Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles (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:

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 2004, 2003, and 2002, such internal costs capitalized totaled $13.1 million, $11.5 million, and $10.7 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the years 2004, 2003, and 2002, capitalized interest on unproved properties totaled $6.5 million, $6.8 million, and $7.0 million, respectively. Interest not capitalized and general and administrative costs related to production and general 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 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 dependant on our production from these properties in future years. Our total amortization per Mcfe was $1.38, $1.17, and $1.11 in 2004, 2003, and 2002, respectively. Our domestic amortization per Mcfe was $1.46, $1.30, and $1.25 in 2004, 2003, and 2002, respectively. Our New Zealand amortization per Mcfe was $1.17, $0.94, and $0.80 in 2004, 2003 and 2002, respectively. Furniture, fixtures, and other equipment, held 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 Property and therefore subject to amortization. In exploration areas, G&G costs 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, the political stability in the countries in which we have an investment, 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 year-end 2004 consisted mainly of natural gas and crude oil 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 depreciation, depletion, and amortization 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 estimate. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered.

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, 2004, we did not have any material natural gas imbalances.

Accounts Receivable. Included in the “Accounts receivable” balance, which totaled $39.0 million and $27.4 million at December 31, 2004 and 2003, respectively, on the accompanying balance sheets, is approximately $2.3 million of receivables related to hydrocarbon volumes produced from 2001 and 2002 that have 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.

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, 2004 and 2003, we had an allowance for doubtful accounts of $0.5 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balances on the accompanying consolidated 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, 2004, was $4.6 million, net of accumulated amortization of $1.0 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, 2004, was $0.8 million, net of accumulated amortization of $1.6 million. The 7-5/8% senior notes due 2011 mature on July 15, 2011, and the balance of their issuance costs at December 31, 2004, was $3.7 million, net of accumulated amortization of $0.2 million. The remaining $2.2 million of debt issuance costs related to the 10-1/4% senior subordinated notes due 2009 was charged to “debt retirement cost” on the accompanying statements of income when the related debt was retired in 2004.

Limited Partnerships. At year-end 2004, we serve as managing general partner for six private limited partnerships, and during fiscal 2004, less than 1% of our total oil and gas sales was attributable to our interests in those partnerships. These six 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 2004, 2003 and 2002, we recognized net losses of $1.3 million, $2.8 million and $0.2 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, 2004, the Company had recorded $0.5 million, net of taxes of $0.3 million, of derivative gains 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 2004, 2003 and 2002 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 twelve months when the forecasted sale of hedged production occurs.

At December 31, 2004, we had in place price floors in effect through the December 2005 contract month for natural gas, that cover a portion of our domestic natural gas production for January 2005 to December 2005. The natural gas price floors cover notional volumes of 4,000,000 MMBtu, with a weighted average floor price of $5.83 per MMBtu. Our natural gas price floors in place at December 31, 2004 are expected to cover approximately 30% to 35% of our domestic natural gas production from January 2005 to December 2005. At December 31, 2004, we also had in place crude oil price floors in effect through the March 2005 contract month, which cover a portion our domestic crude oil production for January 2005 to March 2005. The crude oil price floors cover notional volumes of 216,000 barrels, with a weighted average floor price of $37.00 per barrel. Our crude oil price floors in place at December 31, 2004 are expected to cover approximately 15% to 20% of our domestic crude oil production from January 2005 to March 2005.

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 and crude oil 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 consolidated statement of income. The fair value of our derivatives is computed using the Black-Scholes option pricing model and are periodically verified against quotes from brokers. The fair value of these instruments at December 31, 2004, was $1.8 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 $5.8 million in 2004, $5.1 million in 2003, and $5.3 million in 2002.

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 2004 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, along with favorable corrections to tax basis amounts discovered while preparing the prior year’s tax returns. These amounts were partially offset by higher deferred state income taxes. Income tax expense in 2003 includes a reduction from the U.S. statutory rate, primarily from the result of the currency exchange rate effect on the New Zealand deferred tax. This amount was partially offset by higher deferred 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. The Company is currently evaluating the impact of the recently enacted American Jobs Creation Act of 2004. We do not believe this act will have a material impact in the near-term on our financial position or cash flow from operations.

Accounts Payable and Accrued Liabilities. Included in “Accounts payable and accrued liabilities,” on the accompanying balance sheets, at December 31, 2004 and 2003 are liabilities of approximately $6.9 million and $11.9 million, respectively, represents the amount 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 2004, oil and gas sales to Shell, 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, 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. During 2002, oil and gas sales to Eastex Crude Company were $25.4 million, or 18% of total oil and gas sales, while sales to subsidiaries of Contact Energy in New Zealand were $14.6 million, or 10% of total oil and gas sales. Credit losses in 2004, 2003 and 2002 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 quantifiable, are accrued in advance. Ongoing environmental compliance costs are expensed as incurred.

Restricted Assets. These balances 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, predominantly our portion of our “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, 2004 and 2003, 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, 2004 and 2003, the fair values of our senior subordinated notes due 2012 were $224.0 million , or 112.0% of face value, and $218.0 million, or 109% of face value, respectively. Based upon quoted market prices as of December 31, 2004, the fair value of our senior notes due 2011 was $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 2004 and 2003. The carrying value of our senior notes due 2011 was $150.0 million at December 31, 2004.

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, 2004, we recorded $0.5 million, net of taxes of $0.3 million, of derivative gains 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 2004 were as follows:

Total comprehensive income was $69.2 million, $29.8 million, and $11.7 million for 2004, 2003, and 2002, 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 recorded expense related to these shares of less than $0.1 million in “General and administrative, net” on the accompanying statements of income. 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 option-pricing model with the following weighted average assumptions in 2004, 2003, and 2002, respectively: no dividend yield; expected volatility factors of 38.6%, 34.71%, and 73.72%; risk-free interest rates of 3.59%, 4.63%, and 4.74%; and expected lives of 5.4, 7.2, and 7.4 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 upon settlement. 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, 2004 and 2003, approximately $0.5 million and $0.8 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.

The pro forma effect for 2002, assuming adoption of SFAS No. 143 effective January 1, 2002, would have included a non-cash charge of $3.7 million (net of $2.1 million of deferred taxes), which would have been recorded as a Cumulative Effect of Change in Accounting Principle and recognition of an asset retirement obligation of $6.2 million. The following table displays our pro forma results for the year ended December 31, 2002, had we adopted SFAS No. 143 effective January 1, 2002.

New Accounting Pronouncements. In January 2003, the FASB issued Interpretation No. 46 (Revised December 2003) (“FIN 46R”), Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51 consolidated financial statements (the “Interpretation”). The Interpretation significantly changes whether entities included in its scope are consolidated by their sponsors, transferors, or investors. The Interpretation introduces a new consolidation model - the variable interest model; which determines control (and consolidation) based on potential variability in gains and losses of the entity being evaluated for consolidation. The Interpretation provides guidance for determining whether an entity lacks sufficient equity or its equity holders lack adequate decision-making ability. These variable interest entities (“VIEs”) are covered by the Interpretation and are to be evaluated for consolidation based on their variable interests. These provisions applied immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in special purpose entities for periods ending after December 15, 2003. The provisions apply for all other types of variable interests in VIEs for periods ending after March 15, 2004. We have no variable interests in VIEs, nor do we have variable interests in special purpose entities. The adoption of this interpretation had no impact on our financial position or results of operations.

In September and November 2004, the EITF discussed a proposed framework for addressing when a limited partnership should be consolidated by its general partner, EITF Issue 04-5. The proposed framework 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 protective rights would be considered substantive and preclude consolidation by the general partner and what limited partner’s rights would be considered participating rights that would preclude consolidation by the general partner. The EITF tentatively concluded that for kick out rights to be considered substantive, the conditions specified in paragraph B20 of FIN 46R should be met. With regard to the definition of participating rights that would preclude consolidation by the general partner, the EITF concluded that the definition of those rights should be consistent with those in EITF Issue 96-16. The EITF also reached a tentative conclusion on the transition for Issue 04-05. 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 September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 106 (SAB 106). SAB 106 expresses the SEC staff’s views regarding SFAS No. 143 and its impact on both the full-cost ceiling test and the calculation of depletion expense. In accordance with SAB 106, beginning in the fourth quarter of 2004, undiscounted abandonment cost for future wells, not recorded at the present time but needed to develop the proved reserves in existence at the present time, should be included in the unamortized cost of oil and gas properties, net of related salvage value, for purposes of computing DD&A. The effect of including undiscounted abandonment costs of future wells to the undiscounted cost of oil and gas properties will increase depletion expense in future periods, however, we currently do not believe such increases will be material.

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:

• A "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.
• A "modified retrospective" method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures.