Our production costs were up in 2004 predominantly because of increased production in Lake Washington, higher severance taxes due to increased domestic revenues, and currency exchange rates in New Zealand. Our general and administrative expenses increased in 2004 primarily due to an increase in costs related to our on going compliance efforts with the Sarbanes-Oxley Act, and to increased salaries and benefits.

Our debt to PV-10 ratio decreased to 18% at December 31, 2004 compared to 22% at December 31, 2003, due to higher crude oil and natural gas prices, which have increased our PV-10 value. Our debt to capitalization ratio was 43% at December 31, 2004 compared to 46% at year-end 2003, as debt levels increased slightly in 2004 but were offset by the increase in retained earnings as a result of current year profit. In June 2004, we repurchased $32.1 million of our 10-1/4% senior subordinated notes due 2009 through a tender offer. In July 2004, we repurchased $0.5 million of our 10-1/4% notes at the close of the tender offer. On August 1, 2004, we redeemed the remaining $92.5 million of these notes in accordance with our redemption rights under the indenture governing these notes. In 2004, we recorded approximately $9.5 million of debt retirement costs related to the repurchase of these notes. The redemption of these 10-1/4% notes lowered our effective interest rate.

Year-end 2004 proved reserves of 799.8 Bcfe, representing a 3% decline for the year, were 49% crude oil, 40% natural gas and 11% NGLs, compared to year-end 2003 proved reserves of 820.4 Bcfe, which were 47% crude oil, 41% natural gas and 12% NGLs. Proved developed reserves remained essentially the same at 56% of total reserves at year-end 2004, compared to 59% the previous year. Domestic proved reserves increased at year-end 2004 to 652.7 Bcfe, driven by the acquisition of reserves in December 2004 in the Bay de Chene and Cote Blanche Island fields, which were predominantly proved undeveloped. Proved reserves in New Zealand decreased to 147.1 Bcfe at year-end 2004, primarily attributable to 2004 production and slight downward revisions in the Manutahi and upper Tariki Sands. In 2004 we focused our drilling activity, both domestically and in New Zealand, on proved undeveloped locations that helped maximize production in a high-price environment, but which also resulted in smaller additions to proved reserves.

Results of Operations — Years Ended 2004, 2003, and 2002

Revenues. Our revenues in 2004 increased by 49% compared to revenues in 2003, and our revenues in 2003 increased by 39% compared to 2002 revenues due primarily to increases in oil and natural gas prices in each successive year and increases in production from our Lake Washington area. Revenues from our oil and gas sales comprised substantially all of total revenues for 2004 and 2003, and 94% of total revenues for 2002. Crude oil production comprised 49% of our production volumes in 2004, 38% in 2003, and 31% in 2002. Natural gas production comprised 41% of our production volumes in 2004, 53% in 2003, and 55% in 2002. Domestic production comprised 72% of our total production volumes in 2004, 64% in 2003, and 69% in 2002.

The following table provides information regarding the changes in the sources of our oil and gas sales and volumes for the years ended December 31, 2004, 2003, and 2002:

Costs and Expenses. Our expenses in 2004 increased $50.7 million, or 32%, compared to 2003 expenses. The majority of the increase was due to an $18.5 million increase in DD&A, an $11.4 million increase in severance and other taxes, and a $7.4 million increase in lease operating costs, all of which are primarily due to increased production volumes and oil and gas commodity prices in 2004. We also recorded $9.5 million of debt retirement costs in 2004. Our expenses in 2003 increased $26.6 million, or 20%, compared to 2002 expenses. The majority of the increase was due to a $4.9 million increase in lease operating costs, a $6.5 million increase in severance and other taxes, and a $6.8 million increase in DD&A, all of which increased as our production volumes and revenues increased in 2003.

Our 2004 general and administrative expenses, net, increased $3.7 million, or 26%, from the level of such expenses in 2003, while 2003 general and administrative expenses, net, increased $3.5 million, or 33%, over 2002 levels. The increase in both 2004 and 2003 were primarily due to compliance with the Sarbanes-Oxley Act, increased salaries and burdens, and our increased activities in New Zealand. In 2004, Sarbanes-Oxley Act compliance costs, including internal and external costs, totaled $2.2 million.. The increase in 2003 was also due to a reduction in reimbursements from partnerships that we managed as almost all of the partnerships have been liquidated, along with an increase in franchise tax expense. For the years 2004, 2003, and 2002, our capitalized general and administrative costs totaled $13.1 million, $11.5 million, and $10.7 million, respectively. Our net general and administrative expenses per Mcfe produced increased to $0.30 per Mcfe in 2004 from $0.27 per Mcfe in 2003 and $0.21 per Mcfe in 2002. The portion of supervision fees recorded as a reduction to general and administrative expenses was $5.8 million for 2004, $3.6 million for 2003, and $3.1 million for 2002.

DD&A increased $18.5 million, or 29%, in 2004 from 2003 levels, while 2003 DD&A increased $6.8 million, or 12%, from 2002 levels. Domestically, DD&A increased $17.6 million in 2004 due to increases in the depletable oil and gas property base, higher production in the 2004 period and slightly lower reserve volumes. In New Zealand, DD&A increased by $0.9 million in 2004 due to increases in the depletable oil and gas property base along with lower reserve volumes, offset by lower production in the 2004 period. In 2003, our domestic DD&A increased by $1.0 million due to increases in the depletable oil and gas property base, offset by slightly lower production in the 2003 period and higher reserve volumes that were added primarily through our Lake Washington activities. Our New Zealand DD&A increased by $5.8 million in 2003 due to increased production in the 2003 period. Our DD&A rate per Mcfe of production was $1.40 in 2004, $1.19 in 2003, and $1.13 in 2002, resulting from increases in per unit cost of reserves additions.

We recorded $0.7 million and $0.9 million of accretions to our asset retirement obligation in 2004 and 2003, respectively.

Our lease operating costs per Mcfe produced were $0.71 in 2004, $0.64 in 2003 and $0.58 in 2002. There were no supervision fees recorded as a reduction to production costs in 2004, while there were $1.5 million in 2003 and $2.1 million in 2002. Our lease operating costs in 2004 increased $7.4 million, or 22%, over the level of such expenses in 2003, while 2003 costs increased $4.9 million, or 17% over 2002. Approximately $6.2 million of the increase in lease operating costs during 2004 was related to our domestic operations, which increased primarily due to increased compression and chemical costs in Lake Washington resulting from higher production from our Lake Washington area along with the reduction of 2003 expense of $1.5 million from supervision fees. Our lease operating cost in New Zealand increased in 2004 by $1.2 million due to the continued development of our Rimu/Kauri area and the increased currency exchange rate of the New Zealand dollar as compared to the U.S. dollar. Approximately $4.2 million of the increase in 2003 was due to our New Zealand operations as production increased over 2002 levels.

Severance and other taxes increased $11.4 million, or 60% over 2003 levels, while in 2003 these taxes increased $6.5 million, or 51% over 2002 levels. The increase was due primarily to higher commodity prices and increased Lake Washington and Rimu/Kauri production in each of the periods. Severance taxes on oil in Louisiana are 12.5% of oil sales, which is higher than the other states where we have production. As our percentage of oil production in Louisiana increases, the overall percentage of severance costs to sales also increases. Severance and other taxes, as a percentage of oil and gas sales, were approximately 9.8%, 9.0% and 8.9% in 2004, 2003 and 2002, respectively.

Interest expense on our 7-5/8% senior notes due 2011 issued in June 2004, including amortization of debt issuance costs, totaled $6.2 million in 2004. Interest expense on our 9-3/8% senior subordinated notes due 2012 issued in April 2002, including amortization of debt issuance costs, totaled $19.2 million in 2004, $19.1 million in 2003 and $13.5 million in 2002. Interest expense on our 10-1/4% senior subordinated notes issued in August 1999 and repurchased and retired in 2004, including amortization of debt issuance costs, totaled $7.4 million in 2004, and $13.2 million in both 2003 and 2002. Interest expense on our bank credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.5 million in 2004, $1.6 million in 2003, and $3.6 million in 2002. Other interest cost was $0.3 million in 2003. Our total interest cost in 2004 was $34.2 million, of which $6.5 million was capitalized. Our total interest cost in 2003 was $34.2 million, of which $6.8 million was capitalized. Our total interest cost in 2002 was $30.3 million, of which $7.0 million was capitalized. We capitalize a portion of interest related to unproved properties. The increase of interest expense in 2004 was due to lower capitalized interest than in 2003. The increase in interest expense in 2003 was attributed to the replacement of our bank borrowings in April 2002 with our 9-3/8% senior subordinated notes due 2012 with a longer repayment term but a higher interest rate.

In 2004, we incurred $9.5 million of debt retirement costs related to the repurchase and redemption of our 10-1/4% senior subordinated notes due 2009. The costs were comprised of approximately $6.5 million of premiums paid to repurchase the notes, $2.2 million to write-off unamortized debt issuance costs, $0.6 million to write-off unamortized debt discount and approximately $0.2 million of other costs.

The overall effective tax rate was 32.5% in both 2004 and 2003 and 35.2% in 2002. 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 of approximately $1.3 million 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 domestic state income taxes and other items.

As discussed in Note 1 to the consolidated financial statements, we adopted SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003. Our adoption of SFAS No. 143 resulted in a one-time net of taxes charge of $4.4 million, which was recorded as a cumulative effect of change in accounting principle in the 2003 consolidated statement of income.

Net Income. Our net income in 2004 of $68.5 million was 129% higher than our 2003 net income of $29.9 million due to higher commodity prices and increased production.

Our net income in 2003 of $29.9 million was 151% higher than our 2002 net income of $11.9 million due to higher commodity prices and increased production.

Contractual Commitments and Obligations

Our contractual commitments for the next five years and thereafter as of December 31, 2004 are as follows:

(1) Our office lease in Houston, Texas extends until 2015.

(2) Amounts shown by year are the fair values at December 31, 2004.

(3) Amounts do not include the interest obligation, which is paid semiannually.

(4) The credit facility expires in October 2008 and these amounts exclude a $0.8 million standby letter of credit outstanding under this facility.

Commodity Price Trends and Uncertainties

Oil and natural gas prices historically have been volatile and are expected to continue to be volatile in the future. The price of oil has increased over the last two years and is currently significantly higher when compared to longer-term historical prices. Factors such as worldwide supply disruptions, worldwide economic conditions, weather conditions, actions taken by OPEC, and fluctuating currency exchange rates can cause wide fluctuations in the price of oil. Domestic natural gas prices continue to remain high when compared to longer-term historical prices. North American weather conditions, the industrial and consumer demand for natural gas, storage levels of natural gas, and the availability and accessibility of natural gas deposits in North America can cause significant fluctuations in the price of natural gas. Such factors are beyond our control.

Liquidity and Capital Resources

During 2004, we largely relied upon our net cash provided by operating activities of $182.6 million, the issuance of our 7-5/8% senior notes due 2011, proceeds from the sale of non-core properties and equipment of $5.1 million, less the repayment of our 10-1/4% senior subordinated notes due 2009 to fund capital expenditures of $171.1 million and acquisitions of $27.2 million. During 2003, we relied upon our net cash provided by operating activities of $110.8 million, proceeds from bank borrowings of $15.9 million, and proceeds from the sale of non-core properties and equipment of $10.2 million to fund capital expenditures of $144.5 million.

Net Cash Provided by Operating Activities. For 2004, our net cash provided by operating activities was $182.6 million, representing a 65% increase as compared to $110.8 million generated during 2003. The $71.8 million increase in 2004 was primarily due to an increase of $100.3 million in oil and gas sales, attributable to higher commodity prices and production, offset in part by higher lease operating costs due to higher domestic production and severance taxes as a result of higher commodity prices in 2004. In 2003, net cash provided by operating activities increased by 55% to $110.8 million, as compared to $71.6 million in 2002. The 2003 increase of $39.2 million was primarily due to an increase of oil and gas sales of $69.8 million due to higher commodity prices and production.

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 2002 and 2001 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.

Sarbanes-Oxley Compliance Costs. We have incurred substantial costs to comply with the Sarbanes-Oxley Act of 2002. These expenditures have reduced our net cash provided by operating activities in each of the last two years. In 2004, Sarbanes-Oxley Act compliance costs, including internal and external costs, totaled $2.2 million and are reflected in "General and administrative, net" on the accompanying statements of income. We expect the costs of Sarbanes-Oxley compliance to decrease from 2004 levels in future years.

Existing Credit Facility. We had $7.5 million in borrowings under our bank credit facility at December 31, 2004, and $15.9 million in outstanding borrowings at December 31, 2003. Our bank credit facility at December 31, 2004 consisted of a $400.0 million revolving line of credit with a $250.0 million borrowing base. The borrowing base is re-determined at least every six months and was reaffirmed by our bank group at $250.0 million, effective November 1, 2004. In June 2004, we renewed this credit facility, increasing the facility amount to $400.0 million from $300.0 million and extending its expiration to October 1, 2008 from October 1, 2005. We maintained the commitment amount at $150.0 million, which amount was set at our request effective May 9, 2003. Under the terms of our bank credit facility, we can increase this commitment amount to the total amount of the borrowing base at our discretion, subject to the terms of the credit agreement. Our revolving credit facility includes, among other restrictions that changed somewhat as the facility was renewed and extended, requirements to maintain certain minimum financial ratios (principally pertaining to adjusted working capital ratios and EBITDAX), and limitations on incurring other debt. We are in compliance with the provisions of this agreement.

Our access to funds from our credit facility is not restricted under any "material adverse condition" clause, a clause that is common for credit agreements to include. A "material adverse condition" clause can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have an adverse or material effect on our operations, financial condition, prospects or properties, and would impair our ability to make timely debt repayments. Our credit facility includes covenants that require us to report events or conditions having a material adverse effect on our financial condition. The obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.

Working Capital. Our working capital improved from a deficit of $35.9 million at December 31, 2003, to a deficit of $14.2 million at December 31, 2004. The improvement primarily resulted from a decrease in accrued capital costs due to a reduction in our drilling activities at year-end 2004 in comparison with year-end 2003 activity, along with an increase in accounts receivable for oil and gas sales due to higher sales volumes and commodity prices.

Repurchase of 10-1/4% Senior Subordinated Notes Due 2009. In June 2004, we repurchased $32.1 million of our 10-1/4 senior subordinated notes due 2009 pursuant to a tender offer, and recorded debt retirement costs of $2.7 million related to this repurchase. In July 2004, we repurchased approximately $0.5 million of these notes, and as of August 1, 2004, we redeemed the remaining $92.5 million of these notes. We have recorded a total of $9.5 million in debt retirement costs related to the total repurchase of these notes.

Debt Maturities. Our credit facility extends until October 1, 2008. Our $150.0 million of 7-5/8% senior notes mature July 15, 2011, and our $200.0 million of 9-3/8% senior subordinated notes mature May 1, 2012.

Capital Expenditures. We relied upon our net cash provided by operating activities of $182.6 million, the issuance of our 7-5/8% senior notes due 2011, and proceeds from the sale of non-core properties and equipment of $5.1 million, less the repayment of our 10-1/4% senior subordinated notes due 2009, to fund capital expenditures of $171.1 million and acquisitions of $27.2 million. Our total capital expenditures of approximately $198.3 million in 2004 included:

Domestic expenditures of $162.5 million as follows:

•$87.7 million for drilling and developmental activity costs, predominantly in our Lake Washington area;

•$31.8 million on property acquisitions, including $27.2 million to acquire properties in the Bay de Chene and Cote Blanche Island fields;

•$28.7 million of domestic prospect costs, principally prospect leasehold, Lake Washington three-dimensional seismic activity, and geological costs of unproved prospects;

•$9.9 million on exploratory drilling, mainly in our Lake Washington area;

•$2.5 million primarily for a field office building, computer equipment, software, furniture, and fixtures;

•$1.3 million on field compression facilities; and

•$0.6 million on gas processing plants in the Brookeland and Masters Creek areas.

New Zealand expenditures of $35.8 million as follows:

•$26.7 million for drilling costs and developmental activity costs, predominantly in our Rimu/Kauri area;

•$7.0 million on prospect costs, principally prospect leasehold, seismic and geological costs of unproved properties;

•$1.2 million on gas processing plants;

•$0.7 million on exploratory drilling; and

•$0.2 million for computer equipment, software, furniture, and fixtures.

We have spent considerable time and capital in 2004 and 2003 on significant facility capacity upgrades in the Lake Washington field to increase facility capacity to approximately 20,000 barrels per day for crude oil, up from 9,000 barrels per day capacity in the first quarter of 2003. We have upgraded three production platforms, added new compression for the gas lift system, and installed a new oil delivery system and permanent barge loading facility.

We successfully completed 51 of 66 wells in 2004, for a success rate of 77%. Domestically, we completed 37 of 44 development wells for a success rate of 84% and completed four of ten exploration wells. A total of 30 wells were drilled in the Lake Washington area, of which 21 were completed, and 15 wells were drilled in the AWP Olmos area, of which 13 were completed. In New Zealand, we completed 10 of 12 wells, consisting of four Kauri sand wells drilled, five of six Manutahi sand wells, and the Tariki-D1 well.

Our 2005 capital expenditure budget is $200 million to $220 million, net of $5 million to $15 million of dispositions and excluding any acquisitions. Approximately 80% of the budget is targeted for domestic activities, primarily in South Louisiana, with about 20% planned for activities in New Zealand. Approximately $15 million to $20 million of the 2005 budget will be focused on activity in the newly acquired properties in Bay de Chene and Cote Blanche Island fields. The $5 million to $15 million of dispositions relate to non-core properties planned for later in 2005. We expect that our 2005 capital expenditures will begin at the low end of the range, and depending on commodity prices and operational performance, they may increase to the high end of the range during the course of the year. We anticipate 2005 capital expenditures to approximate our cash flows provided from operating activities during 2005, similar to 2004. For 2005, we are targeting total production and proved reserves to increase 7% to 12% over the 2004 levels.

Our capital expenditures were approximately $144.5 million in 2003 and $155.2 million in 2002. During 2003, we relied upon our net cash provided by operating activities of $110.8 million, proceeds from bank borrowings of $15.9 million, and proceeds from the sale of non-core properties and equipment of $10.2 million to fund capital expenditures of $144.5 million. During 2002, we principally relied upon cash provided by operating activities of $71.6 million, net proceeds from the issuance of long-term debt of $195.0 million of 9-3/8% senior subordinated notes due 2012, and net proceeds from our public stock offering of $30.5 million, less the repayment of bank borrowings of $134.0 million, to fund capital expenditures of $155.2 million. Our capital expenditures in 2003 of approximately $144.5 million included:

Domestic activities of $114.4 million as follows:

•$57.0 million on drilling and developmental activities, primarily in our Lake Washington area;

•$25.9 million for the construction of production and surface facilities, mainly in our Lake Washington area;

•$11.9 million on exploratory drilling, primarily in our Lake Washington area;

•$11.4 million on domestic prospect costs, principally leasehold, seismic, and geological costs;

•$4.4 million on field compression facilities;

•$2.0 million for producing property acquisitions;

•$0.9 million for fixed assets; and

•$0.9 million on gas processing plants in the Brookeland and Masters Creek areas.

New Zealand activities of $30.1 million as follows:

•$15.1 million on developmental activities primarily to further delineate the Rimu/Kauri area;

•$6.4 million on prospect costs;

•$5.7 million on gas processing plants;

•$2.3 million for exploratory drilling mainly for the Tuihu exploratory well;

•$0.3 million on producing properties acquisitions; and

•$0.3 million for fixed assets.

In 2003, we participated in drilling 63 domestic development wells and eight domestic exploratory wells, of which 53 development wells and five exploratory wells were completed. In New Zealand we drilled and completed three development wells and drilled one unsuccessful exploratory well.

Income Tax Regulations

The tax laws in the jurisdictions we operate in are continuously changing and professional judgments regarding such tax laws can differ. We do not believe the recently enacted American Jobs Creation Act of 2004 will have a material impact on our financial position or cash flow from operations in the near-term.

New Accounting Principles

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.

We have elected to adopt the provisions of SFAS No. 123R on July 1, 2005 using the modified prospective method. As permitted by Statement 123, the Company currently accounts 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 result of operations. However, it will have no impact on our overall financial position. We currently use the Black-Scholes formula to estimate the value of stock options granted to employees and expect to continue to use this acceptable option valuation model upon the required adoption of SFAS No. 123R. The significance of the impact of adoption will depend on levels of 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 in "Stock Based Compensation," under Note 1 to our accompanying consolidated financial statements. Statement No. 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption. While the Company cannot estimate what those amounts will be in the future (because they depend on, among other things, when employees exercise stock options), the amount of excess tax deductions recognized were $2.0 million, $0.2 million, and $0.3 million in 2004, 2003 and 2002, respectively. These deductions resulted in an increase in operating cash flows, however, due to the Company’s net operating tax loss position, deferred income taxes were reduced rather than actual cash taxes paid.

Proved Oil and Gas Reserves

At year-end 2004, our total proved reserves were 799.8 Bcfe with a PV-10 Value of $2.0 billion. In 2004, our proved natural gas reserves decreased 17.6 Bcf, or 5%, while our proved oil reserves increased 1.8 MMBbl, or 3%, and our NGL reserves decreased 2.3 MMBbl, or 14%, for a total equivalent decrease of 20.5 Bcfe, or 3%. In 2003, our proved natural gas reserves increased by 9.1 Bcf, or 3%, while our proved oil reserves increased by 11.4 MMBbl, or 22%, and our NGL reserves decreased by 1.0 MMBbl, or 6%, for a total equivalent increase of 71.0 Bcfe, or 9%. We added reserves over the past three years through both our drilling activity and purchases of minerals in place. Through drilling we added 7.2 Bcfe (all of which was domestic) of proved reserves in 2004, 105.6 Bcfe (36.1 Bcfe of which came from New Zealand) in 2003, and 83.9 Bcfe (15.9 Bcfe of which came from New Zealand) in 2002. Through acquisitions we added 43.4 Bcfe of proved reserves in 2004, 0.5 Bcfe in 2003, and 74.2 Bcfe in 2002. At year-end 2004, 56% of our total proved reserves were proved developed, compared with 59% at year-end 2003 and 60% at year-end 2002.

The PV-10 Value of our total proved reserves increased 31% from the PV-10 Value at year-end 2003. Gas prices increased in 2004 to $5.16 per Mcf from $4.56 per Mcf at year-end 2003, compared to $3.49 per Mcf at year-end 2002. Oil prices increased in 2004 to $41.07 per Bbl from $30.16 per Bbl at year-end 2003, compared to $29.27 in 2002. Under SEC guidelines, estimates of proved reserves must be made using year-end oil and gas sales prices and are held constant, for that year’s reserve calculation, throughout the life of the properties. Subsequent changes to such year-end oil and gas prices could have a significant impact on the calculated PV-10 Value.

Critical Accounting Policies

The following summarizes several of our critical accounting policies. See a complete list of significant accounting policies in Note 1 to the consolidated financial statements.

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 that were used to prepare these financial statements include:

• the estimated quantities of proved oil and natural gas reserves used to compute depletion of our properties and the related present value of estimated future net cash flows from these properties,
• accruals related to oil and gas production and revenues, capital expenditures and lease operating and severance tax expenses,
• 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 significant 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.

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 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, including future 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 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.

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.

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 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 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 2004 contract month for natural gas, these 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 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, 2004, was $1.8 million and is recognized on the balance sheet in "Other current assets."

From January 2005 to the date of this filing, we entered into additional natural gas price floors covering contract periods April 2005 to October 2005, which cover our natural gas production for April 2005 to October 2005. Notional volumes are 1,300,000 MMBtu at a weighted average floor price of $5.73 per MMBtu.

See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for additional discussion of commodity risk.

Stock Based Compensation. We have two stock-based compensation plans, which are described more fully in Note 6 to our accompanying consolidated financial statements. 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 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 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.

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 a 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.

Related-Party Transactions

We have been the operator of a number of properties owned by affiliated limited partnerships and, accordingly, charge these entities operating fees. The operating fees charged to the partnerships totaled approximately $0.2 million in 2004 and 2003 and approximately $0.3 million in 2002 and are recorded as reductions of general and administrative, net. We also have been reimbursed for administrative and overhead costs incurred in conducting the business of the limited partnerships, which totaled approximately $0.2 million, $0.4 million, and $1.0 million in 2004, 2003, and 2002, respectively, and are recorded as reductions in general and administrative, net. Included in "Accounts receivable" and "Accounts payable and accrued liabilities" on the accompanying balance sheets is less than $0.1 million and $1.1 million, respectively, in receivables from and payables to the partnerships at December 31, 2004.

We receive research, technical writing, publishing, and website-related services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and controlled by the sister of the Company’s Chairman and Vice Chairman of the Board. The sister and brother-in-law of Messrs. A. E. Swift and V. Swift also own a substantial majority of Tec-Com. In 2004, 2003 and 2002, we paid approximately $0.4 million per year to Tec-Com for such services pursuant to the terms of the contract between the parties. The contract was renewed June 30, 2004 on substantially the same terms and expires June 30, 2007. We believe that the terms of this contract are consistent with third party arrangements that provide similar services. As a matter of corporate governance policy and practice, related party transactions are annually presented and considered by the Corporate Governance Committee of our Board of Directors in accordance with the Committee’s charter.

Forward-Looking Statements

The statements contained in this report that are not historical facts are forward-looking statements as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended. Such forward-looking statements may pertain to, among other things, financial results, capital expenditures, drilling activity, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters, and competition. Such forward-looking statements generally are accompanied by words such as "plan," "future," "estimate," "expect," "budget," "predict," "anticipate," "projected," "should," "believe," or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions, upon current market conditions, and upon engineering and geologic information available at this time, and is subject to change and to a number of risks and uncertainties, and, therefore, actual results may differ materially. Among the factors that could cause actual results to differ materially are: volatility in oil and natural gas prices, internationally or in the United States; availability of services and supplies; fluctuations of the prices received or demand for our oil and natural gas; the uncertainty of drilling results and reserve estimates; operating hazards; requirements for capital; general economic conditions; changes in geologic or engineering information; changes in market conditions; competition and government regulations; as well as the risks and uncertainties discussed in this report and set forth from time to time in our other public reports, filings, and public statements. Also, because of the volatility in oil and gas prices and other factors, interim results are not necessarily indicative of those for a full year.