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Edge Petroleum 10-Q 2005

Documents found in this filing:

  1. 10-Q
  2. Ex-4.2
  3. Ex-31.1
  4. Ex-31.2
  5. Ex-32.1
  6. Ex-32.2
  7. 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 June 30, 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

 

(I.R.S. Employer

incorporation or organization)

 

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 August 5, 2005

 

 

 

Common Stock

 

17,138,357

 

 



 

EDGE PETROLEUM CORPORATION

 

Table of Contents

 

Part I. Financial Information

 

Item 1. Financial Statements:

 

Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004

 

Consolidated Statements of Operations for the Three and Six Months in the Periods Ended June 30, 2005 and June 30, 2004

 

Consolidated Statements of Other Comprehensive Income for the Three and Six Months in the Periods Ended June 30, 2005 and June 30, 2004

 

Consolidated Statements of Cash Flows for the Six Months in the Periods Ended June 30, 2005 and June 30, 2004

 

Consolidated Statements of Stockholders’ Equity as of June 30, 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

 

 

 

June 30,
2005

 

December 31,
2004

 

 

 

(Unaudited)

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

$

2,179,589

 

$

2,267,423

 

Accounts receivable, trade, net of allowance of $525,248 at June 30, 2005 and December 31, 2004

 

14,945,716

 

12,756,097

 

Accounts receivable, joint interest owners, net of allowance of $93,000 and $82,000 at June 30, 2005 and December 31, 2004, respectively

 

2,559,601

 

5,911,073

 

Deferred income taxes

 

1,305,333

 

660,223

 

Derivative financial instruments

 

 

1,824,790

 

Other current assets

 

3,200,943

 

1,445,923

 

 

 

 

 

 

 

Total current assets

 

24,191,182

 

24,865,529

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT, Net – full cost method of accounting for oil and natural gas properties (including unproved costs of $15.9 million and $15.5 million at June 30, 2005 and December 31, 2004, respectively)

 

182,409,838

 

165,840,345

 

 

 

 

 

 

 

OTHER ASSETS

 

213,210

 

284,280

 

 

 

 

 

 

 

TOTAL ASSETS

 

$

206,814,230

 

$

190,990,154

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable, trade

 

$

1,022,216

 

$

3,141,235

 

Accrued liabilities

 

11,271,704

 

12,105,694

 

Asset retirement obligation – current portion

 

197,109

 

193,647

 

Derivative financial instruments

 

1,220,041

 

468,308

 

Total current liabilities

 

13,711,070

 

15,908,884

 

 

 

 

 

 

 

ASSET RETIREMENT OBLIGATION – non-current portion

 

2,100,472

 

1,995,441

 

 

 

 

 

 

 

DEFERRED TAX LIABILITY

 

8,911,769

 

2,618,934

 

 

 

 

 

 

 

LONG-TERM DEBT

 

13,000,000

 

20,000,000

 

 

 

 

 

 

 

Total liabilities

 

37,723,311

 

40,523,259

 

 

 

 

 

 

 

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; 60,000,000 shares authorized; 17,127,837 and 16,535,901 shares issued and outstanding at June 30, 2005 and December 31, 2004, respectively

 

171,278

 

165,359

 

Additional paid-in capital

 

134,956,715

 

126,957,059

 

Retained earnings

 

34,028,849

 

22,095,807

 

Accumulated other comprehensive income (loss)

 

(65,923

)

1,248,670

 

 

 

 

 

 

 

Total stockholders’ equity

 

169,090,919

 

150,466,895

 

 

 

 

 

 

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

 

$

206,814,230

 

$

190,990,154

 

 

See accompanying notes to consolidated financial statements.

 

3



 

EDGE PETROLEUM CORPORATION

 

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2005

 

2004

 

2005

 

2004

 

OIL AND NATURAL GAS REVENUE

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

 

$

26,228,287

 

$

16,225,435

 

$

50,156,976

 

$

32,021,926

 

Loss on hedging and derivatives

 

(17,834

)

(378,031

)

(1,002,678

)

(359,865

)

Total revenue

 

26,210,453

 

15,847,404

 

49,154,298

 

31,662,061

 

 

 

 

 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

 

 

 

 

Oil and natural gas operating expenses

 

1,802,049

 

1,220,092

 

4,044,514

 

2,425,166

 

Severance and ad valorem taxes

 

1,784,837

 

1,210,208

 

3,651,325

 

2,254,922

 

Depletion, depreciation, amortization and accretion

 

8,938,998

 

5,141,387

 

17,574,627

 

10,383,802

 

General and administrative expenses:

 

 

 

 

 

 

 

 

 

Deferred compensation – repriced options

 

(90,259

)

337,386

 

171,645

 

1,448,485

 

Deferred compensation – restricted stock

 

262,745

 

114,600

 

406,344

 

211,100

 

Bad debt expense

 

 

 

11,000

 

 

Other general and administrative expenses

 

2,357,413

 

1,731,453

 

4,836,138

 

3,632,280

 

 

 

 

 

 

 

 

 

 

 

Total operating expenses

 

15,055,783

 

9,755,126

 

30,695,593

 

20,355,755

 

 

 

 

 

 

 

 

 

 

 

OPERATING INCOME

 

11,154,670

 

6,092,278

 

18,458,705

 

11,306,306

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME AND EXPENSE:

 

 

 

 

 

 

 

 

 

Interest income

 

24,129

 

4,023

 

56,475

 

8,031

 

Interest expense, net of amounts capitalized

 

 

(105,405

)

 

(219,683

)

Amortization of deferred loan costs

 

(35,535

)

(40,748

)

(71,070

)

(70,384

)

 

 

 

 

 

 

 

 

 

 

INCOME BEFORE INCOME TAXES

 

11,143,264

 

5,950,148

 

18,444,110

 

11,024,270

 

 

 

 

 

 

 

 

 

 

 

INCOME TAX EXPENSE

 

(3,933,752

)

(2,094,067

)

(6,511,068

)

(3,884,953

)

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

$

7,209,512

 

$

3,856,081

 

$

11,933,042

 

$

7,139,317

 

 

 

 

 

 

 

 

 

 

 

BASIC EARNINGS PER SHARE:

 

$

0.42

 

$

0.30

 

$

0.70

 

$

0.56

 

 

 

 

 

 

 

 

 

 

 

DILUTED EARNINGS PER SHARE:

 

$

0.40

 

$

0.28

 

$

0.67

 

$

0.53

 

 

 

 

 

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING

 

17,120,163

 

12,940,504

 

17,081,493

 

12,833,226

 

 

 

 

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING

 

17,796,443

 

13,588,578

 

17,744,965

 

13,412,589

 

 

See accompanying notes to consolidated financial statements.

 

4



 

EDGE PETROLEUM CORPORATION

 

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (Unaudited)

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2005

 

2004

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

NET INCOME

 

$

7,209,512

 

$

3,856,081

 

$

11,933,042

 

$

7,139,317

 

 

 

 

 

 

 

 

 

 

 

OTHER COMPREHENSIVE INCOME (LOSS), net of tax:

 

 

 

 

 

 

 

 

 

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

 

540,721

 

112,991

 

(647,997

)

(368,047

)

Reclassification of hedging and derivative losses (gains) (2)

 

142,622

 

241,773

 

(666,596

)

155,199

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income (loss)

 

683,343

 

354,764

 

(1,314,593

)

(212,848

)

 

 

 

 

 

 

 

 

 

 

COMPREHENSIVE INCOME

 

$

7,892,855

 

$

4,210,845

 

$

10,618,449

 

$

6,926,469

 

 


 

(1) Income tax (expense) benefit

 

$

291,157

 

$

60,842

 

$

(348,921

)

$

(198,179

)

 

 

 

 

 

 

 

 

 

 

(2) Income tax (expense) benefit

 

$

76,797

 

$

130,186

 

$

(358,936

)

$

89,828

 

 

See accompanying notes to consolidated financial statements.

 

5



 

EDGE PETROLEUM CORPORATION

 

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

 

 

 

Six Months Ended June 30,

 

 

 

2005

 

2004

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net income

 

$

11,933,042

 

$

7,139,317

 

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

 

 

 

 

 

Loss (gain) on the unrealized change in fair value of derivatives

 

554,074

 

(179,261

)

Loss on property

 

1,778

 

 

Deferred income taxes

 

6,511,068

 

3,884,953

 

Depletion, depreciation, amortization and accretion

 

17,574,627

 

10,383,802

 

Amortization of deferred loan costs

 

71,070

 

70,384

 

Deferred compensation

 

577,989

 

1,659,585

 

Bad debt expense

 

11,000

 

 

Changes in assets and liabilities:

 

 

 

 

 

Increase in accounts receivable, trade

 

(1,229,826

)

(630,158

)

(Increase) decrease in accounts receivable, joint interest owners

 

3,340,472

 

(264,742

)

Increase in other assets

 

(1,755,020

)

(946,179

)

Increase (decrease) in accounts payable, trade

 

(2,119,019

)

977,797

 

Increase (decrease) in accrued liabilities

 

(1,731,857

)

1,131,301

 

Increase in accrued interest payable

 

 

20,573

 

 

 

 

 

 

 

Net cash provided by operating activities

 

33,739,398

 

23,247,372

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Oil and natural gas property and equipment additions

 

(34,037,405

)

(19,397,552

)

Proceeds from the sale of oil and natural gas properties

 

 

40,000

 

 

 

 

 

 

 

Net cash used in investing activities

 

(34,037,405

)

(19,357,552

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Borrowings from long-term debt

 

3,000,000

 

 

Payments of long-term debt

 

(10,000,000

)

(3,000,000

)

Net proceeds from issuance of common stock

 

7,210,173

 

1,938,853

 

Deferred loan costs

 

 

(422,304

)

 

 

 

 

 

 

Net cash provided by (used in) financing activities

 

210,173

 

(1,483,451

)

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

(87,834

)

2,406,369

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

 

2,267,423

 

1,327,081

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, END OF PERIOD

 

$

2,179,589

 

$

3,733,450

 

 

See accompanying notes to consolidated financial statements.

 

6



 

EDGE PETROLEUM CORPORATION

 

CONSOLIDATED STATEMENTS 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

 

591,936

 

5,919

 

7,266,180

 

 

 

7,272,099

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred compensation – restricted stock

 

 

 

406,344

 

 

 

406,344

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred compensation - repriced options

 

 

 

171,645

 

 

 

171,645

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Change in valuation of hedging instruments

 

 

 

 

 

(1,314,593

)

(1,314,593

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tax benefit associated with exercise of non-qualified stock options

 

 

 

155,487

 

 

 

155,487

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

11,933,042

 

 

11,933,042

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE, JUNE 30, 2005

 

17,127,837

 

$

171,278

 

$

134,956,715

 

$

34,028,849

 

$

(65,923

)

$

169,090,919

 

 

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 (with the exception of the balance sheet as of December 31, 2004 which has been derived from our Annual Report on Form 10-K for the year ended December 31, 2004) 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 interest expense on borrowed funds not in excess of the balance of our unproved property balance.  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 natural gas liquids (“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 $15.9 million and $15.5 million at June 30, 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 June 30, 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 six-month periods ended June 30, 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 June 30, 2005 and 2004 are as follows:

 

 

 

Six Months Ended June 30,

 

 

 

2005

 

2004

 

ARO, Beginning of Period

 

$

2,189,088

 

$

1,811,995

 

Liabilities incurred in the current period

 

138,883

 

139,737

 

Liabilities settled in the current period

 

(97,919

)

(113,136

)

Accretion expense

 

67,529

 

52,501

 

Revisions

 

 

 

ARO, End of Period

 

$

2,297,581

 

$

1,891,097

 

 

 

 

 

 

 

Current Portion

 

$

197,109

 

$

386,889

 

Long Term Portion

 

$

2,100,472

 

$

1,504,208

 

 

During the six months ended June 30, 2005, ARO liabilities incurred include 15 new well obligations and liabilities settled include six 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,

 

9



 

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-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 June 30,

 

Six Months Ended June 30,

 

 

 

2005

 

2004

 

2005

 

2004

 

Net income as reported

 

$

7,209,512

 

$

3,856,081

 

$

11,933,042

 

$

7,139,317

 

Add:

 

 

 

 

 

 

 

 

 

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

 

112,116

 

293,791

 

375,693

 

1,078,730

 

Deduct:

 

 

 

 

 

 

 

 

 

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

 

(200,765

)

(90,111

)

(325,510

)

(208,288

)

Pro forma net income

 

$

7,120,863

 

$

4,059,761

 

$

11,983,225

 

$

8,009,759

 

 

 

 

 

 

 

 

 

 

 

Earnings Per Share:

 

 

 

 

 

 

 

 

 

Basic – as reported

 

$

0.42

 

$

0.30

 

$

0.70

 

$

0.56

 

Basic – pro forma

 

$

0.42

 

$

0.31

 

$

0.70

 

$

0.62

 

 

 

 

 

 

 

 

 

 

 

Diluted – as reported

 

$

0.40

 

$

0.28

 

$

0.67

 

$

0.53

 

Diluted – pro forma

 

$

0.40

 

$

0.30

 

$

0.68

 

$

0.60

 

 

As a result of the re-pricing in May 1999 of certain non-qualified stock options granted to our employees and directors in prior years, as well as issuing new options in conjunction with such re-pricing, we became subject to the reporting requirements of FASB Interpretation No. (“FIN”) 44, “Accounting for Certain Transactions Involving Stock Compensation”. FIN 44 requires a company, among other things, to record a non-cash, pre-tax charge to deferred compensation expense if the market price of such company’s common stock at the end of a reporting period is greater than the exercise price of any re-priced stock options.  After the first such adjustment is made, each subsequent period is adjusted upward or downward, and a charge or credit, as applicable, for the period is recorded.  Volatility in a company’s stock price can have a direct impact on the amount of these charges and credits from period to period, which may affect the comparability of results between periods. As of June 30, 2005, we had 159,750 of such options outstanding that were subject to these FIN 44 reporting requirements. The market price used to calculate the related charge or credit, as applicable, was $15.68 per share at June 30, 2005, as compared to $16.25 per share at March 31, 2005 and $14.66 per share at December 31, 2004. For the second quarter of 2005, we recorded a non-cash, pre-tax credit of $90,259, as compared to a non-cash, pre-tax charge of $337,386 for the second quarter of 2004.  For the first half of 2005, we recorded a non-cash, pre-tax charge of $171,645 as compared to a non-cash, pre-tax charge of approximately $1.4 million for the same period in 2004.

 

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.

 

10



 

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. 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 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 consolidated financial position, results of operations or cash flows.

 

In June 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, which changes the requirements for the accounting for and reporting of a change in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Application is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Early adoption is permitted. The adoption of SFAS No. 154 is not expected to have a material effect on the Company’s consolidated 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 June 30, 2005, the interest rate applied to our outstanding balance was 6.00%. Commitment fees of 0.50% to 3.75% accrue on the unused portion of the borrowing base, depending on the utilization percentage, and are included as a component of interest expense. As of June 30, 2005, $13.0 million in borrowings were outstanding under the Credit Facility.

 

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

 

11



 

closed December 29, 2004 and drilling activities since the last redetermination. On May 31, 2005, the borrowing base was increased from $65.0 million to $70.0 million as a result of drilling activities since the last redetermination. In addition, the maturity date was extended from December 31, 2006 to December 31, 2007 and the interest rate margins were reduced from previous levels.  The Company’s available borrowing capacity under this facility was $57.0 million at June 30, 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 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 are adjusted for unused capacity under credit agreement and derivative financial instruments, and current liabilities are 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 defined here as part of the Company’s disclosure of its covenant obligations.

 

3.          SHELF REGISTRATION STATEMENT

 

During 2004, the Company filed a $150 million shelf registration statement with the SEC, which became effective in May 2004. During the second quarter 2005, the Company filed a new registration statement that replaced the prior registration statement and increased the amount of securities registered to $390 million.  Under this shelf registration statement, the Company may issue, from time to time, any combination of debt securities, preferred stock, common stock or warrants 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 the shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities, preferred stock, common stock or warrants 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 initial 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 initial shelf registration statement. At June 30, 2005, the Company had $390 million available for issuance under its current shelf registration statement.

 

12



 

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 and six-month periods ended June 30, 2005 and 2004:

 

 

 

Three Months Ended June 30, 2005

 

Three Months Ended June 30, 2004

 

 

 

Income
(Numerator)

 

Shares
(Denominator)

 

Per Share
Amount

 

Income
(Numerator)

 

Shares
(Denominator)

 

Per
Share
Amount

 

Basic EPS

 

 

 

 

 

 

 

 

 

 

 

 

 

Income available to common stockholders

 

$

7,209,512

 

17,120,163

 

$

0.42

 

$

3,856,081

 

12,940,504

 

$

0.30

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock

 

 

197,061

 

(0.01

)

 

138,138

 

(0.01

)

Common stock options

 

 

479,219

 

(0.01

)

 

509,936

 

(0.01

)

Diluted EPS

 

 

 

 

 

 

 

 

 

 

 

 

 

Income available to common stockholders

 

$

7,209,512

 

17,796,443

 

$

0.40

 

$

3,856,081

 

13,588,578

 

$

0.28

 

 

 

 

Six Months Ended June 30, 2005

 

Six Months Ended June 30, 2004

 

 

 

Income
(Numerator)

 

Shares
(Denominator)

 

Per Share
Amount

 

Income
(Numerator)

 

Shares
(Denominator)

 

Per
Share
Amount

 

Basic EPS

 

 

 

 

 

 

 

 

 

 

 

 

 

Income available to common stockholders

 

$

11,933,042

 

17,081,493

 

$

0.70

 

$

7,139,317

 

12,833,226

 

$

0.56

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock

 

 

173,593

 

(0.01

)

 

105,368

 

(0.01

)

Common stock options

 

 

489,879

 

(0.02

)

 

473,995

 

(0.02

)

Diluted EPS

 

 

 

 

 

 

 

 

 

 

 

 

 

Income available to common stockholders

 

$

11,933,042

 

17,744,965

 

$

0.67

 

$

7,139,317

 

13,412,589

 

$

0.53

 

 

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.

 

13



 

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 $6.5 million and $3.9 million was reported for the six months ended June 30, 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 six months ended June 30, 2005 and 2004 is presented below:

 

Description

 

Number of
Shares
Issued

 

Fair Market
Value

 

Six months ended June 30, 2005:

 

 

 

 

 

Shares issued to satisfy restricted stock grants

 

48,261

 

$

481,842

 

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

 

4,275

 

$

61,926

 

Six months ended June 30, 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

 

3,360

 

$

43,582

 

 

For the six months ended June 30, 2005 and 2004, the non-cash portion of Asset Retirement Costs was $40,964 and $26,601, respectively.  A supplemental disclosure of cash flow information related to interest for the six months ended June 30, 2005 and 2004 is presented below:

 

 

 

For the Six Months Ended
June 30,

 

 

 

2005

 

2004

 

Cash paid during the period for:

 

 

 

 

 

Interest, net of amounts capitalized of $480,089 and $211,479 for the six months ended June 30, 2005 and 2004, respectively

 

$

 

$

199,109

 

Income taxes*

 

 

 

 


*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 or speculative 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.

 

14



 

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 six months ended June 30, 2005 and 2004, the Company included in revenue realized and unrealized losses of $1.0 million and $0.4 million, respectively, related to its natural gas hedges and oil derivatives. There was no ineffectiveness recognized during the six months ended June 30, 2005 or 2004.

 

 

 

Six Months Ended June 30,

 

 

 

2005

 

2004

 

Natural gas hedging contract settlements

 

$

156,500

 

$

(222,000

)

Oil derivative contract settlements

 

(605,104

)

(103,276

)

Hedge premium reclassification

 

 

(213,850

)

Oil derivative contract unrealized change in fair value

 

(554,074

)

179,261

 

Gain (loss) on hedging and derivatives

 

$

(1,002,678

)

$

(359,865

)

 

The outstanding hedges at June 30, 2005 and December 31, 2004 impacting the balance sheet were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value of Outstanding Hedging and
Derivative Contracts as of

 

Transaction Date

 

Transaction Type

 

Beginning

 

Ending

 

Price
Per Unit

 

Volumes
Per Day

 

June 30,
2005

 

December 31,
2004 (4)

 

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

 

 

9,162

 

07/04

 

Collar

 

07/01/2005

 

09/30/2005

 

$5.00-$7.67

 

10,000MMbtu

 

(76,232

)

(41,210

)

10/04

 

Collar

 

01/01/2005

 

12/31/2005

 

$6.00-$9.52

 

10,000MMbtu

 

(25,187

)

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

 

(1,118,622

)

(468,308

)

 

 

 

 

 

 

 

 

 

 

 

 

$

(1,220,041

)

$

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.

 

15



 

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. At December 31, 2004 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.

 

Hedges entered into after June 30, 2005 were as follows:

 

Transaction
Date

 

Transaction
Type

 

Effective Dates

 

Price Per
Unit

 

Volumes
Per Day

 

 

 

Beginning

 

Ending

 

 

 

08/05

 

Natural Gas Collar

(1)

01/01/2006

 

12/31/2006

 

$7.00-$10.50

 

10,000 MMBTU

 

 


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

 

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- and six-months ended June 30, 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 (4) 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:

 

 

 

For the Three
Months Ended

 

For the Six
Months Ended

 

 

 

June 30, 2004

 

 

 

(unaudited)
(In thousands, except per share amounts)

 

Revenue

 

$

22,646

 

$

45,009

 

Net income

 

$

7,429

 

$

13,879

 

Net income per common share:

 

 

 

 

 

Basic

 

$

0.43

 

$

0.82

 

Diluted

 

$

0.43

 

$

0.80

 

 

16



 

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. In July 2005, the Company submitted additional documents and evidence supporting its position for the 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.

 

17



 

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 and any other benefit of an acquisition, our ability to access the capital markets to raise additional capital, our debt-to-total capital ratio, our drilling plans and the ability to secure drilling rigs to effectuate these plans, our natural gas and oil production volumes, our 3-D project portfolio, our ability to hedge our risks, our ability to reduce our interest rates, 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, hedging opportunities in the future, 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

 

18



 

Exploration Company (“Miller”).  The transaction was treated as a tax-free reorganization and accounted for as a 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 experienced 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. The recent high commodity price environment has also led to increased costs in our industry, which together with increased demand for rigs, equipment and supplies, have made it difficult at times for us to further our growth.

 

19



 

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.

 

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 June 30, 2005, we had hedge contracts in place covering approximately 40% and 31% of our remaining expected 2005 natural gas and crude oil production, respectively, or approximately 33% 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. In December 2004, our Board approved a 2005 capital budget of $63 million. At our July 27, 2005 Board of Director’s meeting, a budget supplement of $13 million was approved, effectively raising our planned capital budget to $76 million. The capital budget could be further increased to accommodate an increase in wells, if and when additional drilling rigs become available. 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 a net $7.0 million in the first six months of 2005 to $13.0 million at June 30, 2005. As of that date, our debt to total capital ratio was approximately 7.1%. Also in the second quarter of 2005, we took steps to increase our shelf registration statement capacity to $390 million from approximately $90 million (see Note 3 to our consolidated financial statements), which became effective on July 1, 2005. We believe we have the financial flexibility to continue to execute our business strategies.

 

Acquisitions and Divestitures

 

Acquisitions – Acquisitions add meaningful incremental increases in reserves and production and may range in size from acquiring a working interest in non-operated producing property to an entire field or company. Unlike drilling capital, which is planned and budgeted, acquisition capital is neither budgeted nor allocated.  Specific timing of acquisitions cannot be predicted. Although we consider a wide variety of acquisitions, a significant part of our growth strategy is expected to be focused toward producing property acquisitions, which we believe have exploitable potential.  Because of our financial flexibility, we are positioned to take advantage of producing property acquisition opportunities as they may arise. In today’s high price environment, where production is providing greater cash flow and earnings to most companies, identifying quality opportunities is difficult. We believe through hard work, technical ability and creative thinking of our people, we will continue to grow through

 

20



 

both acquisitions and drilling. Any such acquisition could involve the payment by us of a substantial amount of cash or the issuance of a substantial number of additional shares or other securities.

 

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 then 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 2005. 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 half 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 dispositions can have the result of furthering our objective of financial flexibility through reduced debt levels. During the six months ended June 30, 2005, there were no divestitures as compared to the first six 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 as we seek to further our growth. We expect our drilling program to increase from 49 wells (26.9 net) in 2004 to approximately 50 to 55 wells (26 to 29 net) in 2005. Our ability to materially increase the number of wells to be drilled beyond our original budget number is heavily dependent upon the timely access to oilfield services, particularly drilling rigs. The rig situation has delayed the drilling of several larger interest, higher impact wells causing delays in our forecasted growth in production. 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. We initiated activities in the Fayettville and Floyd Shales that we expect to become new core areas for us.

 

To help protect against the possibility that commodity prices do not remain at the current levels, we have entered into several hedges covering approximately 40% of our expected natural gas production and 31% 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 33% of total production on an Mcfe basis. We currently have no contracts covering periods beyond 2005, but may consider hedging opportunities in the future.

 

In order to manage our realized and anticipated growth, we increased our headcount from 51 employees as of December 31, 2004 to 57 employees as of June 30, 2005 and we are currently expanding our office space, 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.

 

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.”

 

21



 

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.

 

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 six months ended June 30, 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 June 30, 2005 were $56.50 per barrel and $6.98 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 June 30, 2005, we had a cushion (i.e. the excess of the

 

22



 

ceiling over our capitalized costs) of $84.0 million. A 10% increase or decrease in prices used would have increased or decreased our cushion by approximately 45%. 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% higher as these prices would be within the collars, but had we decreased the price by 10% the price would have breached our several hedge floors and therefore resulted in a minimal decrease in the ceiling of approximately $8,400. 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 34%.

 

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 June 30, 2005, we had $15.9 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 June 30, 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 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.

 

23



 

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.

 

Effect if different assumptions used: Our independent public accounting firm assists 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.

 

24



 

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, and 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 June 30, 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 $116,500.

 

Results of Operations

 

This section includes discussion of our results of operations for the three-month period ended June 30, 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, Mississippi, Louisiana, and southeast New Mexico.

 

Second Quarter 2005 Compared to the Second Quarter 2004

 

Revenue and Production

 

Total revenue increased 65% from the second quarter of 2004 to the comparable 2005 period.  For the second quarter of 2005 and 2004, our product mix contributed the following percentages of revenues and production:

 

 

 

REVENUES (1)

 

PRODUCTION

 

 

 

2005

 

2004

 

2005

 

2004

 

Natural Gas (Mcf)

 

80%

 

83%

 

76%

 

79%

 

Natural gas liquids (Bbls)

 

5%

 

6%

 

12%

 

12%

 

Crude oil (Bbl)

 

15%

 

11%

 

12%

 

9%

 

 

 

 

 

 

 

 

 

 

 

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 second quarter of 2005 and 2004:

 

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Three Months Ended
June 30,

 

2005 Period Compared
to 2004 Period

 

 

 

 

$
Increase
(Decrease)

 

%
Increase
(Decrease)

 

 

 

2005

 

2004

 

 

 

Production Volumes:

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

3,082,932

 

2,298,064

 

784,868

 

34

%

Natural gas liquids (Bbls)

 

83,156

 

57,602

 

25,554

 

44

%

Oil and condensate (Bbls)

 

79,583

 

45,832

 

33,751

 

74

%

Natural gas equivalent (Mcfe)

 

4,059,334

 

2,918,668

 

1,140,666

 

39

%

Average Sales Price:

 

 

 

 

 

 

 

 

 

Natural gas ($ per Mcf)(1)

 

$

6.76

 

$

5.92

 

$

0.84

 

14

%

Natural gas liquids ($ per Bbl)

 

$

17.15

 

$

14.87

 

$

2.28

 

15

%

Oil and condensate ($ per Bbl)(1)

 

$

49.78

 

$

38.30

 

$

11.48

 

30

%

Natural gas equivalent ($ per Mcfe)(1)

 

$

6.46

 

$

5.56

 

$

0.90

 

16

%

Natural gas equivalent ($per Mcfe)(2)

 

$

6.46

 

$

5.43

 

$

1.03

 

19

%

Operating Revenue:

 

 

 

 

 

 

 

 

 

Natural gas (1)

 

$

20,840,741

 

$

13,613,310

 

$

7,227,431

 

53

%

Natural gas liquids

 

1,425,794

 

856,777

 

569,017

 

66

%

Oil and condensate (1)

 

3,961,752

 

1,755,348

 

2,206,404

 

126

%

Loss on hedging and derivatives

 

(17,834

)

(378,031

)

360,197

 

95

%

Total

 

$

26,210,453

 

$

15,847,404

 

$

10,363,049

 

65

%

 


(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 53% for the three months ended June 30, 2005 over the same period in 2004 due to significantly higher production and higher realized prices. Average natural gas production increased 34% from 2.3 Bcfe in the three months ended June 30, 2004 to 3.1 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 other acquired properties, partially offset by natural declines on other properties. The overall increase in production compared to the prior year period resulted in an increase in revenue of approximately $4.6 million (based on 2004 comparable period pre-hedge prices). Excluding the effect of hedges, the average natural gas sales price for production in the three months ended June 30, 2005 was $6.76 per Mcf compared to $5.92 per Mcf for the same period in 2004.  This increase in average price received resulted in increased revenue of approximately $2.6 million (based on current year production).

 

Revenue from the sale of NGLs increased 66% for the three months ended June 30, 2005 over the same period in 2004. Production volumes for NGLs increased 44%, from 57.6 MBbls for the three months ended June 30, 2004 to 83.2 MBbls for the three months ended June 30, 2005 due primarily to increased production from new wells at Encinitas and Gato Creek, partially offset by natural declines on other properties. The increase in NGL production increased revenue by approximately $380,000 (based on 2004 comparable period average prices).  Higher average realized prices for the three months ended June 30, 2005 resulted in an increase in revenue of approximately $189,000 (based on current year production).  The average realized price for NGLs for the three months ended June 30, 2005 was $17.15 per barrel compared to $14.87 per barrel for the same period in 2004.

 

Revenue from the sale of oil and condensate, excluding derivative activity, increased 126% for the three months ended June 30, 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 June 30, 2005 was $49.78 per barrel compared to $38.30 per barrel in the same period of

 

26



 

2004.  These higher average prices for the three months ended June 30, 2005 resulted in an increase in revenue of approximately $1.3 million (based on current year production).  Production volumes for oil and condensate increased 74% to 79.6 MBbls for the three months ended June 30, 2005 compared to 45.8 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 on our New Mexico and other acquired properties. The increase in oil and condensate production resulted in an increase in revenue of approximately $0.9 million (based on 2004 comparable period average prices).

 

Losses on hedging and derivatives decreased for the three months ended June 30, 2005 over the same period in 2004 due to the change in the fair market value of the outstanding derivative contracts and cash settlements on expiring contracts. Oil and condensate revenues were reduced slightly by realized losses partially offset by unrealized gains on our oil derivatives. For the three months ended June 30, 2005, we recorded $346,590 of realized losses on oil derivatives settlements and $328,756 of unrealized gains 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 net losses account for a $0.22 per barrel decrease in the realized oil price for the three months ended June 30, 2005 from $49.78 per barrel to $49.56 per barrel. Should the crude oil prices decrease from the current levels, we would realize lower revenues from the sale of our crude oil, but our oil derivative gains would also increase. The oil derivatives could also result in larger losses if the prices begin to rise again. There was no hedge impact on natural gas revenue for the three months ended June 30, 2005.  Should natural gas prices move outside the bounds of our collars, it could materially affect our revenues. At June 30, 2004 we had an unrealized gain of $133,795, representing an increase in our realized oil price of $2.92 per barrel, which was partially offset by realized losses on expiring contracts of $103,276, representing a decrease in our realized oil price of $2.25 per barrel. For the three months ended June 30, 2004, we also recognized $186,550 of the premium paid for a natural gas hedge entered into in 2003 and realized $222,000 of losses on settlements of expiring contracts. These losses decreased the effective natural gas sales price by $0.18 per Mcf.

 

Costs and Operating Expenses

 

The table below presents a detail of our expenses for the three months ended June 30, 2005 and 2004:

 

 

 

Three Months Ended
June 30,

 

2005 Period Compared
to 2004 Period

 

 

 

 

$
Increase
(Decrease)

 

%
Increase
(Decrease)

 

 

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas operating expenses

 

$

1,802,049

 

$

1,220,092

 

$

581,957

 

48

%

Severance and ad valorem taxes

 

1,784,837

 

1,210,208

 

574,629

 

47

%

Depreciation, depletion, amortization and accretion:

 

 

 

 

 

 

 

 

 

Oil and gas property and equipment

 

8,839,703

 

5,023,148

 

3,816,555

 

76

%

Other assets

 

65,152

 

92,023

 

(26,871

)

(29

)%

ARO accretion

 

34,143

 

26,216

 

7,927

 

30

%

General and administrative:

 

 

 

 

 

 

 

 

 

Deferred compensation – repriced options

 

(90,259

)

337,386

 

(427,645

)

(127

)%

Deferred compensation – restricted stock

 

262,745

 

114,600

 

148,145

 

129

%

Other general and administrative

 

2,357,413

 

1,731,453

 

625,960

 

36

%

 

 

15,055,783

 

9,755,126

 

5,300,657

 

54

%

Other expense, net

 

11,406

 

142,130

 

(130,724

)

(92

)%

Total

 

$

15,067,189

 

$

9,897,256

 

$

5,169,933

 

52

%

 

27



 

Oil and natural gas operating expenses are the day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. For the three months ended June 30, 2005 these costs increased 48% over the same period of 2004. A substantial portion of this cost increase can be attributed to our increased production. On a Mcfe basis, costs have increased 5% from $0.42 per Mcfe for the three months ended June 30, 2004 to $0.44 per Mcfe for the three months ended June 30, 2005. The December 29, 2004 acquisition of producing properties in South Texas contributed approximately 50% of the increase in costs and new wells drilled since June 30, 2004 further increased the costs for the three months ended June 30, 2005 compared to the prior year. We are experiencing 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 associated costs. When commodity prices decline, associated costs do not necessarily decline at the same rate.

 

Severance and ad valorem taxes for the three months ended June 30, 2005 increased 47% from the same period of 2004.  Severance tax expense for the three months ended June 30, 2005 was 46% 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 June 30, 2005, severance tax expense was approximately 6.0% of revenue subject to severance taxes compared to 6.7% of revenue subject to severance taxes for the comparable 2004 period. The decrease in tax as a percent of revenue was due primarily to a shift in our revenue stream to properties with lower severance tax rates. Ad valorem tax expense for the three months ended June 30, 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 $0.41 per Mcfe for the three months ended June 30, 2005 and 2004, respectively.

 

Depletion, depreciation, and amortization (“DD&A”) represents the systematic expensing of capital costs incurred to acquire, explore and develop natural gas and crude oil, as well as maintain administrative offices to manage these activities. As a full cost company, we capitalize all costs associated with our acquisition, exploration and development efforts, and apportion these costs to each unit of production through DD&A expense. Accretion expense is the systematic accretion of future abandonment costs of our properties. For the three months ended June 30, 2005, DD&A and accretion expense totaled $8.9 million compared to $5.1 million for the same period of 2004.  Depletion on our oil and natural gas properties increased 76% for the three months ended June 30, 2005 compared to the same period of 2004 due to an increase in production levels and in the unit-of-production depletion rate from $1.72 per Mcfe for the three months ended June 30, 2004 as compared to $2.18 per Mcfe in the same period in 2005. The increase in depletion expense from the higher production levels in the three months ended June 30, 2005 as compared to the same period of 2004 resulted in an increase in expense of approximately $2.0 million. The increase in depletion rate for the three months ended June 30, 2005 compared to the same period of 2004 added approximately $1.9 million in depletion expense. Our depletion rate has increased due to increased spending on our drilling program with disproportionate reserve additions. Depreciation of furniture and fixtures for the three months ended June 30, 2005 decreased 29% compared to the same prior year period 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 June 30, 2005 increased 30% over the same prior year period for the new obligations incurred from the wells drilled and acquired since June 30, 2004.

 

G&A expense includes overhead, payroll and benefits of our corporate staff, costs of maintaining our headquarters, managing our production and development operations and legal compliance. We capitalize G&A expense directly related to our acquisition, exploration and development activities. Total G&A for the three months ended June 30, 2005 was $2.5 million, an increase of 16% compared to the same prior year period total of $2.2 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 credit of $90,259 was incurred for the three months ended June 30, 2005 compared to a charge of  $337,386 in the same period of 2004. Amortization related to restricted stock awards granted over the past three years totaled $262,745 and $114,600, respectively, for the three months ended June 30, 2005 and 2004. The increase relates to new grants that have occurred since the June 30, 2004. Other G&A for the three months ended June 30, 2005, which does not include the deferred compensation expenses discussed above, totaled $2.4 million, a 36% increase from the comparable 2004 period total of $1.7 million. The increase in other G&A was attributable to

 

28



 

higher salaries and benefits, due in part to higher staffing levels, as well as higher rent expense for additional office space, higher board of director compensation, higher franchise taxes and higher professional fees for auditors and lawyers, partially offset by reductions in fees paid to consultants for Sarbanes-Oxley implementation. For the three months ended June 30, 2005 and 2004, overhead reimbursement fees reduced G&A costs by $108,482 and $83,569, respectively. Capitalized G&A costs further reduced other G&A by $666,200 and $532,066 for the three months ended June 30, 2005 and 2004, respectively.  Other G&A on a unit of production basis for the three months ended June 30, 2005 was $0.58 per Mcfe compared to $0.59 per Mcfe for the comparable 2004 period.

 

Other income (expense) for the three months ended June 30, 2005 excludes interest expense because 100% of our interest expense for the quarter was capitalized as compared to only a portion being capitalized in the same 2004 period. We incurred higher interest costs for the three months ended June 30, 2005 than for the same period of 2004 due to commitment fees for borrowing base increases and fees on available funds that is a new charge associated with our credit facility in 2005, but we capitalized all of this interest expense as a result of our unproved property balance exceeding our debt balance.

 

 

 

For the Three Months Ended June 30,

 

 

 

2005

 

2004

 

 

 

 

 

 

 

Gross interest

 

$

256,171

 

$

228,329

 

Less: Capitalized interest

 

(256,171

)

(122,924

)

Interest expense, net

 

$

 

$

105,405

 

 

 

 

 

 

 

Weighted Average Debt

 

$

11,186,813

 

$

19,494,505

 

 

We also recorded amortization of deferred loan costs related to our amended credit facility during the three months ended June 30, 2005 and 2004, as well as interest income earned on our outstanding daily cash balances.

 

We are subject to state and federal income taxes and although we are currently generating taxable income for financial reporting purposes, we are not in a federal income tax paying position as a result of deducting intangible drilling costs (“IDC”) that reduce our taxable income for income tax purposes and NOL carryforwards that offset any remaining taxable income. A deferred income tax provision was recorded for the three months ended June 30, 2005 and 2004 of $3.9 million and $2.1 million, respectively. The increase resulted from higher pre-tax income in 2005 as compared to 2004.

 

For the three months ended June 30, 2005, we had net income of $7.2 million, or $0.42 basic earnings per share and $0.40 diluted earnings per share, as compared to net income of $3.9 million, or $0.30 basic earnings per share and $0.28 diluted earnings per share in the comparable 2004 period. Basic weighted average shares outstanding increased for the three months ended June 30, 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.

 

Six Months Ended June 30, 2005 Compared to the Six Months Ended June 30, 2004

 

Revenue and Production

 

Total revenue increased 55% from the first half of 2004 to the comparable 2005 period.  For the six months ended June 30, 2005 and 2004, our product mix contributed the following percentages of revenues and production:

 

 

 

REVENUES (1)

 

PRODUCTION

 

 

 

2005

 

2004

 

2005

 

2004

 

Natural Gas (Mcf)

 

80%

 

83%

 

76%

 

78%

 

Natural gas liquids (Bbls)

 

6%

 

6%

 

12%

 

12%

 

Crude oil (Bbl)

 

14%

 

11%

 

12%

 

10%

 

 

 

 

 

 

 

 

 

 

 

Total (Mcfe)

 

100%

 

100%

 

100%

 

100%

 

 


(1) Includes effect of hedging and derivative transactions.

 

29



 

The following table summarizes volume and price information with respect to our oil and gas production for the six-month periods ended June 30, 2005 and 2004:

 

 

 

Six Months Ended
June 30,

 

2005 Period Compared
to 2004 Period

 

 

 

 

$
Increase
(Decrease)

 

%
Increase
(Decrease)

 

 

 

2005

 

2004

 

 

 

Production Volumes:

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

6,285,166

 

4,720,044

 

1,565,122

 

33

%

Natural gas liquids (Bbls)

 

167,239

 

127,086

 

40,153

 

32

%

Oil and condensate (Bbls)

 

162,594

 

99,660

 

62,934

 

63

%

Natural gas equivalent (Mcfe)

 

8,264,164

 

6,080,520