Edge Petroleum 10-Q 2007
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the transition period from to
Commission file number 0-22149
EDGE PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
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 o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filed, or a non-accelerated filer. See definition of accelerated filer and larger accelerated filer in Rule 12b-2 of the Exchange Act.:
o Large accelerated filer xAccelerated filer o Non-accelerated filer
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of the latest practicable date.
EDGE PETROLEUM CORPORATION
Table of Contents
EDGE PETROLEUM CORPORATION
See accompanying notes to consolidated financial statements.
EDGE PETROLEUM CORPORATION
See accompanying notes to consolidated financial statements.
EDGE PETROLEUM CORPORATION
See accompanying notes to the consolidated financial statements.
EDGE PETROLEUM CORPORATION
See accompanying notes to consolidated financial statements
EDGE PETROLEUM CORPORATION
See accompanying notes to consolidated financial statements
EDGE PETROLEUM CORPORATION
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The financial statements included herein have been prepared by Edge Petroleum Corporation, a Delaware corporation (we, our, us or the Company), without audit pursuant to the rules and regulations of the Securities and Exchange Commission (SEC), and reflect all adjustments which are, in the opinion of management, necessary to present a fair statement of the results for the interim periods on a basis consistent with the annual audited consolidated financial statements. All such adjustments are of a normal recurring nature. The results of operations for the interim periods are not necessarily indicative of the results to be expected for an entire year. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. These financial statements should be read in conjunction with our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2006.
Oil and Natural Gas Properties - Investments in oil and natural gas properties are accounted for using the full-cost method of accounting. The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful-efforts method and the full-cost method. There are several significant differences between these methods. Among these differences is that, under the successful-efforts method, costs such as geological and geophysical (G&G), exploratory dry holes and delay rentals are expensed as incurred whereas under the full-cost method these types of charges are capitalized to their respective full-cost pool. In 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 Companys 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 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, 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 Companys quarterly and annual SEC filings. No ceiling test impairment was required during the quarters ended June 30, 2007 or 2006.
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 9), therefore the ceiling test at June 30, 2007 and 2006 was 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 (NGLs) 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. Oil and natural gas properties included costs of $95.0 million and $57.6 million at June 30, 2007 and December 31, 2006, respectively, related to unproved property, which were excluded from capitalized costs being amortized.
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, Trade includes an allowance for doubtful accounts of $0.2 million and $0.5 million at June 30, 2007 and December 31, 2006, respectively. Accounts Receivable, Joint Interest Owners includes an allowance for doubtful accounts of $3,200 at both June 30, 2007 and December 31, 2006.
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 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 six months ended June 30, 2007 and 2006 are as follows:
During the six months ended June 30, 2007, ARO liabilities incurred include 178 new well obligations, including the newly acquired properties from Smith Production Inc. (see Note 10) and liabilities settled include four wells that were plugged.
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 six months ended June 30, 2007 was approximately $1.5 million, of which $1.2 million is included in general and
administrative expenses (G&A) and $295,300 is capitalized to oil and natural gas properties. Share-based compensation for the six months ended June 30, 2006 was approximately $633,300, of which $463,400 was included in G&A and $169,900 was capitalized to oil and natural gas properties.
During the six months ended June 30, 2007, 259,400 restricted stock units (RSUs) were granted. At June 30, 2007, 586,500 RSUs were outstanding, all of which are classified as equity instruments. No options were granted during the six months ended June 30, 2007. During the first half of 2007, 2,000 options were exercised, resulting in 648,700 options outstanding at period end.
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 take 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 No. FIN 48-1, Definition of Settlement in FASB Interpretation No. 48 (FSP FIN 48-1) as of January 1, 2007. FSP FIN 48-1 provides that a companys 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 7).
Accounting Pronouncements In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FAS Statement No. 115. SFAS No. 159 gives companies the option of applying at specified election dates fair value accounting to certain financial instruments and other items that are not currently required to be measured at fair value. If a company chooses to record eligible items at fair value, the company must report unrealized gains and losses on those items in earnings at each subsequent reporting date. SFAS No. 159 also prescribes presentation and disclosure requirements for assets and liabilities that are measured at fair value pursuant to this standard and pursuant to the guidance in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended). SFAS No. 159 will be effective for fiscal year 2008. As the provisions of SFAS No. 159 are applied prospectively, the impact on the Company will depend on the instruments selected for fair value measurement at the time of implementation.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which provides guidance for using fair value to measure assets and liabilities. The standard also gives expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS No. 157 does not expand the use of fair value in any new circumstances. SFAS No. 157 establishes a fair value hierarchy that prioritizes the information used to develop fair value assumptions. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Early adoption is encouraged. The Company is currently assessing the impact, if any, that SFAS No. 157 will have on its financial statements.
Reclassifications - Certain reclassifications of prior period statements have been made to conform to current reporting practices.
2. LONG-TERM DEBT
On January 30, 2007, the Company terminated its Third Amended and Restated Credit Agreement (the Prior Credit Facility), which it had originally entered into in March 2004 (effective December 31, 2003). The Prior Credit Facility was scheduled to mature on March 31, 2008 and had a borrowing base of $140.0 million, of which $129.0 million was outstanding as of January 30, 2007.
On January 30, 2007, the Company entered into a Fourth Amended and Restated Credit Agreement (the Agreement) for a new Revolving Credit Facility with Union Bank of California (UBOC), as administrative agent and issuing lender, and the other lenders party thereto. Pursuant to the Agreement, UBOC acts as the administrative agent for a senior, first lien secured borrowing base revolving credit facility (the Revolving Facility) in favor of the Company and certain of its wholly-owned subsidiaries in an amount equal to $750 million,
of which only $320 million is available under the borrowing base established at the closing. The Revolving Facility has a letter of credit sub-limit of $20 million. In connection with the Revolving Facility, the Company paid the lenders fees in an amount equal to 1.00% of the initial borrowing base established under the Revolving Facility, or $3.2 million, on January 31, 2007. The Company also paid approximately $0.6 million for certain other administrative fees, legal fees, fronting fees and work fees in connection with the Revolving Facility. The aggregate fees of $3.8 million (of which $0.1 million was paid in December 2006) were recorded to deferred loan costs and are being amortized over the maturity of the Revolving Facility.
The Revolving Facility matures on January 31, 2011 and bears interest at LIBOR plus an applicable margin ranging from 1.25% to 2.5% or Prime plus a margin of up to 0.25%, with an unused commitment fee ranging from 0.50% to 0.25%. At June 30, 2007, all of the Companys outstanding borrowings were LIBOR based, consisting of two tranches of borrowings at interest rates of 7.10% and 7.09%. As of June 30, 2007, $230 million in total borrowings were outstanding under the Revolving Facility. The Companys available borrowing capacity under the Revolving Facility was $90 million at June 30, 2007. The borrowing base of $320 million was reconfirmed by the lenders during the second quarter of 2007.
The Revolving Facility is secured by substantially all of the Companys 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 and certain distributions of cash or properties and certain liens and also contains financial covenants including, without limitation, the following:
· An EBITDAX to interest expense ratio requires that as of the last day of each fiscal quarter the ratio of (a) Edges consolidated EBITDAX (defined as EBITDA plus similar non-cash items and exploration and abandonment expenses for such period) to (b) Edges consolidated interest expense, not be less than 2.5 to 1.0, calculated on a cumulative quarterly basis for the first 12 months after the closing of the Revolving Facility and then on a rolling four quarter basis.
· A current ratio requires that as of the last day of each fiscal quarter the ratio of Edges consolidated current assets to Edges consolidated current liabilities, as defined in the Revolving Facility, be at least 1.0 to 1.0.
· A maximum leverage ratio requires that as of the last day of each fiscal quarter the ratio of (a) Total Indebtedness (as defined in the Agreement) to (b) an amount equal to consolidated EBITDAX be not greater than 3.0 to 1.0, calculated on a cumulative quarterly basis for the first 12 months after the closing of the Revolving Facility and then on a rolling four quarter basis.
Consolidated EBITDAX is a component of negotiated covenants with our lender and is discussed here as part of the Companys disclosure of its covenant obligations. The Revolving Facility includes other covenants and events of default that are customary for similar facilities.
In December 2006, UBOC provided the Company a commitment letter for a $250 million senior, second lien secured bridge loan facility (the Bridge Loan Facility). The Bridge Loan Facility, along with the Revolving Facility, were intended to replace the Companys Prior Credit Facility and to fund the closing of the Smith Acquisition (see Note 10) if the Company was unable to complete one or both of its intended public offerings. Due to the successful completion of the public offering of common stock and 5.75% Series A cumulative convertible perpetual preferred stock on January 30, 2007, the Company did not enter into the Bridge Loan Facility. The Company paid an amount equal to 0.50% of the commitment under the Bridge Loan Facility, or $1.3 million, on January 31, 2007, which is included in interest expense.
3. SHELF REGISTRATION STATEMENT
During the second quarter 2005, the Company filed a registration statement with the SEC which registered securities of up to $390 million of any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities of the Company. 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 Companys 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 Companys securities at prices acceptable to the Company. In July 2007, the Company replaced this shelf registration statement with a new shelf registration statement, which registered offerings of up to $500 million of securities (see Note 4).
In January 2007, the Company completed an offering of 10.925 million shares of its common stock and 2.875 million shares of 5.75% Series A cumulative convertible perpetual preferred stock. The shares were offered to the public at a price of $13.25 per share of common stock and $50.00 per share of preferred stock. The Company received net proceeds of approximately $276.5 million from the offerings ($138.1 million from the common offering and $138.4 from the preferred offering), after deducting underwriting discounts and commissions and the expenses of the offerings.
4. SUBSEQUENT EVENT
On July 12, 2007, the Company filed an amendment to a registration statement filed with the SEC in the second quarter of 2007 that registered securities of up to $500 million of any combination of debt securities, preferred stock, common stock or warrants for debt securities or equity securities of the Company and guarantees of debt securities by the Companys subsidiaries. The shelf registration statement replaces a previous shelf registration statement, which registered offerings of up to $390 million of securities, as discussed in Note 3. 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 Companys 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 Companys securities at prices acceptable to the Company. As of August 9, 2007, the Company had $500 million available under its current shelf registration statement.
5. PREFERRED STOCK
The Company completed the public offering of 2,875,000 shares of its 5.75% Series A cumulative convertible perpetual preferred stock (Convertible Preferred Stock) in January 2007.
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 Companys debt agreements, assets are legally available to pay dividends and the board of directors or an authorized committee of its board declares a dividend payable, the Company will pay dividends in cash, every quarter. The first payment was made on April 15, 2007 for the partial period from issuance through April 15, 2007, and the second payment, which was the first full quarterly dividend, was paid on July 16, 2007.
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 therefore have been set apart on the Convertible Preferred Stock and any parity shares.
Liquidation preference. In the event of the Companys 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 Companys 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 Companys 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;
· on a parity with all of the Companys 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 Companys 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 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 Companys 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 Companys 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 Companys 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 herein), 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 Companys 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, disclosing that the person or group has become the direct or indirect ultimate beneficial owner of the Companys 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 provision in subsection 2 below;
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 Companys 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 our 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.
6. EARNINGS PER SHARE
The Company accounts for earnings per share in accordance with SFAS No. 128, Earnings per Share, which establishes the requirements for presenting earnings per share (EPS). SFAS No. 128 requires the presentation of basic and diluted EPS on the face of the 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 and warrants having exercise prices less than the average market price of the common stock during the periods, using the treasury stock method.
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 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. The following tables present the computations of EPS for the periods indicated:
In the calculation of diluted EPS for the six months ended June 30, 2007, the Companys 5.75% Series A cumulative convertible perpetual preferred stock has been excluded from the computation, because if-converted, the resulting 8.7 million shares are anti-dilutive.
7. INCOME TAXES
The Company accounts for income taxes under the provisions of SFAS No. 109, Accounting for Income Taxes, which provides for an asset and liability approach in accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributable to temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes.
The Company currently estimates that its effective tax rate for the year ending December 31, 2007 will be approximately 36.34%. A provision for income taxes of $2.8 million (36.34% of pre-tax income) and $6.9 million (35.1% of pre-tax income) were reported for the six months ended June 30, 2007 and 2006, respectively. The Companys income tax provisions are primarily non-cash as the Company has NOL carryforwards available that were generated from drilling activity. Currently the Company anticipates that it will pay a small amount of federal alternative minimum and current state income tax in 2007. The Company was required to pay federal alternative minimum taxes of $94,100 in the first six months of 2006.
In June 2006, the FASB issued FIN 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109, which clarifies the accounting for uncertainty in income taxes recognized in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. FIN 48 also requires that the amount of interest expense to be recognized related to uncertain tax positions be computed by applying the applicable statutory rate of interest to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken in a tax return. The Company also adopted FSP FIN 48-1 as of January 1, 2007, which provides that a companys 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. At January 1, 2007, the Company recorded the cumulative effect of the change in accounting principle as a $534,035 decrease in the opening balance of retained earnings. The Company had no reserves prior to adoption at January 1, 2007. The Company recognizes interest and penalties related to unrecognized tax benefits in tax expense. However, the Company has accrued no interest or penalties at June 30, 2007.
8. 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:
For the six months ended June 30, 2007 and 2006, the non-cash portion of Asset Retirement Costs was $0.9 million and $0.2 million, respectively. Dividends declared but not yet paid were $1.7 million for the six months ended June 30, 2007, and none for the same prior year period. A supplemental disclosure of cash flow information is presented below:
9. HEDGING AND DERIVATIVE ACTIVITIES
Due to the volatility of oil and natural gas prices, the Company periodically enters into price-risk management transactions (e.g. swaps, collars and floors) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from commodity price fluctuations. While the use of these arrangements limits the Companys ability to benefit from increases in the price of oil and natural gas, it also reduces the Companys potential exposure to adverse price movements. The Companys arrangements, to the extent it enters into any, apply to only a portion of its production and provide only partial price protection against declines in oil and natural gas prices and limit the Companys potential gains from increases in prices. None of these instruments are used for trading purposes. The use of derivative instruments involves the risk that the counterparties to such instruments will be unable to meet the financial obligations of such contracts. On a quarterly basis, the Companys management reviews all of the Companys 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 monitors the Companys price-risk management policies and trades on a monthly basis.
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 Companys price risk and may be considered hedges for economic purposes, but certain of these transactions may not qualify for cash flow hedge accounting. All derivative instrument contracts are recorded on the balance sheet at fair value and the cash flows resulting from settlement of these derivative transactions are classified in operating 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 on the balance sheet. Rather they are immediately recorded in total revenue on the statement of operations. For those derivatives 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 other comprehensive income 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 as they occur. When the hedged production is sold, the realized gains and losses on the contracts are removed from other comprehensive income and recorded in revenue. While the contract is outstanding, the unrealized and ineffective 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 following table reflects the realized and unrealized gains and losses included in revenue on the statement of operations:
The fair value of outstanding derivative contracts reflected on the balance sheet were as follows:
(1) The Companys natural gas collars 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 Companys crude oil collars were 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 these contracts and the change in fair value is reflected in total revenue.
(3) Subsequent to December 31, 2006, the two natural gas collars entered into in August 2006 covering a portion of our 2007 estimated production were terminated at no cost to the Company and replaced with the new collars entered into January 2007.
10. ACQUISITIONS & DIVESTITURES
Smith Acquisition - On November 16, 2006, the Company entered into two separate purchase and sale agreements (both of which were subsequently amended) with Smith Production Inc. (Smith) for (A) (i) ownership interests in certain oil and gas properties located in 13 counties in southeast and south Texas, consisting of approximately 150 gross (74 net) producing wells from Smith and eight other owners who transferred their interests to Smith prior to the closing, (ii) an ownership interest in approximately 17,000 gross (12,250 net) developed acres and 56,000 gross (16,000 net) undeveloped acres of leasehold, (iii) 25% of Smiths option and leasehold rights and exploration and development rights in an approximate 95 square mile exploration project area known as the Mission project area, also in south Texas, and (iv) certain gathering facilities and ownership of approximately 13 miles of natural gas gathering pipelines and related infrastructure serving certain producing assets in southeast Texas ((i) through (iv) collectively referred to as the Smith Properties); and (B) working interest, option and leasehold rights in two exploration ventures in separate areas, primarily in Texas, from Smith (the Smith Ventures and collectively with the Smith Properties, the Properties). The combined cash purchase price paid at closing on January 31, 2007 was approximately $379.8 million for the Smith Properties and $10.0 million for the Smith Ventures (which includes the deposit paid in December 2006). The purchase price for the Smith Properties was adjusted from the base purchase price of $385 million for, among other things, the results of operations of the Smith Properties between the January 1, 2007 effective date and the January 31, 2007 closing date. Accordingly, the Company's consolidated results of operations include the Smith Properties beginning February 1, 2007. The Company expects further adjustments to the purchase price pursuant to the post-closing adjustment provisions of the amended purchase and sale agreements. The Company financed the purchase price of the Smith Acquisition through public offerings of common and preferred stock (see Note 3) and borrowings under its Revolving Facility (see Note 2). The Company also capitalized approximately $0.7 million in other direct costs resulting from the acquisition and assumed ARO liabilities of $0.9 million.
The following unaudited pro forma results for the three and six months ended June 30, 2006 show the effect on the Company's consolidated results of operations as if the Smith Acquisition had occurred on January 1, 2006. The unaudited pro forma results for the six months ended June 30, 2007 show the effect on the Companys consolidated results of operations as if the Smith Acquisition had occurred on January 1, 2007. The pro forma results for the 2006 and 2007 periods presented are the result of combining the statement of income for the Company with the revenues and direct operating expenses of the Smith properties acquired adjusted for (1) assumption of ARO liabilities and accretion expense for the properties acquired, (2) depletion expense applied to the adjusted basis of the properties acquired using the purchase method of accounting, (3) depreciation expense for other non-oil and gas assets acquired, (4) interest expense on added borrowings necessary to finance the acquisition, (5) amortization of deferred loan costs for new loan costs related to the financing of the acquisition, (6) dividends payable on the Convertible Preferred Stock, (7) the related income tax effects of these adjustments based on the applicable statutory rates, and (8) the impact of common and preferred shares issued in public offerings completed to partially finance the Smith Acquisition. The pro forma information is based upon numerous assumptions, and is not necessarily indicative of future results of operations:
Chapman Ranch Field Acquisition in 2006 - On December 12, 2006, the Company executed an agreement to acquire certain working interests in the Chapman Ranch Field in Nueces County, Texas from Kerr-McGee Oil & Gas Onshore LP (Kerr-McGee), a wholly-owned subsidiary of Anadarko Petroleum Corporation. In late 2005, the Company acquired non-operated working interests in certain wells in this field. Upon the closing of the Kerr-McGee acquisition on December 28, 2006, the Company assumed the role of operator of the Chapman Ranch Field. The base purchase price of the acquisition was $26.0 million. The purchase price was preliminarily adjusted at closing to approximately $25.0 million (including a previously paid deposit of $2.6 million) as a result of adjustments to the purchase price for the results of operations between the December 1, 2006 effective date and the December 28, 2006 closing date, and other purchase price adjustments. There may be post-closing adjustments to the purchase price for results of operations between the effective date and closing date as further information becomes available. The Company financed the purchase price of the Kerr-McGee acquisition through $24.0 million in borrowings under its Prior Credit Facility.
Divestitures - During January 2007, the Company divested a portion of its interest in a Louisiana well for a sales price of $1.1 million.
11. COMMITMENTS AND CONTINGENCIES
From time to time the Company is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, the Company is not currently a party to any proceeding that it believes, if determined in a manner adverse to the Company, could have a material adverse effect on its financial condition, results of operations or cash flows, except as set forth below.
Wade and Joyce Montet, et al., v. Edge Petroleum Corp of Texas, et al., consolidated with Rolland L. Broussard, et al., v. Edge Petroleum Corp of Texas, et al. - This is a consolidated suit, filed in state court in Vermilion Parish, Louisiana in September 2003. Plaintiffs are mineral/royalty owners under the Norcen-Broussard No. 1 and 2 wells, Marg Tex Reservoir C, Sand Unit A (Edges old Bayou Vermilion Prospect). They claim the operator at the time, Norcen Explorer, now Anadarko E&P Company (Anadarko), failed to block squeeze the sections of the No. 2 well, as a prudent operator, according to their allegations, would have done, to protect the gas reservoir from being flooded with water from adjacent underground formations. Plaintiffs further allege Norcen was negligent in not creating a field-wide unit to protect their interests. The allegations relate to actions taken beginning in the early 1990s. Plaintiffs have named the Company and other working interest owners in the leases as defendants, including Norcen Explorers successors in interest, Anadarko. Plaintiffs originally sought unspecified damages for lost royalties and damages due to alleged devaluation of their mineral and property interests, plus interest and attorneys fees. In early 2005, the Company filed a motion for summary judgment in the case asserting, among other defenses, that: (i) there has been no breach of contract, (ii) there is no express or implied duty imposed on the Company to block squeeze the well or form a field-wide unit, (iii) the units were properly formed by the Conservation Commissioner in accordance with the statutory scheme in Louisiana, (iv) plaintiffs claims are barred
by limitations, and (v) other defenses. Along with the other defendants, the Company also filed a special peremptory challenge of no cause of action under the leases and the Louisiana Mineral Code for failure to exhaust administrative remedies and due to lack of a demand. In May and June 2005, the court ruled against the Company on the motion for summary judgment and the peremptory challenges. Of the 18.75% after-payout working interest that was originally reserved in the leases, the Company owned a 2.8% working interest at the time of the alleged acts or omissions. On September 6, 2005, the Company filed a third-party demand to join the other working interest owners who hold the remainder of the 18.75% working interest as third-party defendants in this case. These third-parties consist, for the most part, of partnerships that are directly or indirectly controlled by John Sfondrini, a director of the Company, and hold an aggregate 14.7% working interest (the Sfondrini Partnerships). Vincent Andrews, also a director of the Company, owns a minority interest in the corporate general partner of one of the partnerships. The Sfondrini Partnerships consist of (1) Edge Group Partnership, a general partnership composed of limited partnerships of which Mr. Sfondrini and a company controlled by Mr. Sfondrini are general partners; (2) (A) Edge Option I Limited Partnership, (B) Edge Option II Limited Partnership and (C) Edge Option III Limited Partnership, limited partnerships of which Mr. Sfondrini and a company controlled by Mr. Sfondrini are general partners; and (3) BV Partners Limited Partnership, a limited partnership of which a company controlled by Messrs. Sfondrini and Andrews is general partner and of which Mr. Sfondrini is manager (and of which company Mr. Andrews is an officer). These partnerships were among the third party defendants that the Company has sought to join in the case, and these partnerships have for the most part filed answers denying any liability to the Company. The Company participated for its 2.8% share of the well costs and revenues for the Broussard No. 2 well, as did the other defendants for their share, including the third-party defendant partnerships who participated for 14.7%. The Company strongly believes the parties should only be liable for their proportionate share of any damages awarded should a finding of liability occur in the case. The Company intends to vigorously contest the plaintiffs claims.
As of the date of this report, it is not possible to determine what, if any, the Companys ultimate exposure might be in this matter. Prior to the settlement described below, plaintiffs had asserted damages, including interest, to be as high as $63 million. The plaintiffs expert witness, in his December 2005 deposition, offered his theory that plaintiffs gross damages are in the range of $19 to $22 million. That number is based on his theory that the alleged failure to block squeeze the well resulted in the under-production of gas worth $300 million. Plaintiffs royalty share of that figure yields the $19 to $22 million range of alleged damages. Based on the experts testimony, damages attributable to the full 18.75% interest would be in the range of $3.75 million gross or net to our 2.8% share would be in the range of $560,000 (excluding interest and attorneys fees). Along with the other defendants, the Company hired its own expert witnesses who have refuted these claims, particularly the experts assertions that failure to block squeeze the well caused any damages to the reservoir. The deposition of a Norcen engineer who prepared the completion plan for the Broussard No. 2 well and supervised the completion operations, taken in April 2006, confirms the testimony of the defense experts as to why the well was not block squeezed. The plaintiffs have also retained a damages expert who has given a report that the damages in this case are in the range of $30 million, excluding interest and attorneys fees. The Companys share of that amount based on the full 18.75% would be approximately $5.6 million and net to our 2.8% share would be approximately $840,000. The Company participated in mediation of this lawsuit on July 18, 2006 but the parties failed to reach an agreement. In July 2006, the plaintiffs attorney sent a demand to the defendants for total damages claimed by plaintiffs, with legal interest, totaling $63 million. The Companys share of that amount based on the full 18.75% interest would be approximately $12.2 million and net to our 2.8% interest would be approximately $1.8 million. On July 31, 2006, the Judge granted the defendant groups motion for partial summary judgment dismissing plaintiffs tort-based claims. Also on the same date, the Judge granted the defendant groups motion for partial summary judgment seeking to deny the plaintiffs an award of attorneys fees and also to dismiss any claim of plaintiffs that defendants had an obligation to form a field-wide unit.
On December 19, 2006, the Company, along with the other defendants in this suit, reached a settlement agreement with the Broussard Plaintiffs in full settlement of their 72% of the total claims made in this consolidated action. This settlement was finalized in January 2007. The Companys share of this settlement totaled approximately $208,000, which was recorded in December 2006, and the Sfondrini Partnerships share totaled $1,109,759. The settlement with the Broussard Plaintiffs was finalized on February 1, 2007, and the defendants and the third-party defendants including the Sfondrini Partnerships were released from all claims by the Broussard Plaintiffs.
The Company and the other oil company defendants participated in a mediation regarding the remaining claims in this lawsuit with the Montet plaintiffs on May 10, 2007. All remaining claims were settled for a total agreed payment to the Montet plaintiffs of $3.5 million. The Companys and the Sfondrini Partnerships share of the settlement amount were $118,333 and $502,917, respectively, for a total of $621,250, which amounts were paid by insurance. As part of the settlement, Mid-Continent Casualty Company and one other insurer agreed to cover and pay the full share of the Montet settlement amount attributable to the Company and the Sfondrini Partnerships in return for mutual releases under the policies involved and for a joint dismissal of all claims asserted by the parties in the suit for declaratory judgment filed by Mid-Continent against the Company and the Sfondrini Partnerships in federal district court in Houston. Also as part of the settlement, the Company reimbursed the Sfondrini Partnerships for certain attorneys fees in the amount of $62,500. The settlement with the Montet plaintiffs was finalized in writing in June 2007, all defendants have paid their respective shares of the amounts owed, and the plaintiffs and defendants filed a joint motion to dismiss with the court on August 3, 2007.
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 Childrens 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 at least five leases 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 the Company 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 tortuous 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 has served plaintiffs with discovery and has filed a counterclaim and an amended counterclaim joining various related entities that are controlled by plaintiffs. In addition, plaintiffs have filed an amended complaint alleging claims of slander of title and tortuous interference related to its alleged right to receive an overriding royalty interest from a third party. Plaintiffs currently have on file an amended motion for summary judgment, to which the Company has filed a response. In addition, the Company has filed a motion for summary judgment on the plaintiffs case. In December 2006, the court denied the Companys motion for summary judgment. The court has not ruled on Blakes motion. The trial was scheduled to begin September 10, 2007, but has been passed and the new trial has been set for March 3, 2008. Discovery in the case has commenced and is continuing. The Company has responded aggressively to this lawsuit, and believes it has meritorious defenses and counterclaims.
The following is Managements 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, 2006 (2006 Annual Report).
FORWARD LOOKING STATEMENTS
Certain of the statements contained in all parts of this document, including, but not limited to, those relating to our drilling plans (including scheduled and budgeted wells), the effect of changes in strategy and business discipline, future tax matters, our 3-D project portfolio, future general and administrative expenses on a per unit of production basis, changes in wells operated and reserves, future growth and expansion, future exploration, future seismic data (including timing and results), expansion of operation, our ability to generate additional prospects, our review of outside prospects and acquisitions, additional reserves and reserve increases, our ability to replace production and manage our asset base, enhancement of visualization and interpretation strengths, expansion and improvement of capabilities, integration of new technology into operations, credit facilities, redetermination of our borrowing base, attraction of new members to the technical team, future compensation programs, new focus on core areas, new prospects and drilling locations, new alliances, future capital expenditures (or funding thereof) and working capital, sufficiency of future working capital, borrowings and capital resources and liquidity, projected rates of return, retained earnings and dividend policies, projected cash flows from operations, future commodity price environment, expectation or timing of reaching payout, the outcome, effects or timing of any legal proceedings or contingencies, the impact of any change in accounting policies on our financial statements, the number, timing or results of any wells, the plans for timing, interpretation and results of new or existing seismic surveys or seismic data, future production or reserves, future acquisition of leases, lease options or other land rights, any other statements regarding future operations, financial results, opportunities, growth, business plans and strategy and other statements that are not historical facts are forward-looking statements. These forward-looking statements reflect our current view of future events and financial performance. When used in this document, the words budgeted, anticipate, estimate, expect, may, project, believe, intend, plan, potential, forecast, might, predict, should and similar expressions are intended to be among the expressions that identify forward-looking statements. These forward-looking statements speak only as of their dates and should not be unduly relied upon. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, or otherwise. Such statements involve risks and uncertainties, including, but not limited to, those set forth under ITEM 1A. RISK FACTORS of our 2006 Annual Report and other factors detailed in this document and our other filings with the Securities and Exchange Commission (the SEC). Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties.
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 our current strategy which focuses on a balanced program of exploration, exploitation and development and acquisition of oil and gas properties. We generate revenues, income and cash flows by producing and marketing oil and natural gas produced from our oil and natural gas properties. We make significant capital expenditures in our exploration, development, and production activities that allow us to continue generating revenue, income and cash flows. We have also spent considerable
efforts on acquisitions, including both corporate and asset acquisitions, which have contributed to our growth in recent years.
This overview provides our perspective on the individual sections of MD&A. Our MD&A includes the following sections:
· Industry and Economic Factors a general description of value drivers of our business as well as opportunities, challenges and risks related to the oil and gas industry.
· Approach to the Business information regarding our approach and strategy.
· Acquisitions and Divestitures information about significant changes in our business structure.
· Outlook discussion relating to managements outlook to the future of our business.
· Critical Accounting Policies and Estimates a discussion of certain accounting policies that require critical judgments and estimates.
· Results of Operations an analysis of our consolidated results for the periods presented in our financial statements.
· Liquidity and Capital Resources an analysis of cash flows, sources and uses of cash, and contractual obligations.
· Risk Management Activities Derivatives & Hedging supplementary information regarding our 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.
Industry and Economic Factors
In managing our business, we must deal with many factors inherent in our industry. First and foremost is the fluctuation of oil and natural gas prices. Historically, oil and gas markets have been cyclical and volatile, which makes future price movements difficult to predict. While our revenues are a function of both production and prices, wide swings in commodity prices have most often had the greatest impact on our results of operations. We have little ability to predict those prices or to control them without losing some advantage of the upside potential.
Our operations entail significant complexities. Advanced technologies requiring highly trained personnel are utilized in both exploration and production. Even when the technology is properly used, we may still not know conclusively if hydrocarbons will be present or the rate at which they will be produced. Exploration is a high-risk activity, often times resulting in no commercially productive reserves being discovered. Moreover, costs associated with operating within our industry are substantial. The high commodity price environment in 2005 led to increased demand for oilfield equipment and services and increased costs in our industry, and in 2006, we saw natural gas prices decline while operating costs continued to increase. These factors have made it difficult at times for us to further our growth, and made timely execution of our planned activities difficult. Since late 2006, costs for drilling rigs in our core areas have decreased and the availability of services, including rigs, has increased.
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.
The oil and gas industry is highly competitive. We compete with major and diversified energy companies, independent oil and gas businesses and individual operators in exploration, production, marketing and acquisition activities. In addition, the industry as a whole competes with other businesses that supply energy to industrial and commercial end users.
Extensive federal, state and local regulation of the industry significantly affects our operations. In particular, our activities are subject to stringent operational and environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and gas wells and related facilities. These regulations may become more demanding in the future.
Approach to the Business
Profitable growth of our business will largely depend upon our ability to successfully find and develop new proved reserves of oil and natural gas in a cost-effective manner. In order to achieve an overall acceptable rate of growth, we seek to maintain a prudent blend of low, moderate and higher risk exploration and development projects. We have chosen to seek geologic and geographic diversification by operating in multiple basins in order to mitigate risk in our operations. We also attempt to make selected acquisitions of oil and gas properties to augment our growth and provide future drilling opportunities.
We periodically hedge our exposure to volatile oil and natural gas prices on a portion of our production to reduce price risk. As of June 30, 2007, we had derivative contracts in place covering approximately 59% of our remaining expected 2007 natural gas production and 65% of our remaining expected 2007 crude oil production. As of June 30, 2007, approximately 53% of total remaining 2007 estimated production on an Mcfe basis (including natural gas liquids) was hedged with derivative contracts. As of June 30, 2007, we also had derivative contracts in place covering approximately 46% and 75% of our anticipated 2008 natural gas and crude oil production, respectively, while less than 10% of our total expected 2009 natural gas production and none of our expected 2009 crude oil production was hedged. All of such estimated production is before any new acquisitions that may occur.
Generally, our goal is to fund ongoing exploration and development projects with cash flow provided by operating activities, occasionally supplemented with external sources of capital. During the first quarter of 2007, our Board approved a 2007 capital budget of approximately $140 million. Based upon current expectations for production volumes and commodity prices, we expect to fund our capital program with internally-generated cash from operating activities and borrowings under our Revolving Facility (as defined below). We do not typically include acquisitions in our budgeted capital expenditures, but expect to utilize either borrowings under our Revolving Facility, proceeds from offerings of common stock or other securities under our shelf registration statement or other sources to fund those potential acquisitions.
Our long-term debt balance as of June 30, 2007 was $230 million and our debt-to-total capital ratio was 34.6%.
Acquisitions and Divestitures
Acquisitions - We have become increasingly active in acquisitions in recent years. We have looked to acquisitions to enable us to achieve our growth objectives and we expect acquisitions will continue to play a significant role in our future plans for growth. Acquisitions add meaningful incremental increases in reserves and production and may range in size from acquiring a working interest in non-operated producing property to acquiring an entire field of wells or a company. Unlike drilling capital, which is planned and budgeted, acquisition capital is neither budgeted nor allocated, because the specific timing or size of acquisitions cannot be predicted. Although we consider a wide variety of acquisitions, a significant part of our growth strategy is expected to be focused toward producing property acquisitions, which we believe have exploitable potential. We try to maintain enough financial flexibility such that we are positioned to take advantage of producing property acquisition opportunities as they may arise. We believe through hard work, technical ability and creative thinking of our people, we will continue to grow through both acquisitions and drilling. Any such acquisition could involve the payment by us of a substantial amount of cash or the issuance of a substantial number of additional shares or other securities.
Smith Acquisition - During the first quarter of 2007, we completed the largest acquisition in our history. We acquired oil and natural gas properties, exploration rights, leasehold acreage, gathering facilities and gathering pipelines from Smith Production Inc. for a cash purchase price of approximately $389.8 million. Pursuant to closing adjustment provisions in the agreements, the purchase price is subject to adjustment for the results of operations between the January 1, 2007 effective date and the January 31, 2007 closing date. We have agreed to extend the deadline for the adjustment, which we expect to finalize in the third quarter of 2007. The properties acquired are located in south and southeast Texas, which we consider to be our main core area of operations. This acquisition had a substantial impact to our reserves, production revenues, operating costs, and property base. We have increased staffing levels to manage the growth and help with the integration of these assets into our operations.
Chapman Ranch Acquisition - During the fourth quarter of 2006, we completed the acquisition of additional working interests in the Chapman Ranch Field, in which we also acquired interests from two other companies during the fourth quarter of 2005. We also assumed the role of operator of these properties as a result of this acquisition. The preliminary adjusted purchase price was approximately $25.0 million. Pursuant to closing adjustment provisions in the agreements, the purchase price is subject to further adjustment for the results of operations between the December 1, 2006 effective date and the December 28, 2006 closing date, which we expect to finalize in the third quarter of 2007. The properties acquired are located in Nueces County, Texas and consisted of nine producing wells and an ownership in approximately 1,200 net acres of developed and undeveloped leasehold.
Divestitures - We regularly review our asset base for the purpose of identifying non-core assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. While we generally do not dispose of assets solely for the purpose of reducing debt, such dispositions can have the result of furthering our objective of financial flexibility through reduced debt levels. During the first half of 2007, we divested a portion of our interest in one of our Louisiana properties for a sales price of approximately $1.1 million.
· During the six months ended June 30, 2007, a total of 19 wells were logged with 17 apparent successes, for an overall success rate of approximately 89%.
· We expect to spud between 70 and 80 gross wells in total for the calendar year 2007 and we estimate capital spending for the year to be approximately $140 million. Our ability to materially increase the number of wells to be drilled is heavily dependent upon the timely access to oilfield services, particularly drilling rigs.
· We have and will spend a considerable effort in 2007 integrating the assets acquired in the Smith Acquisition, which had the largest impact of any acquisition on our company. This will include continuing to add to our staff levels to manage the recent and anticipated future growth.
· We will continue to spend considerable effort in 2007 finding and evaluating acquisition opportunities, as we seek to further our growth.
· In the first quarter of 2007, we issued preferred stock. We declared dividend payments to preferred stockholders in March and June 2007. We expect to continue to pay preferred stock dividends on a quarterly basis.
· To help protect against the possibility of downward commodity price movements and lost revenue, we have several derivatives in place to hedge a portion of our expected natural gas and crude oil production streams for 2007 through 2009. We apply mark-to-market accounting treatment, rather than cash flow hedge accounting treatment, and therefore significant volatility from the changes in fair value of those outstanding contracts have and will impact our earnings in 2007 (see Note 9 to our consolidated financial statements).
Our outlook and the expected results described above are both subject to change based upon factors that include, but are not limited to, drilling results, commodity prices, access to capital, the acquisitions market and factors referred to in Forward Looking Statements.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, contingent assets and liabilities and the related disclosures in the accompanying financial statements. Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:
· it requires assumptions to be made that were uncertain at the time the estimate was made, and
· changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.
All other significant accounting policies that we employ are presented in the notes to the consolidated financial statements. The following discussion presents information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate.
Nature of Critical Estimate Item: Oil and Natural Gas Reserves - Our estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment, 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.
Ceiling Test - The full-cost method of accounting for oil and gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full-cost ceiling 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. Oil and natural gas prices used in the reserve valuation at June 30, 2007 were $70.68 per barrel and $6.80 per MMBtu. 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. No such impairment was required in the six months ended June 30, 2006 or 2007.
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 year by approximately 10%.
Ceiling limitation test - The most likely factor to contribute to a ceiling test impairment is the price used to calculate the reserve limitation threshold. A reduction in prices at a measurement date could trigger a full-cost ceiling impairment. We had a cushion of $42.2 million, net of tax, at June 30, 2007. A 10% increase or decrease in prices used would have increased or decreased our cushion (i.e. the excess of the ceiling over our capitalized costs) by approximately 130%, net of tax, respectively. Thus, a less than 10% decrease in the price used in the ceiling test would have triggered a full-cost ceiling impairment as of June 30, 2007. Our hedging program would serve to mitigate some of the economic impact of any price decline.
However, since we do not apply cash flow hedge accounting to our derivative contracts, our hedging program did not have an impact on the ceiling test at June 30, 2007. Had we applied cash flow hedge accounting to our outstanding derivative contracts, the cushion would have increased by 21%. Another likely factor to contribute to a ceiling test impairment is a revised estimate of reserve volume. A 10% increase or decrease in reserve volume would have increased or decreased our cushion by approximately 93%, net of tax, respectively. As noted above, we used pricing and costs as of the last day of the period to determine our ceiling test. Should commodity prices continue to decrease in 2007, the possibility of a ceiling test impairment at a future date exists. Also, the effects of the Smith Acquisition in 2007 could increase the possibility that we will be required to record a ceiling test impairment, particularly if commodity prices decline below the effective levels paid for in the Smith Acquisition.
Nature of Critical Estimate Item: Unproved Property Impairment - We have elected to use the full-cost method to account for our oil and gas activities. Investments in unproved properties are not amortized until proved reserves associated with the prospects can be determined or until impairment occurs. Unproved properties are evaluated quarterly, 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.
Assumptions/Approach Used: At June 30, 2007, we had $95.0 million allocated to unproved property. This allocation is based on costs to date that are associated with potential attributable reserves.
Effect if Different Assumptions Used: A 10% increase or decrease in the unproved property balance (i.e., transfer to full-cost pool) would have decreased or increased, respectively, our depletion expense by approximately 1% for the three months ended June 30, 2007.
Nature of Critical Estimate Item: Asset Retirement Obligations - We have certain obligations to remove tangible equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Prior to the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, costs associated with this activity were capitalized to the full-cost pool as they were incurred and charged to income through depletion expense. SFAS No. 143 significantly changed the method of accruing for costs which an entity is legally obligated to incur related to the retirement of fixed assets (asset retirement obligations or ARO). Primarily, SFAS No. 143 requires us to 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 managements 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. Unless we expect a wells plugging to be significantly different than a normal abandonment, we use this estimate.
Effect if Different Assumptions Used: We expect to see our calculations 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. The resulting estimate, after application of a discount factor and some significant calculations, could differ from actual results, despite all our efforts to make an accurate estimate.
Nature of Critical Estimate Item: Income Taxes - In accordance with SFAS No. 109, Accounting for Income Taxes, we have recorded a deferred tax asset and liability to account for the expected future tax benefits and consequences of events that have been recognized in our financial statements and our tax returns. There are several items that result in deferred tax asset and liability impact to the balance sheet, but the largest of which are income taxes 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.
Assumptions/Approach Used: Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). We are not currently required to pay any federal income taxes because of the prior generation of NOL carryforwards.
Effect if Different Assumptions Used: We have engaged an independent public accounting firm to assist us in applying the numerous and complicated tax law requirements. However, despite our attempt to make an accurate estimate, the ultimate utilization of our NOL carryforwards is highly dependent upon our actual production and the realization of taxable income in future periods. If we estimate that some or all of our NOL carryforwards are more likely than not going to expire or otherwise not be utilized to reduce future tax, we would record a valuation allowance to remove the benefit of those NOL carryforwards from our financial statements.
Nature of Critical Estimate Item: Derivative 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) for a portion of our oil and natural gas production to achieve a more predictable revenue, as well as to reduce exposure from commodity price fluctuations. While all of these transactions are economic hedges of price risk, different accounting treatment may apply depending on if they qualify for cash flow hedge accounting. In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended), all transactions 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 revenue on the income statement. Ineffective portions of the changes in the fair value of the derivative
contracts are recognized in revenue as they occur. The cash flows resulting from settlement of these hedge transactions are included in cash flows from operating activities on the statement of cash flows. While the hedge contract is outstanding, the fair value may increase or decrease until settlement of the contract.
Mark-to-Market Accounting - For transactions accounted for using mark-to-market accounting treatment, the entire change in the fair value of the outstanding derivative contract is recorded in 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 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 managements input. It also approximates the fair value of the contracts as that would be the cost to us to terminate a contract at that point in time. 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 revenue on the income statement rather than in OCI on the balance sheet.
Effect if Different Assumptions Used: At June 30, 2007, 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 $0.9 million. Had we applied cash flow hedge accounting treatment to all of our derivative contracts outstanding at June 30, 2007, our net income for the six months would have been approximately $17.0 million, or $0.64 per basic and $0.57 per diluted earnings per share, assuming that all hedges were fully effective.
Results of Operations
This section includes discussion of our results of operations for the three and six months ended June 30, 2007 as compared to the same period of the prior year. We are an independent energy company engaged in the exploration, development, acquisition and production of oil and natural gas. Our resources and assets are managed and our results reported as one operating segment. We conduct our operations primarily along the onshore United States Gulf Coast, with our emphasis in south and southeast Texas, Louisiana, Mississippi and southeast New Mexico. We completed one acquisition in the fourth quarter of 2006 and one in the first quarter of 2007, which significantly impacted revenues, production and costs for the first half of 2007 and affects the comparability of periods presented.
Second Quarter 2007 Compared to the Second Quarter 2006
Revenue and Production
Total revenue increased 59% from the second quarter of 2006 to the comparable 2007 period. Excluding the effects of derivative activity, revenues increased 52% from the second quarter of 2006 to the comparable 2007 period. Our product mix contributed the following percentages of revenues and production volumes:
(1) Includes effect of derivative transactions.
The following table summarizes volume and price information with respect to our oil and natural gas production for the three months ended June 30, 2007 and 2006: