Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates. Significant estimates include proved reserve volumes, DD&A, and deferred income taxes.

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. Under the full-cost method of accounting, 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 2003, 2002, and 2001, such internal costs capitalized totaled $11.5 million, $10.7 million, and $11.6 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the years 2003, 2002, and 2001, capitalized interest on unproved properties totaled $6.8 million, $7.0 million, and $6.3 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 using 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 capitalized asset retirement obligations, 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. Our amortization per Mcfe was $1.17, $1.11, and $1.31 in 2003, 2002, and 2001, respectively. Furniture, fixtures, and other equipment are depreciated by the straight-line method at rates based on the estimated useful lives of the property. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized.

Geological and geophysical (G&G) costs are recorded in Proved Property and therefore subject to amortization as incurred on developed properties. In exploration areas, G&G costs are capitalized in Unproved Property 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 and the fair value of asset retirement obligations, net of related salvage values, deferred income taxes, and excluding the asset retirement obligation liability is limited to the sum of the estimated future net revenues from proved properties, excluding cash outflows from asset retirement obligations, using hedged adjusted period-end prices, 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 2003 consisted of natural gas price floors with strike prices lower than the period end price and thus did not affect prices used in this calculation. This calculation is done on a country-by-country basis for those countries with proved reserves.

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.

In the fourth quarter of 2001, as a result of low oil and gas prices at December 31, 2001, we reported a non-cash write-down on a before-tax basis of $98.9 million ($63.5 million after tax) on our domestic properties. We had no write-down on our New Zealand properties.

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 the Company’s period-end prices used in the Ceiling Test, even if only for a short period, it is possible that additional 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. 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 differences 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, 2003, we did not have any material natural gas imbalances.

Accounts Receivable. Included in the total “Accounts receivable” balance, which totaled $28.6 million and $20.9 million at December 31, 2003 and 2002, respectively, on the accompanying balance sheet, is approximately $2.3 million of receivables related to volumes produced from 2001 and 2002 that we were notified, were disputed in early 2003. Accordingly, we did not record a receivable with regard to 2003 volumes. We assess the collectibility of trade and other receivables. Based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At December 31, 2003 and 2002, we had an allowance for doubtful accounts of $0.8 million and $0.3 million, respectively. These allowances for doubtful accounts balances have been deducted from the total “Accounts receivable” balances on the accompanying consolidated balance sheet.

Debt issuance costs. Legal and accounting fees, underwriting fees, printing costs, and other direct expenses associated with the public offering in August 1999 of our 10.25% Senior Subordinated Notes (the “Senior Notes”), the September 2001 extension of our bank credit facility, and the public offering in April 2002 of our 9.375% Senior Subordinated Notes were capitalized and are amortized over the life of each of the respective note offerings and credit facility. The Senior Notes due 2009 mature on August 1, 2009, and the balance of their issuance costs at December 31, 2003, was $2.4 million, net of accumulated amortization of $1.1 million. The issuance costs associated with our revolving credit facility, which was extended in September 2001, have been capitalized and are being amortized over the life of the facility. The balance of revolving credit facility issuance costs at December 31, 2003, was $0.6 million, net of accumulated amortization of $1.3 million. The Senior Notes due 2012 mature on May 1, 2012, and the balance of their issuance costs at December 31, 2003, was $5.0 million, net of accumulated amortization of $0.6 million.

Limited Partnerships. At year-end 2003, we serve as managing general partner for six drilling partnerships, and during fiscal 2003 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 be 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) be recorded in the balance sheet as either an asset or a liability measured at its fair value. Special hedge accounting for qualifying hedges would allow 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. Hedges that do not meet the criteria for special hedge accounting are accounted for under mark to market accounting. SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138, was adopted by us on January 1, 2001.

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. Upon adoption of SFAS No. 133 on January 1, 2001, we recorded a net of taxes charge of $0.4 million, which is recorded as a Cumulative Effect of Change in Accounting Principle. During 2003, 2002 and 2001, we recognized net losses (gains) of $2.8 million, $0.2 million and ($1.2) 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, 2003, the Company had recorded $0.3 million, net of taxes of $0.2 million, of derivative losses in “Other comprehensive loss” on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our collar transactions that were qualified as cash flow hedges. The ineffectiveness reported in “Price-risk management and other, net“ for 2003 and 2002 was not material. The Company expects to reclassify all amounts currently held in “Other comprehensive loss” into the statement of income within the next six months when the forecasted sale of hedged production occurs.

As of December 31, 2003, we had in place natural gas price floors in effect for the January 2004 contract month through the June 2004 contract, which cover our domestic natural gas production for January 2004 to June 2004. The natural gas price floors cover notional volumes of 3,300,000 Mmbtu with a weighted average floor price of $4.77. When we entered into these transactions, 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 qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in Other Comprehensive Income (Loss). When the hedged transactions are recorded upon the actual sale of oil and natural gas, these gains or losses are reclassified from Other Comprehensive Income (Loss) and recorded in “Price-risk management and other, net” on the consolidated statement of income. The fair value of our derivatives are 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, 2003, was $0.5 million and is recognized on the balance sheet in “Other current assets.”

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our working interest share on wells where we have a 100% working interest. These supervision fees are recorded as a reduction to general and administrative expenses and oil and gas production expenses based on our estimate of the costs incurred to operate the wells. Effective October 1, 2003, we began recording the supervision fee as a reduction to general and administrative expense only. The total amount of supervision fees charged to the wells we operate was $5.1 million in 2003, $5.3 million in 2002, and $6.8 million in 2001.

Inventories. Inventories consist principally of tubular goods and equipment, stated at the lower of weighted-average cost or market, and oil produced but not sold, stated at the lower of cost (a combination of production costs and depreciation, depletion and amortization expense) or market.

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 bases of assets and liabilities, given the provisions of the enacted tax laws.

Accounts Payable and Accrued Liabilities. Included in accounts payable and accrued liabilities at December 31, 2003 and 2002 are liabilities of approximately $11.9 million and $8.4 million, respectively, representing 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 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 11.2% of total oil and gas sales. During 2002, oil and gas sales to Eastex Crude Company were $25.4 million, or 18.0% of total oil and gas sales, while sales to subsidiaries of Contact Energy in New Zealand were $14.6 million, or 10.3% of total oil and gas sales. During 2001, oil and gas sales to Eastex Crude Company were $31.6 million, or 18.1% of total oil and gas sales, while sales to subsidiaries of Enron were $18.2 million, or 10.4% of total oil and gas sales. During the fourth quarter of 2001, we wrote off $1.4 million due to uncollected receivables related to gas sold to Enron in November 2001. This amount is included in “Other expenses“ on the Consolidated Statement of Income. In 2001, we discontinued sales of oil and gas to Enron and are selling that production to other purchasers. Credit losses in 2002 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 quantifiable, are accrued in advance. Ongoing environmental compliance costs are expensed as incurred.

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 nature of these short-term instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2003 and 2002, and were determined based upon variable interest rates currently available to us for borrowings with similar terms. Based on quoted market prices as of the respective dates, the fair values of our Senior Notes due 2009 were $135.6 million and $129.0 million at December 31, 2003 and 2002, respectively. Based upon quoted market prices as of December 31, 2003 and 2002, the fair values of our Senior Notes due 2012 were $218.0 million and $189.2 million, respectively. The carrying value of our Senior Notes due 2009 was $124.4 million and $124.3 million at December 31, 2003 and 2002, respectively. The carrying value of our Senior Notes due 2012 was $200.0 million at both December 31, 2003 and 2002.

Other Comprehensive Loss. 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, 2003, we recorded $0.3 million, net of taxes of $0.2 million, of derivative losses in “Other comprehensive loss” on the accompanying balance sheet. The components of accumulated other comprehensive loss and related tax effects for 2003 were as follows:

The pro forma effect for 2001, assuming adoption of SFAS No. 143 effective January 1, 2001, would have included a non-cash charge of $2.6 million (net of $1.5 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 $4.3 million. The following table displays our pro forma results for the years ended December 31, 2002 and 2001, had we adopted SFAS No. 143 effective January 1, 2001.