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, 2006, 2005, and 2004:

	Oil and Gas Sales			Oil and Gas Sales Volume
	(In millions)			(Bcfe)
Area	2006	2005	2004	2006	2005	2004
	--------	--------	--------	--------	--------	--------
AWP Olmos	$ 53.7	$ 61.7	$ 49.9	7.5	7.7	9.0
Brookeland	15.6	20.4	18.0	2.1	2.9	3.4
Lake Washington	397.2	229.2	152.3	38.7	26.7	23.2
Masters Creek	13.3	17.9	21.0	1.7	2.4	3.7
Cote Blanche Island / Bay de Chene	29.3	7.4	0.0	3.1	0.9	0.0
Other	28.4	19.3	17.5	3.6	2.4	2.8
	--------	--------	--------	--------	--------	--------
Total Domestic	$ 537.5	$ 355.9	$ 258.7	56.7	43.0	42.1
Rimu/Kauri	36.8	41.6	24.5	6.3	8.2	5.3
TAWN	27.2	26.3	28.1	7.2	8.3	11.0
	--------	--------	--------	--------	--------	--------
Total New Zealand	$ 64.0	$ 67.9	$ 52.6	13.5	16.5	16.3
	--------	--------	--------	--------	--------	--------
Total	$ 601.6	$ 423.8	$ 311.3	70.2	59.6	58.3
	=======	=======	=======	=======	=======	=======

 

Oil and gas sales in 2006 increased by 42%, or $177.8 million, from the level of those revenues for 2005, and our net sales volumes in 2006 increased by 18%, or 10.6 Bcfe, over net sales volumes in 2005. Average prices for oil increased to $64.47 per Bbl in 2006 from $53.63 per Bbl in 2005. Average natural gas prices decreased to $5.05 per Mcf in 2006 from $5.23 per Mcf in 2005. Average NGL prices increased to $32.15 per Bbl in 2006 from $28.04 per Bbl in 2005.

In 2006, our $177.8 million increase in oil, NGL, and natural gas sales resulted from:

• Volume variances that had a $101.1 million favorable impact on sales, with $108.9 million of increases attributable to the 2.0 million Bbl increase in oil sales volumes, offset by a decrease of $3.5 million due to the 0.1 million Bbl decrease in NGL sales volumes, and a decrease of $4.3 million due to the 0.8 Bcf decrease in natural gas sales volumes; and

• Price variances that had a $76.7 million favorable impact on sales, of which $78.0 million was attributable to the 20% increase in average oil prices received, and $2.9 million was attributable to the 15% increase in NGL prices, offset by a decrease of $4.2 million attributable to the 3% decrease in natural gas prices.

Oil and gas sales in 2005 increased by 36%, or $112.5 million, from the level of those revenues for 2004, and our net sales volumes in 2005 increased by 2%, or 1.3 Bcfe, over net sales volumes in 2004. Average prices for oil increased to $53.63 per Bbl in 2005 from $40.24 per Bbl in 2004. Average natural gas prices increased to $5.23 per Mcf in 2005 from $4.12 per Mcf in 2004. Average NGL prices increased to $28.04 per Bbl in 2005 from $22.52 per Bbl in 2004.

In 2005, our $112.5 million increase in oil, NGL, and natural gas sales resulted from:

• Price variances that had a $100.0 million favorable impact on sales, of which $69.1 million was attributable to the 33% increase in average oil prices received, $26.3 million was attributable to the 27% increase in natural gas prices and $4.6 million was attributable to the 24% increase in NGL prices; and

• Volume variances that had a $12.5 million favorable impact on sales, with $17.6 million of increases attributable to the 0.4 million Bbl increase in oil sales volumes, offset by a decrease of $4.6 million due to the 0.2 million Bbl decrease in NGL sales volumes, and a decrease of $0.5 million due to the 0.1 Bcf decrease in natural gas sales volumes.

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

 

		Sales Volume							Average Sales Price
											Natural
	Oil		NGL	Gas	Combined			Oil		NGL	Gas
	(MBbl)		(MBbl)	(Bcf)	(Bcfe)			(Bbl)		(Bbl)	(Mcf)
2004:
First	1,124		277	5.9	14.3			$ 34.14		$ 22.30	$ 3.64
Second	1,142		269	5.8	14.3			$ 37.24		$ 18.84	$ 4.19
Third	1,076		251	6.0	13.9			$ 41.99		$ 23.33	$ 3.97
Fourth	1,380		243	6.1	15.9			$ 46.33		$ 26.01	$ 4.67
	---------		----------	----------	----------
Total	4,722		1,040	23.7	58.3			$ 40.24		$ 22.52	$ 4.12
	======		======	======	======
2005:
First	1,321		223	6.3	15.5			$ 47.66		$ 26.79	$ 4.25
Second	1,426		209	6.1	15.9			$ 50.24		$ 22.95	$ 4.67
Third	1,059		204	5.9	13.5			$ 59.66		$ 31.84	$ 5.29
Fourth	1,353		202	5.3	14.7			$ 58.31		$ 30.83	$ 6.97
	---------		----------	----------	----------
Total	5,159		838	23.6	59.6			$ 53.63		$ 28.04	$ 5.23
	======		======	======	======
2006:
First	1,611		152	6.0	16.5			$ 60.83		$ 30.34	$ 5.38
Second	1,636		138	5.6	16.3			$ 69.63		$ 29.72	$ 4.79
Third	1,992		220	5.5	18.8			$ 69.62		$ 36.18	$ 4.87
Fourth	1,951		203	5.7	18.6			$ 57.88		$ 30.79	$ 5.14
	---------		----------	----------	----------
Total	7,190		713	22.8	70.2			$ 64.47		$ 32.15	$ 5.05
	======		======	======	======

 

In 2006, we settled all insurance claims with our insurers relating to hurricanes Katrina and Rita for approximately $30.5 million and entered into a confidential final settlement agreement. The receipt of these amounts resulted in a benefit of $7.7 million in 2006 recorded in “Price-risk management and other, net,” for the portion of the above referenced settlement, which we have determined to be non-property damage related claims. Approximately $22.8 million of the above referenced settlement was determined to be property damage related claims. We recorded $14.1 million of the property related settlement as a reduction to “Proved properties” on the accompanying consolidated balance sheet, as this related to reimbursement of capital costs we incurred. We also recorded $8.7 million of the property related settlement as a reduction to “Lease operating cost” on the accompanying consolidated statement of income, as this related to reimbursement of repair costs which had been expensed as incurred. In the accompanying consolidated statement of cash flows, we have recorded the reimbursement which reduced “Proved properties” as a reduction of “Net Cash Used in Investing Activities” and the remainder of the insurance settlement was recorded as an increase to “Net Cash Provided by Operating Activities.”

Costs and Expenses. Our expenses in 2006 increased $108.4 million, or 44%, compared to 2005 expenses. The majority of the increase was due to a $61.8 million increase in DD&A, a $23.3 million increase in severance and other taxes, and a $15.2 million increase in lease operating costs, all of which are primarily due to increased production volumes in 2006. Increased commodity prices also increased severance and other taxes, and higher full cost pool balances increased DD&A, offset somewhat by increased reserves volumes in 2006. Our expenses in 2005 increased $36.0 million, or 17%, compared to 2004 expenses. The majority of the increase was due to a $25.9 million increase in DD&A, an $11.8 million increase in severance and other taxes, and a $6.1 million increase in lease operating costs, all of which are primarily due to increased commodity prices and production volumes in 2005. This increase was partially offset by the absence of $9.5 million of debt retirement costs incurred in 2004.

Our 2006 general and administrative expenses, net, increased $9.1 million, or 41%, from the level of such expenses in 2005, while 2005 general and administrative expenses, net, increased $4.4 million, or 25%, over 2004 levels. The increase in both 2006 and 2005 were primarily due to increased salaries and burdens associated with our expanded workforce. Costs also increased in 2006 as a result of expensing stock options and increased restricted stock grants, and increased in 2005 due to restricted stock compensation. For the years 2006, 2005, and 2004, our capitalized general and administrative costs totaled $28.3 million, $18.8 million, and $13.1 million, respectively. Our net general and administrative expenses per Mcfe produced increased to $0.45 per Mcfe in 2006 from $0.37 per Mcfe in 2005 and $0.30 per Mcfe in 2004. The portion of supervision fees recorded as a reduction to general and administrative expenses was $8.8 million for 2006, $7.8 million for 2005, and 5.8 million for 2004.

DD&A increased $61.8 million, or 58%, in 2006 from 2005 levels, while 2005 DD&A increased $25.9 million, or 32%, from 2004 levels. Domestically, DD&A increased $58.1 million in 2006 due to increases in the depletable oil and gas property base and higher production, partially offset by higher reserves volumes. In New Zealand, DD&A increased by $3.7 million in 2006 due to an increase in the depletable oil and gas property base and lower reserves. In 2005, our domestic DD&A increased $18.8 million due to increases in the depletable oil and gas property base, slightly higher production in the 2005 period and lower reserves volumes. In New Zealand, DD&A increased by $7.1 million in 2005 due to the same reasons. Our DD&A rate per Mcfe of production was $2.41 in 2006, $1.80 in 2005, and $1.40 in 2004, resulting from increases in per unit cost of reserves additions.

We recorded $1.0 million, $0.8 million, and $0.7 million of accretions to our asset retirement obligation in 2006, 2005, and 2004, respectively.

Our lease operating costs per Mcfe produced were $0.89 in 2006, $0.79 in 2005 and $0.71 in 2004. Our lease operating costs in 2006 increased $15.2 million, or 32%, over the level of such expenses in 2005, while 2005 costs increased $6.1 million, or 15% over 2004 levels. Approximately $15.0 million of the increase in lease operating costs during 2006 was related to our domestic operations, which increased primarily due to increased production and was also impacted by increased well insurance premiums. Our lease operating cost in New Zealand increased in 2006 by $0.1 million due to increases in well operating costs and storage and handling costs.

Severance and other taxes increased $23.3 million, or 55%, over 2005 levels, while in 2005 these taxes increased $11.8 million, or 39% over 2004 levels. The increases were due primarily to higher commodity prices and increased Lake Washington production in each of the periods. Severance taxes on oil in Louisiana are 12.5% of oil sales, which is higher than in 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 10.9%, 10.0% and 9.8% in 2006, 2005 and 2004, respectively.

Our total interest cost in 2006 was $32.8 million, of which $9.2 million was capitalized. Our total interest cost in 2005 was $32.1 million, of which $7.2 million was capitalized. Our total interest cost in 2004 was $34.2 million, of which $6.5 million was capitalized. Interest expense on our 7-5/8% senior notes due 2011 issued in June 2004, including amortization of debt issuance costs, totaled $11.9 million in both 2006 and 2005 and $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 the same $19.2 million in 2006, 2005, and 2004. 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. Interest expense on our bank credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.5 million in 2006, $1.0 million in 2005, and $1.5 million in 2004. Other interest cost was $0.1 million in 2006. We capitalize a portion of interest related to unproved properties. The decrease of interest expense in 2006 was primarily due to an increase in capitalized interest costs, partially offset by an increase in credit facility interest. The decrease of interest expense in 2005 was primarily due to the lower interest rate applicable to the 7-5/8% notes issued in June 2004 versus the 10-1/4% notes retired at that time.

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.

Our overall effective tax rate was 38.4% for 2006, 35.1% for 2005 and 32.5% for 2004. The effective tax rate for 2006 was higher than the statutory rate primarily because of state income taxes and a valuation allowance, partially offset by favorable adjustments for the currency effect on the New Zealand deferred tax calculation. For 2005, the effective rate was about the same as the statutory rate as state income taxes and the currency effect adjustments essentially offset. For 2004, the effective rate was less than the statutory rate due to favorable adjustments for currency effect and corrections to tax basis amounts, partially offset by deferred state income taxes.

Net Income. Our net income in 2006 of $161.6 million was 40% higher than our 2005 net income of $115.8 million due to higher oil prices and increased production.

Our net income in 2005 of $115.8 million was 69% higher than our 2004 net income of $68.5 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, 2006 are as follows:

 

	2007	2008	2009	2010	2011	Thereafter	Total
	(In thousands)
Non-cancelable operating leases (1)	$ 5,345	$ 5,321	$ 3,334	$ 3,293	$ 3,225	$ 10,109	$ 30,627
Asset retirement obligation(2)	1,650	2,313	2,019	2,110	2,205	24,163	34,460
Computer System Implementation	3,261	—	—	—	—	—	3,261
Construction costs	5,223	—	—	—	—	—	5,223
Drilling rigs, seismic and pipe inventory	28,873	—	—	—	—	—	28,873
7-5/8% senior notes due 2011(3)	—	—	—	—	150,000	—	150,000
9-3/8% senior subordinated notes due 2012(3)	—	—	—	—	—	200,000	200,000
Credit facility(4)	—	—	—	—	31,400	—	31,400
	----------	----------	----------	----------	----------	----------	----------
Total	$ 44,352	$ 7,634	$ 5,353	$ 5,403	$ 186,830	$ 234,272	$ 483,844
	=======	=======	=======	=======	=======	=======	=======

 

(1) Our most significant office lease is in Houston, Texas and it extends until 2015.

(2) Amounts shown by year are the fair values at December 31, 2006.

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

(4) The credit facility expires in October 2011 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 at historical highs when compared to longer-term historical prices. Factors such as worldwide supply disruptions, worldwide economic conditions, weather conditions, fluctuating currency exchange rates, and political conditions in major oil producing regions, especially the Middle East, can cause 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.

Income Tax Regulations

The tax laws in the jurisdictions we operate in are continuously changing and professional judgments regarding such tax laws can differ.

Liquidity and Capital Resources

During 2006, we relied upon our net cash provided by operating activities of $424.9 million, credit facility borrowings of $31.4 million, property sales proceeds of $24.7 million, and cash balances to fund capital expenditures of $557.5 million including $194.3 million of acquisitions. During 2005, we largely relied upon our net cash provided by operating activities of $285.3 million to fund capital expenditures of $264.5 million including $28.9 million of acquisitions.

Net Cash Provided by Operating Activities. For 2006, our net cash provided by operating activities was $424.9 million, representing a 49% increase as compared to $285.3 million generated during 2005. The $139.6 million increase in 2006 was primarily due to an increase of $177.8 million in oil and gas sales, attributable to higher oil prices and production, offset in part by higher lease operating costs and severance taxes due to higher oil prices and higher domestic production. In 2005, our net cash provided by operating activities was $285.3 million, representing a 56% increase as compared to $182.6 million generated during 2004. The $102.8 million increase in 2005 was primarily due to an increase of $112.5 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.

Accounts Receivable. 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 both December 31, 2006 and 2005, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balances on the accompanying balance sheets.

Existing Credit Facility. We had borrowings of $31.4 million under our bank credit facility at December 31, 2006, and no outstanding borrowings at December 31, 2005. Our bank credit facility at December 31, 2006 consisted of a $500.0 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, 2006. 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 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 operations, financial condition, prospects or properties, and would impair the 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 declined from a surplus of $16.6 million at December 31, 2005, to a deficit of $53.4 million at December 31, 2006. The decrease primarily resulted from a decrease in cash and cash equivalents due to property acquisitions during the fourth quarter of 2006.

Debt Maturities. Our credit facility, with a balance of $31.4 million at December 31, 2006, extends until October 3, 2011. 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.

On or after May 1, 2007, we are entitled to redeem our $200.0 million of 9-3/8% senior subordinated notes at a redemption price, plus accrued and unpaid interest, of 104.688% of principal. If these notes were redeemed, we would most likely use a combination of drawings upon our credit facility, cash flows from operations, and the use of debt and/or equity offerings to fund any such redemption.

Capital Expenditures. In 2006 we relied upon our net cash provided by operating activities of $424.9, credit facility borrowings of $31.4 million, property sales proceeds of $24.7 million, and cash balances to fund capital expenditures of $557.5 million including $194.3 million of acquisitions. Our total capital expenditures of approximately $557.5 million in 2006 included:

Domestic expenditures of $502.3 million as follows:

• $214.9 million for drilling and developmental activity costs, predominantly in our South Louisiana area;

• $200.5 million for acquisitions of properties, primarily in our South Louisiana area;

• $20.5 million on exploratory drilling;

• $51.1 million of domestic prospect costs, principally prospect leasehold, 3-D seismic activity, and geological costs of unproved prospects;

• $15.3 million primarily for leasehold improvements, computer equipment, software, furniture, and fixtures;

New Zealand expenditures of $55.2 million as follows:

• $28.8 million for drilling costs and developmental activity costs, predominantly in our Rimu/Kauri area;

• $15.7 million on exploratory drilling;

• $10.4 million on prospect costs, principally prospect leasehold, seismic and geological costs of unproved properties;

• $0.3 million for computer equipment, software, furniture, and fixtures.

We continue to spend considerable time and capital on facility capacity upgrades in the Lake Washington field, and increased facility capacity at year-end 2006 to approximately 28,000 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. During 2006, we began planning for the addition of a fourth production platform which will increase our processing capacity another 10,000 barrels per day by mid-2008.

We completed 45 of 63 wells in 2006, for a success rate of 71%. Domestically, we completed 42 of 49 development wells for a success rate of 86% and were unsuccessful on six exploratory wells, including five very shallow exploration wells in the AWP Olmos area which cost $0.5 million in the aggregate, and one non-operated well in Alaska. A total of 21 development wells were drilled in the Lake Washington area, of which 18 were completed, and 15 development wells were drilled in the AWP Olmos area, of which 14 were completed. We also drilled six development wells in the Bay de Chene area, of which three were completed, drilled three successful development wells in each of the Cote Blanche Island and South Bearhead Creek areas, and drilled one successful development well in the Brookeland area. In New Zealand, we completed three of four development wells but were unsuccessful on four exploratory wells.

Our capital expenditures were approximately $264.5 million in 2005 and $171.1 million in 2004. In 2005, we relied upon our net cash provided by operating activities of $285.3 million to fund capital expenditures of $264.5 million, including acquisitions of $28.9 million. During 2004, 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, 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 $198.3 million, including acquisitions of $27.2 million. Our total capital expenditures in 2005 of approximately $264.5 million included:

Domestic expenditures of $215.8 million as follows:

• $111.0 million for drilling and developmental activity costs, predominantly in our Lake Washington area;

• $29.6 million on property acquisitions, including $28.9 million to acquire properties in the South Bearhead Creek field;

• $36.8 million on exploratory drilling, mainly in our Lake Washington area;

• $34.4 million of prospect costs, principally prospect leasehold, 3-D seismic activity, and geological costs of unproved prospects;

• $3.6 million primarily for a field office building, computer equipment, software, furniture, and fixtures;

• $0.3 million on gas processing plants in the Brookeland and Masters Creek areas; and

• less than $0.1 million on field compression facilities.

New Zealand expenditures of $48.7 million as follows:

• $27.2 million for drilling costs and developmental activity costs, predominantly in our Rimu/Kauri area;

• $13.6 million on exploratory drilling;

• $6.9 million on prospect costs, principally prospect leasehold, seismic and geological costs of unproved properties;

• $0.8 million on gas processing plants; and

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

In 2005, we participated in drilling 45 domestic development wells and nine domestic exploratory wells, of which 37 development wells and five exploratory wells were completed. In New Zealand we drilled five development wells, of which two were completed, and five exploratory wells, of which one was completed.

New Accounting Principles

Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 123 (R), “Share-Based Payment” (SFAS No. 123R) utilizing the modified prospective approach. Prior to the adoption of SFAS No. 123R, we accounted for stock option grants in accordance with Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (the intrinsic value method), and accordingly, recognized no compensation expense for employee stock option grants. Under the modified prospective approach, SFAS No. 123R applies to new awards and to awards that were outstanding on January 1, 2006 as well as those that are subsequently modified, repurchased or cancelled. Under the modified prospective approach, compensation cost recognized for the year ended December 31, 2006 includes compensation cost for all share-based awards granted prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123, and compensation cost for all share-based awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123R. Prior periods were not restated to reflect the impact of adopting the new standard. As a result of adopting SFAS No. 123R on January 1, 2006, our income before taxes, net income and basic and diluted earnings per share for the year ended December 31, 2006, were $3.4 million, $2.8 million, $0.09, and $0.09 lower, respectively. Upon adoption of SFAS 123R, we recorded an immaterial cumulative effect of a change in accounting principle as a result of our change in policy from recognizing forfeitures as they occur to one recognizing expense based on our expectation of the amount of awards that will vest over the requisite service period for our restricted stock awards. This amount was recorded in “General and Administrative, net” in the accompanying consolidated statements of income.

In September 2006, the SEC released SAB 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” ( SAB 108). SAB 108 addresses the process of quantifying financial statement misstatements, such as assessing both the carryover and reversing effects of prior year misstatements on the current year financial statements. SAB 108 became effective for our fiscal year ended December 31, 2006. The adoption of this statement had no impact on our financial position or results of operations.

In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109.” This Interpretation provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding derecognition, classification and disclosure of these uncertain tax positions. FIN No. 48 is effective for fiscal years beginning after December 15, 2006. The adoption of this Interpretation is not expected to have a material impact on its financial position or results of operations.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 addresses how companies should approach measuring fair value when required by GAAP; it does not create or modify any current GAAP requirements to apply fair value accounting. SFAS No. 157 provides a single definition for fair value that is to be applied consistently for all accounting applications, and also generally describes and prioritizes, according to reliability, the methods and inputs used in valuations. SFAS No. 157 prescribes various disclosures about financial statement categories and amounts which are measured at fair value, if such disclosures are not already specified elsewhere in GAAP. The new measurement and disclosure requirements of SFAS No. 157 are effective for us in the first quarter 2008. The Company has not yet determined what impact, if any, this statement will have on its financial position or results of operations.

Proved Oil and Gas Reserves

At year-end 2006, our total proved reserves were 816.8 Bcfe with a PV-10 Value of $2.7 billion (PV-10 is a non-GAAP measure, see the section titled “Oil and Natural Gas Reserves” in our Property section for a reconciliation of this non-GAAP measure to the closest GAAP measure, the standardized measure). In 2006, our proved natural gas reserves increased 36.7 Bcf, or 13%, while our proved oil reserves increased 4.0 MMBbl, or 6%, and our NGL reserves decreased 0.9 MMBbl, or 6%, for a total equivalent increase of 55.1 Bcfe, or 7%. In 2005, our proved natural gas reserves decreased by 30.8 Bcf, or 10%, while our proved oil reserves decreased by 0.7 MMBbl, or 1%, and our NGL reserves decreased by 0.5 MMBbl, or 3%, for a total equivalent decrease of 38.1 Bcfe, or 5%. We added reserves over the past three years through both our drilling activity and purchases of minerals in place. Through drilling we added 72.8 Bcfe (1.2 Bcfe of which came from New Zealand) of proved reserves in 2006, 31.6 Bcfe (2.0 Bcfe of which came from New Zealand) in 2005, and 7.2 Bcfe (all of which was domestic) in 2004. Through acquisitions we added 77.8 Bcfe of proved reserves in 2006, 28.9 Bcfe in 2005, and 43.4 Bcfe in 2004. At year-end 2006, 44% of our total proved reserves were proved developed, compared with 50% at year-end 2005 and 56% at year-end 2004.

Despite increased reserves volumes, the PV-10 Value of our total proved reserves at year-end 2006 decreased 15% from the PV-10 Value at year-end 2005. Gas prices decreased in 2006 to $5.46 per Mcf from $8.94 per Mcf at year-end 2005, compared to $5.16 per Mcf at year-end 2004. Oil prices increased in 2006 to $60.41 per Bbl from $60.12 per Bbl at year-end 2005, compared to $41.07 in 2004. 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 reserves 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 accounting principles generally accepted in the United States (“GAAP”) requires us to make estimates and assumptions that affect the reported amount of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:

the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and the related present value of estimated future net cash flows there-from,

accruals related to oil and gas revenues, capital expenditures and lease operating expenses,

estimates of insurance recoveries related to property damage,

estimates in the calculation of stock compensation expense,

estimates of our ownership in properties prior to final division of interest determination,

the estimated future cost and timing of asset retirement obligations, and

estimates made in our income tax calculations.

While we are not aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as changes in new accounting pronouncements, 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 2006, 2005, and 2004, such internal costs capitalized totaled $28.3 million, $18.8 million, and $13.1 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the years 2006, 2005, and 2004, capitalized interest on unproved properties totaled $9.2 million, $7.2 million, and $6.5 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 recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using period-end prices, adjusted for the effects of hedging, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). Our hedges at December 31, 2006 consisted of natural gas price floors with strike prices higher than the period-end price and did not materially affect prices used in this calculation. This calculation is done on a country-by-country basis.

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

Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline from our period-end prices used in the Ceiling Test, even if only for a short period, it is possible that non-cash write-downs of oil and gas properties could occur in the future. If we have declines in our oil and gas reserves volumes, which also reduce our estimate of discounted future net cash flows from proved oil and gas reserves, a non-cash write-down of our 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 2006, 2005 and 2004, we recognized net gains of $4.0 million, and net losses of $1.1 million and $1.3 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, 2006, the Company had recorded $0.3 million, net of taxes of less than $0.2 million, of derivative gains in “Accumulated other comprehensive income (loss), net of income tax” on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our hedging transactions that qualified as cash flow hedges. The ineffectiveness reported in “Price-risk management and other, net” for 2006, 2005, and 2004 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 three months when the forecasted sale of hedged production occurs.

At December 31, 2006, we had in place price floors in effect for February 2007 through the March 2007 contract month for natural gas, that cover a portion of our domestic natural gas production for February 2007 to March 2007. The natural gas price floors cover notional volumes of 800,000 MMBtu, with a weighted average floor price of $7.00 per MMBtu. Our natural gas price floors in place at December 31, 2006 are expected to cover approximately 25% to 30% of our estimated domestic natural gas production from February 2007 to March 2007.

When we entered into these transactions discussed above, they were designated as a hedge of the variability in cash flows associated with the forecasted sale of natural gas production. Changes in the fair value of a hedge that is highly effective and is designated and documented and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in “Accumulated other comprehensive income (loss), net of income tax.” When the hedged transactions are recorded upon the actual sale of the natural gas, these gains or losses are reclassified from “Accumulated other comprehensive income (loss), net of income tax” and recorded in “Price-risk management and other, net” on the accompanying statement of income. The fair value of our derivatives is computed using the Black-Scholes-Merton option pricing model and is periodically verified against quotes from brokers. The fair value of these instruments at December 31, 2006, was $0.7 million and is recognized on the accompanying balance sheet in “Other current assets.”

Revenue Recognition. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Processing costs for natural gas and natural gas liquids (“NGLs”) that are paid in-kind are deducted from revenues. The Company uses the entitlement method of accounting in which the Company recognizes its ownership interest in production as revenue. If our sales exceed our ownership share of production, the natural gas balancing payables are reported in “Accounts payable and accrued liabilities” on the accompanying balance sheet. Natural gas balancing receivables are reported in “Other current assets” on the accompanying balance sheet when our ownership share of production exceeds sales. As of December 31, 2006, we did not have any material natural gas imbalances.

Asset Retirement Obligation. In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. The liability is discounted from the year the well is expected to deplete. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated on a unit-of-production basis over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss which increases or decreases the full cost pool. This standard requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. Based on our experience and analysis of the oil and gas services industry, we have not factored a market risk premium into our asset retirement obligation. SFAS No. 143 was adopted by us effective January 1, 2003.

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

Stock Based Compensation. We have three 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 SFAS 123R, “Share-Based Compensation,” and related interpretations.

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

Related-Party Transactions

We were 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 the same $0.2 million in 2006, 2005 and 2004, 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 $0.1 million per year in 2006 and 2005, and $0.2 million in 2004, and are recorded as reductions in general and administrative, net. As of December 31, 2006, the remaining two partnerships have been dissolved.

We receive research, technical writing, publishing, and website-related services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and controlled and majority owned by the aunt of the Company’s Chairman of the Board and Chief Executive Officer. We paid approximately $0.5 million to Tec-Com for such services pursuant to the terms of the contract between the parties in 2006, and $0.4 million per year in 2005 and 2004. 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; disruption of operations and damages due to hurricanes or tropical storms; 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.

This page was last updated on Thursday, March 29, 2007, at 01:28:30 PM.

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