Principles of Consolidation. The accompanying consolidated financial statements include the accounts of Swift Energy Company and its wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and natural gas properties, with a focus on inland waters and onshore oil and natural gas reserves in Louisiana and Texas, as well as onshore oil and natural gas reserves in New Zealand. Our undivided interests in gas processing plants, and investments in oil and gas limited partnerships where we are the general partner are accounted for using the proportionate consolidation method, whereby our proportionate share of each entity’s assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements.

Holding Company Structure. In December 2005, we implemented a holding company structure pursuant to Texas and federal law in a manner designed to be a non-taxable transaction. The new parent holding company assumed the Swift Energy Company name and its common stock and continued to trade on the New York and Pacific Stock Exchanges. The purposes of this new holding company structure are to separate Swift Energy’s domestic and international operations to better reflect management practices, to improve our economics, and to provide greater administrative and organizational flexibility. Under the new organizational structure, four new subsidiaries were formed with the Texas parent holding company wholly owning three Delaware subsidiaries, which in turn wholly own Swift Energy's operating subsidiaries. Swift Energy Operating, LLC is the operator of record for Swift Energy's domestic properties. Swift Energy's name, charter, bylaws, officers, board of directors, authorized shares and shares outstanding remain substantially identical. The Company's international operations continue to be conducted through Swift Energy International, Inc. Swift Energy made amendments to its bank credit agreement, debt indentures and various other plans and documents to accommodate the internal reorganization, but the Company's day-to-day conduct of business was not impacted. Accordingly, there was no impact on our financial position or results of operations.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires us to make estimates and assumptions that affect the reported amount of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include:

• the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and the related present value of estimated future net cash flows there-from,
• accruals related to oil and gas revenues, capital expenditures and lease operating expenses,
• estimates of insurance recoveries related to property damage,
• the estimated future cost and timing of asset retirement obligations, and
• estimates made in our income tax calculations.

While we are not aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period during which the adjustment occurs.

Property and Equipment. We follow the “full-cost” method of accounting for oil and gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the years 2005, 2004, and 2003, such internal costs capitalized totaled $18.8 million, $13.1 million, and $11.5 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the years 2005, 2004, and 2003, capitalized interest on unproved properties totaled $7.2 million, $6.5 million, and $6.8 million, respectively. Interest not capitalized and general and administrative costs related to production and general corporate overhead are expensed as incurred.

No gains or losses are recognized upon the sale or disposition of oil and gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.

Future development costs are estimated property-by-property based on current economic conditions and are amortized to expense as our capitalized oil and gas property costs are amortized.

We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and gas properties by the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties—including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties—by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period. This calculation is done on a country-by-country basis, and the period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment, recorded at cost, are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between three and 20 years. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized.

Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved properties” and therefore subject to amortization. G&G costs incurred that are directly associated with specific unproved properties are capitalized in “Unproved properties” and evaluated as part of the total capitalized costs associated with a prospect.

The cost of unproved properties not being amortized is assessed quarterly, on a country-by-country basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, foreign currency exchange rates, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized. To the extent costs accumulate in countries where there are no proved reserves, any costs determined by management to be impaired are charged to expense.

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and gas properties (including gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using period-end prices, adjusted for the effects of hedging, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). Our hedges at December 31, 2005 consisted of natural gas price floors with strike prices lower than the period-end price and thus did not materially affect prices used in this calculation. This calculation is done on a country-by-country basis.

The calculation of the Ceiling Test and provision for DD&A is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. Our reserves estimates are prepared in accordance with Securities and Exchange Commission guidelines; and, are audited on an annual basis at year-end by a firm of independent petroleum engineers in accordance with standards approved by the Board of Directors of the Society of Petroleum Engineers.

Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline from our period-end prices used in the Ceiling Test, even if only for a short period, it is possible that non-cash write-downs of oil and gas properties could occur in the future.

Revenue Recognition. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Processing costs for natural gas and natural gas liquids (“NGLs”) that are paid in-kind are deducted from revenues. The Company uses the entitlement method of accounting in which the Company recognizes its ownership interest in production as revenue. If our sales exceed our ownership share of production, the natural gas balancing payables are reported in “Accounts payable and accrued liabilities” on the accompanying balance sheet. Natural gas balancing receivables are reported in “Other current assets” on the accompanying balance sheet when our ownership share of production exceeds sales. As of December 31, 2005, we did not have any material natural gas imbalances.

Accounts Receivable. Included in the “Accounts receivable” balance, which totaled $39.0 million at December 31, 2004, on the accompanying balance sheets, were approximately $2.3 million of receivables related to hydrocarbon volumes produced from 2001 and 2002 that had been disputed since early 2003. As a result of the dispute, we did not record a receivable with regard to any 2003 disputed volumes and our contract governing these sales expired in 2003. Based on settlement discussions, we settled our claim with this counter-party in July 2005 by receiving a cash payment for less than our gross receivable. Accordingly, in the second quarter of 2005, we increased our reserve for this claim by approximately $0.6 million, which is recorded in “Price-risk management and other, net” on the accompanying statements of income.

We assess the collectibility of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At December 31, 2005 and 2004, we had an allowance for doubtful accounts of less than $0.1 million and $0.5 million, respectively. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balances on the accompanying balance sheets.

Debt Issuance Costs. Legal and accounting fees, underwriting fees, printing costs, and other direct expenses associated with the public offering in April 2002 of our 9-3/8% senior subordinated notes due 2012, the June 2004 extension of our bank credit facility, and the public offering in June 2004 of our 7-5/8% senior notes due 2011 were capitalized and are amortized on an effective interest basis over the life of each of the respective note offerings and credit facility. The 9-3/8% senior subordinated notes due 2012 mature on May 1, 2012, and the balance of their issuance costs at December 31, 2005, was $4.1 million, net of accumulated amortization of $1.5 million. The issuance costs associated with our revolving credit facility, which was extended in June 2004, have been capitalized and are being amortized over the life of the facility. The balance of revolving credit facility issuance costs at December 31, 2005, was $0.6 million, net of accumulated amortization of $1.8 million. The 7-5/8% senior notes due 2011 mature on July 15, 2011, and the balance of their issuance costs at December 31, 2005, was $3.3 million, net of accumulated amortization of $0.7 million.

Limited Partnerships. At year-end 2005, we serve as managing general partner for two private limited partnerships, and during fiscal 2005, less than 1% of our total oil and gas sales was attributable to our general and limited partner interests in those partnerships. These two partnerships were formed between 1996 and 1998, and will continue to operate until their limited partners vote otherwise.

Price-Risk Management Activities. The Company follows SFAS No. 133, which requires that changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The statement also establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the balance sheet as either an asset or a liability measured at its fair value. Hedge accounting for a qualifying hedge allows the gains and losses on derivatives to offset related results on the hedged item in the income statements and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Changes in the fair value of derivatives that do not meet the criteria for hedge accounting, and the ineffective portion of the hedge, are recognized currently in income.

We have a price-risk management policy to use derivative instruments to protect against declines in oil and gas prices, mainly through the purchase of price floors and collars. During 2005, 2004 and 2003, we recognized net losses of $1.1 million, $1.3 million and $2.8 million, respectively, relating to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying statements of income. At December 31, 2005, the Company had recorded $0.1 million, net of taxes of less than $0.1 million, of derivative losses in “Accumulated other comprehensive income (loss), net of income tax” on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our hedging transactions that qualified as cash flow hedges. The ineffectiveness reported in “Price-risk management and other, net” for 2005, 2004, and 2003 was not material. We expect to reclassify all amounts currently held in “Accumulated other comprehensive income (loss), net of income tax” into the statement of income within the next six months when the forecasted sale of hedged production occurs.

At December 31, 2005, we had in place price floors in effect for February 2006 through the June 2006 contract month for natural gas, that cover a portion of our domestic natural gas production for February 2006 to June 2006. The natural gas price floors cover notional volumes of 2,075,000 MMBtu, with a weighted average floor price of $8.39 per MMBtu. Our natural gas price floors in place at December 31, 2005 are expected to cover approximately 35% to 40% of our estimated domestic natural gas production from February 2006 to June 2006.

When we entered into these transactions discussed above, they were designated as a hedge of the variability in cash flows associated with the forecasted sale of natural gas production. Changes in the fair value of a hedge that is highly effective and is designated and documented and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in “Accumulated other comprehensive income (loss), net of income tax.” When the hedged transactions are recorded upon the actual sale of oil and natural gas, these gains or losses are reclassified from “Accumulated other comprehensive income (loss), net of income tax” and recorded in “Price-risk management and other, net” on the accompanying statement of income. The fair value of our derivatives is computed using the Black-Scholes-Merton option pricing model and is periodically verified against quotes from brokers. The fair value of these instruments at December 31, 2005, was $0.3 million and is recognized on the accompanying balance sheet in “Other current assets.”

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to general and administrative, net based on our estimate of the costs incurred to operate the wells, with the remainder applied as a reduction to lease operating cost. Based on recent estimates, effective October 1, 2003, we began recording the supervision fee only as a reduction to general and administrative, net. The total amount of supervision fees charged to the wells we operate was $7.8 million in 2005, $5.8 million in 2004, and $5.1 million in 2003.

Inventories. We value inventories at the lower of cost or market value. Cost of crude oil inventory is determined using the weighted average method and all other inventory is accounted for using the first in, first out method (“FIFO”). The major categories of inventories, which are included in “Other current assets” on the accompanying balance sheets, are shown as follows:

Income Taxes. Under SFAS No. 109, “Accounting for Income Taxes,” deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. The effective tax rate for 2005, 2004 and 2003 was lower than the statutory tax rates primarily due to reductions from the New Zealand statutory rate attributable to the currency effect on the New Zealand deferred tax calculation. The provision for 2005 included the reversal of a New Zealand repatriation allowance offset by an adjustment to correct an immaterial error in a prior year’s tax returns and higher state tax rate estimates. The effective tax rate for 2004 included favorable corrections to tax basis amounts discovered while preparing the prior year’s tax returns, partially offset by higher deferred state income taxes. Income tax expense in 2003 included higher domestic state income taxes and other items. The tax laws in the jurisdictions we operate in are continuously changing and professional judgments regarding such laws can differ.

Accounts Payable and Accrued Liabilities. Included in “Accounts payable and accrued liabilities,” on the accompanying balance sheets, at December 31, 2005 and 2004 are liabilities of approximately $9.9 million and $6.9 million, respectively, which represent the amounts by which checks issued, but not presented to the Company’s banks for collection, exceeded balances in the applicable bank accounts.

Cash and Cash Equivalents. We consider all highly liquid debt instruments with an initial maturity of three months or less to be cash equivalents.

Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. During 2005, oil and gas sales to Shell Oil and affiliates, both domestically and in New Zealand, were $179.9 million, or 42% of total oil and gas sales. During 2004, oil and gas sales to Shell Oil and affiliates, both domestically and in New Zealand, were $149.2 million, or 48% of total oil and gas sales. During 2003, oil and gas sales to Shell Oil and affiliates, both domestically and in New Zealand, were $31.1 million, or 15% of total oil and gas sales, while sales to subsidiaries of Contact Energy in New Zealand were $23.5 million, or 11% of total oil and gas sales. Credit losses in 2005, 2004 and 2003 have been immaterial.

Environmental Costs. Our operations include activities that are subject to extensive federal and state environmental regulations. Costs associated with redemption projects, which are probable and reasonably estimable, are accrued in advance. Ongoing environmental compliance costs are expensed as incurred.

Restricted Assets. These balances primarily include amounts deposited on plugging bonds in New Zealand, along with amounts held in escrow accounts to satisfy domestic plugging and abandonment obligations. These amounts are restricted as to their current use, and will be released when we have satisfied all plugging and abandonment obligations in certain fields domestically and in New Zealand.

Foreign Currency. We use the U.S. Dollar as our functional currency in New Zealand. The functional currency is determined by examining the entities cash flows, commodity pricing environment and financing arrangements. We have both assets and liabilities denominated in New Zealand Dollars, the New Zealand “Deferred income taxes” and a portion of our “Asset Retirement Obligation” on the accompanying balance sheet. For accounts other than “Deferred income taxes,” as the currency rate changes between the U.S. Dollar and the New Zealand Dollar, we recognize transaction gains and losses in “Price-risk management and other, net” on the accompanying statements of income. We recognize transaction gains and losses on “Deferred income taxes” in “Provision for Income Taxes” on the accompanying statement of income.

Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2005 and 2004, and were determined based upon variable interest rates currently available to us for borrowings with similar terms. Based upon quoted market prices as of December 31, 2005 and 2004, the fair values of our senior subordinated notes due 2012 were $214.5 million, or 107.25% of face value, and $224.0 million, or 112% of face value, respectively. Based upon quoted market prices as of December 31, 2005 and 2004, the fair values of our senior notes due 2011 were $153.8 million, or 102.5% of face value, and $162.4 million, or 108.25% of face value. The carrying value of our senior subordinated notes due 2012 was $200.0 million at December 31 for both 2005 and 2004. The carrying value of our senior notes due 2011 was $150.0 million at December 31, 2005.

Reclassification of Prior Period Balances. Certain reclassifications have been made to prior period amounts to conform to the current year presentation.

Accumulated Other Comprehensive Income (Loss), Net of Income Tax. We follow the provisions of SFAS No. 130, “Reporting Comprehensive Income,” which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income or loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company. At December 31, 2005, we recorded $0.1 million, net of taxes of less than $0.1 million, of derivative losses in “Accumulated other comprehensive income (loss), net of income tax” on the accompanying balance sheet. The components of accumulated other comprehensive Income (loss) and related tax effects for 2005 were as follows:

Total comprehensive income was $115.3 million, $69.2 million, and $29.8 million for 2005, 2004, and 2003, respectively.

Stock Based Compensation. We have two stock-based compensation plans, which are described more fully in Note 6. We account for those plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. We issued restricted stock to employees for the first time in 2004 and again in 2005, and recorded expense related to restricted stock shares of less than $0.1 million and $1.2 million in “General and administrative, net” on the accompanying statements of income in 2004 and 2005, respectively. No stock-based employee compensation cost is reflected in net income for employee stock options, as all options granted under those plans had an exercise price equal to the fair market value of the underlying common stock on the date of the grant; or in the case of the employee stock purchase plan, the purchase price is 85% of the lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year or a date during the year chosen by the participant. Had compensation expense for these plans been determined based on the fair value of the options consistent with SFAS No. 123, “Accounting for Stock-Based Compensation,” our net income and earnings per share would have been adjusted to the following pro forma amounts:

Pro forma compensation cost reflected above may not be representative of the cost to be expected in future years. The fair value of each option grant, as opposed to its exercise price, is estimated on the date of grant using the Black-Scholes-Merton option-pricing model with the following weighted average assumptions in 2005, 2004, and 2003, respectively: no dividend yield; expected volatility factors of 41.6%, 38.6%, and 34.71%; risk-free interest rates of 3.83%, 3.59%, and 4.63%; and expected lives of 3.9, 5.4, and 7.2 years. We view all awards of stock compensation as a single award with an expected life equal to the average expected life of component awards and amortize the award on a straight-line basis over the life of the award.

Asset Retirement Obligation. In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. The liability is discounted from the year the well is expected to deplete. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated on a unit-of-production basis over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. This standard requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. Based on our experience and analysis of the oil and gas services industry, we have not factored a market risk premium into our asset retirement obligation. SFAS No. 143 was adopted by us effective January 1, 2003. Upon adoption of SFAS No. 143, we recorded an asset retirement obligation of $8.9 million, an addition to oil and gas properties of $2.0 million, and a non-cash charge of $4.4 million (net of $2.5 million of deferred taxes), which is recorded as a Cumulative Effect of Change in Accounting Principle. The cumulative charge to earnings took into consideration the impact of adopting SFAS No. 143 on previous full-cost ceiling tests. SFAS No. 143 is silent with respect to whether prior period ceiling tests should be reflected in the implementation entry calculation; however, management believes that any impairment on the properties should be reflected in the historical periods. Had we not considered the impact of adopting SFAS No. 143 on previous full-cost ceiling tests, the charge recognized would have been reduced. Excluding the Cumulative Effect of Change in Accounting Principle, the adoption of SFAS No. 143 reduced our 2003 net income by approximately $0.6 million, or $0.02 per diluted share.

The following provides a roll-forward of our asset retirement obligation:

At December 31, 2005 and 2004, approximately $0.3 million and $0.5 million, respectively, of our asset retirement obligation is classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

New Accounting Pronouncements. EITF 04-05 addresses when a limited partnership should be consolidated by its general partner. EITF 04-05 presumes that a sole general partner in a limited partnership controls the limited partnership, and therefore should consolidate the limited partnership. The presumption of control can be overcome if the limited partners have (a) the substantive ability to remove the sole general partner or otherwise dissolve the limited partnership or (b) substantive participating rights. The EITF reached a tentative conclusion on the circumstances in which either kick-out rights or participating rights would be considered substantive and preclude consolidation by the general partner. The FASB ratified the EITF consensus at the June 2005 EITF meeting. We do not believe this EITF will have a material impact on our consolidated financial statements because we believe our limited partners have substantive kick-out rights under paragraph B20 of FIN 46R.

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS No. 123R is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, and supercedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends SFAS No. 95, Statement of Cash Flows. SFAS No. 123R requires all employee share-based payments, including grants of employee stock options, to be recognized in the financial statements based on their fair values. SFAS No. 123 discontinues the ability to account for these equity instruments under the intrinsic value method as described in APB Opinion No. 25. SFAS No. 123R requires the use of an option pricing model for estimating fair value, which is amortized to expense over the service periods. The requirements of SFAS No. 123R are effective for fiscal periods beginning after June 15, 2005. SFAS No. 123R permits public companies to adopt its requirements using one of two methods, we have chosen the “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS No. 123R for all share-based payments granted after the effective date and based on the requirements of SFAS No. 123 for all awards granted to employees prior to the adoption date of SFAS No. 123R that remain unvested on the adoption date.

In April 2005, the SEC issued a release announcing that it would provide for a phased-in implementation process for SFAS No. 123R. As a result, our required date to adopt SFAS No. 123R is January 1, 2006. Also in April 2005, the SEC issued Staff Accounting Bulleting No. 107, Share-Based Payment, which provides guidance on the implementation of SFAS No. 123R. SAB No. 107 provides guidance on valuing options, estimating volatility and expected terms of the option awards, and discusses the SEC’s views on share-based payment transactions with non-employees, the capitalization of compensation cost and accounting for income tax effects of share-based payment arrangements upon adoption of SFAS No. 123R.

We will adopt the provisions of SFAS No. 123R effective January 1, 2006 using the modified prospective method. As permitted by Statement 123, the Company previously accounted for share-based payments to employees using APB Opinion No. 25’s intrinsic value method and, as such, generally recognizes no compensation cost for employee stock options. Accordingly, the adoption of Statement No. 123R’s fair value method is expected to have a significant impact on our results of operations. However, it will have no impact on our overall financial position. We use the Black-Scholes-Merton formula to estimate the value of stock options granted to employees and expect to continue to use this acceptable option valuation model after the required adoption of SFAS No. 123R. The significance of the impact of adoption will depend on levels of outstanding unvested share-based payments on the date of adoption and share-based payments granted in the future. However, had we adopted Statement No. 123R in prior periods, the impact of that standard would have approximated the impact of Statement No. 123 as described in the disclosure of pro forma net income and earnings per share under “Stock Based Compensation.” We are still evaluating the effect of adopting this standard, but do not believe the Cumulative Effect of Change in Accounting Principle will be material to our results of operations.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections: a replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 requires voluntary changes in accounting principles to be applied retrospectively, unless it is impracticable. SFAS No. 154’s retrospective application requirement replaces APB 20’s requirement to recognize most voluntary changes in accounting principle by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. If retrospective application for all prior periods is impracticable, the method used to report the change and the reason the retrospective application is impracticable are to be disclosed.

Under SFAS No. 154, retrospective application will be the transition method in the unusual instance that a newly issued accounting pronouncement does not provide specific transition guidance. It is expected that many pronouncements will specify transition methods other than retrospective. SFAS No. 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005, and the adoption of this statement is expected to have no impact on our financial position or results of operations.

In July 2005, the FASB issued an exposure draft “Accounting for Uncertain Tax Positions, a proposed interpretation of FASB Statement No. 109.” The proposed interpretation would apply to all open tax positions under FASB No. 109. The conclusions in this interpretation include: initial recognition of tax benefits, recognition and de-recognition of tax positions, measurement of tax benefits and classifications of tax liabilities. The comment period on this exposure draft ended in September 2005, and we are currently assessing the impact, if any, that this interpretation would have on our financial position and results of operations. The FASB has not issued an effective date for this interpretation, and a final standard will likely be issued in 2006.