced, in part, by the amount of future capital expenditures. In turn, capital expenditures are influenced by many factors including drilling results, oil and gas prices, industry conditions, availability and prices of goods and services and the extent to which oil and gas properties are acquired.

 

Our primary needs for cash are for exploration, development and acquisition of oil and gas properties, and the repayment of principal and interest on outstanding debt. We attempt to fund our exploration and development activities primarily through internally generated cash flows and budget capital expenditures based on projected cash flows.  We routinely adjust capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, and cash flow.  We typically have funded acquisitions from borrowings under our credit facility and cash flow from operations.  We have historically utilized net cash provided by operating activities, debt and equity as capital resources to obtain necessary funding for all of our cash needs.

 

Some significant changes to working capital may also affect our liquidity in the short term. The increase in the derivative instrument liability is indicative of potential future cash settlements on our hedge positions as the months settle. The fair value of our outstanding hedge and derivative contracts is reflected on the balance sheet, and we show a liability for the positions with each of our two counterparties. The hedge and derivative financial instrument liability represents the amount by which future strip commodity prices exceed the price caps on our contracts at the balance sheet date. The hedge and derivative financial instrument asset represents the amount by which strip commodity prices are lower than the price floors on our contracts at the balance sheet date. Should commodity prices increase or decrease, the applicable positions would change accordingly and the unrealized losses that are reflected in revenue and the unrealized gains reflected in other comprehensive income could possibly reduce or result in gains or losses, respectively. When hedges and derivatives require cash settlement, the Company is receiving higher cash inflows on the sale of production at higher prices, therefore the use of those funds would adequately cover any derivative and hedge payments when they come due.

 

We have historically used our credit facility to supplement any deficiencies between operating cash flow and capital expenditures. We had $10.0 million outstanding under the credit facility at March 31, 2005, which was reduced from $20.0 million at December 31, 2004 with proceeds from the underwriter’s over-allotment option to our December 2004 public stock offering (see discussion below). The maturity for this credit facility is December 31, 2006.

 

After considering the impact of these working capital changes and our forecasts of future results of operations, we believe that cash flows from operating activities, as supplemented by borrowings on our credit facility, combined with our ability to control the timing of the majority of our future exploration and development requirements will provide us with the flexibility and liquidity to meet our planned capital requirements for 2005. In addition, our credit facility had $55.0 million available at March 31, 2005 for general corporate purposes, exploratory and developmental drilling and acquisitions of oil and gas properties.

 

During 2004 and early 2005, we realized increased cash flows as a result of our public stock offerings and activity in stock option and warrant exercises. Most significantly was the net proceeds of $47,810,000 that we received, before direct costs of $0.6 million, from our December 2004 offering of our common stock and the related exercise of the underwriter's over-allotment option for 525,000 additional shares of our common stock, resulting in an additional $7.2 million of net proceeds to us in January 2005. We typically do not rely on proceeds from offerings and the exercise of warrants and stock options to sustain our business as they are unpredictable events.

 

28



 

We had cash and cash equivalents at March 31, 2005 of $4.6 million consisting primarily of short-term money market investments, as compared to $2.3 million at December 31, 2004.  Working capital was $8.1 million as of March 31, 2005, as compared to $9.0 million at December 31, 2004.

 

Net Cash Provided By Operating Activities

 

Cash flows provided by operating activities were $18.0 million for the three months ended March 31, 2005 compared to $12.5 million for the three months ended March 31, 2004. The increase in cash flows provided by operating activities for the three months ended March 31, 2005 compared to 2004 was primarily due to higher oil and gas production revenue partially offset by higher operating expense.  Although fluctuations in commodity prices have been the primary reason for our short-term changes in cash flow from operating activities, increased production volumes significantly impacted us in the past few quarters.  In an effort to reduce the volatility realized on commodity prices, we enter into derivative instruments.  Due to the inflated market crude oil pricing, the impact related to the derivatives to the first three months of 2005 has been negative, as the prices have exceeded the highs we originally expected. We have realized the benefit of these high prices on our crude oil production, but also realized the negative impact from $258,514 of cash settlements on our crude oil derivatives. We have also realized $156,500 of cash gains on our natural gas hedges due to the market natural gas prices falling below our hedge floors. Overall, oil and gas production revenue increased for the three months ended March 31, 2005 as compared to the same period in 2004 with a 33% increase in production and a 9% increase in the average net price received for our production.

 

Net Cash Used In Investing Activities

 

We reinvest a substantial portion of our cash flows in our drilling, acquisition, land and geophysical activities.  As a result, we used $12.8 million in investing activities during the first three months of 2005. Capital expenditures of $10.8 million were attributable to our drilling program. In addition to drilling that was in progress at year-end 2004, we drilled six gross wells during the first quarter of 2005, all of which were successful. Leasehold acquisitions, including seismic data and other geological and geophysical expenditures totaled $1.6 million and acquisition costs totaled $0.3 million for the three months ended March 31, 2005. The remaining capital expenditures were associated with computer hardware and office equipment. During the first quarter of 2004, we used $11.3 million in investing activities and we incurred capital expenditures of $9.4 million attributable to the drilling of nine gross wells, all of which were successful.  Leasehold acquisitions, including seismic data and other geological and geophysical expenditures totaled $1.7 million and acquisition costs totaled $0.1 million for the three months ended March 31, 2004. The remaining capital expenditures were associated with computer hardware and office equipment.  Proceeds from the sale of oil and gas properties totaled $40,000 during the first quarter of 2004.

 

We currently anticipate capital expenditures in 2005 to be approximately $63 million.  Approximately $51.8 million is allocated to our expected drilling and production activities; $7.9 million is allocated to land and seismic activities; and $3.3 million relates to capitalized interest and G&A and other.  We plan to fund these expenditures from expected cash flow from operations.  We do not explicitly budget for acquisitions; however, we do expect to spend considerable effort evaluating acquisition opportunities. We expect to fund acquisitions through traditional oil and gas reserve-based bank debt and the issuance of common stock and, if required, through additional debt and equity financings and production payment financings. We currently have $55.0 million of unused borrowing capacity under our credit facility and $91.8 million of unused capacity under our current shelf registration statement.

 

Net Cash Used In Financing Activities

 

Cash flows used in financing activities totaled $2.8 million for the three months ended March 31, 2005. Net repayments of $10.0 million under our current credit facility were partially offset by $7.2 million in proceeds from the issuance of common stock related to the exercise of the over-allotment option on our December 21, 2004 public offering and stock options exercised in the first three months of 2005. Cash flows used in financing activities totaled $31,759 for the three months ended March 31, 2004, and included repayments of $1.0 million under our credit

 

29



 

facility, $1.3 million of net proceeds from the issuance of common stock and deferred loan costs of $355,629 associated with amending that facility after the Miller merger.

 

Due to our active exploration, development and acquisition activities, we have experienced and expect to continue to experience substantial working capital requirements.  We intend to fund our projected 2005 capital expenditures, commitments and working capital requirements through cash flows from operations. We believe we will be able to generate capital resources and liquidity sufficient to fund our capital expenditures and meet such financial obligations as they come due.

 

Credit Facility

 

In March 2004, but effective December 31, 2003, the Company entered into a new amended and restated credit facility (the “Credit Facility”) which permits borrowings up to the lesser of (i) the borrowing base or (ii) $100 million.  Borrowings under the Credit Facility bear interest at a rate equal to prime plus 0.50% or LIBOR plus 2.25%.  As of March 31, 2005, $10.0 million in borrowings were outstanding under the Credit Facility and our interest rate was 6.25%.  The Credit Facility matures December 31, 2006 and is secured by substantially all of the Company’s assets.

 

Effective December 2004, the borrowing base under the Credit Facility was increased from $48.0 million to $65.0 million as a result of the asset acquisition that closed December 29, 2004 and our drilling activities since the last redetermination.Based on the increase, our available borrowing capacity at March 31, 2005 was $55.0 million. The borrowing base is currently being redetermined by our lender and we expect to be notified of any changes by the end of May 2005.

 

The Credit Facility provides for certain restrictions, including but not limited to, limitations on additional borrowings, sales of oil and natural gas properties or other collateral, and engaging in merger or consolidation transactions. The Credit Facility also prohibits dividends and certain distributions of cash or properties and certain liens.  The Credit Facility also contains the following financial covenants, among others:

 

                  The EBITDAX to Interest Expense ratio requires that the ratio of (a) our consolidated EBITDAX (defined as EBITDA plus similar non-cash items and exploration and abandonment expenses for such period) for the four fiscal quarters then ended to (b) our consolidated interest expense for the four fiscal quarters then ended, to not be less than 3.5 to 1.0.

                  The Working Capital ratio requires that the amount of our consolidated current assets less our consolidated current liabilities, as defined in the agreement, be at least $1.0 million. For the purposes of calculating the Working Capital ratio, current assets is adjusted for unused capacity under credit agreement and derivative financial instruments, and current liabilities is adjusted for derivative financial instruments and asset retirement obligations.

                  The Maximum Leverage ratio requires that the ratio, as of the last day of any fiscal quarter, of (a) Total Indebtedness (as defined in the Credit Facility) as of such fiscal quarter to (b) an amount equal to consolidated EBITDAX for the two quarters then ended times two, not be greater than 3.0 to 1.0.

 

Consolidated EBITDAX is a component of negotiated covenants with our lender and is presented here as part of the Company’s disclosure of its covenant obligations.

 

Shelf Registration Statement

 

We filed a $150 million shelf registration statement with the SEC, which became effective in May 2004. Under the shelf registration statement, we may issue, from time to time, any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities in one or more offerings to those persons who agree to purchase our securities. Net proceeds, terms and pricing of the offering of securities issued under the shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize our shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities, preferred stock, common

 

30



 

stock or warrants for debt securities or equity securities will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.

 

We completed an offering on December 21, 2004 of 3.5 million shares of our common stock under our shelf registration statement, which generated net proceeds to us, before direct costs of the offering, of $47.8 million. These funds were used to finance the asset acquisition that closed on December 29, 2004 with a final adjusted purchase price of $40.1 million, before other acquisition costs, and fund the costs of the offering and other general corporate purposes. On January 5, 2005, the underwriters exercised their over-allotment option for an additional 525,000 shares of common stock, which generated net proceeds to us of $7.2 million. These funds were used to reduce our outstanding debt. Each of these sales was made under our shelf registration statement. At March 31, 2005, we had approximately $91.8 million remaining for issuance under our shelf registration statement.

 

Off Balance Sheet Arrangements

 

We currently do not have any off balance sheet arrangements.

 

Contractual Cash Obligations

 

There were no material changes outside the ordinary course of our business in lease obligations or other contractual obligations since December 31, 2004.

 

Risk Management Activities – Derivatives & Hedging

 

Due to the instability of oil and natural gas prices, we may enter into, from time to time, price-risk management transactions (e.g., swaps, collars and floors) for a portion of our oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from commodity price fluctuations.  While the use of these arrangements limit our ability to benefit from increases in the price of oil and natural gas, it also reduces our potential exposure to adverse price movements.  Our arrangements, to the extent we enter into any, apply to only a portion of our production, provide only partial price protection against declines in oil and natural gas prices and limits our potential gains from future increases in prices. We also use price-risk management transactions to protect forward pricing as a bidding strategy with respect to acquisition offers and execution. None of these instruments are used for trading purposes. On a quarterly basis, our management sets all of our price-risk management policies, including volumes, types of instruments and counterparties. These policies are implemented by management through the execution of trades by the Chief Financial Officer after consultation and concurrence by the President and Chairman of the Board.  Our Board of Directors monitors the Company’s price-risk management policies and trades.

 

All of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” These derivative instruments are intended to hedge our price risk and may be considered hedges for economic purposes, but certain of these transactions may not qualify for special cash flow hedge accounting. Therefore, depending on the type of transaction and the circumstances, different accounting treatment may apply to the timing and location of the income statement impact, but all derivatives are recorded on the balance sheet at fair value. The following table provides additional information regarding the Company’s various derivative and hedging transactions that were recorded at fair value on the balance sheet as of March 31, 2005.

 

 

Fair value of contracts outstanding at December 31, 2004

 

$

1,356,482

 

Contracts realized or otherwise settled during the period

 

(442,030

)

Fair value of new contracts when entered into during 2005:

 

 

 

Asset

 

 

Liability

 

 

Changes in fair values attributable to changes in valuation techniques and assumptions

 

(3,514,547

)

Other changes in fair values

 

 

Fair values of contracts outstanding at March 31, 2005

 

$

(2,600,095

)

 

31



 

The following table details the fair value of our commodity-based derivative and hedging contracts by year of maturity and valuation methodology as of March 31, 2005.

 

 

 

Fair Value of Contracts at March 31, 2005

 

Source of Fair Value

 

Maturity less
than 1 year

 

Maturity 1-3
years

 

Maturity 4-5
years

 

Maturity in
excess of 5
years

 

Total fair
value

 

Prices actively quoted:

 

 

 

 

 

 

Prices provided by other external sources:

 

 

 

 

 

 

 

 

 

 

 

Asset

 

 

 

 

 

 

Liability

 

(2,600,095

)

 

 

 

(2,600,095

)

Prices based on models and other valuation methods:

 

 

 

 

 

 

Total

 

$

(2,600,095

)

$

 

$

 

$

 

$

(2,600,095

)

 

Tax Matters

 

At December 31, 2004, we had cumulative net operating loss carryforwards (“NOLs”) for federal income tax purposes of approximately $73.9 million, that expire beginning 2007 through 2022. The estimated NOLs presented herein assume that certain items, primarily intangible drilling costs, have been written off for tax purposes in the current year. However, we have not made a final determination if an election will be made to capitalize all or part of these items for tax purposes in the future.

 

Recently Issued Accounting Pronouncements

 

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” This statement requires companies to measure the cost of employee services in exchange for an award of equity instruments based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period. SFAS No. 123(R) amends the original SFAS No. 123 and 95 that had allowed companies to choose between expensing stock options or showing pro forma disclosure only. This statement eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25. We currently account for our stock-based compensation plans under the principles prescribed by APB Opinion No. 25. Accordingly, no stock option compensation cost is reflected in net income, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. The adoption of SFAS No. 123(R) will impact our results of operations, but will have no impact on our overall financial position. In March 2005, the SEC issued SAB No. 107. Among other things, SAB No. 107 provides interpretive guidance related to the interaction between SFAS No. 123(R) and certain SEC rules and regulations, as well as provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. SFAS No. 123(R) was to become effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005, but on April 14, 2005, the SEC issued press release 2005-57, which amends the compliance date of SFAS No. 123(R) until fiscal years beginning after June 15, 2005. We anticipate adopting the provisions of SFAS No. 123(R) in the first quarter of 2006 using the modified prospective method for transition. Under this method we will recognize compensation expense for all stock-based awards granted or modified on or after July 1, 2005, as well as any previously granted awards that are not fully vested as of July 1, 2005. Compensation expense will be measured based on the fair value of the awards previously calculated in developing the pro forma disclosures in accordance with the provisions of SFAS No. 123. We expect the impact to be immaterial due to the fact that the Company has not issued options since April 2004 and there will only be a minimal amount of unvested options as of our adoption date. SFAS No. 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost be reflected as a financing cash flow, rather than as an operating cash flow as currently required.

 

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”).  FIN 47 clarifies that the term, “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity.  Even though uncertainty about the

 

32



 

timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional.  Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated.  Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists.  The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred generally upon acquisition, construction, or development or through the normal operation of the asset.  SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation.  FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.  FIN 47 is effective no later than the end of reporting periods ending after December 15, 2005.  Retrospective application for interim financial information is permitted but is not required.  Early adoption of FIN 47 is encouraged.  We are currently evaluating what impact FIN 47 will have on our financial statements, but at this time, we do not believe that the adoption of FIN 47 will have a material effect on our financial position, results of operations or cash flows.

 

ITEM 3.  QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

 

We are exposed to market risk from changes in interest rates and commodity prices.  We use a credit facility, which has a floating interest rate, to finance a portion of our operations. We are not subject to fair value risk resulting from changes in our floating interest rates.  The use of floating rate debt instruments provides a benefit due to downward interest rate movements but does not limit us to exposure from future increases in interest rates.  Based on the March 31, 2005 outstanding borrowings and a floating interest rate of 6.25%, a 10% change in interest rates would result in an increase or decrease of interest expense of approximately $59,700 on an annual basis.

 

In the normal course of business we enter into hedging transactions, including commodity price collars, swaps and floors to mitigate our exposure to commodity price movements, but not for trading or speculative purposes.   During 2004, due to the instability of prices and to achieve a more predictable cash flow, we put in place natural gas and crude oil collars for a portion of our 2005 production. Please refer to Note 7 to our consolidated financial statements. While the use of these arrangements may limit the benefit to us of increases in the price of oil and natural gas, it also limits the downside risk of adverse price movements.  The following is a list of contracts outstanding as of March 31, 2005:

 

Transaction Date

 

Transaction Type

 

 

Beginning

 

Ending

 

Price
Per Unit

 

Volumes Per
Day

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas:

 

 

 

 

 

 

 

 

 

 

 

 

07/04

 

Collar (1)

 

 

04/01/05

 

06/30/05

 

$5.00-$7.53

 

10,000 MMbtu

 

07/04

 

Collar (1)

 

 

07/01/05

 

09/30/05

 

$5.00-$7.67

 

10,000 MMbtu

 

10/04

 

Collar (1)

 

 

01/01/05

 

12/31/05

 

$6.00-$9.52

 

10,000 MMbtu

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude Oil:

 

 

 

 

 

 

 

 

 

 

 

 

05/04(08/04)

 

Collar (2)(3)

 

 

01/01/05

 

12/31/05

 

$35.00-$40.00

 

200/290 Bbl

 

 


(1)     The Company’s current hedging activities for natural gas were entered into on a per MMbtu delivered price basis, using the Houston Ship Channel Index, with settlement for each calendar month occurring five business days following the expiration date.

(2)     Hedge accounting is not applied to the Company’s collars on crude oil, which were entered into on a per barrel delivered price basis, using the West Texas Intermediate Index, with settlement for each calendar month occurring five business days following the expiration date. The change in fair value is reflected in net revenue for the applicable periods.

(3)     In August 2004, the Company replaced the hedge contract that was outstanding at June 30, 2004 with a new contract that changes the volume and pricing terms. The put option is on 200 Bbl/D and the call option is on 290 Bbl/D. This transaction was completed at no additional cost to the Company.

 

  At March 31, 2005, the fair value of the outstanding hedges was a liability of approximately $2.6 million. A 10% change in the commodity price per unit, as long as the price is either above the ceiling or below the floor price would cause the fair value total of the hedge to increase or decrease by approximately $248,200.

 

33



 

ITEM 4. CONTROLS AND PROCEDURES
 

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2005 to provide reasonable assurance that 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 SEC’s rules and forms.

 

Except as described in this item, there has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.  In March 2005, management discovered an error in a spreadsheet application, which was designed to eliminate intercompany balances.  As a result of the error, amounts accumulated in the property account for one subsidiary were also included as an accrued capital expenditure by another subsidiary and inadvertently not eliminated in consolidation.  This caused property balances to be overstated.  This error in the property balance also impacted the computation of depletion expense and therefore operating expenses, operating income, income tax expense, net income and earnings per share.  Management concluded, based on the circumstances involving the error, that, as of December 31, 2004, a material weakness in internal control over financial reporting existed and the Company’s internal control over financial reporting was not effective.  Changes were made to the Company’s internal control over financial reporting in order to remediate the material weakness.  The change in accounting process in the second quarter of 2004 which led to the error was made in order to meet our shortened reporting deadlines with our then-existing staffing level.  In the first quarter of 2005, management effectively corrected the problem by re-instituting the accounting process we had used prior to the second quarter of 2004.  We were able to re-institute the old method as a result of increasing our staffing levels to assist with the closing of our financial statements.  Management believes that these actions remediate the material weakness.  These changes have been tested by the Company and are operating effectively.

 

34



 

PART II - OTHER INFORMATION

 

Item 1 - Legal Proceedings

 

From time to time we are a party to various legal proceedings arising in the ordinary course of business.  While the outcome of lawsuits cannot be predicted with certainty, we are not currently a party to any proceeding that we believe, if determined in a manner adverse to the Company, could have a potential material adverse effect on our financial condition, results of operations or cash flows.

 

During the second quarter of 2004, the Company received notice that its franchise tax returns for the State of Texas would be audited for the tax years 1999 through 2002. After reviewing documents submitted, the agent representing the Office of the Comptroller of the State of Texas proposed adjustments to the calculation that would result in an increased franchise tax liability.  The agent maintained that transfers by the parent company to its subsidiaries that the Company classified as intercompany loans should instead be classified as equity investments in the subsidiary. The State of Texas originally proposed that the franchise tax liability of the subsidiaries would be increased by approximately $3.0 million for the four-year period under audit.

 

During the third quarter of 2004, the agent reduced the proposed franchise tax deficiency adjustment to the Company and its subsidiaries to an aggregate of $467,000. In the fourth quarter of 2004, there was an informal hearing at the local Comptroller’s Office during which the agent indicated he would formally assess the proposed deficiency.  On March 24, 2005, the Company received such deficiency assessment in the amount of $471,482 including penalty and interest.  The Company responded on April 21, 2005 with a request for a formal redetermination hearing.  The Company intends to continue to vigorously contest the assessment through appropriate administrative levels in the Comptroller’s Office and any other available means.  Due to its intention to continue to vigorously contest the proposed adjustments, the Company has not recognized any provision for the additional franchise taxes that would result from the proposed deficiency.

 

Item 2 - Unregistered Sale of Equity Securities and Use of Proceeds

None

Item 3 - Defaults Upon Senior Securities

None

Item 4 - Submission of Matters to a Vote of Security Holders

None

 

 

 

Item 5 - Other Information

 

 

 

The Company filed a Current Report on Form 8-K on May 4, 2005 to report, among other things, changes in the compensation of non-employee directors of the Company.  The 8-K inadvertently stated that the additional retainers approved for chairmen of specified committees of the Board of Directors would not be payable until beginning with the 2006 annual meeting.  However, these additional retainers were instead paid following the 2005 annual meeting.

 

 

Item 6 - Exhibits

 

 

The following exhibits are filed as part of this report:

 

INDEX TO EXHIBITS

 

Exhibit No.

 

 

 

 

2.1

 

Amended and Restated Combination Agreement by and among (i) Edge Group II Limited Partnership, (ii) Gulfedge Limited Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum Corporation, (v) Edge Mergeco, Inc. and (vi) the Company, dated as of January 13, 1997 (Incorporated by reference from exhibit 2.1 to the Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).

 

 

 

 

2.2

 

Agreement and Plan of Merger dated as of May 28, 2003 among Edge Petroleum Corporation, Edge Delaware Sub Inc. and Miller Exploration Company (Miller”) (Incorporated by reference from Annex A to the Joint Proxy Statement/Prospectus contained in the Company’s Registration Statement on Form S-4/A filed on October 31, 2003 (Registration No. 333-106484)).

 

 

 

 

2.3

 

Asset Purchase Agreement by and among Contango STEP, L.P., Contango Oil & Gas Company, Edge Petroleum Exploration Company and Edge Petroleum Corporation dated October 7, 2004

 

35



 

 

 

 

(Incorporated by reference from exhibit 2.1 to the Company’s Current Report on Form 8-K filed October 12, 2004).

 

 

 

 

3.1

 

Restated Certificate of Incorporation of the Company effective January 27, 1997 (Incorporated by reference from exhibit 3.1 to the Company’s Current Report on Form 8-K filed April 29, 2005)..

 

 

 

 

3.2

 

Certificate of Amendment to the Restated Certificate of Incorporation of the Company effective January 31, 1997 (Incorporated by reference from exhibit 3.2 to the Company’s Current Report on Form 8-K filed April 29, 2005)

 

 

 

 

3.3

 

 

Certificate of Amendment to the Restated Certificate of Incorporation of the Company effective April 27, 2005 (Incorporated by reference from exhibit 3.3 to the Company’s Current Report on Form 8-K filed April 29, 2005).

 

 

 

 

3.4

 

Bylaws of the Company (Incorporated by Reference from exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).

 

 

 

 

3.5

 

First Amendment to Bylaws of the Company on September 28, 1999 (Incorporated by Reference from exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003).

 

 

 

 

3.6

 

Second Amendment to Bylaws of the Company on May 7, 2003 (Incorporated by reference from exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).

 

 

 

 

4.1

 

Third Amended and Restated Credit Agreement dated December 31, 2003 among Edge Petroleum Corporation, Edge Petroleum Exploration Company, Edge Petroleum Operating Company, Inc., Miller Oil Corporation, and Miller Exploration Company, as borrowers, the lenders thereto and Union Bank of California, N.A., a national banking association, as Agent (Incorporated by reference from Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).

 

 

 

 

4.2

 

Common Stock Subscription Agreement dated as of April 30, 1999 between the Company and the purchasers named therein (Incorporated by reference from exhibit 4.5 to the Company’s Quarterly Report on Form 10-Q/A for the quarter ended March 31, 1999).

 

 

 

 

4.3

 

Registration Rights Agreement by and among Edge Petroleum Corporation, Guardian Energy Management Corp., Kelly E. Miller and the Debra A. Miller Trust, dated December 4, 2003 (Incorporated by reference from exhibit 4.2 to the Company’s Registration Statement on Form S-3 filed on February 3, 2004 (Registration No. 333-112462)).

 

 

 

 

4.4

 

Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from exhibit 10.1(a) to Miller Exploration Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).

 

 

 

 

4.5

 

Amendment No. 1 to the Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference to Exhibit 4.2 from Miller Exploration Company’s Registration Statement on Form S-8 filed on April 11, 2001 (Registration No. 333-58678)).

 

36



 

4.6

 

Amendment No. 2 to the Miller Exploration Company Stock Option and Restricted Stock Plan of 1997 (Incorporated by reference from Exhibit 4.3 to Miller Exploration Company’s Registration Statement on Form S-8 filed on April 11, 2001 (Registration No. 333-58678)).

 

 

 

 

4.7

 

Form of Miller Stock Option Agreement (Incorporated by reference from exhibit 10.1(b) to Miller Exploration Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-23431)).

 

 

 

 

10.1

 

Form of Indemnification Agreement between the Company and each of its directors (Incorporated by reference from exhibit 10.7 to the Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).

 

 

 

 

10.2

 

Stock Option Plan of Edge Petroleum Corporation, a Texas corporation (Incorporated by reference from exhibit 10.13 to the Company’s Registration Statement on Form S-4 (Registration No. 333-17269)).

 

 

 

 

10.3

 

Employment Agreement dated as of November 16, 1998, by and between the Company and John W. Elias (Incorporated by reference from 10.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998).

 

 

 

 

10.4

 

Incentive Plan of Edge Petroleum Corporation as Amended and Restated Effective as of June 1, 2004 (Incorporated by reference from exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).

 

 

 

 

10.5

 

Edge Petroleum Corporation Incentive Plan “Standard Non-Qualified Stock Option Agreement” by and between Edge Petroleum Corporation and the Officers named therein (Incorporated by reference from exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).

 

 

 

 

10.6

 

Edge Petroleum Corporation Incentive Plan “Director Non-Qualified Stock Option Agreement” by and between Edge Petroleum Corporation and the Directors named therein (Incorporated by reference from exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).

 

 

 

 

10.7

 

Severance Agreements by and between Edge Petroleum Corporation and the Officers of the Company named herein (Incorporated by reference from exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).

 

 

 

 

10.8

 

Form of Director’s Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation (Incorporated by reference from exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).

 

 

 

 

10.9

 

Form of Employee Restricted Stock Award Agreement under the Incentive Plan of Edge Petroleum Corporation (Incorporated by reference from exhibit 10.15 to the Company’s Quarterly Report on Form 10-Q/A for the quarterly period ended March 31, 1999).

 

 

 

 

10.10

 

Edge Petroleum Corporation Amended and Restated Elias Stock Incentive Plan. (Incorporated by reference from exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed May 30, 2001 (Registration No. 333-61890)).

 

 

 

 

10.11

 

Form of Edge Petroleum Corporation John W. Elias Non-Qualified Stock Option Agreement (Incorporated by reference from exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed May 30, 2001 (Registration No. 333-61890)).

 

 

 

 

10.12

 

Summary of Compensation of Non-Employee Directors.

 

37



 

10.13

 

Salaries and Other Compensation of Executive Officers.

 

 

 

 

10.14

 

Description of 2004 Bonus Program for Executive Officers.