Annual Reports

 
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  • 10-Q (Nov 9, 2009)
  • 10-Q (Aug 6, 2009)
  • 10-Q (May 7, 2009)
  • 10-Q (Nov 10, 2008)
  • 10-Q (Aug 11, 2008)
  • 10-Q (May 12, 2008)

 
8-K

 
Other

Edge Petroleum 10-Q 2009

Documents found in this filing:

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

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-Q

 

(MARK ONE)

 

x

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

 

For the quarterly period ended March 31, 2009

 

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. xYes ¨ No

 

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

 

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

 

¨ Large accelerated filer

 

x Accelerated filer

 

 

 

¨ Non-accelerated filer

 

¨ Smaller reporting company

(Do not check if a smaller reporting company)

 

 

 

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

 

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

 

Class

 

Outstanding at May 6, 2009

Common Stock

 

28,867,096

 

 

 



Table of Contents

 

EDGE PETROLEUM CORPORATION

 

Table of Contents

 

 

 

Page No.

Part I. Financial Information

 

 

Item 1. Financial Statements (Unaudited):

 

 

Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008

 

3

Consolidated Statements of Operations for the Three Months Ended March 31, 2009 and 2008

 

4

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2009 and 2008

 

5

Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2009

 

6

Notes to the Consolidated Financial Statements

 

7

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

 

25

Item 3. Qualitative and Quantitative Disclosures About Market Risk

 

50

Item 4. Controls and Procedures

 

51

Part II. Other Information

 

52

Item 1. Legal Proceedings

 

52

Item 1A. Risk Factors

 

53

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

 

53

Item 3. Defaults Upon Senior Securities

 

53

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

 

53

Item 5. Other Information

 

53

Item 6. Exhibits

 

53

Signatures

 

59

 

2



Table of Contents

 

PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

EDGE PETROLEUM CORPORATION

 

CONSOLIDATED BALANCE SHEETS

 

 

 

March 31,

 

December 31,

 

 

 

2009

 

2008

 

 

 

(Unaudited)

 

 

 

 

 

(in thousands, except share data)

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

$

9,901

 

$

8,475

 

Accounts receivable, trade, net of allowance

 

10,343

 

14,548

 

Accounts receivable, joint interest owners and other, net of allowance

 

3,400

 

5,689

 

Derivative financial instruments

 

20,627

 

15,407

 

Other current assets

 

4,800

 

4,591

 

 

 

 

 

 

 

Total current assets

 

49,071

 

48,710

 

 

 

 

 

 

 

PROPERTY AND EQUIPMENT, Net — full cost method of accounting for oil and natural gas properties (including unevaluated costs of $19.0 million and $16.4 million at March 31, 2009 and December 31, 2008, respectively)

 

221,918

 

307,059

 

 

 

 

 

 

 

OTHER ASSETS

 

1,153

 

1,828

 

 

 

 

 

 

 

TOTAL ASSETS

 

$

272,142

 

$

357,597

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable, trade

 

$

1,803

 

$

3,086

 

Accrued liabilities

 

6,715

 

8,779

 

Accrued interest payable

 

13

 

579

 

Current portion of debt

 

234,000

 

239,000

 

Asset retirement obligation

 

550

 

547

 

 

 

 

 

 

 

Total current liabilities

 

243,081

 

251,991

 

 

 

 

 

 

 

ASSET RETIREMENT OBLIGATION — long-term

 

6,103

 

6,011

 

 

 

 

 

 

 

OTHER NON-CURRENT LIABILITIES

 

102

 

102

 

 

 

 

 

 

 

DELIVERY COMMITMENT

 

2,005

 

2,005

 

 

 

 

 

 

 

Total liabilities

 

251,291

 

260,109

 

 

 

 

 

 

 

COMMITMENTS AND CONTINGENCIES (Note 12)

 

 

 

 

 

 

 

 

 

 

 

STOCKHOLDERS’ EQUITY

 

 

 

 

 

Preferred stock, $0.01 par value; 5,000,000 shares authorized; 2,875,000 issued and outstanding at March 31, 2009 and December 31, 2008

 

29

 

29

 

Common stock, $0.01 par value; 60,000,000 shares authorized; 28,866,328, and 28,833,546 shares issued and outstanding at March 31, 2009 and December 31, 2008, respectively

 

289

 

288

 

Additional paid-in capital

 

424,253

 

423,951

 

Retained deficit

 

(403,720

)

(326,780

)

 

 

 

 

 

 

Total stockholders’ equity

 

20,851

 

97,488

 

 

 

 

 

 

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

 

$

272,142

 

$

357,597

 

 

See accompanying notes to consolidated financial statements.

 

3



Table of Contents

 

EDGE PETROLEUM CORPORATION

 

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

 

 

 

Three Months Ended 
March 31,

 

 

 

2009

 

2008

 

 

 

(in thousands,
except per share amounts)

 

OIL AND NATURAL GAS REVENUE:

 

 

 

 

 

Oil and natural gas sales

 

$

12,998

 

$

47,016

 

Gain (loss) on derivatives

 

11,068

 

(29,359

)

Total revenue

 

24,066

 

17,657

 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

Oil and natural gas operating expenses

 

3,825

 

4,472

 

Severance and ad valorem taxes

 

1,091

 

2,185

 

Depletion, depreciation, amortization and accretion

 

10,079

 

27,371

 

Impairment of oil and natural gas properties

 

78,254

 

 

General and administrative expenses

 

4,595

 

4,060

 

 

 

 

 

 

 

Total operating expenses

 

97,844

 

38,088

 

 

 

 

 

 

 

OPERATING LOSS

 

(73,778

)

(20,431

)

 

 

 

 

 

 

OTHER INCOME AND EXPENSE:

 

 

 

 

 

 

 

 

 

 

 

Other income

 

7

 

69

 

Interest expense, net of amounts capitalized

 

(2,243

)

(4,224

)

Amortization of deferred loan costs

 

(926

)

(239

)

 

 

 

 

 

 

LOSS BEFORE INCOME TAXES

 

(76,940

)

(24,825

)

 

 

 

 

 

 

INCOME TAX BENEFIT

 

 

8,646

 

 

 

 

 

 

 

NET LOSS

 

(76,940

)

(16,179

)

 

 

 

 

 

 

Preferred Stock Dividends

 

 

(2,066

)

 

 

 

 

 

 

NET LOSS TO COMMON STOCKHOLDERS

 

$

(76,940

)

$

(18,245

)

 

 

 

 

 

 

BASIC LOSS PER SHARE

 

$

(2.74

)

$

(0.64

)

 

 

 

 

 

 

DILUTED LOSS PER SHARE

 

$

(2.74

)

$

(0.64

)

 

 

 

 

 

 

BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING

 

28,840

 

28,566

 

 

 

 

 

 

 

DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING

 

28,840

 

28,566

 

 

See accompanying notes to consolidated financial statements.

 

4



Table of Contents

 

EDGE PETROLEUM CORPORATION

 

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

 

 

 

Three Months Ended March 31,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net loss

 

$

(76,940

)

$

(16,179

)

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

 

 

 

 

 

Unrealized loss (gain) on the fair value of derivatives

 

(5,220

)

25,360

 

Deferred income taxes

 

 

(9,227

)

Depletion, depreciation, amortization and accretion

 

10,079

 

27,371

 

Impairment of oil and natural gas properties

 

78,254

 

 

Gain on ARO settlement

 

 

(9

)

Amortization of deferred loan costs

 

926

 

239

 

Share-based compensation costs

 

303

 

907

 

Changes in assets and liabilities:

 

 

 

 

 

Decrease (increase) in accounts receivable, trade

 

4,205

 

(1,933

)

Decrease in accounts receivable, joint interest owners

 

2,289

 

4,746

 

Increase in other assets

 

(149

)

(425

)

Decrease in accounts payable, trade

 

(1,283

)

(4,475

)

Decrease in accrued liabilities

 

(2,065

)

(5,226

)

Increase (decrease) in accrued interest payable

 

(566

)

201

 

 

 

 

 

 

 

Net cash provided by operating activities

 

9,833

 

21,350

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Oil and natural gas property and equipment additions

 

(3,097

)

(22,190

)

(Increase) decrease in drilling advances

 

(310

)

641

 

Proceeds from the sale of oil and natural gas properties

 

 

12,248

 

Overhedged derivative settlements

 

 

(1,691

)

 

 

 

 

 

 

Net cash used in investing activities

 

(3,407

)

(10,992

)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Repayments of debt

 

(5,000

)

(10,000

)

Preferred stock dividends paid

 

 

(2,066

)

 

 

 

 

 

 

Net cash used in financing activities

 

(5,000

)

(12,066

)

 

 

 

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

1,426

 

(1,708

)

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

 

8,475

 

7,163

 

 

 

 

 

 

 

CASH AND CASH EQUIVALENTS, END OF PERIOD

 

$

9,901

 

$

5,455

 

 

See accompanying notes to consolidated financial statements.

 

5



Table of Contents

 

EDGE PETROLEUM CORPORATION

 

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

 

 

 

 

 

 

 

 

 

 

 

Additional

 

 

 

Total

 

 

 

Preferred Stock

 

Common Stock

 

Paid-In

 

Retained

 

Stockholders’

 

 

 

Shares

 

Amount

 

Shares

 

Amount

 

Capital

 

Deficit

 

Equity

 

 

 

(in thousands)

 

BALANCE, DECEMBER 31, 2008

 

2,875

 

$

29

 

28,833

 

$

288

 

$

423,951

 

$

(326,780

)

$

97,488

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issuance of common stock

 

 

 

33

 

1

 

(1

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Share-based compensation costs

 

 

 

 

 

303

 

 

303

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

 

 

 

 

 

(76,940

)

(76,940

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

BALANCE, MARCH 31, 2009

 

2,875

 

$

29

 

28,866

 

$

289

 

$

424,253

 

$

(403,720

)

$

20,851

 

 

See accompanying notes to consolidated financial statements.

 

6



Table of Contents

 

EDGE PETROLEUM CORPORATION

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

1.     ORGANIZATION AND BASIS FOR PRESENTATION

 

The financial statements included herein have been prepared by Edge Petroleum Corporation, a Delaware corporation (“we”, “our”, “us” or the “Company”), without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and reflect all adjustments which are, in the opinion of management, necessary to present a fair statement of the results for the interim periods on a basis consistent with the annual audited consolidated financial statements.  All such adjustments are of a normal recurring nature, except for the impairment of the Company’s oil and natural gas properties, as discussed below.  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, 2008.

 

2.     RECENT DEVELOPMENTS

 

Financial and Strategic Alternatives Process - In late 2007, the Company announced the hiring of a financial advisor to assist its Board of Directors with an assessment of strategic alternatives. The credit crisis and related turmoil in the global financial system and economic recession in the U.S. during the fourth quarter of 2008, along with declines in commodity prices and our stock prices, created a challenging environment for the successful completion of our proposed merger with Chaparral Energy, Inc. (“Chaparral”), a privately held company. On December 17, 2008, the Company announced the termination of the Chaparral merger agreement after both the Company and Chaparral determined it was highly unlikely that the conditions to the closing of the proposed merger would be satisfied or that Chaparral would be able to obtain sufficient debt and equity financing to allow them to complete the proposed merger and operate as a combined company, particularly in light of the challenging environment in the financial markets and the energy industry. The Company continues to pursue and review its financial and strategic alternatives as it seeks to resolve the many challenges it currently faces.

 

Going Concern —  In addition to the Deficiency under our Revolving Facility (defined in Note 4) created by the January borrowing base redetermination (see discussion in Note 4), the capital expenditures required to maintain and/or grow production and reserves are substantial. Prices for oil and natural gas declined materially during the fourth quarter of 2008, and natural gas prices continued to decline during the first quarter of 2009.  A continued or extended decline in oil or natural gas prices will have a material adverse effect on the Company’s financial position, results of operations, cash flows and access to capital and on the quantities of oil and natural gas reserves that the Company can economically produce. The Company’s stock price has significantly declined over the past year which also makes it more difficult to obtain equity financing on acceptable terms to address the Company’s liquidity issues. In addition, the Company is reporting negative working capital at March 31, 2009 and continued to report net losses in the three months ended March 31, 2009, following three consecutive years of net losses.  Therefore, there is substantial doubt as to the Company’s ability to continue as a going concern for a period longer than the next twelve months. Additionally, our independent auditors included an explanatory paragraph in their report on our consolidated financial statements in our Form 10-K for the year ended December 31, 2008 that raises substantial doubt about our ability to continue as a going concern. The Company’s ability to continue as a going concern is dependent upon the success of its financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Until the possible completion of the financial and strategic alternatives process, the Company’s future remains uncertain and there can be no assurance that its efforts in this regard will be successful.

 

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Table of Contents

 

The accompanying consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies that the Company will continue to meet its obligations and continue its operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and these consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of this uncertainty.

 

3.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

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 natural gas industry.  There are two allowable methods of accounting for oil and natural 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 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, which constitutes one cost center. The Company also capitalizes a portion of interest expense on borrowed funds.

 

In the measurement of impairment of oil and natural gas properties, the successful-efforts method 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 the “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, prior impairments, and related tax effects) 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.  A ceiling test impairment could result in a significant loss for a reporting period; however, future depletion expense would be correspondingly reduced. Impairment of oil and natural gas properties is assessed on a quarterly basis in conjunction with the Company’s quarterly and annual SEC filings. The Company recorded a net non-cash ceiling test impairment of $78.3 million during the quarter ended March 31, 2009 as a result of further declines in commodity prices since December 31, 2008. No ceiling test impairment was required during the quarter ended March 31, 2008.

 

In accordance with SEC Staff Accounting Bulletin (“SAB”) No. 103, Update of Codification of Staff Accounting Bulletins, derivative instruments qualifying as cash flow hedges are to be included in the computation of limitation on capitalized costs.  Since January 1, 2006, the Company has not applied cash flow hedge accounting to any derivative contracts (see Note 10), therefore the ceiling tests at March 31, 2009 and 2008 were not impacted by the value of our derivatives.

 

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 (“NGL”) are converted to a gas equivalent basis (“Mcfe”) at the rate of one barrel equals six Mcf. In accordance with 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. 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, 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. Costs excluded from amortization related to

 

8



Table of Contents

 

unproved properties were $19.0 million and $16.4 million at March 31, 2009 and December 31, 2008, respectively.

 

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.

 

Accounts Receivable and Allowance for Doubtful Accounts - The Company routinely assesses the recoverability of all material trade and other receivables to determine its ability to collect the receivables in full. Accounts Receivable, Joint Interest Owners included an allowance for doubtful accounts of $15,300 at March 31, 2009 and December 31, 2008, respectively. Accounts Receivable, Trade included an allowance for doubtful accounts of $64,500 at March 31, 2009 and December 31, 2008, respectively.

 

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 and are included in Other Current Assets on the consolidated balance sheet.

 

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. Under SFAS No. 143, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural 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. The changes to the Asset Retirement Obligations (“ARO”) for oil and natural gas properties and related equipment during the three months ended March 31, 2009 and 2008 are as follows:

 

 

 

Three Months Ended March 31,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

ARO, Beginning of Period

 

$

6,558

 

$

6,634

 

Liabilities incurred in the current period

 

11

 

406

 

Liabilities settled/sold in the current period

 

(2

)

(1,098

)

Accretion expense

 

99

 

90

 

Revisions

 

(13

)

 

ARO, End of Period

 

$

6,653

 

$

6,032

 

 

 

 

 

 

 

Current Portion

 

$

550

 

$

432

 

Long-Term Portion

 

$

6,103

 

$

5,600

 

 

During the three months ended March 31, 2009, ARO liabilities were recorded for two new obligations and liabilities settled include two properties. Revisions resulted from a change in working interest on a property located in Texas.

 

Revenue Recognition and Gas Balancing - The Company recognizes oil and natural gas revenue from its interests in producing wells as oil and natural gas is produced and sold from those wells. Oil and natural gas sold by the Company is typically not significantly different from the Company’s share of production. But gas imbalances can occur when sales are more or less than the Company’s entitled ownership percentage of total gas production. Gas imbalances may be accounted for under either the (1) entitlements method, whereby revenue is recorded on the Company’s interest in the gas production actually sold or (2) sales method, whereby revenue is recorded on the basis of total gas actually sold by the Company. The Company uses the sales method of accounting for gas balancing and an asset or a liability is recognized to the extent that there is a material imbalance in excess of the remaining gas reserves on the underlying properties.  As of March 31, 2009 and December 31, 2008, our gas production was materially in balance, i.e. our cumulative portion of gas production

 

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Table of Contents

 

taken and sold from wells in which we have an interest was not materially different from our entitled interest in gas production from those wells.

 

Share-Based Compensation — The Company accounts for share-based compensation in accordance with the provisions of SFAS No. 123R, Share-Based Payment, which requires that the compensation cost relating to share-based payment transactions be recognized in financial statements. Share-based compensation for the three months ended March 31, 2009 was approximately $0.3 million, of which $0.2 million was included in general and administrative expenses (“G&A”) and $0.1 million was capitalized to oil and natural gas properties. Share-based compensation for the three months ended March 31, 2008 was approximately $0.8 million, of which $0.7 million was included in general and administrative expenses (“G&A”) and $0.1 million was capitalized to oil and natural gas properties.

 

During the three months ended March 31, 2009, no restricted stock units (“RSUs”) were granted. At March 31, 2009, there were 246,164 RSUs outstanding, all of which were classified as equity instruments.  No options were granted during the three months ended March 31, 2009, and at period end, there were 443,600 vested unexercised options outstanding.

 

Income Taxes - Effective January 1, 2007, the Company adopted FASB Interpretation No. 48 Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement No. 109) (“FIN 48”).  This interpretation clarified the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return.  FIN 48 also provides guidance on de-recognitions, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company also adopted FASB Staff Position (“FSP”) FIN 48-1, Definition of Settlement in FASB Interpretation No. 48 as of January 1, 2007.  FSP FIN 48-1 provides that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future (see Note 8).

 

Other Comprehensive Income (Loss) — For the periods presented, total comprehensive income (loss) consisted of:

 

 

 

Three Months Ended March 31,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

 

 

 

 

 

 

Net Loss

 

$

(76,940

)

$

(16,179

)

Preferred Stock Dividends

 

 

(2,066

)

Net Loss to Common Stockholders

 

(76,940

)

(18,245

)

 

 

 

 

 

 

Other Comprehensive Income (Loss), net of tax

 

 

 

 

 

 

 

 

 

Other Comprehensive Loss

 

$

(76,940

)

$

(18,245

)

 

 

Fair Value Measurements — Effective January 1, 2008, the Company partially adopted SFAS No. 157, Fair Value Measurements, which provides a common definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements, but does not require any new fair value measurements. On January 1, 2009 the Company adopted SFAS No. 157 for the non-financial assets and non-financial liabilities that were delayed in adoption by FSP FAS 157-2, Effective Date of FASB Statement No. 157. Accordingly, the Company has now applied the provisions of SFAS No. 157 to its AROs. The adoption of SFAS No. 157 had no impact on the Company’s financial statements, but it did result in additional required disclosures as set forth in Note 11.

 

Recent Accounting Pronouncements — In December 2008, the SEC issued the final rule, “Modernization of Oil and Gas Reporting,” which adopts revisions to the SEC’s oil and natural gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. Early adoption of the new rules is prohibited. The new rules are intended to provide

 

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investors with a more meaningful and comprehensive understanding of oil and natural gas reserves to help investors evaluate their investments in oil and natural gas companies. The new rules are also designed to modernize the oil and natural gas disclosure requirements to align them with current practices and changes in technology. The new rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves and permitting disclosure of probable and possible reserves. The Company is currently evaluating the potential impact of these rules. The SEC is discussing the rules with the FASB staff to align FASB accounting standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, the Company will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009.

 

In April 2009, the FASB issued FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, which provides additional guidance in accordance with SFAS No. 157. If an entity determines that either the volume or level of activity for an asset or liability has significantly decreased from normal conditions, or that price quotations or observable inputs are not associated with orderly transactions, increased analysis and management judgment will be required to estimate fair value. The objective in fair value measurement remains unchanged from what is prescribed in SFAS No. 157 and should be reflective of the current exit price. Disclosures in interim and annual periods must include inputs and valuation techniques used to measure fair value, along with any changes in valuation techniques and related inputs during the period. In addition, disclosures for debt and equity securities must be provided on a more disaggregated basis than what was required in SFAS No. 157. FSP FAS 157-4 is effective for interim and annual reporting periods ending after June 15, 2009. The Company does not expect FSP FAS 157-4 to have a material impact on its financial position, results of operations or cash flows.

 

In April 2009, the FASB issued FSP FAS 107-1 and Accounting Principles Bulletin (“APB”) No. 28-1, Interim Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments for publicly traded companies for both interim and annual periods. Historically, these disclosures were only required annually. The interim disclosures are intended to provide financial statement users with more timely and transparent information about the effects of current market conditions on an entity’s financial instruments that are not otherwise reported at fair value. FSP FAS 107-1 and APB 28-1 is effective for interim reporting periods ending after June 15, 2009. Comparative disclosures are only required for periods ending after the initial adoption. The Company does not expect FSP FAS 107-1 and APB 28-1 to have a material impact on its financial position, results of operations or cash flows.

 

In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments, which amends the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. FSP FAS 115-2 and FAS 124-2 does not amend existing recognition and measurement guidance for equity securities, but does establish a new method of recognizing and reporting for debt securities. Disclosure requirements for impaired debt and equity securities have been expanded significantly and will now be required quarterly, as well as annually. FSP FAS 115-2 and FAS 124-2 is effective for interim and annual reporting periods ending after June 15, 2009. Comparative disclosures are only required for periods ending after the initial adoption. The Company does not expect FSP FAS 115-2 and FAS 124-2 to have a material impact on its financial position, results of operations or cash flows.

 

In April 2009 the FASB issued FSP FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a s Business Combination That Arise from Contingencies, which amends and clarifies SFAS No. 141, Business Combinations, (as amended), to address application issues raised by preparers, auditors, and members of the legal profession on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. FSP FAS 141(R)-1 is effective for assets and liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first fiscal reporting period beginning on or after December 15, 2008. The Company expects FSP FAS 141(R)-1 may impact its financial position, results of operations or cash flows if it were to undertake a business combination.

 

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4.              DEBT

 

On January 30, 2007, the Company entered into a Fourth Amended and Restated Credit Agreement (as amended, the “Revolving Facility”) for a new revolving credit facility with Union Bank of California (“UBOC”), as administrative agent and issuing lender, and the other lenders party thereto (together with UBOC, the “Lenders”). Pursuant to the Revolving Facility, UBOC acts as the administrative agent for a senior first lien secured borrowing base revolving credit facility in favor of the Company and certain of its wholly-owned subsidiaries in an amount equal to $750 million, of which $320 million was available under the borrowing base at the time of closing (see below for discussion of current availability).  The Revolving Facility has a letter of credit sub-limit of $20 million. The Revolving Facility’s original maturity was scheduled for January 31, 2011.

 

At March 31, 2009, borrowings under the Revolving Facility bore interest at Prime plus a margin of 2.5%. At March 31, 2009, the interest rate applied to the Company’s outstanding borrowings was 5.75%.  As of March 31, 2009, $234 million in total borrowings were outstanding under the Revolving Facility.

 

As a result of the redetermination process of the borrowing base by the Lenders under the Revolving Facility, which was completed in January 2009, the Lenders established a new borrowing base under the Revolving Facility of $125 million, resulting in a $114 million deficiency (the “Deficiency”).  These reductions were primarily the result of the sale of certain non-core assets during the first quarter of 2008 and the reduction of total proved reserves as reported in the year-end reserve reports of the Company’s independent reserve engineers.

 

Pursuant to the terms of the Revolving Facility, the Company elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due on February 9, 2009.  On February 9, 2009, the Company entered into a Consent and Agreement (the “February Consent”) among the Company and the Lenders under the Revolving Facility deferring the payment date of the first $19 million installment until March 10, 2009, and extending the due date for each subsequent installment by one month with the last of the six installment payments to be due on August 10, 2009.  In connection with the February Consent, the Company agreed to prepay $5.0 million of the Company’s outstanding advances under the Revolving Facility, in two equal installments.  The first $2.5 million prepayment was paid on February 9, 2009 and the second $2.5 million prepayment was paid on February 23, 2009, with each of the prepayments to be applied on a pro rata basis to reduce the remaining six $19 million deficiency payments.  On March 10, 2009, the Company entered into a Consent and Agreement (the “March Consent”) with the Lenders under the Revolving Facility, which provided, among other things, for the extension of the due date for the first installment to repay the Deficiency from March 10, 2009 to March 17, 2009. Notwithstanding such extension, the Company agreed with the Lenders that each of the other five equal installment payments required to eliminate the Deficiency would be due and payable as provided for in the February Consent. On March 16, 2009, the Company entered into Consent and Amendment No. 4 (the “Amended Consent”) which provides, among other things, (1) that the Company will make a $25 million payment on May 31, 2009 with all remaining principal, fees and interest amounts under the Revolving Facility to be due and payable on June 30, 2009, (2) that it will be an event of default (i) if the Company fails to have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a lender or group of lenders reasonably satisfactory to the Lenders providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, (b) a merger agreement or similar agreement involving us as part of a transaction that results in the repayment of the Company’s obligations under the Revolving Facility on or before June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to our Lenders providing for a sale transaction by us that results in the repayment of all of the Company’s obligations under the Revolving Facility on or before June 30, 2009, or (ii) if the Company is in default under or its hedging arrangements have been terminated or cease to be effective without the prior written consent of its Lenders, (3) that the Company’s advances under the Revolving Facility will bear interest at a rate equal to the greater of (a) the reference rate publicly announced by Union Bank of California, N.A. for such day, (b) the Federal Funds Rate in effect on such day plus 0.50% and (c) a rate determined by the Administrative Agent to be the Daily One-Month LIBOR (as defined in the Revolving Facility), in each case plus 2.5% or, during the continuation of an event of default, plus 4.5% (resulting in an effective interest rate of approximately 5.75% as of May 7, 2009), (4) for limitations on the making of capital

 

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expenditures and certain investments, and (5) for the elimination of the current ratio, leverage ratio and interest coverage ratio covenant requirements. The Amended Consent also eliminates the six $19 million deficiency payments which were contemplated by the February Consent and the March Consent. To comply with the terms of the Amended Consent, the Company anticipates that it will need to (i) sell select individual assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or (ii) negotiate a commitment letter with a new lender or group of lenders prior to May 15, 2009 in an amount sufficient to repay all of the Company’s obligations under the Revolving Facility on or before June 30, 2009, and/or (iii) have negotiated the sale, merger or other business combination involving us which results in the repayment of all of the Company’s obligations under the Revolving Facility prior to May 15, 2009 and to have closed such transaction on or before June 30, 2009. The Amended Consent limits the making of capital expenditures and the Company anticipates a severe curtailment of its drilling plans and other capital expenditures in 2009.

 

If the Company breaches any of the provisions of the Amended Consent or Revolving Facility, its Lenders will be entitled to declare an event of default, at which point the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable.  In any event, the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to the Lenders, will be payable on June 30, 2009 unless earlier paid or a further extension with respect to payment is negotiated with the Lenders. The Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because substantially all of the Company’s assets are pledged as collateral under the Revolving Facility, if the Lenders declare an event of default, they would be entitled to foreclose on and take possession of the Company’s assets.  In such an event, the Company may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related to the Company’s liquidity and financial position raise substantial doubt as to our ability to continue as a going concern (see Note 2). With respect to the Company’s compliance with the Amended Consent, there can be no assurance that the Company will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that it will be able to either make any required payments when they become due. Moreover, there can be no assurance that the Company will be successful in its efforts to comply with the terms of the Amended Consent, including its ongoing efforts to evaluate and assess our various financial and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company).  If such efforts are not successful, the Company may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

 

The Company’s obligations under the Revolving Facility are secured by substantially all of the Company’s assets. The Revolving 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 Revolving Facility restricts dividends on common stock and certain distributions of cash or properties and certain liens but no longer contains any financial covenants as a result of the Amended Consent.

 

The Revolving Facility includes certain other covenants and events of default that are customary for similar facilities. It is an event of default under the Revolving Facility if the Company undergoes a change of control.  “Change of control,” as defined in the Revolving Facility, means any of the following events: (a) any “person” or “group” (within the meaning of Section 13(d) or 14(d) of the Exchange Act) has become, directly or indirectly, the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that a person shall be deemed to have “beneficial ownership” of all such shares that any such person has the right to acquire, whether such right is exercisable immediately or only after the passage of time, by way of merger, consolidation or otherwise), of a majority or more of the common stock of the Company on a fully-diluted basis, after giving effect to the conversion and exercise of all outstanding warrants, options and other securities of the Company (whether or not such securities are then currently convertible or exercisable), (b) during any period of two consecutive calendar quarters, individuals who at the beginning of such period were members of the Company’s Board of Directors cease for any reason to constitute a majority of the directors then in office unless (i) such new directors were elected by a majority of the directors of the Company who constituted the Board of Directors at the beginning of such period (or by directors so elected) or (ii) the reason for such

 

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directors failing to constitute a majority is a result of retirement by directors due to age, death or disability, or (c) the Company ceases to own directly or indirectly all of the equity interests of each of its subsidiaries.

 

5.   SHELF REGISTRATION STATEMENT

 

In the third quarter 2007, the SEC declared effective the Company’s registration statement filed with the SEC that registered securities of up to $500 million of any combination of debt securities, preferred stock, common stock, warrants for debt securities or equity securities of the Company and guarantees of debt securities by the Company’s subsidiaries. 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 for debt securities or equity securities will depend upon, among other things, market conditions and the existence of investors who wish to purchase the Company’s securities at prices acceptable to the Company.  As of May 7, 2009, the Company had $500 million available under its shelf registration statement. However, because the aggregate market value of the Company’s outstanding common stock is less than $75 million, the type and amount of any securities offering under the registration statement may be limited.

 

6.   PREFERRED STOCK

 

In January 2007, 2,875,000 shares of its 5.75% Series A cumulative convertible perpetual preferred stock (“Convertible Preferred Stock”) were issued in a public offering.

 

Dividends.  The Convertible Preferred Stock accumulates dividends at a rate of $2.875 for each share of Convertible Preferred Stock per year. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by the Company’s debt agreements, assets are legally available to pay dividends and the Board of Directors or an authorized committee of the board declares a dividend payable, the Company will pay dividends in cash, every quarter. The first payment was made on April 15, 2007 and the Company continued to make quarterly dividends payments through October 15, 2008. The Board did not declare a dividend in the fourth quarter of 2008 or first quarter of 2009 due to the Company’s current reduced liquidity. Cumulative dividends in arrears at March 31, 2009 amounted to approximately $3.8 million.

 

No dividends or other distributions (other than a dividend payable solely in shares of a like or junior ranking) may be paid or set apart for payment upon any shares ranking equally with the Convertible Preferred Stock (“parity shares”) or shares ranking junior to the Convertible Preferred Stock (“junior shares”), nor may any parity shares or junior shares be redeemed or acquired for any consideration by the Company (except by conversion into or exchange for shares of a like or junior ranking) unless all accumulated and unpaid dividends have been paid or funds therefor have been set apart on the Convertible Preferred Stock and any parity shares.

 

Liquidation preference.  In the event of the Company’s voluntary or involuntary liquidation, winding-up or dissolution, each holder of Convertible Preferred Stock will be entitled to receive and to be paid out of the Company’s assets available for distribution to our stockholders, before any payment or distribution is made to holders of junior stock (including common stock), but after any distribution on any of our indebtedness or senior stock, a liquidation preference in the amount of $50.00 per share of the Convertible Preferred Stock, plus accumulated and unpaid dividends on the shares to the date fixed for liquidation, winding-up or dissolution.

 

Ranking.  Our Convertible Preferred Stock ranks:

 

·                  senior to all of the shares of common stock and to all of the Company’s other capital stock issued in the future unless the terms of such capital stock expressly provide that it ranks senior to, or on a parity with, shares of the Convertible Preferred Stock;

 

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·                  on a parity with all of the Company’s other capital stock issued in the future, the terms of which expressly provide that it will rank on a parity with the shares of the Convertible Preferred Stock; and

 

·                  junior to all of the Company’s existing and future debt obligations and to all shares of its capital stock issued in the future, the terms of which expressly provide that such shares will rank senior to the shares of the Convertible Preferred Stock.

 

Mandatory conversion. On or after January 20, 2010, the Company may, at its option, cause shares of its Convertible Preferred Stock to be automatically converted to shares of common stock of the Company at the applicable conversion rate, but only if the closing sale price of its common stock for 20 trading days within a period of 30 consecutive trading days ending on the trading day immediately preceding the date the Company gives the conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day.

 

Optional redemption. If fewer than 15% of the shares of Convertible Preferred Stock issued in the Convertible Preferred Stock offering (including any additional shares issued pursuant to the underwriters’ over-allotment option) are outstanding, the Company may, at any time on or after January 20, 2010, at its option, redeem for cash all such Convertible Preferred Stock at a redemption price equal to the liquidation preference of $50.00 plus any accrued and unpaid dividends, if any, on a share of Convertible Preferred Stock to, but excluding, the redemption date, for each share of Convertible Preferred Stock.

 

Conversion rights. Each share of Convertible Preferred Stock may be converted at any time, at the option of the holder, into approximately 3.0193 shares of the Company’s common stock (which is based on an initial conversion price of $16.56 per share of common stock, subject to adjustment) plus cash in lieu of fractional shares, subject to the Company’s right to settle all or a portion of any such conversion in cash or shares of its common stock. If the Company elects to settle all or any portion of its conversion obligation in cash, the conversion value and the number of shares of its common stock the Company will deliver upon conversion (if any) will be based upon a 20 trading day averaging period.

 

Upon any conversion, the holder will not receive any cash payment representing accumulated and unpaid dividends on the Convertible Preferred Stock, whether or not in arrears, except in limited circumstances. The conversion rate is equal to $50.00 divided by the conversion price at the time. The conversion price is subject to adjustment upon the occurrence of certain events. The conversion price on the conversion date and the number of shares of the Company’s common stock, as applicable, to be delivered upon conversion may be adjusted if certain events occur.

 

Purchase upon fundamental change. If the Company becomes subject to a fundamental change (as defined below), each holder of shares of Convertible Preferred Stock will have the right to require the Company to purchase any or all of its shares at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends, to the date of the purchase. The Company will have the option to pay the purchase price in cash, shares of common stock or a combination of cash and shares. The Company’s ability to purchase all or a portion of the Convertible Preferred Stock for cash is subject to its obligation to repay or repurchase any outstanding debt required to be repaid or repurchased in connection with a fundamental change and to any contractual restrictions then contained in our debt.

 

Conversion in connection with a fundamental change. If a holder elects to convert its shares of the Convertible Preferred Stock in connection with certain fundamental changes, the Company will in certain circumstances increase the conversion rate for such Convertible Preferred Stock. Upon a conversion in connection with a fundamental change, the holder will be entitled to receive a cash payment for all accumulated and unpaid dividends.

 

A “fundamental change” will be deemed to have occurred upon the occurrence of any of the following:

 

1. a “person” or “group” subject to specified exceptions, discloses that the person or group has become the direct or indirect ultimate “beneficial owner” of the Company’s common equity representing more than 50% of the voting power of its common equity other than a filing with a disclosure relating to a transaction which complies with the proviso in subsection 2 below;

 

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2. consummation of any share exchange, consolidation or merger of the Company pursuant to which its common stock will be converted into cash, securities or other property or any sale, lease or other transfer in one transaction or a series of transactions of all or substantially all of the consolidated assets of the Company and its subsidiaries, taken as a whole, to any person other than one of its subsidiaries; provided, however, that a transaction where the holders of more than 50% of all classes of its common equity immediately prior to the transaction own, directly or indirectly, more than 50% of all classes of common equity of the continuing or surviving corporation or transferee immediately after the event shall not be a fundamental change;

 

3. the Company is liquidated or dissolved or holders of its capital stock approve any plan or proposal for its liquidation or dissolution; or

 

4. the Company’s common stock is neither listed on a national securities exchange nor listed nor approved for quotation on an over-the-counter market in the United States.

 

However, a fundamental change will not be deemed to have occurred in the case of a share exchange, merger or consolidation, or in an exchange offer having the result described in subsection 1 above, if 90% or more of the consideration in the aggregate paid for common stock (and excluding cash payments for fractional shares and cash payments pursuant to dissenters’ appraisal rights) in the share exchange, merger or consolidation or exchange offer consists of common stock of a United States company traded on a national securities exchange (or which will be so traded or quoted when issued or exchanged in connection with such transaction).

 

Voting rights. If the Company fails to pay dividends for six quarterly dividend periods (whether or not consecutive) or if the company fails to pay the purchase price on the purchase date for the Convertible Preferred Stock following a fundamental change, holders of the Convertible Preferred Stock will have voting rights to elect two directors to the board.

 

In addition, the Company may generally not, without the approval of the holders of at least 66 2/3% of the shares of the Convertible Preferred Stock then outstanding:

 

·                  amend the restated certificate of incorporation, as amended, by merger or otherwise, if the amendment would alter or change the powers, preferences, privileges or rights of the holders of shares of the Convertible Preferred Stock so as to adversely affect them;

 

·                  issue, authorize or increase the authorized amount of, or issue or authorize any obligation or security convertible into or evidencing a right to purchase, any senior stock; or

 

·                  reclassify any of its authorized stock into any senior stock of any class, or any obligation or security convertible into or evidencing a right to purchase any senior stock.

 

7.   EARNINGS (LOSS) PER SHARE

 

The Company accounts for earnings (loss) 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 statement of operations.  Basic EPS amounts are calculated using the weighted average number of common shares outstanding during each period.  Diluted EPS assumes the exercise of all stock options, warrants and convertible securities having exercise prices less than the average market price of the common stock during the periods, using the treasury stock method. When a loss from continuing operations exists, as in the periods presented, potential common shares are excluded in the computation of diluted EPS because their inclusion would result in an anti-dilutive effect on per share amounts.

 

Diluted EPS also includes the effect of convertible securities by application of the “if-converted” method.  Under this method, if an entity has convertible preferred stock outstanding, the preferred dividends applicable to the convertible preferred stock are added back to the numerator.  The convertible preferred stock is assumed to have been converted at the beginning of the period (or at time of issuance, if later) and the resulting common

 

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shares are included in the denominator of the EPS calculation.  In applying the if-converted method, conversion is not assumed for purposes of computing diluted EPS if the effect would be anti-dilutive. During 2009 and 2008, conversion of the 5.75% Series A cumulative convertible preferred stock is not assumed because the effect would be anti-dilutive. The following tables present the computations of EPS for the periods indicated.

 

 

 

Three Months Ended March 31, 2009

 

Three Months Ended March 31, 2008

 

 

 

Loss 
(Numerator)

 

Shares 
(Denominator)(1)

 

Per 
Share 
Amount

 

Loss 
(Numerator)

 

Shares 
(Denominator)(2)

 

Per 
Share 
Amount

 

 

 

(in thousands, except per share amounts)

 

Net loss

 

$

(76,940

)

 

 

 

 

$

(16,179

)

 

 

 

 

Less: Preferred stock dividends paid

 

 

 

 

 

 

(2,066

)

 

 

 

 

Less: Preferred stock dividends in arrears

 

(2,066

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic EPS

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss to common stockholders

 

(79,006

)

28,840

 

$

(2.74

)

(18,245

)

28,566

 

$

(0.64

)

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock units

 

 

 

 

 

 

 

Common stock options

 

 

 

 

 

 

 

Convertible preferred stock

 

 

 

 

 

 

 

Diluted EPS

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss to common stockholders

 

$

(79,006

)

28,840

 

$

(2.74

)

$

(18,245

)

28,566

 

$

(0.64

)

 


(1)          In the calculation of diluted EPS for the quarter ended March 31, 2009, the 8.7 million shares of common stock resulting from an assumed conversion of the Company’s Convertible Preferred Stock and 8,730 equivalent shares of the Company’s restricted stock units were excluded because the conversion would be anti-dilutive.

 

(2)          In the calculation of diluted EPS for the quarter ended March 31, 2008, the 8.7 million shares of common stock resulting from an assumed conversion of the Company’s Convertible Preferred Stock and 69,531 equivalent shares of the Company’s restricted stock units and common stock options were excluded because the conversion would be anti-dilutive.

 

8.   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.

 

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company considers the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to the historical evidence, and in light of the current market situation and the uncertainty surrounding the Company’s Revolving Facility and related Amended Consent (see Notes 2 and 4), management is not able to determine that it is more likely than not that the deferred tax assets will be realized Therefore, the Company fully provided for additions to its deferred tax asset with a valuation allowance during the period and did not record a tax benefit for the three months ended March 31, 2009. The Company established a full valuation allowance and reduced its net deferred tax asset to zero during 2008. The Company

 

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will continue to assess the valuation allowance against deferred income tax assets considering all available information obtained in future reporting periods.  If the Company achieves profitable operations in the future, it may reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. The valuation allowance has no impact on the Company’s net operating loss (“NOL”) position for tax purposes, and if the Company generates taxable income in future periods, it will be able to use its NOLs to offset taxes due at that time.

 

As of March 31, 2009, the Company had $0.1 million of unrecognized tax benefits related to FIN 48. There were no significant changes to the calculation since December 31, 2008. The Company does not expect the amount of unrecognized tax benefits to materially change in 2009.

 

9.   SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION AND 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 is presented below:

 

Description

 

Number of 
Shares Issued

 

Grant Date
Fair Market Value

 

 

 

(in thousands)

 

Three months ended March 31, 2009:

 

 

 

 

 

Shares issued to satisfy restricted stock grants

 

33

 

$

607

 

Three months ended March 31, 2008:

 

 

 

 

 

Shares issued to satisfy restricted stock grants

 

45

 

$

973

 

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

 

23

 

$

141

 

 

For the three months ended March 31, 2009 and 2008, the non-cash portion of Asset Retirement Costs was approximately $3,700 and $691,600, respectively. Preferred stock dividends declared but not yet paid at March 31, 2008 were $2.1 million, of which $1.7 million was accrued at March 31, 2008. There were no dividends declared or accrued at March 31, 2009. A supplemental disclosure of cash flow information is presented below:

 

 

 

For the Three Months Ended 
March 31,

 

 

 

2009

 

2008

 

 

 

(in thousands)

 

Cash paid during the period for:

 

 

 

 

 

Interest, net of amounts capitalized

 

$

2,811

 

$

4,023

 

 

10.       HEDGING AND DERIVATIVE ACTIVITIES

 

The Company utilizes price-risk management transactions (e.g., swaps, collars and floors) for a portion of its expected oil and natural gas production to seek to reduce exposure from the volatility of oil and natural gas prices and also to achieve a more predictable cash flow. While the use of these arrangements is intended to reduce the Company’s potential exposure to significant commodity price declines, they may limit the Company’s ability to benefit from increases in the price of oil and natural gas. The Company’s arrangements, to the extent it enters into any, are intended to apply to only a portion of its expected production and thereby provide only partial price protection against declines in oil and natural gas prices. None of these instruments are, at the time of their execution, intended to be used for trading or speculative purposes, but a portion of the Company’s 2008 instruments was subsequently deemed as such because of the decrease in the Company’s 2008 production. These price-risk management transactions are generally placed with major financial institutions that the Company believes are financially stable; however, in light of the recent global financial crisis, there can be no assurance of the foregoing. None of the company’s derivative contracts contain collateral posting requirements; however, the counterparty to the Company’s 2009 positions is a member of the lending group of the Company’s Revolving Facility, and certain events of default under the Company’s Revolving Facility may result in a cross default of derivative instruments with such party. On a quarterly basis, the Company’s

 

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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 reviews the Company’s policies and trades monthly.

 

All of these price-risk management transactions are considered derivative instruments and accounted for in accordance with SFAS No. 133 (as amended). These derivative instruments are intended to hedge the Company’s 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 instruments, other than those that meet the normal purchases and sales exception, are recorded on the balance sheet at fair value. The estimated fair value of these contracts is based upon various factors, including closing exchange prices on the NYMEX, over-the-counter quotations, volatility and, in the case of collars and floors, the time value of options. The calculation of the fair value of collars and floors requires the use of an option-pricing model (see Note 11). The cash flows resulting from settlement of derivative transactions which relate to economically hedging the Company’s physical production volumes are classified in operating activities on the statement of cash flows and the cash flows resulting from settlement of derivative transactions considered “overhedged” positions are classified in investing activities on the statement of cash flows. For those derivatives in which mark-to-market accounting treatment is applied, the changes in fair value are not deferred through other comprehensive income (“OCI”) on the balance sheet. Rather they are immediately recorded in total revenue on the statement of operations. For those derivative instrument contracts that are designated and qualify for cash flow hedge accounting, the effective portion of the changes in the fair value of the contracts is recorded in OCI on the balance sheet and the ineffective portion of the changes in the fair value of the contracts is recorded in total revenue on the statement of operations, in either case, as such changes occur. When the hedged production is sold, the realized gains and losses on the contracts are removed from OCI and recorded in total revenue on the statement of operations, which reduces the period to period volatility impacting the statement of operations that may occur throughout the contract term. While the contract is outstanding, the unrealized gain or loss may increase or decrease until settlement of the contract depending on the fair value at the measurement dates. The Company evaluates the terms of new contracts entered into to determine whether cash flow hedge accounting treatment or mark-to-market accounting treatment will be applied. The Company has applied mark-to-market accounting treatment to all outstanding contracts since January 1, 2006.

 

The fair value of outstanding derivative contracts not designated as hedging instruments under SFAS No. 133 (as amended) reflected on the balance sheet was as follows:

 

 

 

 

 

 

 

 

 

Price

 

 

 

 

 

Fair Value of Outstanding
Derivative Contracts as of

 

Transaction

 

Transaction

 

 

 

 

 

Per

 

Volumes

 

Balance Sheet

 

March 31,

 

December 31,

 

Date

 

Type

 

Beginning

 

Ending

 

Unit

 

Per Day

 

Location

 

2009

 

2008

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

Natural Gas (1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

04/07

 

Collar

 

1/1/2009

 

12/31/2009

 

$7.75-
$10.00

 

10,000 MMBtu

 

Derivative Financial Instruments - Current Assets

 

$

9,618

 

$

6,688

 

10/07

 

Collar

 

1/1/2009

 

12/31/2009

 

$7.75-
$10.08

 

10,000 MMBtu

 

Derivative Financial Instruments - Current Assets

 

9,620

 

6,702

 

Crude Oil (2):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10/07

 

Collar

 

1/1/2009

 

12/31/2009

 

$70.00-
$93.55

 

300 Bbl

 

Derivative Financial Instruments - Current Assets

 

1,389

 

2,017

 

 

 

 

 

Total derivatives not designated as hedging instruments under SFAS No. 133

 

$

20,627

 

$

15,407

 

 

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(1)   The Company’s natural gas contracts were entered into on a per MMBtu delivered price basis, using the NYMEX Natural Gas Index. Mark-to-market accounting treatment is applied to these contracts and the change in fair value is reflected in total revenue.

 

(2)   The Company’s crude oil contract was entered into on a per barrel delivered price basis, using the West Texas Intermediate Light Sweet Crude Oil Index. Mark-to-market accounting treatment is applied to this contract and the change in fair value is reflected in total revenue.

 

The following table reflects the realized and unrealized gains and losses included in total revenue on the statement of operations:

 

 

 

 

 

Amount of Gain or (Loss)
Recognized in Income on Derivative

 

Derivatives Not Designated as Hedging

 

Location of Gain or (Loss) Recognized

 

For the Three Months Ended
March 31,

 

Instruments under SFAS No. 133

 

in Income on Derivative

 

2009

 

2008

 

 

 

 

 

(in thousands)

 

Natural gas derivative realized settlements

 

Gain (loss) on derivatives — Total revenue

 

$

5,125

 

$

363

 

Crude oil derivative realized settlements

 

Gain (loss) on derivatives — Total revenue

 

723

 

(4,362

)

Natural gas derivative unrealized change in fair value

 

Gain (loss) on derivatives — Total revenue

 

5,848

 

(25,564

)

Crude oil derivative unrealized change in fair value

 

Gain (loss) on derivatives — Total revenue

 

(628

)

204

 

Gain (loss) on derivatives

 

 

 

$

11,068

 

$

(29,359

)

 

11.  FAIR VALUE MEASUREMENTS

 

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

 

Valuation Techniques

 

In accordance with SFAS No. 157, valuation techniques used for assets and liabilities accounted for at fair value are generally categorized into three types:

 

·      Market Approach. Market approach valuation techniques use prices and other relevant information from market transactions involving identical or comparable assets or liabilities.

 

·      Income Approach. Income approach valuation techniques convert future amounts, such as cash flows or earnings, to a single present amount, or a discounted amount. These techniques rely on current market expectations of future amounts.

 

·      Cost Approach. Cost approach valuation techniques are based upon the amount that, at present, would be required to replace the service capacity of an asset, or the current replacement cost. That is, from the perspective of a market participant (seller), the price that would be received for the asset is determined based on the cost to a market participant (buyer) to acquire or construct a substitute asset of comparable utility.

 

The three approaches described within SFAS No. 157 are consistent with generally accepted valuation methodologies. While all three approaches are not applicable to all assets or liabilities accounted for at fair value, where appropriate and possible, one or more valuation techniques may be used. The selection of the valuation method(s) to apply considers the definition of an exit price and the nature of the asset or liability being valued and significant expertise and judgment is required. For assets and liabilities accounted for at fair value, valuation techniques are generally a combination of the market and income approaches. Accordingly, the

 

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Company aims to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

 

Input Hierarchy

 

SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value directly related to the amount of subjectivity associated with the inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

 

·      Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 

·      Level 2 — Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 2 includes those financial instruments that are valued using models or other valuation methodologies, which consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

 

·      Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date.

 

Fair Value on a Recurring Basis

 

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

 

 

 

 

 

Fair Value Measurements Using:

 

 

 

 

 

Quoted

 

Significant

 

 

 

 

 

 

 

Prices in

 

Other

 

Significant

 

 

 

 

 

Active

 

Observable

 

Unobservable

 

 

 

Total Fair

 

Markets

 

Inputs

 

Inputs

 

 

 

Value

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

Derivative instruments

 

$

20,627

 

$

 

$

 

$

20,627

 

 

The following table sets forth a reconciliation of changes in the fair value of the Company’s derivative instruments classified as Level 3 in the fair value hierarchy.

 

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Three months ended March 31, 2009

 

 

 

Assets

 

Liabilities

 

 

 

(in thousands)

 

Balance as of December 31, 2008

 

$

15,407

 

$

 

Realized and unrealized losses included in earnings

 

(628

)

 

Realized and unrealized gains (losses) included in other comprehensive income

 

 

 

Settlements

 

5,848

 

 

Transfers in and/or out of Level 3

 

 

 

Balance as of March 31, 2009

 

$

20,627

 

$

 

 

Change in unrealized gains relating to instruments still
held as of March 31, 2009

 

$

9,351

 

$

 

 

Gains and losses (realized and unrealized) for Level 3 recurring items are included in total revenue on the Consolidated Statements of Operations. Settlements represent cash settlements of contracts during the period, which are included in total revenue on the Consolidated Statements of Operations.

 

Transfers in and/or out represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. There were no transfers in or out of Level 3 during the periods presented.

 

Fair Value on a Nonrecurring Basis

 

On January 1, 2009, the Company adopted the provisions of SFAS No. 157 for non-financial assets and liabilities, which were delayed by FSP FAS 157-2. Therefore, the Company adopted the provisions of SFAS No. 157 for its AROs. The Company uses fair value measurements on a nonrecurring basis in its AROs. These liabilities are recorded at fair value initially and assessed for revisions periodically thereafter. The lowest level of significant inputs for fair value measurements for ARO liabilities are Level 3. A reconciliation of the beginning and ending balances of the Company’s ARO is presented in Note 3, in accordance with SFAS No. 143. New assets and liabilities measured at fair value during the three months ended March 31, 2009 include:

 

 

 

 

 

Fair Value Measurements Using:

 

 

 

 

 

Quoted

 

Significant

 

 

 

 

 

 

 

Prices in

 

Other

 

Significant

 

 

 

 

 

Active

 

Observable

 

Unobservable

 

 

 

Total Fair

 

Markets

 

Inputs

 

Inputs

 

 

 

Value

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

 

 

(in thousands)

 

Assets:

 

 

 

 

 

 

 

 

 

Asset retirement costs

 

$

11

 

$

 

$

 

$

11

 

 

 

 

 

 

 

 

 

 

 

Liabilities:

 

 

 

 

 

 

 

 

 

Asset retirement obligations — current

 

$

 

$

 

$

 

$

 

Asset retirement obligations — long-term

 

11

 

 

 

11

 

 

12.  COMMITMENTS AND CONTINGENCIES

 

Delivery Commitments — During 2007, the Company executed a gas gathering and compression services agreement with Frontier Midstream, LLC (“Frontier”). Following execution of such agreement, Frontier expedited the installation of the Rose Bud system in White County, Arkansas, including the high and low pressure gathering lines, dehydration, compression and the interconnect with Ozark, in order to

 

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accommodate the Company’s desire to be able to deliver natural gas as soon as its wells were completed. At the time of signing the contract, the Company had completed and tested two productive wells in the Moorefield shale. The Rose Bud system was installed, operational and ready to receive the Company’s production in June 2007. The contract minimum commitment to Frontier is 2.7 Bcf over a three-year period for the pipeline interconnect. This line carries a $0.29 per Mcf deficiency rate, for a total commitment for the pipeline of approximately $0.8 million. The Company has delivered approximately $68,400 of this commitment through March 31, 2009. In addition to the pipeline, Frontier also built and installed lateral gathering lines to eight locations.  The remaining commitment on these laterals is $1.3 million, for a total potential liability of approximately $2.0 million to be paid by June 2010 if the minimum volumes are not delivered. The Company recorded a long-term liability for the aggregate amount of $2.0 million in the fourth quarter of 2008. Although the Company believes there is the potential to develop this area and increase production, it does not currently have sufficient liquidity to ensure that this occurs in the timeframe required by the gas gathering and compression services agreement with Frontier.

 

During 2008, the Company executed a gas gathering and compression services agreement with Integrys Energy Services (“Integrys”) related to the construction and installation of a pipeline connecting the Company’s Slick State properties to its Bloomberg properties in order to secure more advantageous plant processing, transportation and gathering fees and access to gas markets. The pipeline system was installed, operational and ready to redirect the production in September 2008. The contract minimum commitment to Integrys is approximately 11.2 Bcf over a three year period for the pipeline interconnect. The amount of total commitment is $550,000 plus 8% interest per annum, for a total liability of approximately $0.6 million. The Company has delivered approximately $124,000 of this commitment through March 31, 2009. The Company has not recorded a liability for this commitment as it expects to meet the minimum physical delivery based on estimated anticipated production.

 

This contract is not considered a derivative, but has been designated as an annual sales contract under SFAS No. 133 (as amended).

 

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 material adverse effect on the Company’s financial condition, results of operations or cash flows except as set forth below.

 

David Blake, et al. v. Edge Petroleum Corporation — On September 19, 2005, David Blake and David Blake, Trustee of the David and Nita Blake 1992 Children’s Trust, filed suit against the Company in state district court in Goliad County, Texas alleging breach of contract for failure and refusal to transfer overriding royalty interests to plaintiffs in several leases in the Nita and Austin prospects in Goliad County, Texas and failure and refusal to pay monies to Blake pursuant to such overriding royalty interests for wells completed on the leases. The plaintiffs seek relief of (1) specific performance of the alleged agreement, including granting of overriding royalty interests by us to Blake; (2) monetary damages for failure to grant the overriding royalty interests; (3) exemplary damages for his claims of business disparagement and slander; (4) monetary damages for tortious interference; and (5) attorneys’ fees and court costs. Venue of the case was transferred to Harris County, Texas by agreement of the litigants. The Company’s subsidiaries, Edge Petroleum Exploration Company, Edge Petroleum Operating Company and Edge Petroleum Production Company, were also added as defendants. The Company filed a counterclaim against plaintiff and joined various related entities that are controlled by Blake, seeking lease interests in which the Company contends it had been wrongfully denied participation and also claiming that proprietary information was misappropriated. The parties have moved for summary judgment on each other’s claims and counterclaims, which the trial court has denied as to both sides.  In November 2007, the Company filed a separate motion for summary judgment based on the statute of frauds and; the court has not yet ruled on this separate motion. In June 2008, the Plaintiffs filed a Sixth Amended Petition conditionally adding claims for certain prospects that had been previously settled by means of a Compromise and Settlement Agreement (the “Settlement Agreement”), entered in settlement of prior litigation among some of the parties, but only to the extent that rescission of the prior Settlement Agreement was being sought by the Company. The Company is not seeking rescission of the prior Settlement Agreement and responded accordingly in its Fourth Amended Original Counterclaim and Claims Against Additional Parties

 

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filed on October 16, 2008.  On October 17, 2008, the plaintiffs filed their Seventh Amended Petition adding a claim for breach of the Settlement Agreement. The trial, originally scheduled to begin September 10, 2007, has been reset several times, most recently for December 8, 2008, and will be reset in 2009 by the newly-elected judge of the 215th Judicial District Court in Harris County.  In December 2008, one of the Blake counter-defendants filed a motion to arbitrate, which motion has not been heard by the court.  Extensive written discovery has occurred in the case, and the parties are engaging in fact and expert witness depositions. The Company has responded and will continue to respond aggressively to this lawsuit, and believes it has meritorious defenses and counterclaims.

 

Mary Jane Carol Trahan Champagne, et al. v. Edge Petroleum Exploration Company, et al. — On September 19, 2008 the Company was sued in state district court in Vermilion Parish, Louisiana by Mary Jane Trahan, Carol Trahan Champagne and 29 other plaintiffs alleging breach of obligations under mineral leases in Vermilion Parish regarding the Trahan No. 1 well and the Trahan No. 3 well (MT RC SUB reservoir). Plaintiffs are seeking unspecified damages for lost revenue, lost royalties and devaluation of property interest sustained as a result of the defendants’ alleged negligent and improper drilling operations on the Trahan No. 1 well and the Trahan No. 3 well, including alleged failure to prevent underground water from flooding and destroying plaintiffs’ portion of the reservoir beneath plaintiffs’ property.  Plaintiffs also allege defendants failed to “block squeeze” sections of the Trahan No. 3 well as would a prudent operator. This lawsuit, previously removed from the state court to the federal district court for the Western District of Louisiana, Lafayette Division, has been remanded to state court. The Company’s insurance carrier has retained counsel to represent the Company in this matter. The Company has not established a reserve with respect to this claim and it is not possible to determine what, if any, its ultimate exposure might be in this matter. The Company intends to vigorously defend itself in this lawsuit.

 

John Lemke, et al. v. Edge Petroleum Corporation - In October 2008, the Company was sued by alleged assignees of Continental Seismic over an alleged contract to receive a royalty of two-tenths of one percent in certain alleged areas developed for oil and gas in South Louisiana. The Company has filed an answer generally denying the allegations and raising the defenses of the statute of limitations bar and laches. No discovery has been served. The court recently entered a docket control order which establishes a discovery timetable and a trial date of November 30, 2009. The Company has not established a reserve with respect to this claim and has not determined what, if any, the Company’s ultimate exposure might be in this matter.  The Company will respond aggressively to this lawsuit, and believes it has meritorious defenses.

 

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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 MD&A 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, 2008 (“2008 Annual Report”).

 

FORWARD LOOKING STATEMENTS

 

The information contained in this quarterly Report on Form 10-Q includes certain forward-looking statements.  The words “may,” “will,” “expect,” “anticipate,” “believe,” “continue,” “estimate,” “project,” “intend,” and similar expressions used in this Form 10-Q are intended to identify forward-looking statements within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  You should not place undue reliance on these forward-looking statements, which speak only as of the date made.  We undertake no obligation to publicly release the result of any revision of these forward-looking statements to reflect events or circumstances after the date they are made or to reflect the occurrence of unanticipated events. You should also know that such statements are not guarantees of future performance and are subject to risks, uncertainties and assumptions.  Should any of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may differ materially from those included within the forward-looking statements.  Such statements involve risks and uncertainties, including, but not limited to, those set forth under “ITEM 1A. RISK FACTORS” of our 2008 Annual Report and this Quarterly Report on Form 10-Q.

 

GENERAL OVERVIEW

 

Edge Petroleum Corporation (“Edge”, “we” or the “Company”) is a Houston-based independent energy company that focuses its exploration, development, production, acquisition 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 a strategy which focused on a balanced program of exploration, exploitation and development and acquisition of oil and natural gas properties. In late 2007, in an attempt to enhance shareholder value we began to assess our strategic alternatives  and have subsequently expanded this process to include a further evaluation of both our financial and strategic alternatives in late 2008 and continuing into 2009. Our current primary focus is on capital preservation and resolving the uncertainty and challenges we face.

 

We generate revenues, income and cash flows by producing and marketing oil and natural gas produced from our oil and natural gas properties. We have historically made significant capital expenditures in our exploration, development, and production activities that have allowed us to continue generating revenue, income and cash flows. In recent years, we have also spent considerable efforts on acquisitions, including both corporate and asset acquisitions. We are currently operating with a reduced capital spending program as we continue to pursue the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company.

 

This overview provides our perspective on the individual sections of MD&A. Our MD&A includes the following sections:

 

·                  Outlook and Review of Financial and Strategic Alternatives — additional discussion relating to management’s outlook to the future of our business.

 

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·                  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 natural gas industry.

 

·                  Approach to the Business — information regarding our approach and strategy.

 

·                  Divestitures — information about our sales and divestitures.

 

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

 

·                  Results of Operations — an analysis of our 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.

 

·                  Fair Value Measurements — supplementary discussion regarding fair value measurements and implementation of SFAS No. 157, Fair Value Measurements.

 

·                  Risk Management Activities supplementary information regarding our price-risk management activities.

 

·                  Tax Matters — supplementary discussion of income tax matters.

 

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

 

Outlook and Review of Financial and Strategic Alternatives

 

On December 18, 2007, we announced the hiring of a financial advisor to assist our Board of Directors with an assessment of strategic alternatives. During 2008, we focused our efforts on a proposed merger with Chaparral Energy, Inc. (“Chaparral”). However, on December 17, 2008, we announced the termination of the Chaparral merger agreement after both we and Chaparral determined it was highly unlikely that the conditions to the closing of the proposed merger would be satisfied or that Chaparral would be able to obtain sufficient debt and equity financing to allow them to complete the proposed merger and operate as a combined company, particularly in light of the challenging environment in the financial markets and the energy industry.

 

Since December 2008, we have continued with our evaluation and assessment of various financial and strategic alternatives, which may include the sale of some or all of our assets, a merger or other business combination involving the Company, restructuring or recapitalization of the Company to address our liquidity issues and the Deficiency under our Revolving Facility (see discussion below). We are working with an investment banking firm to assist further in the evaluation of our financial and strategic alternatives.

 

During January 2009, we announced that the lenders (“Lenders”) to our Fourth Amended and Restated Credit Agreement (as amended, the “Revolving Facility”) had completed their borrowing base redetermination and reduced our borrowing base to $125 million, resulting in a $114 million borrowing base deficiency (the “Deficiency”).

 

Pursuant to the terms of the Revolving Facility, we elected to prepay the Deficiency in six equal monthly installments, with the first $19 million installment being due on February 9, 2009. On February 9, 2009, we entered into a Consent and Agreement (the “February Consent”) among us and the Lenders under the Revolving Facility deferring the payment date of the first $19 million installment until March 10, 2009, and extending the due date for each subsequent installment by one month with the last of the six installment payments to be due on August 10, 2009.  In connection with the February Consent, we agreed to prepay $5.0 million of our

 

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outstanding advances under the Revolving Facility, in two equal installments. The first $2.5 million prepayment was paid on February 9, 2009 and the second $2.5 million prepayment was paid on February 23, 2009, with each of the prepayments to be applied on a pro rata basis to reduce the remaining six $19 million deficiency payments.  On March 10, 2009, we entered into a Consent and Agreement (the “March Consent”) with the Lenders under the Revolving Facility, which provided, among other things, for the extension of the due date for the first installment to repay the Deficiency from March 10, 2009 to March 17, 2009.  Notwithstanding such extension, we agreed with the Lenders that each of the other five equal installment payments required to eliminate the Deficiency would be due and payable as provided for in the February Consent. On March 16, 2009, we entered into Consent and Amendment No. 4 to our Revolving Facility (the “Amended Consent”) which provides, among other things, (1) that we will make a $25 million payment on May 31, 2009 with all remaining principal, fees and interest amounts under our Revolving Facility to be due and payable on June 30, 2009, (2) that it will be an event of default (i) if we fail to have executed and delivered on or before May 15, 2009 at least one of the following (a) a commitment letter from a lender or group of lenders reasonably satisfactory to our Lenders providing for the provision by such lender or group of lenders of a credit facility in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, (b) a merger agreement or similar agreement involving us as part of a transaction that results in the repayment of our obligations under the Revolving Facility on or before June 30, 2009, and (c) a purchase and sale agreement with a buyer or group of buyers reasonably acceptable to our Lenders providing for a sale transaction by us that results in the repayment of all of our obligations under the Revolving Facility on or before June 30, 2009, or (ii) if we are in default under or our hedging arrangements have been terminated or cease to be effective without the prior written consent of our Lenders, (3) that our advances under the Revolving Facility will bear interest at a rate equal to the greater of (a) the reference rate publicly announced by Union Bank of California, N.A. for such day, (b) the Federal Funds Rate in effect on such day plus 0.50% and (c) a rate determined by the Administrative Agent to be the Daily One-Month LIBOR (as defined in the Revolving Facility), in each case plus 2.5% or, during the continuation of an event of default, plus 4.5% (resulting in an effective interest rate of approximately 5.75% as of May 7, 2009), (4) for limitations on the making of capital expenditures and certain investments, and (5) for the elimination of the current ratio, leverage ratio and interest coverage ratio covenant requirements. The Amended Consent also eliminates the six $19 million deficiency payments which were contemplated by the February Consent and the March Consent. To comply with the terms of the Amended Consent, we anticipate that we will need to (i) sell select individual assets prior to May 31, 2009 to enable us to make the $25 million payment which is due on May 31, 2009, and/or (ii) negotiate a commitment letter with a new lender or group of lenders prior to May 15, 2009 in an amount sufficient to repay all of our obligations under the Revolving Facility on or before June 30, 2009, and/or (iii) have negotiated the sale, merger or other business combination involving us which results in the repayment of all of our obligations under the Revolving Facility prior to May 15, 2009 and to have closed such transaction on or before June 30, 2009. The Amended Consent limits the making of capital expenditures and we anticipate a severe curtailment of our drilling plans and other capital expenditures in 2009.

 

If we breach any of the provisions of the Amended Consent or the Revolving Facility, our Lenders will be entitled to declare an event of default, at which point the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, would become immediately due and payable.  In any event, the entire unpaid principal balance of the loans, together with all accrued and unpaid interest and other amounts then owing to our Lenders, will be payable on June 30, 2009 unless earlier paid or a further extension with respect to payment is negotiated with our Lenders. Our Lenders may take action to enforce their rights with respect to the outstanding obligations under the Revolving Facility. Because substantially all of our assets are pledged as collateral under the Revolving Facility, if our Lenders declare an event of default, they would be entitled to foreclose on and take possession of our assets.  In such an event, we may be forced to liquidate or to otherwise seek protection under Chapter 11 of the U.S. Bankruptcy Code. These matters, as well as the other risk factors related to our liquidity and financial position raise substantial doubt as to our ability to continue as a going concern. See ITEM 2. “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — LIQUIDITY AND CAPITAL RESOURCES — REVOLVING FACILITY.” With respect to our compliance with the Amended Consent, there can be no assurance that we will be able to further negotiate the terms of the Amended Consent or negotiate a further restructuring of the related indebtedness or that we will be able to make any required payments when they become due.  Moreover, there can be no assurance that we will be successful in our efforts to comply with the terms of the Amended Consent, including our ongoing efforts to evaluate and assess our various financial

 

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and strategic alternatives (which may include the sale of some or all of our assets, a merger or other business combination involving the Company, or the restructuring or recapitalization of the Company).  If such efforts are not successful, we may be required to seek protection under Chapter 11 of the U.S. Bankruptcy Code.

 

Going Concern — In addition to the Deficiency under our Revolving Facility, the capital expenditures required to maintain and/or grow production and reserves are substantial. Prices for oil and natural gas declined materially during the fourth quarter of 2008, and natural gas prices continued to decline during the first quarter of 2009.  A continued or extended decline in oil or natural gas prices will have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and natural gas reserves that we can economically produce. Our stock price has significantly declined over the past year which also makes it more difficult to obtain equity financing on acceptable terms to address our liquidity issues. In addition, we are reporting negative working capital at March 31, 2009 and continue to report net losses in the first quarter of 2009 following three consecutive years of net losses.  Therefore, there is substantial doubt as to our ability to continue as a going concern for a period longer than the next twelve months. Additionally, our independent auditors included an explanatory paragraph in their report on our consolidated financials statements as of and for the year ended December 31, 2008 that raises substantial doubt about our ability to continue as a going concern. Our ability to continue as a going concern is dependent upon the success of our financial and strategic alternatives process, which may include the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company and an increase in commodity prices. Until the possible completion of the financial and strategic alternatives process, our future remains uncertain and there can be no assurance that our efforts in this regard will be successful.

 

Our consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies we will continue to meet our obligations and continue our operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and our consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of this uncertainty.

 

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, the results of our financial and strategic alternatives process, access to capital, the acquisitions market and factors referred to in “FORWARD LOOKING INFORMATION” in our 2008 Annual Report.

 

Industry and Economic Factors

 

In managing our business, we must deal with many factors inherent to our industry.  First and foremost is the fluctuation of oil and natural gas prices. Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and natural gas prices and the costs to produce our reserves. Oil and natural gas prices are subject to significant fluctuations that are beyond our ability to control or predict without losing some advantage of the upside potential. In recent years, oil and natural gas commodity prices have generally trended upwards in response to robust demand and constrained supplies, with oil and natural gas prices peaking at more than $140.00 per barrel and $13.00 per Mcf, respectively, in July 2008. In late 2008 and early 2009, a world-wide economic recession and oversupply of natural gas in North America led to an unprecedented decline in oil and natural gas prices, with oil falling by more than $100.00 per barrel and natural gas falling more than $10.00 per Mcf from their peaks in July 2008.

 

Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. Our costs and expenses tend to react to activity levels in our industry and commodity price movements. In response to the recent historically high commodity prices, the oil and natural gas industry experienced significant increases in activity and in demand for oil field services. The increased demand for these services resulted in significant inflation in both operating and capital costs in 2008. Although commodity prices have declined significantly in recent months, the inflated cost of oil field services resulting from recent historically high commodity prices did not decrease as rapidly. While these costs are declining, they have lagged in comparison to the rapid commodity price decline; thus the prospect of continued

 

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low commodity prices and disproportionately higher service costs will constrain the industry’s capital reinvestment for the near future.

 

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, oftentimes resulting in no commercially productive reserves being discovered.  These factors, together with increased demand for rigs, equipment, supplies and services, have made it difficult at times for us to further our growth, and made timely execution of our planned activities difficult.

 

Our business, as with other extractive businesses, is a depleting one in which each gas equivalent produced must be replaced or our asset base and capacity to generate revenues in the future will shrink.  In 2008 and the first quarter of 2009, we were unable to replace the production we generated due to our reduced capital spending program and higher drilling and operating costs. This will continue to be a factor in 2009 as we operate under a severely limited capital and operating budget.

 

The oil and natural gas industry is highly competitive. We compete with major and diversified energy companies, independent oil and natural 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 natural gas wells and related facilities.  These regulations may become more demanding in the future.

 

Poor economic conditions continue to create considerable challenges and uncertainties for the energy industry. We are unable to predict the impact on our business of a continued decline in commodity prices and the global economy, but the current conditions have made it difficult at times for us in our ongoing financial and strategic alternatives process. We expect that continued weakening in the economy could result in further declines in our revenue, cash flows and liquidity.

 

Approach to the Business

 

Historically, our goal has been to fund ongoing exploration and development projects with cash flow provided by operating activities, occasionally supplemented with external sources of capital. In connection with our ongoing financial and strategic alternatives process and our liquidity issues resulting from the Deficiency under our Revolving Facility and the related Amended Consent, we have operated and will continue to operate with a severely limited capital spending program in 2009 as we continue to pursue the sale of some or all of our assets, a merger or other business combination involving the Company or the restructuring or recapitalization of the Company. Our strategy is currently to continue under a severely limited capital and operating budget, thereby reducing our normal exploration and development activities as we seek to preserve liquidity and resolve the uncertainty and challenges that we face as we pursue various financial and strategic alternatives.

 

We normally hedge our exposure to volatile oil and natural gas prices on a portion of our expected production to reduce price risk. As of March 31, 2009, we had derivative contracts in place covering 20,000 MMBtu/d of natural gas and 300 Bbl/d of crude oil for the remainder of 2009.

 

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. We have not completed any divestitures in the first quarter of 2009, but during the first quarter of 2008, we

 

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completed the sale of certain working interests in approximately 100 properties located in Texas to various buyers for aggregate proceeds of approximately $12.2 million.

 

Critical Accounting Policies and Estimates

 

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue, 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 and Natural Gas Reserves - Our estimate of proved reserves is based on the quantities of oil and natural 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, as well as prices and cost levels at that point in time. 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 is used in calculating depletion expense and 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 natural gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full-cost ceiling test. The ceiling is the discounted present value of our estimated total proved reserves (using a 10% discount rate) adjusted for taxes and the impact of cash flow hedges on pricing, if cash flow hedge accounting is applied. The ceiling test calculation dictates that prices and costs in effect as of the last day of the period are to be used in calculating the discounted present value of our estimated total proved reserves.  However, if prices increase subsequent to the balance sheet date, but before the filing date, SEC guidelines allow a company to use the subsequent date’s higher prices in calculating the full-cost ceiling. 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 natural gas properties is not reversible at a later date even if oil and natural gas prices increase. A ceiling test impairment could result in a significant loss for a reporting period; however, future depletion expense would be correspondingly reduced.  Our estimated proved reserves volumes have decreased during the period from year-end 2008 to March 31, 2009, and the average oil, NGL and natural gas prices at the balance sheet date as of March 31, 2009 were $49.66 per barrel, $29.80 per barrel and $3.78 per MMBtu, respectively. As a result, we recorded a net ceiling test impairment for the three months ended March 31, 2009 of approximately $78.3 million, net of tax. This impairment will significantly affect the comparability of results between the 2009 and 2008 periods. Additionally the impairments taken in the third and fourth quarters of 2008 significantly impacted our depletion

 

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expense in the first quarter of 2009. If the 2008 impairments had not been taken, our depletion rate would have been approximately $6.40 per Mcfe as compared to $3.16 per Mcfe reported for the three months ended March 31, 2009.

 

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 - Factors that contribute to a ceiling test impairment include the price used to calculate the reserve limitation threshold and reserve quantities. A reduction in prices at a measurement date could trigger a full-cost ceiling impairment. We recorded an impairment of approximately $78.3 million, net of tax, at March 31, 2009. A 10% increase or decrease in prices would have decreased or increased our impairment by approximately 40%, net of tax, respectively. Therefore, should prices continue to decline in 2009, the potential for additional impairments at upcoming quarter-ends exists. Although our hedging program is intended to mitigate the economic impact of any significant price decline, it did not impact our ceiling test at March 31, 2009 because we do not apply cash flow hedge accounting to our derivative contracts. Had we applied cash flow hedge accounting to our outstanding derivative contracts, there would have been a 29% decrease in the impairment taken as a result of the low prices at the measurement date falling below the price floors. A 10% increase or decrease in reserve volume would have decreased or increased the impairment calculated at March 31, 2009 by approximately 20%.

 

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 natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, we estimate asset retirement costs for all of our assets upon acquisition of the asset, adjust those costs for inflation 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. When new obligations are incurred, i.e. a new well is drilled or acquired, we add to the ARO liability. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, our estimate must be revised. When well obligations are relieved by sale of the property or plugging and abandoning the well, the related estimated liability and asset costs are removed from our balance sheet and replaced by the costs actually spent on retiring the asset.

 

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.

 

Assumptions/Approach 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 period-end reserve reports prepared 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 have developed a standard cost estimate based on historical costs, industry quotes and depth of wells. This cost estimate is reviewed annually to determine whether it is a reasonable estimate in the

 

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current environment. Unless we expect a well’s plugging to be significantly different than a normal abandonment, we use this estimate.

 

Effect if Different Assumptions Used: We expect to see our calculations for new properties and revisions to existing properties impacted significantly if interest rates rise, as the credit-adjusted-risk-free rate is one of the variables used on a quarterly basis. We also expect that significant changes to the cost of retiring assets or the reserve life of our assets would have significant impact on our estimated ARO.

 

Nature of Critical Estimate Item: Income Taxes - In accordance with 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, respectively, of events that have been recognized in our financial statements and our tax returns. There are several items that result in deferred tax assets and liabilities on the balance sheet, the largest of which are deferred liabilities attributable to book basis in excess of tax basis in oil and natural gas properties and the impact of net operating loss (“NOL”) carryforwards. We routinely assess our ability to use all 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 to remove the benefit of those NOL carryforwards from our financial statements. Additionally, in accordance with Financial Accounting Standards Board (“FASB”) Interpretation 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109 (“FIN 48”) we have recorded a liability of $0.1 million associated with uncertain tax positions. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  We are required to determine whether it is more likely than not (a likelihood of more than 50 percent) that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit.  If that step is satisfied, then we must measure the tax position to determine the amount of benefit to recognize in the financial statements.  The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.

 

Assumptions/Approach Used: Numerous judgments and assumptions are inherent in the determination of future taxable income and tax return filing positions that we take, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices).

 

Effect if Different Assumptions Used: Along with consultation from an independent public accounting firm used in tax consultation, we continually evaluate complicated tax law requirements and their effect on our current and future tax liability and our tax filing positions.  Despite our attempt to make an accurate estimate, the ultimate utilization of our NOL carryforwards is highly dependent upon our actual production, the realization of taxable income in future periods, Internal Revenue Code Section 382 limitations and potential tax elections.  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 be required to record a valuation allowance to remove the benefit of those NOL carryforwards from our financial statements, as was done most recently in the fourth quarter of 2008 and the first quarter of 2009. Our liability for uncertain tax positions is dependent upon our judgment on the amount of financial statement benefit that an uncertain tax position will realize upon ultimate settlement and on the probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. To the extent that a valuation allowance or uncertain tax position is established or increased or decreased during a period, we may be required to include an expense or benefit within tax expense in the statement of operations. During the first quarter of 2009, we recorded a valuation allowance of approximately $26.9 million which completely offset deferred tax assets recorded during the quarter. This valuation allowance was recorded as a result of our anticipated inability to utilize all of our deferred tax assets.

 

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Nature of Critical Estimate Item: Derivative and 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) related to our expected oil and natural gas production to seek to achieve a more predictable cash flow, as well as to reduce exposure from commodity price fluctuations. While these transactions are intended to be 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, Accounting for Derivative Instruments and Hedging Activities (as amended), all derivatives, other than those that meet the normal purchases and sales exception, are recorded on the balance sheet at fair value.

 

Cash Flow Hedge Accounting - For transactions accounted for under cash flow hedge accounting treatment, the effective portion of the change in fair value of outstanding derivative contracts is deferred through other comprehensive income (“OCI”) on the balance sheet, rather than recorded immediately in total revenue on the statement of operations. Ineffective portions of the changes in the fair value of the derivative contracts are recognized in total revenue as they occur. While the hedge contract is outstanding, the fair value may increase or decrease until settlement of the contract. The cash flows resulting from settlement of derivative transactions which relate to economically hedging our physical production volumes are classified in operating activities on the statement of cash flows, and the cash flows resulting from settlement of derivative transactions considered “overhedged” positions are classified in investing activities on the statement of cash flows.

 

Mark-to-Market Accounting - For transactions accounted for using mark-to-market accounting treatment, until the contract settles, the entire change in the fair value of the outstanding derivative contract is recorded in total revenue immediately, and not deferred through OCI, and there is no measurement of effectiveness. Since January 1, 2006, we have applied mark-to-market accounting treatment to all outstanding derivative contracts.

 

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 derivatives. We currently obtain and review 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. It also approximates the fair value of the contracts as it would be the cost to us to terminate a contract at that point in time, as well as the potential inflows or outflows of cash at the expiration of the contracts. Due to the fact that we apply mark-to-market accounting treatment, the offset to the balance sheet asset or liability, or the change in fair value of the contracts, is included in total revenue on the statement of operations rather than deferred in OCI on the balance sheet.

 

Effect if Different Assumptions Used: At March 31, 2009, a 10% change in the commodity price per unit would cause the fair value total of our derivative financial instruments to increase or decrease by approximately $2.0 million. Had we applied cash flow hedge accounting treatment to all of our derivative contracts outstanding at March 31, 2009, our net loss to common stockholders for the three months would have been approximately $38.7 million, or $1.41 per basic and diluted loss per share, assuming that all hedges were fully effective, as compared to our reported net loss to common stockholders for the three months ended March 31, 2009 of $76.9 million, or $2.74 basic and diluted loss per share.

 

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Results of Operations

 

This section includes discussion of our results of operations for the three months ended March 31, 2009 as compared to the same period of the prior year.  We are an independent oil and natural gas company engaged in the exploration, development, acquisition and production of crude oil and natural gas properties in the United States.  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 Texas, Mississippi, New Mexico and Louisiana.

 

First Quarter 2009 Compared to the First Quarter 2008

 

Revenue and Production

 

Total revenue increased 36% from the first quarter of 2008 to the comparable 2009 period. Excluding the effects of derivative activity, revenue decreased 72% from the first quarter of 2008 to the comparable 2009 period.  For the three months ended March 31, 2009 and 2008, our product mix contributed the following percentages of revenue and production volumes:

 

 

 

REVENUE (1)

 

REVENUE (2)
Three Months Ended March 31,

 

PRODUCTION
VOLUMES (MCFE)

 

 

 

2009

 

2008

 

2009

 

2008

 

2009

 

2008

 

Natural gas

 

83

%

20

%

69

%

62

%

70

%

69

%

Natural gas liquids

 

8

%

55

%

15

%

20

%

19

%

21

%

Crude oil and condensate

 

9

%

25

%

16

%

18

%

11

%

10

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

100

%

100

%

100

%

100

%

100

%

100

%

 


(1) Includes effect of derivative transactions

(2) Excludes effect of derivative transactions

 

The following table summarizes volume and price information with respect to our oil and natural gas production:

 

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2009 Period Compared
to 2008 Period

 

 

 

Three Months Ended
March 31,

 

$
Increase

 

%
Increase

 

 

 

2009

 

2008

 

(Decrease)

 

(Decrease)

 

 

 

(in thousands, except prices and percentages)

 

 

 

Production Volumes:

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

2,170

 

3,773

 

(1,603

)

(42

)%

Natural gas liquids (MBbls)

 

97

 

191

 

(94

)

(49

)%

Crude oil and condensate (MBbls)

 

59

 

85

 

(26

)

(31

)%

Natural gas equivalent (MMcfe)

 

3,106

 

5,429

 

(2,323

)

(43

)%

Average Sales Price(1):

 

 

 

 

 

 

 

 

 

Natural gas ($ per Mcf)(2)

 

$

4.11

 

$

7.62

 

$

(3.51

)

(46

)%

Natural gas liquids ($ per Bbl)

 

20.44

 

50.51

 

(30.07

)

(60

)%

Crude oil and condensate ($ per Bbl)(2)

 

35.30

 

101.07

 

(65.77

)

(65

)%

Natural gas equivalent ($ per Mcfe)(2)

 

4.18

 

8.66

 

(4.48

)

(52

)%

Natural gas equivalent ($ per Mcfe)(3)

 

7.75

 

3.25

 

4.50

 

138

%

Operating Revenue:

 

 

 

 

 

 

 

 

 

Natural gas (2)

 

$

8,928

 

$

28,744

 

$

(19,816

)

(69

)%

Natural gas liquids

 

1,981

 

9,628

 

(7,647

)

(79

)%

Crude oil and condensate (2)

 

2,089

 

8,644

 

(6,555

)

(76

)%

Gain (loss) on derivatives

 

11,068

 

(29,359

)

40,427

 

138

%

Total revenue

 

$

24,066

 

$

17,657

 

$

6,409

 

36

%

 


(1) Prices are calculated based on whole numbers, not rounded numbers.

(2) Excludes the effect of derivative transactions.

(3) Includes the effect of derivative transactions.

 

Production For the quarter ended March 31, 2009, production volumes decreased as compared to the same 2008 period primarily due to normal production declines, asset sales completed during early 2008 and decreased capital re-investment in replacing production as compared to historical levels. The following summarizes our average daily production volumes:

 

 

 

For the Three Months
Ended March 31,

 

 

 

2009

 

2008

 

Production Volumes per Day:

 

 

 

 

 

Natural gas (MMcf/D)

 

24.1

 

41.5

 

Natural gas liquids (MBbls/D)

 

1.1

 

2.1

 

Oil and condensate (MBbls/D)

 

0.7

 

0.9

 

Natural gas equivalent (MMcfe/D)

 

34.5

 

59.7

 

 

Average sales price — Our sales revenue is sensitive to the 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. In recent years, oil and natural gas commodity prices have generally trended upwards in response to robust demand and constrained supplies, with oil and natural gas prices peaking at more than $140.00 per barrel and $13.00 per Mcf, respectively, in July 2008. In the second half of 2008, a world-wide economic recession and oversupply of natural gas in North America led to an unprecedented decline in oil and natural gas prices, with oil falling by more than $100.00 per barrel and natural gas falling more than $10.00 per

 

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Mcf from their peaks in July 2008. This has significantly affected our business, but in 2009 our commodity derivatives have provided some protection against these falling prices, see “Derivative” discussion below. A continued or extended decline in oil or natural gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and natural gas reserves that we can economically produce.

 

Natural gas revenue - For the three months ended March 31, 2009, natural gas revenue, excluding derivative activity, decreased 69% over the same period in 2008 due to both lower average realized prices and production volumes. The overall decrease in production compared to the prior year period resulted in a decrease in revenue of approximately $12.2 million (based on 2008 comparable period pre-derivative prices). The decrease in production was primarily the result of asset sales, normal production declines and reduced reinvestment in replacing or maintaining production to historical levels. The decrease in average price received, excluding derivative activity, resulted in decreased revenue of approximately $7.6 million (based on current period production).  See below for a discussion of the impact of natural gas derivatives on prices and revenue.

 

Natural gas liquids (“NGL”) revenue - For the three months ended March 31, 2009, NGL revenue decreased 79% over the same period in 2008 due to decreases in prices realized and production volumes. The price decrease resulted in a decrease in revenue of approximately $2.9 million (based on current period production).  The decrease in NGL production decreased revenue by approximately $4.7 million (based on 2008 comparable period average prices).

 

Crude oil and condensate revenue - For the three months ended March 31, 2009, oil and condensate sales revenue, excluding derivative activity, decreased 76% from the comparable period in 2008, due to the 65% decrease in prices realized as a result of decreasing crude oil prices in the market and decreased production volumes. The decreased average realized price for oil and condensate for the three months ended March 31, 2009 resulted in a decrease in revenue of approximately $3.9 million (based on current period production). The decrease in oil and condensate production resulted in a decrease in revenue of approximately $2.7 million (based on 2008 comparable period pre-derivative prices). Production volumes for oil and condensate decreased for the three months ended March 31, 2009 compared to the same prior year period due to asset sales, normal production declines and reduced reinvestment in replacing or maintaining production to historical levels. See below for a discussion of the impact of crude oil derivatives on prices and revenue.

 

Derivatives — The volume and price contract terms of our derivative contracts vary from period to period and therefore interact differently with the changing pricing environment, which makes the comparability of the results for each period difficult. In all periods presented, we applied mark-to-market accounting treatment to our derivative contracts; therefore the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in total revenue and will continue to affect total revenue until outstanding contracts expire. Since these gains/losses are not a function of the operating performance of our oil and natural gas assets, excluding their impact from the above discussions helps isolate the operating performance of those assets. The following table summarizes the various components of the total gain or loss on derivatives for each of the periods indicated and the impact each component had on our realized prices:

 

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Table of Contents

 

 

 

Three Months Ended March 31,

 

 

 

2009

 

2008

 

 

 

$

 

$ per unit (1)

 

$

 

$ per unit (1)

 

 

 

(in thousands, except per unit prices)

 

Natural gas derivative contract settlements (Mcf)

 

$

5,125

 

$

2.36

 

$

363

 

$

0.10

 

Crude oil derivative contract settlements (Bbl)

 

723

 

12.22

 

(4,362

)

(51.00

)

Mark-to-market reversal of prior period unrealized change in fair value of gas derivative contracts (Mcf)

 

(13,390

)

(6.17

)

(2,626

)

(0.70

)

Mark-to-market unrealized change in fair value of gas derivative contracts (Mcf)

 

19,238

 

8.87

 

(22,938

)

(6.08

)

Mark-to-market reversal of prior period unrealized change in fair value of oil derivative contracts (Bbl)

 

(2,015

)

(34.08

)

14,955

 

174.85

 

Mark-to-market unrealized change in fair value of oil derivative contracts (Bbl)

 

1,387

 

23.48

 

(14,751

)

(172.47

)

Gain (loss) on derivatives (Mcfe)

 

$

11,068

 

$

3.57

 

$

(29,359

)

$

(5.41

)

 


(1) Prices per unit are calculated based on whole numbers, not rounded numbers.

 

Should crude oil or natural gas prices increase or decrease from the current levels, it could materially impact our revenues. In a high price environment, hedged positions could result in lost opportunities if there is a cap in place, thus lowering our effective realized prices on hedged production, but in an environment of falling prices, these transactions offer some pricing protection for hedged production.

 

Costs and Operating Expenses

 

The table below details our expenses:

 

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Table of Contents

 

 

 

 

 

 

 

2009 Period Compared
to 2008 Period

 

 

 

Three Months Ended
March  31,

 

$
Increase

 

%
Increase

 

 

 

2009

 

2008

 

(Decrease)

 

(Decrease)

 

 

 

(in thousands, except percentages)

 

Oil and natural gas operating expenses

 

$

3,825

 

$

4,472

 

$

(647

)

(14

)%

Severance and ad valorem taxes

 

1,091

 

2,185

 

(1,094

)

(50

)%

Depletion, depreciation, amortization and accretion:

 

 

 

 

 

 

 

 

 

Oil and natural gas property and equipment

 

9,804

 

27,088

 

(17,284

)

(64

)%

Other assets

 

176

 

193

 

(17

)

(9

)%

ARO accretion

 

99

 

90

 

9

 

10

%

Impairment of oil and natural gas properties

 

78,254

 

 

78,254

 

100

%

General and administrative expenses

 

4,595

 

4,060

 

535

 

13

%

Total operating expenses

 

$

97,844

 

$

38,088

 

$

59,756

 

157

%

 

 

 

 

 

 

 

 

 

 

Other income and expense, net

 

3,162

 

4,394

 

(1,232

)

(28

)%

Income tax benefit

 

 

(8,646

)

8,646

 

100

%

Preferred stock dividends

 

 

2,066

 

(2,066

)

(100

)%

 

Oil and natural gas operating expenses - Oil and natural gas operating expenses include direct operating costs, repairs and maintenance and workover expenses. For the three months ended March 31, 2009, operating expenses decreased primarily as a result of properties we sold effective March 1, 2008. Partially offsetting this decrease were increases due to higher expensed workovers and higher costs for compressor rent, gas processing, and salt-water disposal. Average oil and natural gas operating expenses were $1.23 per Mcfe and $0.82 per Mcfe for the three months ended March 31, 2009 and 2008, respectively. On a per