Exhibit 99.11

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Statements in the following discussion may be forward-looking and involve risks and uncertainties. The Company’s financial results are most directly affected by changing prices for its production. Changing prices can influence not only current results of operations but the determination of the Company’s proved reserves and available sources of financing, including the determination of the borrowing base under its bank credit facility. The Company’s results depend not only on hydrocarbon prices generally, but on its ability to market its production on favorable terms. On a longer term basis, the Company’s financial condition and results of operations are affected by its ability to replace reserves as they are produced through successful exploration, development and acquisition activities. The Company’s results could also be adversely affected by adverse regulatory developments and operational risks associated with oil and gas operations. For further discussion of risks and uncertainties that may affect the Company’s results, see “Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended 2006 and in subsequent quarterly reports and the discussion below.

The following discussion of the Company’s financial condition and results of operations reflects the recasting as discontinued operations of the Company’s Northrock operations (acquired September 27, 2005 and sold in August of 2007) for 2006 and 2005 and its Thailand and Hungary operations (sold in 2005) for all periods presented prior to 2006. See Note 11 – “Discontinued Operations” to the Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data”. Except where noted otherwise, the following discussion relates to the Company’s continuing activities only. The assets comprising the Company’s continuing operations have changed substantially during the periods presented, which affects comparability between periods. In addition to the Northrock acquisition in September 2005, the Company acquired Latigo on May 2, 2006 (“Latigo Acquisition”), and disposed of 50% of its interests in its Gulf of Mexico properties on May 31, 2006 (“Gulf of Mexico Disposition”). For summary pro forma results of operations from the Company’s continuing operations as if the Latigo acquisition had occurred on January 1, 2004, please refer to Note 5 – “Acquisitions” to the Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data”.

Executive Overview

The Company’s objective is to explore for, develop, acquire and produce oil and gas in select locations. In pursuit of that objective, the Company’s goal for each year is to add more oil and gas reserves than it produces. The year 2006 marked the fifteenth consecutive year of reserve replacement for the Company.

The Company pursues a balanced approach in core areas located in major oil and gas provinces in the United States and internationally. The Company follows a strict set of criteria when selecting areas of the world in which to explore. Areas selected are viewed as having proven oil and gas resources, having reasonable economic terms and possessing low political risk. Following these criteria, the Company conducts exploration activities in offshore New Zealand and Vietnam. The Company also seeks to maintain a balanced mixture of the gas/oil ratio of its proven reserves base. Over the last several years, the Company has transitioned from a predominately offshore focused company to a company with the majority of its reserves located in the onshore regions of the United States. As of December 31, 2006, approximately 91.6% of the Company’s reserves are located onshore. As a result of this transition, the Company has lengthened its reserves to production index to over 12 years.

At the end of 2006, proven reserves from continuing operations reached 1,507 Bcfe and production for the year averaged more than 55,700 BOE per day (334,000 Mcfe per day). Oil and gas pricing and production volumes are important components of an exploration and development company’s growth in net income and cash flow.

Oil and gas capital and exploration cash expenditures for 2006 were approximately $1.4 billion. Exploration and development operations were allocated approximately $659 million, and approximately $763 million was spent on selective acquisitions in the Company’s core areas of operations. For 2006 the Company drilled 325 wells with 280 successfully completed, an 86% success rate. During 2006, approximately 388 Bcfe of proven reserves from continuing operations were added to the Company’s reserves ledger.

2006 Results

Total revenue for 2006 was $930.5 million and net income totaled $446.2 million, or $7.74 per share. Cash flow from operations totaled $651.9 million. As of December 31, 2006, long-term debt was $2,319.7 million, increasing from December 31, 2005 by $676.3 million. The Company’s debt to total capitalization ratio, an indicator of a company’s financial strength, was 47% at December 31, 2006 and cash and cash equivalents decreased from $57.7 million at December 31, 2005 to approximately $22.7 million at December 31, 2006. The increase in debt and the decrease in cash are both due primarily to the closing of the Latigo acquisition and increased capital expenditures.

Strategic Alternatives Process

On February 15, 2007, the Company confirmed that its Board of Directors previously initiated the exploration of a range of strategic alternatives to enhance shareholder value and is continuing to do so, including the possible sale or merger of Pogo, the sale of its Canadian, Gulf Coast, Gulf of Mexico or other significant assets, and changes to the Company’s business plan. Pogo has retained Goldman, Sachs & Co. and TD Securities Inc. as financial advisors for the process.

Acquisition of Latigo Petroleum Inc.

On May 2, 2006, the Company completed the acquisition of Latigo Petroleum, Inc. (“Latigo”), a privately held exploration and production company for approximately $764.9 million. The purchase price was funded using cash on hand and debt financing. As of December 31, 2006, Latigo’s estimated proved reserves were approximately 328 Bcfe. Latigo’s operations are concentrated in the Permian Basin and Panhandle of Texas.

Sale of 50% of Gulf of Mexico Interests

On May 31, 2006, the Company closed the sale of an undivided 50 percent interest of each of its Gulf of Mexico oil and gas leasehold interests and related pipelines and equipment to an affiliate of Mitsui & Co., Ltd., for approximately $448.8 million. The proceeds were used to repay a portion of the debt used to finance the Latigo acquisition. As of December 31, 2005, the interests sold were attributed approximately 143 Bcfe of net estimated proven oil and gas reserves. The Company recognized a pre-tax gain of $302.7 million related to the sale in the second quarter of 2006.

Issuance of Senior Subordinated Notes

On June 6, 2006, the Company issued and sold $450 million aggregate principal amount of 7.875% Senior Subordinated Notes due 2013 (the “2013 Notes”). Net proceeds were used to reduce outstanding debt under the Company’s credit facility.

Recognition of Income Tax Benefit

During 2006, the Company’s consolidated effective tax rate was 9.5%, down from 36.9% in 2005. This decrease relates to the enactment of a reduction of the Alberta and Saskatchewan provincial tax rates, in addition to a reduction in the statutory Canadian federal income tax rate, which generated a one-time deferred tax benefit of approximately $112 million. Accounting rules require that the entire tax effect of a change in enacted tax rates be allocated to continuing operations.

Commodity Derivatives

Although the Company’s collars are effective as economic hedges, the Gulf of Mexico disposition and the forecasted shut-in hydrocarbon production from the Company’s Gulf of Mexico properties (resulting primarily from hurricane activity during the third quarter of 2005) caused certain of the gas and crude oil collar contracts to lose their qualification for hedge accounting. The Company recognized a $7.3 million non-cash gain related to these contracts in 2006.

2007 Capital Budget

The Company has established a $720 million exploration and development budget (excluding property acquisitions) for 2007. The Company expects to spend approximately $199 million on exploration and $521 million on development activities. The capital budget calls for the drilling of approximately 370 wells during 2007, including wells in the United States, Canada, and New Zealand. All capital activity related to Northrock has been reported as discontinued operations in the Company’s consolidated financial statements.

Exposure to Oil and Gas Prices and Availability of Oilfield Services

Oil and natural gas prices have historically been seasonal, cyclical and volatile. Prices depend on many factors that the Company cannot control such as weather and economic, political and regulatory conditions. The average prices the Company is currently receiving for production are higher than historical average prices. A future drop in oil and gas prices could have a serious adverse effect on cash flow and profitability. Sustained periods of low prices could have a serious adverse effect on the Company’s operations and financial condition. Additionally, the cost of drilling, completing and operating wells and installing facilities and pipelines is often uncertain and have each increased substantially. The market for oil field services is currently very competitive and shortages or delays in delivery or availability of equipment or fabrication yards could impact the Company’s ability to conduct oil and gas drilling and completion operations.

Results of Operations

Oil and Gas Revenues

The Company’s oil and gas revenues for 2006 were $924.7 million, a decrease of approximately 15% from oil and gas revenues of $1,082.1 million for 2005, which were an increase of approximately 11% from oil and gas revenues of $973.1 million for 2004. The following table reflects an analysis of variances in the Company’s oil and gas revenues (expressed in millions) between years:

	2006			2005
	Compared to			Compared to
	2005			2004

Increase (decrease) in oil and gas revenues resulting from variances in:
Natural gas -
Price	$	(95.1	)	$	144.4
Production	(68.2		)	(35.9		)
	(163.3		)	108.5
Crude oil and condensate -
Price	98.2			130.9
Production	(105.8		)	(134.6		)
	(7.6		)	(3.7		)
Natural gas liquids (“NGL”)
Price	4.7			9.1
Production	8.8			(4.9		)
	13.5			4.2
Decrease in oil and gas revenues	$	(157.4	)	$	109.0

The decrease in the Company’s oil and gas revenues in 2006, compared to 2005, was primarily due to lower natural gas prices and decreases in hydrocarbon production as a result of the Gulf of Mexico disposition, natural production declines in the Company’s Main Pass, South Texas, and Gulf Coast areas, and curtailment of production due to hurricanes, all of which were partially offset by higher crude and condensate prices and an increase in hydrocarbon production due to the Latigo Acquisition. The increase in the Company’s oil and gas revenues in 2005, compared to 2004, was primarily due to increases in the prices the Company received for its hydrocarbon production volumes, which was partially offset by decreases in hydrocarbon production resulting primarily from shutting in Gulf of Mexico platforms in 2005 due to Hurricanes Ivan, Katrina, and Rita. The impact of the volume variances on the Company’s oil and gas revenues is discussed in detail below.

					% Change				% Change
					2005				2004
					to				to
	2006		2005		2006		2004		2005
Comparison of Increases (Decreases) in:
Natural Gas –
Average prices (a)	$	6.22	$	7.35	(15	)%	$	5.73	28	%
Average daily production volumes
(MMcf per day) (a):	201.5		231.6		(13	)%	244.3		(5	)%

Crude Oil and Condensate –
Average prices (b)	$	62.75	$	50.70	24	%	$	38.59	31	%
Average daily production volumes
(Bbls per day) (b):	17,717		22,337		(21	)%	29,530		(24	)%

Total Liquid Hydrocarbons –
Average daily production volumes
(Bbls per day) (b)	22,209		26,179		(15	)%	33,750		(22	)%

(a) Average prices reflect the impact of the Company’s price hedging activity. Price hedging activity increased the average price per Mcf of the Company’s natural gas production $0.03 during 2006 and decreased the average price per Mcf of the Company’s natural gas production $0.11 during 2005. The Company had no price hedging activity related to 2004 production.

(b) Average prices include the impact of the Company’s price hedging activity. Price hedging activity increased the average price per Bbl of the Company’s crude oil and condensate production $0.02 during 2006 and decreased the average price per Bbl of the Company’s crude oil and condensate production $0.20 during 2005. The Company had no price hedging activity related to 2004 production. For average prices, sales volumes equate to actual production.

Natural Gas Production. The decrease in the Company’s natural gas production during 2006, compared to 2005, was primarily due to natural production declines in the Company’s South Texas and Gulf Coast areas, resulting in decreased natural gas revenues of approximately $67.3 million. To a lesser extent, decreased production in the Gulf of Mexico area due to the Gulf of Mexico disposition, natural production declines, and hurricane-related production curtailments reduced natural gas revenues by approximately $20.6 million, $6.7 million, and $5.6 million, respectively. These decreases were partially offset by an increase in natural gas production due to the Latigo acquisition, which added revenues in 2006 of approximately $36.0 million.

The decrease in the Company’s natural gas production during 2005, compared to 2004, was primarily due to shut-in offshore production caused by Hurricanes Ivan, Katrina, and Rita. This shut-in production decreased gas revenues by approximately $67.7 million and was only partially offset by increases in production from acquisitions made in late 2004, which added approximately $26.2 million in gas revenues during 2005.

Crude Oil and Condensate Production. The decrease in the Company’s crude oil and condensate production during 2006, compared to 2005, was primarily due to natural production declines, the Gulf of Mexico disposition, and the curtailment of production resulting from hurricanes resulting in decreased oil and condensate revenues of approximately $82.9 million, $65.4 million, and $16.8 million, respectively. These decreases were only partially offset by an increase in volumes from the Latigo Acquisition, which contributed approximately $55.8 million in crude and condensate revenues. The decrease in the Company’s crude oil and condensate production during 2005, compared to 2004, resulted primarily from the shut-in of Gulf of Mexico platforms due to the effects of Hurricanes Ivan, Katrina and Rita (including Main Pass Block 61/62) during 2005.

NGL Revenues. The Company’s oil and gas revenues, and its total liquid hydrocarbon production, reflect the production and sale by the Company of NGL, which are liquid products that are extracted from natural gas production. The increase in NGL revenues for 2006, compared with 2005, related to an increase in NGL production volumes in the Company’s Western Division. The decrease in NGL revenues for 2005, compared with 2004, related to a decrease in NGL production volumes in the Gulf of Mexico due to the effects of Hurricanes Ivan, Katrina and Rita.

Other Revenues

Other revenue is derived from sources other than the current production of hydrocarbons. This revenue includes, among other items: hedge ineffectiveness, pipeline imbalance settlements and revenue from salt water disposal activities. The increase in other revenues from 2005 to 2006 was due to an increase in hedge ineffectiveness.

Costs and Expenses

							%Change					%Change
Comparison of Increases (Decreases) in:	2006			2005			2005 to 2006		2004			2004 to 2005
	(expressed in millions, except DD&A rate)
Lease Operating Expenses	$	183.4		$	136.0		35	%	$	100.5		35	%
General and Administrative Expenses	$	101.1		$	77.9		30	%	$	62.1		25	%
Exploration Expenses	$	15.8		$	23.1		(32	)%	$	21.7		6	%
Dry Hole and Impairment Expenses	$	80.9		$	82.2		(2	)%	$	61.6		33	%
Depreciation, Depletion and
Amortization (DD&A) Expenses	$	285.3		$	261.3		9	%	$	251.9		4	%
DD&A rate	$	2.33		$	1.84		27	%	$	1.54		19	%
Mcfe produced	122.2			141.9			(14	)%	163.5			(13	)%
Production and Other Taxes	$	67.7		$	56.8		19	%	$	44.1		29	%
Net (Gain) Loss on Sales of Properties	$	(304.8	)	$	(0.2	)	N/M		$	0.3		(167	)%
Other	$	21.3		$	(15.7	)	(236	)%	$	8.4		(287	)%
Interest–
Charges	$	(147.7	)	$	(68.7	)	115	%	$	(29.3	)	134	%
Interest Income	$	0.3		$	7.9		(96	)%	$	0.5		1413	%
Capitalized Interest Expense	$	77.7		$	23.5		231	%	$	14.2		65	%
Commodity Derivative Income (Expense)	$	7.3		$	(13.6	)	(154	)%	$	—		N/A
Loss on Debt Extinguishment	$	—		$	—		N/A		$	(13.8	)	(100	)%
Income Tax Expense	$	(39.6	)	$	(152.6	)	(74	)%	$	(148.9	)	2	%

Lease Operating Expenses

The increase in lease operating expenses for 2006, compared to 2005, is primarily related to higher costs being charged by service companies in 2006 relative to 2005 resulting in increased lease operating expenses of approximately $29.7 million, costs associated with hurricane related repairs resulting in increased lease operating expenses of approximately $22.2 million and the acquisition of Latigo in May 2006, which contributed approximately $20.8 million in additional expenses. These higher lease operating expenses were only partially offset by reductions of approximately $29.8 million related to the Company’s Gulf of Mexico disposition. The increase in lease operating expenses for 2005, compared to 2004, is related primarily to onshore properties acquired by the Company in the fourth quarter of 2004 and throughout 2005 which increased the Company’s expenses by approximately $13.8 million; higher costs being charged by service companies in 2005 relative to 2004 resulting in increased lease operating expenses of approximately $11.4 million, and maintenance expenses on several of the Company’s significant offshore properties due to damage from Hurricanes Ivan, Katrina and Rita resulting in increased expenses of approximately $4.0 million (net of insurance recoveries). The Company currently expects lease operating expenses to increase in future periods with the addition of Latigo related expenses for an entire reporting period. This increase in 2007 should be partially mitigated by the property sales discussed in “Net (gain) loss on sales of properties” below.

On a per unit of production basis, the Company’s total lease operating expenses were $1.50 per Mcfe for 2006, $0.96 per Mcfe for 2005 and $0.61 per Mcfe for 2004. The increased unit costs in 2006 and 2005 were primarily related to the increased expenses discussed above, compounded by the production decreases discussed in “Oil and Gas Revenues.”.

General and Administrative Expenses

The increase in general and administrative expenses for 2006, compared with 2005, is primarily related to increased benefit expenses (excluding increases from the Latigo acquisition) of approximately $16.2 million and approximately $8.3 million in increased salary and benefit expenses resulting from the Latigo acquisition. General and administrative expenses increased in 2005 compared to 2004 primarily due to increases in benefit expenses of approximately $12.1 million and increased miscellaneous G&A of approximately $3.7 million. These increases were only partially offset by a decrease in costs related to Sarbanes-Oxley compliance of $1.1 million. The Company currently expects general and administrative expenses to increase in future periods with the addition of Latigo related expenses for the entire reporting period and the establishment of a Change of Control Retention Program to provide retention incentive for eligible employees during 2007. See Note 7 – “Severance and Retention Incentive Program” to the Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data” for additional information on the Change of Control Retention Program.

On a per unit of production basis, the Company’s general and administrative expenses were $0.83 per Mcfe in 2006, $0.55 per Mcfe in 2005 and $0.38 per Mcfe in 2004. The increased unit costs resulted from the increases in expenses discussed above, compounded by the production decreases discussed in “Oil and Gas Revenues.”

Exploration Expenses

Exploration expenses consist primarily of exploratory geological and geophysical costs that are expensed as incurred and rental payments required under oil and gas leases to hold non-producing properties (“delay rentals”). The decrease in exploration expenses for 2006, compared to 2005, resulted primarily from a decrease in seismic activity in New Zealand (resulting in a reduction of $9.5 million between periods), the sale of a partial interest in the New Zealand seismic license ($4.1 million reduction) and a decrease in exploration activity in the Gulf of Mexico due to the sale of 50% of the Company’s interests ($3.7 million reduction), partially offset by an increase in seismic activity in the Company’s Vietnam operations of $8.3 million and an increase in exploration expense of $1.2 million in the Company’s San Juan region. The increase in exploration expenses for 2005, compared to 2004, resulted primarily from increased seismic charges of $9.5 million in the Company’s New Zealand operations, which were partially offset by decreased 3-D seismic acquisition expenses of $5.7 million in the Gulf of Mexico and decreased seismic charges of $1.7 million in the Company’s Gulf Coast region.

Dry Hole and Impairment Expenses

Dry hole and impairment expenses relate to costs of unsuccessful exploratory wells drilled and impairment of oil and gas properties. During 2006, the Company drilled 16 gross unsuccessful exploratory wells (12.8 net to the Company’s interest) for a total cost of approximately $43.0 million; in 2005 the Company drilled 8 unsuccessful exploratory wells (6.1 net to the Company’s interest) for a total cost of $62.1 million; and in 2004 the Company drilled 7 unsuccessful exploratory wells (5.6 net to the Company’s interest) for a total cost of $40.2 million.

Generally accepted accounting principles require that if the expected future cash flow of the Company’s reserves on a proved property fall below the cost that is recorded on the Company’s books, these costs must be impaired and written down to the property’s fair value. Depending on market conditions, including the prices for oil and natural gas, and the results of operations, a similar test may be conducted at any time to determine whether impairments are appropriate. Depending on the results of this test, an impairment could be required on some of the Company’s proved properties, and this impairment could have a material negative non-cash impact on the Company’s earnings and balance sheet. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The evaluation of unproved properties requires management’s judgment to estimate the fair value of leasehold and exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn unproved properties. As a result of its review of proved and unproved properties, the Company recognized impairments to oil and gas properties of approximately $37.9 million during 2006, approximately $20.1 million during 2005 and $21.4 million during 2004.

Depreciation, Depletion and Amortization Expenses

The Company’s provision for DD&A expense is based on its capitalized costs and is determined on a cost center by cost center basis using the units of production method. The Company generally establishes cost centers for its onshore oil and gas activities on the basis of a reasonable aggregation of properties with a common geologic structural feature or stratigraphic condition. The Company generally creates cost centers on a field-by-field basis for oil and gas activities in offshore areas.

The increase in the Company’s DD&A expense for 2006, compared to 2005, resulted primarily from a decrease in the percentage of the Company’s production coming from fields that have DD&A rates that are lower than the Company’s recent historical composite DD&A rate (principally offshore fields and legacy onshore fields) and a corresponding increase in the percentage of the Company’s production coming from fields that have DD&A rates that are higher than the Company’s recent historical composite rate (principally production from the Latigo acquisition). The Company currently expects its average DD&A rate to increase during 2007, as the effects of the higher rate per Mcf Latigo properties and the sale of the lower rate per Mcf Gulf of Mexico properties have a greater impact on the Company’s overall production profile.

The increase in the Company’s DD&A expense for 2005, compared to 2004, resulted primarily from an increased DD&A rate caused by a decrease in the percentage of the Company’s production coming from fields that have DD&A rates that are lower than the Company’s recent historical composite DD&A rate (principally properties in the Gulf of Mexico which were shut-in due to hurricane downtime) and a corresponding increase in the percentage of the Company’s production coming from fields that have DD&A rates that are higher than the Company’s recent historical composite rate (principally increased production from properties acquired through corporate acquisitions).

Production and Other Taxes

The increase in production and other taxes for 2006, compared to 2005, is primarily related to increased severance taxes of $3.5 million and increased ad valorem taxes of $6.7 million (both increases resulting primarily from the Latigo acquisition). The increase in production and other taxes for 2005, compared to 2004, is primarily due to higher product prices and acquisitions resulting in increased severance taxes of approximately $6.1 million and $4.1 million, respectively. Additionally, franchise taxes increased approximately $3.6 million in 2005 due to acquisitions.

Net (Gain) Loss on Sales of Properties

Net (gain) loss on the sales of properties is derived from the sale of oil and gas properties and other assets, including tubular stock and vehicles. On May 31, 2006, the Company sold an undivided 50 percent interest in each and all of its Gulf of Mexico oil and gas leasehold interests and related pipelines and equipment to an affiliate of Mitsui & Co., Ltd., for approximately $448.8 million, after purchase price adjustments. The sale resulted in a pre-tax gain of $302.7 million. This gain, along with $2.1 million of pre-tax gains on sales of other properties and assets, has been reflected in the caption “Net (gain) loss on sale of properties” in the Company’s results of operations.

Other

Other expense includes the Company’s cost to move its products to market (transportation costs), accretion expense related to Company asset retirement obligations, recognition of recoveries from business interruption insurance and various other operating expenses. The following table shows the significant items included in Other expense and the changes between periods (expressed in millions):

	For the Year Ended December 31,
	2006			2005			2004
Transportation costs	$	12.4		$	12.5		$	13.3
Accretion expense	9.0			8.0			4.8
Miscellaneous	9.1			4.5			1.4
Business interruption insurance	(9.2		)	(40.7		)	(11.1		)
Total	$	21.3		$	(15.7	)	$	8.4

Accretion expense increased during the three year periods due to the Company’s increased property base and increased estimates of future liabilities due to rising service costs. Miscellaneous expense increased in 2006 compared to 2005 due to tax settlements on the Madden unit for 2002 through 2005 ($2.9 million) and the establishment of a reserve for pending litigation ($2.0 million). Miscellaneous expense increased in 2005 compared to 2004 primarily due to hedge ineffectiveness. The business interruption insurance relates to claims from the shut-in of a significant portion of the Company’s Gulf of Mexico production during 2006, 2005, and the fourth quarter of 2004 as a result of the infrastructure damage caused by Hurricanes Ivan, Katrina and Rita.

Interest

Interest Charges. The increase in the Company’s interest charges for 2006, compared to 2005, was due to an increase in the average amount of the Company’s outstanding debt during 2006 (incurred primarily to fund the purchase of Northrock in September 2005 and the purchase of Latigo in May 2006) and, to a lesser extent, an increase in the average interest rate on the Company’s revolving credit facility from 5.84% in 2005 to 6.85% in 2006. The increase in the Company’s interest charges for 2005, compared to 2004, resulted primarily from an increase in the average amount of the Company’s outstanding debt during 2005 and, to a lesser extent, an increase in the average interest rate on the Company’s revolving credit facility from 3.67% in 2004 to 5.84% in 2005. The Company incurred approximately $763 million in additional debt in connection with the Latigo acquisition and $690 million in additional debt in connection with the Northrock acquisition, which had a significant impact on the Company’s 2006 and 2005 interest expense. The Company also incurred $317 million in additional debt during December 2004 primarily related to acquisitions, but this did not have a significant impact on the Company’s 2004 interest expense.

Interest Income. The decrease in the Company’s interest income for 2006, compared to 2005 resulted from a decrease in the average amount of cash and cash equivalents temporarily invested. The cash and cash equivalents invested during 2005 increased from 2004 primarily due to the proceeds from the sale of the Thailand Entities. These proceeds were subsequently used to fund a portion of the Northrock purchase.

Capitalized Interest. Interest costs related to financing major oil and gas projects in progress are required to be capitalized until the projects are substantially complete and ready for their intended use if projects are evaluated as successful. The increase in capitalized interest for 2006, compared to 2005, and for 2005, compared to 2004, resulted from an increase in the average amount of capital expenditures subject to interest capitalization (including those of discontinued operations), as well as the increase in interest charges discussed above. The average amount of capital expenditures subject to interest capitalization was $1.1 billion, $358 million, and $210 million for the years 2006, 2005, and 2004, respectively. In the fourth quarter of 2006, the Company changed the classification of interest capitalized in the Statement of Cash Flows from an operating cash outflow to an investing cash outflow. The Company will reflect this new classification in all future reporting periods.

Commodity Derivative Income (Expense)

Commodity derivative income (expense) for 2005 and 2006 represents gains or losses on derivative contracts that no longer qualify for hedge accounting treatment. Although all of the Company’s collars are effective as economic hedges, the Gulf of Mexico disposition and the shut-in forecasted hydrocarbon production from the Company’s Gulf of Mexico properties (resulting primarily from hurricane activity during the third quarter of 2005) caused certain of the gas and crude oil collar contracts to lose their qualification for hedge accounting under SFAS 133. The Company recorded realized and unrealized gains (losses) related to these contracts of $7.3 million and ($13.6) million for the periods ended December 31, 2006, and 2005, respectively. No such expense was incurred during 2004, as all of the Company’s derivative contracts qualified for hedge accounting at that time.

Loss on Debt Extinguishment

The loss on debt extinguishment for 2004 is related to redemption premiums paid and/or unamortized debt issuance costs which were expensed due to the redemption of the 2009 Notes and the replacement of the Company’s previous bank credit facility with a new credit facility.

Income Tax Expense

Changes in the Company’s income tax expense are a function of the Company’s consolidated effective tax rate, the Company’s pre-tax income and the jurisdiction in which the income is earned. The decrease in the Company’s income tax expense for 2006, compared to 2005, primarily resulted from reductions in the statutory federal income tax rates in Canada from approximately 26% to 19% (phased in through 2010). The increase in the Company’s tax expense for 2005, compared to 2004, resulted primarily from increased pre-tax income. The Company’s consolidated effective tax rate for 2006, 2005 and 2004 was 9.5%, 36.9%, and 37.4%, respectively.

Discontinued Operations

Northrock, the Thailand Entities and Pogo Hungary are classified as discontinued operations in the Company’s financial statements. The summarized financial results and financial position data of the discontinued operations were as follows (amounts expressed in millions):

Operating Results Data

	Year Ended December 31,
	2006			2005			2004
Revenues	$	509.8		$	392.5		$	335.3
Costs and expenses	(427.3		)	(222.4		)	(237.1		)
Other income (expense)	(0.6		)	5.6			0.3
Income before income taxes	81.9			175.7			98.5
Income taxes	(13.5		)	(93.8		)	(85.8		)
Income before gain from discontinued operations, net of tax	68.4			81.9			12.7
Gain on sale, net of tax of $9.7 million in 2005	—			407.8			—
Income from discontinued operations, net of tax	$	68.4		$	489.7		$	12.7

The decrease in income from discontinued operations from 2005 to 2006 is primarily related to the recognition of a gain on the sale of the Thailand Entities and Pogo Hungary in 2005. No gain on sale was recognized in 2006. The increase in income from discontinued operations for 2005, compared to 2004, primarily relates to gains recognized on the sale of the Thailand Entities and Pogo Hungary. The Company recognized no tax benefit for its costs in Hungary, resulting in a high effective tax rate for 2005 and 2004.

Liquidity and Capital Resources

The Company’s primary needs for cash are for exploration, development, acquisition and production of oil and gas properties, repayment of principal and interest on outstanding debt and payment of income taxes. The Company funds its exploration and development activities primarily through internally generated cash flows and budgets capital expenditures based on projected cash flows. The Company adjusts capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition results and cash flow. The Company has historically utilized net cash provided by operating activities, available cash, debt, and equity as capital resources to obtain necessary funding for all other cash needs.

The Company’s cash flow provided by operating activities for 2006 was $651.9 million, of which $387.4 million was provided by continuing operations. This compares to cash flow from operating activities of $845.5 million in 2005 ($602.7 million from continuing operations) and $738.7 million in 2004 ($544.3 million from continuing operations). The resulting changes are attributable to the reasons described under “Results of Operations” above. Cash flows used in investing activities for 2006 were $1,332.3 million in total and $955.2 million in continuing investing activities, which included the approximately $764.9 million Latigo transaction that was funded using available cash on hand, the net proceeds from the Company’s offering of the 2013 Notes, and additional borrowings under the revolving credit facility. Cash flows provided by financing activities were $644.7 million for 2006, of which $623.5 million was provided by continuing financing activities. During 2006, the Company issued $450 million principal amount of 2013 Notes (see description below) and borrowed cash of $226 million (net of repayments) under its revolving credit facility and money market lines. During 2006, the Company also paid for the repurchase of $7.7 million of its common stock and paid $17.5 million of common stock dividends. As of December 31, 2006, the Company had cash and cash equivalents of $22.7 million and long-term debt obligations of $2.3 billion (excluding debt discount) with no repayment obligations until 2009. The Company may determine to repurchase outstanding debt in the future, including in open market transactions, privately negotiated transactions or otherwise, depending on market conditions, liquidity requirements, contractual restrictions and other factors.

Effective October 20, 2006, the Company’s lenders redetermined the borrowing base under its $1 billion revolving credit facility at $1.5 billion. As of February 21, 2007, the Company had an outstanding balance of $823 million under its facility. As such, the available borrowing capacity under the facility was $177 million.

Corporate Acquisitions

On May 2, 2006, the Company completed the acquisition of Latigo Petroleum, Inc. (“Latigo”), a privately held corporation for approximately $764.9 million in cash, including transaction costs. The purchase price was funded using cash on hand and debt financing. Latigo’s operations are concentrated in west Texas and the Texas Panhandle with key exploration plays in the Texas Panhandle. The Company acquired Latigo primarily to strengthen its position in domestic exploration and development properties.

In addition to the Latigo acquisition, Northrock also completed the corporate acquisition of a Canadian company on February 21, 2006 for cash consideration totaling approximately $18.6 million. Due to the sale of the Canadian operations in 2007, the impact of the Canadian acquisitions is now reflected as discontinued operations in the Company’s consolidated financial statements.

2013 Notes

On June 6, 2006, the Company issued $450 million principal amount of 7.875% senior subordinated notes due 2013 (“2013 Notes”). The proceeds from the sale of the 2013 Notes were used to pay down obligations under the Company’s bank revolving credit agreement. The 2013 Notes bear interest at a rate of 7.875%, payable semi-annually in arrears on May 1 and November 1 of each year. The 2013 Notes are general unsecured senior subordinated obligations of the Company, and are subordinated in right of payment to the Company’s senior indebtedness, which currently includes the Company’s obligations under the bank revolving credit agreement and LIBOR rate advances. The Company, at its option, may redeem the 2013 Notes in whole or in part, at any time on or after May 1, 2010, at a redemption price of 103.938% of their principal amount and decreasing percentages thereafter. The Company may also redeem a portion of the 2013 Notes prior to May 1, 2009 with proceeds from equity offerings, and some or all of the Notes prior to May 1, 2010, in each case by paying specified premiums. The indenture governing the 2013 Notes also imposes certain covenants on the Company, including covenants limiting: incurrence of indebtedness, including senior indebtedness; payments of dividends, stock repurchases, and redemption of subordinated debt; the sales of assets or subsidiary capital stock; transactions with affiliates; liens; agreements restricting dividends and distributions by subsidiaries; and mergers or consolidations.

In the event of a “change of control”, as defined in the 2013 Note agreement, the repayment terms of the 2013 Notes could be accelerated. For additional discussion, see “Change of Control” below.

LIBOR Rate Advances

Under separate Promissory Note Agreements with various lenders, LIBOR rate advances are made available to the Company on an uncommitted basis up to $100 million. Advances drawn under these agreements are reflected as long-term debt on the Company’s balance sheet because the Company currently has the ability and intent to reborrow such amounts under its Credit Agreement. The Company’s 2011 Notes, 2013 Notes, 2015 Notes and 2017 Notes may restrict all or a portion of the amounts that may be borrowed under the Promissory Note Agreements. The Promissory Note Agreements permit either party to terminate the letter agreements at any time upon three-business days notice. As of February 21, 2007 there was $100 million outstanding under these agreements.

Change of Control

On February 23, 2007, a shareholder that beneficially owns approximately 7.9% of the Company’s stock, formally provided notice to the Company of its intention to conduct a proxy contest at the Company’s 2007 Annual Meeting that would, if successful,

result in a change in a majority of the Board of Directors by (i) nominating three persons in opposition to the Board’s nominees, and (ii) proposing amendments to the Company’s bylaws to expand the Board and elect three additional nominees. Directors are elected by a plurality of vote of the shareholders, and amendments to the Company’s bylaws must be approved by a majority of the shares outstanding. If there is a change in a majority of the Board of Directors not approved by a vote of two-thirds of the incumbent directors, the indentures governing the Company’s senior subordinated notes require the Company to offer to repurchase all outstanding notes at 101% of their principal amount and to repay all outstanding senior debt, including the credit facility, prior to repurchasing the notes (or obtain consent from the lenders allowing for such repurchase). Although such a change in a majority of the Board of Directors would not, by itself, constitute an event of default under the credit facility, failure by the Company to perform its indenture obligations would allow the lenders under the credit facility to accelerate the credit facility debt. During 2007, two series of the Company’s notes, representing $800 million in aggregate principal amount, have generally traded below their principal face value, and the other two series, representing $650 million in aggregate principal amount, have generally traded above 101% of their principal amount. The Company cannot predict the actions its noteholders or lenders may take. However, the Company believes that holders whose notes were trading below the repurchase price at the time the rights were triggered would exercise their repurchase rights. Additionally, the Company believes that lenders under its credit facility and holders whose notes were trading above the repurchase price may also exercise their repayment or repurchase rights, as the case may be, to the extent they expect that the holders whose notes were trading below the repurchase would exercise such rights or for other reasons. The Company does not have sufficient cash available to fund a repurchase of all or a substantial portion of the senior subordinated notes or to repay all or a substantial portion of outstanding debt under the credit facility.

Defaults under, or the acceleration of, the notes or credit facility could significantly and adversely affect the Company’s financial position. If the Company were not able to refinance the debt, it could be required to sell substantial assets in order to satisfy the obligations or to seek protection under the federal bankruptcy laws. Any refinancing of the Company’s existing debt with new debt, if available, would likely involve substantial costs, including the premium to repurchase notes from existing holders and transaction costs associated with obtaining new debt. Such new debt may be on less favorable terms than the Company’s existing debt. Refinancing may negatively impact the Company’s strategic alternatives initiative.

A change in the majority of the Board of Directors as a result of the pending proxy contest would also trigger an obligation to make payments under the Company’s executive employment agreements (upon termination of employment by the executives during specified periods or in specified circumstances) and under the Company’s severance and retention program.

Future Capital and Other Expenditure Requirements

The Company’s capital and exploration budget for 2007, which does not include any amounts that may be expended for acquisitions or any interest which may be capitalized resulting from projects in progress, was established by the Company’s Board of Directors at $720 million. The Company has included 370 gross wells in its 2007 capital and exploration budget, including wells to be drilled in the United States, Canada and New Zealand. As of February 21, 2007, the Company anticipates that its available cash and cash investments, cash provided by operating activities and funds available under its revolving credit facility will be sufficient to fund the Company’s ongoing operating, interest and general and administrative expenses, its authorized capital budget, and dividend payments at current levels for the foreseeable future. The declaration and amount of future dividends on the Company’s common stock will depend upon, among other things, the Company’s future earnings and financial condition, liquidity and capital requirements, its ability to pay dividends and other payments under covenants contained in its debt instruments, the general economic and regulatory climate and other factors deemed relevant by the Company’s Board of Directors.

Other Material Long-Term Commitments

Contractual Obligations. The Company’s material contractual obligations include long-term debt, operating leases, and other contracts. Material contractual obligations for which the ultimate settlement amounts are not fixed and determinable include derivative contracts that are sensitive to future changes in commodity prices and other factors. See “Item 7A. Quantitative and Qualitative Disclosure about Market Risk.” A summary of the Company’s known contractual obligations as of December 31, 2006 are set forth on the following table:

	Payments due by period (in millions)
			Less than		1 - 3		4 - 5		More than
	Total		1 Year		Years		Years		5 Years
Long Term Debt (a)	$	3,183.8	$	106.2	$	1,084.4	$	400.6	$	1,592.6
Operating Lease Obligations (b)	154.8		14.7		27.7		25.6		86.8
Purchase Obligations (c)	32.0		3.5		18.6		1.1		8.8
Asset Retirement Obligations (d)	870.0		3.8		8.6		5.0		852.6
Other Obligations (e)	—		—		—		—		—
Total	$	4,240.6	$	128.2	$	1,139.3	$	432.3	$	2,540.8

(a) Includes interest on fixed rate debt, but excludes variable rate interest expense on the Company’s bank credit facility.

(b) Operating leases principally include the Company’s office lease commitments and various other equipment rentals, including gas compressors. Where rented equipment such as compressors is considered essential to the operation of the lease, the Company has assumed that such equipment will be leased for the estimated productive life of the reserves, even if the contract terminates prior to such date. See Note 6 to the Consolidated Financial Statements.

(c) This represents i) the Company’s share of the contractual commitments for drilling rigs that have a term greater than six months or which cannot be terminated at the end of the well that is currently being drilled and ii) firm transportation agreements representing “ship-or-pay” arrangements whereby the Company has committed to ship certain volumes of gas for a fixed transportation fee (principally from the Madden Field in Wyoming). The Company entered into these arrangements to ensure its access to gas markets and expects to produce sufficient volumes to satisfy substantially all of its firm transportation obligations.

(d) This represents the Company’s estimate of future asset retirement obligations on an undiscounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 16 to the Consolidated Financial Statements.

(e) As of December 31, 2006, the Company has a projected benefit obligation of $12.3 million related to its pension plan. It has been excluded from this table due to the uncertainty of the timing of the funding of the obligation. See Note 12 to the Consolidated Financial Statements.

Commitments under Joint Operating Agreements. As is common in the oil and gas industry, the Company operates in many instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator in the event that the non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses. The contractual obligations set forth above represent the Company’s working interest share of the contractual commitments that it has entered into as operator and, to the extent that it is aware, the contractual commitments entered into by the operator of projects that the Company does not operate.

Production Sharing Contract. During 2006, the Company, together with a joint venture partner, entered into a Production Sharing Contract with PetroVietnam, the state oil company of Vietnam. Under this agreement, PetroVietnam may exercise the option to hold a participating working interest of up to 20% of any commercial discovery made in the Block 124 area. The Company currently has no production or proved reserves in Vietnam.

Surety Bonds. In the ordinary course of the Company’s business and operations, it is required to post surety bonds from time to time with third parties, including governmental agencies, primarily to cover self insurance, site restoration, equipment dismantlement, plugging and abandonment obligations. As of December 31, 2006, the Company had obtained surety bonds from a number of insurance and bonding institutions covering certain operations in the United States in the aggregate amount of approximately $9.9 million that are not included in the table presented above. In connection with their administration of offshore leases in the Gulf of Mexico, the MMS annually evaluates each lessee’s plugging and abandonment liabilities. The MMS reviews this information and applies certain financial tests including, but not limited to, current asset and net worth tests. The MMS determines whether each lessee is financially capable of paying the estimated costs of such plugging and abandonment liabilities. The Company must annually provide the MMS with financial information. If the Company does not satisfy the MMS requirements, it could be required to post supplemental bonds. In the past, the Company has not been required to post supplemental bonds; however, there can be no assurance that the Company will satisfy the financial tests and remain on the list of MMS lessees exempt from the supplemental bonding requirements. The Company cannot predict or quantify the amount of any such supplemental bonds or the annual premiums related thereto and therefore has not included them in the prior table, but the amount could be substantial.

Guarantees and Letters of Credit. As of February 21, 2007, approximately $2.6 million in letters of credit had been issued on the Company’s behalf relating to its Canadian operations.

Credit Agreement and Borrowing Base Determination

Credit Agreement. The Company has a revolving credit facility (the “Credit Agreement”) that provides for a $1.0 billion revolving loan facility terminating on December 16, 2009. The amount that may be borrowed under the Credit Agreement may not exceed a borrowing base determined at least semiannually using the administrative agent’s usual and customary criteria for oil and gas reserve valuation, adjusted for incurrences of other indebtedness since the last redetermination of the borrowing base. As of February 21, 2007, the borrowing base was $1.5 billion. The credit agreement provides that in specified circumstances involving an increase in ratings assigned to Pogo’s debt, Pogo may elect for the borrowing base limitation to no longer apply to restrict available borrowings. The next redetermination of the borrowing base is expected to occur by May 1, 2007. A significant decline in the prices that the Company is expected to receive for its future oil and gas production could have a material negative impact on the borrowing base under the Credit Agreement which, in turn, could have a material negative impact on the Company’s liquidity. If at a redetermination of the borrowing base, the lenders reduce the borrowing base below the amount then outstanding under the Credit Agreement and other senior debt arrangements, the Company must repay the excess to the lenders in no more than four substantially equal monthly installments, commencing not later than 90 days after the Company is notified of the new borrowing base. Until the deficiency is eliminated, increases in

some applicable interest rate margins apply. Borrowings under the credit facility bear interest, at the Company’s election, at a prime rate or Eurodollar rate, plus in each case an applicable margin. In addition, a commitment fee is payable on the unused portion of each lender’s commitment. The applicable interest rate margin varies from 0% to 0.25% in the case of borrowings based on the prime rate and from 1.00% to 2.00% in the case of borrowings based on the Eurodollar rate, depending on the utilization level in relation to the borrowing base and, in the case of Eurodollar borrowings, ratings assigned to the Company’s debt. The Credit Agreement includes procedures for additional financial institutions selected by the Company to become lenders under the agreement, or for any existing lender to increase its commitment in an amount approved by the Company and the lender, subject to a maximum of $250 million for all such increases in commitments of new or existing lenders. The Credit Agreement also permits short-term swing-line loans up to $10 million and the issuance of letters of credit up to $75 million, which in each case reduce the credit available for revolving credit borrowings. As of February 21, 2007, there was $823 million outstanding under the Credit Agreement.

Application of Critical Accounting Policies and Management’s Estimates

The discussion and analysis of the Company’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. The Company’s significant accounting policies are described in Note 1 to the consolidated financial statements included in this Annual Report on Form 10-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. The Company analyzes its estimates, including those related to oil and gas revenues, bad debts, oil and gas properties, marketable securities, income taxes, derivatives, contingencies and litigation, on a periodic basis and bases its estimates on historical experience and various other assumptions that management believes to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of the Company’s financial statements:

Successful Efforts Method of Accounting

The Company accounts for its oil and gas exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but such costs are charged to expense if and when the well is determined not to have found reserves in commercial quantities. In most cases, a gain or loss is recognized for sales of producing properties.

The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil and gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of oil and gas leasehold acquisition costs included in unproved properties requires management’s judgment to estimate the fair value of such properties. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when the Company enters a new exploratory area in hopes of finding oil and gas reserves. The initial exploratory wells may be unsuccessful and the associated costs will be expensed as dry hole costs. Seismic costs can be substantial, which will result in additional exploration expenses when incurred.

Reserve Estimates

The Company’s estimates of oil and gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the

area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and/or the rate of depletion of such oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material. The Company had a downward reserve revision equivalent to 0.80% of proved reserves during the year ended December 31, 2006, while the years ended December 31, 2005 and 2004 had upward reserve revisions equivalent to 2.85% and 0.95% of proved reserves, respectively. Reserve revisions result from a variety of sources such as changes in well performance related to the efficiency of natural drive mechanisms and the improved understanding of drainage areas. A significant reduction in the 2006 year end price for natural gas resulted in reduced forecasted economic recovery, which more than offset improved performance. For the years ended December 31, 2005 and 2004, increased product prices augmented improved well performance. If the estimates of proved reserves were to decline, the rate at which the Company records depletion expense would increase. Holding all other factors constant, a 1% reduction in the Company’s proved reserve estimate at December 31, 2006 would result in an annual increase in DD&A expense of approximately $3.2 million.

Impairment of Oil and Gas Properties

The Company reviews its proved oil and gas properties for impairment on an annual basis or whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. The Company estimates the expected future cash flows from its proved oil and gas properties and compares these future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to its fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company has recognized impairment expense in 2006, 2005 and 2004. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require the Company to record an impairment of its oil and gas properties and there can be no assurance that such impairments will not be required in the future nor that they will not be material.

Fair Values of Derivative Instruments

The estimated fair values of the Company’s derivative instruments are recorded on the Company’s consolidated balance sheet. Historically, substantially all of the Company’s derivative instruments have initially represented cash flow hedges of the price of future oil and natural gas production. Therefore, while fair values of such hedging instruments must be estimated at the end of each reporting period, the related changes in such fair values are not included in the Company’s consolidated results of operations, to the extent they are expected to offset the future cash flows from oil and natural gas production. Instead, the changes in fair value of hedging instruments are recorded directly to shareholders’ equity until the hedged oil or natural gas quantities are produced and sold.

The estimation of fair values for the Company’s hedging derivatives requires substantial judgment. The Company estimates the fair values of its derivatives on a monthly basis using an option-pricing model. To utilize the option-pricing model, the Company uses various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time value of options. The estimated future prices are compared to the prices fixed by the hedge agreements, and the resulting estimated future net cash inflows (outflows) over the lives of the hedges are discounted using the Company’s current borrowing rates under its revolving credit facility. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differentials and interest rates. Historically, the majority of the Company’s derivative instruments have been hedges of the price of crude oil and natural gas production. The Company is not involved in any derivative trading activities.

Derivative contracts that do not initially qualify for hedge accounting treatment or lose their qualification for hedge accounting treatment (such as those contracts that lost the qualification for hedge accounting treatment during 2005 due to curtailed production resulting from hurricane damage or during 2006 due to the sale of 50% of the Company’s interests in the Gulf of Mexico) are carried at their fair value on the Company’s consolidated balance sheet. The Company recognizes all changes in the fair value of these contracts in the Company’s consolidated results of operations in the period in which the change occurs in the caption “Commodity derivative expense.”

Business Combinations/Acquisitions

In 2006, the Company grew through the acquisition of Latigo Petroleum, Inc. This acquisition was accounted for using the purchase method of accounting. Under the purchase method, the acquiring company adds to its balance sheet the estimated fair values of the acquired company’s assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill. Goodwill and other intangibles with an indefinite useful life are assessed for impairment at least annually. The Company has never recorded any goodwill in connection with its business combinations/acquisitions. However, there can be no assurance that the Company will not do so in the future.

There are various assumptions made by the Company in determining the fair values of an acquired company’s assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas properties acquired. To determine the estimated fair value of both proved and unproved properties, the Company prepares estimates of oil, natural gas and NGL reserves. These estimates are based on work performed by the Company’s engineers and outside petroleum reservoir consultants. The judgments associated with the estimation of reserves are described earlier in this section. The fair value of the estimated reserves acquired in a business combination is then calculated based on the Company’s estimates of future net revenues from oil, natural gas and NGL production. The Company’s estimates of future prices are based on its own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics, such as economic growth forecasts. They are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity and trends in regional pricing differentials. Future price forecasts from independent third parties are also taken into account in arriving at the Company’s own pricing estimates. The Company’s estimates of future prices are applied to the estimated reserve quantities acquired to arrive at estimated future net revenues. For estimated proved reserves, the future net revenues are then discounted to derive a fair value for such reserves. The fair value of proved reserves is then used to estimate the fair value of proved property costs acquired in a business combination. The Company also applies these same general principles in arriving at the fair value of unproved reserves acquired in a business combination. These unproved reserves are generally classified as either probable or possible reserves. The fair value of probable and possible reserves is then used to estimate the fair value of unproved property costs acquired in a business combination. Because of their very nature, probable and possible reserve estimates are less precise than those of proved reserves. Generally, in the Company’s business combinations, the determination of the fair values of oil and gas properties requires more judgment than the estimates of fair values for other acquired assets and liabilities.

Future Development and Abandonment Costs

Future development costs include costs incurred to obtain access to proved reserves, including drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the ultimate settlement amount, inflation factors, credit adjusted discount rates, timing of settlement and changes in the political, legal, environmental and regulatory environment. The Company reviews its assumptions and estimates of future abandonment costs on an annual basis. We account for future abandonment costs pursuant to SFAS 143, which requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Holding all other factors constant, if the Company’s estimate of future abandonment costs is revised upward, earnings would decrease due to higher DD&A expense. Likewise, if these estimates were revised downward, earnings would increase due to lower DD&A expense. It would require an increase in the present value of the Company’s estimated future abandonment cost of approximately $11 million (representing an increase of approximately 9.04% to the Company’s December 31, 2006 asset retirement obligation) to increase the Company’s DD&A rate by $0.01 per Mcfe for the year ended December 31, 2006.

Recognition of Insurance Recoveries

The Company recognizes estimated proceeds from insurance recoveries only when the amount of the recovery is determinable and when the Company believes that the proceeds are probable of recovery. When the amount of the estimated recoveries has been determined and when the Company has concluded that the recovery is probable, the recoveries are recognized in the results of operations. Business interruption proceeds are recorded as a reduction of “Other” expense and property repair and debris removal recoveries are recorded as a reduction of “Lease operating expense”.

Pension and Other Post-Retirement Benefits

Accounting for pensions and other post-retirement benefits involves several assumptions including the expected rates of return on plan assets, determination of discount rates for remeasuring plan obligations, determination of inflation rates regarding compensation levels and health care cost projections. The Company develops its demographics and utilizes the work of actuaries to assist with the measurement of employee-related obligations. The assumptions used vary from year-to-year, which will affect future results of operations. Any differences among these assumptions and the results actually experienced will also impact future results of operations. An analysis of the effect of a 1% change in health care cost trends on post-retirement benefits is included in Note 12 to the Consolidated Financial Statements.

Income Taxes

For financial reporting purposes, the Company generally provides for taxes at the rate applicable for the appropriate tax jurisdiction. Where the Company’s present intention is to reinvest the unremitted earnings in its foreign operations, the Company does not provide for U.S. income taxes on unremitted earnings of foreign subsidiaries. Management periodically assesses the need to utilize these unremitted earnings to finance the foreign operations of the Company. This assessment is based on cash flow projections that are the result of estimates of future production, commodity pricing and expenditures by tax jurisdiction for the Company’s operations. Such estimates are inherently imprecise since many assumptions utilized in the cash flow projections are subject to revision in the future.

Management also periodically assesses, by tax jurisdiction, the probability of recovery of recorded deferred tax assets based on its assessment of future earnings outlooks. Such estimates are inherently imprecise since many assumptions utilized in the assessments are subject to revision in the future.

Other Matters

Inflation. Publicly held companies are asked to comment on the effects of inflation on their business. As of February 21, 2007, annual inflation in terms of the decrease in the general purchasing power of the dollar is running at a moderate rate. While the Company, like other companies, continues to be affected by fluctuations in the purchasing power of the dollar due to inflation, such effect is not considered significant as of February 21, 2007.

Recent Accounting Pronouncements

On July 13, 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes – an interpretation of FAS 109”. FIN 48 clariﬁes the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006 and was adopted by the Company as of January 1, 2007. The adoption of FIN 48 did not result in an adjustment to the Company’s financial statements.

In September, 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of SFAS 157 is not expected to have a material impact on the Company’s financial statements.