8-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 14, 2007

POGO PRODUCING COMPANY

(Exact name of registrant as specified in its charter)

Delaware	1-7792	74-1659398
(State or other jurisdiction	(Commission File Number)	(IRS Employer
of incorporation)		Identification No.)

5 Greenway Plaza, Suite 2700

Houston, Texas 77046-0504

(Address of principal executive offices and zip code)

Registrant’s telephone number, including area code: (713) 297-5000

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

oWritten communications pursuant to Rule 425 under the Securities Act  (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01  Other Events.

On August 14, 2007, Pogo Producing Company, a Delaware corporation (the “Company”), completed the sale of all of the issued and outstanding shares of Northrock Resources Ltd, a Canadian company and a wholly-owned subsidiary of the Company (“Northrock”) for a total purchase price of U.S. $2 billion.  The sale of the shares of Northrock effected the disposition of all of the Company’s Canadian operations.

Under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company classifies assets to be disposed of as held for sale or, if appropriate, discontinued operations when they have received appropriate approvals by the Company’s management or Board of Directors and when they meet other criteria.  As of June 30, 2007, the Company was in the process of completing the sale of Northrock and accordingly classified those operations as discontinued operations for all periods presented in its Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 (“June 2007 Quarterly Report”).

In accordance with requirements of the Securities and Exchange Commission (the “SEC”), the Company has recast information presented in the following items in its Annual Report on Form 10-K for the fiscal year ended December 31, 2006 filed with the SEC on March 1, 2007 (the “2006 Annual Report”) to conform to the presentation of the Company’s Canadian operations as discontinued operations:

·Item 6—Selected Financial Data,

·Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations,

·Item 7A—Quantitative and Qualitative Disclosures About Market Risk, and

·Item 8—Financial Statements and Supplementary Data

The recast information is filed as Exhibits 99.10, 99.11, 99.12 and 99.13 to this report and incorporated herein by this reference.  Except with respect to the limited matters described above, the recast information included in this report has not been updated to reflect events subsequent to the filing of the 2006 Annual Report.  This report should be read in conjunction with the portions of the 2006 Annual Report that have not been recast herein, as well as in conjunction with the Company’s Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2007 and  June 30, 2007 and other Current Reports on Form 8-K filed by the Company with the SEC after the 2006 Annual Report.

Statements in this report other than statements of historical fact are “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act and are thus prospective.  As further discussed under the caption “Forward Looking Statements” in the 2006 Annual Report, these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from future results expressed or implied by such forward-looking statements.

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FORWARD LOOKING STATEMENTS

The statements included or incorporated by reference in this Current Report on Form 8-K include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements included or incorporated by reference herein, other than statements of historical fact, are forward-looking statements. In some cases, you can identify the Company’s forward-looking statements by the words “anticipate,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “goal,” and similar expressions. Such forward-looking statements include, without limitation, statements regarding expected production volumes, drilling of wells and related expenditures and other statements herein and therein regarding the timing of future events regarding the operations of the Company and its subsidiaries, and the statements under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations” regarding the Company’s anticipated future financial position, results of operations, and cash requirements. Although the Company believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations (“Cautionary Statements”) are disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006 (the “Annual Report”) and in other filings by the Company with the SEC. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. The Company’s actual results could differ materially from those anticipated in these forward-looking statements as a result of the factors set forth below, the risk factors described under the caption “Risk Factors” and other factors set forth in the Annual Report and in other SEC filings of the Company. These factors include:

·the cyclical nature of the oil and natural gas industries

·the Company’s ability to successfully and profitably find, produce and market oil and gas

·uncertainties associated with the United States and worldwide economies

·current and potential governmental regulatory actions in countries where the Company operates

·substantial competition from larger companies

·the Company’s ability to implement cost reductions

·the Company’s ability to acquire and integrate oil and gas reserves

·operating interruptions (including leaks, explosions, fires, mechanical failure, unscheduled downtime, transportation interruptions, and spills and releases and other environmental risks)

·fluctuations in foreign currency exchange rates in areas of the world where the Company conducts operations

·covenant restrictions in the Company’s debt agreements

·strategic transactions, including the sale of part or all of the Company, or changes to the Company’s business plan, that may result from its strategic alternative process

Many of these factors are beyond the Company’s ability to control or predict. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels.

All subsequent written and oral forward-looking statements attributable to the Company and persons acting on the Company’s behalf are qualified in their entirety by the Cautionary Statements contained in the Annual Report and in other SEC filings of the Company.

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Item  9.01 Financial Statements and Exhibits

(d)           Exhibits.

Exhibit Number		Description
	23.1	Consent of Ryder Scott Company, L.P.
	23.2	Consent of Miller and Lents, Ltd.
	23.3	Consent of Ryder Scott Company-Canada
	23.4	Consent of Ryder Scott, L.P.
	23.5	Consent of PricewaterhouseCoopers LLP
	* 99.1	Summary Report of Ryder Scott Company, L.P. for the year ended December 31, 2006 (Exhibit 99.1, Annual Report on Form 10-K for the year ended December 31, 2006).
	* 99.2	Summary Report of Ryder Scott Company—Canada for the year ended December 31, 2006 (Exhibit 99.2, Annual Report on Form 10-K for the year ended December 31, 2006).
	* 99.3	Summary Report of Miller and Lents, Ltd. for the year ended December 31, 2006 (Exhibit 99.3, Annual Report on Form 10-K for the year ended December 31, 2006).
	* 99.4	Summary Report of Ryder Scott Company, L.P. for the year ended December 31, 2006 (Exhibit 99.4, Annual Report on Form 10-K for the year ended December 31, 2006).
	* 99.5	Summary Report of Ryder Scott Company, L.P. for the year ended December 31, 2005 (Exhibit 99.1, Amendment No. 1 on Form 10-K/A, filed October 27, 2006, to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
	* 99.6	Summary Report of Ryder Scott Company—Canada for the year ended December 31, 2005 (Exhibit 99.2, Amendment No. 1 on Form 10-K/A, filed October 27, 2006, to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
	* 99.7	Summary Report of Miller and Lents, Ltd. for the year ended December 31, 2005 (Exhibit 99.3, Amendment No. 1 on Form 10-K/A, filed October 27, 2006, to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
	* 99.8	Summary Report of Ryder Scott Company, L.P. for the year ended December 31, 2004 (Exhibit 99.1, Annual Report on Form 10-K for the year ended December 31, 2004).
	* 99.9	Summary Report of Miller and Lents, Ltd. for the year ended December 31, 2004 (Exhibit 99.2, Annual Report on Form 10-K for the year ended December 31, 2004).
	99.10	Selected Financial Data
	99.11	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	99.12	Quantitative and Qualitative Disclosures About Market Risk
	99.13	Financial Statements and Supplementary Data

* Asterisk indicates exhibits incorporated by reference as shown.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	POGO PRODUCING COMPANY
Date: August 17, 2007	By:	/s/ James P. Ulm, II
		James P. Ulm, II
		Senior Vice President and
		Chief Financial Officer

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EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Ryder Scott Company, L.P. hereby consents to the use of its name and the information from its reports regarding its estimates of reserves and future net revenues from the production and sale of these reserves for the years ended December 31, 2006, 2005, 2004 and 2003 in Pogo Producing Company’s Current Report on Form 8-K, dated August 17, 2007, and to the incorporation by reference thereof into Pogo Producing Company’s previously filed Registration Statement Nos. 33-54969, 333-04233, 333-75105, 333-75105-01, 333-75105-02, 333-74861, 333-42426, 333-42428, 333-60800, 333-67324, 333-65548, 333-86856, 333-98205, 333-102775, 333-115130, 333-86417, 333-126097, 333-130557 and 333-136926.

	Your very truly,
	/s/ RYDER SCOTT COMPANY, LP
	RYDER SCOTT COMPANY, L.P.
August 17, 2007
Houston, Texas

EX-23.2

Exhibit 23.2

Miller and Lents, Ltd.

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Miller and Lents, Ltd. hereby consents to the use of its name and the information from its reports regarding its estimates of reserves and future net revenues from the production and sale of those reserves for the years ended December 31, 2006, 2005, 2004 and 2003 in Pogo Producing Company’s Current Report on Form 8-K, dated August 17, 2007, and to the incorporation by reference thereof into Pogo Producing Company’s previously filed Registration Statement Nos. 33-54969, 333-04233, 333-75105, 333-75105-01, 333-75105-02, 333-74861, 333-42426, 333-42428, 333-60800, 333-67324, 333-65548, 333-86856, 333-98205, 333-102775, 333-115130, 333-86417, 333-126097, 333-130557 and 333-136926.

	MILLER AND LENTS, LTD.
	By:	/s/ CARL D. RICHARD
		Carl D. Richard
		Senior Vice President
Houston, Texas
August 17, 2007

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Ryder Scott Company-Canada hereby consents to the use of its name and the information from its report regarding its estimates of reserves and future net revenues from the production and sale of those reserves of Northrock Resources, Ltd. as of December 31, 2006 and 2005, in Pogo Producing Company’s Current Report on Form 8-K, dated August 17, 2007, and to the incorporation by reference thereof into Pogo Producing Company’s previously filed Registration Statement Nos. 33-54969, 333-04233, 333-75105, 333-75105-01, 333-75105-02, 333-74861, 333-42426, 333-42428, 333-60800, 333-67324, 333-65548, 333-86856, 333-98205, 333-102775, 333-115130, 333-86417, 333-126097, 333-130557 and 333-136926.

	Your very truly,
	/s/ RYDER SCOTT COMPANY — CANADA
	RYDER SCOTT COMPANY—CANADA
August 17, 2007
Calgary, Alberta

EX-23.4

Exhibit 23.4

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Ryder Scott Company, L.P. hereby consents to the use of its name and the information from its reports regarding its estimates of reserves and future net revenues from the production and sale of those reserves of Latigo Petroleum Inc. for the year ended December 31, 2006 in Pogo Producing Company’s Current Report on Form 8-K, dated August 17, 2007, and to the incorporation by reference thereof into Pogo Producing Company’s previously filed Registration Statement Nos. 33-54969, 333-04233, 333-75105, 333-75105-01, 333-75105-02, 333-74861, 333-42426, 333-42428, 333-60800, 333-67324, 333-65548, 333-86856, 333-98205, 333-102775, 333-115130, 333-86417, 333-126097, 333-130557 and 333-136926.

	Your very truly,
	/s/ RYDER SCOTT COMPANY, LP
	RYDER SCOTT COMPANY, L.P.
August 17, 2007
Houston, Texas

EX-23.5

Exhibit 23.5

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-4 (Nos. 333-126097, 333-130557, and 333-136926) and Form S-8 (Nos. 333-115130, 333-102775, 333-98205 and 333-86856) of Pogo Producing Company of our report dated March 1, 2007, except as to Note 11, for which the date is August 17, 2007, relating to the consolidated financial statements, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 8-K.

PricewaterhouseCoopers LLP

Houston, Texas

August 17, 2007

EX-99.10

Exhibit 99.10

ITEM 6.     Selected Financial Data

In the following table, the Company’s financial, production and other data for 2006 reflect the acquisition of Latigo Petroleum, Inc. (“Latigo”) on May 2, 2006.  The financial, production and other data for 2006 and 2005 reflect the Company’s Canadian oil and gas exploration, development and production activities in its wholly owned subsidiary Northrock Resources (“Northrock”) as discontinued operations. Northrock, which was acquired on September 27, 2005 was sold in August of 2007. The Company’s results for periods presented prior to 2006 reflect its oil and gas exploration, development and production activities in the Kingdom of Thailand and Hungary, which were sold in 2005, as discontinued operations.  The selected financial data should be read in conjunction with “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and notes thereto included under “Item 8 – Financial Statements and Supplementary Data.”

	For the Year Ended December 31,
	2006		2005			2004		2003			2002
	(Expressed in millions, except per share and production data)
Financial Data
Revenues and other:
Crude oil and condensate	$	405.8	$	413.4		$	417.1	$	426.4		$	282.0
Natural gas	457.8		621.1			512.6		397.3			231.3
Natural gas liquids	61.1		47.6			43.4		32.4			24.4
Oil and gas revenues	924.7		1,082.1			973.1		856.1			537.7
Other	5.8		3.8			3.8		2.0			1.3
Total	$	930.5	$	1,085.9		$	976.9	$	858.1		$	539.0
Income from continuing operations before cumulative
effect of change in accounting principle	$	377.8	$	261.0		$	249.0	$	235.2		$	68.6
Income from discontinued operations, net of tax	68.4		489.7		(a)	12.7		59.9			38.4
Cumulative effect of change in accounting principle	—		—			—		(4.2		)(b)	—
Net income	$	446.2	$	750.7		$	261.7	$	290.9		$	107.0
Per share data:
Basic income from operations before cumulative
effect of change in accounting principle -
From continuing operations	$	6.56	$	4.32		$	3.90	$	3.76		$	1.18
From discontinued operations	1.18		8.11			0.20		0.96			0.67
Basic income from operations before cumulative
effect of change in accounting principle	$	7.74	$	12.43		$	4.10	$	4.72		$	1.85
Diluted income from operations before cumulative
effect of change in accounting principle -
From continuing operations	$	6.50	$	4.28		$	3.87	$	3.67		$	1.16
From discontinued operations	1.18		8.04			0.19		0.93			0.61
Diluted income from operations before cumulative
effect of change in accounting principle	$	7.68	$	12.32		$	4.06	$	4.60		$	1.77
Cash dividends on common stock	$	0.30	$	0.25		$	0.2125	$	0.20		$	0.12
Price range of common stock:
High	$	60.42	$	59.69		$	51.34	$	49.50		$	39.28
Low	$	38.01	$	41.59		$	39.25	$	34.29		$	23.00
Weighted average number of common
shares outstanding
Basic	57.6		60.4			63.8		62.5			57.9
Diluted	58.1		60.9			64.4		64.6			64.3
Long-term debt at year end	$	2,319.7	$	1,643.4		$	755.0	$	487.3		$	722.9
Shareholders’ equity at year end	$	2,567.4	$	2,098.6		$	1,727.9	$	1,453.7		$	1,077.8
Total assets at year end	$	6,971.1	$	5,675.7		$	3,481.1	$	2,758.7		$	2,491.6
Production (Sales) Data
Net daily average production
and weighted average price:
Natural gas (MMcf per day)	201.5		231.6			244.3		210.4			201.3
Price (per Mcf)	$	6.22	$	7.35		$	5.73	$	5.17		$	3.15
Crude oil and condensate (Bbl per day)	17,717		22,337			29,530		40,173			30,971
Price (per Bbl)	$	62.75	$	50.70		$	38.59	$	29.08		$	24.95
Natural gas liquids (Bbl per day)	4,492		3,842			4,220		4,109			4,480
Price (per Bbl)	$	37.28	$	33.93		$	28.09	$	21.59		$	14.94

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	For the Year Ended December 31,
	2006		2005		2004		2003		2002
	(Expressed in millions)
Capital Expenditures
(including interest capitalized)
Oil and gas:
Domestic Onshore -
Exploration	$	210.2	$	117.1	$	29.0	$	26.2	$	14.5
Development	371.2		143.3		159.5		118.0		117.2
Purchase of properties	1,046.2		46.0		583.8		177.7		—
Domestic Offshore -
Exploration	12.1		63.8		54.3		28.1		33.6
Development	35.1		20.9		74.0		23.9		100.7
Purchase of properties	—		—		24.7		—		—
Other international -
Exploration	0.1		—		5.6		0.1		—
Development	—		0.1		—		—		—
Total oil and gas	1,674.9		391.2		930.9		374.0		266.0
Other	4.7		6.0		6.2		2.5		3.3
Total	$	1,679.6	$	397.2	$	937.1	$	376.5	$	269.3

a)Includes approximately $408 million of after-tax gain on the sale of the Company’s operation in Hungary and Thailand.

b)Effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations.”  This new accounting standard required a change in the accounting for asset retirement obligations.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations, Application of Critical Accounting Policies and Management’s Estimates, Future Development and Abandonment Costs” for further discussion of the provisions of SFAS 143.

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EX-99.11

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.

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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.

2

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.

3

					% 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.

4

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.”

5

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.

6

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.

7

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.

8

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,

9

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.

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(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

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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

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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.”

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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”.

14

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.

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EX-99.12

Exhibit 99.12

ITEM 7A.     Quantitative and Qualitative Disclosures About Market Risk.

The Company is exposed to market risk, including adverse changes in commodity prices, interest rates and foreign currency exchange rates as discussed below.

Commodity Price Risk

The Company produces, purchases, and sells natural gas, crude oil, condensate and NGLs. As a result, the Company’s financial results can be significantly affected as these commodity prices fluctuate widely in response to changing market forces. In the past, the Company has made limited use of a variety of derivative financial instruments only for non-trading purposes as a hedging strategy to manage commodity prices associated with oil and gas sales and to reduce the impact of commodity price fluctuations. See “Business—Competition and Market Conditions.”

Interest Rate Risk

From time to time, the Company has entered into various financial instruments, such as interest rate swaps, to manage the impact of changes in interest rates. As of February 21, 2007, the Company has no open interest rate swap or interest rate lock agreements. Therefore, the Company’s exposure to changes in interest rates primarily results from its short-term and long-term debt with both fixed and floating interest rates. The following table presents principal or notional amounts (stated in millions) and related average interest rates by year of maturity for the Company’s debt obligations and their indicated fair market value at December 31, 2006:

	2007		2008		2009			2010		2011			Thereafter			Total			Fair Value
Long-Term Debt:
Variable Rate	$	—	$	—	$	872.0		$	—	$	—		$	—		$	872.0		$	872.0
Average Interest Rate	—		—		6.84		%	—		—			—			6.84		%	—
Fixed Rate	$	—	$	—	$	—		$	—	$	200.0		$	1,250.0		$	1,450.0		$	1,429.0
Average Interest Rate	—		—		—			—		8.25		%	7.18		%	7.32		%	—

Foreign Currency Exchange Rate Risk

In addition to the U.S. dollar, the Company and certain of its subsidiaries conduct a substantial portion of their business in foreign currencies and are therefore subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investing transactions. Currently, the Company’s greatest exposure to exchange rate fluctuations is for transactions being conducted in Canadian dollars, while the exposures in New Zealand and Vietnam currencies are immaterial at this time.  As of February 21, 2007, the Company is not a party to any foreign currency exchange agreement.

Current Hedging Activity

As of December 31, 2006, the Company held various derivative instruments.  The Company has entered into natural gas and crude oil option agreements referred to as “collars”.  Collars are designed to establish floor and ceiling prices on anticipated future natural gas and crude oil production. The Company has designated a significant portion of these contracts as cash flow hedges designed to achieve a more predictable cash flow, as well as to reduce exposure to price volatility. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.  Currently, the Company does not expect losses due to creditworthiness of its counterparties.

The gas derivative transactions are generally settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days of a particular contract month.  The oil derivative transactions are generally settled based on the average of the reporting settlement prices for West Texas Intermediate on the NYMEX for each trading day of a particular calendar month.  For any particular collar transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price of such transaction.

The estimated fair value of these transactions is based upon various factors that include closing exchange prices on the NYMEX, volatility and the time value of options.  Further details related to the Company’s hedging activities as of December 31, 2006 are as follows:

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		NYMEX
		Contract				Fair Value
Contract Period and		Price				of
Type of Contract	Volume	Floor		Ceiling		Asset/(Liability)
						(in millions)
Natural Gas Contracts (MMBtu) (a)
Collar Contracts:
January 2007 - December 2007	5,475	$	6.00	$	12.00	$	1.6
January 2007 - December 2007	1,825	$	6.00	$	12.15	$	0.5
January 2007 - December 2007	9,125	$	6.00	$	12.50	$	2.9
January 2007 - December 2007	913	$	8.00	$	13.40	$	1.4
January 2007 - December 2007	2,738	$	8.00	$	13.50	$	4.2
January 2007 - December 2007	913	$	8.00	$	13.52	$	1.4
January 2007 - December 2007	913	$	8.00	$	13.65	$	1.4
January 2008 - December 2008	1,830	$	8.00	$	12.05	$	1.5
January 2008 - December 2008	2,745	$	8.00	$	12.10	$	2.3
January 2008 - December 2008	915	$	8.00	$	12.25	$	0.8
Crude Oil Contracts (Barrels)
Collar Contracts:
January 2007 - December 2007	1,460,000	$	50.00	$	75.00	$	(2.2	)
January 2007 - December 2007	365,000	$	50.00	$	75.25	$	(0.6	)
January 2007 - December 2007	3,650,000	$	50.00	$	77.50	$	(3.9	)
January 2007 - December 2007	182,500	$	60.00	$	82.75	$	0.3
January 2007 - December 2007	547,500	$	60.00	$	83.00	$	0.9
January 2007 - December 2007	182,500	$	60.00	$	84.00	$	0.3
January 2008 - December 2008	183,000	$	60.00	$	80.00	$	0.1
January 2008 - December 2008	183,000	$	60.00	$	80.05	$	0.1
January 2008 - December 2008	183,000	$	60.00	$	80.10	$	0.1
January 2008 - December 2008	366,000	$	60.00	$	80.25	$	0.2

(a) MMBtu means million British Thermal Units.

 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 now recognizes all future changes in the fair value of these collar contracts in the consolidated statement of income for the period in which the change occurs under the caption “Commodity derivative income(expense).’’  As of December 31, 2006, the Company had the following collar contracts that no longer qualify for hedge accounting:

		NYMEX
		Contract				Fair Value
Contract Period and		Price				of
Type of Contract	Volume	Floor		Ceiling		Asset/(Liability)
						(in millions)
Natural Gas Contracts (MMBtu)
Collar Contracts:
January 2007 - December 2007	7,300	$	6.00	$	12.15	$	2.2
January 2007 - December 2007	3,650	$	6.00	$	12.20	$	1.1

 Additional information about the Company’s hedging activities can be found in Note 14 – “Commodity Derivatives and Hedging Activities” in this report.

2

EX-99.13

Exhibit 99.13

ITEM 8.        Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of Pogo Producing Company:

We have completed integrated audits of Pogo Producing Company’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Pogo Producing Company and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Annual Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria.  Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO.  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting.  Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit.  We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Latigo Petroleum, Inc. (Latigo) from its assessment of internal control over financial reporting as of December 31, 2006 because

1

Latigo was acquired in a purchase business combination during 2006.  We have also excluded Latigo from our audit of internal control over financial reporting. Latigo is a wholly-owned subsidiary of the Company whose total assets and total revenues represent 16% and 5%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2006.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 1, 2007, except as to Note 11, for which the date is August 17, 2007.

2

POGO PRODUCING COMPANY & SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2006			2005			2004
	(Expressed in millions,
	except per share amounts)
Revenues:
Oil and gas	$	924.7		$	1,082.1		$	973.1
Other	5.8			3.8			3.8
Total	930.5			1,085.9			976.9
Operating Costs and Expenses:
Lease operating	183.4			136.0			100.5
General and administrative	101.1			77.9			62.1
Exploration	15.8			23.1			21.7
Dry hole and impairment	80.9			82.2			61.6
Depreciation, depletion and amortization	285.3			261.3			251.9
Production and other taxes	67.7			56.8			44.1
Net (gain) loss on sales of properties	(304.8		)	(0.2		)	0.3
Other	21.3			(15.7		)	8.4
Total	450.7			621.4			550.6
Operating Income	479.8			464.5			426.3
Interest:
Charges	(147.7		)	(68.7		)	(29.3		)
Income	0.3			7.9			0.5
Capitalized	77.7			23.5			14.2
Commodity Derivative Income (Expense)	7.3			(13.6		)	—
Loss on Debt Extinguishment	—			—			(13.8		)
Income From Continuing Operations Before Taxes	417.4			413.6			397.9
Income Tax Expense	(39.6		)	(152.6		)	(148.9		)
Income From Continuing Operations	377.8			261.0			249.0
Income from Discontinued Operations, net of tax	68.4			489.7			12.7
Net Income	$	446.2		$	750.7		$	261.7
Earnings per Common Share:
Basic
Income from continuing operations	$	6.56		$	4.32		$	3.90
Income from discontinued operations	1.18			8.11			0.20
Net income	$	7.74		$	12.43		$	4.10
Diluted
Income from continuing operations	$	6.50		$	4.28		$	3.87
Income from discontinued operations	1.18			8.04			0.19
Net income	$	7.68		$	12.32		$	4.06
Dividends per Common Share	$	0.30		$	0.25		$	0.2125

The accompanying notes to consolidated financial statements are an integral part hereof.

3

POGO PRODUCING COMPANY & SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2006			2005
	(Expressed in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	22.7		$	57.7
Accounts receivable	103.9			129.2
Other receivables	47.6			19.9
Federal income taxes receivable	58.0			18.4
Deferred income tax	—			12.2
Inventories - tubulars	18.5			16.3
Commodity derivative contracts	10.9			—
Assets of discontinued operations	96.5			90.0
Other	10.1			3.1
Total current assets	368.2			346.8
Property and Equipment:
Oil and gas, on the basis of successful efforts accounting
Proved properties	5,056.6			4,308.5
Unproved properties	301.8			111.7
Other, at cost	43.2			35.7
	5,401.6			4,455.9
Accumulated depreciation, depletion, and amortization
Oil and gas	(1,619.8		)	(1,807.1		)
Other	(30.5		)	(24.1		)
	(1,650.3		)	(1,831.2		)
Property and equipment, net	3,751.3			2,624.7
Other Assets:
Commodity derivative contracts	5.0			—
Assets of discontinued operations	2,819.5			2,672.9
Other	27.1			31.3
	2,851.6			2,704.2
	$	6,971.1		$	5,675.7

The accompanying notes to consolidated financial statements are an integral part hereof.

4

	December 31,
	2006			2005
	(Expressed in millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable – operating activities	$	107.6		$	93.2
Accounts payable – investing activities	74.2			63.8
Income taxes payable	0.4			2.0
Accrued interest payable	26.0			20.2
Accrued payroll and related benefits	5.1			3.7
Commodity derivative contracts	—			52.3
Deferred income tax	7.2			—
Liabilities from discontinued operations	162.7			150.0
Other	18.6			9.9
Total current liabilities	401.8			395.1
Long-Term Debt	2,319.7			1,643.4
Deferred Income Tax	804.3			505.9
Asset Retirement Obligation	114.9			105.1
Other Liabilities and Deferred Credits	44.3			66.5
Liabilities from Discontinued Operations	718.7			861.1
Total liabilities	4,403.7			3,577.1
Commitments and Contingencies (Note 6)	—			—
Shareholders’ Equity:
Preferred stock, $1 par; 4,000,000 shares authorized	—			—
Common stock, $1 par; 200,000,000 shares authorized, and 65,794,206 and 65,275,106 shares issued, respectively	65.8			65.3
Additional capital	971.4			977.9
Retained earnings	1,892.9			1,464.2
Accumulated other comprehensive income (loss)	(1.4		)	(30.0		)
Deferred compensation	—			(17.5		)
Treasury stock (7,365,359 shares, at cost)	(361.3		)	(361.3		)
Total shareholders’ equity	2,567.4			2,098.6
	$	6,971.1		$	5,675.7

The accompanying notes to consolidated financial statements are an integral part hereof.

5

POGO PRODUCING COMPANY & SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2006			2005			2004
	(Expressed in millions)
Cash flows from operating activities:
Cash received from customers	$	963.7		$	1,061.5		$	978.5
Operating, exploration and general and administrative expenses paid	(432.7		)	(262.2		)	(243.3		)
Income taxes paid	(117.4		)	(189.5		)	(159.6		)
Income taxes received	3.2			0.2			0.4
Interest paid	(58.8		)	(51.3		)	(30.0		)
Cash received (paid) related to commodity derivative contracts	2.7			(11.4		)	—
Business interruption insurance proceeds	15.5			47.1			—
Other	11.2			8.3			(1.7		)
Net cash provided by continuing operating activities	387.4			602.7			544.3
Net cash provided by discontinued operating activities	264.5			242.8			194.4
Net cash provided by operating activities	651.9			845.5			738.7
Cash flows from investing activities:
Capital expenditures	(599.9		)	(334.4		)	(285.9		)
Purchase of properties	(58.7		)	(90.8		)	(189.6		)
Acquisition of corporations, net of cash acquired of $1.8 million, $32.9 million and $11.9 million, respectively	(763.1		)	(1,704.6		)	(270.4		)
Sale of properties and corporations, net of $51.5 million cash on hand in 2005	451.4			763.9			1.5
Purchase of current investments	—			(16.8		)	(15.0		)
Sale of current investments	—			122.3			15.0
Commodity derivative contracts	(0.4		)	(8.6		)	—
Hurricane-related insurance proceeds	15.5			17.9			—
Net cash used in continuing investing activities	(955.2		)	(1,251.1		)	(744.4		)
Net cash used in discontinued investing activities	(377.1		)	(139.1		)	(217.3		)
Net cash used in investing activities	(1,332.3		)	(1,390.2		)	(961.7		)
Cash flows from financing activities:
Borrowings under senior debt agreements	2,419.0			3,865.0			2,010.0
Payments under senior debt agreements	(2,193.0		)	(3,774.0		)	(1,594.0		)
Proceeds from issuance of new financing	450.0			797.3			—
Purchase of Company stock	(7.7		)	(351.8		)	—
Payments (to) from discontinued operations	(21.2		)	138.3			(25.0		)
Redemption of debt	—			—			(157.8		)
Proceeds from exercise of stock options and realization of tax benefits	5.2			11.2			12.0
Payment of cash dividends on common stock	(17.5		)	(15.2		)	(13.6		)
Payment of senior debt acquired through corporate purchase	—			—			(50.0		)
Payment of financing issue costs and other	(11.3		)	(14.9		)	(3.8		)
Net cash provided by continuing financing activities	623.5			655.9			177.8
Net cash (used in) provided by discontinued financing activities	21.2			(139.6		)	25.0
Net cash provided by financing activities	644.7			516.3			202.8
Effect of exchange rate changes on cash	0.7			(0.3		)	2.2
Net decrease in cash and cash equivalents	(35.0		)	(28.7		)	(18.0		)
Cash and cash equivalents from continuing operations, beginning of the year	8.0			0.6			55.8
Cash and cash equivalents from discontinued operations, beginning of the year	49.7			85.8			48.7
Cash and cash equivalents at the end of the year	$	22.7		$	57.7		$	86.5

The accompanying notes to consolidated financial statements are an integral part hereof.

6

	Year Ended December 31,
	2006			2005			2004
	(Expressed in thousands)
Reconciliation of net income to net cash provided by operating activities:
Net income	$	446.2		$	750.7		$	261.7
Adjustments to reconcile net income to net cash provided by operating activities Income from discontinued operations, net of tax	(68.4		)	(489.7		)	(12.7		)
(Gains) losses on sales	(304.8		)	(0.2		)	0.3
Depreciation, depletion and amortization	285.3			261.3			251.9
Dry hole and impairment	80.9			82.2			61.6
Other	1.5			(7.3		)	8.5
Deferred income taxes	(32.7		)	(3.9		)	3.1
Change in assets and liabilities:
(Increase) decrease in accounts receivable	32.2			(9.2		)	(26.7		)
Increase in federal income taxes receivable	(37.4		)	(40.0		)	(12.7		)
Increase in inventory - product	—			—			—
(Increase) decrease in other assets	(4.0		)	1.9			3.5
Increase (decrease) in accounts payable	(24.4		)	35.3			12.7
Increase (decrease) in income taxes payable	(4.4		)	4.7			(0.7		)
Increase (decrease) in accrued interest payable	8.2			15.7			(5.4		)
Increase in accrued payroll and related benefits	1.4			0.2			0.3
Increase (decrease) in other current liabilities	3.9			(2.7		)	(3.7		)
Increase in deferred credits	3.9			3.7			2.6
Net cash provided by continuing operating activities	387.4			602.7			544.3
Net cash provided by discontinued operating activities	264.5			242.8			194.4
Net cash provided by operating activities	$	651.9		$	845.5		$	738.7

The accompanying notes to consolidated financial statements are an integral part hereof.

7

POGO PRODUCING COMPANY & SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Expressed in millions)

								Accumulated
								Other			Deferred
								Compre-			Compen-									Compre-
								hensive			sation						Share-			hensive
	Common	Additional			Retained			Income			Restricted			Treasury			holders’			Income
	Stock(a)	Capital			earnings			(Loss)			Stock			Stock			Equity			(Loss)
Balance at December 31, 2003	63.8	$	914.5		$	480.6		$	—		$	(3.5	)	$	(1.8	)	$	1,453.6
Net income	—	—			261.7			—			—			—			261.7			$	261.7
Stock option activity and other	0.5	16.8			—			—			—			—			17.3
Shares issued as compensation	0.3	12.4			—			—			—			—			12.7
Issuance of restricted stock, less amortization of $1.9 million	—	—			—			—			(6.4		)	—			(6.4		)
Dividends ($0.2125 per common share)	—	—			(13.6		)	—			—			—			(13.6		)
Unrealized gain arising during the year on price hedge contracts	—	—			—			3.0			—			—			3.0
Net unrealized gains on price hedge contracts	—	—			—			(0.4		)	—			—			(0.4		)	2.6
Comprehensive income	—	—			—			—			—			—			—			$	264.3
Balance at December 31, 2004	64.6	$	943.7		$	728.7		$	2.6		$	(9.9	)	$	(1.8	)	$	1,727.9
Net income	—	—			750.7			—			—			—			750.7			$	750.7
Stock option activity and other	0.4	15.9			—			—			—			—			16.3
Shares issued as compensation	0.3	18.3			—			—			—			—			18.6
Issuance of restricted stock, less amortization of $4.6 million	—	—			—			—			(7.6		)	—			(7.6		)
Dividends ($0.25 per common share)	—	—			(15.2		)	—			—			—			(15.2		)
Share repurchase	—	—			—			—			—			(359.5		)	(359.5		)
Unrealized loss arising during the year on price hedge contracts	—	—			—			(72.2		)	—			—			(72.2		)
Reclassification adjustment included in net income	—	—			—			16.7			—			—			16.7
Net unrealized gains on price hedge contracts	—	—			—			—			—			—			—			(55.5		)
Foreign currency translation adjustment	—	—			—			22.9			—			—			22.9			22.9
Comprehensive income	—	—			—			—			—			—			—			$	718.1
Balance at December 31, 2005	65.3	$	977.9		$	1,464.2		$	(30.0	)	$	(17.5	)	$	(361.3	)	$	2,098.6
Net income	—	—			446.2			—			—			—			446.2			$	446.2
Stock option activity and other	0.1	6.1															6.2
Shares issued as compensation	0.4																0.4
Restricted stock activity		15.0															15.0
Cumulative adjustment - FAS 123(R)		(27.6		)							17.5						(10.1		)
Dividends ($0.30 per common share)					(17.5		)										(17.5		)
Cumulative adjustment - FAS 158								(19.6		)							(19.6		)
Unrealized gain arising during the year on price hedge contracts								68.1									68.1
Reclassification adjustment included in net income								(8.5		)							(8.5		)
Net unrealized gains on price hedge contracts	—	—			—			—			—			—			—			59.6
Foreign currency translation adjustment	—	—			—			(11.4		)	—			—			(11.4		)	(11.4		)
Comprehensive income	—	—			—			—			—			—			—			$	494.4
Balance at December 31, 2006	65.8	$	971.4		$	1,892.9		$	(1.4	)	$	—		$	(361.3	)	$	2,567.4

(a)  Reflects both dollar and share amounts at $1.00 par value.

The accompanying notes to consolidated financial statements are an integral part hereof.

8

POGO PRODUCING COMPANY & SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)  Summary of Significant Accounting Policies

Nature of Operations—

Pogo Producing Company was incorporated in 1970. Pogo Producing Company and its subsidiaries (the “Company”) are engaged in oil and gas exploration, development, production and acquisition activities in the United States, both onshore principally in the states of New Mexico, Texas, Louisiana, Wyoming and Indiana, and offshore in the Gulf of Mexico (primarily in federal waters offshore Louisiana and Texas). The Company also conducts exploration activities in offshore New Zealand and Vietnam.

The Company’s results for 2006 and 2005 reflect its oil and gas exploration, development and production activities in Canada, which was acquired on September 27, 2005 and sold in 2007, as discontinued operations. The Company’s results for 2005 and 2004 reflect its oil and gas exploration, development and production activities in the Kingdom of Thailand and Hungary, which were sold in 2005, as discontinued operations.  Except where noted, the discussions in the following notes relate to the Company’s continuing activities only.

Use of Estimates—

The preparation of these financial statements requires the use of certain estimates by management in determining the Company’s assets, liabilities, revenues and expenses. Actual results could differ from such estimates.  Depreciation, depletion and amortization of oil and gas properties, the impairment of oil and gas properties, and the Company’s allocation of purchase price to acquired properties are all determined using estimates of oil and gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way.  Proved reserves of crude oil, condensate, natural gas and natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. Proved reserves do not include, for example, hydrocarbons that may be recovered from undrilled prospects or the recovery of which is otherwise subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or through the application of fluid injection or other improved recovery techniques confirmed by a pilot project or operation of an installed program. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled and other undrilled units where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. The Securities and Exchange Commission provides a complete definition of proved reserves in Rule 4-10(a) of Regulation S-X.

Principles of Consolidation—

The consolidated financial statements include the accounts of Pogo Producing Company and its subsidiaries, after elimination of all significant intercompany transactions. Majority owned subsidiaries are fully consolidated. The Company’s operating and working interests in oil and gas joint ventures are pro rata consolidated.

Revenue Recognition—

The Company follows the “sales” (takes or cash) method of accounting for oil and gas revenues.  Under this method, the Company recognizes revenues on production as it is taken and delivered to its purchasers.  The volumes sold may be more or less than the volumes the Company is entitled to based on its ownership interest in the property.  These differences result in a condition known in the industry as a production imbalance.  The Company’s crude oil and natural gas imbalances are not significant.  Such imbalances are reflected as adjustments to proved reserves and future cash flows in the unaudited supplementary oil and gas data included herein.

Inventories—Tubulars—

Tubular inventories consist primarily of tubular pipe and general equipment used in the Company’s operations and are stated at the lower of average cost or market value.

9

Oil and Gas Activities and Depreciation, Depletion and Amortization—

The Company follows the successful efforts method of accounting for its oil and gas activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Proved oil and gas properties are reviewed annually or when circumstances suggest the need for such a review and, if required, the proved properties are written down to their estimated fair value. Estimated fair value includes the estimated present value of future net cash flows. 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 costs related to a given area.  Drilling activities in an area by other companies may also effectively condemn unproved properties.  Exploratory well costs are capitalized until the results are determined.  If proved reserves are not discovered, the exploratory well costs are expensed.  The following table reflects the net changes in capitalized exploratory well costs pending proved reserve determination during 2006, 2005 and 2004 (amounts expressed in millions):

	2006			2005			2004
Balance at January 1,	$	6.8		$	11.8		$	1.0
Additions to capitalized exploratory well costs pending the determination of proved reserves	18.0			6.8			10.8
Reclassifications to proved oil and gas properties	(6.8		)	(6.7		)	—
Capitalized exploratory well costs charged to expense	—			(5.1		)	—
Balance at December 31,	$	18.0		$	6.8		$	11.8

None of the exploratory well costs have been capitalized for a period of greater than one year.

Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated as successful. Other exploratory costs, such as geological and geophysical costs and rental payments, are expensed as incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above, and is computed on a cost center by cost center basis using the units of production method, with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves. Generally, the Company 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 Company has from time to time disposed of certain non-core properties and other assets that it considers to be under performing, to have little or no remaining upside potential, or which face significant future expenditures that would result in an unacceptable rate of return. Refer to the captions “Net (gain) loss on sales of properties” in the Consolidated Statements of Income.

Other properties and equipment are depreciated using a straight-line method in amounts which, in the opinion of management, are adequate to allocate the cost of the properties over their estimated useful lives.

Income Taxes—

Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes.  Changes in tax legislation are included in the relevant computations in the period in which such changes are effective.  Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit when the Company believes it is more likely than not that such benefits will not be realized.  Note 3 contains information about the Company’s income taxes, including the components of income tax provision and the composition of deferred income tax assets and liabilities.

Price Risk Management—

The Company from time to time enters into commodity price hedging contracts with respect to its oil and gas production to achieve a more predictable cash flow, as well as reduce its exposure to price volatility. The Company follows the provisions of Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”).  SFAS 133, as amended, established accounting and reporting standards requiring that every derivative instrument (including

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certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument (i.e. ineffectiveness,) if any, must be recognized currently in earnings as “Other” revenue or expense.  To the extent the forecasted transaction in a designated and qualifying hedge relationship is no longer probable of occurring, gains and losses previously deferred in other comprehensive income are immediately reclassified to earnings under the caption “Commodity derivative income(expense).’’  For those derivative instruments that do not qualify as a cash flow hedge instrument, the Company recognizes all future changes in the fair value of these instruments in the consolidated statement of income for the period in which the change occurs under the caption “Commodity derivative income(expense).’’

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 damage recoveries are recorded as a reduction of “Lease operating expense”.  During the years ended December 31, 2006, 2005, and 2004 the Company recognized $9.2 million, $40.7 million, and $11.1 million, respectively of business interruption insurance recoveries related to deferred production resulting from Hurricanes Ivan, Katrina and Rita.  During the same periods, the Company recorded reductions to lease operating expense of $18.5 million, $14.5 million, and $4.9 million, respectively, for property damage recoveries.

Treasury Stock—

On January 25, 2005, the Company announced a plan to repurchase, through open market or privately negotiated transactions, not less than $275 million, or more than $375 million of its common stock.   The repurchased shares were accounted for as treasury stock.  As of December 31, 2006, the Company had completed the purchase of 7,310,000 shares under this plan at a total cost of $359.5 million.

Retirement and Post-Retirement Benefits—

As of December 31, 2006, the Company adopted Financial Accounting Statement (“FAS”) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”, which amends FAS No. 87, “Employers’ Accounting for Pensions”, No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits”, No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”, and No. 132(R), “Employers’ Disclosures About Pensions and Other Postretirement Benefits – an amendment of FAS Nos. 87, 88, and 106”. The Statement requires companies to recognize on their 2006 balance sheets the funded status of their pension and other postretirement benefit plans, measured as of the balance sheet date. The Statement also requires that the actuarial gains and losses and the prior service costs and credits that arise during the period be recognized, net of tax, as components of other comprehensive income; these amounts in other comprehensive income will be adjusted as they are subsequently amortized and recognized as net periodic benefit costs. See Note 12 for additional information.

Consolidated Statements of Cash Flows—

The Company considers all highly liquid investments with a maturity date of three months or less to be cash equivalents. Significant transactions may occur which do not directly affect cash balances and, accordingly, are not disclosed in the Consolidated Statements of Cash Flows. Significant non-cash transactions are disclosed in the Consolidated Statements of Shareholders’ Equity relating to shares issued as compensation and in Note 16 relating to asset retirement costs.

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Foreign Currency—

The Canadian dollar is the functional currency for the Company’s Canadian operations. Accordingly, foreign exchange translation adjustments resulting from translating the Northrock financial statements from Canadian dollars to U.S. dollars are included as a separate component of other comprehensive income in shareholders’ equity on the consolidated balance sheet.  Gains or losses incurred on currency transactions in other than Canadian dollars are included in the consolidated statements of income under the caption “Income From Discontinued Operations, Net of Tax” for the period in which the transactions occur.

The U.S. dollar is the functional currency for all other areas of operations of the Company. Accordingly, monetary assets and liabilities and items of income and expense denominated in a foreign currency are remeasured to U.S. dollars at the rate of exchange in effect at the end of each month or the average for the month, and the resulting gains or losses on foreign currency transactions are included in the consolidated statements of income for the period.

Prior Year Reclassifications—

Certain prior year amounts have been reclassified to conform with the current year presentation.  Such reclassifications had no effect on the Company’s net income or shareholders’ equity. The Company changed the classification of “Net (gain) loss on sales of properties” from “Revenue and Other Income” to reflect it as a component of “Operating Costs and Expenses” for both the current and prior periods.

Recent Accounting Pronouncements

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.

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(2) Earnings per Share

Earnings per common share (basic earnings per share) are based on the weighted average number of shares of common stock outstanding during the periods indicated. Earnings per common share and potential common share (diluted earnings per share) consider the effect of dilutive securities as set out below. Amounts are expressed in millions, except per share amounts.

	2006		2005		2004
Income (numerator):
Income from continuing operations	$	377.8	$	261.0	$	249.0
Income from discontinued operations, net of tax	68.4		489.7		12.7
Net income - basic and diluted	$	446.2	$	750.7	$	261.7
Weighted average shares (denominator):
Weighted average shares - basic	57.6		60.4		63.8
Dilution effect of stock options and unvested restricted stock outstanding at end of period	0.5		0.5		0.6
Weighted average shares - diluted	58.1		60.9		64.4
Earnings per share:
Basic:
Income from continuing operations	$	6.56	$	4.32	$	3.90
Income from discontinued operations	1.18		8.11		0.20
Basic earnings per share	$	7.74	$	12.43	$	4.10
Diluted:
Income from continuing operations	$	6.50	$	4.28	$	3.87
Income from discontinued operations	1.18		8.04		0.19
Diluted earnings per share	$	7.68	$	12.32	$	4.06
Antidilutive securities;
Shares assumed not issued from options to purchase common shares as the exercise prices are above the average market price for the period or the effect of the assumed exercise would be antidilutive	0.02		—		0.02
Average price	$	48.93	$	—	$	49.02

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(3) Income Taxes

The components of income from continuing operations before income taxes for each of the three years in the period ended December 31, 2006, are as follows (expressed in millions):

	2006			2005			2004
United States	$	424.0		$	417.7		$	403.8
Foreign	(6.6		)	(4.1		)	(5.9		)
Income from continuing operations before income taxes	$	417.4		$	413.6		$	397.9

The components of income tax expense (benefit) for each of the three years in the period ended December 31, 2006, are as follows (expressed in millions):

	2006			2005			2004
Current
United States	$	73.8		$	156.9		$	145.7
Foreign	(1.5		)	1.9			0.1
Deferred
United States	79.5			(6.2		)	3.1
Foreign	(112.2)		(a)	—			—
Income tax expense	$	39.6		$	152.6		$	148.9

(a)The foreign income tax benefit in 2006 is a result of statutory reductions in the Canadian federal and provincial tax rates. Generally accepted accounting principles (“GAAP”) require that the entire tax effect of a change in enacted tax rates be allocated to continuing operations.

Total income tax expense for each of the three years in the period ended December 31, 2006, differs from the amounts computed by applying the statutory federal income tax rate to income before taxes as follows (expressed as percent of pretax income):

	2006		2005		2004
Federal statutory income tax rate	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Canadian income tax rate reduction	(26.9	)	—		—
State income taxes, net of federal benefits	1.5		1.7		1.5
Other	(0.1	)	0.2		0.9
	9.5	%	36.9	%	37.4	%

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.  GAAP requires that the entire effect of changes in enacted tax rates be allocated to continuing operations.

The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2006 and 2005 (expressed in millions) are as follows:

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	December 31,
	2006			2005
Deferred tax assets:
Foreign deferred tax assets and net operating loss carry forwards	$	2.1		$	6.3
Valuation allowance of deferred tax assets and foreign net operating loss	(2.1		)	(6.3		)
Tax basis in excess of book basis for commodity derivative contracts	—			35.2
Tax basis in excess of book basis for deferred compensation and benefit plans	21.3			20.0
Net operating loss carryforwards	62.3			2.4
Other	4.9			4.3
	88.5			61.9
Deferred tax liabilities:
Book basis in excess of tax basis for oil and gas properties and equipment	(893.3		)	(549.9		)
Other	(6.7		)	(5.7		)
	(900.0		)	(555.6		)
Net deferred tax liability	$	(811.5	)	$	(493.7	)

Book basis in excess of tax basis for oil and gas properties and equipment primarily results from differing methodologies for recording property costs and depreciation, depletion and amortization under United States generally accepted accounting principles and income tax reporting. In addition, the Company recorded a deferred tax liability resulting from book and tax basis differences for corporations acquired in 2004, 2005, and 2006.

As of December 31, 2006, the Company has a U.S. net operating loss (NOL) carryforward of approximately $178 million that may be used in future years to offset taxable income. The NOL was obtained as part of the acquisition of Latigo Petroleum, Inc. The NOL is subject to certain limitations on future utilization. The Company does not anticipate that these limitations will affect the ultimate utilization of the NOL.

As of December 31, 2006, the Company has a foreign NOL carryforward of approximately $6.4 million that may be used in future years to offset foreign taxable income.  The majority of these NOL carryforwards have no expiration date, however their utilization may be subject to limitations as a result of enacted tax legislation within the applicable foreign jurisdiction and their realization is dependent upon generating sufficient taxable income within the applicable foreign jurisdiction.  The $2.1 million valuation allowance at December 31, 2006 was related to exploration expenses the Company incurred in its foreign operations.  During 2006, the Company reduced the foreign NOL carryforwards due to the liquidation of several foreign subsidiaries.

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. Unremitted earnings of foreign subsidiaries (principally its Canadian subsidiary) for which U.S. income taxes have not been provided are approximately $220.6 million at December 31, 2006. It is not practicable to determine the amount of U.S. income taxes that would be payable upon remittance of the assets that represent those earnings.

On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the “Act”).  The Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 through 2010.  The Act also created a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations.  The Company adopted a Domestic Reinvestment Plan that qualifies for the temporary incentive. Based on that decision, the Company repatriated $497 million in extraordinary dividends, as defined in the Act, during the third quarter of 2005. The Company also repatriated an additional $315 million that did not qualify for the temporary incentive. As a result of the repatriation of $812 million, the Company recorded a U.S. tax expense of $24.1 million during 2005.

The Company and its subsidiaries file income tax returns in the U.S. federal and various state and foreign jurisdictions. The Company is no longer subject to U.S. federal, state, or local tax examinations by tax authorities for years prior to 2003. The Company’s Canadian subsidiary is no longer subject to examinations by Canadian taxing authorities for years prior to 2002. The

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Internal Revenue Service (“IRS”) completed the examination of the Company’s U.S. income tax returns through 2003 in the fourth quarter of 2005, which resulted in a refund to the Company in 2006 of $1.4 million. The IRS also reviewed the Company’s income tax return for 2004 and indicated they do not presently intend to perform an examination of that tax return. Based on the results of the last examination, the Company does not anticipate that any adjustments made to the filings for open years would result in a material change to its financial position.

On January 1, 2007, the Company will adopt the provisions of FASB Interpretation No.48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes.” The Company has determined that no uncertain tax positions exist where the Company would be required to make additional tax payments. As a result, the Company has not recorded any additional liabilities for any unrecognized tax benefits as of December 31, 2006, and will not be required to record any on January 1, 2007.

The Company’s accounting policy is to recognize penalties and interest related to unrecognized tax benefits as income tax expense. The Company does not have an accrued liability for the payment of penalties and interest at December 31, 2006.

(4) Long-Term Debt

Long-term debt at December 31, 2006, and 2005, consists of the following (dollars expressed in millions):

	December 31,
	2006			2005
Senior debt -
Bank revolving credit facility:
LIBOR based loans, borrowings at December 31, 2006 and 2005 at interest rates of 6.8524% and 5.837%, respectively	$	797.0		$	606.0
LIBOR Rate Advances, borrowings at December 31, 2006 and 2005 at interest rates of 6.6833% and 5.618%, respectively	75.0			40.0
Total senior debt	872.0			646.0
Subordinated debt -
8.25% Senior subordinated notes, due 2011	200.0			200.0
7.875% Senior subordinated notes, due 2013	450.0			—
6.625% Senior subordinated notes, due 2015	300.0			300.0
6.875% Senior subordinated notes, due 2017	500.0			500.0
Total subordinated debt	1,450.0			1,000.0
Unamortized discount on 2015 Notes	(2.3		)	(2.6		)
Long-term debt	$	2,319.7		$	1,643.4

On December 16, 2004, the Company entered into a new credit agreement (the “Credit Facility”), replacing its then existing credit agreement dated as of March 8, 2001, as amended.  The Credit Facility is with various financial institutions and provides for revolving credit borrowings up to a maximum principal amount of $1 billion at any one time outstanding, with borrowings not to 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 December 31, 2006, the borrowing base was $1.5 billion.  The Credit Facility provides that in specified circumstances involving an increase in ratings assigned to the Company’s debt, the Company may elect for the borrowing base limitation to no longer apply to restrict available borrowings.  The Credit Facility also 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. Additionally, the Credit Facility 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.   All outstanding amounts owed under the Credit Facility become due and payable no later than the final maturity date of December 16, 2009, and are subject to acceleration upon the occurrence of events of default which the Company considers usual and customary for an agreement of this type, including failure to make payments under the credit agreement, non-performance of covenants and obligations continuing beyond any applicable grace period, default in the payment of other indebtedness in excess in principal amount of $25 million or a default accelerating or permitting the acceleration of any such indebtedness, or the occurrence of a “change in control” of the Company, including the acquisition of beneficial ownership of in excess of 50% of its capital stock. If at any time the outstanding credit extended under the agreement exceeds the applicable borrowing base, the deficiency is required to be amortized in four monthly installments

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commencing 90 days after the deficiency arises, and 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 Facility contains various covenants, including among others, restrictions on liens, restrictions on incurring other indebtedness if a default under the credit agreement exists or would result or if a borrowing base deficiency would result, restrictions on dividends and other restricted payments if a default under the credit agreement exists or would result, restrictions on mergers, restrictions on investments, and restrictions on hedging activity of a speculative nature or with counterparties having credit ratings below specified levels. Financial covenants include a covenant not to permit the Company’s ratio of consolidated debt to consolidated total capitalization (determined without reduction for any non-cash write downs after the date of the credit agreement) to exceed 60% at any time, and not to permit the Company’s consolidated ratio of EBITDAX to Fixed Charges (as those terms are defined in the Credit Facility) for the four most recent fiscal quarters to be less than or equal to 2.5 to 1.0 at the end of any quarter.

On June 6, 2006, the Company issued $450 million principal amount of 7.875% senior subordinated notes due 2013. 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.

On September 23, 2005, the Company issued $500 million principal amount of 2017 Notes. The proceeds from the sale of the 2017 Notes were used to fund a portion of the Northrock acquisition.  The 2017 Notes bear interest at a rate of 6.875%, payable semi-annually in arrears on April 1 and October 1 of each year. The 2017 Notes are general unsecured senior subordinated obligations of the Company, and are subordinated in right of payment to the Company’s senior indebtedness, which includes the Company’s obligations under the Credit Facility and LIBOR rate advances.  The Company, at its option, may redeem the 2017 Notes in whole or in part, at any time on or after October 1, 2010, at a redemption price of 103.4375% of their principal amount and decreasing percentages thereafter. The Company may also redeem a portion of the 2017 Notes prior to October 1, 2008 and some or all of the Notes prior to October 1, 2010, in each case by paying specified premiums.  The indenture governing the 2017 Notes also imposes certain covenants on the Company including covenants limiting: incurrence of indebtedness including senior indebtedness; restricted payments; the issuance and sales of restricted subsidiary capital stock; transactions with affiliates; liens; disposition of proceeds of assets sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and merger, consolidations and the sale of assets.

On March 29, 2005, the Company issued $300 million principal amount of 2015 Notes at 99.101%. The proceeds from the sale of the 2015 Notes were used to pay down obligations under the Company’s bank Credit Facility.  The 2015 Notes bear interest at a rate of 6.625%, payable semi-annually in arrears on March 15 and September 15 of each year. The 2015 Notes are general unsecured senior subordinated obligations of the Company, and are subordinated in right of payment to the Company’s senior indebtedness, which includes the Company’s obligations under the Credit Facility and LIBOR rate advances.  The Company, at its option, may redeem the 2015 Notes in whole or in part, at any time on or after March 15, 2010, at a redemption price of 103.3125% of their principal amount and decreasing percentages thereafter. The Company may also redeem a portion of the 2015 Notes prior to March 15, 2008 and some or all of the Notes prior to March 15, 2010, in each case by paying specified premiums.  The indenture governing the 2015 Notes also imposes certain covenants on the Company including covenants limiting: incurrence of indebtedness including senior indebtedness; restricted payments; the issuance and sales of restricted subsidiary capital stock; transactions with affiliates; liens; disposition of proceeds of asset sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and merger, consolidations and the sale of assets.

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On April 10, 2001, the Company issued $200 million principal amount of 2011 Notes. The 2011 Notes bear interest at a rate of 8.25%, payable semi-annually in arrears on April 15 and October 15 of each year. The 2011 Notes are general unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company’s senior indebtedness, which currently includes the Company’s obligations under the Credit Facility and LIBOR rate advances.  The Company, at its option, may redeem the 2011 Notes in whole or in part, at any time on or after April 15, 2006, at a redemption price of 104.125% of their principal amount and decreasing percentages thereafter. The indenture governing the 2011 Notes also imposes certain covenants on the Company including covenants limiting: incurrence of indebtedness including senior indebtedness; restricted payments; the issuance and sales of restricted subsidiary capital stock; transactions with affiliates; liens; disposition of proceeds of asset sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and merger, consolidations and the sale of assets.

During 2004, the Company redeemed all $150 million of its 10.375% Senior Subordinated Notes due 2009 (the “2009 Notes”) at 105.188% of their face amount.  On April 19, 2004, the Company paid $157.8 million (excluding accrued interest) in cash to holders of the 2009 Notes.  The cash redemption payment was funded through borrowings under the Company’s existing bank Credit Facility. The Company recorded a pre-tax expense on the redemption of the 2009 Notes of $10.9 million in “Loss on debt extinguishment” during the year ended December 31, 2004.

A change in control in the ownership of the Company, as defined in the subordinated note agreements, could result in the acceleration of debt repayment. See Note 6 – “Commitments and Contingencies” for further discussion.

(5) Acquisitions

2006 - - 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.  At the date of purchase, Latigo owned approximately 100,100 net producing acres, plus approximately 304,600 net acres of undeveloped leasehold.  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.  The following is a calculation and final allocation of purchase price to the acquired assets and liabilities based on their relative fair values:

CALCULATION OF PURCHASE PRICE (IN MILLIONS)
Cash paid, including transaction costs	$	764.9
Plus fair market value of liabilites assumed:
Deferred income taxes	205.9
Other liabilities	55.1
Total purchase price for assets acquired	$	1,025.9
ALLOCATION OF PURCHASE PRICE (IN MILLIONS)
Proved oil and gas properties	$	846.9
Unproved oil and gas properties	157.0
Other assets	22.0
Total	$	1,025.9

In addition to the Latigo acquisition, the Company, through its Northrock subsidiary, also completed the corporate acquisition of a Canadian company on February 21, 2006 for cash consideration totaling approximately $18.6 million. The Company recorded the estimated fair value of assets and liabilities that consisted primarily of $26.9 million of oil and gas properties and deferred tax liabilities of $8.0 million.  No goodwill was recorded in connection with either of these transactions.  Due to the sale of the Canadian operations in 2007, the impact of the Canadian acquisition is now reflected as discontinued operations in the Company’s consolidated financial statements.

2005 - On September 27, 2005, the Company completed the acquisition of Northrock for approximately $1.7 billion in cash.  The Company purchased all of the outstanding shares of Northrock pursuant to a share purchase agreement that was entered into on July 8, 2005.  As of September 27, 2005, Northrock owned approximately 292,000 net producing acres, plus approximately 950,000 net acres of undeveloped leasehold.  Northrock’s activities are concentrated in Saskatchewan and Alberta with key exploration plays in Canada’s Northwest Territories, British Columbia and the Alberta Foothills. The Company acquired Northrock primarily to

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strengthen its position in North American exploration and development properties.  The following is a calculation and final allocation of purchase price to the acquired assets and liabilities based on their relative fair values:

CALCULATION OF PURCHASE PRICE (IN MILLIONS)
Cash paid, including transaction costs	$	1,737.5
Plus fair market value of liabilites assumed:
Other liabilites	100.5
Asset retirement obligation	38.8
Deferred income taxes	745.6
Total purchase price for assets acquired	$	2,622.4
ALLOCATION OF PURCHASE PRICE (IN MILLIONS)
Proved oil and gas properties	$	1,715.8
Unproved oil and gas properties	787.3
Other assets	119.3
Total	$	2,622.4

In addition to the Northrock acquisition, during 2005 the Company, through its Northrock subsidiary, also completed two corporate acquisitions in Canada for cash consideration totaling approximately $32.9 million and six other producing property acquisitions for cash consideration totaling approximately $51 million.  The Company recorded the estimated fair value of assets and liabilities on the two corporate transactions which consisted primarily of $50 million of oil and gas properties and deferred tax liabilities of $15.8 million.  No goodwill was recorded for these transactions. 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.

2004 - In December 2004, the Company completed the acquisition of two privately held corporations for approximately $282.5 million in cash and a deferred payment of $26.4 million made in 2005 to the former owner of one of the corporations. The corporations have subsequently been named Pogo Producing (San Juan) Company and Pogo Producing (Texas Panhandle) Company (the “corporations”).  The transactions included properties located primarily in the San Juan basin of New Mexico and the Texas Panhandle. The Company acquired the corporations primarily to strengthen its position in domestic natural gas properties. The Company recorded the estimated fair values of the assets acquired and the liabilities assumed at the closing date of the transactions, which primarily consisted of oil and gas properties of $423.7 million, long term debt of $50.1 million and deferred tax liabilities of $67.4 million.  No goodwill was recorded for the transactions.

In 2004, the Company also completed six other producing property acquisitions for cash consideration totaling approximately $186 million.

Pro Forma Information

The following summary presents unaudited pro forma consolidated results of operations for the three years ended December 31, 2006 for the Company’s continuing operations as if the acquisitions of Latigo and the corporations had each occurred as of January 1, 2004.  The pro forma results are for illustrative purposes only and include, in addition to the pre-acquisition historical results of Latigo and the corporations, adjustments such as increased depreciation, depletion and amortization expense resulting from the allocation of fair value to oil and gas properties acquired, increased interest expense on acquisition debt and the related tax effects of these adjustments.  The unaudited pro forma information (presented in millions of dollars, except per share amounts) is not necessarily indicative of the operating results that would have occurred had the acquisitions been consummated at that date, nor are they necessarily indicative of future operating results.

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	Year Ended December 31,
Pro Forma:	2006		2005		2004
	(Unaudited)
Revenues	$	972.0	$	1,176.3	$	1,081.1
Net income	452.9		785.5		262.3
Earnings per share:
Basic	$	7.86	$	13.01	$	4.11
Diluted	$	7.79	$	12.89	$	4.07

(6) Commitments and Contingencies

The Company has commitments for operating leases (primarily for office space) in Houston, Midland, Laredo, Tulsa, Ho Chi Minh City, and New Plymouth, and for other equipment (including gas compressors).  Rental expense for office space was $3.8 million in 2006, $2.7 million in 2005, and $2.9 million in 2004. Rental expense for other equipment was $5.1 million in 2006, $5.0 million in 2005 and $5.5 million in 2004.

Future minimum lease payments related to the Company’s operating leases at December 31, 2006 are approximately $14.7 million in 2007; $13.9 million in 2008; $13.8 million in 2009; $13.1 million in 2010; $12.5 million in 2011 and $86.8 million thereafter. 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.

On February 23, 2007, a shareholder that owned 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. 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.

20

(7) Severance and Retention Incentive Program

The Company has established a Change of Control Severance and Retention Program (the “Plan”), effective as of January 1, 2007, to provide severance benefits and a retention incentive to employees who are designated by the Plan Administrator as eligible for benefits under the Plan in the event of a “Change in Control.” The Company expects to pay approximately $11.4 million in retention incentives under the program during 2007.

The Company made retention incentive plan payments of $2 million to those personnel who were employed by Latigo at both May 2, 2006, the date of acquisition, and November 2, 2006, six months thereafter.

The Company had in place a retention incentive plan that covered personnel who were employed by Northrock on September 27, 2005 (the date of acquisition) and were still employed by Northrock on September 27, 2006. On that latter date, the Company made payments of $13.4 million related to the retention incentive plan. The impact of the Northrock retention plan has been reported as discontinued operations in the Company’s consolidated financial statements.

(8) Sales to Major Customers

The Company is an oil and gas exploration and production company that generally sells its oil and gas to numerous customers on a month-to-month basis. For purposes of comparison, sales have been presented for all three years for customers who have exceeded 10% of revenues in any given year (expressed in millions):

	2006		2005		2004
Shell Trading Company	$	96.4	$	116.8	$	147.1
Kinder Morgan	59.8		113.8		94.9

(9) Credit Risk

Substantially all of the Company’s accounts receivable at December 31, 2006 and 2005, result from oil and gas sales and joint interest billings to other companies in the energy industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. Such receivables are not collateralized.   The Company provides reserves for specifically identified receivables from customers and joint interest owners that, in the opinion of management, are considered doubtful of collection.  As of December 31, 2006 and 2005, the Company’s allowances for doubtful accounts were not material.

(10) Geographic Information

Subsequent to the sale of Northrock in 2007, the Company consists of one operating segment for oil and gas with operations primarily in the United States.

(11) Discontinued Operations

Under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, the Company classifies assets to be disposed of as held for sale or, if appropriate, discontinued operations when they have received appropriate approvals by the Company’s management or Board of Directors and when they meet other criteria.

Northrock Resources Ltd.

.  On May 28, 2007, the Company entered into an agreement to sell all of the outstanding stock of its wholly-owned subsidiary, Northrock Resources Ltd. (“Northrock”) for $2.0 billion in cash. The Company completed the sale during the third quarter of 2007 and used the proceeds to pay off senior debt and invest the remainder while evaluating debt repayment strategies.

21

Thaipo Ltd. and B8/32 Partners Ltd.—

On August 17, 2005, the Company completed the sale of its wholly owned subsidiary Thaipo Ltd. and its 46.34% interest in B8/32 Partners Ltd. (collectively referred to as the “Thailand Entities”) for a purchase price of $820 million.  The Company recognized an after tax gain of approximately $403 million on the sale of the Thailand Entities.

Pogo Hungary Ltd.—

On June 7, 2005, the Company completed the sale of its wholly owned subsidiary Pogo Hungary, Ltd. (“Pogo Hungary”) for a purchase price of $9 million.  The Company recognized an after tax gain of approximately $5 million on the sale of Pogo Hungary.

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

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	December 31,
Financial Position Data	2006		2005
Assets of Discontinued Operations
Accounts receivable	$	71.7	$	69.6
Inventories	24.7		16.0
Other current assets	0.1		4.4
Total current assets	96.5		90.0
Property, plant and equipments, net	2,805.8		2,659.7
Other long-term assets	13.7		13.2
Total noncurrent assets	2,819.5		2,672.9
Total assets	$	2,916.0	$	2,762.9
Liabilities of Discontinued Operations
Accounts payable	$	158.5	$	147.4
Income taxes payable	0.4		—
Other current liabilities	3.8		2.6
Total current liabilities	162.7		150.0
Deferred income tax	673.7		811.0
Asset retirement obligation	41.4		44.3
Other long-term liabilities	3.6		5.8
Total noncurrent liabilities	718.7		861.1
Total liabilities	$	881.4	$	1,011.1

(12) Employee Benefit Plans

The Company has a tax-advantaged savings plan in which all U.S. salaried employees may participate. Under such plan, a participating employee may allocate up to 30% of their salary, up to a maximum allowed by law, and the Company will then match the employee’s contribution on a dollar for dollar basis up to the lesser of 6% of the employee’s salary or $15,000 in 2006. Funds contributed by the employee and the matching funds contributed by the Company are held in trust by a bank trustee in six separate funds. Amounts contributed and earnings and accretions thereon may be used to purchase shares of the Company’s common stock, invest in a money market fund or invest in four stock, bond, or blended stock and bond mutual funds according to instructions from the employee. The Company contributed $1.9 million to the savings plan in 2006, $1.5 million in 2005, and $1.4 million in 2004.

The Company has adopted a trusteed retirement plan for its U.S. salaried employees. The benefits are based on years of service and the employee’s average compensation for five consecutive years within the final ten years of service which produce the highest average compensation. The Company makes annual contributions to the plan in the amount of retirement plan cost accrued or the maximum amount that can be deducted for federal income tax purposes. During 2006 and 2005, the Company contributed $7.0 million and $4.5 million to the plan, respectively.  The Company will continue to monitor the plan to determine whether a contribution will need to be made in 2007. The plan’s investment strategy and goals are to ensure, over the long-term life of the retirement plan, an adequate pool of sufficiently liquid assets to support the benefit obligations to participants, retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles of three to five years.

Although the Company has no obligation to do so, the Company currently provides full medical benefits to its retired U.S. employees and dependents. For current employees, the Company assumes all or a portion of post-retirement medical and term life insurance costs based on the employee’s age and length of service with the Company. The post-retirement medical plan has no assets and is currently funded by the Company on a pay-as-you-go basis.  The expected Company contributions to the post-retirement medical plan during 2007 are approximately $0.7 million.

The following two tables set forth the plans’ status (in millions of dollars) as of and for the years ended December 31 of the applicable year.

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							Post-Retirement
	Retirement Plan						Medical Plan
	2006			2005			2006			2005
Change in benefit obligation
Benefit obligation at beginning of year	$	46.6		$	36.9		$	21.9		$	21.2
Service cost	5.3			3.4			2.6			1.4
Interest cost	2.5			2.1			1.3			1.0
Plan amendments	—			—			1.6			—
Benefits paid	(6.2		)	(2.4		)	(0.4		)	(0.4		)
Actuarial loss	5.1			6.6			2.5			(1.3		)
Benefit obligation at end of year	$	53.3		$	46.6		$	29.5		$	21.9
Change in plan assets
Fair value of plan assets at beginning of year	$	35.7		$	32.3		$	—		$	—
Actual return on plan assets	4.9			1.6			—			—
Employer contributions	7.0			4.5			0.4			0.4
Benefits paid	(6.2		)	(2.4		)	(0.4		)	(0.4		)
Administrative expenses	(0.4		)	(0.3		)	—			—
Fair value of plan assets at end of year	$	41.0		$	35.7		$	—		$	—
Overfunded (underfunded) status	$	(12.3	)	$	(10.9	)	$	(29.5	)	$	(21.9	)
Reconciliation of funded status
Funded status	$	(12.3	)	$	(10.9	)	$	(29.5	)	$	(21.9	)
Unrecognized actuarial loss	—			20.6			—			3.8
Unrecognized transition (asset) or obligation	—			—			—			—
Unrecognized prior service cost	—			0.6			—			—
Net amount recognized	$	(12.3	)	$	10.3		$	(29.5	)	$	(18.1	)
Amounts recognized in the statement of financial position
Other assets	$	—		$	10.3		$	—		$	—
Current liabilities	—			—			(0.7		)	—
Deferred credits	(12.3		)	—			(28.8		)	(18.1		)
Net amount recognized	$	(12.3	)	$	10.3		$	(29.5	)	$	(18.1	)
Accumulated benefit obligation	$	40.8		$	35.6

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										Post-Retirement
	Retirement Plan									Medical Plan
	2006			2005			2004			2006		2005		2004
Components of net periodic benefit cost
Service cost	$	5.3		$	3.4		$	2.6		$	2.6	$	1.4	$	1.4
Interest cost	2.5			2.1			1.8			1.3		1.0		1.0
Expected return on plan assets	(2.8		)	(2.6		)	(2.6		)	—		—		—
Amortization of prior service cost	0.1			0.1			—			—		—		—
Amortization of transition (asset) obligation	—			—			—			—		0.3		0.3
Amortization of net loss	1.9			1.2			0.7			0.4		—		0.2
	$	7.0		$	4.2		$	2.5		$	4.3	$	2.7	$	2.9

The balance in Accumulated Other Comprehensive Income (AOCI) at December 31, 2006 consists of the following components (in millions of dollars):

	Retirement		Post-Retirement
	Plan		Medical Plan
Actuarial loss	$	14.6	$	3.8
Prior service cost	0.3		0.9
Total	$	14.9	$	4.7

Prior to the adoption of SFAS 158, the Company had no minimum pension liability that would have been reflected in AOCI.

The amounts in AOCI expected to be recognized as net periodic benefit expense over the next fiscal year are as follows (in millions of dollars):

	Retirement		Post-Retirement
	Plan		Medical Plan
Actuarial loss	$	2.0	$	0.4
Prior service cost	0.1		0.2
Total	$	2.1	$	0.6

The following table shows the incremental effects (in millions) of applying FASB Statement No. 158 on individual line items in the statement of financial position as of December 31, 2006:

	Before application					After application
	of FAS 158		Adjustments			of FAS 158
Other assets	$	37.4	$	(10.3	)	$	27.1
Total assets	6,981.4		(10.3		)	6,971.1
Deferred credits	23.8		20.5			44.3
Deferred income taxes	815.5		(11.2		)	804.3
Total liabilities	4,394.4		9.3			4,403.7
Accumulated OCI	18.2		(19.6		)	(1.4		)
Total shareholders’ equity	2,587.0		(19.6		)	2,567.4

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Plan Assumptions

							Post-Retirement
	Retirement Plan						Medical Plan
	2006		2005		2004		2006		2005		2004
Plan assumptions to determine benefit obligations
Discount rate	5.75	%	5.50	%	5.75	%	5.75	%	5.50	%	5.75	%
Rate of compensation increase	5.50	%	5.50	%	5.50	%	—		—		—
Plan assumptions to determine net cost
Discount rate	5.50	%	5.75	%	6.00	%	5.50	%	5.75	%	6.00	%
Expected long-term rate of return on plan assets	8.50	%	8.50	%	8.50	%	—		—		—
Rate of compensation increase	5.50	%	5.50	%	4.75	%	—		—		—

To develop the expected long-term rate of return on plan assets assumption, the Company considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class.  The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on plan assets assumption for the portfolio.  This resulted in the selection of the 8.50% assumption for 2006.

The Company determines the discount rate used to measure plan liabilities as of the December 31 measurement date for both plans. The discount rate reflects the current rate at which the associated liabilities could be effectively settled at the end of the year. In determining this rate, the Company reviews rates of return on fixed-income investments of similar duration to the liabilities in the plan that receive high, investment grade ratings by recognized ratings agencies. Additionally, the Company performs an analysis of the Citigroup Pension Discount Curve (CPDC) as of that date for both plans. The CPDC uses spot rates that represent the equivalent yield on high quality, zero coupon bonds for specific maturities. These rates were used to develop an equivalent single discount rate based on the plans’ expected future benefit payment streams and duration of plan liabilities. Using this methodology, the Company determined a discount rate of 5.75% to be appropriate as of December 31, 2006, which is an increase of 0.25 percentage points from the rate used as of December 31, 2005.

Expected benefit payments for the retirement and the post-retirement medical plans for the next ten years are as follows (expressed in millions):

	Expected Benefit Payments
Year Ending	Retirement		Post-Retirement
December 31,	Plan		Medical Plan
2007	$	3.5	$	0.7
2008	5.3		0.8
2009	5.0		0.9
2010	4.9		1.1
2011	6.1		1.2
Next 5 Years	37.8		7.8

The following table provides the target and actual asset allocations in the retirement plan:

			Actual as of December 31,
Asset Category	Target		2006		2005
Equity securities	100	%	89	%	87	%
Debt securities	0	%	0	%	0	%
Real estate	0	%	0	%	0	%
Other	0	%	11	%	13	%
Total	100	%	100	%	100	%

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For measurement purposes related to the Company’s post-retirement medical plan, a 10% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2006. The rate is assumed to decrease gradually to 5% for 2013 and remain at that level thereafter.  This compares to the amounts used for 2005 measurement purposes, where a 10% annual rate of increase in the per capita cost of covered health care benefits was assumed, decreasing gradually to 5% for 2012 and remaining level thereafter.

Assumed health care cost trends have a significant effect on the amount reported for the health care plan. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in millions):

	One Percentage Point
	Increase		Decrease
Effect on total of service and interest cost components for 2006	$	0.8	$	(0.7	)
Effect on year-end 2006 post-retirement benefit obligation	$	5.2	$	(4.2	)

In December 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduced a prescription drug benefit under Medicare (Medicare Part D), as well as a nontaxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company has elected not to reflect changes in the Act in its 2006 financial statements since the Company has concluded that the effects of the Act are not a significant event that calls for remeasurement under FAS 106.

(13) Stock-Based Compensation Plans

The Company’s incentive plans authorize awards granted wholly or partly in common stock (including rights or options which may be exercised for or settled in common stock) to key employees and non-employee directors.  Awards to employees of the Company may be made as grants of stock options, stock appreciation rights, stock awards, cash awards, performance awards or any combination thereof (collectively, “Stock Awards”).  Employee stock options generally become exercisable in three installments.  Employee restricted stock generally vests in four installments.  The number of shares of Company common stock available for future issuance was 3,284,524, 3,637,057, and 3,975,757 as of December 31, 2006, 2005, and 2004, respectively. Stock options granted during and after 2003 expire 5 years from the date of grant, if not exercised.  Stock options granted prior to 2003, if not exercised, expire 10 years from the date of grant.

Effective January 1, 2003, the Company adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock Based Compensation” (“SFAS 123”) and the prospective method transition provisions of Statement of Financial Accounting Standards No. 148, “Accounting for Stock Based Compensation—Transition and Disclosure—an amendment of FAS No. 123” (“SFAS 148”) for all Stock Awards granted, modified or settled after January 1, 2003.  Under SFAS 123, the Company recognized compensation cost for all Stock Awards on either a straight-line basis over the vesting period or upon retirement, whichever was shorter (the nominal vesting period approach).  On January 1, 2006, the Company adopted the provisions of SFAS No. 123 (revised 2004) (“SFAS 123R”), “Share-Based Payment”, which replaced the provisions of SFAS 123.  The cumulative effect of the change in accounting principle resulting from the adoption of SFAS 123R was recognized in the Company’s financial statements through the elimination of previously recognized deferred compensation costs, with offsetting amounts recorded in the additional paid in capital account within shareholders’ equity and the related deferred income tax payable.  The Company adopted SFAS 123R using the modified prospective transition method.  Under that transition method, compensation cost recognized during the twelve months ended December 31, 2006 includes (a) compensation cost for Stock 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 123, and (b) compensation cost for all Stock Award grants subsequent to January 1, 2006 based on the grant date fair value estimated in accordance with SFAS 123R.  Compensation cost for restricted stock and stock options is recognized using the nonsubstantive vesting period approach, i.e. (a) on a straight-line basis, over either the vesting period for the applicable Stock Award or until retirement eligibility age, whichever is shorter, or (b) over a six-month period for Stock Awards to employees who have reached retirement eligibility age.  The impact of using the nonsubstantive vs. the nominal vesting period approach would have resulted in a reduction in after-tax compensation expense of $1.0 million  for the year ended December 31, 2006, and an increase in after-tax compensation expense of $3.1 million and $10.0 million for the years ended December 31, 2005, and 2004, respectively.

The following table illustrates the effect on the Company’s net income and earnings per share if the fair value recognition provisions of SFAS 123R for employee stock-based compensation had been applied to all Stock Awards outstanding during the years ended December 31, 2005 and 2004 (in millions of dollars, except per share amounts):

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	Year Ended
	December 31,
	2005			2004
Net income, as reported	$	750.7		$	261.7
Add:        Employee stock-based compensation expense, net of related tax effects, included in net income, as reported	5.4			3.0
Deduct:   Total employee stock-based compensation expense, determined under fair value method for all awards, net of related tax effects	(6.8		)	(6.7		)
Net income, pro forma	$	749.3		$	258.0
Earnings per share:
Basic - as reported	$	12.43		$	4.10
Basic - pro forma	$	12.41		$	4.04
Diluted - as reported	$	12.32		$	4.06
Diluted - pro forma	$	12.30		$	4.01

Restricted Stock

The fair value of restricted stock grants is estimated based on the average of the high and low share price on the date of grant. The Company granted the following shares of restricted stock during the periods indicated:

		Weighted
		Average
	Number	Grant Date
Year Ended	of	Fair Value
December 31,	Awards	(in millions)
2006	400,000	$	17.8
2005	351,800	$	19.5
2004	303,400	$	13.2

A summary of the status of the Company’s unvested restricted stock activity during and as of the year ended December 31, 2006, is presented below:

			Weighted
			Average
			Grant Date
Unvested restricted stock:	Shares		Fair Value
Unvested at December 31, 2005	630,600		$	51.57
Granted	400,000		$	44.49
Vested	(233,875	)	$	48.67
Forfeited	(25,700	)	$	47.83
Unvested at December 31, 2006	771,025		$	47.54

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As of December 31, 2006, there was approximately $27.1 million of total unrecognized compensation cost related to unvested restricted stock that is expected to be recognized over a weighted average period of 1.5 years.  Total compensation expense for restricted stock for the years ended December 31, 2006, 2005, and 2004 was $15.6 million ($9.9 million, net of tax), $7.1 million ($4.5 million, net of tax), and $3.3 million ($2.1 million, net of tax), respectively.  The total fair value of shares that vested and were distributed during the years ended December 31, 2006, 2005 and 2004, was $10.7 million, $6.4 million, and $1.6 million, respectively, which resulted in the recognition of deferred tax assets in excess of the benefits of the tax deductions (“excess tax deficiencies”) of $0.3 for 2006, and the recognition of the benefits of the tax deductions in excess of deferred tax assets  (“excess tax deductions”) of  $0.5 million and $0.02 million for 2005 and 2004, respectively.

Stock Options

The Company granted options covering 30,000 shares of stock during the period ended December 31, 2004. Those options had  a grant date fair market value of $0.3 million. No stock options were granted during 2005 or 2006. The fair value of previous stock option grants that vested in 2005 and 2006 was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for stock option grants made in 2004 and 2003, respectively: risk free interest rates of 3.00% and 2.30%, expected volatility of 25.7% and 28.4%, dividend yields of 0.48% and 0.61%, and an expected life of the options of three and a half and three years.  Total compensation expense for stock options for the years ended December 31, 2006, 2005, and 2004 was $0.7 million ($0.5 million, net of tax), $1.4 million ($0.9 million, net of tax) and $1.4 million ($0.9 million, net of tax), respectively. The total intrinsic value of stock options exercised during the years ended December 31, 2006, 2005, and 2004 was $2.7 million, $7.3 million, and $9.4 million respectively, resulting in excess tax deductions of $1.0 million, $2.7 million, and $3.3 million for the same respective periods. As of December 31, 2006, there was less than $0.1 million in unrecognized compensation cost related to unvested stock options that is expected to be recognized over a weighted average period of 4 months.  The Company’s current practice is to issue new shares to satisfy stock option exercises.

A summary of the Company’s stock option activity during and as of the year ended December 31, 2006, is presented below:

					Weighted
			Weighted		Average	Aggregate
			Average		Remaining	Intrinsic
	Number of		Exercise		Contractual	Value
	Awards		Price		Term	(millions)(a)
Outstanding, December 31, 2005	1,782,236		$	29.69
Exercised	(144,800	)	$	30.95
Canceled	(15,867	)	$	43.11
Outstanding, December 31, 2006	1,621,569		$	29.45	4.1 years	$	31.6
Exercisable, December 31, 2006	1,614,902		$	29.37	4.1 years	$	31.6

(a) Calculated based on the exercise price of underlying awards and the quoted price of the Company’s common stock as of the balance sheet date.

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The following table summarizes information about stock options outstanding at December 31, 2006:

	Options Outstanding				Options Exercisable
		Weighted
		Average
		Remaining	Weighted			Weighted
		Contractual	Average			Average
Range of	Number	Life	Exercise		Number	Exercise
Option Prices	Outstanding	(days)	Price		Exercisable	Price
$ 17.91 to $ 19.56	47,500	841	$	18.30	47,500	$	18.30
$ 20.31 to $ 24.77	607,101	1,519	$	23.30	607,101	$	23.30
$ 25.38 to $ 29.78	604,600	1,966	$	29.58	604,600	$	29.58
$ 31.18 to $ 33.94	40,000	1,988	$	31.36	40,000	$	31.36
$ 40.63 to $ 43.46	304,034	510	$	41.82	304,034	$	41.82
$ 45.89 to $ 49.48	18,334	860	$	48.38	11,667	$	48.50
Total	1,621,569	1,481	$	29.45	1,614,902	$	29.37

Restricted Stock Units

The Company awards Restricted Stock Units (the “Units”) to certain employees of Northrock.  The Units vest ratably over a three-year period.  Vested Units are payable in cash in an amount equal to the fair market value of the Company’s common stock for the five-day trading period ending on the vesting date.  The Company recognizes compensation expense and a liability over the vesting period based on the average fair market value of Company common stock for the last five trading days of the period. On October 31, 2006, 43,979 of the Units vested, which resulted in payments of $2 million. As of December 31, 2006, there were 239,133 unvested Units. For the years ended December 31, 2006, and 2005, the Company recognized compensation expense related to the Units of $2.4 million and $0.4 million, respectively. Amounts related to the Units are reported in discontinued operations in the Company’s consolidated financial statements.

(14) Commodity Derivatives and Hedging Activities

During the year ended December 31, 2006, the Company recognized $2.7 million of pre-tax gains in its oil and gas revenues related to settled price hedge contracts, as well as a pre-tax gain of $3.4 million due to ineffectiveness on unsettled hedge contracts  During the year ended December 31, 2005, the Company recognized $11.3 million of pre-tax losses in its oil and gas revenues from settled price hedge contracts, as well as a pre-tax loss of $1.3 million due to ineffectiveness on unsettled hedge contracts. During the year ended December 31, 2004, the Company did not recognize any gains or losses from its hedging activities related to 2004 production, but did recognize a pre-tax gain of $0.7 million due to ineffectiveness. Net unrealized gains on derivative instruments of $6.6 million, net of deferred taxes of $3.8 million, have been reflected as a component of other comprehensive income for the year ended December 31, 2006.  Based on the fair market value of the hedge contracts as of December 31, 2006, the Company would reclassify additional pre-tax gains of approximately $6.2 million (approximately $3.9 million after taxes) from accumulated other comprehensive loss (shareholders’ equity) to net income during the next twelve months.

The estimated fair value of the Company’s hedging transactions is based upon various factors that include closing exchange prices on the NYMEX, volatility and the time value of options.  Further details related to these hedging activities as of December 31, 2006 are as follows:

30

	NYMEX					Fair Value
	Contract					of
Contract Period and	Price					Asset/(Liability)
Type of Contract	Volume	Floor		Ceiling		(in millions)
Natural Gas Contracts (MMBtu) (a)
Collar Contracts:
January 2007 – December 2007	5,475	$	6.00	$	12.00	$	1.6
January 2007 – December 2007	1,825	$	6.00	$	12.15	$	0.5
January 2007 – December 2007	9,125	$	6.00	$	12.50	$	2.9
January 2007 – December 2007	913	$	8.00	$	13.40	$	1.4
January 2007 – December 2007	2,738	$	8.00	$	13.50	$	4.2
January 2007 – December 2007	913	$	8.00	$	13.52	$	1.4
January 2007 – December 2007	913	$	8.00	$	13.65	$	1.4
January 2008 – December 2008	1,830	$	8.00	$	12.05	$	1.5
January 2008 – December 2008	2,745	$	8.00	$	12.10	$	2.3
January 2008 – December 2008	915	$	8.00	$	12.25	$	0.8
Crude Oil Contracts (Barrels)
Collar Contracts:
January 2007 – December 2007	1,460,000	$	50.00	$	75.00	$	(2.2	)
January 2007 – December 2007	365,000	$	50.00	$	75.25	$	(0.6	)
January 2007 – December 2007	3,650,000	$	50.00	$	77.50	$	(3.9	)
January 2007 – December 2007	182,500	$	60.00	$	82.75	$	0.3
January 2007 – December 2007	547,500	$	60.00	$	83.00	$	0.9
January 2007 – December 2007	182,500	$	60.00	$	84.00	$	0.3
January 2008 – December 2008	183,000	$	60.00	$	80.00	$	0.1
January 2008 – December 2008	183,000	$	60.00	$	80.05	$	0.1
January 2008 – December 2008	183,000	$	60.00	$	80.10	$	0.1
January 2008 – December 2008	366,000	$	60.00	$	80.25	$	0.2

(a) MMBtu means million British Thermal Units.

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 now recognizes all future changes in the fair value of these collar contracts in the consolidated statement of income for the period in which the change occurs under the caption “Commodity derivative income (expense).’’  The Company recognized 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. As of December 31, 2006, the Company had the following collar contracts that no longer qualify for hedge accounting:

	NYMEX					Fair Value
	Contract					of
Contract Period and	Price					Asset/(Liability)
Type of Contract	Volume	Floor		Ceiling		(in millions)
Natural Gas Contracts (MMBtu)
Collar Contracts:
January 2007 – December 2007	7,300	$	6.00	$	12.15	$	2.2
January 2007 – December 2007	3,650	$	6.00	$	12.20	$	1.1

31

(15) Divestitures

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 million of pre-tax gains on sales of other properties, has been reflected in the caption “Net (gain) loss on sales of properties” in the Company’s results of operations.

(16) Asset Retirement Obligations

The Company accounts 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.

Activity related to the Company’s ARO during the years ended December 31, 2006 and 2005 is as follows (in thousands):

	Year Ended December 31,
	2006			2005
Initial ARO as of January 1,	$	109.5		$	74.0
Liabilities incurred during period	3.2		(a)	3.6		(a)
Liabilities settled during period	(34.4		) (b)	(6.4		)
Revisions to previous estimate	36.1		(c)	32.3		(c)
Accretion expense	7.3			6.0
Balance of ARO as of December 31,	$	121.7		$	109.5
Less: Current portion of ARO as of December 31,	(6.8		)	(4.4		)
Long term portion of ARO as of December 31,	$	114.9		$	105.1

(a) $1.9 million and $0.7 million of this amount relates to acquisitions during 2006 and 2005, respectively.

(b) $31.8 million of this amount relates to the sale of 50% of the Company’s interest in its Gulf of Mexico properties

(c) Related primarily to increased estimated future service costs based on substantial inflation in the pricing environment.

For the years ended December 31, 2006, 2005 and 2004, the Company recognized depreciation expense related to its ARC of $7.2 million, $3.9 million and $1.0 million, respectively.

(17) Comprehensive Income

As of the indicated dates, the Company’s comprehensive income consisted of the following (in millions):

	Twelve Months Ended
	December 31,
	2006			2005			2004
Net income	$	446.2		$	750.7		$	261.7
Foreign currency translation adjustment, net of tax of ($3.2) million and $10.2 million, respectively	(11.4		)	22.9			—
Change in fair value of price hedge contracts, net of tax of $39.1 million, ($41.5) million, and $1.6 million, respectively	68.1			(72.2		)	3.0
Reclassification adjustment for hedge contract (gains) losses included innet income, net of tax of ($4.9) million, $9.6 million, and ($0.2) million, respectively	(8.5		)	16.7			(0.4		)
Comprehensive income	$	494.4		$	718.1		$	264.3

32

(18) Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value.

Cash and Cash Equivalents

Fair value is carrying value.

Receivables and Payables

Fair value is approximately carrying value.

Derivative Financial Instruments

Fair value is carrying value.

Debt and Other

Instrument	Basis of Fair Value Estimate
Bank revolving credit agreement(s)	Fair value is carrying value as of December 31, 2006 and 2005 based on the market value interest rates.
LIBOR rate advances	Fair value is carrying value as of December 31, 2006 and 2005 based on the market value interest rates.
2011 Notes	Fair value is 102.5% and 104.1% of carrying value as of December 31, 2006 and 2005, based on quoted market value.
2013 Notes	Fair value is 101.5% of carrying value as of December 31, 2006, based on quoted market value.
2015 Notes	Fair value is 96.5% and 98.0% of carrying value as of December 31, 2006 and 2005, based on quoted market value.
2017 Notes	Fair value is 96.0% and 97.1% of carrying value as of December 31, 2006 and 2005, based on quoted market value.

The carrying value and estimated fair value of the Company’s financial instruments at December 31, 2006 and 2005 (in millions of dollars) are as follows:

	2006						2005
	Carrying			Fair			Carrying			Fair
	Value			Value			Value			Value
Cash and cash equivalents	$	22.7		$	22.7		$	57.7		$	57.7
Receivables	$	151.5		$	151.5		$	149.1		$	149.1
Payables	$	(181.8	)	$	(181.8	)	$	(157.0	)	$	(157.0	)
Debt:
Bank revolving credit agreement loans	$	(797.0	)	$	(797.0	)	$	(606.0	)	$	(606.0	)
LIBOR Rate Advances	$	(75.0	)	$	(75.0	)	$	(40.0	)	$	(40.0	)
2011 Notes	$	(200.0	)	$	(205.0	)	$	(200.0	)	$	(208.3	)
2013 Notes	$	(450.0	)	$	(456.8	)	$	—		$	—
2015 Notes	$	(297.7	)	$	(287.3	)	$	(297.5	)	$	(291.4	)
2017 Notes	$	(500.0	)	$	(480.0	)	$	(500.0	)	$	(485.6	)

The Company occasionally enters into hedging contracts to minimize the impact of oil and gas price fluctuations. See Note 14 for a further discussion of these contracts.

33

Oil and Gas Producing Activities

The results of operations from oil and gas producing activities (expressed in millions) exclude non-oil and gas revenues, corporate general and administrative expenses, other non oil and gas producing expenses, net (gains) losses on sales of properties, interest charges, interest income and interest capitalized. Income tax (expense) or benefit was determined by applying the statutory rates to pre-tax operating results with adjustments for permanent differences.  Except as indicated, the “Total” amounts reflect only those activities related to the Company’s continuing operations.

	2006
	Other			United
	International			States			Total
Revenues	$	—		$	924.7		$	924.7
Lease operating expense	—			(183.4		)	(183.4		)
Exploration expense	(3.8		)(d)	(12.1		)	(15.9		)
Dry hole and impairment expense	—			(80.9		)	(80.9		)
Depreciation, depletion and amortization expense	—			(278.8		)	(278.8		)
Production and other taxes	—			(67.6		)	(67.6		)
Transportation and accretion	(0.6		)	(29.9		)	(30.5		)
Pretax operating results	(4.4		)	272.0			267.6
Income tax (expense) benefit	2.5			(111.9		)	(109.4		)
Operating results from continuing operations (b)	$	(1.9	)	$	160.1		$	158.2

	2005
	Other			United
	International			States			Total
Revenues	$	—		$	1,082.1		$	1,082.1
Lease operating expense	—			(136.0		)	(136.0		)
Exploration expense	(9.0		)(a)	(14.1		)	(23.1		)
Dry hole and impairment expense	—			(82.2		)	(82.2		)
Depreciation, depletion and amortization expense	—			(256.6		)	(256.6		)
Production and other taxes	—			(56.8		)	(56.8		)
Transportation and accretion	—			(25.0		)	(25.0		)
Pretax operating results	(9.0		)	511.4			502.4
Income tax (expense) benefit	—			(182.4		)	(182.4		)
Operating results from continuing operations (b)	$	(9.0	)	$	329.0		$	320.0

	2004
	Other			United
	International			States			Total
Revenues	$	—		$	973.1		$	973.1
Lease operating expense	—			(100.5		)	(100.5		)
Exploration expense	—			(21.7		)	(21.7		)
Dry hole and impairment expense	(5.5		)(c)	(56.1		)	(61.6		)
Depreciation, depletion and amortization expense	—			(248.5		)	(248.5		)
Production and other taxes	—			(44.1		)	(44.1		)
Transportation and accretion	—			(19.5		)	(19.5		)
Pretax operating results	(5.5		)	482.7			477.2
Income tax (expense) benefit	—			(175.6		)	(175.6		)
Operating results from continuing operations (b)	$	(5.5	)	$	307.1		$	301.6

(a)Related to New Zealand.

(b)Excludes operating results from discontinued operations of $209.7 million, $87.4 million and $28.8 million in 2006, 2005 and 2004, respectively.

(c)Related to the Danish North Sea.

(d)($4.6) million is related to New Zealand and $8.3 million is related to Vietnam.

34

The following table sets forth the Company’s costs incurred (expressed in millions) for oil and gas producing activities, including capitalized interest, during the years indicated.

	2006
	Other		United				Discontinued
	International		States		Total		Operations
Costs incurred
(capitalized unless otherwise indicated):
Property acquisition
Proved	$	—	$	1,046.2	$	1,046.2	$	21.4
Unproved	—		67.1		67.1		15.4
Exploration
Capitalized	0.1		155.2		155.3		75.1
Expensed	3.8		12.1		15.9		15.9
Development	—		406.3		406.3		230.9
Asset retirement cost	—		39.9		39.9		(2.4		)
Total oil and gas costs incurred	$	3.9	$	1,726.8	$	1,730.7	$	356.3

	2005
	Other		United				Discontinued
	International		States		Total		Operations
Property acquisition
Proved	$	—	$	46.0	$	46.0	$	1,786.9
Unproved	—		50.8		50.8		830.0
Exploration
Capitalized	—		130.1		130.1		10.4
Expensed	9.1		14.0		23.1		3.4
Development	0.1		164.2		164.3		125.4
Asset retirement cost	—		3.3		3.3		49.9
Total oil and gas costs incurred	$	9.2	$	408.4	$	417.6	$	2,806.0

	2004
	Other		United				Discontinued
	International		States		Total		Operations
Property acquisition
Proved	$	—	$	613.0	$	613.0	$	—
Unproved	—		26.9		26.9		—
Exploration
Capitalized	5.6		57.0		62.6		35.1
Expensed	—		21.7		21.7		1.5
Development	—		228.5		228.5		114.2
Asset retirement cost	—		14.3		14.3		4.0
Total oil and gas costs incurred	$	5.6	$	961.4	$	967.0	$	154.8

35

The following information regarding estimates of the Company’s proved oil and gas reserves, which are located onshore in the United States and offshore in United States waters of the Gulf of Mexico for continuing operations and were located offshore in the Kingdom of Thailand and onshore in Canada and Hungary for discontinued operations, is based on reports prepared by Ryder Scott Company, L.P. (“Ryder Scott”) and reports prepared by the Company and reviewed by Ryder Scott, for certain of its domestic properties acquired from Latigo, Ryder Scott Company – Canada (“Ryder Scott Canada”), for all of its Canadian properties, and Miller and Lents, Ltd. (“Miller and Lents”), for certain onshore Gulf Coast and Rocky Mountain properties. The definitions and assumptions that serve as the basis for the discussions under the caption “Item 1, Business—Exploration and Production Data—Reserves” should be referred to in connection with the following information.   Only reserves data related to the Company’s continuing operations is presented under the Total amounts.

Estimates of Proved Reserves

Oil, Condensate and Natural Gas Liquids (Bbls.)

	Domestic		Discontinued
	Total		Operations
Proved Reserves as of December 31, 2003	77,552,530		37,317,479
Revisions of previous estimates	5,012,763		(730,971	)
Extensions, discoveries and other additions	1,727,761		2,469,912
Purchase of properties	13,775,000		—
Sale of properties	(1,832,000	)	—
Estimated 2004 production	(12,370,000	)	(6,540,000	)
Proved Reserves as of December 31, 2004	83,866,054		32,516,420
Revisions of previous estimates	5,537,272		(23,300	)
Extensions, discoveries and other additions	1,801,097		3,083,600
Purchase of properties	588,379		60,100,000
Sale of properties	—		(28,496,442	)
Estimated 2005 production	(9,554,925	)	(5,377,290	)
Proved Reserves as of December 31, 2005	82,237,877		61,802,988
Revisions of previous estimates	8,508,423		1,102,519
Extensions, discoveries and other additions	8,503,900		6,896,000
Purchase of properties	23,421,000		186,000
Sale of properties	(15,846,500	)	—
Estimated 2006 production	(8,106,770	)	(5,370,507	)
Proved Reserves as of December 31, 2006	98,717,930		64,617,000
Proved Developed Reserves as of:
December 31, 2003	67,391,031		19,878,246
December 31, 2004	72,968,008		19,606,216
December 31, 2005	63,160,705		55,413,014
December 31, 2006	67,685,050		55,917,925

36

Estimates of Proved Reserves

Natural Gas (MMcf)

	Domestic		Discontinued
	Total		Operations
Proved Reserves as of December 31, 2003	837,004		175,319
Revisions of previous estimates	(16,357	)	(4,497	)
Extensions, discoveries and other additions	33,610		4,038
Purchase of properties	172,022		—
Sale of properties	(2,888	)	—
Estimated 2004 production	(89,410	)	(29,171	)
Proved Reserves as of December 31, 2004	933,981		145,689
Revisions of previous estimates	6,280		954
Extensions, discoveries and other additions	29,063		32,646
Purchase of properties	6,500		259,610
Sale of properties	—		(127,926	)
Estimated 2005 production	(84,526	)	(24,546	)
Proved Reserves as of December 31, 2005	891,298		286,427
Revisions of previous estimates	(63,162	)	(15,028	)
Extensions, discoveries and other additions	73,885		69,410
Purchase of properties	134,477		5,990
Sale of properties	(48,288	)	—
Estimated 2006 production	(73,553	)	(28,486	)
Proved Reserves as of December 31, 2006	914,657		318,313
Proved Developed Reserves as of:
December 31, 2003	702,836		77,938
December 31, 2004	769,753		83,095
December 31, 2005	685,301		220,704
December 31, 2006	701,550		236,791

37

POGO PRODUCING COMPANY & SUBSIDIARIES

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES—Unaudited

The standardized measure of discounted future net cash flows from the production of proved reserves (expressed in millions) is developed as follows:

1.Estimates are made of quantities of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

2.The estimated future gross revenues from proved reserves are priced on the basis of year-end market prices, except in those instances where fixed and determinable natural gas price escalations are covered by contracts.

3.The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as certain abandonment costs based on year-end cost estimates, and the estimated effect of future income taxes. These cost estimates are subject to some uncertainty.

4.The cash flows are discounted at 10% per annum.

The standardized measure of discounted future net cash flows does not purport to present the fair value of the Company’s oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

38

	Year Ended December 31, 2006
	Domestic			Discontinued
	Total			Operations
Future gross revenues	$	10,063.5		$	4,275.5
Future production costs	(2,878.5		)	(1,315.4		)
Future development and abandonment costs	(1,324.5		)	(251.4		)
Future net cash flows before income taxes	5,860.5			2,708.7
Discount at 10% per annum	(2,881.3		)	(1,209.8		)
Discounted future net cash flows before income taxes	2,979.2			1,498.9
Future income taxes, net of discount at 10% per annum	(781.9		)	(343.3		)
Standardized measure of discounted future net
cash flows related to proved oil and gas reserves	$	2,197.3		$	1,155.6

	Year Ended December 31, 2005
	Domestic			Discontinued
	Total			Operations
Future gross revenues	$	11,670.4		$	4,834.5
Future production costs	(2,585.1		)	(1,169.8		)
Future development and abandonment costs	(709.6		)	(204.5		)
Future net cash flows before income taxes	8,375.7			3,460.2
Discount at 10% per annum	(3,709.2		)	(1,506.1		)
Discounted future net cash flows before income taxes	4,666.5			1,954.1
Future income taxes, net of discount at 10% per annum	(1,445.1		)	(612.7		)
Standardized measure of discounted future net
cash flows related to proved oil and gas reserves	$	3,221.4		$	1,341.4

	Year Ended December 31, 2004
	Domestic			Discontinued
	Total			Operations
Future gross revenues	$	8,850.2		$	1,724.3
Future production costs	(2,123.5		)	(406.0		)
Future development and abandonment costs	(437.1		)	(143.6		)
Future net cash flows before income taxes	6,289.6			1,174.7
Discount at 10% per annum	(2,650.3		)	(242.0		)
Discounted future net cash flows before income taxes	3,639.3			932.7
Future income taxes, net of discount at 10% per annum	(1,080.6		)	(395.8		)
Standardized measure of discounted future net
cash flows related to proved oil and gas reserves	$	2,558.7		$	536.9

39

The following are the principal sources of change in the standardized measure of discounted future net cash flows.

	For the Year Ended December 31, 2006
	Domestic			Discontinued
	Total			Operations
Beginning balance	$	3,221.4		$	1,341.4
Revisions to prior years’ proved reserves:
Net changes in prices and production costs	(1,350.5		)	(433.8		)
Net changes due to revisions in quantity estimates	(30.5		)	(20.3		)
Net changes in estimates of future development costs	(570.0		)	(87.0		)
Accretion of discount	466.6			195.4
Changes in production rate and other	216.4			(117.4		)
Total revisions	(1,268.0		)	(463.1		)
New field discoveries and extensions, net of future production and development costs	233.2			224.4
Purchases of properties	616.3			15.8
Sales of properties	(940.6		)	—
Sales of oil and gas produced, net of production costs	(652.3		)	(348.8		)
Previously estimated development costs incurred	324.2			116.6
Net change in income taxes	663.1			269.3
Net change in standardized measure of discounted future net cash flows	(1,024.1		)	(185.8		)
Ending balance	$	2,197.3		$	1,155.6

	For the Year Ended December 31, 2005
	Domestic			Discontinued
	Total			Operations
Beginning balance	$	2,558.7		$	536.8
Revisions to prior years’ proved reserves:
Net changes in prices and production costs	1,528.3			—
Net changes due to revisions in quantity estimates	150.0			(7.6		)
Net changes in estimates of future development costs	(334.6		)	—
Accretion of discount	363.9			54.4
Changes in production rate and other	(154.1		)	369.5
Total revisions	1,553.5			416.3
New field discoveries and extensions, net of future production and development costs	145.5			193.9
Purchases of properties	32.2			1,509.8
Sales of properties	—			(819.4		)
Sales of oil and gas produced, net of production costs	(864.5		)	(308.7		)
Previously estimated development costs incurred	160.4			29.6
Net change in income taxes	(364.4		)	(216.9		)
Net change in standardized measure of discounted future net cash flows	662.7			804.6
Ending balance	$	3,221.4		$	1,341.4

40

	For the Year Ended December 31, 2004
	Domestic			Discontinued
	Total			Operations
Beginning balance	$	2,009.1		$	440.9
Revisions to prior years’ proved reserves:
Net changes in prices and production costs	631.1			237.0
Net changes due to revisions in quantity estimates	39.7			(14.4		)
Net changes in estimates of future development costs	(154.7		)	(7.0		)
Accretion of discount	292.9			76.1
Changes in production rate and other	(51.2		)	7.8
Total revisions	757.8			299.5
New field discoveries and extensions, net of future production and development costs	126.2			86.8
Purchases of properties	596.2			—
Sales of properties	(58.6		)	—
Sales of oil and gas produced, net of production costs	(809.0		)	(265.2		)
Previously estimated development costs incurred	98.1			50.1
Net change in income taxes	(161.1		)	(75.3		)
Net change in standardized measure of discounted future net cash flows	549.6			95.9
Ending balance	$	2,558.7		$	536.8

41

Quarterly Results—Unaudited

Summaries of the Company’s results of operations by quarter for the years 2006 and 2005 are as follows:

	Quarter Ended
	Mar. 31		June 30			Sept. 30			Dec. 31
	(Expressed in millions, except per share amounts)
2006
Revenues	$	243.7	$	237.5		$	232.1		$	217.1
Gross profit (a)	$	101.1	$	398.6	(d)	$	58.8		$	22.5
Income (loss) from continuing operations	$	45.9	$	336.6	(d)	$	11.1		$	(15.7	)
Income (loss) from discontinued operations, net of tax	$	21.6	$	25.3		$	22.2		$	(0.8	)
Net income (loss)	$	67.5	$	361.9	(d)	$	33.3		$	(16.5	)
Basic earnings per share (b):
Income (loss) from continuing operations	$	0.80	$	5.87		$	0.19		$	(0.28	)
Income (loss) from discontinued operations	0.38		0.44			0.39			(0.01		)
Basic earnings per share	$	1.18	$	6.31		$	0.58		$	(0.29	)
Diluted earnings per share (b):
Income (loss) from continuing operations	$	0.79	$	5.81		$	0.19		$	(0.28	)
Income (loss) from discontinued operations	0.37		0.44			0.39			(0.01		)
Diluted earnings per share	$	1.16	$	6.25		$	0.58		$	(0.29	)
2005
Revenues	$	255.8	$	274.5		$	270.4		$	285.4
Gross profit (a)	$	92.4	$	144.7		$	149.8		$	155.5
Income (loss) from continuing operations	$	39.5	$	74.0		$	61.0		$	86.5
Income (loss) from discontinued operations, net of tax	$	19.7	$	29.5		$	412.5	(c)	$	28.0
Net income (loss)	$	59.2	$	103.5		$	473.5	(c)	$	114.5
Basic earnings per share (b):
Income (loss) from continuing operations	$	0.62	$	1.23		$	1.02		$	1.49
Income (loss) from discontinued operations	0.31		0.48			6.94			0.49
Basic earnings per share	$	0.93	$	1.71		$	7.96		$	1.98
Diluted earnings per share (b):
Income (loss) from continuing operations	$	0.62	$	1.22		$	1.02		$	1.48
Income (loss) from discontinued operations	0.31		0.48			6.87			0.48
Diluted earnings per share	$	0.93	$	1.70		$	7.89		$	1.96

(a)Represents revenues plus net gain from property sales less lease operating, production and other taxes, other, exploration, dry hole, and impairment, and depreciation, depletion and amortization expenses.

(b)The sum of the individual quarterly earnings (loss) per share may not agree with year-to-date earnings (loss) per share as each quarterly computation is based on the income or loss for that quarter and the weighted average number of common shares outstanding during that period.

(c)Includes approximately $403 million of after-tax gain on the sale of the Company’s Thailand operations.

(d)Includes a pretax gain of $302.7 million from the sale of an undivided 50% of the Company’s Gulf of Mexico oil and gas leasehold interests and related pipelines and equipment to an affiliate of Mitsui & Co., Ltd.

42