Contractual Commitments and Obligations

Our contractual commitments for the next five years and thereafter are as follows:

		2003		2004		2005		2006		2007		Thereafter3
		--------------		--------------		-------------		--------------		--------------		---------------
Non-cancelable operating lease commitments		$2,190,363		$2,191,495		$523,755		$190,676		$ 190,676		$186,834
Capital commitments due to pipeline operators		933,666		---		---		---		---		---
Senior Notes due 20091		---		---		---		---		---		125,000,000
Senior Notes due 20121		---		---		---		---		---		200,000,000
Credit Facility which expires in October 20052		---		---		---		---		---		---
		--------------		--------------		-------------		--------------		--------------		---------------
		$ 3,124,029		$ 2,191,495		$523,755		$190,676		$190,676		$325,186,834
		============		===========		===========		============		===========		============

¹These amounts do not include the interest obligation, which is paid semiannually.

²The repayment of the credit facility is based upon the zero balance at December 31, 2002. This amount excludes $0.8 million of a standby letter of credit issued under this facility.

³These amounts exclude asset retirement obligations, as accounted for under SFAS No. 143 "Accounting for Asset Retirement Obligations." We adopted this statement on January 1, 2003, and recorded a liability of $8.9 million. This standard required us to record a liability for the fair value of its dismantlement and abandonment costs, excluding salvage values.

 

Commodity Price Trends and Uncertainties

Oil and natural gas prices historically have been volatile and will likely continue to be volatile in the future. Worldwide supply disruptions, such as the reduction in crude oil production from Venezuela, together with perceived risks such as the threat of war between the United States and Iraq, along with other factors, have caused the price of oil to increase significantly in the first quarter of 2003 when compared to historical prices. Other factors such as actions taken by OPEC, worldwide economic conditions, and weather conditions can cause wide fluctuations in the price of oil. Natural gas prices have also increased significantly in the first quarter of 2003 when compared to 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 wide fluctuations in the price of natural gas. All of the above factors are beyond our control.

Liquidity and Capital Resources

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, 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. During 2001, we relied both upon internally generated cash flows of $139.9 million and upon additional borrowings from our bank credit facility of $123.4 million to fund capital expenditures of $275.1 million.

Net Cash Provided by Operating Activities. In 2002, net cash provided by our operating activities decreased by 49% to $71.6 million, as compared to $139.9 million in 2001 and $128.2 million in 2000. The 2002 decrease of $68.3 million was primarily due to a reduction of oil and gas sales of $40.0 million due to lower commodity prices and to an increase in interest of $10.6 million due to the higher debt balances and interest rates in 2002. The 2001 increase of $11.7 million was primarily due to a $14.0 million reduction in working capital as oil and gas sales receivables decreased in 2001 along with a reduction in interest expense of $3.3 million. These increases in cash flow were offset by an $8.0 million reduction of oil and gas sales, a $7.5 million increase in oil and gas production costs, and a $2.6 million increase in general and administrative expense.

Existing Credit Facilities. At December 31, 2002, we had no outstanding borrowings under our credit facility. Our credit facility at year-end 2002 consisted of a $300.0 million revolving line of credit with a $195.0 million borrowing base. The borrowing base is re-determined at least every six months and was reconfirmed by our bank group in November 2002 with the $195.0 million borrowing base. Our revolving credit facility includes, among other restrictions, requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios) and limitations on incurring other debt. We are in compliance with the provisions of this agreement. The credit facility extends until October 2005. At December 31, 2001, we had $134.0 million in outstanding borrowings under this facility.

Working Capital. Our working capital increased from a deficit of $36.5 million at December 31, 2001, to a deficit of $17.1 million at December 31, 2002. The increase was primarily due to reductions in payables to partnerships related to December 2001 property sales.

Capital Expenditures. In 2002, our capital expenditures of approximately $155.2 million included:

New Zealand activities of $95.2 million as follows:

• $56.1 million, or 36%, on producing properties acquisitions, with approximately $51.7 million spent on the TAWN acquisition and the remainder for the cash portion of our Bligh and Antrim acquisitions;
• $12.6 million, or 8%, on developmental drilling to further delineate the Rimu and Kauri areas;
• $10.6 million, or 7%, on gas processing plants, principally the Rimu Production Station;
• $10.3 million, or 7%, for exploratory drilling in the Rimu and Kauri areas;
• $5.2 million, or 3%, on prospect costs, principally seismic and geological costs;
• $0.4 million, or less than 1%, for fixed assets, principally computers and office furniture and fixtures.

Domestic activities of $60.0 million as follows:

• $34.4 million, or 22%, on developmental drilling;
• $11.1 million, or 7%, on domestic prospect costs, principally leasehold, seismic, and geological costs;
• $8.3 million, or 5%, on exploratory drilling;
• $2.3 million, or 1%, for producing property acquisitions, including the purchase of property interests from partnerships managed by us;
• $2.0 million, or 1%, on gas processing plants in the Brookeland and Masters Creek areas;
• $1.1 million, or less than 1% on field compression facilities; and
• $0.8 million, or less than 1%, for fixed assets.

In 2002, we participated in drilling 23 domestic development wells and seven domestic exploratory wells, of which 17 development wells and three exploratory wells were successful. In New Zealand three development wells and three exploratory wells were drilled. One of the development wells and one of the exploratory wells were dry.

We currently plan to spend $115 to $130 million in total capital expenditures in 2003, excluding acquisition costs and net of approximately $5 million to $15 million in non-core property dispositions. The budget for 2003 is largely dependent upon performance and pricing during the year. Domestic activities account for 85% of budgeted spending, primarily in the Lake Washington Area.

We believe that the anticipated internally generated cash flows for 2003, together with bank borrowings under our credit facility, will be sufficient to finance the costs associated with our currently budgeted 2003 capital expenditures. If other producing property acquisitions become attractive during 2003, we will explore the use of debt and/or equity offerings to fund such activity.

Our capital expenditures were approximately $275.1 million in 2001 and $173.3 million in 2000. During 2000, we used cash flows from operating activities of $128.2 million to fund capital expenditures of $173.3 million, along with part of the remaining net proceeds from our third quarter 1999 issuance of Senior Notes and common stock. During 2001, we relied both upon internally generated cash flows of $139.9 million and upon additional borrowings of $123.4 million from our bank credit facility to fund capital expenditures of $275.1 million. Our capital expenditures in 2001 included:

Domestic activities of $224.3 million as follows:

• $120.6 million, or 44%, on developmental drilling;
• $40.5 million, or 15%, for producing property acquisitions, with approximately $32.6 million spent on the Lake Washington acquisition and the remainder for the purchase of property interests from partnerships managed by us;
• $36.4 million, or 13%, on exploratory drilling;
• $25.3 million, or 9%, on domestic prospect costs, principally leasehold, seismic, and geological costs;
• $1.1 million, or less than 1%, for fixed assets;
• $0.3 million on field compression facilities; and
• $0.1 million on gas processing plants in the Brookeland and Masters Creek areas.

New Zealand activities of $50.8 million as follows:

• $19.0 million, or 7%, on developmental drilling to further delineate the Rimu and Kauri areas;
• $17.9 million, or 7%, on the Rimu Production Station;
• $7.2 million, or 3%, for exploratory drilling in the Rimu and Kauri areas;
• $5.5 million, or 2%, on prospect costs, principally seismic and geological costs;
• $0.8 million, or less than 1%, on producing property acquisition evaluation costs related to our TAWN acquisition; and
• $0.4 million for fixed assets, principally computers and office furniture and fixtures.

In 2001, we participated in drilling 40 development wells and 13 exploratory wells, of which 38 development wells and six exploratory wells were successful. Four of the development wells were drilled in New Zealand to delineate the Rimu and Kauri areas, two of which were successful. Two of the exploratory wells were drilled in New Zealand; one was unsuccessful and one was temporarily abandoned.

Results of Operations

Revenues. Our revenues in 2002 decreased by 18% compared to revenues in 2001 due primarily to decreases in oil and gas prices. Partially offsetting the decrease in commodity prices received was the effect of an increase in production from our New Zealand and Lake Washington areas.

Oil and gas sales revenues in 2002 decreased by 22%, or $40.0 million, from the level of those revenues for 2001 even though our net sales volumes in 2002 increased by 11%, or 5.0 Bcfe, over net sales volumes in 2001. Average prices received for oil decreased to $20.88 per Bbl in 2002 from $22.64 per Bbl in 2001. Average gas prices received decreased to $2.30 per Mcf in 2002 from $4.23 per Mcf in 2001. The increase in production during the 2002 period is primarily from our New Zealand and Lake Washington areas.

In 2002, our $40.0 million decrease in oil and gas sales resulted from:

• Price variances that had a $59.0 million unfavorable impact on sales, of which $6.6 million was attributable to the 8% decrease in average oil prices received and $52.4 million was attributable to the 46% decrease in average gas prices received; and
• Volume variances that had a $19.0 million favorable impact on sales, with $16.2 million of increases coming from the 715,000 Bbl increase in oil sales volumes, and $2.8 million of the increases from the 0.7 Bcf increase in gas sales volumes.

Revenues in 2001 decreased by 4% compared to 2000 revenues. In 2001, oil and gas sales revenues decreased by 4%, or $8.0 million, from the level of those revenues in 2000 even though our net sales volumes in 2001 increased by 6%, or 2.4 Bcfe, over net sales volumes in 2000. Average prices received for oil decreased to $22.64 per Bbl in 2001 from $29.35 per Bbl in 2000. Average gas prices received decreased slightly to $4.23 per Mcf in 2001 from $4.24 per Mcf in 2000.

In 2001, our $8.0 million decrease in oil and gas sales resulted from:

• Price variances that had a $20.6 million unfavorable impact on sales, of which $20.5 million was attributable to the 23% decrease in average oil prices received and $0.1 million was attributable to the slight decrease in average gas prices received; and
• Volume variances that had a $12.6 million favorable impact on sales, with an increase of $17.1 million from the 583,000 Bbl increase in oil sales volumes offset somewhat by a decrease of $4.5 million from the 1.1 Bcf decrease in gas sales volumes.

The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes from our four domestic core areas and New Zealand:

		Revenues				Net Sales Volume
		(in millions)				(Bcfe)
Area		2002		2001		2002		2001
		--------		--------		-------		-------
AWP Olmos		$33.1		$56.1		10.9		13.0
Brookeland		11.9		25.1		4.1		6.5
Lake Washington		18.5		4.6		4.4		1.2
Masters Creek		32.3		62.3		9.7		15.3
Other		16.3		31.3		5.2		8.3
		--------		--------		--------		--------
Total Domestic		$ 112.1		$ 179.4		34.3		44.3
Rimu/Kauri		4.0		1.8		1.5		0.5
TAWN		25.1		---		14.0		---
		-----------		-----------		----------		----------
Total New Zealand		$29.1		$1.8		15.5		0.5
		-----------		-----------		----------		----------
Total		$141.2		$181.2		49.8		44.8

 

The following table provides additional information regarding our oil and gas sales:

		Net Sales Volume							Average Sales Price
		----------------------------------------------							-------------------------------
		Oil and							Oil and
		Condensate		Gas		Combined			Condensate		Gas
		(MBbl)		(Bcf)		(Bcfe)			(Bbl)		(Mcf)
		-------		------		---------			----------		--------
2000:
First Qtr.		653		6.6		10.6			$27.35		$2.93
Second Qtr.		650		6.9		10.8			$27.55		$3.99
Third Qtr.		591		7.0		10.5			$30.68		$4.39
Fourth Qtr.		578		7.0		10.5			$32.26		$5.55
		-------		------		---------
		2,472		27.5		42.4			$29.35		$4.24
		-------		------		---------
2001:
First Qtr.		603		6.7		10.3			$27.63		$6.86
Second Qtr.		691		7.1		11.3			$26.05		$4.66
Third Qtr.		813		6.8		11.7			$23.76		$2.94
Fourth Qtr.		948		5.9		11.5			$16.02		$2.21
		-------		------		---------
		3,055		26.5		44.8			$22.64		$4.23
		-------		------		---------
2002:
First Qtr.		944		6.6		12.3			$16.10		$1.72
Second Qtr.		1,002		6.7		12.7			$20.98		$2.60
Third Qtr.		908		6.7		12.2			$23.05		$2.32
Fourth Qtr.		916		7.1		12.6			$23.55		$2.55
		-------		------		---------
		3,770		27.1		49.8			$20.88		$2.30
		-------		------		---------

 

In the table above, for 2002, natural gas liquids have been combined with oil and condensate for reporting purposes. The natural gas liquids production for 2002 was 1,174 MBbls, at an average price of $12.82 per barrel.

In March 2002, we received $7.5 million for our interest in the Samburg project located in Western Siberia, Russia as a result of the sale by a third party of its ownership in a Russia joint stock company that owned and operated the field. Although the proceeds from sales of oil and gas properties are generally treated as a reduction of oil and gas property costs, because we had previously charged to expense all $10.8 million of cumulative costs relating to our Russian activities, this cash payment, net of transaction expenses, resulted in recognition of a $7.3 million non-recurring gain on asset disposition in the first quarter of 2002. This activity was recorded in “Gain on asset disposition” in the accompanying consolidated statement of income.

During 2002, we recognized net losses of $191,701 relating to our derivative activities, as compared to net gains of $1,173,094 in 2001. In 2002, $7,889 of the losses were unrealized, while $16,784 of losses recognized in 2001 were unrealized. This activity is recorded in “Price-risk management and other, net” on the accompanying income statement.

Revenues from our oil and gas sales comprised 94% of total revenues for 2002 and 99% of total revenues for both 2001 and 2000. Natural gas production made up 55% of our production volumes in 2002, 59% in 2001, and 65% in 2000.

Costs and Expenses. Our expenses in 2002 decreased $86.4 million, or 40%, compared to 2001 expenses. The majority of the decrease was due to the $98.9 million non-cash write-down of domestic oil and gas properties in 2001, offset by increases in operating costs in 2002 related to our increased activities in New Zealand. Our expenses in 2001 increased by $119.5 million, or 121%, compared to 2000 expenses. The majority of this increase was due to the non-cash write-down of domestic oil and gas properties in 2001.

Our general and administrative expenses, net in 2002 increased $2.4 million, or 29%, from the level of such expenses in 2001, while 2001 general and administrative expenses increased $2.6 million, or 47%, over 2000 levels. These increases reflect additional costs needed to run our increased activities in New Zealand, along with a reduction in reimbursement from partnerships we manage as these partnerships have liquidated. Our general and administrative expenses per Mcfe produced increased to $0.21 per Mcfe in 2002 from $0.18 per Mcfe in 2001 and $0.13 per Mcfe in 2000. The portion of supervision fees netted from general and administrative expenses was $3.0 million for 2002, $3.1 million for 2001, and $3.4 million for 2000.

Depreciation, depletion, and amortization of our assets, or DD&A, decreased $3.3 million, or 6%, in 2002 from 2001 levels, while 2001 DD&A increased $11.7 million, or 25%, from 2000 levels. Domestically, DD&A decreased $15.6 million due to decreased production in the 2002 period, the domestic non-cash write-down of oil and gas properties in the fourth quarter of 2001 that decreased our depletable oil and gas property base, and higher reserve volumes that were added primarily though our Lake Washington activities. In New Zealand, our production and the depletable oil and gas property base both increased in the 2002 period due primarily to the TAWN acquisition. The May 2002 commissioning of our Rimu Production Station also increased the depletable oil and gas property base. In 2001, the increase domestically was primarily due to additional dollars spent to add to our reserves and increased associated costs in an environment where demand for oil and gas services had increased compared to 2000, along with a 6% increase in production. Our DD&A rate per Mcfe of production was $1.13 in 2002, $1.33 in 2001, and $1.13 in 2000, reflecting variations in per unit cost of reserves additions.

Our production costs per Mcfe produced were $0.83 in 2002, $0.82 in 2001, and $0.69 in 2000. The portion of supervision fees netted from production costs was $2.0 million for 2002, $3.1 million for 2001, and $3.4 million for 2000. Our production costs in 2002 increased $4.8 million, or 13%, over such expenses in 2001, while those expenses in 2001 increased $7.5 million, or 26%, over 2000 costs. Overall, production costs increased in 2002 as our New Zealand activities increased, offsetting the domestic production costs decrease which mainly was due to a decrease in production volumes. Approximately $1.7 million of the increase in production costs during 2001 was related to severance taxes. Severance taxes increased primarily from the expiration of certain specific well severance tax exemptions. The remainder of the 2001 increase reflected costs associated with new wells drilled and acquired and the related increase in costs in procuring such services in an environment where demand for oil and gas services has increased from the prior year.

Interest expense on our Senior Notes issued in July 1999, including amortization of debt issuance costs, totaled $13.2 million in 2002 and $13.1 million in both 2001 and 2000. Interest expense on our Senior Notes issued in April 2002, including amortization of debt issuance costs, totaled $13.5 million in 2002. Interest expense on our Convertible Notes due 2006, including amortization of debt issuance costs, totaled $7.4 million in 2000. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $3.6 million in 2002, $5.8 million in 2001, and $0.7 million in 2000. The total interest cost in 2002 was $30.3 million, of which $7.0 million was capitalized. The total interest cost in 2001 was $18.9 million, of which $6.3 million was capitalized. The 2000 total interest cost was $21.2 million, of which $5.2 million was capitalized. We capitalize that portion of interest related to our exploration, partnership, and foreign business development activities. The increase in interest expense in 2002 was attributed to the replacement of our bank borrowings in April 2002 with the Senior Notes that carry a higher interest rate. The decrease in total interest expense in 2001 was attributed to the conversion and extinguishment of our Convertible Notes in December 2000 and the increase in capitalized interest, partially offset by the increase in interest paid on our credit facility.

In the fourth quarter of 2001, we recognized a domestic non-cash write-down of oil and gas properties, as discussed in Note 1 to the Consolidated Financial Statements. Lower prices for both oil and natural gas at December 31, 2001, necessitated a pre-tax domestic full-cost ceiling write-down of $98.9 million, or $63.5 million after tax. In addition to this domestic ceiling write-down, we also expensed $2.1 million of charges in the fourth quarter of 2001 for certain delinquent accounts receivable, the majority of which were related to gas sold to Enron, and a write-off of debt issuance costs for a planned offering that was cancelled based upon market conditions following the events of September 11, 2001.

As discussed in Note 1 to the Consolidated Financial Statements, we adopted SFAS No. 133, amended by SFAS No. 137 and SFAS No. 138, on January 1, 2001. Our adoption of SFAS No. 133 resulted in a one-time net of taxes charge of $392,868, which is recorded as a “Cumulative Effect of Change in Accounting Principle” on the 2001 consolidated statement of income.

In the fourth quarter of 2000, we recorded a $0.6 million loss on the early extinguishment of debt (net of taxes), as discussed in Note 4 to the financial statements. We called our Convertible Notes for redemption effective December 26, 2000. Holders of approximately $100.0 million of the Convertible Notes elected to convert their notes into shares of our common stock. Holders of the remaining $15.0 million of the Convertible Notes elected to redeem their notes for cash plus accrued interest. This cash redemption resulted in this extraordinary item.

Net Income (Loss). Our net income in 2002 of $11.9 million was 153% higher and basic earnings per share (“Basic EPS”) of $0.45 was 150% higher than our 2001 net loss of $(22.3) million and basic loss per share (“Basic EPS”) of $(0.90). Our earnings per diluted share in 2002 of $0.45 was 150% higher than our 2001 loss per diluted share of $(0.90). These amounts increased in 2002 due to overall lower costs, as a non-cash write-down of oil and gas properties occurred in 2001 and not 2002, offset somewhat by lower revenue in 2002.

Our net loss in 2001 of $(22.3) million was 138% lower and basic loss per share of $(0.90) was 132% lower than our 2000 net income of $59.2 million and basic earnings per share of $2.79. Our earnings per diluted share in 2001 of $(0.90) was 136% lower than our 2000 earnings per diluted share of $2.51. These decreases reflected the effect of $101.0 million in charges in 2001 as described above.

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 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.

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 or 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 2002, 2001, and 2000, such internal costs capitalized totaled $10.7 million, $11.6 million, and $10.3 million, respectively. Interest costs related to unproved properties are also capitalized to unproved oil and gas properties. 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.

Future development, site restoration, and dismantlement and abandonment costs, net of salvage values, 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, site restoration, and dismantlement and abandonment costs, net of salvage value, 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. This calculation is done on a country-by-country basis. 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.

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, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using unhedged 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”). 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 our 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.

Price-Risk Management Activities. We follow 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 reported in the balance sheet as either an asset or 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 would require that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

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 protection price floors and collars. We adopted SFAS No. 133 effective January 1, 2001. Accordingly, we marked our open contracts at December 31, 2000, to fair value at that date, resulting in a one-time net of taxes charge of $392,868, which was recorded as a Cumulative Effect of Change in Accounting Principle. During 2002 and 2001, we recognized net losses of $191,701 and net gains of $1,173,094 relating to our derivative activities. Approximately $7,889 of the losses recognized in 2002 were unrealized as the contracts were still open, while $16,784 of losses recognized in the comparative 2001 period were unrealized. This activity is recorded in “Price-risk management and other, net” on the accompanying statements of income. At December 31, 2002, we had recorded $178,053, net of taxes of $100,155, 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 2002 was not material. We expect to reclassify all amounts held in “Other comprehensive loss” into the statement of income within the next six months.

As of December 31, 2002, we had entered into the cash flow hedge commodity derivative instruments set forth in the table below for our domestic oil and natural gas production for portions of 2003. When we entered into the following transactions they were designated as a hedge of the variability in cash flows associated with the forecasted sale of our oil and 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 initially 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 transferred from Other Comprehensive Income (Loss) and recorded in “Price-risk management and other, net” on the 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 is recognized on the balance sheet, in “Accounts payable and accrued liabilities,” at December 31, 2002.

Crude Oil - Cash Flow Hedges
				Collars
				------------------------------------------------
Period and Type of Contract		Volume in Bbls (000s)		Floors Weighted Average		Ceilings Weighted  Average		December 31, 2002 Fair Value (000s)
------------------------------------------		-----------------		--------------------		--------------------		----------------------
January 2003 - June 2003     Participating Collar Contracts		360		$21.00				$76
		144				$30.35		$(256)
								----------------------
Total								$(180)
								----------------------
Natural Gas  - Cash Flow Hedges
				Collars
				------------------------------------------------
Period and Type of Contract		Volume in MMBtu (000s)		Floors Weighted Average		Ceilings Weighted  Average		December 31, 2002 Fair Value (000s)
------------------------------------------		-----------------		--------------------		--------------------		----------------------
January 2003 - June 2003     Participating Collar Contracts		1,900		$3.00				$12
		760				$5.27		$(122)
								----------------------
Total								$(110)
								----------------------

 

In January and February 2003, we entered into natural gas “floors” financial transactions covering contract periods April 2003 to October 2003. Notional volumes are 450,000 MMBtu per month at a weighted average floor price of $4.36 per MMBtu. In January 2003, we entered into crude oil “floors” financial transactions covering the contract periods of February to April 2003. Notional volumes are 625,000 barrels over the three-month period with a weighted average floor price of $26.39 per barrel. Also in February 2003, we entered into a crude oil “collar” financial transaction covering the contract period April 2003 to June 2003. Notional volumes are 120,000 barrels over the three-month period with a weighted average floor price of $25.25 per barrel and 48,000 barrels over the three-month period with a weighted average ceiling price of $33.08 per barrel.

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

Related-Party Transactions

We have been the operator of a number of properties owned by our affiliated limited partnerships and, accordingly, charge these entities operating fees. The operating fees charged to the partnerships in 2002, 2001, and 2000 totaled approximately $300,000, $925,000, and $1,775,000, respectively, and are recorded as reductions of general and administrative expense and oil and gas production expense. We also have been reimbursed for direct, administrative, and overhead costs incurred in conducting the business of the limited partnerships, which totaled approximately $973,000, $3,140,000, and $4,465,000 in 2002, 2001, and 2000, respectively. In partnerships in which the limited partners voted to sell their remaining properties and liquidate their limited partnerships, we also have been reimbursed for direct, administrative, and overhead costs incurred in the disposition of such properties, which costs totaled approximately $510,000, $2,360,000, and $1,220,000 in 2002, 2001, and 2000, respectively.

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 and 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 herein 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.

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